An Assessment of Oil Shale Technologies

June 1980

NTIS order #PB80-210115
Library of Congress Catalog Card Number 80-600101

For sale by the Superintendent of Documents, U.S. Government Printing Office

Washington, D.C. 20402 Stock No. 052-003 -00759-2
Foreword

For many decades, the oil shale resources of the Western United States have

been considered possible contributors to the Nation’s liquid fuel supply. This volume reviews several paths to development of these resources and the likely consequences of following these paths. A chapter providing background information

about the nature of oil shale is followed by an evaluation of technologies for recovery of shale oil. The economics and finances of establishing an industry of various

sizes are analyzed. The fact that much of the best shale is located on Federal land

is examined in light of the desire to increase use of the resources. The consequences of shale development in terms of impact on the physical and social environments, and a discussion of the availability of water complete the report.

Policy options addressing barriers that could hinder the establishment of the

industry are presented. These options, designed primarily for Congressional consideration, are limited to the obstacles OTA identified as currently existing. Other

issues, of equal importance for the protection of the environment and the communities, but not constraints to development, are discussed in the body of the report.

The assessment deals only with oil shale; no systematic attempt was made in this

study to compare this energy source with liquid fuel sources other than conventional petroleum or with alternative energy strategies. Other OTA assessments

are addressing many of these topics.

Volume II evaluates the Federal Prototype Oil Shale Leasing Program. Both

volumes were prepared in response to requests from the Senate Committee on Energy and Natural Resources. We hope they will be of value to the entire Congress

when considering domestic energy policies.

JOHN H, GIBBONS

Director

///
Oil Shale Advisory Committee

James H. Gary, Chairman

Colorado School of Mines

James Boyd

Private Consultant

William Brennan

Rancher

Rio Blanco County, Colo.

Robert L. Coble*

Massachusetts Institute of Technology

Roland C. Fischer

Colorado River Water Conservation

District

John D. Haun

Colorado School of Mines

Carolyn A. Johnson

Public Lands Institute

Sidney Katell

West Virginia University

Estella B. Leopold

University of Washington

*Resigned March 1979.

* *Died April 1979.

Charles H. Prien**

Denver Research Institute

John F. Redmond

Retired, Shell Oil Co.

Richard D. Ridley

Occidental Oil Shale, Inc.

Raymond L. Smith

Michigan Technological University

Thomas W. Ten Eyck

Rio Manco Oil Shale Co.

Wallace Tyner

Purdue University

Glen D. Weaver

Colorado State University

NOTE: The Advisory Committee provided advice and comment throughout the assessment, but does

not necessarily approve, disapprove, or endorse the report, for which OTA assumes full responsibility.
Oil Shale Technology Project Staff

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Audrey Buyrn, Materials Program Manager

Thomas A. Sladek, Principal Investigator

William E. Davis, Social and Economic Impacts

Patricia L. Poulton, Environmental and Water Availability

Phillip L. Robinson, Economic and Financial

Administrative Staff

Patricia A. Canavan Margaret M. Connors

Carol A. Drohan Jackie S. Robinson

Contributors

Bob Fensterheim, Health Program Donald G. Kesterke, U.S. Bureau of Mines*

Mike Gough, Health Program Albert E. Paladino, National Bureau of Standards**

Steven Plotkin, Energy Program

Publishing Staff

John C. Holmes, Publishing Officer

Kathie S. Boss Debra M. Datcher Joanne Heming

*Oil Shale Project Director through January 1979, on detail to OTA from the U.S. Bureau of Mines.

**Materials Program Manager through December 1978.
Acknowledgments

This report was prepared by the Office of Technology Assessment Materials

Program staff. The staff wishes to acknowledge the assistance and cooperation of

the following contractors and consultants in the collection and analysis of data.

Steven C. Ballard, University of Oklahoma

Colorado School of Mines Research Institute

Denver Research Institute

Energy and Environmental Analysis, Inc.

Renee Ford, editor

The John Muir Institute for Environmental Studies, Inc.

Colin J. High, Dartmouth College

Christopher T. Hill, Center for Policy Alternatives,

Massachusetts Institute of Technology

Robert Kalter Associates

Kevin Markey, Friends of the Earth

The Pace Company Consultants and Engineers, Inc.

Plant Resources Institute

Quality Development Associates, Inc.

Resource Planning Associates, Inc.

The Rocky Mountain Center for Occupational and Environmental Health

Bernel Stone, Georgia Institute of Technology

George W. Tauxe, University of Oklahoma

Water Purification Associates

Richard W. Wright, Cardozo Law School, Yeshiva University

Wyoming Research Corp.

The Materials Program staff also wishes to acknowledge the assistance of

the large number of Federal, State, and local government groups and privatesector parties who provided advice and guidance throughout the assessment.
Contents

Chapter Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

Summary ... ... o.. ... ... ... o.. o.. .o . . . . . ... ... ... ... ... O.. 3

Introduction, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Constraints to Oil Shale Commercialization: Policy Options to Address

These Constraints. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Background. .., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technology .,... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Economic and Financial Considerations . . . . . . . . . . . . . . . . . . . . ., .,

Resource Acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Considerations. ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Water Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Socioeconomic Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Appendixes

A. Description and Evaluation of the Simulation Model . . . . . . . . . . . . . . .

B. Assumptions and Data for Computer Analyses. . . . . . . . . . . . . . . . . . . .

C, Oil Shale Water Pollutants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

D. Technologies for Managing Point Sources of Wastewater. . . . . . . . . . .

E. Acronyms, Abbreviations, and Glossary. . . . . . . . . . . . . . . . . . . . . . . . .

55

85

119

179

235

255

359

419

477

480

481

488

513

Vfl
CHAPTER 1

CHAPTER 1

Summary

Summary of Findings

Technology

Two basic retorting technologies are being

developed: modified in situ (MIS) for underground retorting, and aboveground retorting

(AGR) for processing mined shale. These

technologies are not presently ready for

large-scale commercialization, but a sound

R&D base exists, and they could be made

ready either by modular demonstration projects or construction of pioneer plants. The

MIS process is being developed on two sites

and one commercial facility is planned.

Aboveground retorts have been tested at up

to one-tenth of full size and at least one

commercial-scale retort is planned in conjunction with an MIS demonstration. There

are no firm plans for testing other above-

-ground retorts, although several companies

have shown interest. One process would be

tested if a lease were provided for the Department of Energy (DOE) facility at Anvil

Points, Colo. With financial incentives, two

others could be tested on private lands. A

multimineral aboveground process awaits the

availability of Federal land, either through

land exchange or limited leasing. Two true in

situ (TIS) processes are being developed with

DOE cost sharing, but are only at preliminary

stages. Underground mining would also benefit from additional research, development,

and demonstration. No major technical problems are anticipated either for open pit mining or for the conventional room-and-pillar

method of underground mining. Minor uncertainties remain in the upgrading and refining

area.

Economics

An oil shale industry could benefit the Nation’s economy and security, but would also

entail several economic risks. For example, a

400,000-barrel-per-day (bbl/d) industry established by 1990 would reduce expenditures for imported oil by $4.2 billion per year

and expand regional employment, but would

lead to increases in local inflation for certain

goods, services, and property. The establishment of a l-rnillion-bbl/d industry by 1990

could save more than $10 billion per year in

charges for imported oil and would substantially increase local employment; however,

the risks associated with overextended design and construction capacity, insufficient

equipment manufacturing capability, and

possible inefficiency from tight construction

schedules could cause damaging cost overruns. Severe regional inflation could be expected for land and housing as well as for

other goods and services.

Shale oil may be price competitive with foreign crude, but when expected real rates of

return on investment are 12 percent or less,

the commercialization of the industry could

still be impeded by uncertainties and risks.

Among these are cost estimates for constructing the facilities, the future price of oil, regulations, and competition with lower cost investments of similar risk in conventional oil or

other alternatives. To establish a 200,000-

bbl/d (or larger) industry within 10 years

would require financial incentives. The most

effective would be production tax credits,

purchase agreements, and price supports.

The smaller firms may need loan guarantees.

The net cost of an effectively designed and

administered incentives program could range

from $0.60 to $1.40/bbl* of shale oil syncrude** produced. Financial incentives alone

may not spur development because alternative investments with a greater return for an

equivalent level of risk could compete for the

available capital.

The Government also could build its own

commercial-scale or modular plants, but at

*Present barrel equivalent over 20 years at lo-percent discount rate.

**A synthetic crude oil produced by adding hydrogen to

crude shale oil. Shale oil syncrude is a high-quality material,

comparable with the best grades of conventional crude.

3
4 . An Assessment of 0il Shale Technologies

much higher cost. A Government effort to

construct and supervise demonstration modules (9,000 to 12,000 bbl/d each) would provide technological information that could resolve some hitherto unanswered questions

about the implications of oil shale development. It might also reduce the initial costs of

industry development. However, the Government’s experience in designing, financing,

and operating facilities could be sufficiently

dissimilar to that of possible private operators to make the information inapplicable.

Government efforts also probably would lessen the commercial and R&D interest of the

business community.

Resource Acquisition*

A 400,000-bbl/d production of shale oil

could be achieved by 1990 without extensive

leasing of additional Federal land if subsidies are provided so that two presently active

projects are completed, three suspended projects are resumed, and a new project on private land is initiated. If these financial incentives are not provided, then additional Federal leasing will probably be necessary if it is

desired to achieve this level of production. To

produce 1 million bbl/d by IWO would require

leasing, land exchanges, and substantially

greater subsidies.

Environment

Air and water quality, topography, wildlife, and the health and safety of the workers

will be affected by the development of an oil

shale industry. Many effects will be similar

to those caused by any type of mineral development, but the scale of operations, their

concentration in a relatively small geographic area, and the nature of the wastes

will present some unique challenges. Many

of the impacts will be regulated by State and

Federal laws. The developers plan to comply

by using control technologies from other in-

*On May 27, 1980, the Department of the Interior (DOI) announced it will lease up to four new tracts under the Prototype

Program and will begin preparations for a new permanent

leasing program.

dustries. While there is reason to believe that

the methods can be made to work, they have

not been tested in commercial-scale oil shale

plants because none exist.

The potential leaching of waste disposal

areas and in situ retorts after the plants are

abandoned is a major concern. If it occurs,

the leachates could degrade the water quality

in the Colorado River system, a vital water

resource in the Southwest. Such “nonpoint”

wastewater discharges are neither well understood nor well regulated, although the

Clean Water Act provides a regulatory

framework. Techniques for preventing leaching need to be demonstrated on a commercial

scale. It will be necessary to test a variety of

development technologies to assure adequate

control of a large industry.

The Clean Air Act is the only existing environmental law that could prevent the creation of a large industry. It could limit production in Colorado to 400,000 bbl/d, although

additional capacity could be installed in

Utah. The procedures for obtaining environmental permits can take several years. Although unexpected regulatory delays should

not preclude the establishment of an individual project, they could lead to cost overruns

and might prevent the deployment of a large

industry.

Water Availability

A 500,000-bbl/d” industry would increase

by about 1.5 percent the water demands projected for the Upper Colorado River Basin in

the year 2000. Surplus surface water could

be available to support this industry until at

least 2025, after which water scarcities may

limit all regional growth. Severe shortages

could be experienced as much as 20 years

sooner if the region develops more rapidly

than expected. Surface water scarcity may

lead to intensified ground water development, to a shift in the economic base, or to importation of water from other areas. Any

large oil shale industry will need new reservoirs and diversion projects. Their environmental effects, though small overall, will be
Ch 1–Summary ● 5

substantial in the areas where they are built.

The use of water for a 2-million-bbl/d oil shale

industry, while increasing regional income by

several billion dollars per year, would cause

losses of about $25 million per year to farming and hydroelectric power generation.

States that will not directly share in the increased regional income will experience

some of these losses.

Socioeconomic

Oil shale development will change the

communities in the sparsely populated oil

shale region both socially and economically.

Growth problems arising from the simultaneous development of oil shale and other energy resources are likely to be more difficult to

solve than those from shale development

alone. There is a potential for adverse effects, whose severity will depend on where,

when, and how rapidly the plants are built,

and on how well the communities are prepared to cope with the growth. The communities could accommodate the growth accompanying an industry of up to 200,000 bbl/d by

1990 if presently planned improvements and

expansions are completed. Social and personal distress will occur unless active measures are taken for their prevention. A l-million-bbl/d industry could not be accommodated without major Government involvement

and massive mitigation programs. The participation of Federal, State, and local agencies,

the public, and the developers would be essential to minimize the adverse living conditions that would inevitably arise.

Background

Oil shale deposits are found on all inhabited continents. Those in Colorado, Utah, and

Wyoming contain both a solid hydrocarbon

(kerogen) that can be converted to crude

shale oil by heating, and sodium minerals that

can be used in air pollution control, in glassmaking, and to produce aluminum. Deposits

of somewhat different chemical composition

and geology are found elsewhere. Those in

some foreign countries (Scotland, Spain, Australia) have been the sites of very small-scale

industries in the past. Other countries (Brazil,

the U. S. S. R., the People’s Republic of China)

either have such industries or are building

them.

The deposits of the Green River formation

are found in northwestern Colorado, southwestern Wyoming, and northeastern Utah.

(See figure 1.) The Federal Government owns

about 70 percent of the land, which contains

close to 80 percent of the oil shale and nearly

all of the associated sodium minerals. Private

parties, Indian tribes, and the three States

share the rest. Large deposits are also found

throughout the Midwestern and Eastern

States. Because of their richness and accessibility, however, the Green River shales are

the ones most likely to be developed on a large

scale in the near future.

The formation has been divided into several distinct geological basins. (See figure 2.)

The richest and most thoroughly explored deposits occur in Colorado’s Piceance basin.

The resources of Utah’s Uinta basin are, in

general, of somewhat poorer quality. The

Wyoming deposits are relatively inferior and

often intermingled with rock that contains no

organic matter. Overall, the deposits contain

the equivalent of over 8 trillion bbl of crude

shale oil. However, only a few hundred billion

barrels could be recovered economically with

existing technology.

In general, the oil shale region is rugged

country, with elevations ranging from 4,300

to 9,000 ft above sea level. The climate is dry,

and the weather is strongly influenced by the

topography. Although the soils are generally

thin and dry, they support diverse plant communities and over 300 species of animals, including the largest migratory deer herd in

North America and several threatened or endangered species.

Air quality is generally excellent, but high

concentrations of hydrocarbons* (possibly

from vegetation) and windblown dust are occasionally encountered, and thermal inver-

“Organic chemicals that contain only hydrogen and carbon.
6 ● An Assessment of 0il Shale Technologies

Figure 1 .—The Western Oil Shale Region

..

i,

“1

.

)URCE The National Atlas, Department of the Interior

sions are frequent. Water quality in the although it does not, in general, satisfy drinksurface stream-s is good to excellent in the

upper reaches but much poorer downstream

because of the discharges from naturally

saline streams, irrigated fields, and towns

and mineral development sites. The quality of

the water in the extensive ground water aquifers* also varies widely. Some contain only

saline brines; others contain potable water,

*An aquifer is an undergrounfl formation containing water,

ing water standards.

The population is approximately 120,000—

about 3 persons per square mile. Only four

towns in the shale region have populations

over 5,000: Grand Junction and Craig in Colorado, Vernal in Utah, and Rock Springs in

Wyoming. The economy is based on agriculture, minerals, tourism, and recreation. Coal,

oil, and gas development is increasing rapidly. The oil shale resources are also receiving

considerable attention.
Ch. 1–Summary ● 7

Figure 2.—Oil Shale Deposits of the Green River Formation

I

IDAHO

—.-

--i

I

I

● Salt Lake City

I

GREAT

DIVIDE

BASIN

RIVER WYOMING . . %

BASIN

WASHAKIE

BASIN

UTAH

UINTA

SAND

WASH

BASIN

Y’ Vernal ~+~ ~

● @ ,,

COLORADO

/“ i

/ a

Rifle

/’”

1 11

EXPLANATION

Area underlain by the Green Fhver FormatIon

In which the 011 shale IS unappralsed or

low grade

Area underlain by 011 shale more than

10 feet thick, whtch ytelds 25 gallons

or more 011 per ton of shale

SOURCE D C Duncan and V E Swanson, Orgarr/c.R/ch Sha/es of the United States and Wodd Land Areas, U S Geological Survey Circular 523, 1965
8 An Assessment of Oil Shale Technologies

Phofo credit George Wa//erste/n

Central Piceance basin, Colo.

Establishing an Oil Shale Industry: Perspectives and Tradeoffs

The Objectives for Development

The ultimate decision as to whether, how,

and to what extent to develop oil shale will be

political. Diverse groups with disparate preferences for particular types and rates of development will influence the decision. Some

of the objectives of the different groups are

discussed below.

To position the industry for rapid deployment.—The advocates of this objective believe the industry should be ready to expand

rapidly. They acknowledge that more information and experience are needed if production is to be expanded in times of national

need. Many techniques and sites would have

to be evaluated in order to answer the remaining questions. Supporters favor policies

expanding technical, economic, and environmental R&D, which should include demonstration plants to evaluate a full spectrum of

technologies. Incentives and additional Federal land might be employed to encourage private sector experiments. All programs would

be designed to maximize information generation.

To maximize energy supplies.—This objective has both economic and national security

implications. Its pursuit would lead to the

rapid development of a large industry. The

benefits that might accrue include reduced

import reliance, improved balance of payments, stimulation of private investment, increased employment, and lower energy costs

over the long term. Policy responses favored

by supporters of this objective emphasize

encouragement of the industry and removal

of the restraints on its establishment. Included might be leasing programs, substantial incentives, direct Government involvement in production, and the waiving of environmental laws.

To minimize Federal promotion.—This objective is supported by those who oppose governmental interference with private enterprise, and by those who stress that oil shale

should not be promoted at the expense of
Ch 1–Summary ● 9

other energy resources. They believe the industry should develop in response to market

pressures and opportunities without active

Government support or participation. Policies

furthering this objective emphasize technical

and environmental R&D and testing to provide a basis for developing regulations and

for comparing oil shale with other energy alternatives. Planning for future mobilization

programs would be carried out; leasing, land

exchanges, and incentives programs would

not.

To maximize ultimate environmental information and protection.—Advocates of this

objective emphasize the desirability of maintaining an ecological balance. They also believe that oil shale should not be promoted

more than other energy sources that could be

less harmful to the environment. They would

phase development to evaluate its potential

impacts and to design and test controls, Information on environmental effects and control

strategies would be acquired for all technologies that might be used in a commercial industry. Policies would emphasize enforcement of existing regulations, siting of plants

to minimize potential impacts, monitoring and

R&D to provide guidance for new regulations,

and public education and participation.

To maximize the integrity of the social environment .—Supporters of this objective emphasize personal and community needs. They

believe it essential that growth management

be well planned and coordinated, and that development proceed at a gradual pace. Policies

stress involving the region’s residents in managing growth, structuring incentive and leasing programs to avoid excessive growth rates

in the communities, funding community improvements and planning efforts, and allocating responsibilities for impact mitigation

among the developers and the Federal, State,

and local governments.

To achieve an efficient and cost-effective

energy supply system.—Supporters of this

objective emphasize the importance of providing a mix of energy alternatives with the

best overall ratio of costs to benefits. They

stress the need for positioning the industry

and its technologies for long-term profitable

operations so that any future expansions

could be financed with internally generated

resources. The related objectives of efficient

development of the resource and balanced

environmental and social protection are also

emphasized. The pace of development would

allow thorough evaluation of the technologies

so that the elements of production (including

land, labor, capital, water, and energy) could

be used most efficiently if a large-scale industry were created. Policies would focus on incentives that leave intact some degree of

managerial risk, on thorough testing of diverse technologies and sites, and on advanced R&D and demonstration to provide a

basis for comparing oil shale with its alternatives. The policies would not require a commitment of funds and resources to the exclusion of other potential energy sources.

* * *

The Government, in preparing its oil shale

policies, must consider all of these, as well as

well as other objectives. For example, the

Government owns rich oil shale deposits and

is responsible for protecting the Nation from

interruptions in energy supplies; this would

encourage the rapid development of public

lands. On the other hand, the public trust

requires that these lands be developed efficiently, with equitable returns for the use of

the public’s resources, and with fair treatment of the affected groups and regions. This

mandate would lead to a moderate pace of development. Finally, the Government is required by law to protect the environment and

to consider the socioeconomic consequences

of its major actions. These mandates require

carefully managed development.

Depending on which objectives are emphasized, a number of future industries can be

postulated. The following section evaluates

the relative degree to which each of four production targets could be expected to attain

the objectives for development, given a construction deadline of 1990.
IO . An Assessment of 011 Shale Technologies

Attainment of the Objectives

OTA analyzed four production targets for

1990: 100,000 bbl/d, 200,000 bbl/d, 400,000

bbl/d, and 1 million bbl/d. Strategies to reach

the targets would entail substantially different requirements, consequences, and policy

responses. Regardless of the strategy, tradeoffs among objectives are inevitable. This is

indicated in figure 3, where the production

goals are rated according to the relative degree to which they are expected to attain the

objectives for development. The following illustrates how attainment varies with the size

of the industry.

To position the industry for rapid deployment.—The 400,000-bbl/d industry is given

the highest rating because a wide variety of

technologies and sites would be evaluated

and substantial technical, environmental,

and economic information would be obtained;

all of which would place the industry in a

good position for rapid scaleup. The l-millionbbl/d goal is rated next since production at

this level would constitute a major industry;

further rapid deployment could then follow. It

is rated lower than the 400,000-bbl/d industry

because its accelerated construction schedule would preclude precommercial experiments and would probably result in less technically efficient plants. The other goals are

rated lower because fewer processes could

be evaluated.

To maximize energy supplies.—The benefits, and thus the ratings, are proportional to

the production rate.

To minimize Federal promotion.—The

100,000-bbl/d target is rated highest because

it could be achieved by completing the presently active projects. The 200,000-bbl/d goal

probably would require some incentives, and

the 400,000-bbl/d goal would require incentives, a small land exchange, and the shortterm leasing of a Federal R&D facility in Colorado for a demonstration project. The l-milFigure 3.—The Relative Degree to Which the Production Targets Would Attain the Objectives for Development

I

1990 production target, bbl/d

100.000 200.000 400.000 1 million

I

To position the industry for rapid deployment I I

I

i

To maximize energy supplies

To minimize federal promotion

,

To maximize environmental information and

protection ‘ 1

To maximize the integrity of the social

environment

To achieve an efficient and cost-effective

energy supply system

Lowest degree of attainment I I - Highest degree of attainment

SOURCE Off Ice of Technology Assessment
Ch l–Summary ● 1 1

lion-bbl/d goal would require much stronger

subsidies, additional long-term leasing of public land, permitting modifications, variances,

and extensive Federal involvement in growth

management.

To maximize ultimate environmental information and protection.—The quantity of pollutants and wastes generated will increase as

the rate of production increases. Establishing

a l-million-bbl/d industry in 10 years would

cause the most disturbance per unit of production because there would not be enough

time to improve the control technologies, The

100,000 -bbl/d goal is also given a low rating

because the limited number of technologies

tested would provide neither extensive information on impacts nor guidance for the improvement of controls and regulations. The

400,000-bbl/d target would meet the needs

for information and testing of control technologies but would incur a greater environmental risk per unit of production than 200,000

bbl/d. The latter would maximize the attainment of this objective.

To maximize the integrity of the social

environment. —The 100,000-bbl/d target is

rated high because it should be within the

physical capacities of the communities. A

200,000-bbl/d industry would strain the ability of the towns to absorb the number of expected new residents; the amount of stress

would depend on the location of the development. Adjusting to the growth associated with

a 400,000-bbl/d industry would be possible if

the plantsites were dispersed in Utah and

Colorado, if plant construction were phased,

and if preparations for the construction of

new towns were started at once; but boomtown effects would most probably accompany

the growth. A l-million-bbl/d industry would

require coordinated growth management

strategies and extensive financial outlays.

Severe social disruption could ensue.

To achieve an efficient and cost-effective

energy supply system.—The 400,000-bbl/d

target has the highest rating because it would

provide a balance of information generation

and of process development and demonstration. The 100,000- and 200,000-bbl/d targets

are rated lower because only a few technologies and sites would be tested. The l-millionbbl/d industry is also rated low because its

deployment strategy would use many of the

elements of production poorly. Furthermore,

the plants might not generate sufficient profit

capital for subsequent expansion.

An illustration of the need for tradeoffs

among objectives can be seen at the l-millionbbl/d level. This choice has high attainment of

the positioning and energy production objectives (e.g., it would displace about 16 percent

of the imported oil and reduce the balance of

payments significantly); however, reaching

the target requires tradeoffs in all the other

areas (for example, it would violate the Clean

Air Act).

Constraints

OTA analyzed the requirements for achieving each of the production goals by 1990,

given the present state of knowledge and the

current regulatory structure. The factors

identified as hindering or even preventing

reaching the goals are shown in table 1. The

constraints judged to be “moderate” will

hamper but not necessarily preclude development; those judged to be “critical” could become severe barriers. When it was inconclusive whether or to what extent certain factors would impede development, they were

called “possible” constraints.
12 ● An Assessment of Oil Shale Technologies

Table 1.–Constraints to lmplementing Four Production Targets

1990 production target, bbl/d

100,000 200,000 400,000 1 million

Possible deterring factors Severity of impediment

Technological

Technological readiness ... ., ... . None None None Critical

Economic and financial

Availability of private capital ... None None None Moderate

Marketability of the shale 011 . . . Possible Possible Possible Possible

Investor participation . . None Possible Possible Possible

Institutional

Availability of land. . . . . . . . . None None Possible Critical

Permitting procedure s None None Possible Critical

Major-pipeline capacity . None None None Critical

Design and construction services . ... None None Moderate Critical

Equipment availabilit y None None Moderate Critical

Environmental

Compliance with environmental regulations. . None None Possible Critical

Water availability

Availability of surplus surface water. . None None None Possible

Adequacy of existing supply system s None None Critical Critical

Socioeconomic

Adequacy of community facilities and services . None Moderate Moderate Critical

SOURCE Otflce of Technology Assessment

Issues and Policy Options

Technology

Oil shale contains a solid hydrocarbon

called kerogen that when heated (retorted)

yields combustible gases, shale oil, and a solid residue called spent, retorted, or processed shale. Crude shale oil can be obtained

by either aboveground or in situ (in place)

processing. In aboveground processing, the

shale is mined and then heated in retorting

vessels. In a TIS* process, a deposit is first

fractured by explosives and then retorted underground. TIS is at present a primitive technology, although R&D and field tests are

being conducted. MIS* is a more advanced in

situ method in which a portion of the deposit

is mined and the rest is shattered (rubbled) by

explosives and retorted underground. The

mined portion can either be retorted on the

surface or discarded as waste. The crude

shale oil can be burned as a boiler fuel, or it

can be converted into a synthetic crude oil

(syncrude) by adding hydrogen. The syncrude

can also be burned as boiler fuel, or it can be

*TIS = true in situ; MIS = modified in situ.

converted to petrochemicals or refined like

most conventional crudes. It is better as a

source of jet fuel, diesel fuel, and the other

heavier distillates than of gasoline. (The processing steps for an AGR system are shown in

figure 4.)

Issues

1

What are the advantages and disadvantages of different mining and processing methods?

Open pit mining allows large-scale, economical development and maximizes the recovery of the resource. Its application, however, is limited to a few areas in the Piceance

basin and to several in the Uinta basin. Alterations to the surface of the land are substantial, and the stripped overburden must be disposed of along with the processing wastes.

Open pit mining of oil shale has never been

tested. The technique is highly developed

with other minerals, however, and few technical problems are anticipated.
Ch I–Summary ● 1 3

Photo credit Departmenf of Energy

Department of Energy’s batch retort

pilot test plant, Laramie, Wyo.

Underground mining, which has been

tested in four mines in the Piceance basin, is

more generally applicable. The Piceance

mines, however, were relatively small and

were located on the southern fringe. Mining

conditions in other areas are considerably

different. Underground mining is especially

affected by the physical properties of the ore

and by the presence of ground water. In general, it is more costly than open pit mining,

and resource recovery is lower.

The advantages of TIS processing are that

mining is not required, spent shale is not produced on the surface, and the surface facilities needed are minimal. Its principal disadvantages are that the technology is not well

advanced, that it is applicable only to deposits that are not deeply buried, that oil recoveries are lower than by other methods, and

that the retorted shale is left underground

where it may be leached by ground water,

The MIS process requires mining 20 to 40

percent of the deposit to be retorted, and involves more facilities and waste disposal on

the surface. More oil is recovered per ton of

rock processed than with TIS, but less than

with aboveground processing. Oil recovery

per acre is probably higher with MIS than

with a combination of underground mining

and aboveground processing, but lower than

with surface mining and aboveground processing. The principal advantage of above-

-ground processing is its high oil recovery. Its

principal disadvantage is that it requires

large mining and waste disposal operations

and substantial surface facilities.

2

Are the technologies ready for largescale applications?

The commercial-scale deployment of the

critical retorting processes, at their present

developmental stage, would entail appreciable risks of both technological and economic

failure. All the components of an oil shale

project must function together, which means

that building a large-scale project is risky.

Even though some of the other components,

like the upgrading and refining processes, are

highly advanced, the oil shale processes are

not.

More than 30 years of R&D by governmental and private organizations has provided a

basis for commercialization tests. Two above-

-ground retorts have been tested for several

months at production rates approaching

1,000 bbl/d, about one-tenth of the size of

commercial modules. Others, like the Paraho

retort, have been tested at rates of a few hundred barrels per day. These experiments

have produced a total of about 500,000 bbl of

shale oil—the equivalent of 10 days’ production from a 50,000bbl/d commercial plant.

Additional testing, especially of the TIS process, is needed before a major industry can be

established with a reasonable level of confidence. The MIS process is being developed on

three sites in the Piceance basin, and the re-
14 . An Assessment of Oil Shale Technologies

Figure 4.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTS

FROM UPGRADING UNITS

● Low Sulfur Fuel 011 ● Ammonia

● Liquefied Petroleum Gas ● sulfur

● Coke

PROCESSED SHALE REVEGETATION

IN SHALLOW CANYON OR VALLEY

- -~ .- -. \.

Compacted

D.....-... -A c

--- .

\

--- - . .’--..,, ,.m .-r. -

-. f 1 L-,

Covered Processe

Shale Conveyors .

-. -.

Yno.

,..

,.

L

Y

Catchment Dam HEADFRAME DISCHARGE

; Surface Runoff STATION

Water reused

Roof Upper Bench

Bolting Scaling Loading Dnlhng -

— . . . .-.. ___

w

1 . .

ROOM AND PILLAR MINING

(Several Hundred Feet or more

Underground) SKIP LOADING STATION

SOURCE: C-b Shale Oil Project, Deta//ed Development Plan and Related Materlak, Ashland 011, Inc., and Shell Oil Co., February 1976, p. 1.24

suits of this work should assist in determining

its applicability to other areas.

produced, and the somewhat lower oil recovery efficiencies. With AGR, the effects of

scaleup on the performance and reliability of

the retorts themselves and on their associated equipment (pollution controls, product

recovery devices, and materials-handling

equipment) are unknown.

3

What are the major areas of uncertainty?

The effects of shale stability and strength

on mine design, on safety, and on resource recovery from underground mines are presently unclear. The effects that large inflows of

ground water would have on efficiency are

also not determined. Many uncertainties exist with respect to the feasibility and environmental impacts of TIS processing. The major questions about MIS concern its applicability to very rich or deeply buried shales, use

of the large quantities of retort gas that are

4

What can be done to reduce the uncertainties?

TIS will require extensive evaluation, including theoretical, laboratory, and field

studies, before its commercial potential can

be determined. Some of the uncertain aspects

of MIS and AGR processing could also be resolved with small-scale R&D programs. How-
Ch. l–Summary . 15

ever, demonstration projects will be needed

to accurately determine the performance, reliability, and costs of the various development

systems under commercial operating conditions. At a minimum, the retorting systems

could be demonstrated by the construction

and operation of modular retorts—the smallest production units that would be used in a

commercial operation. The module for an

MIS process might be a single retort with a

capacity of several hundred barrels a day, or

a cluster of retorts producing several

thousand. An AGR processing module might

produce 10,000 bbl/d. (A commercial plant

might contain five or six of these modules. )

Other technologies, such as open pit mining,

may necessitate a substantially larger degree

of scaleup, perhaps to a full-scale commercial

plant. The retorting technologies could also

be demonstrated in full-scale “pioneer”

plants, as proposed by Colony Development.

Policy Options

●

●

R&D funding.—R&D programs could be

conducted by Government agencies or by

the private sector, with or without Federal

participation. Federal programs could be

implemented through the congressional

budgetary process by adjusting the appropriations for DOE and other executive

branch agencies, by providing additional

appropriations earmarked for oil shale

R&D, or by passing legislation specifically

for R&D for oil shale technologies.

Demonstration programs.—Government

ownership of demonstration plants would

maximize its intervention and expense, but

would also provide it with the largest

amount of information, This would, however, discourage independent industry programs. Funding by the private sector alone

would minimize Government involvement

and expense, but the developers might not

be willing to invest in a timely manner and

share information. Cost sharing of the projects would entail intermediate costs to the

public and intermediate levels of information. Modular demonstration projects

would require a smaller total capital investment than a commercial plant, but they

would cost much more per barrel of oil produced. The projects could be structured in

several ways.

—A single module on a single site would

have the lowest total cost but the highest

per barrel cost. The information would

be useful only to the process and the site

evaluated.

—Several modules on a single site would

have higher total costs but the costs per

module and per barrel would be lower.

A full-scale commercial plant, incorporating several technologies, could be

simulated.

—Single modules on several sites would

have even higher costs. Unit costs would

be similar to those for the single module/single site option. Several sites and

processes could be evaluated.

—Several modules on several sites, the

equivalent of a pioneer commercial industry, would be the most costly but

would generate the maximum amount of

information and experience.

Economics and Finances

An oil shale plant will be very costly and

the oil will be expensive. Trends in world oil

prices suggest that shale oil may be competitive, both now and in the foreseeable future.

On the other hand, the long-term profitability

of the industry could be impeded by future

pricing strategies for competing fuels, by inaccuracies in the current cost estimates for

constructing facilities, and by risks that regulatory problems or litigation could delay or

bar a project’s completion. The following discussion deals with oil shale’s economic aspects and with some possible economic policies. All costs and prices are expressed in

third-quarter 1979 dollars.
16 . An Assessment of 0il Shale Technologies

Issues

1

What are the economic and energysupply benefits of oil shale development?

The output from a 400,000-bbl/d industry

would approximate the petroleum requirements of the Department of Defense or would

satisfy about 70 percent of the demand for

liquid fuels in the Rocky Mountain States. A

l-million-bbl/d industry could provide about

20 percent of the liquid fuels currently consumed in the entire Midwest, including 60

percent of the jet fuel, diesel fuel, and distillate heating oil. The amount of output

would replace about 16 percent of the current imported oil requirement. At $32/bbl,

this would reduce expenditures for imported

oil by about $10 billion per year (about 56

percent of the balance-of-payments deficit in

1979). * The effects of this industry on world

oil prices cannot be accurately predicted. For

illustration, if prices were depressed by 1

percent, then expenditures for foreign oil

would be reduced by an additional $900 million per year. Employment in the oil shale region would increase dramatically if an industry of any appreciable size were established.

2

What are the negative economic effects of establishing the industry?

During its construction by 1990, a l-million-bbl/d industry would cause a very small,

but perceptible, increase in the national rate

of inflation. In the longer term, this impact

would be offset by improvements in the balance of payments. If the industry were emphasized at the expense of less costly alternatives, the long-term inflationary effects,

through increased energy costs, might be

greater. Inflationary impacts on the oil shale

region would be significant for a 200,000-

bbl/d industry, substantial for 400,000 bbl/d,

and severe for 1 million bbl/d, Costs of labor

and housing would be most affected.

*Posted prices of some foreign crudes currently exceed

$32/bbl.

3 How much will oil shale facilities cost?

According to the current cost estimates, to

complete a 50, 000-bbl/d” syncrude project by

1990 would require a capital investment of

about $1.7 billion. The economic and financial requirements of the four production targets are indicated in table 2, together with

their requirements for water and labor. A 1-

million-bbl/d industry (approximately 20 projects) would cost about $35 billion, unless cost

overruns resulted from regulatory delays, accelerated construction schedules, or attempts

to build many of the projects simultaneously,

Establishing this industry by 1990 could cost

as much as $45 billion.

About 70 percent of the capital investment

would probably come from corporate equity;

the rest would be borrowed. The annual debt

requirement for a l-million-bbl/d industry

would constitute no more than 4 percent of

annual business investment, and should not

significantly strain U.S. private sector lending capabilities.

4 Is oil shale competitive?

Estimates of a breakeven price for shale oil

are highly dependent on assumptions, including the real rate of return required on investment, capital costs, operating costs, annual

real escalations of operating costs, productive life of the resource base, and the effective tax rate for developers. OTA’s computer

simulations indicate that prices of $48 and

$62/bbl (in 1979 dollars) of shale oil syncrude

would be required to achieve real, aftertax

rates of return of 12 and 15 percent, respectively. (See table 3.)

OTA’s assumptions are more conservative

(less optimistic) than those of many developers who believe that syncrude breakeven

price estimates are $6 to $9/bbl below those

used by OTA. OTA based its analysis, however, on the most recent cost estimates for

those technologies having advanced engineering designs, and the results are believed to

represent accurately the present economic
Ch. l–Summary 17

Table 2.–Requirements for the Production Targets

1990 production target, bbl/d

100,000 200,000 400,000 1 million

Resource Requirements

Institutional

Design and construction services, % of 1978 U.S. capacity needed each year

Plant equipment, % of 1978 U.S capacity needed each year

Economic and financiala

Loans. $ billion .,

Equity, $ billio n

Total, $ billion

Annual, $ billlonb : : Water avai/abi/ity

Water, acre-ft/yrc

Socioeconomic

Workers ., .,

New residents requlrlng housing and community services ., .,

Minimal

Mlnlmal

$0.9-1.35

2,1-3,15

3.0-4.5

06-0.9

9,800-24,600

5,600

23,000

Minimal

Minimal

$1,8-26

4,2-59

6.0-85

1.2-1,7

19,600-49,200

8,800-11,200

41,200-47,200

12

6-12

$3.6-42

8.4-98

12,0-140

2.4-2,8

39,200-98,400

17,600-22,400

82,000-95,000

35

15-30

$90-13 5

21.0 -31,5

30,0 -45.0

6.0-9.0

100,000-250,000

44,000-56,000

118,000-236,000

alhlrd quarter 1979 dollars

bMaxlmum annual requlcements for a 5 year construchon period

cAssumes 4 9001012 300 acre It /yr for producf(on of 50 000 bbl/d of shale 011 syncrude

dA55umes 1 200 Construction ~o~kers and 1 600 operators per 50 oo&bbl/d plant Multlp[lers used for total Increase = ‘2 5 x (Corlsfructlofl workers) + 55 x (Opt3rdOrS) Ranges reflect adjustments In

construction work forces assuming phasing of plant construction

SOURCE Ofhce of Technology Assessment

\

$

/’

Photo cred~t OTA staff

Oil shale retort plant at Anvil Points, Colo.
18 ● An Assessment of Oil Shale Technologies

Table 3.–Subsidy Effect and Not Cost to the Government of Possible Oil Shale Incentivesa

(12-percent rate of return on invested capital)

Change in Total expected cost

Total expected expected profit Probability to Government Breakeven

Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl)

Construction grant (50% ) $707 $487 0.00 $494 $3400

Construction grant (33%) . . . . . . . . 542 321 0.00 327 38.70

Low-interest loan (70% ) 497 277 0.00 453 43.40

Production tax credit ($3 ) 414 194 0.01 252 42.60

Price support ($55) . . . . . . . . . . . . 363 142 0,01 172 NA

Increased depletion allowance (27%) . . . . . 360 140 0.05 197 45,70

Increased investment tax credit (20%) . . . . . . 299 79 0.05 87 45.80

Accelerated depreciation (5 years) ., . . . . . . . 296 76 0.05 79 46.00

Purchase agreement ($55) . . . 231 11 0.03 0 NA

None . . 220 0 0.09 0 48.20

(15-percent rate of return on invested capital)

Change in Total expected cost

Total expected expected profit Probability to Government Breakeven

Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl)

Construction grant (50%) ., ., ., $281 $477 0.00 $494 $40.60

Construction grant (33%) . . . . . 119 315 0.19 327 47,70

Low-interest loan (70%) . , 81 277 0.23 453 54.70

Production tax credit ($3) ., . , - 6 1 135 0.63 252 56.10

Price support ($55) ., ., ., ., ., : : - 8 8 108 0.77 172 NA

Increased depletion allowance (27%) ., . . -11 0 86 0.75 197 57.20

Increased investment tax credit (20%) ... ., -13 1 65 0.77 87 58.80

Accelerated depreciation (5 years) . , -12 7 69 0.76 79 58.90

Purchase agreement ($55) ., ., ., ., ., ., -15 0 46 0.92 0 NA

None ., ., ., ., ., ... ., ., -19 6 0 0.93 0 61.70

aThe Ca[culatlofls assume a $sslbbl price for conventional premmrm crude that escalates at a real rate of 3 percent per year Thus, the predtcled $48/bbl breakeven price fOr the f 2-PerCent dlscounf rate WIII

be reached In t 1 years, or In the fifth year of production Therefore, m narrow economic terms, 011 shale plants starfmg constructwn now which assume a 12-percent dlscounl rate WIII be profitable over

the life of the project wtfhout subsidy (See dscusslon especially ch 6, for caveats concerning this Conclusion ) The calculations are for a 50 000-bbl/d plant coshng $1 7 bdhon All monetary values are m

1979 dollars

SOURCE Resource Planrung Associates Inc Washington D C

position of shale oil. If OTA’s cost estimates ●

proved correct and a 12-percent rate of return were sufficient to attract industry investment, Government incentives might not

be required to foster shale oil development.

Similarly, if OTA has overestimated the costs

and required rate of return, this conclusion

would still hold. On the other hand, if the uncertainties discussed below should come to

pass and/or a rate of return higher than 12

percent is required to attract capital, subsidies or other public policy actions would be ●

required to encourage development.

Several uncertainties bear on forecasts of

competitiveness. Although OTA’s analysis attempted to capture them, the following ones

cannot be completely incorporated in a quantitative analysis:

Unreliable cost estimates.—There are

no cost data for commercial-size plants

because none have been built. Cost estimates for projects have traditionally

been unstable, rising by more than 400

percent between 1973 and 1978. The

current range of estimates, based on

preliminary engineering designs and experience with other industries, is believed to be more accurate, although the

possibility of significant errors remains,

Regulatory disincentives.— Projects

may be delayed or precluded by procedures for obtaining permits, by siting or

process changes necessitated by regulations or litigation, or by future regulations that cannot be met economically.

Unexpected delays would contribute to

cost overruns.
Ch. 1–Summary . 19

●

●

Uncertain future world oil prices.—

Present prices are high, and rising.

There is a possibility, however, that future price changes may be less significant than commonly forecast, or that

they could be sufficiently unstable to

add appreciably to the risks of oil shale

development.

Cost overruns because of competition

with other projects.—Individual projects could be completed in 5 to 7 years

(10 years if preliminary demonstration

tests were conducted for the technologies). A 400,000-bbl/d industry could

probably be put in place by 1990 without

severe cost overruns if the various

plants’ construction were coordinated

and phased. However, the 20 or so projects needed for 1 million bbl/d by 1990

would face delays and cost overruns because of the large demands for equipment, labor, and construction services.

These uncertainties make any forecast of

breakeven prices unreliable. At the same

time, they may induce developers to seek

higher rates of return for their shale investments. For example, a 15-percent real rate of

return, which would be substantially greater

than that required for more conventional investments, would increase the price of shale

oil syncrude by $14/bbl (to about $62/bbl) and

thus would make it noncompetitive, without

subsidy, with the forecast prices of foreign

oil.

The rate of return issue.—In addition to

the interactions between the uncertainties

and required rate of return, there is another

important interrelationship. It pertains to the

flow of private capital given the rates of

return for potential alternative investments.

There has been much confusion over why the

estimated costs of shale oil always have been

higher than the actual costs of conventional

oil, even after the sustained high price rises

of the 1970’s. As discussed above (and in ch.

6), the effects of both increasingly detailed

engineering cost estimates and of inflation on

construction and capital equipment costs

have contributed significantly to the rising

estimates of the cost for a barrel of shale oil.

Alternative investment possibilities also

critically affect shale oil’s competitiveness.

Shale oil is tied to conventional oil in two

ways. First, it is a substitute in the marketplace, and therefore must be price competitive. Second, the companies that are potential

oil shale developers are the same ones that

produce or refine petroleum, or are potential

developers of other synthetic fuels. The profitability of shale oil must be “competitive” in

the sense of selling at a price that competes

with conventional oil while permitting a reasonable rate of return. A company with a finite amount of capital is most likely to invest

in those projects that offer the highest rate of

return at a given level of risk.

Price increases over the past 7 years have

dramatically increased the profitability of

both domestic and foreign petroleum development. As a consequence, companies may

choose to invest in petroleum so long as it has

a similar rate of return and does not entail

the extensive uncertainties of oil shale. It

follows that public policies to encourage oil

shale development must address making its

risks and rates of return comparable to those

of petroleum.

Oil shale investments at 12- or 15-percent

rates of return are not likely to displace investments that have lower costs, lower risks,

and higher rates of return, even if shale oil

has a competitive price. The incentives summarized in this chapter and discussed in detail in chapter 6 primarily address making

shale oil price competitive. They will not necessarily assure that it will compete successfully with alternative investments. Fewer opportunities in the future for investment in

conventional petroleum projects will tend to

increase interest in oil shale investments.

These considerations of price, cost, and rate

of return also apply to other synthetic and alternate energy industries. To the extent that

subsidies or other policy actions encourage

shale development alone, these other energy

investment alternatives are put at at relative

disadvantage.
20 ● An Assessment of Oil Shale Technologies

5

Which incentives would be most effective?

OTA analyzed 10 possible incentives on the

basis of 6 economic and financial criteria.

(See table 4.) Price supports, purchase agreements, and production tax credits appear to

have the most overall economic merit. Debt

guarantees or low-interest loans, however,

will probably be necessary to encourage the

participation of smaller firms. All incentives

programs would have to be properly administered to be effective, and should be removed

when no longer needed.

6 What would incentives programs cost?

The total net cost of subsidizing a 50,000-

bbl/d plant with one of the more effective subsidies could range from $200 million to $400

million. (See table 3.) This cost would be

spread over about 22 years, and would range

from $0.60 to $1.40/bbl of oil produced. It is

determined by:

● the size and timing of the outflows from

the Treasury,

● the size and timing of the increased

taxes paid by the developers, and

● the discount rate assumed for Government expenditures. *

It is not necessarily true that the least costly

incentive would be the best choice. Firms

with different corporate circumstances will

prefer different incentives because they must

avert different risks. It would be cost effective to offer a choice of incentives (e.g., grants

and low-interest loans to smaller firms, tax

credits to larger firms with bigger tax liabilities) to encourage participation by a variety

of firms.

7

What other economic factors could affect the establishment of an industry?

Attempts to establish a large industry

quickly could be impeded by the capacity of

*The Office of Management and Budget uses a discount rate

of 10 percent per year to compare the cost effectiveness of Government programs.

existing major pipeline systems leading to

Midwest markets and by shortages in design

and construction services and plant equipment. These factors should not be major problems for industries of up to 400,000 bbl/d.

Policy Options for Financial Support

Financial support could be provided either

by incentives to private industry or by direct

Government ownership or participation.

Incentives to private industry .—Incentive

programs could be structured for a high level

of risk reduction with relatively small net

costs and administrative burdens. The proper

incentives would share the risks associated

with creating the projects, but would leave

some of the managerial risks intact. This

would help establish the industry but would

allow market risks and opportunities to govern its development.

A possible disadvantage of incentives

would be that the Government could not directly control the pace of the industry’s

growth unless extensive encouragement were

provided. On the other hand, direct Government control is likely to discourage participation by private firms and could incur the risk

of managerial inefficiency. Also, with reliance on incentives, the Government would not

have direct access to the types of technical

and economic information that might be

needed to structure future oil shale policies. *

Incentives legislation could include requirements for disclosure of proprietary information and for specific test programs, but such

requirements would discourage industrial

participation. Information could also be obtained through licensing arrangements with

the owners of the technologies.

Direct Government participation or ownership. —A Government-owned industry

might be desirable in a crisis situation. OTA

did not analyze this option in detail because

of its extremely high cost to the public. The

*In its May 27, 1980, oil shale policy announcement, DOI indicated it would seek Memoranda of Understanding and other

formal documents to expand its ability to obtain performance

information.
Table 4.–Evaluation of Potential Financial Incentives for Oil Shale Development

Effect of Incentwe on program ob]ectwes Extent to which Incentive meets pohcy guldehnes

. . Promohon of comDetltlon

Incentive Subsidy effect Risk-sharing effect Flnanclng effect

Moderate, shares risk Slight, Improves -

associated with price uncer- project economics

talnty (If tax credit varies with

IJromotlon 01 Mlnlmlzatlon ot

economic efficiency admlnlstratwe burden — -.

Effect on firms Firm preferences —

1.

2.

3.

4.

5.

6.

7

8

9

Prod uctIon tax

credit ($3/bbl)

Investment tax

credit (additional

Strong, subsidizes

product price

Sllght adverse effect,

distorts product price

Mlnlmal admlnlstratwe

burden

Benefits firms with

large tax Ilablllty and

strong flnanclal

capability

Benefits firms with

large tax Ilabdlty and

strong flnanclal

capability

Supported by relatwely

large firms,

product price)

Moderate; shares msk

associated with Investment

cost uncertainty

Strong, subsidizes

Investment cost

SIlght, Improves

project economics

Moderate adverse effect;

dcstorts Input costs,

favors capital-lntenswe

technologies

Minimal admmlstratwe

burden

Supported very strongly by most firms;

however, firms that

would not be able to

use the investment

tax credit do not favor

Its enactment

Moderately supported

by a wide range

of firms

10YO)

Price supper Strong; subsidizes

product price (If contract price IS higher

than market price)

Slight; subsidizes

Investment cost

Moderate: shares nsk

associated with price

uncertainty

Moderate; improves

borrowing capability

Sllght adverse effect,

distorts product price

Moderate

admlnlstratwe burden

Benefits all ftrms

except those with

very weak flnanclal

capability

Benefits firms with

weak financial

capability

Benefits firms with

weak flnanclal

capability

Benefits all firms but

those with very weak

financial capabdlty

BenefNs all firms

Moderate; shares nsk of

project failure

Strong: improves

borrowing capability

Loan guarantee Slight adverse effect;

distorts Input costs:

favors capital-lntenswe

technologies

Shght adverse effect;

distorts Input costs;

favors capital-lntenswe

technologies

Sllght adverse effect;

distorts product price

Moderate

administrative burden

Supported by firms

with Ilmited debt

capacity

Subsidized interest

loan (70% debt at

3Y0 below market

rate)

Purchase

agreements

Block grant (33 &

50% of plant cost)

Shght; subsidizes

investment cost

Moderate; shares risk of

project failure

Strong; Government

provides capital

Moderate

adminlstratwe burden

Supported by firms

with Ilmited debt

capacity

Strong; but less than

price supports

Strong; shares risk of price

uncertainty

Moderate; improves

borrowing capability

Moderate (normally

more than price supports)

Moderate

administrative burden

Moderate, but less

than for price

supports

Supported by firms In

widely varying

flnanclal

circumstances

Little support

Strong; neutral

subsidy

None Strong; Government

prowdes capital

No adverse effect

Government

parflcipation

Slight Strong, shares all project

risks

Moderate; reduces

firm’s capital requirement

No adverse effect on firm

decisions; however, active Government involvement may lead to inefficiency

Moderate adverse effect,

distorts Input costs,

favors capital-intensive

technologies

Major admlnstrative

burden

Benefits firms that are

very averse to risk

(e. g., smaller, less

well-financed firms)

Benefits firms with

large tax Ilabdltles

and strong flnanclal

capabdlty

Accelerated de- Moderate: subsidizes Moderate; shares risk SIlght; Improves

project economics

Minimal admlnlstratwe

burden

Supported by large,

Integrated 011

companies

predation (5 years) investment cost; max- associated with Investment

imum subsidy effect cost uncertainty

is limited by Federal

corporate income tax

rate and interaction

with the depletlon

allowance

Shght; improves

project economics

Moderate adverse effect, Mlnlmal admlnistrahve Benefits firms with

large tax Ilabdltles

and strong flnanclal

capability

10. Percentage deple- Moderate: subsidizes None; Increases nsk

tion allowance product price; value associated with price

(27Yo) of subsidy increases uncerfalnty

as the need for the

subsidv decreases

Not supported

distorts product price In a burden

variable and undesirable

manner

SOURCE Resource Planning Assoclales Inc
22 . An Assessment of O// Shale Technologies

remaining option is Federal participation in

demonstration programs for the purpose of

obtaining and disseminating information.

This could provide a better assessment of the

public’s oil shale resources, allow for the participation of firms lacking oil shale land or

proprietary technologies, permit the thorough

testing of environmental controls, and facilitate regulation of the industry. *

The Government could become a part

owner of the project by sharing the capital

and operating costs with industry. The consequences would be similar to those resulting

from the construction grant option, except

that the Government would share all of the

risks and benefits. Almost without exception,

potential developers believe that active Government participation would increase managerial complexity and inefficiency. Administrative burdens would be high.

The Government could also contract for the

construction of several modular plants it

would then operate, either alone or through

contracts. It would then be in a position to obtain information on technical feasibility, project economics, and the relative merits of different processes. This might be of assistance

in evaluating future policies towards oil shale

development, in disseminating technical information, and in improving understanding of

the value of publicly owned oil shale resources. The facility could later be scrapped

or sold to a private operator. This option

would provide the Government with information and experience. The cost, however,

would be much higher than that of incentives

to private developers.

Considering that the technologies to be

tested are proprietary, it is by no means clear

that the Government would have the legal

right to publish all this information. In addition, its experience in designing, financing,

managing, and obtaining permits for an oil

shale plant may not resemble that of private

industry. Thus, the information acquired

might be of little use to subsequent private developers. Environmental information gath-

*Various types of demonstration programs are discussed in

the section on technological policies.

ered in this way would not entail such problems. Furthermore, most of the information

secured through Government ownership

could be made available as a condition of

granting private financial incentives.

Government intervention is likely to discourage private developers from undertaking

their own modular development and R&D initiatives, because programs of this kind tend

to reduce the benefits that a particular firm

could obtain from its own R&D or modular

testing. Finally, the patenting and licensing of

technologies make definite provision for dissemination of technical information on both

gratis and fee terms to possible users of the

processes.

Policy Options for Services, Equipment,

and Pipelines

Training programs could alleviate the

shortage of design and construction personnel, whose skills could be used later in the

operating facility. Developers normally try to

avoid equipment shortages by identifying

items with long delivery times and ordering

them early. Developers who coordinated efforts to standardize equipment could reduce

their problems with specially fabricated

items. However, such coordination could be

impeded by developers’ unwillingness to

share their process information and by antitrust laws. The Government could reduce or

eliminate tariffs and quotas on imported

equipment. Domestic suppliers would resist

this action. Shortages in pipeline capacity

could be reduced only by building more pipelines. The Government could provide aid by

expediting the review and approval of the numerous permit applications that would be required.

Resource Acquisition

The oil shale resources are owned by the

Federal and State governments, by Indian

tribes, and by private firms. (See figure 5.)

Overall, the Government owns about 70 percent of the land surface, which overlies about

80 percent of the resources. About 20,000
Ch 1–Summary 23

acres (less than 1 percent) of the Federal land

has been leased to private firms. It may be

necessary to involve more Federal land in

order to test certain technologies, or to establish a large industry rapidly.

Issues

1

Could the private land support 1argescale development?

The private lands are extensive, but it is

unlikely that a large industry will be sited on

them until the processing technologies have

been proven to be economic. As shown in figure 6, the private lands in the Piceance basin

generally lie along the southern fringe where

the deposits are comparatively thin and lean,

and are sometimes mixed with layers of barren rock. Development would be more costly

than on the Federal land to the north, where

the deposits are more than 1,000 ft thick and

yield more oil per ton. In addition, the privately owned resources contain no large deposits

of sodium minerals and they are, in general,

too deeply buried for economical open pit

mining. The large sodium mineral deposits

and the shallow oil shale beds are on Federal

land.

There are some tracts, Colony and Union,

for example, that contain commercially attractive rich deposits. These firms have been

developing retorting technologies for about

20 years, and projects with a total capacity of

about 150,000 bbl/d have been proposed for

their tracts. These projects have been suspended, however, pending a more favorable

economic and regulatory climate. The tracts

owned by Getty, Standard Oil of California,

and others contain resources of comparable

quality, but no projects have been announced

for any of these private lands. In part, this reflects the technological positions of the landowners who do not own advanced retorting

technologies. They may plan to license the

processes of the other companies, once these

have been demonstrated.

2

What production is expected from the

Federal lease tracts?

Production from the two Federal Prototype

Program lease tracts that are presently active could reach 133,000 bbl/d by 1987. However, only the lessees of Colorado tract C-b

are committed to commercial-scale production (57,000 bbl/d). Four other leases were offered in 1973, but those in Wyoming were not

sold and those in Utah are suspended until

the Supreme Court decides who owns the

land. * The potential production from the

Utah tracts (100,000 bbl/d) is not assured.

3

What other projects have been proposed or are presently active?

Tosco is proceeding at a slow pace in response to the diligence requirements of a

State lease in Utah. Geokinetics, Inc., and

Equity Oil are conducting small-scale R&D

projects under cost-sharing arrangements

with DOE. Occidental Oil Shale is conducting

large-scale tests of its MIS process under a

similar arrangement. Paraho Development is

attempting to extend its lease for DOE’s research facility at Anvil Points, Colo., and to

obtain funding for a modular demonstration

program. Superior Oil Co. has proposed a

land exchange to develop a multimineral

process in Colorado, and EXXON Corp. has

proposed to exchange its scattered holdings

for a single tract of Federal land in the Piceance basin.** DOE and the Department of

Defense are preparing a plan to develop Naval Oil Shale Reserve (NOSR) 1, near the Anvil Points site. If the current R&D is successful, if the land exchanges are consummated,

and if favorable economic conditions exist,

the total production from these projects could

exceed 250,000 bbl/d.

*On May 19, 1980, the U.S. Supreme Court reversed the

lower court decisions and held that the Secretary of the Interior could reject Utah’s applications for oil shale lands (Andrus v, Utah, No, 78-1522).

**The Bureau of Land Management recently denied Superior’s initial proposal. Negotiations are continuing.
.

24 . An Assessment of Oil Shale Technologies

Figure 5.—Ownership of the Oil Shale Lands of the Green River Formation

SOURCE Map of the Ma/or 0// Shale Ho/dregs—Colorado, Wyorrrmg, Utah, Denver, Colo Cameron Engineers, Inc , January 1978

4

Will more Federal land be needed to

initiate an oil shale industry?

The need for more land will depend on

whether a large industry is to be created rapidly, on the prevailing prices for imported oil,

on whether financial incentives are provided,

and on whether specific processing technologies are to be tested. Different amounts of

shale oil that might result from various Government actions are indicated in table 5. An

industry producing at least 60,000 bbl/d could

emerge without additional Federal actions. A

360,000-bbl/d industry might result if incentives were provided to encourage Colony and

Union to resume their projects. * An industry

*The incentives would have to be carefully structured to

achieve this result. See the section on economic and financial

policies for a discussion of incentives programs.
Ch 1–Summary ● 2 5

Figure 6.— Privately Owned Tracts in the Piceance basin

EXXON

INTERNATIONAL NUCLEAR RANGELY MEEKER

.

JFEDERAL

PICEA

BASIN

k

TRACT C.a

GULF

STD OF

Q

INDIANA

MOBIL

EQUITY

Lb’wMOBIL

ARCO

EQUITY

N C

STANDARD OF

CALIFORNIA UNION COLONY

\/

L

SERVICE v- (

OCCIDENTAL

~Qo

o+

~ov

a

Outhne of the Green Rwer

forrnatjon

A Proposed odshale prolect

N

SOURCE Map of the Ma/or 0// Shale Ho/d/rigs-Colorado, Wyofn/ng, Utah. Denver, COIO Cameron Engineers, Inc , January 1978

t ~- , i“ , < — ,
26 ● An Assessment of 0il Shale Technologies

Case

Federal action 1 2 3 4 5 6 7 8-

None

—

x

Incentives for first-generation developersa

x x x x x

Testsites for modular retortsb

x x x x x x

Resolution of ownership issues on Utah tractsc

x x x x x

Offtract land used

x x x x

Proposed land exchange s x x x

Incentives for second-generation developers

(or Improved economics ) x x

Naval 011 Shale Reserves or expanded

Prototype Program or permanent Ieasing x

Production, bbl/ d 60,000 -

f 360,00 0 390,000 490,000 560,000 620,000 850,000 1,000,000

185,000

aA~~ume~ the entry of one as yet unannounced develoPer

blncludes the proposed Superior 0,[ land ex~hange and a lea~lng of AnvI[ polnl~ by paraho Oevelopmen[ A 31J 000.b~{/ci production Increment Irom Government-sponsored modular lest retorls could occur

at any po[nf w the hrst 400000 bbl/d of production

cResumptlon of the Iracl U-a/ J.b prolect may also depend on the avallablllfy of lncentwes and on other Improvements in project economics

dFor ~as[e O’lsposa( fronl [he open pIt rrurre fhal was Orlglnally proPosed for tract C a

elncludes the proposed Superior 011 and EXXON land exchanges

fonly 57000 bbltd IS fwmly committed

SOURCE Offtce of Technology Assessment
Ch 1–Summary . 27

approaching 400,000 bbl/d could be realized

if incentives were provided and small tracts

of Federal land were available for retort test

programs. A multimineral lease or land exchange (such as proposed by Superior) and

continuation of the Paraho lease at Anvil

Points are alternatives. If the Utah lease

tracts resume development, a production of

500,000 bbl/d might be possible. If the tract

C-a lessees returned to the original open pit

mining concept, production could reach

560,000 bbl/d. (This would require permission to site processing facilities and to dispose of the solid wastes outside of the tract

boundaries. ) Adding the EXXON land exchange might increase production to 620,000

bbl/d. Unless economic conditions became

very favorable, a much stronger set of incentives would be needed to spur development of

the “second generation” tracts—those near

the fringe of the Piceance basin. All of these

conditions, plus additional leasing or development of the NOSR in Colorado, would be required to reach 1 million bbl/d by 1990.

5

What are the options for making Federal land available?*

The major options are governmental development of the NOSRs, leasing, and land exchange, Leasing is allowed under the Mineral

Leasing Act of 1920, as amended. The Prototype Program was structured under this Act.

Land exchanges such as those proposed by

Superior and EXXON are authorized by the

Federal Land Policy and Management Act of

1976 (FLPMA).

6

What are their advantages and disadvantages?

The NOSRs contain poorer quality oil shale

than the Federal holdings in the central Piceance basin. NOSR 1 in Colorado, however, is

large enough to support production of

*On May 27, 1980, DOI announced it will lease up to four

new tracts under the Prototype Program and will begin preparations for a new perm~nent leasing effort. Also announced

was the decision not to give special emphasis to the execution

of exchanges.

200,000 bbl/d for at least 20 years. One

drawback is that this reserve is located near

the private lands that may be developed, and

environmental and socioeconomic effects

would be concentrated if it were developed

concurrently. Any program for developing

the reserves (whether by a Governmentowned corporation, leasing, or cooperative

agreement with industry) could be structured

to yield valuable information, but would also

add a level of administrative overhead,

Leasing has several advantages. Informational requirements and environmental stipulations can be included in the lease provisions, and the pace of development can be

controlled (e.g., specifying preconstruction

monitoring periods, providing favorable royalty arrangements, and including diligence

requirements). Under the Mineral Leasing

Act, as amended, a portion of the leasing proceeds would be returned to the affected State

and could be used to mitigate the socioeconomic impacts accompanying development. A

major long-term advantage would be that the

Government would continue to own the land.

Additional leasing at this time also has

disadvantages. It could increase environmental and socioeconomic impacts by encouraging development before these impacts are fully understood and strategies for their mitigation in place. Delaying leasing, however,

while information is collected could lead to

better design of a future leasing program.

Furthermore, it can be argued that new leasing is unwarranted now since existing projects theoretically could yield about 400,000

bbl/d, which is sufficient to test a variety of

technologies at commercial scale.

Land exchanges could improve resource

management by allowing consolidation of

tracts that are presently too small, or too unfavorably situated, for economical development. Under FLPMA, however, environmental stipulations, informational requirements,

and developer participation in socioeconomic
28 ● An Assessment of 01/ Shale Technologies

impact mitigation programs could not be

made conditions of any exchange.

Either lease tracts or land exchange parcels could be selected to avoid ecologically

sensitive areas and to disperse socioeconomic

effects.

7

What are the difficulties with leasing

and land exchange?

All actions involving Federal land in the oil

shale region may be affected by the unpatented mining claims that overlie most of the

Federal holdings. * The claims have been a

source of legal controversy since the 1920’s.

If they are validated by the courts, the Government could lose control of much of the oil

shale land, including tracts potentially available for leasing or land exchange.

Some provisions of the Mineral Leasing Act

also may inhibit industry’s response to lease

offerings. These provisions limit the number

of leases to one per person or firm and restrict the size of a lease tract to a maximum

of 5,120 acres.**

If a firm wishes to exchange its holdings

for a Federal tract, the values of the lands

must be within 25 percent of one another.

Given the lower quality of the private oil

shale lands, such equivalent values may be

difficult to achieve. In addition, the evaluation and review procedures for exchanges so

far have been time consuming. (The Superior

proposal has been in the review stage since

1973. ) The experiences of Superior and Colony were the first attempts to use, for oil

shale lands, the exchange authority under

FLPMA. Colony did not immediately request

expedited treatment. Inadequate information

in Superior’s initial request may have been

partly responsible for the delay in evaluating

its request.

*On June 2, 1980, the U.S. Supreme Court ruled in favor of

two groups of unpatented claimholders in Colorado. It is too

early to determine the effects of this action on other unpatented claims. Andrus v. Shell OiJ Co. (No. 78-1815, June 2,

1980).

* *]n its May 27, 1980, decision paper, DOI stated that ‘t

would seek legislation to remove the statutory acreage limitations on lease size, and to permit holding a maximum of four

leases nationwide and two per State.

Policy Options

●

●

●

Amend the Mineral Leasing Act of 1920.

—The Act could be amended to increase

the acreage limitations, or to set the size of

the tract according to the recoverable

resources it contained. This might allow

more economies of scale, thereby improving economic feasibility. It might also allow

the inclusion of a suitable waste disposal

site within a tract’s boundaries, thus avoiding the need for separate offtract disposal

while still providing adequate shale resources for sustained, large-scale operations. The number of leases per person or

firm could also be increased. This might encourage firms that do not own oil shale

lands because it would allow them to apply

experience obtained on one lease tract to

another while the first was still operating.

However, the number participating in the

leasing program could be reduced if a few

firms acquired all of the leases. One possibility would be to increase the number but

limit it to one lease per State. This might

encourage a firm to develop a process in

the richer deposits in Colorado and then

apply it to the poorer quality resources in

Utah or Wyoming.

Amend FLPMA. —FLPMA could be

amended to allow the inclusion of conditions (such as environmental stipulations

and diligence requirements) in oil shale

land exchange agreements. This would improve the Government’s control over the

exchanged parcel, but could discourage

private participation.

Allow offsite land use for lease tracts.

—Legislation could be passed to allow a

lessee to use land outside of the boundaries

of a lease tract for facility siting and waste

disposal. * This might permit larger, more

economical operations (including perhaps

an open pit mine) and would maximize resource recovery on the tract, but could inhibit subsequent development of the offtract areas.

*DOI indicated in its May 1980 announcement that it would

propose such a legislative change.
Ch 1–Summary ● 2 9

●

●

●

Lease additional tracts under the Prototype Program.—There is no statutory limitation on the number of tracts that could

be leased under the Prototype Program.

However, DOI originally committed to leasing no more than six. Because two of the

original tracts were not leased, offering

two new ones might be justified, provided

that the technologies to be tested were different from the processes being developed

on the existing tracts. (One of the primary

goals of the Prototype Program is to obtain

information about a variety of technologies. ) Leasing more than two more tracts,

or leasing for the purpose of expanding

near-term shale oil production, would be

opposed by critics of rapid oil shale development. Leasing could begin sooner than

under a new leasing program, if some of

the potential lease tracts previously nominated were offered. A supplemental environmental impact statement (EIS) would be

required. Construction on the tracts could

probably not begin until 1985 and production no sooner than 1990.

Lease only for testing of multimineral

extraction. * —Multimineral extraction,

wherein shale oil is obtained along with

other commercially valuable minerals such

as nahcolite and dawsonite, has been receiving increased attention. Potential developers argue that obtaining the associated minerals would substantially increase

the profitability of the venture, The only

suitable land for multimineral experimentation is federally owned.

Initiate a new, permanent leasing program.—An advantage would be that more

production than is possible under the present Prototype Program could be achieved.

A full EIS and a new set of leasing regulations would be needed. Without the information to be acquired by completing the

present Prototype Program projects, it

might be difficult to prepare an accurate

environmental assessment and to structure

comprehensive leasing regulations. Pro-

*DOI will offer at least one multimineral tract in its renewed

Prototype Program.

duction could probably not begin until after

1990. Abandonment of the Prototype Program would be implied, which might engender opposition.

Expedite land exchanges.—No regulations

governing land exchanges have been promulgated under FLPMA. Standardized and

objective procedures could significantly

expedite the process. The review and approval procedures could also be improved

by, for example, setting up a task force

within DOI specifically for oil shale proposals,

Government development.—The Government could develop the NOSRs. Unless this

were done by leasing to private developers,

it would involve competition with private

industry, and would encounter political opposition. It would also be costly; the public

would have to pay the full cost of the facilities, and that might discourage independent experiments by private firms. The option would be helpful in obtaining information for developing policies and regulations

for the industry, but the information might

not be useful to private developers when

evaluating their investment alternatives.

This is because of the discrepancy between

Government and private developers’ experience in financing and operating facilities. Some of the information is being acquired in the present Prototype Program. It

could also be obtained in additional leasing

programs or through licensing arrangements with the owners of the technologies.

Continuation of present policies.—Continuation of present policies concerning offsite disposal, lease limitations, and land exchange procedures (without additional

leasing) would help protect the social and

physical environments. It would preclude

commercial development beyond that presently envisioned on the four lease tracts

and the three to five private holdings that

could support commercial operations. By

limiting future leasing and land exchanges,

shale oil production could not exceed

300,000 to 400,000 bbl/d and the adverse

impacts of a larger industry would be
30 ● An Assessment of Oil Shale Technologies

avoided. The gathering and evaluation of

information would enhance understanding

of the environmental consequences of development prior to further commercialization, and the pace would provide leadtime

for the communities to prepare for growth.

Given the long period needed to construct

facilities, however, this option would restrict the contribution shale oil could make

in the near term to the Nation’s liquid fuel

supply. The option also would tend to discourage further corporate interest and

could delay the testing of a variety of technologies,

Environment

Oil shale facilities, like other mineral

operations, will emit pollutants and produce

large amounts of solid wastes. The severity of

the environmental impacts will depend on the

scale and duration of the operations, on the

kinds of development technologies used, and

on the efficiency of the control strategies. The

plants must be designed and operated in compliance with environmental laws. The developers plan to achieve compliance largely

through use of control technologies applied

successfully in other industries. There appears to be little reason to believe that the

proposed controls cannot be made to work,

but they have not yet been tested for extended ‘periods with the

during oil shale processing

Issues

wastes produced

1

How will oil shale development affect

the environment?

The air in the oil shale region is relatively

unpolluted and, even if the best available control technologies are used, a large industry

will affect visibility and air quality not only

near the facilities but also in nearby parks

and wilderness areas. These impacts will be

regulated under the Clean Air Act.

Water quality is a major concern in the region. Oil shale operations could pollute the

water by accidental leaks and spills, by pointsource wastewater discharges, and by nonpoint discharges, such as runoff and leaching

of waste disposal areas and ground water

leaching of in situ retorts. Unless the pollution

is properly controlled, aquatic biota and

water for irrigation, recreation, and drinking

could be adversely affected. Point-source discharges are well regulated under the Clean

Water Act; developers plan to discharge no

processing wastewater to surface streams,

although they may discharge ground water

during the early stages of development.

Standards for injecting wastewaters into

ground water aquifers are being promulgated

under the Safe Drinking Water Act; developers do not plan to inject any wastewaters, but

may reinject the ground water extracted during mining. Most of the wastewaters will be

treated for reuse within the facility. Untreatable wastes will be sent to solid-waste disposal areas. As mentioned, these areas have the

potential for nonpoint discharges that are

neither well understood nor well regulated at

present, although a framework for their regulation has been established under the Clean

Water Act and the Resource Conservation

and Recovery Act.

The extent to which development will affect the land will be determined by the location of the tract; the scale, type, and combination of processing technologies used; and the

duration of the operations. Land conditions

(largely topographic changes from mining

and waste disposal) and wildlife will be affected. The facilities must comply with the

State laws that govern land reclamation and

waste disposal, which in some ways are less

stringent than the Federal laws governing

reclamation of land disturbed by coal mining.

Appropriate methods must be used to prevent

the large quantities of solid wastes from polluting the air with fugitive dust and the water

with runoff and leachates.

Many of the occupational safety and health

hazards will be similar to those of hard-rock

mining, mineral processing, and the refining

of conventional petroleum. Workers might,

however, be exposed to unique hazards be-
Ch 1–Summary ● 3 1

Phofo credit OTA staff

Colorado River flowing along Interstate 70

cause of the physical and chemical characteristics of the shale and its derivatives, the

types of development technologies employed,

and the scale of the operations. To protect

workers from these hazards, the developers

will have to comply with the Occupational

Safety and Health Act and the Mine Safety

and Health Act. Specific practices will have

to be developed as the industry grows. This

may be difficult if the growth is too rapid.

2

What are the major uncertainties with

respect to the impacts of the industry?

Although extensive work has been undertaken on pollution control technologies and

mitigating strategies and on procedures to

protect the safety and health of the workers,

uncertainties remain. For example, it is not

known whether conventional methods could

treat all of the process wastewaters to discharge standards, should this become necessary or desirable in the water-short region.

Nor is it known whether the proposed reclamation techniques will adequately protect the

waste disposal areas from leaching. Were

significant leaching to occur, it could have

severe effects on the region’s water quality.

The stability of revegetated spent shale piles

will remain uncertain for many years, and

the effectiveness of strategies proposed for

controlling the leaching of in situ retorts is

unknown.

Worker fatalities and injuries have been

rare in the industry to date, but oil shale has

been mined and processed only for experimental purposes, and at rates that are insignificant compared with commercial-scale op-
32 . An Assessment of 01/ Shale Technologies

erations. Predictions of a safe working environment have yet to be verified under conditions of sustained large-scale production.

The rates and characteristics of atmospheric emissions have not been firmly defined, and their dispersion patterns cannot be

accurately predicted because modeling methods are not yet adequate for the irregular terrain and complex meteorology of the oil shale

region.

Laboratory studies, computer simulations,

and pilot-scale test programs could clear up

some of these uncertainties (such as dispersion behavior and wastewater treatment).

Others (such as the efficacies of waste disposal practices) may need extensive test programs involving commercial-scale modules or

plants.

3

What potential impacts are not presently well regulated?

New Source Performance Standards for

air and water pollution control have not yet

been developed, although the regulatory

framework exists and they will be forthcoming as experience is gained with the operations. Standards for hazardous air pollutants and visibility will be promulgated by the

end of 1981. It does not appear, however, that

the hazardous substances to be covered by

these regulations will be generated in significant quantities by oil shale operations. Nonpoint sources of water pollution are not

presently well regulated. Performance standards for land reclamation that are specific to

oil shale have not yet been developed. Standards developed for coal under the Surface

Mining and Reclamation Act are not entirely

suitable for oil shale because of the significant differences that exist in geology, topography, waste characteristics, and other factors. A regulatory framework similar to that

in the Act could be used for developing oil

shale standards.

Environmental monitoring is presently required on private lands to assure compliance

with State and Federal regulations. The requirements, however, are not so strict as

those under the Prototype Leasing Program.

Environmental groups believe that the same

conditions should apply to both private lands

and Federal lease tracts. This, they believe,

would provide better information about the

environmental impacts from the technologies

operating on private holdings, and would

allow comparison with the effects from the

Federal lands. Furthermore, since one purpose of the Prototype Program is to obtain information about a variety of technologies, additional monitoring of the private lands might

provide these data. As a result, the need for

additional Federal leasing might be reduced.

Developers using private lands oppose this

action and claim that existing requirements

are more than sufficient to monitor the effects of their projects. They also point out

that additional monitoring is done voluntarily,

and assert that some of the tests required on

the lease tracts are of limited or dubious

value.

4 How much will pollution control cost?

Air pollution control is estimated to cost

approximately $0.90 to $1.15/bbl of syncrude

produced. Water pollution control is estimated to cost about $0.25 to $1.25/bbl of syncrude, assuming the water is treated for reuse within the facilities. Land reclamation

will cost about $4,000 to $l0,000/acre disturbed, or about $0.01 to $0.04/bbl of syncrude. The total cost, which may vary significantly with the location of a project, with the

nature of the operation, and with other factors, might be about $1.00 to $2.50/bbl (1.6 to

2.4 cents/gal) of oil produced. Although substantial, the cost should not preclude the establishment of an industry since it would

have only a small effect on the product price.

5

Will the size of the industry be limited

by existing environmental regulations?

Existing regulations for water quality, land

use, and worker health and safety do not appear to be obstacles. However, the industry’s

capacity will probably be limited by air quali-
Ch. 1–Summary ● 3 3

ty standards governing the prevention of significant deterioration (PSD). These specify

the maximum increase in the concentrations

of sulfur dioxide and particulate that can occur in any area, Under the Clean Air Act, the

oil shale region has been designated a Class II

area, where some additional pollution and industrial growth are allowed. Class I areas,

where the air quality is more strictly regulated, however, are nearby. One of these, the

Flat Tops Wilderness, is less than 40 miles

from the edge of the Piceance basin, where

most of the near-term development is likely to

take place. A preliminary dispersion modeling study by the Environmental Protection

Agency (EPA) has indicated that an industry

of up to 400,000 bbl/d in the Piceance basin

could probably comply with the PSD standards for Flat Tops, if the plants were dispersed. Additional capacity could be installed in the Uinta basin, which is at least 95

miles from Flat Tops. A l-million-bbl/d industry could probably not be accommodated,

because at least half of its capacity would

have to be located in the Piceance basin.

The lack of commercially available plant

species that are adaptable to the oil shale

region also could impose a temporary restriction on the industry’s land reclamation efforts. If commercial growers were to expand

their production to keep ahead of the needs,

this problem could be solved.

6

Will the industry be limited by the procedures for obtaining environmental

permits?

Of the more than 100 permits required for

construction and operation of an oil shale facility, about 10—the major environmental

permits—require substantial commitments of

time and resources. It may take as long as 2

years after the start of baseline monitoring

programs to obtain these permits, with an additional minimum of 9 to 24 months required

if an EIS needed. * If the regulatory agencies

*A statement may take much longer. The programmatic EIS

for the Prototype Leasing Program required 4 years. Preparing

the draft EIS for the proposed Superior land exchange required

2 Vears. The EIS for extending Paraho’s Anvil Points lease is in

its fifth revision, after more than 2 years.

need additional technical information, or if

agency personnel are overloaded with work,

the process may even take longer. Although

the permitting process is lengthy, it should

not preclude the establishment of an individual project. Particularly if many projects begin simultaneously, agency overloads could

delay them all, thus causing cost overruns.

This should not limit the size of the industry,

but it might prevent a large industry from

being established rapidly.

Policy Options for Air Quality Management

Increase information.—More R&D could

be conducted on air pollutants, their effects, and their controls. Studies of the

dispersion behavior of oil shale emissions,

for example, would lead to a better understanding of the long-range consequences of

these emissions on ambient air quality.

This, in turn, would provide guidance for

plant siting to reduce air quality deterioration. Options include the evolution of existing R&D programs in EPA and DOE, their

expansion by redistributing or increasing

appropriations, and the passage of legislation specifically for air quality studies.

R&D should be coordinated with any demonstration projects that are conducted.

Data from these projects could help in setting performance standards for pollution

control.

Change the standards.—The emissions

standards for oil shale facilities have not

yet been set because of a lack of information about the nature of the operations, The

estimated limit of 400,000 bbl/d in the Piceance basin is based on estimates of the

emissions that would occur if the best currently available control technologies were

applied. EPA could set stricter emissions

standards that would reduce air pollution

and, if the standards could be met, would

also allow more production. If the plant

emissions were cut in half, for example, up

to 800,000 bbl/d could be installed in the

Piceance basin, and more in Utah. This option would entail much higher control
34 ● An Assessment of Oil Shale Technologies

●

costs, and it might not be technologically

achievable.

Another option would be to redesignate

the oil shale region from Class II to Class

III. This would allow greater degradation

of air quality (the extent of which cannot

be accurately predicted in the absence of

reliable regional modeling studies) while

allowing more production. However, it

would not remove the limits imposed by

nearby Class I areas, which at present appear to be controlling.

Amend the Clean Air Act.—There are

three options for amending the Act. Each

deals with the restriction posed by the PSD

standards.

At present, EPA distributes PSD permits

to developers on a first-come, first-served

basis. The Act could be changed to require

a coordinated strategy for facility siting

that would maximize production while

maintaining air quality at regulated levels.

EPA could allocate portions of the PSD increments based on its own analysis of

needs and impacts, or it could consult with

all of the potential developers in an attempt

to evolve an optimum distribution. (An

amendment would be required to avoid impediments to such cooperation under the

antitrust laws. ) Distributing the PSD increment among the maximum number of facilities would amount to an implicit tightening

of the emissions restrictions, which would

add to the costs of air pollution control.

The Act could be amended to exempt the

developers from maintaining the air quality of the nearby Class I areas, while adhering to Class II standards in the oil shale

region. The maximum size of the industry

would be limited, because the developers

would still have to comply with the region’s

standards. Alternatively, if this action

were coupled with a redesignation of the

oil shale region to Class III, there could be,

at the cost of increased pollution in all

areas, at least twice as much production as

is presently possible. (The Class III standards allow twice as much pollution as

Class II.)

Finally, the Act could be amended to exempt the developers from air quality regulations in both the oil shale area and the

nearby Class I areas. This would allow

high levels of production, again at the cost

of increased pollution over a large area.

This action would encounter significant political and legal resistance.

Policy Options for Water Quality Management

Increase information.—More R&D could

be conducted to develop and demonstrate

methods for treating the process wastewaters to meet discharge standards. Although not a part of current developer

plans, such treatment could provide additional water resources for the water-short

region. Additional attention could also be

given to preventing leaching of waste disposal areas and in situ retorts. Policy actions would be similar to those for air

quality R&D. Alternatively, requirements

for developing strategies for dealing with

the long-term effects on water quality

could be added to leases for Federal land.

(The lessees in the current Prototype Leasing Program are required to develop and

demonstrate both reclamation methods

and procedures that will prevent the leaching of in situ retorts. )

Develop regulatory procedures and standards.—Promulgating standards in the

areas that are not presently well regulated

would reduce the uncertainty that future

regulations could preclude profitable operations. Under the present approach, regulations evolve as the industry and its control technologies develop. This introduces

uncertainty, but allows the standards to be

set with a knowledge of the technical and

economic limitations. As an alternative,

standards could be set that would not

change for a period of say, 10 years, after

which they could be adjusted to reflect the

experience of the industry. This would remove the uncertainty, but the standards

would have to be carefully established to

assure that they were both adequate to
Ch. 1–Summary ● 3 5

protect the environment and attainable at

reasonable cost.

● Ensure the long-term management of

waste disposal sites and in situ retorts.—

These locations may require monitoring

and maintenance for many years after the

projects are completed. Long-term management could be regulated, for example, under the Resource Conservation and Recovery Act, which allows EPA to set standards

for the management of hazardous materials, including mining and processing

wastes. (Spent oil shale has not been classified as a hazardous waste, but EPA has

suggested that it may be given a special

classification because of the large volumes

that will be produced.) Alternatively, the

developers could be required to guarantee

such management by incorporating appropriate provisions in leasing regulations.

Policy Options for Occupational Health and Safety

●

●

●

Increase information.—R&D could be conducted on the cancer risks associated with

processing oil shale and shale oil. This

work should take advantage of the extensive, but often conflicting, prior work and

should be coordinated with ongoing studies. Policy actions would be similar to those

for air quality R&D.

Undertake health surveillance,-A central

registry of health records would facilitate

the identification of hazards and the development of protective methods. It could be

located in a regional medical center, with

or without the active participation of Federal agencies. Funds could be provided by

the Government, by the States, by labor organizations, or by the developers.

Develop exposure standards.—As information about potential chemical health

hazards is analyzed, the National Institute

of Occupational Safety and Health, the Occupational Safety and Health Administration, and the Mine Safety and Health Administration could address the necessity

for exposure standards.

Policy Options for Land Reclamation

●

●

●

●

Increase information.—R&D and field testing could be conducted on reclamation

methods and the selection of plant species

for revegetation. This work would help set

reclamation performance standards for

the oil shale industry. Policy actions would

be similar to those for air quality R&D. Additionally, the developers could continue to

be required in future leasing programs to

develop viable reclamation methods (currently required of participants in the Prototype Leasing Program).

Establish Federal reclamation standards.—Legislation could be introduced to

provide standards that are appropriate to

the conditions in the oil shale region and to

the types of disturbance that will occur

with development. The standards should

be ecologically sound, economically achievable, and consistent with the public’s goals

for postmining land use. Consideration

should be given to the relative merits of

alternative control strategies and environmental performance standards necessary

to reduce erosion and leaching and to allow

more efficient use of the land for wildlife,

grazing, or other purposes.

Expand the production of seeds and plant

materials.—This might avoid a possible delay in reclamation programs. It could be

done by providing appropriations to the

Federal plant materials centers and by expanding the cooperative programs between these centers and commercial suppliers.

Protect the wildlife and their habitats.

—Lease tracts and land exchange parcels

could be chosen to minimize disruption of

ecologically fragile areas. This would require extensive, site-specific characterization studies in advance of leasing or exchange. These studies would be expensive

and time consuming, but they could ultimately expedite subsequent actions by reducing the duration of the baseline monitoring period that might be required of de-
. .

36 ● An Assessment of Oil Shale Technologies

velopers. (Provisions for wildlife maintenance were included in the leases for the

Prototype Program.)

Policy Options for Monitoring and for

Permitting Procedures

 Increase information.—Additional environmental monitoring of developments on

private lands could be required. This

would entail changing existing laws and

regulations. Its advantages include gathering comparable information for both private holdings and Federal lease tracts. The

new information might reduce the need for

leasing more Federal tracts to test technologies not being used by the Prototype Program lessees. Its disadvantages include the

possibility of litigation. It would also increase expenses for developers using private holdings,

Further study of the permitting procedures could help to design more efficient

ones while maintaining a high level of environmental protection. The studies could be

conducted by the regulatory agencies or by

the General Accounting Office.

● Increase agency resources.—Increasing

personnel and financial resources would

allow the agencies to improve their response capabilities and increase their assistance to State and local regulators. Coordination of the expanded resources

would also be needed.

● Improve coordination among the agencies

and between the agencies and the public.-Coordinated reviews could be conducted to reduce jurisdictional overlaps,

paperwork, and workloads. It might be

necessary to mandate coordination to assure its effectiveness. Another approach

would be to establish a regionwide environmental monitoring system to determine

baseline conditions for all areas to be affected by oil shale projects. This might reduce the duration and the cost of the monitoring programs now required of permit

applicants. Site-specific studies and monitoring would still be needed for certain

data. Another option would be to improve

●

●

●

●

the coordination of public participation in

agency decisionmaking processes. This

might help reduce confrontations, although

it could lead to an expanded perception of

risks and thus to stronger opposition.

Clarify the regulations and the permitting

process.— Simplifying the procedures

would have the advantage of retaining the

laws and their protection while making it

easier to comply with them. Problems could

arise if procedures were changed while applications were in process. Another approach would be to establish detailed,

standardized specifications for permit applications. (EPA is doing this for the PSD

process.) This would reduce, but not eliminate, delays. Fully standardized forms are

probably not practical.

Expedite the permitting procedure.—An

authority (such as the Energy Mobilization

Board) could be established with power to

make regulatory decisions if the agencies

do not do so within a set period. This would

provide a single point of contact between

the developer and the regulatory system,

but it would add to the bureaucracy and increase controversy. Another possibility

would be to limit the period of litigation for

permitting actions, as was done in the case

of the Trans-Alaska oil pipeline.

“Grandfather” oil shale projects.—Plants

under construction, or already operating,

could be exempted from future regulations.

(This concept is embodied in the Energy

Mobilization Board legislation.) This would

remove many regulatory uncertainties, but

would reduce environmental protection.

Some environmental laws already contain

“grandfather” clauses.

Waive existing environmental laws.—This

would remove virtually all of the problems

and delays associated with permitting.

However, it would have serious political,

environmental, and social ramifications.

The allocations of the waivers would be

highly controversial. The extent to which

such action would speed the deployment of

an oil shale industry is unclear.
Ch 1–Summary . 37

Water Availability

Oil shale development will affect the hydrologic basins of the Green River, the White

River, and the Colorado River mainstem in

Colorado. These basins are located within the

semiarid Upper Colorado River Basin, which

includes the Colorado River and its tributaries north of Lee Ferry, Ariz. (See figure 7.)

The river system is one of the most important

in the Southwest, It serves approximately 15

million people, and its waters are critical resources for towns, farming, industry and mining, energy development, recreation, and the

environment. In the past, natural flows along

with water storage and diversion projects

have generally been adequate. However, because the region is developing, water supplies

are beginning to be strained, and at some

point in the future a scarcity of water may

limit further growth.

Issues

1

What are the water needs of an oil

shale industry?

Depending on the technologies used, producing 50,000 bbl/d of shale oil syncrude

would consume 4,800 to 12,300 acre-ft/yr of

water for mining, processing, waste disposal,

land reclamation, municipal growth, and

power generation. This is the equivalent of

from 2. I to 5.2 bbl of water consumed per

barrel of oil produced. A l-million-bbl/d industry using a mix of technologies might require 170,000 acre-ft/yr. This is slightly more

than 1 percent of the virgin flow* of the Colorado River at Lee Ferry, or 5 percent of the

water consumed in the Upper Basin at present. * *

‘Virgin flow is the flow that would occur in the absence of

human-related activities.

**For comparison, irrigated agriculture along the White

River and the Colorado River consumes about 549.000 acreft/yr to produce 3 percent of Colorado”s crop production. This is

equivalent to the water needs of a 3.2-m illion-bbl/d oil shale industry.

2

Is there enough surface water available to support a large industry without curtailing other uses?

Surplus surface water will be available to

supply an industry of at least 500,000 bbl/d

through the year 2000 if:

additional reservoirs and pipelines are

built;

and

demand for other uses increases no faster than the States” high growth rate projections;

and

average virgin flows of the Colorado

River do not decrease below the 1930-74

average (13.8 million acre-ft/yr).

Otherwise, surface water supplies would not

be adequate for this level of production unless other uses were curtailed, interstate and

international delivery obligations as presently interpreted by the Government were not

met, or other sources of water were developed. If the reservoirs and pipelines are built,

flows do not decrease, and the region develops at a medium rate (which the States regard as more likely), there should be sufficient surplus water to support an industry of

over 2 million bbl/d through 2000.

In the longer term, surface water may not

be adequate to sustain growth. Surplus water

availability is much less assured after 2000.

If the rivers’ flows do not decrease, and if a

low growth rate prevails, demand will exceed

supply by 2027 even without an oil shale industry. With a medium growth rate, the surplus will disappear by 2013. A high growth

rate will consume the surplus by 2007, again

without any oil shale development. This is a

potentially serious problem for the region,

and its implications for oil shale development

are controversial. On the one side, it is

argued that there is no surplus surface water

and this should preclude the establishment of

an industry. On the other side, it is maintained that the facilities in a major industry

could function for much of their economic

lifetimes without significantly interfering
38 ● An Assessment of Oil Shale Technologies

Figure 7.—The Upper and Lower Colorado River Basins

k-● BOIS E

IDAH O

\

A w

I

lbGreat

Salt

Lake

● .

J’

CHEYENNE

(

MEXIC O

1 t

100 MILES

SOURCE’ C. W Stockton and G. C Jacoby, “Long-Term Surface-Water SUPPIY and Streamfiow Trends In the UPper Colorado Rwer Basin Based on Tree-Ring Analyses,”

Lake Powell Research Project Bulletin No. 18, March 1976, p. 2.
Ch. 1–Summary . 39

with other users, and in any case would use

relatively little water. (A l-million-bbl/d industry would accelerate the point of critical

water shortage by about 3 years if only surface water were used.)

In any event, the analysis of future water

availability is clouded by the uncertain demand schedules of other users and by a longstanding legal conflict between the Upper

and Lower Basin States. It is not clear how

much water is legally available to the Upper

Basin and therefore to the oil shale region,

For example, the calculations presented

above assume that 750,000 acre-ft/yr is sent

from the Upper Basin to Mexico to satisfy a

national delivery obligation incurred under

the Mexican Water Treaty of 1944-45. The

Upper Basin States maintain that they are not

responsible for this obligation and that the

water should be freed for their use. (The

quantity of water in question is equivalent to

the water needs of a 4.4-million-bbl/d oil shale

industry. ) The region’s water problems cannot be solved, however, simply by reallocating surface water supplies from the Lower

Basin States, where water is an equally critical resource. Rather, if growth is to be sustained in both basins, it may be necessary to

increase net supplies by more efficient municipal, industrial, and agricultural use; or to

increase gross supplies by importing water

from other hydrologic basins or possibly by

weather modification. All of these options

would be expensive, will involve environmental impacts, and could encounter legal, political, and institutional opposition.

3

Will the costs of obtaining water limit

the size of the oil shale industry?

Although water is expensive in the West,

the costs of water development will be a small

fraction of the costs of producing shale oil

and therefore should not limit development.

The costs of the most expensive water supply

option, importation from other hydrologic basins, could exceed $1/bbl of shale oil produced. Other supplies would cost less than

$0.50/bbl. This includes the amortized costs

of reservoir and pipeline construction plus

the cost of treating the water to industrial

standards. Development of high-quality

ground water would be least expensive, but

would be limited to specific areas.

4

Will the use of water for oil shale development affect irrigated agriculture?

The effects on farming should be relatively

small, especially when compared with those

caused by competition for labor and by the

purchase of farmlands for municipal growth.

Farm production in the Colorado portion of

the Upper Basin would be reduced if rights to

irrigation water were sold to oil shale developers, but the present developers do not plan

to purchase irrigation water in significant

quantities. In the longer term, if water shortages occur, the industry may have to purchase water, thus displacing farm production. The water laws of all three States allow

the transfer of rights between willing sellers

and purchasers.

5

Will developing water resources for oil

shale have severe environmental impacts?

The environmental impacts will include reduced stream flows, increased salinity in the

river system, and land alterations as a consequence of constructing reservoirs and diversion facilities. These should be small on the

Upper Basin as a whole, but could be large in

some areas, especially where reservoirs will

be built. Fish habitats and recreational activities along the White River are expected to be

the most severely affected. Environmental impacts on the Lower Basin States should not be

substantial.

6

What will be the economic effects of

developing water resources for oil

shale?

The economic losses from decreased flows

and increased salinity could reach $25 million per year for a 2-million-bbl/d industry.
40 . An Assessment OfOil Shale Technologies

These would include the effects of increases

in salinity on farming and of reductions in

river flows on farming and hydroelectric

power production. (It is assumed that the developers do not purchase irrigation water. )

The positive effects of the same industry

would include a gain of several billion dollars

per year in regional income. A simple comparison of the relative gains and losses

should be made with caution, however, because some of the adverse effects would occur in areas that will not enjoy the benefits.

For example, some of the impacts on farming

will be experienced in the Lower Basin.

Policy Options

● Development of a water management system.—The U.S. Bureau of Reclamation

(USBR)* and individual developers and

other users have conducted preliminary

water management studies. No systematic

basinwide evaluation of water manage-

*NOW the Water Power Resources Service,

●

ment alternatives, however, has compared

water supply options with respect to their

water and energy efficiency, their costs

and benefits, and their environmental and

social effects. Such an assessment, involving Federal, State, and local governments;

regional energy developers; other users;

and the general public, may be an appropriate prelude to actions to construct new

water storage and diversion projects. It

could be especially useful in evaluating

and coordinating such controversial options as importation of water. Funding

could be provided by DOI, DOE, or other

agencies. USBR or the Colorado River Compact Commission could manage the study.

Financing and building new reservoirs.—

New reservoirs will be needed if a large industry is to be established. These could be

provided through two mechanisms, First,

Congress could appropriate funds for those

water projects that have already been authorized under the Colorado River Storage

Project Act. (At least one of these, the West
Ch 1–Summary ● 4 1

Divide project, may be suitable for supplying water to oil shale facilities in Colorado. )

Second, legislation could be passed specifying both the construction and funding of

water projects not now authorized for the

region, Alternatively, a State organization

or the oil shale developers themselves

could finance and build the water storage.

A commitment to the facilities would simplify planning for the oil shale industry and

for other regional growth as well. The facilities would be expensive, and their construction might be resisted especially if

general tax revenues were used for this

purpose.

● Minimizing reservoir and diversion siting

problems.—The siting, construction, and

operation of reservoirs and diversion projects could be affected by the Endangered

Species Act, the National Wild and Scenic

Rivers Act, and the Wilderness Act. Problems could be avoided if Congress directed

that the Federal agencies complete a survey of endangered species in the area (including the designation of critical habitats,

if any are found), identify the stream

reaches that will be included in the Wild

and Scenic Rivers System, and designate

the areas to be included in the National

Wilderness Preservation System. The storage and diversion facilities could then be

sited to minimize interference with these

areas. The environmental surveys in particular could be time-consuming and expensive, and expediting the selection processes might involve departing from the purposes of the respective Acts.

● Make water available for oil shale.—

Congress could take steps to assure that

water was supplied to oil shale facilities

from Federal reservoirs, both the existing

ones and any new ones that might be built,

This policy would have to be carefully implemented to avoid interfering with other

users and with the water management policies of the affected States,

The Government could also provide water from Federal reserved rights. Because

of legal restrictions on the use of water

from Federal reservations, the only potential source appears to be the NOSRs in Colorado and Utah. The States might resist allocating this water to an oil shale industry.

For example, the use of water from NOSR 1

is in the early stages of litigation in Colorado.

Supply water through interbasin diversions.—Water shortages in the Upper

Basin could be reduced by importing water

from other hydrologic basins. Options include transporting water directly to the oil

shale region; or to satisfy all or part of the

delivery obligation to Mexico; or to supply

water to the cities in Colorado’s Front

Range Urban Corridor (to replace the water that is presently obtained from the oil

shale region). All of these options could release sufficient water to support a large industry as well as allowing other types of regional growth. However, they all would be

expensive. Furthermore, the study of diversions into the Colorado River Basin is

banned by Federal statute until 1988, This

ban would have to be lifted before the option of supplying water directly to the oil

shale region could proceed. The other alternatives might not be impeded.

Encourage more efficient use of water.—

Financial and technical assistance could

be provided to encourage municipal, agricultural, and industrial water conservation

practices. Likely targets would be agriculture, powerplants, the oil shale facilities in

the development region itself, and the cities

on the eastern slope of the Rocky Mountains that import water from the region,

Large quantities of water could be saved,

although at substantial cost. The implementation of these policies could encounter

resistance. Augmentation methods such as

weather modification could

would entail environmental,

stitutional problems.

be tried but

legal, and inSocioeconomics

The oil shale region in which near-term development is likely to occur is a 3,200 mi

2
—

42 . An Assessment of Oil Shale Technologies

rural area, sparsely populated and with limited transportation. (See figure 8.) In northwestern Colorado, about a dozen towns in

three counties are likely to be substantially

affected. * The population of one of these

counties could increase by as much as sevenfold if a 500,000-bbl/d industry were established and other energy industries expanded.

(See figure 9.) The benefits of this growth

could include increased employment, higher

wages, a broader tax base, community improvements, and stimulation of other businesses. Among the negative consequences

could be a severe housing shortage, strain on

public services and facilities, symptoms of

social stress such as increased crime, and

private-sector dislocations such as smallbusiness failures. Even if the growth is reasonably well controlled, some residents may

perceive a deterioration in their quality of

life. The term “modern boomtown” has been

used to describe communities that have experienced these kinds of growth-related negative impacts.

The region is presently growing and has experienced some adverse effects, although local officials are confident that their communities can deal with additional development.

The oil shale developers have been responsive to the social effects of the industry’s expansion. A sense of increased community

identity and pride is already evident, and is

considered by some as a positive consequence of oil shale development. Whether the

communities will continue to deal successfully with their growth, or be overwhelmed by it,

will depend on a number of factors. Among

these are:

●

●

●

●

●

the absolute numbers and abruptness of

the population influx;

the attitudes of both long-term residents

and newcomers;

past experiences with boom and bust

cycles;

the ability of local political structures to

prepare for population growth; and

the availability of assistance—financial

and other—for mitigation of impacts.

*This summary refers primarily to Colorado. Utah and Wyoming are discussed in ch. 10.

Issues

1

How many people can the region absorb?

Between 1985 and 1990, the physical facilities of the small communities in Garfield and

Rio Blanco Counties that will be most affected

by oil shale development should be able to accommodate up to 35,000 people. This assumes presently planned improvements and

expansions (including the construction of Battlement Mesa, a new town) can be completed.

(See table 6.) This capacity, which is an increase of 250 percent over the present population, is compatible with the growth that will

accompany completion of the two presently

active oil shale projects (they could produce

133,000 bbl/d). The growth accompanying an

industry of up to 200,000 bbl/d could be accommodated if the construction were phased

and if some of the new people lived in adjacent Mesa County. If additional projects were

sited in Utah, the industry could reach

300,000 bbl/d. Major efforts would be necesTable 6.–Actual and Projected Population and Estimated

Capacity of Oil Shale Communities in Colorado

Population

1977 1980 1985-90

Location a

census b projected c capacity d

Garfield County

Rifle . , 2,244

Silt . . . . . . . . . 859

New Castle. . , 543

Grand Valley . 377

Battlement Mesae 

–

Other . . . . . –

4,362

1,211

831

589

198

—

10,000

2,800

1,000

3,000

2,500

1,700

Subtotal f. 4,023

Rio Blanco County

Meeke r ,. 1,848

Rangely . . . : : : : : : : ., 1,871

Other. . . . 1,381

Subtotal . . ., ... 5,100

7,191

2,779

2,223

1.542

6,544

Total . . . . . . . . ., 9,123 13,735

21,000

6,000

6,000

2,000

14,000

35,000

a~es not Include Mesa or Moffat Counties both of which are more dlslant from the area Of development

bAcluals from a special U S census

cEnd.of.lhe.year projections by the Colorado West Area COUflCIl of Governments

dEstlmated by OTA from various plarlrllrlg and needs assessments documents, assumes COM@

hon of currently planned protects (e g housing, waler and sewer system expanwons street

and road Improvements, elc )

eA new [own, cons[ruc(lon anhclpaied 10 begin In the early 1980 s

flncludes only [he Immediate 011 shale Wlnlty

SOURCE Off Ice of Technology Assessment
Ch. 1–Summary 43

Photo crecfff OTA stalt

Marker indicating original site of the

Northern Ute Indian Reservation near Meeker, Colo.

sary to assist the small communities in Utah if

sudden, rapid growth accompanied industry

expansion. * In Colorado, additional growth

could be accommodated if some of the presently planned facilities for workers and their

families were constructed quickly. For example, according to current schedules, Battlement Mesa will house 1,500 residents in its

first phase of development (ultimate plans

call for a maximum of 7,000 units for 21,000

people). If construction were accelerated,

more could be housed in a shorter period of

time.

The Colorado communities expect to be

able to assimilate more residents because

they have been preparing for an oil shale industry for nearly 10 years. Local interests

have participated in broadly structured task

forces that assist in planning and managing

growth. The industry has supported these

groups. It also has aided local governments,

has adopted programs to reduce negative im-

*Plaming for oil shale impacts in Utah has not been as extensive as in Colorado for a number of reasons. Most important

is that mitigation funds from a major source (the State’s share

of bonus and lease payments under the Mineral Leasing Act)

have been held in escrow pending settlement of the ownership

questions.

pacts, and has invested in housing and in the

land for Battlement Mesa. The communities

have been developing municipal facilities and

services. New housing is being built, businesses expanded, and health care extended.

The State has appropriated more than $40

million for over 75 projects, and the Federal

Government has contributed technical assistance. These efforts have prepared the towns

for a reasonable number of new residents.

2

Will oil shale development cause community disruption?

Not enough is known about the causes of

boomtowns to be able to predict the exact

threshold beyond which oil shale development would lead to serious impacts. However, establishing a l-million-bbl/d industry

by 1990 would exceed the capacity of all of

the communities, and stressful living conditions would be inevitable. It is known that the

possibility of disruption will be influenced by

the location of the growth, by the total number of newcomers, by the rapidity with which

they arrive, and by the ability of the communities to prepare for the influx. Some

towns in Wyoming have successfully accommodated expanded coal development, while

others that have experienced the same kinds

of growth, and have had access to the same

preventive programs, have suffered for long

periods. The social and economic problems

accompanying oil shale growth could be aggravated if development is concurrent with

expansions in other industries. The region is

already experiencing some rapid growth,

particularly from coal mining.

3

What role can industry play in dealing

with the socioeconomic consequences

of oil shale development?

Industry has contributed financial and

technical assistance to the growth management effort. The Mineral Leasing Act of 1920

allows the affected States to share in the pro

ceeds from leasing programs; Colorado received nearly $74 million as its share of the

bonus payments for Federal tracts C-a and
44 ● An Assessment of Oil Shale Technologies

I

Y

L— — —1

I

L .— I

I

I

I

I

I

I

I

I

I

I

I

I

I

I

I

I

I

I \\

\ I

I

I I

I

I
Ch 1–Summary ● 4 5

Figure 9.— Projected Growth of Counties in Northwestern Colorado From Oil Shale Development, 1980-2000

190,000

180,000

170,000

160,000

150,000

140,000

130,000

120,000

110,OOO

100,OOO

.5 90,000

~

# 80,000

70,000

60,000

50,000

40,000

30,000

20,000

10,000

*

MESA COUNTY /

e GARFfELD COUNTY

/ RIO BLANCO COUNTY

o

1 m n 1 1 9

1977 1980 1985 1990 1995

1977-actual t30mdation from special U.S. census

1980-ZOOO+ojections assun& oil shale development with a production I@/el of

500,000 BPD by 1990 and 750,000 BPD by 1995 combined with other

energy industry (e.g., coal, electric generation, oil & gas) expansion.

SOURCE: Colorado West Area Council of Governments.
46 . An Assessment of Oil Shale Technologies

C-b. From this fund has come the $40 million

for community improvements in Colorado’s oil

shale area. The lessees and other developers

have contributed additional money and support for planning efforts and other improvements. If more projects are initiated by leasing, more funds will become available. If, on

the other hand, the new projects are on private land or on land-exchange parcels, developer participation will be voluntary.

It is in the developers’ best interest to participate. The benefits of such involvement are

illustrated by the experience of the Missouri

Basin Power Cooperative in installing a powerplant on the Laramie River in Wyoming.

The developer invested $21 million in mitigation efforts through grants and revenue guarantees to towns, counties, and public agencies; by inkind services; with bond guarantees; and with other types of assistance. The

company believes that it saved about $50 million in project costs by reducing employee

turnover and avoiding construction delays.

Furthermore, all but about $3 million of the

initial outlay will be recovered. Ultimately,

the amount spent for mitigation may be less

than 1 percent of the total cost of the plant.

4

What role can the Federal Government

play?

The region should be able to accommodate

growth from the presently active projects,

and no new Federal initiatives appear to be

needed unless an industry larger than

200,000 bbl/d is desired before 1990. Although some towns and counties have experienced problems in obtaining funds for specific improvements, the existing growth management mechanisms have been successful to

date. They involve a cooperative effort among

local citizens; municipal and county governments; regional, State, and Federal agencies;

the oil shale developers; and other energy industries. These efforts must not be interrupted if the communities are to continue to

be able to deal with their growth problems.

Increased Federal involvement will be required if production of over 200,000 bbl/d is

attempted before 1990. In this case, a coordinated growth management strategy would be

required to ensure that financing was available for building houses, that public facilities

and services could be provided, that basic

needs could be met, and that a reasonably

stable work force could be maintained for the

industry. Many Federal, State, local, and private organizations, operating in many areas

and at all levels, would have to be involved to

cope with sustained, rapid growth.

Policy Options

The courts have affirmed that, under the

National Environmental Policy Act of 1969,

the Federal Government must examine the social impacts of its major actions. The problems accompanying recent expansion of energy industries have led to a call for more Federal involvement. The extent and nature of

this involvement, however, are controversial.

On the one side it is argued that socioeconomic changes are the inevitable results of industrial development and are, at most, State

and local problems. On the other side the

position is taken that national energy requirements are the root causes of negative

impacts and, for reasons of equity, active

Federal participation in their amelioration is

appropriate. Some examples of Federal assistance programs arising from the latter

position are the Coastal Zone Management

Act Amendments of 1976, which are directed

at communities experiencing impacts from oil

and gas development on the Outer Continental Shelf, and the Powerplant and Industrial

Fuel Use Act of 1978, which established the

Impacted Area Development Assistance Program (the sec. 601 program) to aid areas affected by coal and uranium development.

With respect to the socioeconomic problems of oil shale development, there are three

policy options available. These options could

be considered in bills that deal with the effects of all types of energy development; or

they could be considered along with the impacts of similar energy forms (e.g., synthetic

fuels); or they could be treated solely as the

consequences of oil shale development.
Ch 1–Summary . 47

●

●

Continuation of present policies.—Federal

assistance could continue to emphasize

technical and financial aid. Revenues

channeled through established programs

would be the major mechanism, but other

programs not now designed to deal specifically with impact mitigation could be redirected to assist the communities. Congressional action would primarily involve

continuing or increasing appropriations.

Increased growth management involvement. —New emphasis could be given to increased regulation. For example, social

and economic effects could be made criteria for selecting Federal tracts to be offered in leasing programs, Alternatively,

mandatory participation of the lessees in

mitigation efforts could be included in the

lease terms. Greater Federal involvement

in monitoring and in technical assistance is

another possibility. Congressional action

could include amending existing laws,

passing new legislation, or exercising oversight powers.

Extension of impact mitigation programs.

—Existing programs could be expanded or

new ones adopted. Amendments to extend

the assistance provided by the Powerplant

and Industrial Fuel Use Act of 1978 are

currently under consideration by Congress. * Among their features are the authorization of grants, loans, loan guarantees, and payment of interest on loans. An

expediting process for providing assistance through current Federal programs is

proposed, as is an interagency council to

coordinate Federal efforts. This assistance

is directed to the effects of major energy

developments, which could include oil

shale.

*S. 1699.
CHAPTER 2
——

CHAPTER 2

Introduction

At the request of the Senate Energy and

Natural Resources Committee, OTA has

studied the history and status of efforts to develop the oil shale resources in Colorado,

Utah, and Wyoming. The Committee’s request

called for a complete assessment of shale oil

recovery technology in general and of the current Federal Prototype Oil Shale Leasing Program in particular.

The remaining chapters of this volume deal

with the general context of oil shale development, The following subjects are discussed,

● Chapter 3— “Constraints to Oil Shale

Commercialization: Policy Options to Address These Constraints’ ’—describes

some alternative objectives that might

be pursued to control the growth of the

industry. Four development scenarios

are used as a framework for identifying

the obstacles that might inhibit or preclude the establishment of industries of

various sizes before 1990, (This analysis

is based largely on information contained in the subsequent chapters.) The

congressional policies that might be directed to these obstacles are then discussed. Given these obstacles and policies, the relative degree to which each

scenario would attain each objective for

development is then described.

● Chapter 4—’’Background"-describe

the oil shale region, discusses the resources, outlines the processes for extracting shale oil and other materials,

and summarizes the history and status

of development efforts in the United

States and abroad.

 Chapter 5—” Technologies ’’—describes

the mining and processing methods that

could be employed to recover shale oil

and to refine it to finished fuels. The advantages and disadvantages of the various processes are presented and their

status summarized. Research, development, and demonstration needs are iden-

●

●

●

tified, and some possible Government

policies are discussed.

Chapter 6 — “Economic and Financial

Considerations”- deals with the costs of

recovering shale oil and with the risks

that inhibit oil shale projects. These

risks include the absence of certainty

about the capital cost estimates for commercial plants, the future of conventional oil prices and their impact on

shale oil prospects, and the adequacy of

U.S. equipment manufacturing and construction and design capacity for rapid

deployment of a large industry. The need

for Government subsidies is evaluated.

A number of financial incentives are examined for their influence on the breakeven price for syncrude from shale oil,

the probability of project financial loss,

and the net cost to the Government. No

explicit attempt has been made to compare the economics of shale oil with that

of other synthetic fuels nor with possibilities such as conservation or solar energy. Such a comparison is outside the

scope and mandate of the present study.

The chapter assumes that the commercial prospects of shale oil will continue

to be determined until the end of this

century by its cost and price relationship

with conventional oil.

Chapter 7—’’Resource Acquisition”’—

discusses the characteristics of the oil

shale lands that are owned by the Federal Government and by private parties.

The possible need for involving additional Federal land is related to the level of

shale oil production that is desired, and

to the provision of other types of encouragement, such as subsidies, The principal mechanisms for providing such land

—leasing and land exchange—are described and evaluated.

Chapter 8—’’Environmental Considerations”—discusses the implications of de51
52 ● An Assessment of 0il Shale Technologies

●

●

velopment for the environment and for

the workers. Separate discussions are

provided for the potential effects on air

quality, water quality, land characteristics, and the health and safety of the

workers. In each case the legal framework governing the effects is described,

the potential impacts of development are

discussed, the proposed control technologies are evaluated, and the areas of uncertainty are identified. A discussion is

also included of the procedures that

trol the issuance of environmental

mits for oil shale projects. Possible

ernmental policy responses are

cussed for each area of concern.

conpergovdisChapter 9—”Water Availability”-

deals with the implications of oil shale

development for the region’s scarce

water supply. The water resources

themselves are described, and the institutional framework that governs their

allocation is discussed. Water requirements of conventional users are projected to the year 2000 and compared

with the physical resources to determine

if surplus water might be available to

support an oil shale industry. Mechanisms and policies for making additional

water available are discussed.

Chapter 10—” Socioeconomic Aspects”

—deals with the effects of development

on the small, rural communities that

characterize the oil shale region. The

population increases that might accompany development are estimated, and

the abilities of the communities to accommodate this growth are evaluated,

The nature of the potential impacts is

discussed and possible policy responses

are presented.

Volume II presents a history of the current

Federal Prototype Oil Shale Leasing Program,

together with an analysis of a prior leasing

attempt which, although unsuccessful, affected the character and conduct of the Prototype Program. The problems encountered in

the Program since its inception are discussed,

and the status of development on the lease

tracts is described, The ability of the Program to achieve its original objectives is evaluated.

Each aspect of this assessment is based on

recent publications, on contractor reports

prepared for OTA, and on the independent investigations of the project staff. The results

are current as of February 1980. It is important to note that the oil shale situation is in a

state of flux and that new developments may

significantly alter the status and outlook of

the industry and affect the accuracy of any

conclusions presented herein.
CHAPTER 3

Constraints to Oil Shale

Commercialization: Policy Options to

Address These Constraints
Contents

Page Table No.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 8. Some Potential Oil Shale Development

Approaches to Development . . . . . . . . . . . . . . 55 Sites in Colorado and Utah . . . . . . .. , . .

Possible Objectives. . . . . . . . . . . . . . . . . . . . . . 55 9. Some Production Alternatives for the

Possible Futures . . . . . . . . . . . . . . . . . . . . . . . . 57 Scenarios . . . . . . . . . . . . . . . . . . . . . . . . .

10, Constraints to Implementing Four

Requirements for Development. . . . . . . . . . . . 57

Constraints to Development. . . . . . . . . . . . . . . 60

Technological . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Economic and Financial . . . . . . . . . . . . . . . . . . 62

Institutional . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Environmental . . . . . . . . . . . . . . . . . . . . . . . . . 64

Water Resources . . . . . . . . . . . . . . . . . . . . . . . 64

Production Targets .. ... .~ . . . . . . . . ,.

11. Actual and Projected Population and

Estimated Capacity of Oil Shale

Communities in Colorado. . . . . . . . . . . . .

12. Subsidy Effect and Net Cost to the

Government of Possible Oil Shale

Incentives. . . . . . . . . . . . . . . . . . . . . . . . .

Socioeconomic . . . . . . . . . . . . . . . . . . . . . . . . . 65

Policy Considerations. . . . . . . . . . . . . . . . . . . . 66

Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Economic and Financial . . . . . . . . . . . . . . . . . . 67

Institutional . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Environmental . . . . . . . . . . . . . . . . . . . . . . . . . 74

Water Resources . . . . . . . . . . . . . . . . . . . . . . . 75

Socioeconomic . . . . . . . . . . . . . . . . . . . . . . . . . 78 List of Figures

Scenario Evaluation. . . . . . . . . . . . . . . . . . . . . 80

ListofTables

Figure No.

10. Some Present and Potential Oil Shale

Development Sites in Colorado and Utah

‘I’able No. Page 11. The Relative Degree to Which the

7. Requirements for the Production Production Targets Would Attain the

Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . 58 Objectives for Development. . . . . . . . . . .

Page

60

61

61

65

68

Page

59

81
——

CHAPTER 3

Constraints to Oil Shale Commercialization:

Policy Options to Address These Constraints

Introduction

This chapter describes the requirements

for establishing an oil shale industry by 1990,

discusses potential constraints to its establishment, and presents policy options to address them, The effects of oil shale development on the physical, social, and economic

environments are discussed in this chapter

only to the extent that they are obstructions

to development, Not all of these effects hinder

development, and those not judged to be barriers are not included here, For instance, filling a canyon with spent shale constitutes an

irrevocable alteration to the locale’s appearance; but does not, by itself, bar development.

The many important issues not identified

as constraints are summarized in chapter 1

and dealt with at length in the subsequent

chapters. Comprehensive analyses are presented of the economics of oil shale development (ch. 6), and of the effects production

could have on the air, land, water, worker

health and safety (ch. 8), on regional water

availability (ch. 9), and on the social and

economic structure of the region’s communities (ch. 10). As the next section explains,

these considerations all bear on decisions

about the future of oil shale, even though they

may not be discussed here as barriers to its

development.

This chapter is organized as follows:

●

●

●

●

●

Alternative objectives for development

are identified. To provide a framework

for analysis, production scenarios are

presented that might result from pursuing different combinations of these objectives.

The requirements for investment capital, water, labor, and a favorable combination of marketability and land availability are summarized for the production targets of the scenarios.

The constraints to achieving the targets

are identified.

Some policies for dealing with the constraints are discussed.

Given the requirements, constraints,

and policies, the scenarios are evaluated

with respect to the relative degree they

could attain each of the objectives for

development.

Approaches to Development

Possible Objectives

Whether, how, and to what extent an oil

shale industry should be developed will ultimately be a political decision. The past efforts of diverse groups—Government agencies, private firms, public-interest advocates,

and environmental conservationists—to influence public policy on behalf of their goals

will undoubtedly continue, These interests

have different perceptions about the relative

importance of certain basic values. The preferences they show for particular types and

rates of development reflect these differences. Some of the varied, and often competing, objectives for development are discussed

below.

To position the industry for rapid deployment.—The supporters of this objective acknowledge that more information is needed

about oiI shale technologies if production is to

be expanded rapidly in times of national

need. Many techniques and sites would be re55
.

56 ● An Assessment of Oil Shale Technologies

quired to answer most of the remaining questions about the technical, economic, and environmental implications of full-scale development. Demonstration plants to allow the

evaluation of a full spectrum of technologies

would be needed. Incentives and additional

Federal land might be made available to encourage private sector experiments. All programs would be designed to maximize information generation. Growing international

tensions, with the consequent potential for severe disruptions in oil supplies, provide a rationale for this objective.

To maximize domestic energy supplies.—

This objective emphasizes the rapid development of a large industry, and has both economic and national security implications. The

benefits include reduced reliance on oil imports, improved balance of payments, stimulation of private capital investment, increased employment, and lower energy costs

over the long term. Policies supporting this

objective emphasize the encouragement of

the oil shale industry and the removal of restraints on its establishment. Among these

policies might be additional Federal leasing,

substantial economic incentives, waiving of

environmental laws, and direct Government

involvement in the production of shale oil.

To minimize Federal promotion.—This objective is supported by those who oppose Government involvement in the free market and

with private enterprise. Other supporters

stress that oil shale should not be promoted at

the expense of other energy sources. In both

cases, the advocates believe the industry

should develop in response to traditional market pressures and opportunities and without

the active financial participation or support

of the Government. Policies that relate to this

objective emphasize R&D, with particular attention to technological and environmental

uncertainties; this would provide a basis for

comparing oil shale with other energy alternatives and for developing regulations. Planning for future programs to mobilize the industry would be carried out; programs such

as leasing, land exchanges, and financial incentives would not.

To maximize ultimate environmental information and protection.—The desirability of

maintaining the existing environmental quality of the oil shale region and its environs is

emphasized by the supporters of this objective. They also believe that oil shale should

not be promoted more than other potential energy sources that could be less harmful to the

environment. They would prefer that development proceed slowly, if at all, until its potential impacts have been determined and

control strategies designed and thoroughly

tested. The policies in this case would emphasize the enforcement of existing environmental regulations, the siting of any new plants to

minimize their impacts, continued monitoring

and R&D to provide information for the promulgation of new regulations, and public education and participation in decisions.

To maximize the integrity of the social environment.-This objective emphasizes personal and community needs. Its supporters

would prefer to see a slow but steady developmental pace in order to avoid the potentially disruptive effects of too-rapid growth.

Well-planned and coordinated growth management is essential to meet this objective.

Policies would stress the involvement of local

residents in the growth management process,

efforts to avoid exceeding the growth capacities of the communities, the funding of needed

community improvements, and the allocation

of responsibilities for both growth management and impact mitigation among the oil

shale developers, and the local, State, and

Federal governments.

To achieve an efficient and cost-effective

energy supply system.—Supporters of this

objective emphasize the importance of providing a mix of energy alternatives with the

best overall ratio of costs to benefits. They

stress the need to position the industry and its

technologies for long-term profitable operations. Future expansions could then be supported with internally generated financing.

The related objectives of efficient development of the resource and balanced environmental and social protection are also empha-
Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints . 57

sized. The proposed pace of development

would allow thorough evaluation of the technologies so that the elements of production

(land, labor, capital, water, energy, and incremental environmental changes) could be

used most efficiently if a large-scale industry

were created. Policies would give attention to

incentives that left intact a degree of managerial risk, to thorough testing of diverse

technologies and sites, and to advanced R&D

that would provide a basis for comparing oil

shale with its alternatives. These policies

would not require a commitment of funds and

resources to the exclusion of other potential

energy sources.

Possible Futures

The Government, in preparing its policies

for oil shale development, is bound to consider and weigh along with others, all of the objectives discussed above. For example, the

Government is responsible for protecting the

Nation from external threats of interruptions

in the supply of essential raw materials like

petroleum. This responsibility, when coupled

with the Government’s ownership of the richest oil shale deposits, would tend to encourage the rapid development of public lands. On

the other hand, the public trust requires that

these resources be developed with good management practices, with minimum waste and

inefficiency, and with equitable treatment of

the affected groups and regions. This mandate would lead to a moderate pace of development. Furthermore, the Government is required by its own laws to protect the environment of the oil shale region and to consider

the socioeconomic consequences of each of

its major actions. These mandates would lead

to slow, carefully managed development.

Depending. on the emphasis given to the

various development objectives, a number of

future industries could be postulated, from

none at all, to the production of several

million barrels of shale oil per day. Four

scenarios, based largely on shale oil production targets for 1990, will be considered as a

framework for evaluating the requirements,

the effects, and the policy implications of development. These are:

Production target of

Scenario shale oil (bbl/d)

Requirements for Development

●

●

●

●

●

●

●

●

●

●

●

The

and

1 . . . . . . . . . . . . . . . 100,000

2 . . . . . . . . . . . . . . . 200,000

3 . . . . . . . . . . . . . . . 400,000

4 . . . . . . . . . . . . . . . 1,000,000

In order to proceed, each project will need:

land,

water,

adequate mining and processing technologies,

access to markets,

a favorable economic outlook,

investment capital,

compliance with environmental regulations,

design and construction services,

equipment and construction materials,

construction and operating labor, and

housing and community services.

requirements of the scenarios for design

construction services, equipment, capital, water, and labor are shown in table 7.

Also shown are the numbers of new residents

who will have to be accommodated by the region’s communities. Water requirements increase directly with the level of production

because the amount each plant will need is

independent of the others. Ranges are given

because different technologies having different water requirements could be used. Because of the assumptions made about the

phasing of construction, the labor requirements do not always increase directly with

the level of production. In addition, whereas

scenario 4 produces 2.5 times more oil than

scenario 3, it requires from 2.5 to 4 times

more capital. This cost escalation is attributable to the large demands for labor, materials, and equipment for 1 million bbl/d.

i. - ,1-
. —

58 . An Assessment of Oil Shale Technologies

Table 7.–Requirements for the Production Scenarios

Requirements

Resource Scenario 1 Scenario 2 Scenario 3 Scenario 4

Institutional

Design and construction services, % of 1978 U.S. capacity needed each year Minimal Minimal 12 35

Plant equipment, % of 1978 U S. capacity needed each year Minimal Minimal 6-12 15-30

Economic and financiala

Loans, $ billion ., ., $09-1.35 $1,8-2,6 $36-4. 2 $90-13 5

Equity, $ billion ., ., 2.1-315 4.2-5.9 84-9,8 21.0-31 5

Total, $ billio n ,,, ., ,, 30-4,5 6.0-8,5 12,0 -14,0 30,0 -45.0

Annual, $ billion b 06-0,9 1.2-1 7 24-2.8 6.0-9,0

Water availability

Water, acre-ft/yrc ., ., ., ., ., 9,800-24,600 19,600-49,200 39,200-98,400 100,000-250,000

Socioeconomic

Workers . ., ,,, 5,600 8,800-11,200 17,600-22,400 44,000-56,000

New residents requiring housing and community services ., 23,000 41,200-47,200 82,000-95,000 118,000-236,000

aTh!rd-quarler 1979 dollars

bMaxlmum annual requlrernerl[s for a 5-year ConstructIon period

cAssumes 4900.12300 acre.ft/ yr for produchon of 50000 bbl/d Of shale oll syncrude

dAssumes I 200 ~onstructlon ~orker~ and 1 600 operators per 51J OO&bbl/d plant Multlpllers used for [o[al Increase = z 5 x (Corlstruct[r)f) workers ~ + 55 x (O~eralOrS) Ranaes reflect adjustments In

conslruct!on work forces assuming phasing ot plant construchon

SOURCE OftIce ot Technology Assessment

All projects share certain critical requirements that do not appear in the table. First,

permits will have to be obtained. Their number and nature will depend on the project’s

location, on the technologies used, and on

whether the site is privately owned or is controlled by either the Federal Government or a

State. In order to obtain the necessary permits, the firm will have to demonstrate its

ability to comply with the regulations promulgated under the Clean Air Act, the Clean

Water Act, the Resource Conservation and

Recovery Act, and other laws. Second, each

developer must have a transportation system

to move the products and byproducts to markets. Third, a project must be economically

feasible. That is, market conditions must appear favorable based on reliable cost estimates, contractor services and equipment

must be available at reasonable costs, compliance with existing and future regulations

must be possible, and the permitting process

must not unduly delay a facility’s construction and operation. Finally, the developer

must have land—either public, private, or a

combination of both.

The interrelationship between the requirements for land, marketability, and a conducive regulatory environment can be illustrated by considering how some projects

might be combined to achieve the production

goals of the scenarios. The locations of tracts

on which projects could be sited are shown in

figure 10. The ownership of the tracts and the

status of their development are shown in

table 8. Many other tracts exist that could be

developed, thus the list of possible sites in

table 8 is far from complete. It does not include any tracts in Wyoming, for example,

because no large-scale projects have been

proposed for that State. The only Stateowned land shown is the tract leased for the

Sand Wash project. Utah has additional land

that could be leased. Also, the federally

owned tracts shown total only about 160,000

acres—roughly 3 percent of the public’s oil

shale land in Colorado and Utah.

In table 9, potential projects on these

tracts are combined in alternative ways to

reach the production targets of the scenarios.

The projects are assigned to four categories:

active projects, suspended projects, projects

needing additional Federal land, and projects

on other private tracts. Three alternatives

are shown for scenarios 1 and 2. The first

alternative represents the completion and

possible extension of presently active projects. In the second, it is assumed that two

presently active projects are canceled, leaving a production shortfall. This is eliminated
Ch. 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints 59

Figure 10.—Some Present and Potential Oil Shale Development Sites in Colorado and Utah

\ \ \ I

Green

Rwer

)

2

0

1

UINTA BASIN (

I

I

/

● Rangely

\

0

3

->HicoLoRADo u

1 Geokmetlcs (Geokmetlcs T/S)

2 NOSR 2

3 Texaco

4 Tosco (Sand Wash)

5 Tracts U-a & U-b (Wh/te Rwer)

6 SOHIO Cleveland Cliffs

7 Mobil Equity

8 Tract C-a (FfIo Blanco)

9 Super$or(Super/or pro/ect)

LEGEND

10 EXXON (Love Ranch)

11 Multi Mineral (Integrated MIS)

12 Tract C-b (Cattredra/ Bluffs)

13 EXXON (WI//ow Creek)

14. Mobd ARCO Equity (Equrty T/S)

15 Chevron

16. Texaco

17 Getty

18 SOHIO Cleveland Cliffs

19 Cltles Serwce

20 ARCO

21 Occidental (Logan Wash)

22 Chevron

23 Umon

24 Colony (Colony prolecf)

25 Umon (Long Ridge)

26 Mobil

27 NOSR 1 & 3

I ~ Ed~eoftheodshaledeposW., - Stream: ● Towns

SOURCE Office of Technology Assessment

by the reactivation of presently suspended

projects in response to substantial improvements in the economic and regulatory climate. In the third alternative, the shortfall is

eliminated by the commitment of additional

Federal land. Only two alternatives are

shown for scenarios 3 and 4. The first incorporates the completion and extension of present projects and the development of new projects on private land, in response to favorable

economic and regulatory conditions. The second alternative assumes that less favorable

conditions exist, but that Federal land is

made available.

In structuring the alternatives it has been

postulated that the more advanced projects

will respond to improved conditions before

the less advanced. However, it should be understood that the industry patterns shown

are in part arbitrary, and probably extreme

in some cases. For example, the scenario 4

alternatives require either new projects on

private land or new Federal tracts. In reality,

an industry created under this scenario

would more likely involve both types of land.

Also, the combinations of projects shown are

only illustrative; they

recommendations of

technologies, projects,

do-not represent the

specific developers,

sites, or policies.
60 ● An Assessment of Oil Shale Technologies

Table 8.–Some Potential Oil Shale Development Sites in Colorado and Utah

Announced

Site Location Ownership Developer Project title Status production targetb

1 Utah

2 Utah

3 Utah

4 Utah

5 Utah

6 Utah

7 Colorado

8 Colorado

9 Colorado

10 Colorado

11 Colorado

12 Colorado

13 Colorado

14 Colorado

15 Colorado

16 Colorado

17 Colorado

18 Colorado

19 Colorado

20 Colorado

21 Colorado

22 Colorado

23 Colorado

24 Colorado

25 Colorado

26 Colorado

27 Colorado

State

Federal a

Private

State

Federal c

Private

Private

Federal c

Private

Federal

Federal

Federal c

Federal

Private

Private

Private

Private

Private

Private

Private

Private

Private

Private

Private

Private

Private

Federal a

Geokinetics Geokinetics TIS

Navy/DOE NOSR 2

Texaco None

Tosco Sand Wash

Phillips/Sundeco/ SOHIO White River

(tracts U-a & U-b)

SOHIO/Cleveland Cliffs None

Mobil/Equity None

Standard of lndiana/Gulf (tract C-a) Rio Blanco

Superior Oil

EXXON

Multi Mineral

Occidental/Tenneco (tract C-b)

EXXON

Mobil/ARCO/Equity

Chevron

Texaco

Getty

SOHIO/Cleveland Cliffs

Cities Service

ARCO

Occidental

Chevron

Union

Colony Development

Union

Mobil

Navy/DOE

Superior

Love Ranch

Integrated MIS

Cathedral Bluffs

WIIIOW Creek

BX

None

None

None

None

None

None

Logan Wash

None

None

Colony

Long Ridge

None

NOSR 1 & 3

Small-scale field tests underway of TIS method At least 2,000 bbl/d

No development, None

No development, None

Baseline monitoring and mine planning 50,000 bbl/d

underway,

Suspended pending resolution of land- 100,000 bbl/d

ownership issue.

No development, None

No development, None

Preparing for MIS retort demonstration, 76,000 bbl/d

Suspended pending approval of land exchange 11,500 bbl/d

proposal.

Proposal submitted for land exchange, 60,000 bbl/d

Negotiations begun for use of USBM mine shaft ,50,000 bbl/d

Preparing for MIS retort demonstration. 57,000 bbl/d

Proposal submitted for land exchange, None

Small-scale field tests underway of Equity’s None

TIS method,

No development. None

No development. None

No development. None

No development, None

No development, None

No development, None

Small-scale field tests of Oxy’s MIS technique. Few hundred bbl/d

Results wiII support Cathedral Bluffs project.

No development. None

No development, None

Suspended because of economic and 46,000 bbl/d

regulatory uncertainty,

Suspended because of economic and 75,000-150,000

regulatory uncertainty, bbl/d

No development, None

Development management plan being prepared, None

‘Naval Oil Shale Reserve

bBased on developers prehmlnary Plans

cLeased under the Federal Prototype 011 Shale Leasing pro9ram

SOURCE Ofhce of Technology Assessment

Constraints to Development

The factors that will hinder or even prevent reaching the production goals of the

OTA scenarios are shown in table 10. They

were identified by analyzing the scenario requirements, given the present state of knowledge and the current regulatory structure.

Constraints judged to be “moderate” will

hamper, but not necessarily preclude, development; those judged to be “critical” could

become major barriers. When it was inconclusive whether or to what extent certain factors would impede development, they were

called “possible” constraints. Only those that

could be addressed by Federal action are

shown.

Each potential constraint is important by

itself, but the combined effect that more than

one might have on a scenario’s realization

should also be considered. Thus, a moderate

restriction on the availability of land together

with one on permitting could preclude investor participation. Similarly, an inadequate

community water supply for the workers and

their families coupled with a moderate restriction on the availability of water for a

project could become a critical constraint.
Ch 3–Constraints to Oil Shale Commercialization Policy Options to Address These Constraints ● 61

Table 9. –Some Production Alternatives for the Scenarios (barrels of shale oil per day)

Possible projects

Active projects

RIO Blanco

Cathedral Bluff s

Sand Wash

Geokinetics

Equity BX

Suspended projects

Union Long Ridge

Colony

White River

Projects needing more Federal land

Superior

Multi Minera l

EXXON Love Ranch

EXXON WIIIOW Creek

NOSR 1

NOSR 2

New lease tracts

Other private tracts . . . . . . . . . . . . .

Scenario 1 Scenario 2 Scenario 3

alternatives alternates alternatives

Scenario 4

alternates

1 -A 1 -B 1 -c 2-A 2-B 2-c 3-A 3-B 4-A 4-B

76,000

57,000

50,000

2,000

—

—‘ }

—

—

—

—

—

76,000

57,000

50,000

76,000

57,000

50,000

21,000

150,000

46,000

I 50,000”

57,000

2,000

- }

—

11,500

50,000

60,000

69,500

—

76,000 150,000’

57,000 100,000

50,000 50,000

— — —

57,000

—

2,000

—

141,000

—

57,000 57,000 57,000 — — —

2,000 2,000 )2,000

. } — — 17000 20,000 40,000 I

150,000 150,000

46,000 46,000

100,000 100,000

—‘} —

41,000 :

—

—

— —

—

—

—

—

—

—

11,500

29,500

—

—

—

—

—

—

—

—

—

—

—

—

—

—

—

11,500

50,000

60,000

— 11,500

— 50,000

60,000

—

—

‘} 242,000

—

— 19,500

— 501,000 – —

Tota l 185,000 100,000 100,000 200,000 200.000 200,000 400,000 400,000 1,000,0001,000,000

‘Possibly ln~ol,,ng open PII mlmng and of flracf hasfe d(sposal

SOURLE Of’l~e of Techno ogy Assessmeof

Table 10.–Constraints to Implementing Four Production Targets

1990 production target, bbl/d

100,000 200,000 400,000 1 million

Possible deterring factors Severity of Impediment

Technological

Technological readiness

Economic and financial

Availability of private capital

Marketability of the shale 0 1 1

Investor particlpation

Institutional

Availability of land

Permitting procedures

Major- pipeline capacity

Design and construction services

Equipment availability

Environmental

Compliance with environmental regulations.

Water availability

Availability of surplus surface water

Adequacy of existing supply system s

Socioeconomic

Adequacy of community facilities and service s

None None None Critical

Moderate

Possible

Possible

None

Possible

None

None

Possible

Possible

None

Possible

Possible

None

None

None

None

None

None

None

None

None

None

Possible

Possible

None

Moderate

Moderate

Critical

Critical

Critical

Critical

Critical

None None Possible Critical

None

Critical

Possible

Critical

None

None

None

None

None Moderate Moderate Critical

SOURCE Olflce of Technology Assessment
62 ● An Assessment of Oil Shale Technologies

Technological

Technological readiness will not hinder the

first three scenarios because the relatively

slow pace of their development will allow normal scaleup practices to be followed. Scenario 4 presents a different case. To achieve

its goals, the construction of almost all plants

will have to be started before 1984, which

does not allow sufficient time either to undertake much preliminary experimentation, or to

gain experience by modular demonstration or

by the operation of pioneer facilities. In addition, the necessity to standardize the plant

designs could have a number of unfortunate

consequences. Among these could be that erroneous equipment specifications and other

design flaws would be duplicated, and plant

components would be unreliable and shortlived. Unanticipated environmental problems

caused by the failure of pollution control systems could delay the projects, increase their

costs, and have severe ecological consequences. Unreliability and less than optimum

performance could prevent some plants from

ever operating at their design capacity.

Economic and Financial

For a project to be economically viable and

attract investors, it needs to have a favorable

combination of market conditions, of construction and operating costs, and of resources such as land, water, and workers.

The necessary permits must also be readily

obtainable. Tradeoffs are possible. Thus, if

adequate resources are available, and permits obtainable without undue expenditure of

time and money, then somewhat less favorable market conditions might be acceptable.

Until late in 1979, it was assumed that sizable subsidies would be needed to offset unfavorable market conditions. However, in January 1980, developers estimated that they

could profitably market shale oil syncrude at

$35 to $40/bbl. * The present selling price for

similar high-quality crudes is within this

*Whether shale oil requires subsidy for profitable marketing

depends in part on the discount rate developers are assumed to

require in order to proceed. See table 12,

range (e.g., Wyoming Sweet sold in January of

1980 for a posted price of around $35/bbl).

The “spot” or noncontract prices for these

crudes are considerably higher ($40 to $52/

bbl). Industry sources and petroleum economists expect the world price of crude to continue advancing in the future. Consequently,

in a narrow economic sense shale oil appears

to have reached parity with conventional

crude.

The situation calls into question the need

for financial incentives for the oil shale industry. This assumes, however, that market

conditions continue to improve, and that institutional barriers (e.g., regulations, permitting

requirements, and land availability) do not

preclude development. Such could be the

case if the developers responded to normal

market pressures and opportunities. If, however, high levels of production must be

achieved within a relatively short time, then

Government support will probably be required to reduce the remaining risks associated with oil shale development. The most important of these risks are:

●

●

●

Present capital and operating cost estimates for oil shale plants could substantially underestimate actual costs. No

commercial facility has ever been built,

and most of the existing engineering design estimates are preliminary. Estimates for the costs of building plants

have consistently increased much faster

than the rate of general inflation.

Uncertainties in the regulatory or permitting process, or changes in the regulations after a plant was built, could

jeopardize a project’s economics or even

preclude its development.

Future petroleum prices might not allow

shale oil to be profitably marketed once

the plants were built. Since developers

do not know precisely what their production or construction costs will be, the

uncertainty of future prices for shale

oil’s primary competitor is a crucial risk.

Investor participation is not considered to

be a problem for scenario 1, and the financial

community will be able to supply the neces-
Ch 3–Constraints to 0il Shale Commerciailzation Policy Options to Address These Constraints ● 63

sary capital for scenarios 1, 2, and 3. The

financial requirements of scenario 4 will

strain the Nation’s resources of investment

capital only slightly or moderately. However,

it is questionable whether investors would be

willing to risk participating in scenarios 2, 3,

and 4 because of such factors as the uncertainties in world oil prices, the existence of

institutional barriers, and the doubtful future

of Government policies. “Possible” obstacles

are shown for these scenarios.

Institutional

Land

The availability of land is not expected to

be a problem with scenarios 1 and 2 because

potential developers already have access to

sufficient private and public lands to achieve

the relatively modest production goals. It

could, however, cause some problems for scenario 3, particularly if multimineral recovery

or open pit mining were to be tested, It will be

a critical obstacle for scenario 4. The production target (1 million bbl/d) will require about

15 to 20 plants each on a tract of approximately 5,000 acres, or a smaller number of

larger operations, probably including some

open pit mines. It is doubtful that private

holdings are either large enough or contain

enough rich oil shale to support this many

projects by 1990.

Permitting Procedures

As a production target increases in size, so

will the number of permits that must be obtained from the many different Government

agencies. If many projects are involved, these

agencies are likely to be overwhelmed by the

sheer number of applications that must be reviewed, revised, and approved, The evaluation process could become more lengthy and

complicated, which would increase the risk of

delays in project schedules. Financial losses

to the developers would be the outcome. Alternatively, if the agencies bypassed certain

review steps in order to expedite the permitting process, design problems could slip by

that would subsequently need to be corrected, introducing additional delays; or, if

not caught, would result in environmental

damage. Regulatory changes during the development of the projects could mandate unanticipated, and possibly uneconomical, process modifications that could have more easily

been made during the design phase. These

factors are likely to discourage some developers in scenario 3; they would severely impede reaching the targets of scenario 4.

Pipelines

Under the first three scenarios, the existing system of major pipelines should be adequate to convey the shale oil to nearby markets as well as to more distant ones in the

Rocky Mountain region. Only relatively small

pipeline spurs, plus some truck and rail

transport, will be needed to supplement the

system. The system will not be adequate for

scenario 4, and new pipelines will be needed

to provide access to markets in the Midwest,

Design and Construction Services

Only about 20 architectural, engineering,

and design firms in the United States have the

capacity to design and build an oil shale facility. The projects that would be needed for

scenario 3 would require about 12 percent of

their capacity; those in scenario 4 about 35

percent. If other industrial expansion competes for their services, the availability of

these firms could delay the attainment of both

scenarios. Contracting with foreign firms

could be a short-term solution. In the longer

term, as domestic firms expanded and smaller companies merged, the necessary array of

technical expertise would become available.

If the projects were to be completed before

the 1990 deadline, however, these adjustments would have to take place in the early

1980’s, which may not be possible. In any

case, the demand for design and construction

services would escalate project costs, especially in scenario 4.
64 ● An Assessment of 0il Shale Technologies

Equipment

Scenario 3 will require between 6 and 12

percent of the U.S. production of valves, compressors, heat exchangers, pressure vessels,

and other industrial equipment. If there were

shortages, scenario 4, which will need 15 to

30 percent, could be severely hampered by

project delays and cost escalations. Deficiencies in equipment supplies and design and

construction services could escalate project

costs by as much as 50 percent. *

Environmental

Although harm to the air, water, and land

would certainly increase as the industry expanded, existing regulations for water quality, land use, and worker health and safety do

not appear, at present, to be obstacles under

any of the scenarios. This observation is

based only on the results of laboratory tests,

engineering design studies, and experience

with small-scale plants. Therefore, it is not

possible to accurately evaluate large-scale

operations with respect to the efficacies of

their control systems, the characteristics of

their ultimate emissions streams, the consequences of the scaleup necessary to build

them, and thus their effects on the environment. It is not known whether the industry

will be able to meet, in the future, permitting

standards and regulations for environmental

protection.

The same types of uncertainties also apply

to air quality. Recent studies, however, indicate that even when the best available control technologies are used, production capacity will be limited by the standards for prevention of significant deterioration (PSD).

These were promulgated under the Clean Air

Act, and specify the maximum allowable increases in the ambient concentrations of sulfur dioxide and particulate for any area.

The oil shale region has been designated as

a Class II area, i.e., some additional air pollution and moderate industrial growth are al-

*Such increases occurred in process plant construction during the period from 1973 to 1975. See ch. 6.

lowed. There are also Class I areas nearby,

where the air quality must be kept virtually

unchanged. These could be affected by oil

shale operations. One of these, the Flat Tops

Wilderness, is less than 40 miles from the

edge of the Piceance basin, and about 95

miles from the eastern edge of the Uinta

basin. A preliminary regional modeling study

undertaken by the Environmental Protection

Agency (EPA) has indicated that by carefully

siting the plants in the Piceance basin, an industry of up to 400,000 bbl/d could probably

be controlled to satisfy the PSD standards for

Flat Tops. The standards might hinder scenario 3 if all the capacity were concentrated

in the eastern Piceance basin, but this is

unlikely. It is more probable that some projects will be sited in the Uinta basin. Thus the

scenario’s goal could probably be achieved.

Under scenario 4, air quality deterioration

would be sufficiently large that compliance

would not be possible because at least half of

the capacity (500,000 bbl/d) would be located

in the Piceance basin.

Water Resources

The availability of surplus surface water

for large-scale oil shale development depends

on the rate of regional growth holding to the

medium levels anticipated by the States, and

the long-term average flow of the Colorado

River remaining at or very near the levels

that have obtained since 1930. If there are

higher rates of regional growth, or if the

river’s flows decrease by a few percent, production could be limited to about 500,000

bbl/d unless water were diverted from other

users. Shortages of surface water, which

could hinder scenario 4, could be offset by developing ground water, by purchasing surface water from other users, or by importing

water from other areas. However, these

strategies could encounter institutional obstacles. For example, importation of water is

presently banned by Federal statutes, and

ground water could be developed only if the

rights of surface water users were protected.

All of the scenarios will require additional

reservoirs to assure year-round water sup-
Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints ● 65

plies. In many cases, these will be small and

located at the plantsites. However, a large industry will need new reservoirs if the projects, and all other users, are to have adequate water supplies, The existing reservoirs

will not be adequate for scenarios 3 and 4,

and new storage will have to be built in the

basins of the White River and the Colorado

River mainstem. Reservoir siting could be restricted on some streams by their designation

as wild and scenic rivers, or by the presence

of rare and endangered species.

All of the scenarios will require diversion

projects to carry water from the streams and

reservoirs to the oil shale plants. Their construction would also come under environmental laws.

Socioeconomic

Social and economic obstacles will arise if

the communities are unable to adapt to the

growth caused by shale development, These

obstacles have two aspects, The first relates

to the physical ability of the towns to provide

adequate housing, facilities, and services.

The second involves the effects of local living

conditions on workers and other residents.

Even when physical facilities are adequate,

the way of life can be unpleasant. In some

Western and Great Plains communities

where large and rapid growth has accompanied energy industry construction, living conditions have become so intolerable that workers and their families have simply left. The

consequences for the projects of this labor

turnover were construction delays, cost overruns, and poor workmanship.

Communities in the oil shale region are preparing for additional growth. In Colorado, for

example, the State government, and the oil

shale counties and municipalities—with the

support and cooperation of industry—have

been preparing for increased development

for nearly 10 years. Consequently, the region

is awaiting expanded oil shale development,

and is prepared to absorb a moderate number of new residents. Assuming there are no

breakdowns from boomtown stresses, and

that presently planned facilities (such as the

new town of Battlement Mesa) can be built,

the region could accommodate up to 35,000

people between 1985 and 1990. (See table

11. ) More could be incorporated if preparations were begun at once. The established

communities could expand and new towns

could be constructed, provided that financing

were available, regulatory actions could be

taken in a timely fashion, and the political

and administrative atmosphere were favorable. However, if community and individual

stress became too great and social institutions faltered, not even the total of 35,000

residents could be absorbed without disruption.

Although some social stress can be anticipated, the area should be able to deal with

the growth associated with scenario 1. Scenario 2 could probably be accommodated if

project construction were phased, and if

some projects were developed in Utah. Severe problems would accompany the growth

expected for scenario 3, and the growth for

scenario 4 would greatly exceed the capaciTable 11 .–Actual and Projected Population and Estimated

Capacity of Oil Shale Communities in Colorado

Population

1977 1980 1985-90

Location a

census b projected capacity d

Garfield County

Rifle . 2,244 4,362 10,000

Silt : 859 1,211 2,800

New Castle 543 831 1,000

Grand Valley. ~ ~ 377 589 3,000

Battlement Mes a

e 

~ — 198 2,500

Other ~ ~ – – 1,700

Subtotal f

. ., 4,023 7,191 21,000

Rio Blanco County

Meeke r 1,848 2,779 6,000

Rangely ... 1,871 2,223 6,000

Other. . 1,381 1,542 2,000 — — —

Subtotal 5,100 6,544 14,000

— — —

Total . , , . . 9,123 13,735 35,000

aooes not IflCIUcle MeSa or Mot[at Counties both of which are more dtslanl from the area of development

bAc[ua15 from a special U S census

cEnd-of.the year projections by the Colorado West Area Counc[l of Governments

dEsllma[ed by OTA from various plannlng and needs assessment documents assumes comple

Ilon of currently planned orojects (e g housing waler and sewer system expamlons s{reet

and road Improvements etc I

‘A new town Construction antupated 10 begtr (n the early 1980 s

f/nC/udes only Ihe Immedla!e 011 shale vlClnlty

SOURCE Off Ice of Technology Assessment
66 . An Assessment of Oil Shale Technologies

ties of the communities. Not only would the cal stress would be inevitable for scenario 4,

existing towns have to double or triple in size, and there is little doubt that adverse living

but several new ones would have to be estab- conditions would prevent the realization of its

lished. Disruption from social and psychologi- production goal.

Policy Considerations

Some possible Federal policy responses to

the constraints that would inhibit or preclude

the expansion of the oil shale industry are

discussed in this section. Other issues and impacts that have not been identified as constraints are dealt with in the subsequent

chapters and summarized in chapter 1. Some

examples are the efficacies, over the long

term, of the proposed solid waste disposal

practices, and the consequences of decreases in the flows of the Colorado River

system.

Technology

Accelerated research, development, and

demonstration would be needed to remove the

technological barriers to scenario 4. The

following programs might be considered.

R&D Policy Options

Some of the remaining technical questions

could be answered in small-scale R&D programs. These could be conducted by Government agencies or by the private sector, with

or without Federal participation. If Federal

involvement is desired, the R&D programs

could be implemented through the congressional budgetary process by adjusting the appropriations for the Department of Energy

and other executive branch agencies, by providing additional appropriations earmarked

for oil shale R&D, or by passing new legislation specifically for R&D on oil shale technologies.

Demonstration Options

In general, potential developers would

prefer to follow conventional engineering

practice, and to approach commercialization

through a sequence of increasingly larger

production units. Union, Colony, and Paraho

have progressed through this sequence to the

semiworks scale of operation—about onetenth of commercial module scale. Larger

demonstration projects will be needed to accurately determine the performance, reliability, and costs of processing technologies under commercial operating conditions. For

Union and Paraho, the next step is a modular

demonstration facility that would incorporate

only one retort. Although costing several hundred million dollars, this facility would provide the necessary experience and the technical and economic data to decide whether to

commit much larger sums to commercial

plants. Rio Blanco and Cathedral Bluffs are

also following the modular demonstration

path. Colony regards the pioneer commercial

plant as more suitable for demonstrating the

TOSCO II technology.

As discussed in the section on economic

and financial policies, whether the Federal

Government plays an active role in funding and operating the demonstration projects

will strongly influence the balance that is

achieved between information generation

and dissemination, timing of development,

and cost to the Treasury. There are four

possible structures for demonstration programs. In all cases, the net cost of the program will depend on where the facilities are

sited. If the site could be subsequently developed for commercial production (e.g., a private tract, a potential lease tract, or a candidate for land exchange), the facility would

have substantial resale value. Otherwise, it

would have only scrap value.

A single module on a single site.—This option would provide comprehensive information about one process on one site. Either

underground or surface mining experiments
Ch 3–Constraints to 0il Shale Commercialization. POlicy Options to Address These Constraints ● 67

could be performed, but probably not both.

The costs would be small overall but large on

a per-barrel basis, because there would be no

economies of scale. Some of the mined shale

could be wasted because the single retort

might not be able to process all of it economically.

Several modules on a single site.—This

program might consist of an MIS operation

coupled with a Union retort for the coarse

portion of the mined oil shale and a TOSCO II

for the fine portion. As with the single-module

option, either surface or underground mining

could be tested, or possibly both if the plant

had sufficient production capacity. The total

costs would be larger than for the single-module program, but unit costs would be much

lower. For example, a three-module demonstration plant would cost about twice as

much as a single-module facility; a six-module

plant about four times as much. Different

technologies could be combined to maximize

resource utilization, and detailed information

could be obtained for each. However, all of

the information would be applicable to only

one site. If many modules were tested, the

demonstration project would be equivalent to

a pioneer commercial plant, except that a

true pioneer operation would probably not

use such a wide variety of technologies.

Single modules on several sites.—Several

technologies might be demonstrated, each at

a separate location. For example, an underground mine could be combined with a

TOSCO II retort on one site; a surface mine

with a Paraho retort at another. Total costs

would be large, as would unit costs, which

would be comparable with those of the singlemodule/single-site option. The principal advantage would be that different site characteristics, mining methods, and processing

technologies could be studied in one program.

Several modules on several sites.—For

each site, a combination of mining and processing methods could be selected that would

be appropriate for the site’s characteristics

and the nature of its oil shale deposits. The

maximum amount of information would thus

be acquired in exchange for the maximum

amount of investment. Each project would resemble the several-module/single-site option;

the collection would constitute a pioneer

commercial-scale industry.

Economic and Financial

Continuing uncertainties over eventual

plant costs, along with present regulatory

deterrents, may mean that financial incentives will be needed. Government action to

allow easier access to public oil shale land, or

to remove regulatory impediments, could reduce this need. If, however, assuring the production for scenarios 3 or 4 by 1990 is a major objective, then financial incentives should

be seriously considered. They would be particularly important in meeting the goals of

scenario 4, because the rapid deployment of a

large number of projects within 10 years is

likely to create cost overruns and jeopardize

project economics.

Government Financial Support

Several types of Government financial supports are discussed below. These are basically of two kinds: incentives to private industry,

and direct Government ownership or participation.

Incentives to industry.—An effective incentive must avert one or more economic

risks. It should also be cost-effective: its cost

to the Government should be low and its subsidy effect high. It should promote, or at least

not impede, efficient investment and production decisions, and should encourage competition. It should facilitate access to capital. It

should entail small administrative and bureaucratic costs. Finally, it should be phased

out as market conditions improve and risks

are reduced. The following analysis assumes

that only temporary incentives will be required for the first generation of oil shale

facilities. If this assumption proves incorrect,

the implications of subsidizing the industry

should be reevaluated; permanent subsidies

are a very different economic proposition

from temporary ones.
——— -. . ——.—

68 ● An Assessment of 011 Shale Technologies

OTA analyzed 10 possible economic incentives. These differ with respect to the criteria

described above and also with respect to

whether the Government provides the incentive before or after production begins. The

latter option is desirable because the Government could phase in the subsidy disbursement. Production incentives (those applied

after production begins) limit the Government’s financial exposure and risk. The use

of production subsidies alone, however, may

encourage only large corporations with exceptional debt capacity.

The net cost to the Government of a particular incentive can directly reflect the extent

of its subsidy effect, but the relationship is

not necessarily linear: some incentives definitely provide more subsidy at a lower cost to

the Treasury than others. (See table 12.) It is

also important to note that the corporate, financial, technical, and fiscal circumstances

of the potential developers will show considerable differences. Consequently, it is unlikely that any single “best” incentive will be

revealed. However, some are clearly superior

to others from the viewpoints of both the Government and developers. An optimal policy

might be to provide a variety of incentives of

approximately equal dollar value, and to

allow each company to choose the one that is

most appropriate to its particular circumstances. The implications of each of the incentives follow. *

● Construction grant. —The Government provides a direct grant to cover a prespecified

percentage of total construction costs.

*Fu1l discussion is found inch. 6.

Table 12.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’

(12-percent rate of return on invested capital)

Change in Total expected cost

Total expected expected profit Probability to Government Breakeven

Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl)

Construction grant (50%) $707 $487 0 0 0 $494 $34.00

Construction grant (33%) ~ 542 321 0.00 327 38.70

Low-interest loan (70%) ., ~ ., 497 277 0,00 453 43,40

Production tax credit ($3) ., 414 194 0,01 252 42,60

Price support ($55 ) ,. 363 142 0.01 172 NA

Increased depletion allowance (27%) ~ ~ ~ 360 140 0.05 197 4570

Increased Investment tax credit (20%) ~ ~ 299 79 0.05 87 4580

Accelerated depreciation (5 years ) 296 76 0.05 79 46,00

Purchase agreement ($55) . , 231 11 0.03 0 NA

None ., ~ ~ ~ 220 0 0 0 9 0 4820

(15-percent rate of return on invested capital)

Change in Total expected cost

Total expected expected profit Probability to Government Breakeven

Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl)

Construction grant (50%) $281 —

$477 0.00 $494 $4060

Construction grant (33%) ., ~ ~ ~ ~ ~ 119 315 0.19 327 47,70

Low-Interest loan 81 277 0.23 453 5470

Production tax credit ($3) ~ ., ~ ~ - 6 1 135 0 6 3 252 56.10

Price support ($55) ., ., ... - 8 8 108 0 7 7 172 NA

Increased depletion allowance (27%) ., ., -11 0 86 0.75 197 57.20

Increased Investment tax credit (20%) ., -13 1 65 0.77 87 58,80

Accelerated depreciation (5 years) ., .. . – 127 69 0.76 79 5890

Purchase agreement ($55) , . . -15 0 46 0 9 2 0 NA

None ., ... ., ., ., ., ~ ~ ~ ., -19 6 0 0 9 3 0 61.70

aThe calcUlallonS assume a $3!j/bbl price for conventional premtum crude that escalates at a real rate of 3 percent per year Thus the predicted S48/bbl breakeven price fOr lhe 12-perCent discount rate ‘Will

be reached 10 11 years or In the I[tth year of produchon Therelore tn narrow economic Ierms 011 shale plants starting construction now which assume a 12.percent discount rate WIII be profitable over

the hle of the project wlthoul subsmy (See discussion for caveats concerning Ihls conclusion ) The calculations are for a 50,000 -bbl/d plant costing $1 7 blllton All monetary values are In 1979 dollars

SOURCE Resource Plannlng Associates Inc Washington O C
Ch 3–Constraints to Oil Shale Commercialization: Policy Options 10 Address These Constraints ● 69

(OTA analyzed both 50- and 33-percent

grants.) This incentive has a strong effect

on project financing. It benefits all developers, and does not distort investment or

production decisions. However, it would

impose large administrative burdens on

both the Government and industry. There

would be no assurance that production

would occur even with the grants. Large

initial lump-sum payments would be required rather than phased-in treasury disbursements. The subsidy would probably

be politically unpopular.

Production tax credit.—The developer is

allowed a credit against corporate income

taxes for each barrel of shale oil produced.

(A $3 credit per bbl of crude shale oil was

analyzed. ) This incentive provides a strong

subsidy effect, and moderately shares investment cost uncertainty. It imposes minimal administrative burdens. It only slightly improves project financing, however,

and entails some distortion of product

price, It most strongly affects firms that

have large tax liabilities, and its net cost to

the Government is high compared with

other possible incentives. It is widely supported by potential developers.

Price support.—A minimum price for shale

oil is guaranteed for a long enough period

to allow developers to recover their capital. (OTA analyzed a minimum price of $55/

bbl of shale oil syncrude-the Government

would pay the difference if the market

price were lower.) This incentive has a

very strong effect on project economics. It

removes most of the risk of price fluctuations in foreign oil. On the other hand, it

does not prevent shale oil from being sold

in the private market if prices there are

higher than the supported price. With

present and projected world oil prices, it is

very possible that no Government purchases would be necessary. In this case,

the Government would gain income since

the developers would pay taxes on their

production. This incentive limits the Government’s financial exposure—a highly desirable feature. * Its availability would also

help developers obtain project financing.

Price supports would benefit all firms.

However, they might not be sufficient for

firms with limited debt capacity (i.e., firms

that could not borrow the required capital), especially if they were considering

costly commercial-size plants. The administrative burden would range from slight to

moderate. This subsidy is supported by a

variety of potential developers. Its characteristics make it attractive to both developers and the Government.

Purchase agreement.—A developer contracts with the Government to sell shale oil

at a specified price that is usually somewhat above the expected market price.

(OTA’s analysis assumed a price of $55/bbl

in constant 1979 dollars. ) This incentive is

similar to a price support except that the

developer must sell the oil to the Government; he does not have the option of selling

it in the open market. Purchase agreements

increase profitability to a lesser extent

because the firm does not benefit if the

market price is above the contract price.

On the other hand, the Government shares

in both the risks and the potential benefits

of shale oil production. Consequently, the

average cost to the Government is somewhat lower than with a price support. Purchase agreements limit the possibility of

loss, but also reduce the likelihood of large

profits. They are less popular with industry than are price supports. The administrative costs are also higher than those of

price supports, but their severity can be

controlled, to some extent, by the manner

in which the subsidy is constructed.

Low-interest loan. —The developer borrows a specified percentage of capital

costs from the Government at an interest

rate below the prevailing market rate.

(OTA’s analysis assumed 70-percent fi-

*As indicated in table 12, the net cost to the Government of

providing such an incentive —even if developers chose to sell to

the Government-would be low relative to most other incentives,
70 . An Assessment of Oil Shale Technologies

●

●

nancing at 3 percentage points below the

market rate. ) This incentive requires the

Government to share significantly in the

risk of project failure, and it has a marked

effect on a developer’s ability to obtain

financing, but it tends to distort input

costs, and to bias investment decisions in

favor of capital-intensive technologies. It

also imposes large administrative burdens.

This type of subsidy is usually designed to

provide the greatest benefits to firms with

weak financial capability. In practice,

however, it is difficult to deny loans to

strong firms.

Debt guarantees.—The Government

agrees to pay back a loan if the developer

defaults. With this insurance, a firm can

usually obtain lower interest rates. Usually, only a fraction of the total loan is insured, and the borrower is required to pay

a premium for the insurance. This incentive only slightly subsidizes the investment,

but it provides maximum sharing of the

risk of project failure. It considerably

eases borrowing problems. Loan guarantees primarily benefit financially weak

firms. They distort input cost, and they

bias investment decisions toward capitalintensive technologies. They also impose a

significant administrative burden. Perhaps

the most obvious drawback is the uncertain financial exposure of the Government.

The Government’s costs would be zero if no

plants failed, but huge if even a few failures occurred. The Government has had

considerable experience with debt insurance programs during the last 15 years,

and the fees paid by firms for the protection have, in sum, yielded it net income. If

the participation of small- and mediumsized firms is desired, then either debt

guarantees or low-interest loans will probably be necessary.

Investment tax credit (10 percent), accelerated depreciation (5 years), and increased depletion allowance.—None of

these would be likely to have a major impact on oil shale development. Their incentive characteristics are discussed in

chapter 6.

Direct Government Participation or Ownership

The Government could share the capital

and operating costs with industry, and thereby become a part owner of the project. The

consequences would be similar to the construction grant option, except that the Government would share all of the risks and benefits. Almost without exception, potential developers believe that active Government participation would increase managerial complexity and inefficiency. Administrative burdens would be very high.

The Government could also contract for the

construction of several modular plants it

would then operate, either alone or through

contracts. It could thus conduct operations to

obtain accurate information on technical feasibility, project economics, and the relative

merits of different processes. This would be

of assistance in evaluating its future policies

towards oil shale, in disseminating technical

information, and in improving its understanding of the value of its oil shale resources.

After enough information had been obtained,

the facility could be scrapped or sold to a private operator. This policy would provide the

Government with information and experience, but the cost would be much higher than

that of incentives to private developers.

Because industrial partners would insist

on some protection of proprietary information, the Government would probably not be

able to disseminate all project data as it

chose. In addition, its experience in designing, financing, managing, and obtaining permits for an oil shale plant may not resemble

that of private industry. Thus, the information acquired may be of only limited use to

subsequent private developers.

Most of the information secured through

Government ownership could be made available as a condition of granting private financial incentives. Furthermore, this kind of

Government intervention is likely to discour-
Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints ● 71

age private developers from undertaking

their own modular development and R&D programs. Government programs of this kind

tend to reduce the benefits that a particular

firm could obtain from R&D or modular testing. Finally, when patenting and licensing

technologies, definite provision is made for

the dissemination of technical information on

both gratis and fee terms to possible users of

the processes,

Institutional

Use of Federal Land*

The Federal Government owns over 70 percent of the oil shale lands and nearly 80 percent of the best shale resources. Essentially

all of the large deposits of nahcolite and daw- sonite x in the Piceance basin are federally

owned. No permanent leasing program exists

for these lands, and the current Prototype Oil

Shale Leasing Program is limited to no more

than six tracts of 5,120 acres each. To date,

four tracts have been leased: Utah tracts U-a

and U-b (the White River project) and Colorado tracts C-a (Rio Blanco) and C-b

(Cathedral Bluffs). The other two tracts were

proposed for Wyoming, but no bids were received when their leases were offered in

1974. Development is proceeding on the Colorado tracts, but the ones in Utah have been

stalled by litigation between the State and the

Federal Government. ***

*On May 27, 1980 the Department of the Interior (DOI) announced several oil shale decisions. Up to four new tracts will

be leased under the Prototype Program and preparations

started for a permanent leasing program. At least one multimineral tract will be included in the renewed Prototype Program. Land exchanges will not be given special emphasis, and

no decision will be made to settle mining claims until the Supreme Court rules on Andrus v. Shell Oil (the oil shale mining

discovery standard case). [NOTE: This case was decided on

June 2, 1980. No. 78-1815.] The administration will propose to

Congress legislation to give DOI the authority to grant leases

bigger than the present statutory limitation of 5,120 acres, to

provide for off-lease disposal of shale and siting of facilities,

and to allow the holding of a maximum of 4 leases nationwide

and 2 per State.

* *Nahcolite is a mineral containing sodium; dawsonite contains aluminum.

***On May 19, 1980, the U.S. Supreme Court reversed the

lower court decisions and held that the Secretary of the Interior could reject Utah’s applications for oil shale lands as school

land indemnity selections (Andrus v. Utah, No. 78-1522).

Additional Federal land would not be

needed to achieve the goal of scenario 1, nor

to reach that of scenario 2 if economic conditions favored oil shale development. The goal

of scenario 3 could also be met without more

Federal land if regulatory and economic uncertainties were sufficiently reduced to encourage Tosco, Colony, Union, and Rio Blanco

to continue their commercialization programs. On the other hand, implementation of

scenario 4 would require a highly favorable

economic and regulatory climate (probably

including Federal subsidies), or the use of additional Federal land, or both. In any of the

scenarios, more public land may be required

if large-scale multimineral recovery processes or open pit mining are to be tested in the

near future.

The land could be leased, exchanged for

private land, or developed by the Government. All three options may be affected by the

fact that much of the best Federal oil shale

land is subject to unpatented mining claims

by private parties. The validity of some of

these claims will be determined by the Supreme Court in 1980. If the Court’s ruling favors the claimants, much less Federal land

may be available for disposition.

Leasing.—Under the Mineral Leasing Act

of 1920, the Department of the Interior (DOI)

has the authority to lease public oil shale

lands to private developers. The Act limits

the number of leases to one per person or

firm, and restricts the maximum size of a

single tract to 5,120 acres (8 mi2

). Individuals

and firms are allowed to hold shares in several leases, but the total area covered by these

shares cannot exceed 5,120 acres.

Whether the acreage limitation will impede development will depend on the location

of the tract and on the types of development

technologies to be employed. It might preclude large-scale operations in the thinner,

leaner deposits in Wyoming. However, a

5,120-acre tract in the relatively rich areas of

the Piceance and Uinta basins could easily

support a commercial-scale operation over its

economic lifetime. On the other hand, if a

very large facility were desired, the acreage
72 . An Assessment of 01/ Shale Technologies

limitation could impede efficient resource development, especially if surface mining were

to be used. If the entire tract were suitable

for surface mining, the need to dispose of mining and processing wastes within the tract

boundaries would reduce overall resource recovery, and might allow only relatively inefficient development. One solution would be to

include in the tract an area (such as a dry

canyon) that contains no oil shale resources

but that could be used for waste disposal.

This option would not require amending the

Leasing Act, but it could complicate mining

operations and would reduce the value of the

tract to the private sector. Another option

would be to allow disposal in similar areas

outside the tract boundaries, as was originally proposed for tract C-a, but this would require amending the Federal Land Policy and

Management Act of 1976 (FLPMA).

The argument in favor of limiting the number of leases per individual or firm is that it

prevents a small number of entrepreneurs

from cornering the lease market. The argument against the restriction is that it prevents

a developer from acquiring experience and

technical information on one tract and then

applying it to another while the first is still

operating. The latter position is valid for

potential developers who do not have their

own oil shale land, but not for those whose

privately owned tracts could be developed

commercially if the company could acquire

the necessary expertise in the richer deposits

on public land. The options are to increase

the number of leases allowed to two or three

per company or individual, regardless of the

locations of the tracts; or to allow one lease

per developer per State. The latter would

allow a developer to obtain experience with

the richer oil shales in Colorado, for example,

which could then be applied in Utah or Wyoming. Potential developers prefer the first option because the shales in Utah and Wyoming

are much poorer than those in Colorado. Both

options would require amending the Mineral

Leasing Act.

If additional leasing is desired, it could be

carried out either in a new, permanent leasing program, or as part of the Prototype Program. Opportunities exist for leasing at least

two additional tracts within the Prototype

Program because of the two Wyoming leases

that were not purchased during the 1974 offering. No congressional action would be required to extend the Prototype Program, but

its extension would constitute a major Federal action. Therefore, a supplementary environmental impact statement (EIS) would be

required. Its preparation could take from 1 to

2 years.

Nomination of the tracts and preparation

of leasing regulations could add several

months to a year to the front end of the schedule. Unless the preliminary steps were expedited, the leases could probably not be sold

until about 1983. If the leases were similar to

those for the existing Prototype tracts, a

2-year environmental monitoring program

would be mandated before site development

could proceed. Thus, the first construction

work could not begin until about 1985. If a

commercial plant were built without a preliminary demonstration phase, commercial

production could start in about 1990. With a

demonstration phase, commercial production

could not begin before 1992 or 1993.

The timespan could be reduced somewhat

by offering the tracts that were considered in

the mid-1970’s as replacements for the Wyoming tracts. The nomination process was

completed for these tracts, and work was begun on a supplemental EIS. They were originally selected as sites for in situ operations,

and to offer them now for this type of development would be inconsistent with one of the

Program’s major goals, which was to test a

variety of processing technologies. (Both of

the active Prototype tracts are being developed by in situ techniques. ) If they were also

suitable for aboveground processing, their

use in the program extension would shorten

the commercialization schedule by about a

year.

The other leasing option would be a new,

permanent leasing program that would be independent of the Prototype Program and

therefore not restricted by its six-tract limit.

Implementing this option would take longer
Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints ● 73

than extending the Prototype Program, because of the need to prepare new leasing regulations and an entirely new EIS. No congressional action would be required, unless the

program were to be coupled with an incentives package or with amendments to the Mineral Leasing Act.

The adoption of a new leasing program

would imply the abandonment of another objective of the Prototype Program, namely to

obtain the technical, economic, and environmental information needed to design a permanent leasing program. For a variety of reasons, the Prototype Program has not yet provided this information. (See vol. II. ) Its abandonment would engender political opposition

from the individuals and groups that criticize

oil shale development, especially where public land is involved.

Land exchange. —Private interests own

several million acres of oil shale land. Of the

approximately 400,000 acres of privately

owned land in Colorado, at least 170,000

acres contain beds that are at least 10 ft deep

with a potential yield of 25 gal/ton, It has

been estimated that the total potential oil

yield from these richer tracts is at least 80

billion bbl. However, much of the privately

held land is located on the fringes of the oil

shale basins, and contains thinner, leaner deposits than does the adjacent Federal land,

Furthermore, many of the private tracts are

in small, noncontiguous parcels (mainly former homesteads and small mining claims)

that cannot be economically developed. Private oil shale development would be encouraged if these lands were exchanged for more

economically attractive Federal tracts.

There are essentially two land exchange

options. The first involves “blocking up’ scattered or oddly shaped private tracts by exchanging some of them for adjacent Federal

lands. (Superior Oil Co. proposed such an exchange for its tract near the northern edge of

the Piceance basin. ) The second option involves the exchange of large privately owned

parcels for equivalent Federal tracts, perhaps in an area that is more suitable for a

specific development method.

Both options are allowed by FLPMA. Under

FLPMA, the Government may exchange public land for private land, provided that the exchange is in the public interest and that the

properties involved are within 25 percent of

equal value. The difference can be made up

with cash. The major problem with exchanges under FLPMA is that the procedures

are time-consuming, complex, and costly. Several Federal agencies must be involved in

estimating the relative values of the tracts in

question and in determining whether the exchange is in the public interest. An EIS may

be needed; its preparation could take as long

as 2 years. The overall process, including review, evaluation, and approval by the agencies plus a period for public comment, can

take even more time.

There are several ways to improve the exchange process. One would be to streamline

the review procedures, perhaps by setting up

a task force within DOI to deal with exchange

proposals involving oil shale lands. Another

option would be for DOI to nominate Federal

tracts, to characterize their environments,

and to evaluate their resources, even if no exchange proposals had been received from private parties. With this advance preparation,

the exchange process would be shortened,

and the Government would be able to control

the location of the future oil shale plants.

Both options would be costly and would enlarge the bureaucracy. Additional appropriations, and possibly authorizing legislation,

would have to be provided by Congress.

A third option would be to exchange private land for Federal land that is adjacent to

State-owned tracts. The mix of private and

State land could then be developed under a

State-controlled leasing program. This option

would be most applicable to the Uinta basin,

where the State’s extensive holdings are intermingled with Federal and private tracts.

Government development.—The Government could also develop its own oil shale

lands. Two likely tracts are the 40,000-acre

Naval Oil Shale Reserve I (NOSR 1) in Colorado and the 90,000-acre NOSR 2 in Utah. (The

resources on NOSR 2 are of much poorer
74 . An Assessment of 0il Shale Technologies

quality.) These sites could be developed

either with a Government-owned corporation,

or through a cost-sharing arrangement with

industry. The advantages and disadvantages

of different types of Government participation are discussed in the section on economic

and financial policies.

Permitting Procedures

Developers view the costs and potential

risks of the present regulatory process as one

of two primary impediments to development.

Reaching the production goals of scenarios 1

and 2 will probably not require expediting the

permitting process, but it will be needed to

meet the goals of scenario 3, and is even more

important for scenario 4. One or more of the

following actions could speed up the process:

require regulatory agencies to make decisions in a specified period of time; “grandfather” projects under development to make

new laws and regulations inapplicable to

them; create an energy board or authority

with the power to overrule Federal regulatory decisions; or limit litigation as was done

with the Alaskan oil pipeline. The first two

options are likely to be a part of the powers of

the Energy Mobilization Board.

Another possibility would be for regulatory

agencies themselves to take the lead in simplifying their own permitting procedures. This

could be done by the imposition of internal

time limits on the period of review, and could

be combined with an arrangement whereby

developers applied for a package of related

permits. This would consolidate the number

of permits required, and eliminate some of

the existing permit duplication. EPA Region

VIII appears to be adopting these procedures,

although it is not clear whether and to what

extent they will actually expedite the permitting process.

Pipelines

A major pipeline would have to be built to

ship most of the l-million-bbl/d target of scenario 4 because existing pipelines to Wyoming and Midwestern refineries are inadequate. Its construction could require access

across Federal land and eminent domain

rights to private land, as well as extensive

regulatory actions and EISs. Congressional

action might be needed to facilitate such a

project.

Design and Construction Services

and Equipment

To achieve the goals of scenario 4, Federal

assistance might be needed to deal with scarcities of heavy equipment and limited design

and construction services. The following policies might be developed:

●

●

●

●

●

●

Training programs could be set up for

construction workers to provide a skilled

work force when construction begins.

Equipment with long delivery times

could be identified and supplies increased by either expanding existing capacity, stimulating additional capacity,

or encouraging early orders.

Tariffs and quotas on imported equipment could be reduced or eliminated.

Federally sponsored R&D programs

could address the technical questions of

scaling up to commercial-sized facilities.

Developers, local governmental units, related industries, concerned interest

groups, and appropriate Federal agencies could be encouraged to coordinate

their efforts. This would help avoid construction delays,

Standardization of plant designs could

be used to reduce complexity and simplify construction.

Environmental

Air Quality

The PSD standards promulgated under the

Clean Air Act could hinder scenario 3 and

will, with current “best available control

technologies, ” prevent achieving scenario 4.

Policy options for addressing these obstacles

include:

● Coordinate the issuance of PSD permits.—

This option would not alter the PSD regulations nor relax air quality standards, but
Ch. 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints ● 75

●

●

would change the methods for issuing the

PSD permits that are needed before construction of the plants can begin. Rather

than issuing the permits on a first-come

first-served basis, EPA would encourage

all prospective developers to coordinate

their development plans before applying

for their permits. The goal would be a siting pattern that maximized production

while complying with air quality standards. This might relieve some of the siting

difficulties envisioned for the Piceance basin as a result of its proximity to the Flat

Tops Wilderness area. The implementation

of this type of option, however, could be

complicated by factors such as antitrust

laws.

Redesignate the oil shale region from

Class 11 to Class III.—This option would be

initiated at the State level, with a requirement for final approval from EPA. The criteria that would have to be satisfied include:

—the Governors of Colorado, Utah, or

Wyoming must specifically approve the

redesignation after consultation with

legislators, and with final approval of

local government units representing a

majority of the residents of the area to

be redesignated, and

—the redesignation must not lead to pollution in excess of allowable increments in

any other areas.

This option would allow greater degradation of air quality, but would permit more

industrial development. While it would appear that with such an option there could

be about twice as much oil shale development as presently possible, there would

still be limitations owing to nearby Class I

areas. With this option it is expected that

the production target of scenario 3 could

be achieved, but not that of scenario 4.

Amend the Clean Air Act.—This congressional option would exempt the oil shale region from compliance with certain provisions of the Act. Under this option Congress might direct EPA and the States to

redesignate the oil shale region from a

Class 11 to a Class III area, and to exempt

the developers from maintaining the visibility and air quality of nearby Class I

areas. This would remove both the major

uncertainties surrounding the siting of facilities within the resource region itself

and any siting barriers connected with the

degradation of the Class I areas. Such an

option should allow achievement of the scenario 4 production goal at the cost of increased air pollution in the oil shale and

nearby regions.

Environmental R&D

The public and private sectors have carried out extensive work on the environmental

impacts of oil shale development and on pollution control technologies to reduce these impacts. Yet many questions remain about the

effects that a commercial-size industry would

have both on the physical environment and on

worker health and safety. It is essential,

therefore, that R&D keep pace with the industry’s development. The information generated

would also assist regulatory agencies to develop emission and effluent standards for the

industry.

Options at the Federal level for improving

technical information include improved coordination of R&D among executive branch

agencies, increased appropriations for oil

shale R&D, the use of existing national commissions (e.g., the National Commission on

Air Quality) and the passage of legislation

specifically directed to R&D on the environmental impacts of oil shale technologies. (Environmental R&D needs are discussed in ch. 8

and summarized in ch. I.)

Water Resources

Policy options for removing obstacles associated with water resources are discussed

below.

Financing and Building New Reservoirs

Major new reservoirs will be needed for

scenarios 3 and 4 to ensure that the water

needs of oil shale developers as well as all
—.——————

76 . An Assessment of 01/ Shale Technologies

other users can be satisfied. They could be financed and built by the Federal Government,

by State organizations, or by the developers.

The options for Federal involvement are discussed below. (Those for the States and the

developers are discussed inch. 9.)

Congress could provide for the construction and financing of new water projects

through two mechanisms. First, funds could

be appropriated for a projector projects that

have already been authorized. Several have

already been evaluated by the Water and

Power Resources Service (WPRS), * and their

construction approved. Actual construction

cannot not be started until they are funded.

However, not all of these projects have been

evaluated for their suitability to supply water

for oil shale development, and some projects

may not be optimally located to serve oil shale

plants. A second option would be to pass legislation that would specify both the construction and funding of new, but not previously

authorized, Federal water projects. Unless

language were included to expedite construction, these projects would require a long review process. They could, however, be designed and sited as water sources for oil

shale (as well as other possible uses). An example would be constructing irrigation reservoirs with additional capacity for oil shale requirements.

Under either option, DOI, through WPRS,

could operate these reservoirs in accordance

with State water law. Their costs could be recovered over the operating life of the facilities from revenues generated by selling water to oil shale developers and other users, in

accordance with authorizing legislation.

The Siting of Reservoirs and Direct

Flow Diversions

The construction of new reservoirs and direct flow diversions (e.g., pipelines) might be

hampered, delayed, or even disallowed under

provisions of the Endangered Species Act, the

National Wild and Scenic Rivers Act, and the

*Formerly the U.S. Bureau of Reclamation (USBR).

Wilderness Act. Potential problems could be

reduced by the following mechanisms.

●

●

Identifying endangered or threatened species.—Two federally designated rare and

endangered fish species, the humpback

chub and the Colorado River squawfish,

have already been found in the waters of

the oil shale region, and additional species

requiring protection may be found during

future studies. The Endangered Species

Act may be interpreted as restricting activities that might affect the critical habitats

of such species, although no critical habitat has been declared for the squawfish or

humpback chub. Knowing the approximate

location of the critical habitats of endangered species would be helpful if it were

decided to establish an oil shale industry

because the timely siting of reservoirs and

direct flow diversions could be affected by

agency interpretations involving instream

flows. Should construction of these facilities begin before the critical areas were

identified, there could be opposition to

their completion, and water supplies from

a particular reach of a river could be delayed or interrupted. If the locations of all

designated critical habitats were identified

by DOI and the required biological opinions

obtained, the facilities could be sited to

minimize interference and delay.

Alternatively, Congress could designate

such reservoirs to be in the national interest, and could allow their construction in

spite of the effect this might have on endangered species.

Designating wild and scenic rivers and

wilderness areas.—To date, no rivers in

the oil shale region have been designated

for inclusion in the Wild and Scenic Rivers

System; however, several within the basins

of the Colorado River mainstem are being

considered, Diversions of water from specific stream reaches could be affected if

they are set aside. An early designation of

the eligible rivers would assist in the planning for future shale oil production. Given

this information, direct flow diversions

could be sited downstream from the por-
Ch 3–Constraints to 0il Shale Commercialization, Policy Options to Address These Constraints ● 77

tions designated as wild or scenic. This

would avoid a direct conflict within a given

river stretch but could add to the water

supply costs. (Supply costs are discussed in

detail inch. 9.)

To date, four areas in the basins of the

White River and the Colorado River mainstem have been designated under the Wilderness Act. Other areas are being considered pursuant to the Roadless Area Review

and Evaluation II (RARE II) program. * New

reservoirs would not be permitted in the

designated areas. A complete listing of wilderness areas that might be considered in

the near future would allow potential developers to locate their water storage facilities elsewhere. Alternatively, Congress

could specifically exclude rivers and/or

new areas in the oil shale region from designation as wild and scenic rivers or wilderness areas.

Federal Sources of Water for

Oil Shale Development

Congress, under its constitutional powers,

could make water available from Federal water projects, or potentially from the reserved

rights doctrine. (See ch, 9.) If Congress decides that water from congressionally funded

projects should be made available for oil

shale development, then any legislation

enacted should provide that the term “industrial use or purpose” includes the use of

water for oil shale development,** Congress

could also amend the authorizing legislation

for those projects from which water for oil

shale development might be sought, to permit

*“1’he Forest Service, in its RARE 11 progr~m, is evaluating

over 66 million acres of land to determine their suitability for

designation as wilderness, During the period of initial evaluation, and up to final recommendation by Congress, these lands

will be in some form of restrictive management.

**A Memorandum of Understanding ex ists between DOI and

the State of Colorado with respect to the use of water from existing or authorized U.S. Bureau of Reclamation (now WPRS)

projects, The State desires thfit the water not be changed from

agricultural, municipal, or light industrial uses to energy product ion (including oil shale] that are inconsistent with State policies. Under this memorandum, the State WT ill review any applications to redistribute water from conventional uses to energy

production. The memorandum could be superseded bV direct

congressional directives of overriding national importance.

the use of their water for this purpose. The

objective of this action would be to overcome

any administrative reluctance to permit the

use of water for oil shale development under

an authorization that did not specifically

mention oil shale,

The power of Congress over reserved waters is more limited than its power over

waters in congressionally funded projects.

Water rights covered by the reserved right

doctrine must be used “in furtherance of the

purpose of the reservation. ” For this reason,

Federal water rights do not seem to be likely

sources for oil shale development, except

perhaps in the case of lands set aside for the

Naval Oil Shale Reserves. This question, however, is in the early stages of litigation.

Interbasin Diversion

Interbasin diversion is a technically feasible although costly option for bringing additional water to the oil shale region, There are

also serious political obstacles to this alternative. The Reclamation Safety of Dams Act of

1978, amending the Colorado River Basin

Project Act, prohibits the Secretary of the Interior from studying the importation of water

into the Colorado River Basin until 1988. If it

were decided to pursue this option as a

means of supplying water to an oil shale industry coming online in 1990, this prohibition

would have to be lifted.

Interbasin transfers could be used to relieve the water problems of the oil shale region in several ways, Water could be transferred directly to the oil shale region, either

exclusively for oil shale development or for

all users. Alternatively, the water needs of

Colorado’s eastern slope cities, presently

being supplied in part from the Upper Colorado River Basin, could be met from other

hydrologic basins. The water presently being

exported from the Upper Basin then could be

used for oil shale development. In a third application of interbasin transfers, all or a portion of the 750,000 acre-ft/yr presently being

supplied to Mexico by the Upper Basin States

under the Mexican Water Treaty of 1944-45,

could be taken from another hydrological
78 ● An Assessment of Oil Shale Technologies

basin (perhaps the Mississippi basin). The

water thus freed in the Upper Basin could be

assigned in part to oil shale development

(750,000 acre-ft/yr would be sufficient for a

3-million- to 7.5-million-bbl/d shale oil industry).

The Allocation of Water Resources

If Congress were to pass legislation encouraging the development of an oil shale industry, it might wish to address the issue of how

the necessary water would be supplied and

how oil shale legislation might affect water

allocation.

Water in the oil shale region is presently

distributed by a complex framework of interstate and interregional compacts, State and

Federal laws, Supreme Court decisions, an international treaty, and administrative decisions. Within the Western States, water

rights are apportioned by the States to competing users according to a doctrine of prior

appropriation under which water rights are a

form of property separate from the land.

Oil shale developers presently hold extensive, but largely junior (i.e., low priority) surface water rights. Therefore, if water shortages were to occur, existing developer supplies could be interrupted. More reliable supplies may be provided through development

of ground water not tributary to the surface,

purchase of the consumptive portion of irrigation rights during the irrigation season, purchase of surplus water from Federal reservoirs, or importation of water from more distant hydrological basins. (The last two options have been discussed above). A discussion of the amount of water needed for oil

shale development is presented in detail in

chapter 9.

If control over the water supply for oil

shale is to be left to the States, then Congress

should probably so specify that decision in oil

shale legislation to avoid any question of the

preemption of State water laws. Legislation

that would confirm preservation to the States

of the same power over water for oil shale as

they have over other water supplies should

require the developer to comply with State

procedures in securing a water supply, and

provide that the established State appropriation system has the same authority to grant,

deny, or place conditions on a water right and

permit as would prevail in the absence of the

legislation.

If Congress were to attempt to remove the

water supply for oil shale production from

the control of the State, strong legal and

political resistance would ensue. Such resistance could delay oil shale development.

Socioeconomic

The social and economic effects of oil shale

development are not unique to the resource

being produced or to the technologies involved. Rather, they derive from an influx of

people, regardless of the cause. In this respect, they are similar to the effects of

growth in other energy industries, such as

coal or oil and gas. Before looking at specific

policy options for the effects of oil shale development, the perspective from which they

are viewed and the role of the Federal Government in impact mitigation must be considered.

Congress can view socioeconomic impacts

from one of three policy perspectives:

●

●

As part of the consequences of all kinds

of energy development.—In recent sessions, Congress has considered bills that

would provide assistance to communities faced with problems from the

growth of many different energy industries, and programs for oil shale could be

included in such legislation.

As an aspect of specific energy initiatives.—Proposed amendments to the

Powerplant and Industrial Fuel Use Act

of 1978 are illustrative of this more limited approach. These amendments are

directed to the adverse effects of major

energy developments, which could include oil shale. They authorize grants,

loans, loan guarantees, and payments of

interest on loans; and propose an expediting process for present Federal pro-
Ch 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints ● 79

grams as well as an interagency council

to coordinate Federal impact assistance.

● As the result of oil shale development

alone.—In this case, specific language

dealing with socioeconomic effects could

be included in bills providing for the development of oil shale resources.

The ways in which Congress deals with the

impacts will depend on which perspective is

adopted.

Policy decisions must also consider the role

of the Federal Government in impact mitigation. Assistance in coping with the consequences of growth is not expected in the usual course of economic development. Recently,

domestic energy development has become an

exception when the distinction has been

drawn between effects that can be handled

by local communities—i.e., those that can be

considered a normal adjunct of development,

and those that cannot be readily solved with

local resources—boomtown problems. The

extent and nature of Federal involvement in

impact mitigation is highly controversial. On

the one side, it is argued that social and

economic difficulties are State and local

problems that should be viewed as the inevitable consequences of industrial growth, and

thus the Federal Government need not be involved with their amelioration. On the other

side, the position is taken that national energy

requirements are the root causes of impacts,

therefore a Federal role is appropriate. Several Western States propose that for reasons

of equity, the national goal of accelerated

domestic energy production requires direct

Federal participation in alleviating negative

impacts. This question about the Federal role

must be faced before decisions can be made

about appropriate Federal actions for dealing

with the impacts of oil shale development.

No new Federal initiatives appear to be

needed for scenarios 1 and 2, as long as the

existing mechanisms are effective. Several

requirements must be met, however:

● both Federal and State actions must support already established growth management processes;

●

●

●

efforts to improve the delivery of Federal programs should continue;

State appropriations from funds designated to assist the oil shale communities

will be necessary; and

support services, such as technical assistance to the local governments, should

not be reduced.

Increased Federal participation will be

needed if the region is to accommodate the

growth anticipated under scenarios 3 and 4.

Several kinds of support could be given. One

option would be to provide additional financing for expanding the communities and for

planning and establishing new ones. Another

would be to create Federal programs to solve

problems for which local groups have neither

the time nor the resources. For instance, difficulties may arise from inequities in the distribution of revenues among States. These

could be evaluated, and Federal actions

taken for their correction. Such problems will

occur if the workers for Utah developments

choose to live in Colorado; Utah will gain tax

revenues from the plants but Colorado will

have to pay for the consequences of increased growth in its rural areas. Yet

another option would be to expand Federal

R&D efforts. As an example, it would be valuable to have estimates of the maximum rate

at which the communities could grow without

experiencing severe disruption. These estimates could be used by policymakers to adjust the timing and location of additional Federal oil shale leases to take into account socioeconomic impacts.

Which of the options would be best will depend on the success of local preparations and

on the nature and timing of new development.

If the industry grows slowly, Federal participation might be limited to R&D and other supporting activities. If it expands rapidly, substantial direct financial support and active

growth management efforts will be needed.

For example, a coordinated strategy will be

required to cope with the growth that would

accompany the production of 1 million bbl/d,

as envisioned by scenario 4; and the responsibilities would have to be shared by Federal,
80 An Assessment of Oil Shale Technologies

State, regional, and local governmental units

as well as by all private sectors. Extensive

Federal participation would be unavoidable.

One option would be to create a new Federal

regional authority, for the impacts will extend into Utah and Wyoming. The powers

granted to such an authority would depend on

the degree of coordination and cooperation

between the public and private sectors, and

on the severity of the negative impacts. For

instance, construction of new homes, apartments, and other living facilities will have to

be financed. This will involve private parties

like lending institutions, and possibly the oil

shale developers. But where private capital is

insufficient, the Federal or State governments will have to step in. Housing is only one

sector where the needs can be expected to

outstrip the resources, and where combined

efforts to meet them will be essential. Many

agencies, operating in many areas and at all

levels, would have to be involved to cope with

the growth that would accompany the establishment of a l-million-bbl/d industry by 1990.

Scenario Evaluation

As has been shown for the four scenarios,

different development strategies entail substantially different requirements, consequences, and Federal actions. Regardless of

the strategy selected, tradeoffs among objectives and requirements are inevitable. This is

indicated in figure 11, where the scenarios

are rated according to the relative degrees to

which they are expected to attain the objectives for development. The following summarizes how the attainment of each objective

varies with the production goals.

To position the industry for rapid deployment.—The 400,000-bbl/d industry is given

the highest rating because a wide variety

of technologies and sites would be evaluated and substantial technical, environmental, and economic information would

be obtained; all of which would place the

industry in a good position for rapid scaleup. The l-million-bbl/d goal is rated next

since production at this level would constitute a major industry; further rapid deployment could then follow. It is rated lower

than the 400,000-bbl/d” scenario because its

accelerated construction schedule would

preclude valuable precommercial experiments and would probably not result in the

most technically efficient plants. The other

goals are rated lower because fewer processes could be evaluated.

To maximize energy supplies.—The benefits, and thus the ratings, are proportional

to the production rate.

● To minimize Federal promotion.—The

100,000-bbl/d target is rated highest because it could be achieved by completing

the presently active projects. The 200,000-

bbl/d goal probably would require some incentives, and the 400,000-bbl/d” one would

require incentives, a small land exchange,

and the short-term leasing of a Federal

R&D facility in Colorado for a demonstration project. The l-million-bbl/d target

would require much stronger subsidies, additional leasing of public land for a longer

period, permitting modifications, variances, and extensive Federal involvement

in growth management.

● To maximize ultimate environmental information and protection.—The quantity of

pollutants and wastes generated will increase in proportion to the rate of production. Establishing a l-million-bbl/d industry

in 10 years would cause the most disturbance per unit of production because there

would not be enough time to improve the

control technologies. The 100,000-bbl/d industry is also given a low rating because

the limited number of technologies tested

would provide neither extensive information on impacts nor guidance for the improvement of controls and regulations. The

400,000-bbl/d target would meet the needs

for information and testing of control technologies but would incur a greater environmental risk per unit of production than
Ch 3–Constraints to 011 Shale Commercialization Policy Options to Address These Constraints ● 81

Figure 11 .—The Relative Degree to Which the Production Targets Would Attain the Objectives for Development

1990 production target, bbl/d

100,000 200,000 400,000 1 million

I To position the industry for rapid deploymentI I

To maximize energy supplies

To minimize federal promotion

I To maximize environmental information and I

1 I

protection I

To maximize the integrity of the social

environment

To achieve an efficient and cost-effective

energy supply system

Lowest degree of attainment I

I _ Highest degree of attainment

SOURCE Off Ice of Technology Assessment

●

200,000 bbl/d. The latter would maximize

the attainment of this objective.

To maximize the integrity of the social environment. —The 100,000-bbl/d target is

rated high because this level of growth

should be within the physical capacities of

the communities. The 200,000-bbl/d” goal

would create some strain in the ability of

the towns to absorb the number of expected new residents; the degree of stress

would depend on the location of the development. Adjusting to the growth associated

with a 400,000 -bbl/d industry would be

possible if the plantsites were dispersed in

Utah and Colorado, if plant construction

were phased, and if preparations for the

construction of new towns were started at

once; but there would be a high probability

that boomtown effects would accompany

this level of growth. A l-million-bbl/d industry would require coordinated growth management strategies and extensive financial

outlays. Severe social disruption could be

anticipated.

● To achieve an efficient and cost-effective

energy supply system.—The 400,000-bbl/d

target has the highest rating because,

among other factors, it would provide a

balance of information generation and

process development and demonstration.

The 100,000- and 200,000-bbl/d targets are

rated lower because only a few technologies and sites would be tested. The l-million-bbl/d industry is also rated low because its deployment strategy would poorly

utilize many of the elements of production.

Furthermore, the plants might not generate

sufficient profit capital for subsequent expansion.

An illustration of the need for tradeoffs between objectives can be seen at the l-millionbbl/d level. This choice has high attainment of

the positioning and energy production objectives (e.g., it would displace about 16 percent

of the imported oil and reduce the balance of

payments significantly). However, reaching

the target requires tradeoffs in all the other

areas. (For example, it would violate the

Clean Air Act.)
— — —

CHAPTER 4

Background
Contents

Pag e

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

The Need for a New Energy Supply System. , . 85

The Purpose and Organization of This Chapter 86

Oil Shale Resources . . . . . . . . . . . . . . . . . . . . . 87

The Genesis of Oil Shale. . . . . . . . . . . . . . . . . . 87

Worldwide Deposits . . . . . . . . . . . . . . . . . . . . . 87

Deposits in the United States . . . . . . . . . . . . . . 88

Description of the Oil Shale Resource Region. 93

Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Topography and Geology. . . . . . . . . . . . . . . . . 93

Climate and Meteorology. . . . . . . . . . . . . . . . . 99

Plants and Animals. ... , . . . . . . . . . . . .. ....100

Air and Water Quality and Economic Base. .. 103

Oil Shale Products and Their Potential

Applications . . . . . . . . . . . . . . . . . . . . .. ...105

The Nature of Oil Shale . .................105

Kerogen Pyrolysis. . . . . . . . . . . . . . . . . . . . . .. 105

Associated Minerals. . . ..................107

The History of Oil ShaleDevelopment. .. ....108

Scotland . ............................,108

Sweden . . . . . . . . . . . . ................,..108

France . . . . . . . . . ................,......109

Spain . . . . . . . . . . . ......................109

Germany . . . . . . . .......................109

South Africa ..,.... . ...................109

Australia. .,...... . ....................109

United States, . . . .....................,.110

Status of Foreign Oil Shale Industries . . . . . . .111

Morocco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

Soviet Union . ..........................111

People’s Republic of China. . .....,..,.....112

Brazil. ...,..... . ......................112

Pag e

Status of U.S. Oil Shale Projects . ..........113

Chapter 4 References. . ..................114

List of Tables

Table No.

13. Potential Shale Oil in Place in the Oil

14

15

Shale Deposits of theUnited States . . . . .

Potential Shale Oil in Place in the Green

River Formation: Colorado, Utah, and

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . .

Potential Shale Oil Resources of the

Green River Formation . . . . . . . . . . . . . .

16. Composition and Pyrolysis Products of

Typical Colorado Oil Shale . . . . . . . . . . .

17. Status of MajorU.S. Oil Shale Projects. .

List of Figures

Figure No,

12. Oil Shale Deposits of the United States. .

13. Oil Shale Deposits of the Green River

Formation . . . . . . . . . . . . . . . . . . . . . . . . .

14. The Oil Shale Resource Region of the

Green River Formation: Colorado, Utah,

and Wyoming. . . . . . . . . . . . . . . . . . . . . .

15. Major Mountain Systems in the Vicinity

of the Green River Formation . . . . . . . . .

16. Topographic Relief of the piceance

Basin, Colo,. . . . . . . . . . . . . . . . . . . . . . . .

17. Stratigraphy and Landform Units Along

Parachute Creek,Piceance Basin, Colo. .

18. Idealized Cross Section of the Piceance

Page

89

91

92

106

114

Page

89

90

94

95

96

97

Basin, Colo. . . . . . . . . . . . . . . . . . . . . . . . . 98
CHAPTER 4

Background

Introduction

The United States has obtained energy for

human comfort, security, and productivity

from a variety of sources over the past 200

years. The availability of energy was instrumental in its transformation from a largely

agricultural society until the late 18th century to a major industrial power in the 20th.

During all of the 18th century and early

19th, human muscles and those of beasts of

burden did most of the useful work. Throughout this period, wood was the primary fuel,

supplemented by relatively small amounts of

coal, coal oil, whale oil, mechanical energy

from falling water, and kerosene derived

from natural petroleum seeps. By the middle

of the 19th century, coal had become the

chief fuel and dominated the Nation’s energy

supply system for about a hundred years.

Petroleum-based fuels and natural gas entered the picture after 1859, the year in

which the first commercial oil well was

drilled in Pennsylvania. The use of petroleum

grew rapidly. It was further accelerated by

the arrival of the automobile age in the early

1900’s. Natural gas, which was originally

burned or vented as a waste product from oil

wells, became a major fuel for domestic, commercial, and industrial heating by the end of

World War II.

By the middle of the 20th century, oil and

gas had become the leading sources of energy

in the United States, having displaced coal

because of their convenience. In 1972, according to the Department of Energy (DOE),

the Nation’s economy consumed approximately 72 Quads of energy from primary

sources, * of which approximately 46 percent

was obtained from petroleum, 32 percent

from natural gas, and 17 percent from coal.

Relatively small amounts were supplied by

*One Quad equals 1 quadrillion ( 101 Btu. A primary energy

source is one that may be converted to another form prior to

end use. Coal burned for power genera t ion is an example.

hydroelectric dams, nuclear powerplants,

geothermal sources, biomass, and other energy resources. Wood, once the principal energy source for the Nation, was used largely by

some lumber mills and wood-processing facilities.

The Need for a New Energy

Supply System

In 1973, Arab oil exporting nations instituted an embargo against the United States

and other nations that supported Israel. Reduced petroleum availability was followed by

a recession that lasted through 1974 and into

1975. As a consequence, energy consumption

declined slightly, bottoming out at about 71

Quads in 1975. By 1976, energy demand had

returned to its 1973 level of about 74.5

Quads/yr. It has continued to rise, although

somewhat less rapidly than prior to the embargo.

In 1978, approximately 78 Quads of energy

were consumed in the United States—the

equivalent of 13.4 billion bbl of fuel oil.

Energy supply patterns had altered slightly

since 1972. In 1978, petroleum supplied about

48 percent of the energy, natural gas about

25 percent, and coal about 18 percent. Geothermal and biomass use had increased substantially, but these resources, together with

nuclear and hydropower, still provided only

about 9 percent of the Nation’s energy.

It is likely that energy consumption will

continue to rise until conservation strategies

are adopted by all sectors of the economy. If

historical growth trends for energy consumption are followed, the annual energy consumption will reach 135 Quads by the year

2000-the equivalent of over 23 billion bbl of

fuel oil per year or nearly twice the 1978 consumption. Actual consumption should be considerably lower, because energy demand is

85
86 ● An Assessment of 01/ Shale Technologies

now growing more slowly than in the past.

Conservation should slow it down further.

Several implications may be drawn from

this discussion. First, the United States consumes enormous amounts of energy. (The

1978 consumption was equivalent to over

2,500 gal of fuel oil per citizen per year, ) Second, energy demand will continue to rise in

the near future. Third, the Nation runs on

fossil fuel, with petroleum satisfying nearly

50 percent of the total energy demand.

This last implication is crucial because it

appears that the United States no longer has

adequate petroleum reserves of its own. New

petroleum discoveries peaked in the 1950’s.

Domestic oil production followed suit in about

1970, except for the fields in Alaska and on

the Continental Shelf. Domestic discoveries

are increasing, at present, because of higher

oil prices, but it is unlikely that sufficient U.S.

reserves exist to provide secure supplies beyond the end of the 20th century. Because of

the inability of domestic petroleum development to keep pace with growing demands for

liquid fuels, the United States has become increasingly dependent on imported oil. In

1978, the United States imported nearly 24

percent of its total energy supply and nearly

45 percent of its requirement for crude oil

and refined petroleum products. A barrel of

imported petroleum now costs five to six

times as much as it did in 1972.

The short-term reliability of imported oil

supplies is very uncertain, as exemplified by

disruptions arising from the Suez crisis of

1956, the Arab-Israeli War of 1967, the Arab

oil embargos of 1973 and 1974, and the present Iranian situation. Long-term reliability is

also questionable because worldwide oil production is expected to peak within the next

few decades and to decline rapidly thereafter. Eventually, it may be impossible to import oil at any price.

Growing reliance on increasingly scarce

and expensive energy imports has had many

adverse effects. Some of the economic impacts (such as balance-of-payments deficits)

can be quantified with some degree of precision. Other, less tangible effects (such as

threats to national security and the social

and economic impacts of supply disruptions),

although more difficult to quantify may prove

to be much more significant. It has become

apparent that an energy supply system needs

to be evolved that is more appropriate to the

Nation’s present and projected needs and internal resources. Just as wood was displaced

by coal, coal by domestic petroleum and gas,

and domestic petroleum by imported oil, it appears that imported energy must be replaced

by new sources of domestic energy.

An initial step in developing a new energy

supply system should involve formulating a

comprehensive policy that reduces demand

through conservation, increases availability

from domestic resources, and restricts imports. Conservation must be an important element of any such policy. However, there are

limits to the savings that can be accomplished

through conservation. Thus, it appears that it

will be necessary to develop new energy resources. Potential sources include additional

reserves of conventional oil and gas, enhanced oil recovery, expanded coal development, solar-thermal and photovoltaics, wind

energy, tidal energy, ocean thermal gradients, increased nuclear fission for power generation, nuclear fusion, biomass combustion,

and the recovery of synthetic liquid and gaseous fuels by the conversion of coal, tar

sands, biomass, and oil shale. The challenge

is to derive optimal combinations of these

sources which, when coupled with conservation and restricted imports, will provide sufficient energy for future economic growth and

development, while simultaneously protecting

the Nation’s physical and social environments.

The Purpose and Organization

of This Chapter

As noted in the Introduction to this report,

this assessment is concerned with only one of

the Nation’s energy supply opportunities, oil

shale—specifically with deposits in the Green

River formation of Colorado, Utah, and Wyo-
Ch 4–Background ● 8 7

ming. Although the oil shale literature is ex- ●

tensive, the information is inadequate concerning certain environmental, socioeconomic, technological, and financial aspects of oil

shale development. However, the assessment’s overall analysis has been facilitated

by the extensive body of background information acquired during the Nation’s long but ●

sporadic involvement with oil shale as an

energy resource. The purpose of this chapter

is to organize this background information

into a supporting framework for the detailed

analyses found in subsequent chapters. The

following subjects are discussed: ●

● the location and extent of the oil shale

resources of the United States and foreign nations;

the characteristics of the resource region in Colorado, Utah, and Wyoming, including brief descriptions of the geography, the geology, the climate, and the

physical and social environments;

the potential applications for materials

derived from the Green River oil shales,

including oil, fuel gases, minerals, and

spent shale; and

the history and status of development efforts in the United States and other

countries, with emphasis on the efforts

currently underway in the Green River

formation.

Oil Shale Resources

The Genesis of Oil Shale

Oil shale is a sedimentary rock that contains organic matter, which although not appreciably soluble in conventional petroleum

solvents can be converted to soluble liquids

by heating. Oil shale was formed in the distant past by the simultaneous deposition of

mineral silt and organic debris on lakebeds

and sea bottoms. As the raw materials accumulated, heat and pressure transformed

them into a stable mixture of inorganic minerals and solidified organic sludge. The formation processes that yielded petroleum, tar

sands, and coal were conceptually similar,

but differed with respect to key physical and

chemical conditions. In oil shale, these conditions resulted in the formation of chemical

bonds between individual organic molecules.

The large size of the molecules formed by this

bonding prevents them from dissolving in normal solvents. When heated in processes

known as pyrolysis and destructive distillation, the bonds rupture forming smaller liquid

or gaseous molecules. These can then be separated from the inorganic matrix, which remains behind as the spent shale waste product .

Photo credlf Department of the /nfer/or

Oil shale sample showing layers of organic composition

Worldwide Deposits

Oil shale deposits have been found on all of

the inhabited continents. The extent of the

worldwide resources cannot be accurately

determined, but it appears to be very large indeed. In 1965, the U.S. Geological Survey
88 ● An Assessment 01 01/ Shale Technologies

(USGS) estimated that the world’s oil shale

deposits comprised over 4 quadrillion tons,

having a total potential shale oil yield of over

2 quadrillion bbl. If all of this oil were extracted and distributed among the world’s

residents, each person would receive about

600,000 bbl. However, the spent shale waste

would cover the entire surface of the world,

land areas and oceans included, to a depth of

about 10 ft.

The deposits in Asia contain the largest

amount of potential shale oil resources, over

700 trillion bbl; Africa is second, with nearly

500 trillion bbl; North America contains over

300 trillion bbl; South America (principally

Brazil) about 250 trillion bbl; Europe has

about 170 trillion bbl; and Australia and New

Zealand together have only about 120 trillion

bbl.

Many of the world’s deposits have been

subjected to commercial-scale development

at various times in the past. Those in Scotland, France, Germany, Australia, Sweden,

Spain, and South Africa are of historical interest because of the industries that once

flourished in those countries. The deposits in

Estonia, Manchuria, Brazil, and Morocco are

of current interest because they are the sites

of present or projected commercial development.

Deposits in the United States

Overview

The oil shale deposits in the United States

are shown in figure 12, and their theoretical

shale oil yields are given in table 13. The deposits in the Green River formation in Colorado, Utah, and Wyoming are particularly noteworthy because they contain the largest concentration of potential shale oil in the world.

Because deposits in the Central and Eastern

United States underlie a larger area, they appear more impressive on maps than do those

of the Green River. However, they contain

less than half the oil shale in the Green River

formation, and do not yield as much oil on a

unit basis because of a lower proportion of

hydrogen to carbon in their organic component.

Some of the eastern shales have attracted

interest because of the natural gas resources

locked within the shale formations. DOE is

presently supporting a research and development (R&D) program to evaluate the potential

of eastern shales for producing this fuel, with

special attention given to stimulating gas production from the Devonian shales that occur

in and around eastern Ohio and the western

part of West Virginia. The Antrim shales in

southern Michigan are also being investigated as potential sources of synthetic pipeline gas, which would be obtained by underground gasification methods. DOE is also

investigating the Chattanooga oil shales in

Tennessee and Kentucky. In addition to their

organic component these shales contain lowgrade uranium and thorium ores. But they do

not appear to have much commercial potential because the beds are thin and unfavorably located, and ore concentrations are very

low.

The Green River Formation

The Green River formation is a geologic entity underlying some 34,000 mi2 of terrain in

northwestern Colorado, southwestern Wyoming, and northeastern Utah. (See figure 13. )

The formation has been divided into several

distinct geologic basins. The Green River,

Great Divide, and Washakie basins occur primarily in Wyoming. Together with the Sand

Wash basin in northern Colorado, these basins underlie about 14,000 mi2

. About 35 million years ago they were occupied by a single

large and long-lasting freshwater lake.

The Uinta basin in northeastern Utah and

northwestern Colorado and the Piceance basin in Colorado underlie about 20,000 mi2 of

terrain, and were once occupied by a second

freshwater lake. Most of Colorado’s Piceance

basin lies north of the Colorado River, but it

includes oil shale deposits within Battlement

Mesa and Grand Mesa on the south side of

the river. Colorado oil shale also occurs in the

Sand Wash basin, which is north of the Piceance basin near the Wyoming border.
Ch 4–Background ● 8 9

Figure 12.—Oil Shale Deposits of the United States

/u_ --—4’ ‘1

,.

Monterey Formation, Califorma;

I middle Tertiary deposits In

I + - \

Montana. Black areas are

_- —- -

known htgh-grade deposits.

i “’=’~ ‘Y

-—+.+. (_ - ‘). — -- ‘,7 Mesozoic deposts

i~ 1, )- - ~ ,/ Marine shale m Alaska

r

- - -

1

- -%’ ---

I— --

~-— . i

r’ Permian deposits

“)

1’ Phosphoric Formation,

‘-./-’; ‘“

T

Montana

\

o 200 400 600

‘\.. ~

MILES

Devonian and Mississippian

deposits (resource estimates

included for hatchured areas

only). Boundary dashed

where concealed or where

location is uncertain,

SOURCE D C Duncan and V E Swanson, Orgarr/cR/ch Sha/es of the Urr/fed States arrd Wor/d Larrd Areas, U S Geological Survey Ctrcular 523, 1965

Table 13.–Potential Shale Oil in Place in the Oil

Shale Deposits of the United States (billions of barrels)

Range of shale oiI yields,

gallons per ton

Location 5- 10a10- 2 5

a 25- 10 0a

Colorado, Utah, and Wyoming (the

Green River formation ) 4,000 2,800 1,20 0

Central and Eastern States (Includes

Antrim, Chattanooga, Devonian, and

other shales ) 2,000 1,000 (?)

Alask a Large 200 250

Other deposit s 134,000 22,500 (7)

Tota l 140,000+ 26,000 2,000(?)

ar)rder of magnitude est[mate Includes known deposits extrapolahon and !nterpolallon of known

deposits and anhc!paled deposits

Dala from D C Duncan and V E Swanson Orgarr/c-R/ch SJWes of Me LMed Safes md

Wor/d Larid Afeas U S Geological Survey Circular 523 1965

Oil shale resources have been found under

some 17,000 mi2

, or 11 million acres, of the

basins of the Green River formation. The

principal deposits are found in the Piceance,

Uinta, Green River, and Washakie basins.

These areas, and in particular the Piceance

basin, are among the most intensely explored

geologic regions in the United States. The U.S.

Bureau of Mines (USBM), USGS, and private

industry have drilled hundreds of exploratory

coreholes into the basin rocks. The earliest of

USBM’s efforts took place during World War

H. As a result, there is a considerable body of

geological information about some areas of

the deposits. Other deposits, particularly

near the fringes of the Uinta basin and the basins in Wyoming, are still largely unexplored.

To comprehend the potential value of the

oil shale in the Green River formation, it is

necessary to distinguish among deposits, resources, and reserves. A deposit is simply a

natural accumulation. A resource is a naturally occurring substance with properties

63-898 0 - 80 - 7
90 ● An Assessment of 011 Shale Technologies

Figure 13.—Oil Shale Deposits of the Green River Formation

I

IDAHO 8

I

—..

+

● Salt Lake City

I

I

L

.!. - *. , - GREAT

DIVIDE

BASIN

WYOMING

UTAH

SAND

WASH

BASIN

I

:R

-’”’”s !’

EXPLANATION

WP”:L

Area underlain by the Green River Formation Area underiain by oil shale more than

in which the oil shale is unappraised or 10 feet thick, which yields 25 gallons

low grade. or more oil per ton of shale.

SOURCE D C Duncan and V E Swanson, Orgarrlc-R/ch Shales of the Urvfed States and Wodd Land Areas, U S Geological Survey Circular 523, 1965

that can be put to use. A reserve is the equiv- mercial development. However, if the cost of

alent of money in the bank. All of the rocks in extracting fuels from the resource is greater

the Green River formation occur in deposits. than the value of the fuels obtained, the reSome of the deposits are also resources be- source is not a reserve. Reserves exist only

cause they contain sufficient oil shale, which when the resource can be extracted and

when properly manipulated can yield useful processed to yield products that can be marfuels to warrant being considered for com- keted at a profit.
Ch 4–Background ● 9 1

The total oil shale deposits of the Green

River formation contain, in place, * the equivalent of over 8 trillion bbl of crude shale oil,

including all rocks that would yield from 5 to

100 gal/ton of oil on destructive distillation.

However, many of these deposits are too thin,

too deeply buried, or too low in oil yield to be

included in a survey of oil shale resources,

because it would not be economically feasible

to develop them.

In table 14, the quality of the Green River

shale is evaluated according to thickness and

potential oil yield. Only deposits that yield at

least 15 gal/ton and are at least 15 ft thick are

considered even marginally attractive. This

group includes shales containing as much as

1.4 trillion bbl of shale oil in place. The highgrade shales are further defined as shale

beds that are at least 100 ft thick that would

yield at least 30 gal/ton. Their in-place oil content is an additional 0.4 trillion bbl, for a total

shale oil resource of about 1.8 trillion bbl, in

place.

The extent of the oil shale reserves cannot

be determined at present. Resources can be

regarded as reserves only when processes for

developing them appear to be economically

feasible. This has yet to be demonstrated for

oil shale processes. However, several attempts have been made to delineate particular Green River resources that would present

a greater potential for profitable extraction.

In 1972, the National Petroleum Council

(NPC) used published geological data to classify the shale beds according to thickness and

“~he ter-rn “in place” is used to indicate the quantity of oil

that would be created if the shale were retorted. As noted, oil

shale deposits contain essentially no oil as such.

richness, accessibility to underground mining, and the extent to which they had been explored. A summary of the results appears in

table 15. Data are presented for four classes

of oil shale resources. Classes 1 and 2 were

considered economically attractive for existing aboveground recovery technologies.

They include only the more favorably located

and better defined shale beds, which are at

least 30 ft thick and would yield at least 30

gal/ton. These two classes contain about 130

billion bbl of shale oil, in place. The shales in

class 3 might also be economically attractive,

but they are less well-defined, and their unfavorable locations could hinder commercial

development. Class 3 shales contain about

186 billion bbl. The bulk of the Green River

resources are in class 4, which includes

lower grade, poorly defined, and unfavorably

located deposits. Class 4 shales contain nearly 1.5 trillion bbl. Some of the deposits in

classes 3 and 4 may be suitable only for in

situ processing.

The total estimate shown in table 15 (about

1.8 trillion bbl) agrees well with the total

shown in table 14. However, the higher quality resources in the first three classes contain

only 315 billion bbl, which is about 2 percent

of the total estimated. The potential yield of

these deposits can be estimated by taking into

consideration the inevitable losses that would

occur during mining and processing. Conventional underground mining methods can recover from 60 to 70 percent of the oil shale in

a mining zone; large-scale aboveground mining can recover about 90 percent. Processing

the mined ore in aboveground retorts recovers approximately 90 to 100 percent of the oil

that would be recovered if the shale were disTable 14.–PotentiaI Shale Oil in Place in the Green River Formation: Colorado, Utah, and Wyoming

(billions of barrels)

Nature of the deposit Colorado Utah Wyoming Total

At least 100 ft thick with oil yields averaging at least 30 gal/ton ., 355 50 13 418

At least 15 ft thick with oil yields averaging at least 15 gal/ton,

excluding the deposits shown abov e 840 270 290 1,400

Totals (rounded ) 1,200 320 300 1,820

SOURCE W C Culberfson and J K Pllman 011 Shale In Um(ed Slates Mmera/ Resources U S Geological Survey Professional Paper 8?0 1973

pp 497503
92 An Assessment of Oil Shale Technologies

Table 15.–Potential Shale Oil Resources of the Green River Formation (billions of barrels)

Resource classa

Location 1 2 3 4 Total

Piceance basin (Colorado), ., ., ... 34 83 167 916 1,200

Uinta basin (Utah and Colorado) . . . . – 12 15 294 321

Wyoming basins .,, . . . . .,, . . . . . . . . . . . . . – – 4 256 260

Totals .,.,.,.,,,,.,,,.,,.,...,,,,,, 3 4 95 186 1,466 1,781

a 1 Deposits atleast 30 ftthlck andaveraglng 359al/ton

2 Dei)ost sat least 30 ftthlckandaveragmg 30gal/ton

3 Deposits slmllar to classes 1 and 2 but less well defined arm not as Iavorabley located

4 Poorly dehned depostts ranging down to 15 gal/lon

SOURCE An Inmal Appraisal by the 011 Shale Task Group t971-1985 U S Energy Oul/ook–An /rMerm Repofl, The Nahonal Petroleum Council,

Washington D C 1972

tilled under carefully controlled laboratory

conditions. If it is assumed that about 60 percent of the oil in the shale deposits could be

recovered, the resources in classes 1 through

3 could yield 189 billion bbl of crude shale oil.

The projected yield of 189 billion bbl of

shale oil is only a small fraction of the total

potential yield estimated—1.8 trillion bbl. It

is very small compared with the total in-place

shale oil content of the Green River deposits

(some 8 trillion bbl). To put the figure in a

meaningful perspective, the United States

consumed about 6.5 billion bbl of crude petroleum in 1978, of which about 2.8 billion bbl of

crude oil and refined products were imported. At the 1978 consumption levels, the

higher quality Green River resources have

the potential to supply all of the Nation’s

crude oil needs for 29 years or to replace imports for nearly 68 years. Looked at another

way, the resources in the first three classes

could sustain a l-million-bbl/d shale oil industry for over 500 years. The class 1 resources in Colorado’s Piceance basin alone

could supply it for nearly 56 years.

With existing data, a preliminary evaluation of the Green River resources can be

made with respect to their promise of commercial development, but the actual reserve

value is still highly uncertain. It is likely that

some of the deposits could not be developed

without unacceptably damaging the environment. It is also possible that some favorably

located resources could not be developed because of particular geotechnical characteristics (such as highly fractured ore zones or the

presence of excessive amounts of ground water) that were not considered in NPC’s analysis. In any case, the economic aspects of development are not well-understood because

large-scale technologies have not as yet been

built and operated. As previously observed,

the key criterion in estimating reserves is economic feasibility.

If all the above factors were given careful

consideration, it is possible that actual reserves would be very small. On the other

hand, it is also possible that an evaluation of

the potential of known resources for in situ

processing along with additional exploration

and research, could increase the reserve estimate. There are deficiencies in the NPC estimate that largely reflect the current status of

technical and geological knowledge. For example, over 75 percent of the Uinta basin deposits were placed in class 4 because they

have not been as thoroughly explored as

those of the Piceance basin. The analysis also

downgraded deposits that are not well-suited

to mining and aboveground retorting but

might be ideal for underground processing. If

the survey were revised in the light of present

knowledge, it is possible that the reserve estimate would be substantially increased.
Ch 4–Background ● 9 3

Description of the Oil Shale Resource Region

Location

The oil shale deposits of the Green River

formation underlie about 17,000 mi2 of terrain in northwestern Colorado, northeastern

Utah, and southwestern Wyoming. * Major

settlements in the area and major tributaries

that drain the region’s watershed into the

Colorado River system are shown in figure 14.

Topography and Geology

At the time of their deposition, the oil shale

basins probably resembled the fairly uniform

topography of continuous lakebeds. Tectonic

upheavals have since elevated them, and substantial erosion by wind and water have altered their terrain. Today, most of the oil

shale region is very rugged country. The topography of both the Uinta and Piceance basins is typified by rolling plateaus, cliffs, and

canyons. The elevation ranges from approximately 4,300 ft above sea level along the

Green River in the Uinta basin to more than

9,000 ft at a point near the southeastern edge

of the Piceance basin. This irregular topography strongly influences such characteristics

as climate, air motion and dispersion patterns, and the duration of the growing season.

The various mountain systems surrounding

the area of the Green River formation are

shown in figure 15, and the general topographic relief of the Piceance basin north of

the Colorado River in figure 16. This figure

does not show Battlement Mesa and Grand

Mesa, which lie to the south of the Colorado

River. These are part of the Piceance structural basin, but the characteristics of their oil

shale resources are not well known.

The main part of the Piceance basin is

bounded by the White River on the north, by

the Grand Hogback on the east, by the Roan

Cliffs on the south, and by Douglas Creek and

the Cathedral Bluffs on the west. Within the

basin are topographically high areas such as

*This area is slightly larger than Vermont and New Hampshire combined.

the Roan Plateau, which is relatively flat but

severely eroded by stream courses.

The southern escarpments (steep cliffs)

that overlook the valleys of the Colorado and

Green Rivers are the most spectacular features of both the Piceance and Uinta basins.

At several locations these sheer cliffs rise to

heights of 4,000 ft above the adjacent river

valleys. They are nearly continuous for a distance of some ZOO miles from the intersection

of the Roan Cliffs with the Grand Hogback

near Rifle along the Cathedral Bluffs on the

western side of the Piceance basin, to the intersection of the Book Cliffs with the Wasatch

Plateau at the western tip of the Uinta basin.

Escarpments along tributary canyons are

similarly impressive. The topography along

one stretch of Parachute Creek in the Piceance basin is depicted in figure 17. * At the

location shown, the maximum elevation is approximately 8,100 ft above sea level at the

ridge of the escarpment, and the minimum

elevation is about 6,100 ft in the adjacent bed

of Parachute Creek. The topography in other

tributary canyons is similar. For example, the

Roan Creek Valley (near the southern edge of

the Piceance basin) is more than 30 miles long

and from 2,000 to 3,000 ft deep. The Federal

oil shale lease tracts are located in less

eroded areas of the basin, and their topographic relief is much less dramatic. On tract

C-a, for example, the average difference in

elevation between valley floors and nearby

ridge tops is only about 300 to 600 ft.

Figure 18 is an idealized cross section of

the Piceance basin that shows the stratigraphic relationships between the various

structural members of the Green River formation, the overlying Uinta formation, and the

underlying Wasatch formation.** The bound-

*The Parachute Creek valley was the site of two oil shale development projects in the 1950’s and 1960’s, and additional

projects are currently being considered for the same locations.

**The Uinta formation was previously called the Evacuation

Creek member of the Green River formation in this area. See:

C. W. Keighin, “Resource Appraisal of Oil Shale in the Green

River Formation, Piceance Creek Basin, Colorado, ” Quarterly

of the Co~orado School of Mines, vol. 70, No. 3, July 1975, pp.

57-68.
94 . An Assessment Of Oil Shale Technologies

Figure 14.—The Oil Shale Resource Region of the Green River Formation: Colorado, Utah, and Wyoming

*. Rawlins

k $prlngs \

W-a weuAm VvYolMING

‘r ~~3~WASH1 /

Craig .Sttaamhmat .Snrinnc ----- “ ----- -r’‘“ ‘Y-

(/. /

UTAH

.1L,

d

F ti”’ER’%KEANCE- rRO\ UINTA BASIN

d’:;:;:on\ Cnl nRArm v

F

i

\

)

I l-.

Oil shale more than 15-ft thick and yielding 25 gal of 011

per ton of shale or more,

Unassayed or low yield

SOURCE. E DISante, “A Look at 011 Shale–What’s It All About, ” Sha/e Country Magazine, VOI 1, No 1, January 1975, p 7
Ch 4–Background ● 9 5

Figure 15.—Major Mountain Systems in the Vicinity of the Green River Formation

113” 112 111” 110” 109”

44” —

r-m=i ‘t%l” “‘-: i’o---‘*=

r---l==---+==, -

1 43”

m. --4x%!!--:-+% - -—-- —-1

-.. J

25 0 100 males

SOURCE U S Department of the Interior, F/rra/ Errv/ronrnenta/ SIaternent for the Protofype 0// Sha/e /-eas/rrg Program, GPO stock No 2400-00785, 1973. p 112

aries of these members, which are visible

along Parachute Creek, were shown in figure

17. The Green River formation is about 3,000

ft thick near the center of the basin.

The top strata of the section comprise the

Uinta formation, which underlies the surfaces of high plateaus in the Piceance basin.

The Uinta is largely barren sandstone and

siltstone with some interbedded oil shale.

Below the Uinta, at a depth of 500 to 1,000 ft,

is the Parachute Creek member of the Green

River formation, which is almost entirely oil

shale marlstone with occasional beds of volcanic material (tuff) and sandstone. Near the

basin’s depositional center, the Parachute

Creek member contains scattered deposits of

the minerals dawsonite, nahcolite, and halite.

Dawsonite, which contains aluminum, is occasionally found in thin layers between the oil
96 . An Assessment of Oil Shale Technologies

Figure 16.—Topographic Relief of the Piceance Basin, Colo.

SOURCE Goider Associates, Inc., Water Management m O// Sha/e Mmmg, September 1977, NTIS No PB.276086, p 73

shale beds. More commonly it occurs as microscopic crystals disseminated throughout

the oil shale. Nahcolite is sodium bicarbonate. It is a source of soda ash, a raw material

for glassmaking, and may also be used to

remove sulfur dioxide from stack gases.

Halite is sodium chloride, from which table

salt is made. The Parachute Creek member

also includes the Mahogany Zone, which contains oil shale yielding up to 70 gal/ton. Below

the Mahogany Zone, near the center of the

basin, is a region from which soluble sodium

salts have been leached out by the ground

water flows and which now contains saline

ground water. Near the bottom of the Parachute Creek member is the “saline zone, ”

which contains high concentrations of nahcolite and other sodium salts that have not been

leached.

The lower extremities of the Garden Gulch

and Douglas Creek members, which underlie

the Parachute Creek member, roughly coincide with the bottom of the ancient lake on

which the raw materials for the Green River

oil shales accumulated. The upper 200 to 300

ft of the Garden Gulch member contain clay

beds and deposits of shale having an appreciable organic content. ’ The Garden Gulch

shales are true shales in that their primary

inorganic components are aluminum-containing illite clays, unlike the oil shales of Parachute Creek, which are primarily composed

of dolomite (calcium and magnesium carbonate) rocks. Below the Douglas Creek member

is the Wasatch formation, which is largely

barren sandstone and mudstone. The Wasatch rocks generally form valley floors

throughout much of the Piceance basin. They
Ch 4–Background ● 9 7

Figure 17.— Stratigraphy and Landform Units Along Parachute Creek, Piceance Basin, Colo.

LANDFORM UNITS STRATIGRAPHY

I—CLIFFS (ESCARPMENT) UINTA FORMATION

2—MID-SLOPES GREEN RIVER FORMATION

3—SLIP AND ROCKFALL TERRAIN (TALUS) Tgp--PARACHUTE CREEK MEMBER

4—WASATCH FOOTSLOPES Tgg—GARDEN GULCH MEMBER

5-ALLUVIAL FAN Tgd—DOUGLAS CREEK MEMBER

6-CHANNEL LAND WASATCH FORMATION

SOURCE Bureau of Land Management, Draft ,Env~ronrnenfa/ Stafernenf for Proposed Deve/opfnenf of 0(/ Sha/e Resources by (he Co/ony Oeve/oprnen/ Operat(on In Co/

orado U S Department of the Interior, 1975 p III-101
98 . An Assessment of 01/ Shale Technologies

Figure 18.— Idealized Cross Section of the Piceance Basin, Colo.

SOUTH NORTH

Roan Plateau

Ledge

SOURCE Bureau of Land Management, Dralt EnVlr0nIr7ental Stater77ent tor Proposed Development O( 0// Sha/e Resources by the Colony Deve/oprrrent

Opera//on m Colorado, U S. Department of the Interior, 1975, p 111.13

do not contain any oil shale of commercial interest.

Variations in the properties of the various

strata have had significant effects on the topographic relief of the region. The Uinta formation sandstones cover the oil shale deposits over much of the Piceance basin. Over the

past several million years, outcrops of the

Uinta rocks have weathered considerably.

The organic-rich oil shale zones of the underlying Parachute Creek member, however,

have been much more resistant to weathering. The Mahogany Zone of the Parachute

Creek member is an outstanding example. It

is from 10 to 225 ft thick, contains oil shale

that has, in general, a high organic content,

and underlies an area of more than 1,200 mi2

in the Piceance basin. It also extends into the

neighboring Uinta basin. * Oil shale beds im-

*Green River oil shale has a Iaminar appearance because of

variations in the organic content of adjacent strata. Polished

sections of the richer beds resemble mahogany wood. Most oil

shale projects in the near term will be focused on the rich

shales of the Mahogany Zone. The other potential source of

rich oil shale, the Garden Gulch member, is probably too deep

for near-term commercial development.

mediately above and below the Mahogany

Zone are lower in organic content and less

resistant to weathering. Where the zone outcrops along tributary canyons, its richer

shales have resisted erosion, but the leaner

surrounding shales have not. Consequently,

the outcropping fringe of the zone is often

highly visible as an overhanging prominence

known as the Mahogany Ledge, which appears in most areas as a dark band along the

escarpment, as shown near the top of figure

17.

Gradual deterioration of the ledge has resulted in rockfalls and the formation of talus

(debris) slopes between the bottom of the

ledge and the river valley below. Such slopes

were indicated in figure 17 as slip and rockfall terrain. They are steep and unstable, particularly if naturally or artificially undercut.

Because talus slopes are naturally unstable

and lack sufficient permanent topsoil, they do

not provide favorable growing conditions for

most types of vegetation. However, varying

amounts and kinds of vegetation can grow on

some slopes depending on their aspect and
Ch 4–Background 99

the available moisture. The north-facing

slopes generally have fairly abundant vegetation; the south-facing slopes much less.

Climate and Meteorology

Climate

The climate of the oil shale region is classified on the whole as semiarid to arid. Annual precipitation varies from approximately

7 inches in the Wyoming plains to approximately 24 inches in the high plateaus of the

Piceance basin. Most of this occurs as snowfall, Snowpack, which commonly exceeds 30

inches on protected slopes, provides surface

runoff during the spring. Summer and fall are

usually dry, but there are short, heavy thunderstorms occasionally during the late summer months. These can cause flash flooding

in low-lying areas, Relative humidity is generally low to moderate, with high evaporation

rates throughout the region. Because of the

region’s abundant sunshine, most valley

floors and south-facing slopes are usually not

covered with snow during winter,

Average temperatures are generally moderate, but maximum daytime temperatures

can reach 100° F (38° C) at lower elevations

during midsummer, and winter temperatures

may drop to – 40

0 F ( –400 C) at higher elevations. The number of frost-free days varies

from 50 at higher elevations to 125 at lower

elevations. The limited rainfall and low relative humidity coupled with the short growing

season restrict the agricultural use of tillable

areas. Some forage crops are produced along

the tributary valleys within the basins, but

most food crops are grown outside of the basin along major rivers where adequate irrigation water is available.

Meteorology

The meteorology of the oil shale region in

Colorado is typified by year-round gradient

winds from the west that are interrupted only

by the passage of frontal systems. Migratory

low-pressure systems are frequently deflected around the entire region by the Sierra

Nevadas to the west and the Rocky Mountains to the east, Stagnant high-pressure cells

sometimes persist for days over the basins,

their passage blocked by the surrounding

high mountains. Adjacent mountain ranges

also contribute to the region’s dry climate.

Moist air from the Gulf of Mexico is blocked

by the Rocky Mountains, while moist air from

the Pacific is blocked by the Sierra Nevadas.

Flows from both directions lose most of their

moisture before reaching the oil shale area.

The frequent presence of dry, high-pressure

air cells over the basins causes an abundance

of clear sunny days with light winds and

large differences between daytime and nighttime temperatures.

Air Patterns

Localized wind patterns and other meteorological conditions are very sensitive to topography and elevation. For example, in the Piceance basin, shielding by the Cathedral Bluffs,

the gentle downward slope of the basin to the

northeast quadrant and the existence of deep

gullies, effectively channel surface wind

flows and decouple them from the prevailing

gradient winds. The shielding effect is provided by the sheer escarpment of the Cathedral Bluffs and Roan Cliffs along the southern

and western edges of the basin. When prevailing winds encounter the bluffs they must

rise approximately 3,000 ft to clear the upper

ridges. The rising air increases in speed and

generates turbulent eddies whose duration is

enhanced by the downward slope of the basin’s upper surface. The shielding of the escarpments combined with the basin’s downslope minimizes the effect of gradient winds

on surface wind patterns except along very

high ridges and plateaus. Airflows in the Colorado River valley, in tributary canyons, and

along the valleys and low hills atop the Roan

Plateau are almost entirely determined by local topography. They follow a drainage-wind

pattern and are nearly independent of the behavior of prevailing gradient winds aloft.
100 ● An Assessment of 0il Shale Technologies

The Mountain-Valley Breeze System

The predominance of drainage-wind patterns is exemplified by the mountain-valley

breeze system that has been observed on both

Federal oil shale lease tracts in Colorado. The

phenomenon is characterized by gentle downvalley air flows beginning around sunset and

prevailing for about 10 hours in winter, followed by gentle up-valley flows starting at

midmorning. On clear nights, when the upper

atmosphere is stable, layers of dense, cold air

form near ground level. Any cold air that

enters the valley along adjacent slopes will

tend to flow downslope into the stagnant cold

layer. In the early morning, sunlight gradually warms the surrounding slopes. The cold air

then disperses and flows upslope to become

entrained in the prevailing gradient winds. At

various times during the day and night, circular flow patterns and eddies may prevail

within the valley, but they will not carry air

from the valley unless gradient winds

the upper ridges are quite strong.’

Thermal Inversions and Their Implications

The mountain-valley breeze system

along

often

causes a layer of cold stagnant air to form

below a layer of warm air—a thermal inversion. Such inversions exacerbate air pollution

problems. There is little air transport out of

the cold layer, and pollutants emitted near

ground level will tend to accumulate there. Inversions are usually broken by surface heating during the daylight hours, but under certain adverse conditions they may prevail for

several days. Valleys with broad floors are

especially susceptible, particularly after a

snowfall. Snow cover reflects sunlight and inhibits the warming of the stagnant layer during the day, thus reducing the upward flow of

warm air that is essential to disruption of the

inversion. At night, the exposed snow surface

enhances the downward flow of air from the

valley ridges, thus increasing the thickness of

the inversion layer.

Studies have shown that Grand Junction,

Colo., which is located outside of the oil shale

basins, experiences one of the highest inversion frequencies in the United States. The inversions occur most frequently during the

winter and persist over 50 percent of the time

in the fall and winter months. Inversions

might be expected to occur less frequently on

the slopes and plateaus of the Piceance basin.

However, it has been predicted that inversion

episodes lasting from 3 to 6 days could occur

at least once a year over the entire region.3

Recent investigations performed on the Federal lease tracts have concluded that the pollutant dispersion potential of the basin is

good when contaminated air is released

above the higher plateaus, and relatively

poor when fumes are released into the valleys. The same studies have predicted that

trapping inversions, * such as are associated

with the mountain-valley breeze system,

should seldom persist longer than 24 hours.

Plants and Animals

The Green River formation underlies a

large area. Its soil characteristics show considerable variation over this area. In combination with climate, meteorology, and topography, soil characteristics largely determine the types of plant communities that can

be supported. These, in turn, influence the

diverse animal species that feed directly or

indirectly on them.

Plants

The vegetation of the region is highly diverse, and its makeup is strongly affected by

elevation. Most of the broader stream valleys

in the region contain fertile alluvial (floodplain) soils that support relatively luxuriant

growths of cottonwood, shrubs, and other

species. In contrast, the surfaces of steep

slopes and some upper plateaus are bare

rocks and ledges with little or no soil development. Vegetation is often absent or at best

quite sparse in such areas, especially in some

plateaus in Utah and Wyoming and in the Piceance basin where the saline rocks of the

*A trapping inversion is one that traps contaminated air regardless of the temperature at which the contaminants are released from their source.
Ch 4–Background ● 101

Garden Gulch member are exposed, Some

gently sloping upland areas contain thin and

poorly developed soils with occasional localized strips of alluvium. Plant cover in these locations varies from very sparse in the poorer

areas to relatively abundant over the alluvial

deposits. In general, the extent of vegetation

is strongly influenced by aspect. South-facing

slopes have much less vegetation because

their greater exposure to sunlight accelerates the evaporation of critical moisture.

In the high plains of southwestern Wyoming, soils are usually thin and dry, and vegetation is predominantly saltbrush-greasewood and related shrubs. There are limited

areas of Douglas fir forests and mountain mahogany woodlands in the northern fringes of

the Green River and Washakie basins. Soils

are somewhat thicker in the Uinta basin, but

the arid climate inhibits plant growth except

along the valleys of the major rivers, Saltbrush-greasewood and other shrubs dominate, but there are occasional stands of

mountain mahogany, oak shrub, pine, and fir.

In the Piceance basin, shrublands and

woodlands also dominate, and forestlands

are sparse. Shrubland plants consist primarily of mixed shrubs on moist soils at higher

elevations and sagebrush, which dominates

in all dry soils. Woodlands occur in thinner

soils at lower elevations, and are dominated

by pinyon pine and juniper, except where

grazing and other disruptions have allowed

intrusions of brushes and grasses. Forests

are primarily cottonwood along streams at

lower elevations, and Douglas fir and aspen

on northern and eastern slopes at higher

elevations,

Overall, plant life in the Green River formation area is less abundant than in other

regions that have ample rainfall and less

rugged terrain. However, the area contains

diverse plant communities that are well

adapted to their environment. Some of the

communities in the Piceance basin were studied by the developers of Federal lease tracts

C-a and C-b as part of the baseline-monitoring

function required for the preparation of detailed development plans. The baseline studies included a census of existing plant species

and a determination of the structural characteristics and successional status of plant communities. The results of these studies provide

an indication of the diversity of plant life in

the vicinity of proposed oil shale development

sites.

The plants identified on tract C-a included

5 types of trees, 36 shrub species, and 168

herbaceous species, of which 44 were classified as grass or grass-like. One of the plants,

dragon milkvetch, is on the Smithsonian Institution’s list of endangered plant species.

However, the species is not considered

threatened in Colorado.’ On tract C-b, 37

types of trees, shrubs, and vines were identified, together with 137 species of herbs.

Vegetation community types included pinyonjuniper woodlands and rangelands, upland

and valley sagebrush, Douglas fir forests and

aspen woodlands, mixed mountain shrublands, marshes, riparian areas, agricultural

fields, mountain grasslands and communities

dominated by bunchgrass, Great Basin wild

rye, rabbitbush, greasewood, and annual

wild plants. No threatened or endangered

plant species were found on tract C-b or on

tracts U-a and U-b, s Colony Development{ has

reported the presence of two endangered

plant species (yellow columbine and milkvetch) and one threatened plant species (sullivantia) along the valley of Parachute Creek.6

Animals

Many types of mammals, cold-blooded vertebrates, birds, invertebrates, and aquatic

systems exist throughout the oil shale regions. The diversity of vertebrates is among

the highest in the United States, a result of

the highly diversified habitats of woodland,

grassy shrubland, and high desert that characterize the area. In Colorado’s Piceance

basin, for example, more than 300 species of

birds, reptiles, mammals, and amphibians

have been found or are believed to exist. Similar numbers of animal species have been reported in other geologic basins of the Green

River formation. ’ Because of the relatively

low rainfall, wildlife of the region are highly
102 . An Assessment of Oil Shale Technologies

dependent on the stream systems and the

riparian habitats of their environs.

COLORADO’S PICEANCE BASIN

The Piceance basin is Colorado’s most important mule deer range. It is the principal

wintering ground for the White River herd,

the largest nonmigratory deer herd in North

America. Its size has been estimated at approximately 100,000 head.8 The northeast

corner of the basin normally supports the

highest deer concentrations in winter, and

the entire basin is considered to be a deer

range in the summer. Antelope are also found

there, but are primarily restricted to the

northern edge. Limited numbers of elk live in

the general area of the basin and especially

on the upper plateaus. A few mountain lions

roam over it, largely in pursuit of migrating

deer herds and sheep flocks, and a few black

bear are found at higher elevations in the

southern part. Coyotes and bobcats are regarded as abundant, but there has been no

detailed census of these predators. There

may be as many as 150 to 200 cottontail rabbits per square mile, and both snowshoe

hares and pine squirrels are found in the

Douglas fir forests of the high plateaus. Other

mammals present include yellow-bellied marmots, prairie dogs, ground squirrels, porcupines, chipmunks, red foxes, raccoons, badgers, and skunks, and from 150 to 250 wild

horses range throughout the entire area. The

avian species found in this basin include sage

grouse, partridge (stocked), pheasants, malPhofo credit OTA staff

lards and other ducks, mourning doves, pigeons, golden and bald eagles, and many

other species of migratory waterfowl, shorebirds, songbirds, hawks, eagles, and vultures.

Fish species include trout, suckers, and minnews.

g

UTAH’S UINTA BASIN

Utah’s Uinta basin is more primitive and

isolated than the Piceance basin. It has been

described as an ideal natural faunal habitat. ’() Parts of the basin are utilized by mule

deer herds as winter feeding areas, and small

numbers of elk are also present in restricted

areas. Transplanted antelope have become

established and appear to be flourishing.

Bears have been reported in the area but are

considered scarce. Mountain lions also range

over the basin, but their numbers are unknown. Other mammal species include coyotes, porcupine, bobcat, muskrat, beaver,

mink, rabbits and hares, and others. The Bureau of Land Management (BLM) has estimated that about 130 head of wild horse inhabit Utah’s oil shale lands. Most bird species

found in the Piceance basin are also found in

the Uinta basin. Fish live in the clear headwaiters of various tributaries but are less

abundant in the heavily silted lower reaches

of most rivers and streams. 11

WYOMING’S BASINS

Over 300 animal species have been identified in Wyoming’s Green River and Washakie

basins. Of the larger mammals, elk and moose

are believed to inhabit the parts of Wyoming

that encompass the oil shale regions. Relatively few elk and moose live in the oil shale

basins per se, but black bear and lions have

been observed. The basins also contain important antelope ranges and habitats. Sizable

numbers of wild horses live in the Washakie

basin and winter in the highlands where prevailing winds sweep the heavy snowfalls from

grazing areas. Several species of grouse,

ptarmigan, partridge, wild turkey, pheasant,

ducks, and geese have also been observed in

the general vicinity of the oil shale lands.

Tributaries support several trout varieties including the Colorado River cutthroat, and
Ch 4–Background ● 103

some of the better trout habitats are located

within the oil shale area. 12

ENDANGERED SPECIES

In compiling an inventory of animal species, the tract C-a lessees recorded sightings

of both peregrine falcons, listed as an endangered species by the U.S. Department of the

Interior (DOI), and prairie falcons, a fully protected species, The number of peregrine falcons was estimated at from one to four. No

falcon nesting sites were found in the 170 mi2

survey area. It is unlikely that falcons would

nest within the tract boundaries because of

the absence of large cliff faces (their preferred nesting location) and the scarcity of

water. Approximately 30 greater sandhill

cranes, endangered species in Colorado,

were observed in the study area, but no nesting sites were discovered within a 20-mile

radius of the tract. The tract and its environs

may serve as staging and foraging areas for

the birds during their annual migrations, but

the area does not contain any important

crane habitats. 13

The environmental reconnaissance on

tract C-b did not reveal any rare, endangered, threatened, or protected animal species. However, a prairie falcon was sighted

outside of the tract boundaries.14 Environmental surveys for Colony Development revealed no endangered or threatened species

within the tract boundaries.15 BLM’s environmental statement for the Colony program lists

several species of concern that might be present in the general area. These include the

southern bald eagle, the prairie and peregrine falcons, the humpback chub, the Colorado squawfish, the Colorado cutthroat trout,

the bonytail sucker, the black-footed ferret,

and the ferruginous hawk. 16

Air and Water Quality and Economic Base

Regional air and water quality, and their

potential alterations because of oil shale development, are discussed in chapter 8. The

region’s economic base, and the impacts it

might experience during the development of

an oil shale industry, are discussed in

chapter 10.

Air Quality

In general, air quality is excellent throughout most of the region because of the region’s

rural character and lack of industrialization

and urban development. Ambient concentrations of sulfur dioxide, nitrogen oxides, hydrogen sulfide, and carbon monoxide are

very low compared with more densely populated areas in the three oil shale States. In

both the Piceance and Uinta basins, however,

there are occasionally high ambient concentrations of nonmethane hydrocarbons, particulate, and ozone, The hydrocarbons are apparently emitted in aerosol form by sagebrush and other vegetation, because their

concentrations vary with the growing seasons for these plants. Windstorms and passing automobile traffic on unpaved roads both

contribute to high particulate concentrations.

Haze is occasionally observed in the valley of

the Colorado River and in the canyons of its

tributaries. It has not been determined

whether this haze is caused by photochemical

smog or by a combination of suspended particulate and local humidity. In general, the

area is free from man-induced odors. 17

Air quality problems may be encountered

in the future because of the region’s peculiar

meteorological conditions. As discussed previously, the predominance of the mountainvalley breeze system coupled with high altitudes and the effects of surrounding mountain ranges on gradient winds aloft, leads to

frequent thermal inversions, especially during winter. To date, such inversions have

been offensive only near the larger population centers outside of the oil shale basins,

such as Grand Junction. However, inversionrelated air pollution is likely to become more

severe as the region develops, regardless of

whether such growth is associated with the

creation of an oil shale industry or expansions in other activities. The potential for inversions may preclude siting processing

plants in canyons and other low-lying areas,
-.

104 ● An Assessment of 0il Shale Technologies

thus, limiting them to higher areas such as

the Roan Plateau of the Piceance basin.

Water Quality

Water quality in the region is highly variable. It is good to excellent in most of the

upstream reaches of major tributaries such

as the Colorado River, but significantly

poorer in the downstream reaches. The gradual deterioration is caused by discharges

from numerous point and nonpoint sources.

About half of the increase in salinity is related to the discharge of naturally saline

streams into the river system. The rest is generally related to the concentration of human

activities, such as urban areas, mineral development sites, and irrigated farmlands.

A twentyfold increase in salinity has been

noted in the Colorado River between its headwaiters and Imperial Dam in Arizona. 18 Salinity is of special concern because the Colorado

River system is important to the entire Southwest. Irrigated agriculture causes most of the

human-related salinity effects through salt

loading (picking up soluble salts from field

soils) and salt concentration (the evaporation

and transpiration of relatively pure water in

irrigation canals and fields).

Photo credit OTA staff

White River near Meeker, Colo.

Surface streams within the oil shale basins

also show wide variations in water quality. In

Piceance Creek, for example, the concentration of dissolved solids range from less than

400 mg/1 in the upper reaches to over 5,000

mg/1 at the discharge point into the White

River. f

’ Dissolved solids in Yellow Creek in

the Piceance basin range from about 700 to

3,000 mg/1. Water quality deteriorates in the

downstream direction because of natural surface runoff, agricultural return flows, and

the discharge of saline ground water from

aquifers in the Green River and Uinta formations. As described in chapters 8 and 9,

ground water quality in the aquifers of the Piceance basin varies enormously, from a low

of less than 250 mg/1 in the purer waters of

the upper aquifer above the Mahogany Zone

to over 63,000 mg/1 in the highly saline brines

of the lower aquifer in the northern portions

of the basin. In general, the ground water

from all the aquifers in the Piceance basin

does not satisfy the drinking-water standards

of the U.S. Public Health Service. There are

particular problems with respect to dissolved

solids, fluoride, and barium concentrations. 20

The quality of surface streams and ground

water in the Uinta basin shows similar extreme variability. The concentration of total

dissolved solids in the Uinta basin ground

water aquifers range from 350 mg/1 (which is

considered potable water) to 72,000 mg/1

(which is considered brine). In the Wyoming

oil shale basins, surface streams have dissolved solids concentrations from 150 to 855

mg/1, while concentrations in ground water

range from about 450 to 7,000 mg/l. 21

Population

The population density over the entire oil

shale resource region is low, averaging about

3 persons per square mile. The densities in

many areas are even lower. For example,

when the oil shale resources of a 2,500 mi2

area of the Uinta basin were mapped in 1967,

250 people lived in the entire area, with 200

of them living in the town of Bonanza. The

average population density of the area was

therefore about 0.1 persons per square mile. 22

The population of the entire Green River

formation region is approximately 120,000.

About 62 percent live in Colorado, 17 percent

in Utah, and 21 percent in Wyoming. The major communities are Grand Junction, Rifle,
Ch 4–Background ● 105

Meeker, Craig, and Rangely in Colorado; Ver- region’s present economy is based on agriculnal in Utah; and Green River and Rock ture (crop raising and sheep and cattle ranchSprings in Wyoming, Grand Junction, the ing), minerals production (oil, gas, uranium,

largest Colorado town, has a population of trona, and coal), and tourism and recreaapproximately 24,000, Vernal ‘has about tion,232425

6,200, and Rock Springs about 28,000, The

Oil Shale Products and Their Potential

The Nature of Oil Shale

Green River oil shale is not a shale nor does

it contain appreciable amounts of liquid oil.

The shale portion is actually a marlstone, and

its principal constituents are dolomite, calcite, and quartz. In contrast, true shales are

composed largely of silicate clays. They have

a finely stratified or laminated structure and

tend to fracture along individual bedding

planes. Oil shale also has a stratified appearance and tends to fracture in a similar matter, particularly when organic matter is present in low concentrations. These properties

led early investigators to believe that the

Green River oil shales were true shales. However, the appearance and fracture properties

of Green River shale arise from variations in

the concentrations of organic matter it contains, and not to any great extent from the

characteristics of the inorganic component,

Most of the organic component is a solid

material called kerogen, from the Greek

words for waxmaking, that is insoluble in

most standard petroleum solvents. About 10

percent of the organic component is a solid

substance called bitumen that can be dissolved in certain solvents.

Kerogen is composed of carbon and hydrogen molecules cross-linked together by sulfur

and oxygen atoms to form relatively large

three-dimensional macromolecules with molecular weights of about 3,000. These macromolecules are embedded within the finer

grained inorganic or mineral matrix of the oil

shale rock. This organic continuous phase

gives kerogen-rich oil shale most of its physical strength and stability. When the organic

matrix is removed from very rich oil shale,

the mineral

strength and

powder,

Applications

residue has little cohesive

is easily crushed to a fine

Kerogen Pyrolysis

When kerogen is heated above 400” F

(2000 C), chemical bonds between and within

the individual organic molecules are ruptured, forming smaller molecules. Most of

these can be readily isolated from the mineral

material as liquid and gaseous products.

Some of the organic coproducts of kerogen

decomposition remain trapped within the inorganic material as a coke-like residue.

A chemical change produced by heat is

called pyrolysis, This process can also be

called destructive distillation, when an organic substance is broken down by heat and

the products are distilled off, leaving a residue. When pyrolysis is carried out in a vessel

called a retort, the process is called retorting.

Oil shale retorts may vary in size from laboratory-size Fischer assay* units used to estimate the potential oil yield of oil shale rocks,

to commercial-sized vessels that can process

10,000 tons of raw oil shale per day, to in situ

retorts containing several hundred thousand

tons of rock.

When kerogen is pyrolyzed, three combustible products are formed: vaporized oil,

which can be condensed by cooling; a gaseous

mixture containing hydrogen, oxides of carbon, hydrogen sulfide, and hydrocarbon

*In a Fischer assay, small samples of crushed oil shale are

heated to 9320 F (500° C] under carefully controlled conditions.

The oil yield by this method is the standard measure of oil shale

quality.

63-398 “) - 80 - 6
106 ● An Assessment of 01/ Shale Technologies

gases such as methane; and a coke-like solid

residue that remains behind in the retort.

The relative proportions of oil, gases, and

coke largely depend on the pyrolysis temperature and atmospheric conditions in the retort,

and to a lesser extent on the organic content

of the raw shale. The product yields from a

typical Green River oil shale pyrolyzed at

932° F (500° C) according to the standard

Fischer assay technique are summarized in

table 16. As indicated, the raw shale conTable 16.–Composition and Pyrolysis Products

of Typical Colorado Oil Shalea

Mineral constituents

Mineral Weight percent of minerals

Dolomit e 32

Calcite 16

Quartz ~ 15

Illit e , . 19

Low-albit e 10

Adulari a 6

Pyrite ., . 1

Acalcime ~ 1

Total . 100

Ultimate analysis of organic constituent

Element Weight percent of organics

Carbo n 7 6 5

Hydroge n 103

Nitroge n 2 5

Sulfu r 1.2

Oxyge n 9.5

Tota l 1000

Yields from Fischer assay Pyrolysis

Weight percent of

organic constituent Weight percent of

Decomposition product in raw shale total raw shale

Oil 63 10,4

Noncondensable gas 15 2.5

Fixed-carbon residue 13 2.2

Water vapo r 9 1.4

Total ... . , 100 16,5

aPy@yzed by the slafldard Fischer assay procedure at 932° F 011 y(eld = ?6 7 gal/ton

SOURCE T A Sladek Recent Trends [n 011 Shale–Pad 1 Htstory Nature and Reserves

Mmera/ /nduslrfes f3u/e/in VOI 17 No 6 November 1974 pp 4.5

tained about 17 percent organic matter by

weight and yielded about 27 gal/ton. Oil was

the largest decomposition product. It comprised 63 percent of the organic matter

originally present in the shale, Noncondensible gases comprised 15 percent, and the carbon residue about 13 percent. The balance of

hydrogen and oxygen content of the organic

matter was transformed to water vapor by

the pyrolysis process.

Each of the three main products of kerogen

decomposition is a potential source of energy.

Crude shale oil can be burned directly as a

fuel or it can be refined to produce fuels similar to those obtained from conventional petroleum crude oils. As discussed in chapter 6,

the physical and chemical properties of crude

shale oil differ from those of conventional

crude, thus presenting some refining challenges. However, shale oil can yield highquality finished fuels such as gasoline and jet

fuel.

The composition and properties of the offgas from kerogen pyrolysis vary tremendously with the nature of the pyrolysis process.

Gas from the Fischer retort typically has a

heating value comparable to that of natural

gas. Such high-quality gas could be used as

plant fuel in the oil shale facility, or it could

be pipelined to other areas for commercial or

industrial applications. In contrast, gases

from commercial directly heated retorts are

highly diluted with carbon dioxide (from combustion and from the decomposition of carbonate minerals) and nitrogen. They have

only about one-tenth the heating value of

natural gas. Such gases could be useful

within the oil shale facility but they could not

be transported economically over any significant distance, nor could they be upgraded to

higher heating values at reasonable cost. Surplus retort gases could become valuable byproducts if they were burned for power generation. Some developers plan to do this.

The coke residue is also a potential source

of energy, but it is a very poor solid fuel compared with coal or with the raw shale itself.

(A typical shale coke from the Fischer retort

has a heating value of about 250 Btu/lb; most

quality coals have heating values of about

12,000 Btu/lb.) Transportation of the coke

residue for offsite combustion would not be

practical because of its high content of inert

mineral matter. Any energy values will have

to be recovered within the oil shale facility

either by burning the residue in the retorts or

by converting its carbonaceous component to
Ch 4–Background ● 107

fuel gas. If the latter approach is followed,

the gas may be consumed within the plant,

upgraded for external sale, or burned onsite

for power generation.

As indicated in table 16, inorganic minerals comprise approximately 80 percent of

raw Green River oil shale. These minerals remain as part of the coke residue after the oil

and gas products are removed. The properties of this retorted or spent shale vary with

the type of retorting procedure used. Indirectly heated retorts produce a carbonaceous

spent shale, while directly heated retorts produce a shale that is essentially stripped of

carbon. The indirectly heated TOSCO II retort, for example, produces a spent shale resembling black talcum powder. The directly

heated Union “A” retort produces a gray decarbonized spent shale resembling coal ash

and clinkers.

Spent shale will be produced in enormous

quantities by an oil shale industry of any

significant size. Some potential uses exist for

the spent shale produced by aboveground retorts. With in situ processing, the spent shale

remains underground, and the only option for

byproduct recovery is by means of a leaching

process. Spent shale on the surface could be

converted to cement or building materials,

but the output from a single commercial-size

facility will far exceed the market demand

for such material. Nearly all of the spent

shale will have to be disposed of as a waste

material, and such disposal will have to be

done either on or very near the plantsite.

Spent shale disposal is the source of much of

the environmental controversy surrounding

oil shale development as discussed in chapter 8.

Associated Minerals

In addition to kerogen, some deposits in the

Green River formation contain several sodium-bearing minerals that could be commercially valuabIe. These include nahcolite, dawsonite, and trona. Nahcolite (sodium bicarbonate) is chemically identical to commercial

baking soda. As mentioned previously, it occurs in scattered deposits near the depositional center of the Piceance basin and is

found in high concentrations near the bottom

of the Parachute Creek member. Nahcolite

may be processed to yield soda ash, a common raw material for glass production, and

its ability to adsorb sulfurous gases may be of

use in scrubbing sulfur compounds from powerplant stack gases.

Dawsonite (dihydroxy sodium aluminum

carbonate) is a potential source of alumina,

which can be converted to aluminum. As indicated previously, dawsonite is found as disseminated crystals and crystalline planes in

the Parachute Creek member. Occurrences of

both nahcolite and dawsonite are very extensive in this basin. A survey of mineral resources in the basin by USGS estimated that 1

m i

2 of terrain in the soda-mineral region

overlies 1 billion bbl of potential shale oil in

place, 130 million tons of nahcolite with a potential soda ash yield of 82 million tons, and

sufficient dawsonite to produce 42 million

tons of alumina. By comparison, the bauxite

deposits in the rest of the United States contain the equivalent of only about 30 million

tons of alumina.26

Trona is a hydrated mixture of sodium carbonate and sodium bicarbonate. It is also a

source of soda ash for glass production, and

is presently being mined for this purpose in

Sweetwater County, Wyo. Unlike nahcolite

and dawsonite, trona does not always occur

in intimate association with oil shale, and its

commercial development could take place

either with or without the related development of hydrocarbon resources. The existing

facilities in Sweetwater County do not recover shale oil. Projected plans for multiminerals

operations, such as those of Superior Oil and

the Multi Minerals Corp., call for the simultaneous production of shale oil, soda ash, and

alumina. 27 28

Both of these projects depend on acquiring

access to Federal land through land exchanges or leasing. No privately owned tracts

contain sufficient quantities of dawsonite and

nahcolite for their development to be economically attractive. Some sodium leases have

been issued for oil shale land, but these exclude the development of the associated oil

shale.
108 ● An Assessment of 011 Shale Technologies

The History of Oil Shale Development

Useful hydrocarbons have been extracted

from oil shale for many years. In the 14th century, Austrian and Swiss oil shales were pyrolyzed to yield “petro oleum, ” or “rock oil. ”

This was subsequently processed to yield an

ointment called Icthyol, a name derived from

the Greek words for fish-oil, in reference to

the fossilized fish remains frequently encountered in the marine oil shales of central Europe.

29 In 1694, England issued patent No. 33

for a retorting process that was claimed to

produce “oyle from a kinde of stone. ”30

In 1859, the first commercial oil well was

drilled in Pennsylvania. Prior to that year, at

least 50 commercial plants existed along the

Atlantic seaboard of the United States for extracting fuel oil from oil shales.]’ Also in 1859,

the first commercial oil shale retort began

operating in Scotland. It started an industry

that lasted for over 100 years.

In 1874, workers on the transcontinental

rail line found that rocks picked up from excavations along the Green River in Wyoming

ignited when used to protect campfires from

the night winds. The March 1874 issue of Scientific American noted that the railroad superintendent :32

. . . has caused analyses and experiments to

be made with this substance which proves to

be a shale rock rich in mineral oils. The oil

can be produced in abundant quantities, say

35 gallons to the ton of rock. The oil thus obtained is of excellent quality.

The rocks of interest were pieces of oil shale

from the Green River formation.

The use of oil shale as a fuel resource thus

predates the large-scale use of conventional

petroleum by several centuries. In the past

150 years, commercial industries have existed in Scotland, France, Germany, Spain,

South Africa, Australia, and the United

States. At present, industries exist or are

being started in Estonia, the People’s Republic of China, Brazil, and perhaps the United

States. The following section describes the

history of foreign and U.S. development efforts and defines the status of present industries around the world.

Scotland

Scottish oil shales occur in seams from 4 to

14 ft thick yielding approximately 22 gal/ton.

Reserves were originally estimated to contain

about 600 million bbl. The first retorting

plant was built in 1859. Its economic viability

was immediately threatened by the rapid development of conventional petroleum that

followed the drilling of the first commercial

oil well. The production of shale oil and valuable byproducts such as waxes, ammonia,

pyridines, * ammonium sulfate, and building

materials enabled the Scottish industry to

survive for over 100 years despite the high

cost of the oil in comparison with conventional crude oil. At its peak, the industry involved about 140 different companies and

processed about 3.3 million ton/yr of oil shale.

In 1919, the companies were consolidated

into a single corporation that subsequently

became a subsidiary of the predecessor of

British Petroleum. The industry was subsidized by the British Government with tax

credits and other incentives, but competition

from cheap petroleum forced the last plant to

close in 1962.

Sweden

Typical Swedish oil shales are about 50 ft

thick and yield from 6 to 15 gal/ton. The total

resource is estimated to be about 2.5 billion

bbl of shale oil in place. The Swedish oil shale

industry began in the 1920’s, with the largest

operations near the city of Kvarntorp. These

facilities featured two types of aboveground

retorts and a unique type of in situ process in

which the deposits were pyrolyzed with electric heaters. The industry reached a maximum capacity of 2 million tons of oil shale per

year (6,000 ton/d) and produced as much as

*Nitrogen-containing organic solvents also used to synthesize other useful products.
Ch 4–Background ● 109

550,000 bbl/yr of crude shale oil. Because of

the limited quantity of high-quality reserves,

and price competition from petroleum crude,

the industry ceased operation in 1966.

France

French resources total about 500 million

bbl of shale oil in place. They are of medium

quality and yield from 10 to 24 gal/ton. They

are more properly called bituminous shales,

rather than oil shales, because they contain

inclusions of asphaltic compounds. The

French industry began in 1840 and continued

intermittently until 1957. Its maximum

throughput was 0,5 million ton/yr of shale, attained in 1950. For most of its existence, the

industry was protected from competition with

foreign oil by excise taxes and import duties.

Spain

The best Spanish resources yield from 30

to 36 gal/ton. Reserves have been estimated

at about 280 million bbl of oil in place. The

Spanish industry began in 1922 using retorts

similar to those that had been developed in

Scotland. Maximum throughput for these

units was 220 ton/d, reached in 1947. In 1955,

new retorts from Scotland were installed. In

1960, the enlarged industry processed 1 million tons, supplying more than half of Spain’s

requirement of lubricating oil, Obsolete processing technology and high operating costs

forced the industry to cease operation in

1966.

Germany

German resources are estimated to contain

only about 2 million bbl of shale oil in place.

Oil yields average only 12 gal/ton. German

shales were developed as early as 1857, and

several retorts were operated in the 1930’s.

A major development effort was initiated during World War II in response to wartime fuel

shortages. The German industry used two

types of aboveground retorts and one in situ

process. A plant with about 30 Lurgi above-

-ground retorts was operated from 1947 to

1949. In 1961, a plant was built in the town of

Dotterhausen that burns finely crushed oil

shale in a fluidized-bed combustor. The heat

of combustion is used for power generation,

and the spent shale product is used to make

cement. The plant is the only active oil shale

facility in West Germany.

South Africa

Very rich deposits are found in South Africa. Oil yields reach 100 gal/ton, with an average of 55 gal/ton, and the deposits are located

just beneath coalbeds. South African shale oil

production began in 1935, and the industry

attained a maximum throughput of 800 ton/d

in the 1950’s, with a corresponding shale oil

production of 800 bbl/d. The industry was located in the country’s interior, and although

it was not directly subsidized by the government, its economic viability was enhanced by

the high cost of transporting competing petroleum from the seacoast ports to interior markets in the vicinity of the plants. The richer

deposits were eventually depleted, and the industry ceased operations in 1962,

Australia

Oil shale deposits are found throughout

Australia. Those of New South Wales and

Tasmania have been developed commercially. Total reserves are estimated at 270 million

bbl of shale oil in place. Most of the deposits

are very rich, with oil yields as high as 180

gal/ton. Shale oil production in New South

Wales began in 1862, and by 1892, about

100,000 tons of shale were being processed

each year. The Australian Government began

subsidizing the industry in 1917, but production ceased in 1925. Production of Tasmanian

shale oil began in 1910 and ceased in 1935. In

the interim, about 41,000 tons of oil shale

were processed, and 85,000 bbl of shale oil

were produced.

Production was resumed in New South

Wales early in World War II under the direction of the Australian Government. By 1947,

annual throughput reached 330,000 tons, and

about 100,000 bbl of shale-derived gasoline
110 ● An Assessment of Oil Shale Technologies

were produced annually. The production was

equivalent to about 3 percent of Australia’s

gasoline consumption. The plant was closed

in 1952 because of resource depletion, high

operating costs, and competition from conventional petroleum.

United States

As indicated previously, the U.S. oil shale

industry was an important part of the Nation’s energy economy before the first oil well

was drilled. At least 50 commercial plants for

extraction of fuel oil from eastern oil shales

existed prior to 1859. The industry disap

peared shortly after commercial petroleum

production began.

Between 1915 and 1920, supplies of domestic crude fell below demand, and oil imports

increased, especially from new oilfields in

Mexico. USGS indicated at that time that the

United States had only a 9-year reserve of

petroleum in the ground and that the outlook

for new discoveries was not good. At about

the same time, USGS announced that large

fuel resources were contained in the oil

shales of the Green River formation. When

combined with predictions of forthcoming

fuel shortages, the announcement triggered

an oil shale boom. Some 30,000 mining claims

were filed on Federal lands, and about 200

companies were formed to develop the resource. Retort development programs were

initiated at several locations, and at least 25

retorting processes were advanced to the

pilot-plant stage. Total shale oil production

was negligible, but interest was at an all-time

high. The boom ended abruptly with the discovery of large oilfields in eastern Texas. Oil

prices dropped to a few cents per barrel, and

interest in oil shale development essentially

disappeared.

Little R&D was conducted in the United

States until World War II. In 1944, out of concern for the hazards of imported energy, Congress passed the Synthetic Liquid Fuels Act,

which authorized USBM to establish a liquid

fuel supply from domestic oil shale. USBM began a comprehensive R&D program that has

continued to the present day, although oversight authority was transferred to the Energy

Research and Development Administration in

1974 and to its successor, DOE, in 1978.

One of USBM’s most significant early acts

was the establishment of a research facility

at Anvil Points on the Naval Oil Shale Reserve

near Rifle, Colo. Between 1944 and 1956, the

Anvil Points facility was used for mining

studies that led to the application of the roomand-pillar technique of underground mining.

The gas combustion retort, the predecessor of

modern directly heated retorts, was also developed during this period. In 1964, the facility was leased by the Colorado School of

Mines Research Foundation, and was the site

of a 4-year development program in which the

gas combustion retort was evaluated and improved by a consortium of six major oil companies: Mobil, Humble, Continental, Pan

American, Phillips, and Sinclair.

In 1973, the facility was leased by Development Engineering, Inc. (DEI), which operated

it for 5 years during which the Paraho retorting process was developed. This is an improved version of the gas combustion retort.

DEI then used the facility to produce over

100,000 bbl of shale oil for refining studies,

and has recently proposed to use Anvil Points

for further development work, including the

construction and operation of a commercialsize module of the Paraho retort.

Between 1963 and 1968, DOI evolved a

leasing proposal that was intended to encourage private development of the Federal oil

shale lands in the Green River formation. The

program failed to attract private participation. However, it gave rise to the current

Federal Prototype Oil Shale Leasing Program,

which was conceived in 1969 and promulgated in 1974 with the sale of leases to

four tracts in Colorado and Utah. The histories of these leasing programs are presented in volume II of this report. The status

of development efforts on the Federal lease

tracts is described in the last section of this

chapter.
Ch 4–Background 111

In addition to these activities on Federal

lands, private companies have also engaged

in exploration and R&D programs on their

own lands, The companies that have been

most heavily involved are: Union Oil, Occidental Petroleum and its subsidiary Occidental

Oil Shale, Inc.; Superior Oil Co.; and the Colony Development Operation group, which has

included Tosco, Atlantic Richfield, Cleveland

Cliffs Iron Co., and Ashland Oil Co. The activities of these companies, and others that are

presently involved in oil shale development,

are summarized in the following section,

together with a status report on the industries in other countries.

Status of Foreign Oil Shale Industries

Morocco

Oil shale is found in Morocco at Timahdit,

in the Middle Atlas mountains, and at Tarfaya, on the Atlantic coast in the southern

part of the country. Other, smaller deposits

have also been found. Most of the development efforts involve the Timahdit deposits,

which contain an estimated 4 billion to 9

billion bbl of shale oil in a seam that is as

much as 350 ft thick. The Moroccan Government is actively investigating aboveground

retorting, direct combustion of oil shale for

power generation, and modified in situ processing technologies.

Soviet Union

The principal reserves of the U.S.S.R. are

in the Baltic Basin, with additional deposits in

the Ukranian S.S.R. and the Central Asian Republics. The latter resources have been little

explored and are not being developed; most

development activity is centered on the “kukersite” oil shales in the Baltic basin. The

total Baltic resource is estimated to be about

21 billion tons, with about 11.3 billion tons

regarded as having commercial potential.

About 8.4 billion tons occur in the Estonian

S. S. R., with about 2.9 billion tons in the Leningrad area. The Estonian shales occur in beds

about 10 ft thick and are buried beneath 30 to

130 ft of overburden. They are of good quality, yielding about 50 gal/ton.

The Estonian deposits were first developed

in the 1920’s after the State achieved independence from Finland. In 1939, about 1.7

million tons were processed. About 60 percent of the shale was retorted to obtain fuel

oil; the rest was burned directly for process

heat and power generation. During World

War II, the area was occupied by Germany,

and the shale oil produced during this period

was refined to obtain illuminating oil and

bunker fuel oil for the German navy. When

the Estonian S.S.R. was created, the Germanbuilt plants were expanded to provide fuel

gas for the cities of Tallinn and Leningrad.

Shale oil and petrochemicals were also produced, but most of the shale mined was

burned as a boiler fuel for power generation.

In 1970, about 14 million tons were mined.

The present goal is to expand production to

54 million ton/yr. About 75 percent of the

present production is burned under boilers to

supply about 90 percent of Estonia’s electrical needs. The rest is retorted to produce fuel

oil, gasoline, fuel gas, and chemicals.

The Soviet industry is estimated to have

mined about 560 million tons of kukersite

between 1945 and 1975. As noted, only onefourth of the mined shale is retorted. If all of

the shale had been converted to oil, the average production rate would have been about

67,000 bbl/d, slightly more than would be produced by a single commercial-scale oil shale

facility in the United States. The present

target of 54 million ton/yr is equivalent to

about 200,000 bbl/d.

Two types of large-scale retorts are used:

the Kiviter gas generator which is similar to

the gas combustion and Paraho directly

heated retorts; and the Galoter retort which

uses spent shale as a heat carrier and is

remarkably similar to the TOSCO II indirectly
112 . An Assessment of 01/ Shale Technologies

heated design. At present, the largest Kiviter

retort has a capacity of about 1,000 ton/d,

about one-tenth the size of retorts planned for

U.S. plants. The largest Galoter unit has a

capacity of about 500 ton/d. A 3,30()-ton/d

nit is under construction. *

People’s Republic of China

Oil shale is found near Fushun in Manchua, and near Maoming in the Province of

Kwantung. The Manchuria deposits occur in

450-f t-thick seams and overlie thick coal

seams. The shale is mined by open pit methods, together with the coal, Oil yields average

only about 15 gal/ton. The deposits were first

developed by the Japanese when they invaded

Manchuria during World War II. About 1.3

million bbl of shale oil were recovered during

the war through use of retorts similar to the

gas combustion design. Most of the oil was refined into fuel oil for the Japanese navy. During the Korean war, production was expanded to about 50,000 bbl/d. Byproducts included chemical fertilizer from the nitrogen

in the shale oil and cement from the spent

shale. Additional shale was mined, mixed

with coal, and burned directly for power generation.

During the past decade, the capacity of the

Manchuria industry has remained fairly

constant, but six retorting plants have been

built in the Kwantung Province. The total production from the Chinese plants is unknown,

but it is unlikely to be more than about 50,000

to 70,000 bbl/d. About two-thirds of the oil is

refined, the rest is burned directly for power

generation.

Brazil

Brazil has very large deposits which could

contain as much as 3 trillion bbl of potential

shale oil. The largest deposits of commercial

interest are those of the Irati formation,

which begins in the State of Sao Paulo and extends southward in an S-shaped curve for a

*For additional information on retorting technologies see ch.

5.

distance of about 1,000 miles to the border

with Uruguay. Irati shale yields about 20

gal/ton on retorting, which is comparable to a

medium grade of Green River shale.

Small retorts have been used intermittently

in Brazil since 1862. Early operations produced illuminating gases for home use. Retorting was discontinued in 1946 but resumed

in the 1950’s under control of the national

government. In 1970, a 2,200-ton/d” demonstration retorting plant was completed at Sao

Mateus do Sul in the State of Parana. The

plant has operated on an experimental basis.

The Petrosix retorting process is used. It was

developed by the engineering staff of Petrobras, the national oil company, with the assistance of Cameron Engineers, a U.S. engineering firm. Little information has been released about the demonstration but, given the

properties of the Irati shale and assuming

high oil recoveries from the retort, the plant

could produce about 1,000 bbl/d of shale oil,

eve. a million cubic feet of high-Btu gas per

day, and about 15 ton/d of elemental sulfur.

At present, Petrobras is attempting to raise

about $1.5 billion to build a commercial-size

plant with a capacity of about 45,000 bbl/d.

The plant would be sited near the present

demonstration facility. About 20 Petrosix retorts would be used. Current plans call for a

25,000-bbl/d operation by 1983, with subsequent expansion to full capacity by 1985. The

deposits in the immediate vicinity of the plantsite could supply the full-size facility for

about 30 years. Two additional plants of similar size are contemplated for the State of Rio

Grande do Sul, which is south of the demonstration plant.

Brazil’s enduring interest in oil shale development is related to its oil-import problem.

It consumes about a million barrels of crude

oil per day, of which about 960,000 bbl/d are

imported. The net drain of the national economy is about $11 billion per year, which contributes to a net deficit in the balance of international payments of about $1.55 billion. It is

difficult to track the effect of this deficit in an

economy with a 60-percent annual inflation

rate, but the currency drain to purchase im-
Ch 4–Background ● 113

ported oil is estimated to be equivalent to same proportion of its GNP on imported oil,

about 6 percent of the nation’s gross national about 15 million bbl/d would be imported, or

product (GNP). If the United States spent the nearly twice the present rate.

Status of U.S. Oil Shale Projects

The characteristics and status of 11 projects that are at least at the stage of field testing in the Green River shales are summarized

in table 17. The list does not include several

relatively new projects (such as Multi Mineral Corp. ’s project for extraction of oil, nahcolite, and alumina from deeply buried deposits

in the Piceance basin) or projects that are being conducted in the eastern shales. It also

does not include the numerous theoretical investigations and laboratory-scale experiments that are being conducted by Federal

and State agencies and private companies.

Two of the projects—Rio Blanco and

Cathedral Bluffs—are actively proceeding

towards commercial-scale operations on Federal lease tracts in Colorado. The White River

project is also on a Federal lease tract, but it

is inactive at present because of legal uncer- tainties.* Tosco’s Sand Wash project is Proceeding towards commercialization at a relatively leisurely pace to maintain compliance

with the due-diligence provisions of the Utah

leases. Three projects—Logan Wash, Geokinetics, and BX—are of an experimental nature and are being partially funded by DOE.

The four other projects—Colony, Union, Superior, and Paraho—are aimed towards ultimate commercial-scale operations but are inactive at present for a variety of reasons,

principally economic.

*The Rio Blanco, Cathedral Bluffs, and White River projects

are parts of the Federal Prototype oil Shale Leasing !Y )grarn,

which is discussed in vol. II of this report.
114 An Assessment of 01/ Shale Technologies

Table 17.–Status of Major U.S. Oil Shale Projects

Production target

Project Location Proposed technology (barrels per day) Status summary

Rio Blanco Oil Shale Co.:

Gulf, Standard of Indiana

Cathedral Bluffs 011 Shale

project: Occidental Oil

Shale: Tenneco

White River Shale project:

Sundeco; Philips; SOHIO

Colony Development Operation: ARCO; Tosco

Long Ridge project: Union

011 of California

Superior Oil Co.

Sand Wash project: Tosco

Paraho Development Corp.

Logan Wash project, Occidental Oil Shale: DOE

Geokinetics, Inc., DOE

BX 0il Shale project Equity

0il Co. ; DOE

Federal lease tract C-a,

Colorado

Federal lease tract C-b;

Colorado

Federal lease tracts U-a

and U-b; Utah

Colony Dow West

property ;Colorado

Union property; Colorado

Superior property;

Colorado

State-leased land; Utah

Anvil Points: Colorado

D. A. Shale property;

Colorado

State-leased land, Utah

Equity property; Colorado

MISa and Lurgi-Ruhrgas

aboveground retorts

Occidental MIS

Paraho aboveground

retorts

TOSCO II aboveground

retorts

Union ‘‘B’ aboveground

retort

Superior aboveground

retort

TOSCO II aboveground

retorts

Paraho aboveground

retorts

Occidental MIS

Horizontal-burn true in situ

True in situ retorting with

superheated steam

(Equity process)

76,000 Shaft sinking for MIS module development.

(1987) Designing Lurgi-Ruhrgas module, PSDb

permit obtained for 1,000 bbl/d.

57,000 Shaft sinking for MIS module development,

(1986) Process development work being done at

Logan Wash, PSD permit obtained for

5,000 bbl/d.

100,000 Inactive because of litigation between Utah,

the Federal Government, and private

claimants over landownership

46,000 Inactive pending improved economic

conditions. PSD permit obtained

for 46,000 bbl/d.

9,000 Inactive pending improved economic

conditions. PSD permit obtained for

9,000 bbl/d.

11,500 Inactive pending BLM approval of land

plus nahcolite, soda exchange proposal. PSD permit obtained

ash, and alumina for 11,500 bbl/d.

50,000 Site evaluation and feasibility studies

underway. Lease terms require $8 million

investment by 1985,

7,000 Inactive following completion of pilot plant and

semiworks testing. Seeking Federal and

private funding for a modular demonstration

program,

500 Two commercial-size MIS retorts planned for

1980 m support of the tract C-b project. PSD

permit obtained for 1,000 bbl/d,

2,000 Continuation of field experiments, About

(1982) 5,000 bbl have been produced to date.

Unknown Steam injection begun and will continue for

about 2 years. Oil production expected in

1980. Production rate has not been

predicted

aModdled In SIIU processing

bpreventlon of Slgnif[canl delerloratlon–an alr quallty permit that must be obtained before conslrucllon can be91fl (See ch 8 ]

SOURCE Off Ice ol Technology Assessment

Chapter 4 References

‘C. E. Banks and B. C. Franciscotti, “Resource

Appraisal and Preliminary Planning for Surface

Mining of Oil Shale, Piceance Creek Basin, Colorado,” Quarterly of the Colorado School of

Mines, vol. 71, No. 4, October 1976, pp. 257-285.

‘R. Nelson, “Meteorological Dispersion Potential in the Piceance Creek Basin,” Quarterly of the

Colorado School of Mines, vol. 70, No, 4, October

1975, pp. 223-238.

‘Bureau of Land Management, Draft Environmental Impact Statement—Proposed Development of Oil Shale Resources by Colony Development Operation in Colorado, Department of the Interior, Dec. 12, 1975, p. 111-9,

“Rio Blanco Oil Shale Project, Detailed Development Plan—Tract C-a, Gulf Oil Corp. and Standard Oil Corp. (Indiana), March 1976, p. 3-6-12.

5Environmental Protection Agency, Assessment

of the Environmental Impacts From Oil Shale Development, EPA-600/7-77-069, July 1977, p. 100,

‘Supra No. 3, at p. 111-121.

7

Supra No. 4, at p. 9-11-18.

6 e artment of the Interior, D p Final Environmental Statement for the Prototype Oil Shale Leasing

Program, Washington, D. C., 1973, pp. H-79 to

11-90.

‘Supra No,4,atp.9-11-16.

%upra No. 8, at p. 11-231.
Ch 4–Background ● 115

‘

l Supra No. 8, at p. II-232.

1%upra No. 8, at p. II-292.

1 !3upra No. 4, at p. 9-11-16.

‘qC-b Shale Oil Project, Oil Shale Tract C-b—Detailed Development Plan and Related Materials,

Ashland Oil, Inc., and Shell Oil Co., February

1976, pp. VII-5 and XI-63.

1%upra No. 3, at p. III-47.

%upra No. 3, at pp. III-9 and III-11.

17 Environmental Protection Agency, Pol)ution

Guidance Control for Oil Shale Development (Revised Dru~t Report), Cincinnati, Ohio, July 1979. p.

1-14.

‘“Bureau of Reclamation, Critical Water Problems Facing the Eleven Western States—Westwide Study, vol. I, Department of the Interior,

April 1975, p. 176,

“J. B. Weeks, et al., Simulated Effects of Oil

Shale Development on the Hydrology of Piceance

Basin, Colorado, U.S. Geological Survey Professional Paper No, 908, 1967, pp. 19-22.

‘(’Ibid.

‘lSupra No. 17, at pp. 1-15 to 1-17,

“W, B. Cashion, Geology and Fuel Resources of

the Green River Formation, Southeastern Uinta

Basin, Utah and Colorado, U.S. Geological Survey

Professional Paper No, 548, 1967.

“C. Edmonds, “Rock Springs: ‘Sinking City’ on

the Rise, ” Shale Country Magazine, vol. 2, No. 9,

September 1976, pp. 10-12.

“C. Edmonds, “Vernal, Utah: From Dinosaurs to

Shale,” ShaJe Country Magazine, vol. 1, No. 3,

March 1975, pp. IO-12.

‘%upra No. 17, at p. 1-15.

‘OR. J. Hite and J, R. Dyni, “Potential Resources

of Dawsonite and Nahcolite in the Piceance Creek

Basin, Northwest Colorado,’” Quarterly of the Co~-

orado School of Mines, vol. 62, No. 3, July 1967,

pp. 25-38.

‘7B. Weichman, Saline Zone Oil Shale and the

Integrated In Situ Process—The Unrecognized

Solution for Crude Imports, Multi Mineral Corp.,

Houston, Tex., May 1979.

‘8J. H. Knight and J. W. Fishback, “Superior’s

Circular Grate Oil Shale Retorting Process and

Australian Oil Shale Process Design, ” Twelfth Oil

Shale Symposium Proceedings, Golden, Colo., Colorado School of Mines Press, August 1979, pp.

1-16,

I°F. C. Jaffe, “Oil Shale. Part I: Nomenclature,

Uses, Reserves, and Production, ” Mineral Industries Bulletin, vol. 5, No, 2, March 1962.

IOJ. H, Gary, “Foreword to the Seventh Oil Shale

Symposium, ” Quarterly of the Colorado School of

Mines, vol. 69, No. 2, April 1974, p. v.

31R, D, George, “Geology and Distribution of Oil

Shales,’” in R. H. McKee, cd., Shale OiJ, New York:

The Chemical Catalog Co., Inc., 1925, pp. 37-42.

‘

2 Supra No. 30.
CHAPTER 5

Technology

Introduction ● .*. ... . * * ,, *,, , **,,.*.,.

Page

119

Summary of Findings. . . . . . . . . . . . . . . . .. ..119

An Overview of Oil Shale Processing . ......120

Oil Shale Mining. . . . . . . . . . . . . . . . . . . . . .. .123

Surface Mining. . . . . . . . . . . . . . . . . . . . . . . . . 123

Underground Mining . ...................125

Oil Shale Retorting. . ...................,128

True In Situ. . . . . ................,......128

Modified In Situ . .......................131

Aboveground Retorting . .................137

Advantages and Disadvantages of the

Processing Options. . ..................153

Oil Recovery . . . . . ......................154

Properties of Crude Shale Oil .. .... ... ....155

Shale Oil Refining. . ..................,..157

Shale Oil Upgrading Processes . ....,......158

Total Refining Processes . ................160

Cost of Upgrading and Refining . ...........162

Markets for Shale Oil. . ..................163

Shale Oil as a BoilerFuel . ................163

Shale Oil as a Refinery Feedstock . .........164

Shale Oil as a Petrochemical Feedstock .. ...166

Issues and Uncertainties . ................167

R&D Needs and Present Programs. . ........170

R&D Needs . ...........................170

Present Programs. . ..............,..,...172

Policy Options. . . . . . . . . . . . . . . . . .**.,*,.. 173

R&D. . . . . . . . . . . . ................,.....173

Page

Demonstration . ........................173

Chapter 5 References. . ..................175

List of Tables

Table No. Page

18. Overall Shale Oil Recoveries for

Several Processing Options . . . . . . . . . 155

19. Properties of Crude Shale Oil From

Various Retorting Processes. . . . . . . . . 156

20. Supply of Finished Petroleum Products

in PADDs 2, 3, and 4 in1978 . . . . . . . . . 165

21. Technological Readiness of Oil Shale

Mining, Retorting, and Refining

Technologies . . . . . . . . . . . . . . . . . . . . . 168

List of Figures

FigureNo. Page

19.

20.

21.

22.

23.

24,

25.

26.

27.

Oil Shale Utilization . . . . . . . . . . . . . . . 121

The Components of an Underground

Mining and Aboveground Retorting Oil

Shale Complex. . . . . . . . . . . . . . . . . . . . 122

An Open Pit Oil Shale Mine. . . . . . . . . . 124

Open Pit Oil Shale Mining. . . . . . . . . . . 125

The Colony Room-and-PillarMining

Concept . . . . . . . . . . . . . . . . . . . . . . . . . 126

Room-and-Pillar Mining on MultipIe

Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

The Original Mine Development Plan

for Tract C-b . . . . . . . . . . . . . . . . . . . . . 128

True In Situ Oil Shale Retorting . . . . . . 129

Modified In Situ Retorting. . . . . . . . . . . 132
28.

29.

30.

31.

32.

33.

34.

35,

36.

37,

38.

39.

4U.

41.

Pag e

The RISE Method of MIS Oil Shale

Retorting . . . . . . . . . . . . . . . . . . . . . . ,. 134

Initial Modular MIS Retort

Development Plan for Tract C-a . . . . . . 135

Present MIS Retort Development Plan

for Tract C-a . . . . . . . . . . . . . . . . . . . . . 136

Retort Development Plan for the

Multi Mineral MIS Concept.. . . . . . . . . 136

Preparation of a Multi Mineral MIS

Retort . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

A Set of Multi Mineral Misreports . . . 138

The Operation of an NTU Retort.. . . . . 140

Discharging Spent Shale Ash Froma

40-Ton NTU Retort. . . . . . . . . . . . . . , . . 141

The Paraho Oil Shale Retorting System 143

The Paraho Semiworks Unit at

Anvil Points, Colo. ● , ● ● ● ● ● ● . ● . . . ● , . ● 143

The Petrosix Oil Shale Retorting

System . .,..,.,.......,,..0.,.,0 . 145

The Petrosix Demonstration Plant,

Sao Mateus do Sul, Brazil. . . . . . . . . . . 146

The Union Oil “B” Retorting Process.. 147

Block Diagram for the Superior

Multi Mineral Concept . . . . . . . . . . . . . 149

42.

43.

44,

45*

46.

47*

48.

49.

50.

Paq e

The Superior Oil Shale Retort.. , . . . . . 150

The Colony Semiworks Test Facility

Near Grand Valley, Colo. . . . . . . . . . . . 151

The TOSCO II Oil Shale Retorting

System .,, , . . . . . 0 ., . . . . ., .,....,, 152

The Lurgi-Ruhrgas Oil Shale Retorting

. ,0 ,0 . . . . . . . . . . . . . . . . . . . . . 153

Refining Scheme Used by the U.S.

Bureau of Mines to Maximize Gasoline

Production From Shale Oil . . . . . . . . . . 161

Refining Scheme Employing Coking

Before an Initial Fractionation, Used by

Chevron U.S.A. in Refining

Experiments. ., . . . . . . . . . . . . . . . . . . . 161

Refining Scheme Employing Initial

Hydrotreating, Used by Chevron U.S.A.

in Refining Experiments . . . . . . . . . . . . 161

Refining Scheme Employing Initial

Fractionation, Used by SOHIO in

Prerefining Studies . . . . . . . . . . ... , . . 162

The Petroleum Administration for

Defense Districts. . . . . . . . . . . . . . . . . . 165
CHAPTER 5

Technology

Introduction

The mining and processing technologies

that can be used to convert kerogenf the organic component of oil shale, into marketable

fuels are discussed in this chapter. The characteristics of these technologies will influence the effects that an oil shale industry will

have on the physical environment, and their

technological readiness will affect the rate at

which an industry can be established. The

following subjects are discussed:

●

●

●

the general types of processing methods

and their major unit operations;

the mining methods that could be used to

remove oil shale from the ground and

prepare it for aboveground processing;

the generic types of retorting methods

Summary

Oil shale contains a solid hydrocarbon called

kerogen that when heated (retorted) yields combustible gases, crude shale oil, and a solid residue called

spent, retorted, or processed shale. Crude shale oil

can be obtained by either aboveground or in situ (in

place) processing. In aboveground retorting (AGR),

the shale is mined and then heated in retorting

vessels. In a true in situ (TIS) process, a deposit is

first fractured by explosives and then retorted underground. In modified in situ (MIS) processing, a portion of the deposit is mined and the rest is shattered

(rubbled) by explosives and retorted underground.

The crude shale oil can be burned directly as boiler

fuel, or it can be converted into a synthetic crude oil

(syncrude) by adding hydrogen. The syncrude can

also be burned as boiler fuel, or it can be converted

to petrochemicals or refined to obtain finished fuels.

Some of OTA’s major findings concerning these mining and processing technologies are:

● Limited areas of the oil shale deposits may be

amenable to open pit mining. This technique has

never been tested with oil shale but it is well-

●

●

●

●

●

that could be used to convert the oil

shale to liquid and gaseous fuels;

the upgrading and refining methods that

could be used to convert crude shale oil

to finished products;

the potential markets for shale-derived

fuels;

the technological readiness of the major

steps in the oil shale conversion system;

the uncertainties and the research and

development (R&D) needs that are associated with each major unit operation;

and

the policies available to the Government

for dealing with the uncertainties,

of Findings

●

●

advanced with other minerals. More oil shale experience has been acquired with underground

mining, particularly room-and-pillar mining, and

preparing MIS retorts. Although uncertainties remain, the mining technologies should advance

rapidly if presently active projects continue and

suspended ones resume.

TIS is presently a very primitive process, although

R&D and field tests are being conducted. The principal advantages of TIS are that mining is not

needed and surface disturbance from facility siting

and waste disposal is minimized. The principal

disadvantages are a low level of technological

readiness, low recovery of the shale oil, and a potential for surface subsidence and leaching of the

spent shale by ground water.

MIS is a more advanced in situ method. It is being

further developed on two lease tracts and a privately owned site. The Department of Energy

(DOE) is providing substantial R&D support. The

principal advantages of MIS are that large depos119
120 ● An Assessment of Oil Shale Technologies

its can be retorted, oil recoveries per acre affected

are high, and relatively few surface facilities are

required. However, some mining and some disposal of solid wastes on the surface are required,

and the oil recovery per unit of ore processed is

low relative to AGR methods. The burned-out MIS

retorts have a potential for ground water pollution.

● AGR also has a medium level of technological

readiness. Three retorts have been tested for several months at rates approaching one-tenth the capacity of commercial-size modules. Others are still

at the laboratory or pilot-plant stages. The principal advantage of AGR processing is high oil recovery per unit of ore processed. However, with some

mining methods, oil recoveries per acre may be

lower than with MIS. Surface disturbance is highest with AGR because of the extensive surface facilities, and because large quantities of solid

waste are generated.

● The physical and chemical properties of crude

shale oil differ from those of many conventional

crudes. However, depending on the nature of the

upgrading techniques applied, the syncrude can

be a premium-quality refinery feedstock, comparable with the best grades of conventional crude.

Shale oil is a better source of jet fuel, diesel fuel,

and distillate heating oil than it is of gasoline. Although some technical questions remain, the upgrading and refining processes are well-advanced. Refining shale oil may cost from $0.25 to

●

●

$2.00 more per bbl than refining some of the

poorer grades of domestic crude.

The initial output from the pioneer oil shale industry will probably be marketed near the oil shale

region. Once the industry is established, the shale

oil will probably be used as boiler fuel or refined in

the Rocky Mountain States. A large industry will

most likely supply oil to Midwest markets. A 1-

million-bbl/d industry could completely displace

the quantities of jet, diesel, and distillate heating

fuels that are presently obtained from foreign

sources in the entire Midwest.

With the present technical status of the critical

retorting processes, deploying a major oil shale industry would entail appreciable risks of technological and economic failure. Although much R&D

has been conducted, and development is proceeding, the total amount of shale oil produced to date

is equivalent to only 10 days of production from a

single 50,000-bbl/d plant. Because of its primitive status, much basic and applied R&D is needed

for the TIS method. The MIS approach and some

of the AGR processes are ready for the next stage

of development—either modular retort demonstrations or pioneer commercial-scale plants. Such

demonstrations would be costly, but they would

substantially reduce the risks associated with the

much larger capital investments needed to create

an industry,

An Overview of Oil Shale Processing

Converting shale in the ground to finished broken with explosives to create a highly

fuels and other products for consumer mar- permeable zone through which hot fluids

kets involves a series of processing steps. can be circulated; and

Their number and nature are determined by ● AGR processes in which the shale is

the desired mix of products and byproducts mined, crushed, and heated in vessels

and by the generic approach that is followed near the minesite.

in developing the resource. The alternative Figure 19 is a flow sheet for the steps com- approaches are: mon to all three options. How the steps would

●

●

TIS processes in which the shale is left be integrated in an AGR facility is shown in

underground, and is heated by injecting figure 20. In the first step, the oil shale is

hot fluids; mined and crushed for aboveground processMIS processes in which a portion of the ing, or the deposit is fractured and rubbled

shale deposit is mined out, and the rest is for in situ processing. The main product is
Ch 5– Technology 121

Figure 19.– Oil Shale Utilization

Mining & Crushing

or In situ retort Wastes &

b

preparation byproducts

7

Treated Re-Use

~ % * Reinfection

m ~ water Discharge

a ~

o

Y ?

- #

Wastes & Residues

Retorting Treatment # \

byproducts

Disposal

T

A

~ ~

@

6 ~ Sulfur, NH3,

*

Industrial ●

byproducts markets

7

1 f

Upgrading< Wastes &

byproducts

I

9‘ransportatonm ‘ef’n’ng l’=% “strbut”n t-+ C==l

aMay not be nee~e(j for some in S1 tu methods

SOURCE Off Ice of Technology Assessment

raw oil shale with a particle size appropriate

for rapid heat transfer. Nahcolite ore can be

one of the various byproducts from this step.

Dust and contaminated water are among its

wastes, In the retorting step, the raw oil shale

is heated to pyrolysis temperatures (about

1,000° F (535° C)) to obtain crude shale oil.

Other products are the spent shale residue,

pyrolysis gases, carbon dioxide, contaminated water, and in some cases additional

nahcolite and dawsonite ore. The crude shale

oil may be sent to an upgrading section in

which it is physically and chemically modified

to improve its transportation properties, to

remove nitrogen and sulfur, and to increase

its hydrogen content. (Crude shale oils from

some in situ processes may not need upgrading before transportation. ) Contaminated air

and water, and in some units refinery coke,

are the wastes produced along with gases

that contain sulfur and nitrogen compounds.

Depending on the extent of the treatment, the

upgraded product—shale oil syncrude-can

be a high-quality refinery feedstock, comparable with the best grades of conventional

crude. In the refining step, which may be conducted either onsite or offsite, hydrogen is

added to convert the syncrude to finished

fuels such as gasoline, diesel fuel, and jet

fuel. The syncrude, or the crude shale oil,

could also be used directly as boiler fuel.

After refining, the fuels are distributed to

consumer markets. Refining also produces

waste gases and various contaminated condensates.

To protect the environment, contaminated

water must be treated for reuse in the oil

shale facility, for reinfection into the ground

water aquifer source, or for discharge into
122 ● An Assessment of 01/ Shale Technologies

Figure 20.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTS

FROM UPGRADING UNITS

. Low Sulfur Fuel Oil . Ammorwa

● Liquefied Petroleum Gas ● Sulfur

. Coke

UPGRADING UNITS u RETORT UNITS

-— . . wde Convevors <

-. == . - . ,.- -– !* .; ;... . . . . .

. + . . . .. Sha ,

= - . . .s. .

, ,... ., .

.: - - ““ - ,— Processed /. -

. ., L

. . .. . — - Y

.

\

b, 7 “

. .

- ‘ Catchment Dam

/ Surface Runoff

Water reused

HEADFRAME DISCHARGE

STATION

surface streams. Contaminated air and process gases must be purified to meet Federal

and State air pollution standards before they

can be discharged to the atmosphere. The

waste gases from retorting, upgrading, and

refining are potential sources of ammonia

(for fertilizer and other uses) and sulfur (for

sulfuric acid and many other materials).

These can be recovered during the treatment

steps and sold to industrial processors. In

some portions of the Green River formation,

the solid residues from mining and retorting

will contain nahcolite (which can be used to

produce soda ash and for stack gas scrub-

[_TI PRIMARY

CRUSHING

i

r~L ~

-.=.

Roof Upper Bench

Loading ---:, .4* !

BOMng ScaImg Dnllmg and Blasting x . -’

,.

-1

.-. —

——

gr~~;g;$f~

—.

. </, .:.: - - —- ‘ ) “

$;::. {

.“ 1?

~~ Drdlmg

} Lower Bench

/ - -~—, ”

ROOM AND PILLAR MINING

(Several Hundred Feet or more

Underground)

SOURCE C b Shale 01 I Project Defa(led Deve/oprnenf Plan and Re/ated Mater/a/:

u

SKIP LOADING STATION

Ashland 011, Inc and Shell 011 Co , February 1976, p 1-24

bing) and dawsonite (a source of aluminum

metal). In any case, spent shale from above-

-ground processing must be moistened, compacted, and revegetated to prevent erosion

and leaching. Retorted shale in in situ retorts,

and spent shale from surface operations that

is backfilled into underground openings, must

be protected from leaching by ground water.

This chapter deals with the processing

technologies used in mining, retorting, upgrading, and refining. Technologies for treating air, water, and solid wastes are discussed

in chapter 8.
Ch 5– Technology ● 123

Oil Shale

Both MIS and AGR require mining. In the

case of AGR, the mined shale is conveyed to

retorts where it is processed to recover shale

oil. With MIS, the shale may also be retorted

aboveground, or it may be discarded on the

surface as a solid waste.

Green River oil shale deposits are characterized by their extreme thickness and by

their extensiveness. The richer shale zones in

the Piceance basin, for example, are more

than a thousand feet thick, in places, and are

continuous over an area of 1,200 mi2

. Deposits of this nature could be amenable to either

surface mining (strip or open pit) or to underground mining methods (such as room and pillar), depending on topographical features, accessibility, overburden thickness, presence of

ground water in the mining zone, and many

other factors. Surface mining may be feasible

for very thick oil shale zones that are not

deeply buried, especially if their average oil

yield is not high, Because of the thickness of

the overburden, only a limited area of the

Piceance basin and somewhat more of the

Uinta basin and the Wyoming basins is amenable to surface mining. In other areas,

streams have eroded gulleys and canyons

through the shale beds, exposing some of the

richer shale zones. Shale that outcrops in

these areas, plus the shale in all deeply

buried beds, will probably be extracted by

underground mining,

Despite the high price of crude oil, oil shale

is a lean ore compared with many ores that

contain valuable metals. Economies of scale

encourage massive mining installations, regardless of the mining method selected. A

prospective developer once characterized

commercial-scale oil shale mines as “prodigious, ” because it connotated a larger size

than “giant.’” A sense of this can be conveyed by comparing their capacities with

those of more conventional mines. At present,

the largest surface mine in the United States

is Kennecott Copper’s Bingham Canyon pit in

Utah, which produces about 110,000 ton/d of

copper ore. The largest underground mine is

Mining

the San Manuel copper mine in Arizona,

which yields about 50,000 ton/d of ore, About

70,000 ton/d of 30 gal/ton oil shale would

have to be mined to support a single 50,000-

bbl/d plant that used aboveground retorts. *

This mine would be substantially larger than

the San Manuel mine. A 400,000-bbl/d industry of aboveground retorts would have to

mine about 560,000 ton/d—the equivalent of

5 Bingham Canyon pits or 11 San Manuel

mines. If the same industry used only MIS,

about 230,000 to 460,000 ton/d would have to

be mined—the equivalent of four to seven

San Manuel mines. ** Some of the mining

techniques that could be used to achieve

these levels of production are described

below.

Surface Mining

The two principal types of surface mining

—open pit and strip—both have been widely

used to develop coal seams and deposits of

many other minerals. Their technical aspects

are fairly well-understood for these minerals.

However, their feasibilities and effects vary

with the nature of the ore body. Neither technique has yet been applied to the oil shales of

the Green River formation.

Surface mining is economically attractive

for large, low-grade ore deposits because it

permits high recovery of the resource and

allows sufficient space for very large and efficient mining equipment. An open pit mine

could recover almost 90 percent of the oil

shale in a very thick deposit. Strip mining

could provide even higher recoveries. In contrast, underground mining would recover less

than 60 percent. One of the reasons that industry’s bids on a lease for Federal tract C-a

were so high was that the deposit could be

*This assumes recovery of 100 percent of Fischer assay oil,

a recoverv efficiency that h:)s been achieved in tests of the

“rOSCO 11 technology.

**This assumes mining of 20 to 40 percent of the shnle in the

retort volume, and an oil recovery of 60 percent of Fischer

assay.
124 ● An Assessment of 011 Shale Technologies

mined by open pit methods. About five times

as much shale could be recovered by open pit,

which could have mined the entire deposit,

than by underground room-and-pillar mining,

which would have been limited to a relatively

thin zone.2

A mature open pit mine is shown in figure

21 and the steps in its operation in figure 22.

In the first step, overburden is drilled and

blasted loose over a large area above the oil

shale zone. The burden is carried by trucks or

conveyors to an offsite disposal area. When

enough burden is removed to expose the shale

beds, the shale itself is drilled and blasted,

and is hauled from the pit for processing in

aboveground retorts. As mining proceeds, a

huge hole is formed, extending from the top of

the overburden to deep into the oil shale deposit. The walls of the pit are under pressure

from the overburden, and must be angled outFigure 21 .—An Open Pit Oil Shale Mine

Off site disposal

Ov n

SOURCE Hear/rigs on 0// Sha/e Leasing, Subcommittee on Minerals, Materials,

and Fuels of the Senate Commltee on Interior and Insular Affairs,

94th Cong 2d sess , Mar 17, 1976, p 84

wards to transmit the pressure without collapsing.

Open pit mining was originally proposed

for tract C-a by the Rio Blanco Oil Shale Co.,

the lessee. The pit was to have started in the

northwest corner of the tract, and eventually

to have covered its entire surface. After a

few decades, freshly removed overburden

and spent shale from the aboveground retorts

would have been returned to the pit as backfill. In the interim, the solid wastes would

have been disposed of on a highland to the

northeast of the tract boundaries. This concept was abandoned when the Department of

the Interior (DOI) refused to allow offtract

waste disposal. Rio Blanco later switched to

MIS techniques because the alternative—underground mining—would have reduced resource recovery and threatened profitable

operations. * At present, there are no plans

for any open pit mines, although Rio Blanco

may reconsider its original plan if offsite disposal were allowed.3

In strip mining, overburden is removed

with a dragline—a massive type of scraper

shovel. When the dragline has filled its scoop,

it pivots and dumps the burden into an adjacent mined-out area. One difference between

open pit and strip mines is that in strip mining, the burden is simply cast into a nearby

area; in open pit, it must be moved far from

the minesite to prevent interfering with the

development of the pit. Strip mining has not

been proposed for any of the Green River deposits.

Surface mining of most oil shale deposits is

made difficult by the great thickness of the

overburden that covers them. In the center of

the Piceance basin, for example, the 2,000-ftthick oil shale zones are buried under about

1,000 ft of inert rock and very lean oil shale.

This does not necessarily preclude surface

mining, because the deposits are generally

characterized by a favorable stripping ratio—the ratio of overburden thickness to orebody thickness. The thick beds in the center

of the Piceance basin have 1 ft of overburden

*This change in plans is discussed in vol. 11,
Ch 5–Technology 125

Figure 22.—Open Pit Oil Shale Mining

I

I

Jl- .-

/

OVERBURDEN

t

4 0 -–

 —“— “—— “

1 OIL SHALE

SOURCE U S Energy Oullook–AnIfrtenrn RePort The National Petroleum Council Washington D C 1972

for every 2 ft of oil shale—a stripping ratio of

1:2. With coal, a stripping ratio of 10:1 is

often economically acceptable. A study by the

National Petroleum Council indicates that

open pit mining would be favored for stripping ratios between 2:1 and 5:1, strip mining

for smaller ratios, and underground mining

for larger ratios than 5:1.’

However, the economic principles of coal

mining should be applied with caution to oil

shale. Removing 1,000 ft of overburden to recover 2,000 ft of shale might be possible in

theory, but the pit’s boundaries would be so

extensive that it would have to be located on

a very large tract. Furthermore, the large

“front-end” investment in removing overburden many years in advance of retorting would

probably make open pit mining of deep deposits uneconomical. Also, strip mining would

not be feasible in many parts of the oil shale

region, even those with favorable stripping

ratios, because the dragline would have to

reach to the bottom of a 3,000-ft-thick layer of

overburden and oil shale. It is not clear that

such a machine could be built.

Underground Mining

Many underground mining procedures

have been proposed for oil shale deposits5-10

but to date only room-and-pillar mining and

mining in support of MIS retorting have been

tested at any significant scale. In room-andpillar mining, some shale is removed to form

large rooms and some is left in place, as pillars, to support the mine roof, The relative

sizes of rooms and pillars are determined by

the physical properties of the shale, by the

thickness of the overburden, and by the

height of the mine roof. Most of the deposits

of commercial interest are very thick and

have relatively few natural faults and fissures. The ore itself resists compression and

vertical shear stresses. These properties

allow the use of large rooms, and relatively

little shale needs to be left as unrecoverable

pillars.

The U.S. Bureau of Mines (USBM) studied

underground mining of oil shale at the Anvil

Points Experimental Station in the late 1940’s

and early 1950's. 11 The primary purpose of
126 ● An Assessment of 011 Shale Technologies

the mining program was to supply raw shale mining plan proposed for Colony Developfor the Bureau’s retorting experiments, but ment’s 46,000-bbl/d facility in the Piceance

the program was also designed to develop a basin. 12 The rooms are 60 ft wide; the pillars

safe, low-cost mining method. The room-and- are 60 ft square; and the mine roof is 60 ft

pillar technique was adopted after extensive high. Mining is conducted in two 30-ft-high

testing. From their studies, which included benches. The upper bench is mined first by

enlarging the rooms until the roof failed, the drilling blastholes into the walls of a producinvestigators concluded that for safe mining tion room, and breaking the shale loose with

conditions the rooms should be 60 ft wide explosives. The broken shale is carried by

with pillars that are 60 ft on a side. trucks to the crushers where it is crushed to

the size range required by the TOSCO 11

Many of the modern mine designs have aboveground retorts. The walls and the roof

been patterned after the USBM experimental of the new room are then “scaled” to remove

mine. The design depicted in figure 23 is the shale that was loosened by the blasting but

Figure 23.—The Colony Room-and-Pillar Mining Concept

SOURCE R W Marshall Colony Development Operation Room. andPlllar 011 Shale Mlnlng, ” Quarterly 01 the Colorado School o/ Mines, VOI 69, No 2 April 1974. PP

171 184
Ch 5–Technology ● 127

did not fall. Holes are drilled into the roof,

and roof bolts are inserted to assure its integrity, thus protecting the miners from roof

falls. The USBM studies indicated that roof

bolts would have to be installed in the access

passageways but not in areas that were actively being mined. These production rooms

would be vacated long before there was any

serious danger of roof falls.

The lower bench is mined next, The sequence is similar except the blastholes are

drilled into the floor of the upper bench, and

additional roof bolting is not needed, The cycle of drilling, blasting, loading, scaling, and

roof bolting was designed to produce about

66,000 ton/d of shale. About 60 percent of the

shale in the mining zone was to be removed

for processing in the aboveground retorts.

The rest was to remain in the support pillars.

Colony estimated that enough shale is present

in the 60-ft seam to support the retorting facility for at least 20 years.

The same type of mine was proposed by the

Colony partners for development of tract C-b,

after considering longwall mining, long-hole

blasting, continuous mining, block caving,

open pit mining, in situ processing, and many

other options. The major advantages of the

room-and-pillar method were identified as: 13

it is highly flexible and can easily be

modified to accommodate new conditions, new equipment, or technological

advances:

it can be highly mechanized and high

overall production rates can be achieved

because many areas can be mined simultaneously:

the mine openings are relatively easy to

ventilate:

development of access passageways is

also a production operation because oil

shale would be removed; and

the mine could be designed to minimize

surface subsidence.

disadvantages were the high cost of the

roof support system and the relatively low recovery. In this regard, it was estimated that

only 30 to 50 percent of the shale in a 75-ftthick interval could be recovered. Higher recoveries would be possible if the pillars were

subsequently mined out or if the mining were

conducted on multiple levels. (See figure 24, )

Figure 24. —Room-and-Pillar Mining

on Multiple Levels

&

\

~ Pillar

. Room

, >ill

~ Mining

Leve l

SOURCE Hearing on 0// Shale Leas/rig Subcommittee on Minerals Materials

and Fuels of the Senate Comm It lee on I n Ierlo r and I n su Iar Affairs

94th Cong 2d sess Mar 17 1976 p 83

The mine eventually would have extended

under the entire surface of tract C-b, as

shown in figure 25. However, the concept

was abandoned when it was discovered that

the shale in the mining zone was highly fractured—a condition that would have required

large support pillars thus reducing resource

recovery to uneconomic levels. All of the

original partners subsequently withdrew

from the tract, and it is now being developed

by MIS methods by Occidental Oil Shale and

Tenneco Oil Co.

Mining to prepare for MIS retorts is distinguished from room and pillar both by the

volume of the deposit that is disturbed and by

the configuration of the disturbed areas. As

indicated, the underground mines both on the

Colony property and on tract C-b would have

been developed in a 60-ft-high mining zone;
.

128 ● An Assessment of 01/ Shale Technologies

Figure 25.—The Original Mine Development Plan for Tract C-b

~– BoUNDARy OF TRACT C-B #

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} ‘- --- ”---;

I 11 I+w I ‘-

SOURCE C-b Shale 011 Project, Detaded Deve/OPmefrt plan and Relafed MaterlalS, Ashland 011, Iflc , and Shell 011 Co , February 1976, p IV-1 1

present plans for the MIS operations on in which the MIS retorts will be created, plus

tracts C-a and C-b call for recovering oil from shafts from the surface for ventilation, drainthe shale in a 750-ft-high zone. However, the age, passageways for the miners, and transactual mining required to support this devel- portation of combustion air and retorting

opment will take place in relatively confined products. Some of the mining plans are disareas. The mine will consist primarily of fair- cussed later in the section on MIS retorting

ly small underground openings in the region methods.

Oil Shale Retorting

The three generic methods for recovering True In Situ

shale oil from oil shale deposits are described

below. Brief discussions of some of the more The sequential steps in TIS processing are:

significant R&D programs that have been conducted as part of their development are in- 1. dewatering, if the deposit occurs in a

eluded. ground water area;
Ch. 5–Technology ● 129

2.

3.

4.

The

fracturing or rubbling if the deposit is

not already permeable to fluid flow;

injection of a hot fluid or ignition of a

portion of the bed to provide heat for pyrolysis; and

recovery of the oil and gases through

wells.

principles of TIS processing are illustrated in figure 26. Several types have been

proposed that differ from each other with respect to the methods for preparing and heating the deposit. All use a system of injection

and production wells that are drilled according to a prescribed pattern. One that is commonly used is the “five-spot” pattern in which

four production wells are drilled at the corners of a square and an injection well is

drilled at its center. The deposit is heated

through the injection well and the products

are recovered through the production wells,

For efficient TIS processing, the deposit

must be highly permeable to fluid flow, which

is true of portions of the Green River oil

shales. A good example is the Leached Zone

of the Piceance basin where ground water

has dissolved salt deposits to leave large

rubble-filled zones. It is estimated to contain

about 550 billion bbl of shale oil in place. 14

There are interconnected fractures and voids

in other areas of the formation, but these, in

general, have only a very limited permeability. The permeability of most of the zones that

appear to have commercial promise is essentially zero. Deposits that lie near the surface

could be fractured by injecting water or explosive slurries, but mining would probably

be needed to increase the permeability of

deeply buried deposits. MIS or AGR processes are more appropriate for the deeper resources.

In 1961, Equity Oil Co. began developing a

TIS process for the Leached Zone, which was

tested in the Piceance basin between 1966

and 1968. It involved dewatering a portion of

the zone followed by injecting hot natural gas.

Pyrolysis gases and a small amount of oil

were swept in the natural gas stream to production wells through which they were

Figure 26. —True In Situ Oil Shale Retorting

1? 11

PRC‘DUC1NGWWQM13

SOURCE B F Grant Retorting 011 Shale Underground—Problems and Posslbllltles, ouarfedy of the Co/orado Schoo/ of

M(nes VOI 59, No 3, July 1964, p 40
130 . An Assessment of 01/ Shale Technologies

pumped to the surface. The gas was separated from the oil, reheated, and reinfected

into the deposit. The oil had a much lower

pour point, viscosity, and nitrogen content

than oils from aboveground retorts. * These

favorable characteristics may have been related to the solvent properties of the natural

gas, and to the absence of oxygen from the retorting zone. The quality of the retort gases

was also good, partly because of their natural

gas component, and partly because during retorting combustion and the decomposition of

carbonate minerals were minimal. **

Process development was not pursued because too much of the natural gas was lost in

the unconfined formation. In 1968, Atlantic

Richfield Co. (ARCO) purchased an interest in

the process and resumed its development. In

1971, a revised concept was announced in

which superheated steam, rather than natural gas, was to be used to heat the deposits. In

1977, DOE contracted with Equity to test the

concept in a 50()-f t-thick seam in the Leached

Zone of the Piceance basin. The seam underlies about 0.7 acre of surface, and contains

about 700,000 bbl of oil in place. It has been

estimated that as much as 300,000 bbl could

be recovered over a 2-year period, with about

half of the oil produced in the first 7 months. ’s

Steam injection has begun at the site, and will

continue through 1981. No detailed estimates

have yet been released of production rates or

retorting efficiency. If the process proves to

be technically and economically feasible, it

could be applied in portions of both the Piceance and the Uinta basins.

At present, no work is being done in slightly fractured formations, but much research is

being performed to develop methods for increasing their permeability by enlarging natural fractures and creating new ones. Some

*rI’hese properties have economic significance. Pour point is

the lowest temperature at which oil will flow. Oils with high

pour points are hard to transport because they solidify at normal ambient temperatures. Viscosity is a measure of a fluid ”s

resistance to flow. Oils with high viscosity are expensive to

pump. Reducing the high nitrogen content of most crude shale

oils consumes hydrogen, which is costly.

**Both of these processes produce carbon dioxide, which is

a major constituent of gases produced by some above-ground retorts.

of the fracturing techniques used have been

chemical explosives, electricity, and injecting

high-pressure air and water. These methods

have been used to enhance recovery of conventional petroleum; oil shale fracturing

poses a similar problem. Nuclear explosives

were also proposed in the 1960’s, but were

not tested because of their potential for harming the environment, A nuclear test—Project

Rio Blanco—was conducted in the Piceance

basin to fracture sand formations containing

natural gas. The test failed.

The earliest TIS work was by Sinclair Oil

Co., between 1953 and 1966. A thin section of

shale in the Mahogany Zone of the Piceance

basin was fractured by injecting air. The bed

was ignited, although with difficulty, and a

small quantity of shale oil was collected before the hot shale swelled and sealed the

fractures. After additional tests, Sinclair concluded that the zone’s limited permeability

would not permit profitable operations. *

Research on TIS processing began at

USBM in the early 1960’s. In 1974, the programs and personnel were transferred to the

Energy Research and Development Administration, and in 1978, they moved to DOE. The

R&D programs have included laboratory experiments, computer simulations, pilot-plant

studies, and field tests. Among the latter

were tests of electrical, hydraulic, and explosive fracturing and combustion retorting

near Rock Springs, Wyo. These revealed

some of the problems associated with the TIS

approach. In one early test, for example,

after inert gas at about 1,300° F (7050 C) was

pumped into a fractured formation for a period of 2 weeks, about 1 gal of shale oil was recovered. In another experiment in a zone that

contained 7,800 bbl of shale oil in place, it

was estimated that only 60 bbl of the close to

1,000 bbl that were released were actually

recovered.

Low oil recoveries are often associated

with TIS processing because of the large im-

*rI’he results of a mathematical simulation indicated that

about 18 years of continuous steam injections would be rec~uired to heat the shale to pyrolysis temperatures within a 30-

ft radius of a fracture.
Ch 5–Technology ● 131

permeable blocks of shale in the fractured

formation. These cannot be fully retorted in a

reasonable length of time. Irregular fracturing patterns that can cause the heat carrier

to bypass large sections of the deposit are

another problem. Oil shale that is located in

the bypassed regions will not be retorted,

And, even if all of the shale in a fractured

area were retorted, much of the oil would not

reach the production wells, but would remain

trapped in the pores of the spent shale or

would diffuse beyond the production wells, to

be lost in surrounding areas.

To develop methods for improving recovery, an extensive R&D program has been conducted at the Federal research center in Laramie, Wyo. Aboveground batch retorts with

capacities of both 10 and 150 tons of shale

have been used to simulate in situ retorting,

but under more controlled conditions than exist underground. Oil recoveries of up to 67

percent have been achieved, and an experiment in a “controlled-state” retort achieved

95-percent oil recovery. *

In 1976 and 1977, the program was expanded to include field tests of different fracturing and retorting techniques under costsharing contracts with Equity Oil, Talley -

Frac, Inc., and Geokinetics, Inc.** The Equity

program has been described. The Talley-Frac

program was terminated after the fracturing

method failed. The Geokinetics process uses a

fracturing technique called surface uplift in

which an explosive is injected into several

wells and detonated to fracture the shale and

make it permeable to fluid flow, The shale is

ignited by injecting air and burning fuel gas

through one well. It is pyrolyzed by the heat

that sweeps through the bed in the gas

stream, Oil and gases are pumped to the surface through outlying production wells. It is

hoped that the technical feasibility of the

*rI’he large retorls resemble the classic Newia-Tex:]s-Utah

(N’I’U) retort that is described later in this chapter. Because of

the higher percentage of void volume in the rubble, these retorts provided better simulations of hlIS processing thtin of

‘1’1S. “1’he controlled-state retort was much smfiller and was

equipped for better cent rol of retortin~ renditions.

**Tbe procurement also included a contract with Occidental

Oil Shale, Inc., to develop its MIS process, which is discussed in

the next section.

process can be demonstrated for thin deposits that are covered by less than 100 ft of

overburden. It has been estimated that there

are at least 6 billion bbl of shale oil in place in

this type of deposit. It is common in the Uinta

basin, 16) and at present, would be most economically developed by strip mining.

Geokinetics has been investigating the surface uplift approach since 1973, and is presently burning its 20th retort in Utah. The

largest retort prior to 1979 measured 130 ft

by 180 ft by 30 ft thick. A retort about 200 ft

on a side and 30 ft thick will be required to

demonstrate the technical feasibility of the

process. By 1982, DOE and Geokinetics hope

to have developed a commercial-scale operation with a production capacity of 2,000

bbl/d.17

Modified In Situ

In MIS processing, the permeability of oil

shale deposits is increased by mining some

shale from the deposit and then blasting the

remainder into the void thus created. The

two-step process is depicted in figure 27. In

the first step, a tunnel is dug to the bottom of

an oil shale bed, and enough shale is removed

to create a room with the same cross-sectional area as the future retort. Holes are drilled

through the roof of the room to the desired

height of the retort. They are packed with explosives that are detonated in the second

step. A chimney-shaped underground retort

filled with broken shale results. The access

tunnel is then sealed, an injection hole is

drilled from the surface (or from a higher

mining level) to the top of the rubble pile. The

pile is ignited by injecting air and burning

fuel gas, and heat from the combustion of the

top layers is carried downward in the gas

stream. The lower layers are pyrolyzed, and

the oil vapors are swept down the retort to a

sump at the bottom from which they are

pumped to the surface. The burning zone

moves slowly down the retort, fueled by the

residual carbon in the retorted layers. When

the zone reaches the bottom of the retort, the

flow of air is stopped, causing combustion to

cease.
132 An Assessment of Oil Shale Technologies

Figure 27. —Modified In Situ Retorting

STEP A

/

OVERBURDEN

F--- ~ 7

—

7– —7

— BLASTHOLE S

‘/////Al LEAN SHALE

REMOVED FOR

//////l I OR DISPOSAL

/

STEP B GAS TO

---–

,- d:

–~ PURIFICATION

RECYCLE GAS ~~, ~BLOWER .COMBUSTION .

— AIR

.—

OVERBURDEN

——.

n

/ ’ b- / , <- .< , (![ 1

, ,/,

‘, / / , //,

‘ / ,/ ‘/ // ,/ ,!’ , / , ,

/

/,/ :/

,

{’ k J

/ , ‘,,

/ /

,’/ , /

/// , .

v’ ] //,/1‘ ‘i \ RUBBLED SHALE

P-——————=——————”’

SOURCE T A Sladek Recent Trends In 011 Shale — Part 2 Mlnlng and Shale 011 Extraction Processes Mjnera/ /rrdus/rles Bu//e/lrr VOI 18 No 1 January 1975, p 18

Phofo credif OTA staff

Head frame at tract C-a

Occidental Oil Shale, Inc., a subsidiary of

Occidental Petroleum (Oxy) has demonstrated the MIS process, 18 Oxy’s work began

in 1972 on the D. A. Shale property along

Logan Wash—a private tract on the southern

fringe of the Piceance basin about 50 miles

northeast of Grand Junction, Colo. To date,

six retorts have been burned at the site, with

varying degrees of success. The first retort

was about 32 ft on each side and 70 ft high.

About 60 percent (1,200 bbl) of the shale oil in

place was recovered, comparable to the best

results from USBM’s experiments at Laramie, The next two retorts were slightly

larger, and performed similarly, The fourth

retort was of nearly commercial size—120 ft

on each side and 270 ft high. It contained

about 32 times as much shale as the first retort and yielded about 25 times as much oil.

The fifth was the same size but was designed

for a much lower void volume. The rubbling

step did not evenly distribute the void volume,

and the performance was poor. Only 40 percent of the oil was recovered. The burning of
Ch 5–Technology ● 133

retort 6 began in 1978, but the sill pillar—the

layer of unbroken shale that caps a retort—

collapsed into the rubble pile. Operations

were disturbed while the top was resealed,

but retorting was eventually completed, and

about 40 percent of the oil was recovered.

DOE will share the costs of retorts 7 and 8,

which are scheduled for 1980 and 1981,

The oil shale at the Logan Wash site is not

considered to be of commercial quality because of its low kerogen content. In 1976, Oxy

acquired access to the higher quality resources of tract C-b by exchanging its technical knowledge for a half interest in the

lease. In 1978, Ashland Oil Co., Oxy’s partner

in the C-b Shale Oil Venture, withdrew and

left Oxy in full charge. In 1979, Tenneco Oil

Co. purchased a half interest in the lease for

$110 million and is proceeding to develop the

tract in cooperation with Oxy, If present

plans are followed, Oxy’s technology could be

used to produce about 57,000 bbl/d by 1985.

Oxy’s technique uses a vertical burn configuration— that is, the combustion zone progresses vertically through the shale bed. It is

also theoretically possible to advance the

burn front horizontally, in much the same

way as it is done in TIS processing. A crude

version of this approach was implemented in

Germany during World War II, when a few

MIS retorts were created by digging tunnels

into oil shale deposits and then collapsing

their walls into the void volume. These operations were short-lived because oil recoveries

were extremely low, and they were very hard

to control. 19

Horizontal MIS might be practical if a technique could be developed to remove large sections of oil shale strata. One possibility is to

use solution mining: the injection of fluids into

the formation to dissolve soluble salts from

among the oil shale layers, The result would

be a honeycomb pattern of voids that could

then be distributed throughout the area to be

retorted by injecting and detonating an explosive slurry. This method would be limited to

areas like the Leached Zone or the Saline

Zone that contain significant concentrations

of soluble salts. Other methods, such as longwall mining or mechanical underreaming,

could be used in other areas. It might be possible to operate mechanical underreaming

machines by remote control from the surface,

thus reducing or even eliminating the need

for miners to work underground. None of

these approaches has been tested in any oil

shale deposit.

Other MIS techniques that use verticalburn patterns have also been developed. For

example, the firm of Fenix and Scisson designed two systems for underground mining,

rubbling, and retorting in the vertical mode. z

’

)

To date, they have been tested only with a

computer model. DOE’S Lawrence Livermore

Laboratory has also developed an MIS technique called rubble in situ extraction (RISE)

with the aid of computer simulation and laboratory experiments in pilot-scale above-

-ground retorts.21-23 (See figure 28. ) Several

levels are mined, and a portion of the deposit

is removed at each. The remaining shale is

broken with explosives. Sufficient broken

shale is then removed so that there is a total

void volume of 20 percent in the retort area.

The rubble is then ignited at the top, and retorting proceeds as in the Oxy system.

The RISE approach was originally proposed by Rio Blanco Oil Shale Co. for tract

C-a, but the firm is now going ahead with its

own process, which has benefited from technical information acquired under a licensing

arrangement with Oxy. Livermore’s modeling

studies and laboratory experiments are continuing.

The initial plans for developing tract C-a by

MIS methods are shown in figure 29. They

would have involved five precommercial retorts of increasing size. The present plan,

which was adopted after purchase of Oxy’s

MIS technology, is shown in figure 30. In the

new development plan, a small pilot retort

(retort “O”) will be followed by two demonstration retorts of increasing size. The largest

(retort “2”) will be close to commercial scale.

Several options of different size are being

considered for retort 2, with one option a retort with dimensions 60 ft by 150 ft by 400 ft

high, The method by which the shale is rub-
134 An Assessment of Oil Shale Technologies

Figure 28.—The RISE Method of MIS Oil Shale Retorting

~“”~~~--.—-~ -- -

-—-—-— ‘-

. — --- —-- —--- —- ——— .—.— =.

/

/

-/5

OIL OUT

/

A. Isometric

I 1 I

I 1

Level A

(1

. .. . .

? .“ .“.’.s+

Development proceeds simultaneously on several levels. At each

level, horizontal drifts are driven the full width of the retort block,

and a vertical slot is bored to provide void volume for blasting.

About 200/. of the broken shale is removed after each blasting

operation. The rest is left in the retort volume.

. . . .

: Sublevel Level B

4 Starting slot

. . ‘“’”””””””””””””’!!;:- . . . . . . . . .

~Leve’c

B. Elevation

SOURCES: 01/ Shale Retorting Technology, prepared for OTA by Cameron Engineers, Inc., 1978; and C. K. Jee, et al., Rewew and Analyws of Od Shale Techno/ogy—

Vo/ume 3. Mod/tied In Situ Tec/rrro/ogy, report prepared for the U.S Department of Energy by Booz-Allen & Hamilton, Inc , under contract No, EX-76-C01-2343, August 1977, p. 6.
Ch 5–Technology ● 135

Figure 29.— Initial Modular MIS Retort Development Plan for Tract C-a

COMMERCIAL

FIELD 2 1

c’ ‘r

,,

. ’

r

~.,

)

,. -

.-

/ ‘> t -“

SOURCE RIO Blanco 011 Shale Project Revised Deta~/ed De~e/OP~eflt P/an Tracf C a Gulf 011 Corp and Standard 011 Co (Indiana), May 1977 P 125

bled, and the fraction of the shale that is

mined from each retort area are two of the

major differences between the Rio Blanco approach and Oxy’s technique. Oxy has tested

several rubbling methods, including drilling

blastholes up from a room at the bottom of the

retort, drilling down from the top, and boring

a central shaft the full length of the retort

and then blasting the surrounding shale into

the shaft. In Rio Blanco’s approach, a room

will be created at the bottom of the future retort, blastholes will be drilled from the surface into the roof of the room, and explosives

will be detonated sequentially at different

levels, The shale above the room will thereby

be blasted loose in layers, with each layer of

rubble falling to the bottom of the retort

volume before the next higher layer is

blasted. Through this technique, Rio Blanco

hopes to obtain uniform size distribution in

the rubble. This is believed to be a key technical requirement for efficient MIS retorting.

Rio Blanco also proposes to mine twice the

volume (40 v. 20 percent) as is contemplated

by Oxy.

Another MIS method that is still being designed is the integrated in situ technology proposed by Multi Mineral Corp. for recovering

shale oil, nahcolite, alumina, and soda ash

from oil shale deposits in the Saline Zone of

the Piceance basin. This zone underlies the

Leached Zone, is relatively free from ground
136 ● An Assessment of Oil Shale Technologies

Figure 30.— Present MIS Retort

Development Plan for Tract C-a

\ Down-Hole

Escape%

Shaft

%=

I’HF Ventilation Shaft

Off-Gas Shaft

- Access Shaft

figure 31, If technical and economic feasibility is indicated during the test program, Multi

Mineral would proceed to a commercial-scale

facility that would produce 50,000 bbl/d of

shale oil, 10,000 ton/d of nahcolite, 1,000

ton/d of alumina, and 20,000 ton/d of soda

ash.

The Multi Mineral approach resembles the

RISE technique in that mining and rubbling

are conducted at several levels along the

height of the retort, It departs from RISE in

that, after rubbling, the broken shale in the

retort is removed from the bottom, crushed

and screened, and returned to the top in a

continuous operation. This part of the retort

development plan is shown in figure 32. The

rubbled shale will contain free nahcolite and

+1 I I Ill II II II z SeDarator

Figure 31 .— Retort Development Plan for the

Multi Mineral MIS Concept

SOURCE The Pace Co Consultants and Engineers Inc Cameron Synthe(lc

Fue/s Report VOI 16 No 3 September 1979 p 28

water, and contains extensive resources of

nahcolite and dawsonite in addition to oil

shale. Development is hindered because the

zone is deeply buried (about 2,000 ft) below

the surface of the basin. To reduce the costs

of its R&D program, Multi Mineral has proposed to use an 8-ft-diameter shaft that was

drilled by USBM in 1978 through the Leached

Zone and into the Saline Zone. In the first

phase, mining and mine safety methods will

be tested, and about 8,000 tons of nahcolite

and 11,000 bbl of shale oil will be produced.

The nahcolite will be used for stack-gas

scrubbing tests in a powerplant. In the second phase, a retorting module will be used to

produce up to 3,000 ton/d of nahcolite, 10,000

bbl/d of shale oil, 200 ton/d of alumina, and

3,000 ton/d of soda ash. The modular retort

and the access shafts and drifts are shown in

--

(LEVEL B)

.-

(LEVE~D;

- -

CROSS CUT

STOPE FLOOR

SOURCE B Welchman, Sa//ne Zone 0// Sha/e Deve/opmen/ by [he /nlegrated

/n S/fU Process Multi Mineral Corp Houston Tex December 1979.

p 9
Ch 5– Technology ● 137

Figure 32.— Preparation of a Multi Mineral

MIS Retort

I

< HOLE NO. 1

HOLE NO. 2 ➤

BACKFILLED n

SHAFT

2200’

\)/ LEVEL

\

w \

SOURCE B We(c hman Sa/~ne Zone O() Shd/e Deve/oprnent by fhe /nlegrd(ed

In SJtu Process M u It I M I neral Corp H o uston Tex December 1979

D 15

nahcolite that is still associated with the

large blocks of shale. Crushing will liberate

most of the associated nahcolite, and screening will separate it from the shale particles.

The shale will be backfilled to the top of the

retort; the nahcolite is transported to the surface for processing. The result would be a retort that is filled with uniformly sized oil shale

particles. With this configuration, Multi Mineral hopes to avoid the channeling and bypassing problems that may occur in TIS and

MIS processing.

In a commercial-scale facility, the retorts

would be operated in sets of three, as shown

in figure 33, In retort 3, the oil shale is being

pyrolyzed by injecting hot gases to produce

shale oil (which is removed to the surface),

residual carbon, and soda ash and aluminum

oxide—the products of the thermal decomposition of dawsonite. The last three products

remain in the retort rubble. In retort 2, the residual carbon is being gasified by injecting a

mixture of steam and air. The heat from the

gasification reaction is carried to retort 3. In

retort 1, the hot gasified shale is being cooled

by passage of cold recycle gas. The heat thus

recovered is conveyed to retort 2. After the

shale in retort 1 is cooled, the soda ash and

the aluminum oxide can be leached out with

water. The leachate is then pumped to the

surface and processed to recover its mineral

values.

Temperature control is the key to the entire

operation. Oil alone could be recovered with

a combustion-type method, such as Oxy’s, but

because of the high temperatures, the decomposition of the dawsonite would produce compounds insoluble in water. The gas-recycle

heating method would avoid this problem by

maintaining lower retorting temperatures.

The operation also depends on the ability of

explosive rubbling techniques to produce

broken shale that can be fed to conventional

crushing equipment. Overall, the method is

very interesting because of its potential for

simultaneously recovering fuel and minerals

from deposits that may not be accessible with

any other approach. However, too little is

known about the various steps to permit a

thorough evaluation at this time.

Aboveground Retorting

Hundreds of retorts have been invented in

the 600-year history of oil shale development.

Most were never brought to the processing

stage but some were tested using laboratoryscale equipment, and a few at pilot-plant and

semiworks scales. None has been tested at a

scale suitable for modern commercial operations. This section summarizes the technical

aspects of seven retorting systems that offer

the promise of being applicable in the near

future. One obsolete technology that is the

basis for several

also discussed.

of the modern systems is

l – <

. . .

- 1
138 ● An Assessment of 01/ Shale Technologies

Figure 33.—A Set of Multi Mineral MIS Retorts

EXCESS

GAS

RETORT 1 RETORT 2 (RETORT 3

(HEAT RECOVERY) (CARBON RECOVERY) (PYROLYSIS) IIt

COLD RECYCLE GAS I ‘;

TK===========--====-=------=="*----=---*==---------; I

il

,1

i

II

II

OIL

I

‘1t

1,

1,

1,

;1

Ii

t

1,

I

,1

--- ------ a

SOURCE B Welchman, Sa//rre Zone” 0(/ Shale Deve/oprnerrf by the Irrtegrafed In SIfu Process, Multl Mineral Corp , Houston, Tex December 1979, p 11

Although aboveground retorts differ widely with respect to many technical details and

operating characteristics, they can be

grouped into four classes:

Class 1: Heat is transferred by conduction through the retort wall. The Pumpherston retorts used in Scotland, Spain,

and Australia were of this class, as is

the Fischer assay retort that was developed in the 1920’s. It is a laboratory

device for estimating potential shale oil

yields. Its oil yield is the standard to ●

which the retorting efficiencies of all

other retorts are compared. Because

conduction heating is very slow, no modern industrial retorts are in class 1.

Class 2: Heat is transferred by flowing

gases generated within the retort by

combustion of carbonaceous retorted

shale and pyrolysis gases. Retorts in this

class are also called directly heated.

They include the Nevada-Texas-Utah

(NTU) and Paraho direct processes described below, and also USBM’s gas

combustion retort and the Union “A”

retort. Class 2 retorts produce a spent

shale low in residual carbon and low-Btu

retort gas. Their thermal efficiencies are

high because energy is recovered from

the retorted shale. However, recovery

efficiencies are relatively low—about 80

to 90 percent of Fischer assay.

Class 3: Heat is transferred by gases

that are heated outside of the retort vessel. Retorts in this class are also called

indirectly heated. They include the Paraho indirect, Petrosix, Union “B,” and Superior retorts discussed below, and also

the Union SGR and SGR-3, the obsolete

Royster design, the Soviet Kiviter, the

Texaco catalytic hydrotort, and others.

These retorts produce a carbonaceous
Ch. 5–Technology ● 139

spent shale and a high-Btu gas. Thermal

efficiencies are relatively low because

energy is not recovered from the residual carbon, but oil recovery efficiencies

are high, from 90 to over 100 percent of

Fischer assay.

● Class 4: Heat is transferred by mixing

hot solid particles with the oil shale.

They include the TOSCO II and LurgiRuhrgas retorts described below, and

also the Soviet Galoter retort. Class 4 retorts achieve high oil yields (about 100

percent of Fischer assay) and produce a

high-Btu gas. The spent shale may or

may not contain carbon, and thermal efficiencies vary, depending on whether

the spent shale is used as the heat carrier. The retorts are sometimes referred

to as indirectly heated, as in class 3, because they also lack internal combustion, and produce a similar gas product.

Several other conversion methods have been

developed that cannot easily be placed in

these classes. These include microwave heating, bacterial degradation, gasification, and

circulation of hot solids slurries. Although

some of these processes have potentially valuable characteristics, they will not be discussed in this section because they have not

yet been proposed for near-term commercial

application.

The Nevada-Texas-Utah Retort

The NTU retort is a modified downdraft

gas producer similar to units used in the 19th

century to produce low-Btu gas from coal. It

is a vertical steel cylinder, lined with refractory brick and equipped with an air supply

pipe at the top and an exhaust pipe at the bottom. The top may be opened for charging a

batch of shale; the bottom for discharging the

spent shale after retorting. The unit was developed and tested for oil shale processing by

the NTU Co. in California in 1925, and was

also tested by USBM at Rifle, Colo., from 1925

to 1929. Two units with nominal capacities of

40 tons of raw shale were built and operated

by USBM at Rifle between 1946 and 1951.

They produced more than 12,000 bbl of shale

oil. Three units that were operated in Australia during World War 11 produced nearly

500,000 bbl. As noted previously, USBM used

two units to simulate in situ retorting.

The operating sequence for the NTU retort

is shown in figure 34. The unit is loaded with

crushed oil shale and sealed. The gas burner

is lighted, and air is blown in. Once the top of

the shale bed is burning (step A), the fuel gas

is shut off but the air supply continues. As the

air flows through the burning layer, it is

heated to approximately 1,500° F (815° C).

This hot gas heats the shale in the lower layers and induces the pyrolysis of the kerogen.

The oil and gases produced are swept down

through the cooler portions of the bed to the

exhaust port (step B). The solid product from

the conversion of the kerogen (residual carbon) remains on the spent shale and is consumed as the combustion zone moves down

the retort, providing fuel for additional combustion and thereby heat for additional pyrolysis. When all the carbon is burned from the

upper layers of the bed, the four zones shown

in step C are formed. The top layer contains

burned and decarbonized spent shale. The

second layer is burning, releasing heat for pyrolysis in the third layer. In the bottom layer,

the shale is being heated but is not yet at pyrolysis temperatures.

As time passes, the top layer expands

downward and the lower three zones move

uniformly down the retort. When the leading

edge of the combustion zone reaches the exhaust port, oil production ceases, air injection

stops, and the retort is emptied. The dumping

of spent shale ash from the 40-ton NTU at

Laramie is shown in figure 35. The entire

cycle, from ignition to dumping, takes about

40 hours.

NTU retorts are simple to operate, and require no external fuel except for small

amounts of gas to start the retorting. They

can process a wide variety of shales with oil

recoveries ranging from 60 to 90 percent of

Fischer assay. They are unsuitable for modern commercial applications because they

are batch units with high labor costs and

small capacities. Over 600 150-ton retorts
— .

140 ● An Assessment of 011 Shale Technologies

Figure 34.—The Operation of an NTU Retort

r

AIR SUPPLY

BLOWER

h- GAS BURNER: ON

SHALE IGNITES:

ED

~1N BURNER GAS AND

)

~1

SHALE OFF-GAS

HEAT REMAINING

SHALE

1- BURNER FLUE GAS

SMOKE, AND FUMES

STEP A

E

— AIR SUPPL Y

BLOWER

GAS BURNER: OFF

STEP B

COMBUSTION ZONE;

RESIDUAL CARBON BURNS

IN AIR STREAM

PYROLYSIS ZONE:

KEROGEN CONVERSION

WITHOUT FURTHER

COMBUSTION

PREHEAT ZONE:

SHALE HEATED BY

OFF-GAS TO BELOW

PYROLYSIS TEMPERATURE

LOW-BTU GAS AND OIL MIST

TO SEPARATION EQUIPMENT

r

AIR SUPPLY

BLOWER

/%-

GAS BURNER: OFF

}

SPENT SHALE ZONE:

ALL RESIDUAL CARBON

}

BURNED

COMBUSION ZONE:

RESIDUAL CARBON

1

BURNING

PYROLYSIS ZONE;

KEROGEN CONVERSION

N!!iN\ \

l\ II ‘+

(

PREHEAT ZONE;

{

Y

\\ y

t LOW-BTU GAS AND

OIL MIST

STEP C

SOURCE T A Sladek, Recent Trends In 011 Shale– Part 2 Mining and Shale 011 Extract Ion Processes, M(nera/ /ndustr/a/ Elu//ef/n VOI 18 No 1 January 1975 p 5

would be needed to produce 50,000 bbl/d of

crude shale oil. In contrast, plants using some

of the continuous technologies described below would require only about six retorts for

the same production capacity.

The Paraho Direct and Indirect Retorts

An NTU retort becomes a Paraho direct retort when it is turned upside down, made continuous, and mechanically modified. The Paraho retorts are based on USBM’s gas combustion retort which, in turn, evolved from the

NTU retorts tested at Anvil Points in the late

1940’s. The gas combustion process was

tested in 6-, 10-, and 25-ton/d units by USBM

between 1949 and 1955, and by a consortium

of six oil companies between 1964 and 1968.

The Paraho direct retort is similar in design

to the gas combustion technology but it is

more likely to be commercialized.-

It was developed by Development Engineering, Inc.,

(DEI) in the late 1960’s, and was tested for

limestone calcining in three cement kilns in

South Dakota and Texas. Each kiln had a capacity of 330 ton/d and was comparable to

the largest gas combustion retort tested by

the six oil companies.

After verifying the solids-flow characteristics of the Paraho technology in the limestone kilns, DEI leased the Anvil Points site

from the Federal Government in May 1972,

and began a 5-year program to develop the

technology for oil shale processing. Funding

was obtained from a consortium of 17 energy

companies and engineering firms. In return

for a contribution of $500,000, each company
Ch 5– Technology ● 141

Figure 35.— Discharging Spent Shale Ash From a 40-Ton NTU Retort

.

SOURCE U S Department of Energy
142 ● An Assessment of 0il Shale Technologies

was guaranteed a favorable royalty arrangement in any subsequent commercial application of DEI’s technology. The Paraho Development Corp. was formed to manage the project. * Two retorts, a pilot-scale unit 4.5 ft in

diameter and 60 ft high and a semiworks unit

10.5 ft in diameter and 70 ft high, were installed and tested after August 1973. They

were used to produce over 100,000 bbl of

crude shale oil, some of which was used for

refining and end-use experiments by DOE

and the Department of Defense. Maximum

throughput rates reached about 400 ton/d in

the semiworks unit. Both direct and indirect

heating modes were tested.

The Paraho retort is shown in figure 36,

and the Anvil Points semiworks unit in figure

37. In its direct mode, the retort is very similar to the older gas combustion design. However, significant differences exist in the shale

feeding mechanism, in the gas distributors,

and in the discharge grate. During operation,

raw shale is fed to the retort through a rotating distributor at the top. It descends as a

moving bed along the vertical axis of the retort. As it moves, it is heated to pyrolysis temperatures by a rising stream of hot combustion gases. The oil and gas produced are

swept up through the bed to collecting tubes

and out of the retort to product separation

equipment. The retorted shale retains the residual carbon. As the shale approaches the

burner bars, the carbon is ignited and gives

off the heat required for pyrolyzing additional raw shale. Passing beyond the burner bars,

the shale is cooled in a stream of recycle gas

and exits the bottom of the retort through the

discharge grate. It is then moistened and sent

to disposal.

The retort may also be operated as a class

3 retort. The configuration would resemble

directly heated operations except that air

would not be injected and the offgas steam

would be split into four parts after oil separation. One part would be the net product gas.

Another would be sent through a reheating

furnace and then reinfected into the middle of

*“ Paraho” is from the Portuguese words “para homen”’—

for mankind.

Figure 36.— The Paraho Oil Shale Retorting System

RAW

SHALE

(?w ltl1 OIL MIST

SEPARATORS

---- -—-

MIST

FORMATION

AND

PREHEATING

- — ---- OIL

RETORTING OIL

ZONE PRODUCT ru

I I

GAS ELECTROSTATIC

-- — - --- t PRECIPITATOR

COMBUSTION F

1

ZONE

-

4

i

----—- RESIDUE

COOLING

AND

GAS

PREHEATING \ --- —- -

/v

4 ●

t * A A

RECYCLE GAS

BLOWER

AIR BLOWER

~ SpEED

CONTROLLER‘y

RESIDUE

A. Direct Heating Mod e

RAW

SHALE

OIL MiST

SEPARATORS

MIST

FORMATION

AND

PREHEATING ——-—- — [ ~OIL

RETORTING OIL

ZONE STACK L —

t

GAS ELECTROSTATIC

--—- —- < HEATER PRECIPITATOR

HEATING

0

T RECYCLE GAS i —

t

BLOWER

----- --

RESIDUE

COOLING PRODUCT GAS

AND

GAS

~REHEATIN$ AIR BLOWER

—— —- -

c?-

‘)1(

RESIDUE

B. Indirect Heating Mode

SOURCE C C Shlh, et al Techno/ogma/ Ovefv)ew Reporfs for Eight Sha/e 0//

Recovery Processes report prepared for the U S Environmental Protection Agency by TRW under contract No EPA.600/7.79-075 March

1979, pp 20 and 23
Ch 5– Technology ● 143

Figure 37.— The Paraho Semiworks Unit at Anvil Points, Colo.

SOURCE Paraho Development Corp
144 ● An Assessment of Oil Shale Technologies

the retort. A third would not be reheated but

would be reinfected through the bottom of the

retort to cool the shale before discharge. The

fourth would be used for fuel in the reheating

furnace. All heat for kerogen pyrolysis would

be provided by the reinfected gases, and no

combustion would occur in the retort vessel

itself.

To date, the Paraho retorting technology

has been tested at about one-twentieth of the

size that would be used in commercial plants.

Paraho would like to test a full-size module

producing about 7,300 bbl/d at Anvil Points,

and has submitted a proposal to DOE for such

a program. Both direct and indirect heating

modes would be tested. Permission has been

obtained from the Department of the Navy to

use large quantities of shale from the Naval

Oil Shale Reserves for the program. An environmental impact statement (EIS) is being

prepared for the project. Paraho has responded to a DOE Program Opportunity Notice for a $15 million engineering design study

of modular oil shale retorting, and would

base the design of the Anvil Points module on

results of the study. Outcome of the procurement has not yet been announced.

The Petrosix Indirectly Heated Retort

The Petrosix process was developed for the

Brazilian Government by Petrobras, the national oil company, with the assistance of

Cameron and Jones, Inc., a U.S. engineering

firm, Russell Cameron, later president of

Cameron Engineers, worked on the gas combustion program at Anvil Points, as did John

Jones, later president of Paraho. The system

is depicted in figure 38. Figure 39 is a photograph of the demonstration retort that has

been built and tested in Brazil. The retort is

18 ft in diameter, and has a capacity of 2,200

ton/d of Irati oil shale. It was built in 1972,

and tested intermittently until quite recently.

In 1975, a U.S. patent was issued for the process, A 50,000-bbl/d plant is planned by the

Brazilian Government, to be developed in a

two-stage project. The first stage would involve construction of a 25,000-bbl/d facility

about 5 miles from the site of the demonstration plant near the city of Sao Mateus do Sul

in the State of Parana. In the second stage,

the full commercial plant would be built on

the same site, to include 20 Petrosix units,

each about 33 ft in diameter. Brazil is not

committed to either stage, but if financing is

obtained in 1980, the first stage could be completed by 1983 and the second by 1985. In

addition to the shale oil, the plant would

also produce sulfur and liquefied petroleum

gases. Preliminary plans are also being prepared for two additional commercial-scale

plants south of the present demonstration

plant in the State of Rio Grande do Sul.

Except for mechanical differences, the

Petrosix retort is very similar to the Paraho

indirect retort described above. This similarity is not surprising in view of the shared engineering heritage of the two systems. One

operational difference is that the Petrosix

spent shale is discharged into a water bath

and pumped in a slurry to a disposal pond.

Paraho shale is discharged dry, with only a

little water added prior to disposal.

Little information has been released about

the demonstration program. Oil characteristics have been described, but these have little

relevance to the processing of Green River

shale. It can be predicted that the retort

should have high oil recovery efficiencies and

produce a retort gas with high heating value.

The spent shale would be carbonaceous. In

the demonstration plant, recovery of energy

from the spent shale was not possible because of the slurry disposal method. In any

commercial plant, it is possible that the shale

would be burned in a separate unit to produce heat for pyrolysis.

The Union “B’ Indirectly Heated Retort

The Union “B” retort is a class 3 retort that

evolved from the Union “A,” a class 2 retort,

by the Union Oil Co. of California. Two other

systems, the SGR and SGR-3, have also been

proposed by Union, Union describes them all

as continuous, underfeed, countercurrent retorts. The “B” has not been field tested, but

the “A” was tested in Colorado in the 1950’s
Ch. 5–Technology ● 145

Figure 38. —The Petrosix Oil Shale Retorting System

=ALGAS<”’LSHALEFEED

PYROLYSIS

VESSEL

DISCHARGE

MECHANISM

D

HIGH BTU GAS

FEED HOPPER

PRODUCT FOR

PURIFICATION

DISTRIBUTOR ELECTROSTATIC

PRECIPITATOR CONDENSER

●

CYCLONE

I

SEPARATOR

HEAVY COMPRESSOR

SHALE OIL HOT HEAVY

0000 0 d ‘A s

v 9 SHALE OIL

\ WASTE

WATER

HEATER

\ COOL GAS

WATER JftJ -

SEAL SYSTEM

RETORTED SHALE SLURRY

TO DISPOSAL

SOURCE 0// Sha/e Refer//ng Technology, prepared for OTA by Cameron Engineers, Inc , 1978

at up to 1,200 ton/d. Figure 40 is a sketch of

the Union “B” design. It incorporates most of

the design features of the “A.”

During operation, shale is fed through the

bottom of the inverted-cone vessel. The retorting process thereafter resembles that of a

continuous NTU retort. Hot gases enter the

top of the retort and pass down through the

rising bed, causing kerogen pyrolysis. Shale

oil and gas flow down through the bed. The oil

accumulates in a pool at the bottom, which

seals the retort and acts as a settling basin

for entrained shale fines. Oil and gas are

withdrawn from the top of the pool. The gases

are split into three streams. One is reheated

and reinfected to induce additional kerogen

pyrolysis; one is used as fuel in the reheating

furnace; and one is the net product. The shale

is discharged from the top of the retort and

falls into a water bath in the retorted shale

cooler. From there it is conveyed to disposal.

The key to all of Union’s retorting systems

is the solids pump that is used to move the oil

shale through the retort. In the “B” design,

the solids pump is mounted on a movable carriage and is immersed in the shale oil pool.
146 ● An Assessment of 0il Shale Technologies

Figure 39.— The Petrosix Demonstration Plant, Sao Mateus do Sul, Brazil

SOURCE Cameron Engineers, Inc
Ch 5– Technology . 147

TiT

A. The

r

k!%

Figure 40.—The Union Oil “B” Retorting Process

Ii?

P-4‘. “’

=.+.’.’ AA-+--d 1

=OIL LEVEL

RETORTED SHALE

/ DISCHARGE

\\\\\l\ll

.h\\\\\\lllt

j?{!

r T

—

r

TO WATER SEAL

7

RETORT

* GAS

- ROCK PUM P

M

m * SHALE OIL

I

m

\ \ \ \~\\\ ‘\\ \\~. \ \’ \l\\ . ~. . .1 \\\ \ \“.’\\\\\\\\\\\\~.\

Retorting System

SHALE IN SHALE IN

I

SHALE IN SHALE IN

B. Hock Pump Detail

SOURCE 0/1 Strale Reforf/ng Technology, prepared for OTA by Cameron Engineers Inc .1978
.

148 . An Assessment of Oil Shale technologies

The pump consists of two hydraulic assemblies that act in sequence. (See figure 40.)

While the cylinder of one assembly is filling

with oil shale, the other is charging a batch of

shale into the bottom of the retort. When this

operation is completed, the carriage moves

horizontally on rails until the full cylinder is

under the retort entrance. A piston then

moves the oil shale in this cylinder upwards

into the retort, while the other fills with fresh

shale from the other feed chute. The carriage

then returns to its original position and the

process is repeated.

The “B” achieves high oil yields, and the

retort gas has a high heating value, although

much of it is consumed in the reheating furnace. The mechanical nature of the rock

pump is troublesome because its moving

parts would be subject to wear during operation. However, the pump is immersed in the

shale oil pool, which should provide adequate

lubrication. Union appears to be satisfied

with its reliability.

In 1976, Union announced plans to build a

demonstration plant on its private land in Colorado. The “B” retort was to be used to produce 7,000 bbl/d of shale oil from 10,000 ton/d

of oil shale. Later, the announced capacity

was increased to 9,000 bbl/d. The demonstration plant, called the Long Ridge project,

would be the first step towards a 75,000-bbl/d

commercial-scale plant. Air quality permits

have been obtained for the modular plant,

which could be completed before 1985. Construction has not begun because Union is

awaiting financial incentives from the Federal Government.

The Superior Oil Indirectly Heated Retort

The Superior retort is unique among the

aboveground retorts discussed in this section

because it is designed for recovery of sodiumbearing minerals in addition to shale oil. As

discussed in chapter 4, the minerals nahcolite

and dawsonite occur in substantial quantities

in portions of the Piceance basin. They are

potential sources of sodium bicarbonate,

soda ash, and aluminum.

A block diagram for the Superior approach

is shown in figure 41. In step 1, the mined

oil shale is crushed to pieces smaller than 8

inches and screened. About 85 to 90 percent

of the nahcolite in the shale is in the form of

distinct, highly friable nodular inclusions that

become a fine powder during the crushing

operation. This is screened from the coarser

shale in step 2. The shale is then further

crushed to smaller than 3 inches and is fed in

step 3 to a doughnut-shaped traveling-grate

retort, which includes sequential stages for

heating, retorting, burning, cooling, and discharging the oil shale feed. The retort is

sketched in figure 42. In the heating section,

oil is recovered by passing hot gases through

the moving bed. In the carbon recovery section, process heat is recovered by burning the

residual carbon. In the cooling section, inert

gases are blown through the bed of spent

shale, cooling the shale and heating the gases

for use in the heating section. After discharge, the cooled spent shale is sent to other

units in which alumina is recovered from calcined dawsonite and soda ash from calcined

nahcolite. The alumina is shipped to offsite

aluminum refineries; the soda ash to glass

plants; and the nahcolite to refineries and

powerplants for use as a stack-gas scrubbing

agent.

Superior chose the traveling-grate retort

because it allows close temperature control,

important to maintaining dawsonite’s solubility during the burning stage. Similar, simpler

devices have been used to sinter iron ore for

steelmaking and to roast lead and zinc sulfides. Superior’s process has been tested for

oil shale in pilot plants in Denver and Cleveland. A commercial-scale plant would consume 20,000 ton/d of oil shale to produce

10,000 to 15,000 bbl/d of shale oil, 3,500 to

5,000 ton/d of nahcolite, 500 to 800 ton/d of

alumina, and 1,200 to 1,600 ton/d of soda ash.

In the early 1970’s, Superior proposed to

build a commercial-size demonstration plant

on its 7,000-acre tract in the northern Piceance Basin. The deposit was to be developed by deep room-and-pillar mining on several levels. The single retort was to produce
Ch 5–Technology 149

Figure 41 .— Block Diagram for the

Superior Multi Mineral Concept

14EH---T I I

I

I

SPENT SHALE

SHALE

STEP 2 STEP 3 STEP 4

SHALE

NAHCOLITE

ASH

>

OIL E

ALUMINA &

RECOVERY RECOVERY SODA ASH

RECOVERY

● ● ● ●

NAHCOLITE OIL SODA ASH ALUMINA

SOURCE 01/ Shale Retorting Technology, prepared for OTA by Cameron Engl

neers, Inc .1978

11,500 bbl/d of shale oil, plus the byproducts

described above. Although the tract’s resources are extensive, its L-shaped configuration does not favor large-scale development. Superior therefore proposed to exchange portions of the tract for adjacent land

controlled by the Bureau of Land Management (BLM). Approval was delayed by BLM

review and by preparation of an EIS, a draft

of which was recently released. In February

1980, BLM denied the exchange because the

two tracts involved were not considered to

have equivalent value. The decision is open to

review.

The TOSCO H Indirectly Heated Retort

The TOSCO II is a class 4 retort in which

hot ceramic balls carry heat to finely crushed

oil shale, It is a refinement of the Aspeco

process developed by a Swedish inventor.

Patent rights were purchased by The Oil

Shale Corp. (later Tosco) in 1952. Early development work was performed by the Denver

Research Institute, including testing of a 24-

ton/d pilot plant. In 1964 Tosco, Standard Oil

Co. of Ohio (SOHIO), and Cleveland Cliffs Iron

Co. formed Colony Development, a joint venture company, to commercialize the TOSCO II

technology. Between 1965 and 1967, the

group operated a 1,000-ton/d semiworks

plant on its land near Grand Valley, Colo.,

next to the site of Union’s semiworks operations. In 1968, Colony prepared a preliminary

engineering design and cost estimate for a

commercial-scale plant that would contain

six TOSCO II retorts, and convert 66,000

ton/d of oil shale into about 46,000 bbl/d of

shale oil. In 1969, ARCO joined Colony, and a

second semiworks program began to test

scaleup procedures and to evaluate environmental controls. The program continued until

April 1972. Between 1965 and 1972 the semiworks plant converted 220,000 tons of oil

shale into 180,000 bbl of shale oil.

In 1974, the 1968 cost estimate, which had

been updated in 1971, was further revised to

incorporate operating data from the latter

part of the semiworks program and to account for additional pollution controls. The

resulting cost estimate was about three times

as large as the previous estimate. This cost

escalation raised doubts about commercial

feasibility, and the project was postponed indefinitely. SOHIO and Cleveland Cliffs subsequently withdrew from the Colony group.

Early in 1974, Tosco, ARCO, Ashland, and

Shell purchased a lease for tract C-b from the

Federal Government. Initial development

plans for the tract involved a plant similar to

that proposed for Colony’s private tract.

These plans were also affected by the cost escalations, and in 1976 suspension of operations on tract C-b was granted by the Government. In 1977 Tosco and ARCO withdrew

from the tract. Shell withdrew in 1977. Ashland, the remaining partner, teamed with

Oxy to develop the tract using MIS techniques.

Colony’s semiworks retort, which is about

one-tenth of commercial scale, is shown in

figure 43. The TOSCO II retorting system is

sketched in figure 44. Raw shale is crushed

smaller than one-half inch and enters the system through pneumatic lift pipes in which the

shale is elevated by hot gas streams and preheated to about 500” F (260° C). The shale

then enters the retort, a heated ball mill, and

contacts a separate stream of hot ceramic

balls. As the shale and balls mix, the shale is

heated to about 950

0 F (5100 C), causing retorting to take place. Oil vapors and gases are

withdrawn. The oil is condensed in a fraction-
150 . An Assessment of Oil Shale Technologies

Figure 42.—The Superior Oil Shale Retort

COOL

RECYCLE

GAS

SHALE

FEED

HOT

RECYCLE

S+LE HEATING

+

‘As -~

COOL

RECYCLE

/

GAS

1- --

~--- 1

SOURCE. 0// Sha/e Retorturg Tec/rno/ogy, prepared for OTA by Cameron Eng!neers, Inc , 1978 (after Arthur G McKee & Co j

ator. Some of the gases are burned in a heater to reheat the ceramic balls to about 1,2000

F (650° C). At the retort exit, the retorted

shale and the cooled ceramic balls pass over

a trommel, a perforated rotating separation

drum. The shale, which has been thoroughly

crushed during retorting, falls through holes

in the trommel. It is cooled and sent to disposal. The larger balls pass over the trommel

and are sent to the ball heater.

Oil yields exceeding 100 percent of Fischer

assay have been reported for the TOSCO II

technology. However, overall thermal efficiencies are low because energy is not recovered from spent shale carbon, and much of

the product gas is consumed in the ball heater. Tosco has patented processes to burn the

retorted shale as fuel for the ball heater, thus

increasing energy recovery, and freeing

valuable retort gases for other uses.

the

The retort’s chief disadvantages are its

mechanical complexity and large number of

moving parts. The ceramic balls are consumed over time. The need for a fine feed size

results in crushing costs that are higher than

those of systems that can handle coarser

feeds. On the other hand, all crushing operations produce some fine shale that could be

screened from the feed to coarse-shale retorts and converted in auxiliary TOSCO II

units. Disposal of TOSCO II spent shale

presents some problems because it is very

finely divided and contains carbon.

At present Tosco is participating in two

projects that are committed to its proprietary
Ch 5–Technology ● 151

Figure 43. — The Colony Semiworks Test Facility Near Grand Valley, Colo.

SOURCE Colony Development Corp
152 ● An Assessment of 011 Shale Technologies

Figure 44.—The TOSCO II Oil Shale Retorting System

FLUE GAS PREHEAT SYSTEM

TO ATMOSPHERE

4

STACK

—

RAW

CRUSHED

SHALE

WATER VENTURI BALLS

WET SCRUBBER

SEPARATOR FOUL WATER To

-h

z FOUL WATER

~ STRIPPER

CERAMIC u

BALL

a NAPHTHA

HEATER

:

SLUDGE” F

v

<

-

- HYDROCARBON ~ GAS OIL TO GAS 01 L

VAPORS HYDROGENATION

n

HOT BALLS BOTTOMS OIL TO

:

ACCUMULATOR DELAYED COKER

Q

~

u.

w

~

2

w

t-3

-1 BALL CIRCULATION

E SYSTEM STACK

VENTURI

WET

SCRUBBER

I

HOT FLUE GAS

PREHEAT SYSTEM HOT

(INCLUDES INCINERATOR) PROCESSED

SHALE

FLUE GAS

+

*

cnnu CTFAM SLUDGE I

COOLER

MOISTURIZER“’++

MOISTURIZER 4 SCRUBBER

r+) WATER STACK

VENTURI WET

SCRUBBER

t

SLUDGE

MOISTURIZED PROCESSED

COVERED PROCESSED

SHALE CONVEYOR - ‘+$%spOsAL SOURCE 0// Shale Retorflng Technology prepared for OTA by Cameron Engineers, Inc , 1978.

retorting technology. The Colony project has The Lurgi-Ruhrgas Indirectly Heated Retort

been mentioned previously. The other venture, the Sand Wash project, is being devel- The Lurgi-Ruhrgas retorting system uses a

oped on 14,000 acres of land in the Uinta class 4 retort in which hot retorted shale carBasin leased from the State of Utah. Unlike ries pyrolysis heat to oil shale. The process

the Colony project, which has been sus- was developed jointly by Ruhrgas A. G. and

pended pending resolution of economic uncer- Lurgi Gesellschaft fur Warmetechnik m. b. H.,

tainties, Sand Wash is proceeding towards two West German firms that have been incommercialization in compliance with the due volved in synfuels production for decades.

diligence requirements of the State leases. A The process was developed in the 1950's for

plant similar to the proposed Colony facility is low-temperature coal carbonization. A 20-

contemplated, but no schedule has been an- ton/d pilot plant was built in West Germany,

nounced for its construction. At present, to test a variety of coals, oil shales, and

work consists of monitoring the environment, petroleum oils. European shales were tested

and preparing to sink a mine shaft. in the late 1960’s, and Colorado oil shale in
Ch 5–Technology ● 153

1972. The plant has since been scrapped but

smaller retorts are available.

Coal processing plants using the LurgiRuhrgas technique have been built in Japan,

West Germany, England, and Argentina.

There are also two Yugoslavian plants, each

built in 1963, with a capacity of 850 ton/d of

brown coal. The Japanese plant is also of

commercial size, and uses the process to

crack petroleum oils to olefins. No large-scale

oil shale plants have yet been built.

The retorting system is shown in figure 45.

Finely crushed oil shale is mixed with hot retorted oil shale in a mechanical mixer that resembles a conventional screw conveyor. Retorting takes place in the mixer, and gas and

shale oil vapors are withdrawn. Dust is removed from these products in a cyclone separator and oil is separated from the gas by condensation. Retorted shale leaves the mixer

and is sent to a lift pipe where it is heated to

about 1, 100° F (5950 C) in a burning mixture

of fuel gas and air. The hot retorted shale is

then sent back to the mixer, and the process

is repeated.

High oil yields have been reported for the

retort, and the product gas is of high quality.

Figure 45. —The Lurgi-Ruhrgas Oil Shale

Retorting System

WASTE HEAT

-OLIDS1 ~-~ FLUE GAS wAsTE

RECOVERY

OIL GASEOUS ANO

LIQUID PRODUCTS

CONDENSER

DUST

MIXING SCREW

TYPE RETORT SOLIDS

SURGE

LIFT BIN

PIPE

TO WASTE

~ AIR - FUEL

(!! Reqwed)

SOURCE 0// .Shale Retorf/ng Technology, prepared for OTA by Cameron Engt

neers Inc 1978

Except for the mixer, the process is mechanically simple and has few moving parts. It

should be capable of processing most oil

shales, if they are crushed to a fine size. The

two major problems with the system appear

to be accumulation of dust in the transfer

lines and dust entrainment in the oil. Dusty

crude oil is not a severe problem because the

dust is concentrated in the low-value residual

product when the oil is subsequently refined.

As with the TOSCO II process, requirements

for a fine feed material will result in high

crushing costs. These costs would be partially offset by the ability to process the fine fraction from any crushing process, including

those used to prepare shale for coarse-shale

retorts.

In 1972, Lurgi proposed to develop its retorting technologies with Colorado oil shale.

The program was not funded, but Lurgi’s interest in commercializing the technique has

continued. In recent years Lurgi has been

working with Dravo Corp. to interest U.S.

firms in using the technology. At present, at

least one company—Rio Blanco—has obtained a license to investigate the use of

Lurgi-Ruhrgas retorts. Present plans call for

constructing a modular Lurgi-Ruhrgas retort

that will be close to commercial size (2,200

ton/d). It will be used to retort the shale that

will be mined during the preparation of MIS

retorts on tract C-a.

Advantages and Disadvantages of

the Processing Options

The greatest advantage of TIS processing

is that mining is not required, and spent shale

is not produced on the surface. The technical,

economic, and environmental problems associated with above-ground waste disposal are

thereby avoided. MIS does involve mining and

aboveground waste disposal, although to a

lesser extent than with AGR. However, the

MIS waste is either overburden or raw oil

shale. Both materials are found naturally exposed on the surfaces of deeper canyons in

the oil shale basins. Although raw shale has

low concentrations of the soluble salts, it does

contain soluble organic materials that could
154 . An Assessment of 011 Shale Technologies

be leached from the disposal piles. It should

be noted that the presence of spent shale underground has the potential to cause environmental problems because soluble salts could

be leached by ground water. Therefore, environmental controls will also be needed for

TIS and MIS methods.

Surface Facilities

TIS has another theoretical advantage in

that the required surface facilities are minimal, consisting only of wells, pumps, gas

cleaning and product recovery systems, oil

storage, and a few other peripheral units.

These facilities would probably resemble

those for processing of crude oil and natural

gas. MIS requires more facilities to support

the mine and the waste disposal program.

Aboveground processing, which uses the

largest number of facilities, causes the most

surface disruption.

Oil Recovery

The advantage of AGR is that the conditions within the retorts can be controlled to

achieve very high oil recoveries—approaching or even in some cases exceeding the yields

achieved with Fischer assay retorts. Retorting efficiencies are usually lower for MIS

processing and much lower for TIS because

of the difficulty in obtaining a uniform distribution of broken shale and void volume,

which in turn, makes it difficult to maintain

uniform burn fronts and leads to channeling

and bypassing of the heat-carrier gases. The

few estimates of the retorting efficiencies of

TIS operations that have been published have

not been encouraging. (USBM achieved recoveries of 2 to 4 percent in its field tests. ) MIS

retorting has not exceeded 60-percent recovery of the potential oil in the shale within the

retorts. It is expected that yields from MIS retorts could be increased by injecting steam or

hydrocarbon gases (as is done in Equity’s TIS

process), but it is doubtful that recoveries can

reach those of carefully controlled above-

-ground retorts. On the other hand, the present low efficiencies of MIS operations are

partially compensated for by their ability to

convert very large sections of an oil shale deposit, by their ability to process shale of a

lower grade than would be practical for AGR,

and by their lower cost of preparing the shale

for retorting.

It is difficult to compare overall recoveries

from MIS and AGR without making numerous

assumptions about the operating characteristics of both systems. To make a rough comparison, it could be assumed that AGR (with

room-and-pillar mining) and MIS were to be

applied to two 30()-f t-thick deposits with identical physical characteristics. The net recoveries from several development options are

summarized in table 18. The highest recovery

(100 percent) is for full-subsidence mining in

conjunction with AGR processing. It should

be noted that full-subsidence mining, for

either MIS processing or AGR, would result

in extensive surface disturbance and could

increase risks to the miners. Subsidence mining has never been tested in oil shale. Its potential for surface disturbance could be reduced by backfilling the mined-out areas with

spent shale from surface processing, The retorted shale in burned-out MIS retorts would

also reduce the severity of subsidence.

The three generic approaches to oil shale

processing also have various other advantages and disadvantages with respect to

water needs, environmental effects, financial

requirements, and social and economic impacts. These aspects are discussed in the respective chapters of this report.
Ch 5–Technology ● 155

Table 18.–Overall Shale Oil Recoveries for Several Processing Options

First-stage

Case retorting technology First-stage mining method

1 AGR Conventional room-and-pillar mining on three levels 60-ft

rooms, 60-ft barrier and siII pillars.

2 MIS Conventional MIS mining. 40% of shale left behind in barrier

pillars 20% of the disturbed shale IS removed to the surface

to provide void volume in the retorts

3 MIS As in case 2

4 AGR As in case 1

5 MIS Full subsidence b

6 MIS Full subsidence b

7 AGR Full subsidence b

Second-stage processing

None

None

AGR processing of the mined shale

Barrier and siII pillars collapsed and

retorted by MIS

None

AGR processing of the mined shale

None.

Overall shale

oil recoverya

36%

29%

41 %,

74%

48%

68%

100%

aAssurnlng AGR reco~ers 100 ~ercenl of the potential 011 In the shale retorted MIS assumed to recover 60 percent of the potential 011

bEntlre deposit IS mned

SOURCE Off Ice of Technology Assessment

Properties of Crude Shale Oil

Crude shale oil (also called raw shale oil,

retort oil, or simply shale oil) is the liquid oil

product recovered directly from the offgas

stream of an oil shale retort. Synthetic crude

oil (syncrude) results when crude shale oil is

hydrogenated. In general, crude shale oil

resembles conventional petroleum in that it is

composed primarily of long-chain hydrocarbon molecules with boiling points that span

roughly the same range as those of typical

petroleum crudes. The three principal differences between crude shale oil and conventional crude are a higher olefin content (because of the high temperatures used in oil

shale pyrolysis), higher concentrations of oxygen and nitrogen (derived from oil shale kerogen), and, in many cases, higher pour point

and viscosity,

The physical and chemical properties of

crude shale oil are affected by the conditions

under which the oil was produced. Some

retorting processes subject it to relatively

high temperatures, which may cause thermal

cracking and thus produce an oil with a lower

average molecular weight. In other processes

(such as directly heated retorting) some of the

lighter components of the oil are incinerated

during retorting. The result is a heavier final

product. Others may produce lighter products because of refluxing (cyclic vaporization

and condensation] of the oil within the retort.

One of the most important factors is the condensing temperature within the retorting system—the temperature at which the oil product is separated from the retort gases, The

lower this temperature, the higher the concentration of low molecular weight compounds in the product oil,

The properties of crude shale oil from several aboveground and MIS retorting processes are listed in table 19.24 It is important to

note that the oils that are characterized were

produced in small-scale test runs under conditions that may not be representative of

those that will be encountered in other areas,

and with larger processing systems. The oils

from commercial-scale facilities in other

parts of the oil shale region may have properties that are quite different,

The properties of the oil produced by different AGR processes vary widely, but the

differences between these oils and the in situ

oils are much more significant. In situ oils are

generally much lighter, as indicated by their

higher yields of material with relatively low

boiling points, and would produce more lowboiling product (such as gasoline) and less

high-boiling product (such as residual oil). In

general, the low yields of residuum make

shale oils attractive as refinery feedstocks in

comparison with many of the heavy conven-
156 . An Assessment of Oil Shale Technologies

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Ch 5– Technology ● 157

tional crudes that are currently being processed in the United States. For example, in

situ oil from Oxy’s MIS process contains 1 to

4 percent of material with a boiling range of

over 1,000° F (5350 C), compared with 20 percent for crude from Alaska’s North Slope,

and 18 percent for Arabian Light crude.25 26

Other foreign crudes, such as Kuwait and

Arabian Heavy, contain even larger residuum

fractions. Oils from some AGR processes contain as much as 30 percent of residuum

which, although higher than the contents of in

situ crudes, is substantially lower than that

for many conventional crudes.

Coal-derived liquids are often regarded as

alternatives to shale oil feedstocks. However,

syncrudes from coal have a much higher yield

of gasoline and low-boiling distillates than

shale oil, with little or no material boiling at

temperatures above 850° to 1,000° F (4550 to

535° C), The coal liquids would be well-suited

for gasoline production because their higher

concentrations of lower boiling constituents

when refined would yield the desired light

naphtha fractions. Shale oil, on the other

hand, has a much higher concentration of

high-boiling compounds, and would favor production of middle distillates (such as diesel

fuel and jet fuels) rather than naphtha, Shale

oil and coal-derived syncrudes should, therefore, be regarded not as a competitive or substitutable feedstocks but rather as complementary feedstocks, with each yielding a difShale Oil

Shale oil has been successfully refined in

oil shale operations in Sweden, Scotland,

Australia, West Germany, the U. S. S. R., and

other countries, although on a relatively

small scale and under unusual economic conditions. In the United States, the initial refining research was conducted by USBM at the

Petroleum and Oil Shale Experiment Station

at Laramie, Wyo. It was coordinated with the

early development of the gas combustion retort at Anvil Points, Colo. The results of this

work, plus the findings of other investigators,

allowed a preliminary assessment to be made

ferent major fuel product from an equivalent

amount of refining.

Among the negative characteristics of most

crude shale oils are high pour point, high

viscosity, and high concentrations of arsenic

and other heavy metals and of nitrogen. The

pour point and viscosity are of economic importance because transporting viscous oil

that has a high pour point is difficult and costly, thus suggesting the need for pretreatment

prior to marketing. * As shown in table 19, in

situ oils with their relatively low pour points

and viscosities could be marketed without

pretreatment but they would retain their high

nitrogen contents. This would reduce their

value as refinery feedstocks and boiler fuels.

High concentrations of arsenic and other

metals are a disadvantage because they poison refining catalysts, especially in hydrogenation units. They must be removed prior to

catalytic processing, and a variety of physical and chemical methods have been developed for this purpose.28 29 It should be noted

that the concentrations of heavy metals in

crude shale oil will vary with the location of

the deposit from which the oil is recovered.

Oils from some sites may be relatively free of

such contaminants.

*Some convention:]] (Iru(ics h:)~[’ ({)mpilr[]t)l} h]gh pour

points. For example, the Alt[~mon I crude from Ut:)h hi]s ;{ pour

point Of about 100° F (35° (;).

Refining

of the economic aspects of shale oil utilization, and justified continued efforts aimed at

its recovery. In recent years, refining R&D

has been revived because refiners now consider the availability of shale oil to be a distinct possibility. There is also a need to perform more precise and up-to-date economic

analyses.

To date, refining studies have been conducted on the upgrading of crude shale oil to

a transportable product, and on the total refining of shale oil into finished fuels. The dif-
158 . An Assessment of Oil Shale Technologies

ference between these operations lies in the

nature of the desired final product. As discussed previously, some crude shale oils have

pour points and viscosities that make transporting them difficult and expensive. In some

situations, economic considerations may dictate that the crude shale oil be partially refined (upgraded) near the retorting site to improve its transportation characteristics. In

other instances, a developer may desire to obtain a complete array of finished fuels from

an integrated processing facility located near

the minesite. In this case, a total-refining

facility would be considered rather than a

more simple upgrading plant.

To date, upgrading experiments have been

carried out largely at the bench scale, and

in relatively small pilot plants. Theoretical

studies and computer modeling have also

been used to evaluate the expected performance of three types of upgrading processes:

thermal, catalytic, and additive. Thermal

processes include visbreaking (a relatively

mild treatment) and coking (a severe treatment). Mild thermal treatment will reduce

pour point and viscosity, but the oil will retain

its initial amounts of nitrogen and sulfur. In

contrast, severe thermal treatment reduces

pour point, viscosity, and sulfur content and

also causes the nitrogen compounds to concentrate in the heavier products. The properties of the lighter products will thus be considerably improved.

In catalytic processes, the shale oil is reacted with hydrogen in the presence of a catalyst. Viscosity is reduced, and the nitrogen

and sulfur are converted to ammonia and hydrogen sulfide gases that can be recovered as

byproducts. In additive processes, blending

agents are added that reduce the pour point

and allow the crude to be transported by

pipeline. Such pour point depressants have

been added in several instances with success,

but the technique is not yet highly developed.

Total refining studies have focused either

on the needs of existing refineries that would

have to be modified for processing shale oil,

or on those of newly built facilities that could

be designed specifically for shale oil feedstocks. These studies differ in their approach

to the analysis of refining requirements.

Studies of existing refineries must consider

the equipment that is in place, and must allow

for the limited flexibility of this equipment for

processing a feedstock that is different from

the one for which the refinery was designed.

Studies of specially built refineries, in contrast, need not be biased in this manner, and

can draw upon any processing technique that

is available within the refining industry.

However, both types of studies must make

assumptions about feedstock characteristics

and desired product mixes. These will vary

with the location of the refinery, the nature of

the market it serves, and the type of retorting

facility that supplies its feedstocks. The optimal refining conditions for one set of assumptions will probably not be applicable to

another set. For example, a refining method

to maximize gasoline production from TOSCO

II shale oil would not maximize diesel fuel

production from Oxy’s in situ oil.

Numerous computer studies and benchscale refining investigations have been conducted for a wide range of shale oil feedstocks and operating conditions. The results

of these studies can be extrapolated, with

some degree of caution, to predict the

performance of commercial-scale refineries.

However, refining tests both in pilot plants

and in commercial-scale facilities, because of

much higher costs, have focused on only a

few feedstocks, and have been conducted for

particular sets of operating constraints. In

general, each large-scale study has dealt only

with oil from aboveground retorts or with oil

from in situ operations, but usually not with

both types of feedstocks. The conclusions of

all studies are highly dependent on the combination of feedstock and refining conditions

assumed. Caution must be used when applying the results to different conditions.

Shale Oil Upgrading Processes

The treatment techniques that can be used

to improve the transportation properties of

crude shale oil are briefly described below.
Ch 5–Technology ● 159

Visbreaking

This technique involves heating the crude

shale oil to approximately 900° to 980° F

(480° to 525° C) and holding it at this temperature range for from several seconds to

several minutes. The product is then cooled,

and the gases evolved during the heating are

removed. There is little reduction in the contents of nitrogen, sulfur, and oxygen. Therefore, the principal improvements are reductions in pour point and viscosity. This technique is simple but energy-intensive. It could

reduce the pour point of crude shale oil from

about 850 F to about 400 F (300 to 40 C).30

Coking

This process involves heating the oil to

about 900° to 980° F (480° to 525° C) and

then charging it into a vessel in which thermal decomposition occurs. If the vessel is a

coke drum, the process is called delayed coking. The coke—the solid product from thermal decomposition—is allowed to accumulate

until it fills about two-thirds of the drum’s volume. The feed is then switched to another

drum while the coke is cleaned out of the first

one.

In the fluid coking process, hot oil is

charged into a vessel that contains a fluidized

bed of coke particles. The particles become

coated with oil, which then decomposes to

yield gases and another layer of coke. The

gases are withdrawn from the vessel. The

coke is also withdrawn continuously, at a

rate sufficient to maintain an active stock of

coke within the bed.

The flexicoking process, developed by

EXXON, combines conventional fluid coking

with gasification of the product coke. The advantage is that energy is recovered from the

coke. The process is used in the refining industry, but tests would have to be performed

to determine if it would be suitable for the

coking characteristics of crude shale oil.

Catalytic Hydrogenation

In these processes, the crude shale oil is

reacted with hydrogen in the presence of a

catalyst. The sulfur in the oil is converted to

hydrogen sulfide, the nitrogen to ammonia,

the oxygen to water, the olefin hydrocarbons

to their paraffin equivalents, * and long-chain

molecules to smaller molecules. The hydrogenation reactions can take place in a fixedbed reactor through which a mixture of oil

vapors and hydrogen is passed, in a fluidizedbed reactor, or in an ebulliating-bed reactor.

The latter technique is being promoted by Hydrocarbon Research, Inc., as the H-Oil process. Plants in several foreign nations have

successfully used it for heavy petroleum feedstocks and for residuum fractions from a variety of crudes. In this process, a mixture is

injected into the bottom of a reactor at a high

enough velocity to cause catalyst ebulliation

(a boiling motion). This movement reduces the

possibility that the bed will become plugged

by coke and by the liquid tars that are formed

during the coking process. It also allows spent

catalyst and coke to be removed, and fresh

catalyst to be added, so as to keep the bed actively stocked.

Catalytic hydrogenation produces upgraded products of the highest quality, but it

is relatively expensive. The use of fixed-bed

reactors would probably be confined to the

treatment of streams from an initial fractionation step; fluid-bed or ebulliating-bed

processes could be used for either fractionator products or for the whole shale oil.

‘Olefins are unsaturated (lower ratio of hydrogen to carbon)

hydrocarbon compounds having at least one double bond. They

are the source of synthetic polymers such as polyethylene and

polypropylene used in the manufacture of fibers and other materials. Paraffins are saturated hydrocarbons (equal ratio of

hydrogen to carbon) having only single bonds. Methane,

ethane, propane, and butane are some of the paraffin hydrocarbons.
160 ● An Assessment of 0il Shale Technologies

Additives

Chemicals may also be added to crude

shale oil to improve its transportation properties. Pour point depressants have been successful in some instances, but this does not

mean that they would always work. A chemical that is suitable for one type of oil may not

work at all with oil from another retorting

process. Furthermore, pour point depressants are disadvantageous because they only

change the physical characteristics of the oil

and not its chemical properties. Thus, their

cost can be offset only if they save transportation costs.

Conventional petroleum crudes are other

potential blending agents. Since shale oil (at

least in Colorado) will be produced in an area

that also contains petroleum reserves, and

even active crude oilfields, the possibility exists that the light petroleum crudes could be

mixed with crude shale oil to form a transportable blend. The feasibility of this concept

is unclear because, in general, the blend

would not be as valuable as a refinery feedstock on a per-unit basis as would the petroleum alone. However, the decrease in unit

value would be offset by the increased volume. In the case of a refinery that does not

have a reliable supply of crude, this could be

a significant advantage.

Total Refining Processes

The three primary factors that affect the

design of a refining system are:

. the characteristics of the crude shale oil

feedstock;

● the desired mix of finished products; and

● the constraints imposed by the equipment and operating practices of the proposed refinery.

The first factor probably will have the lowest

effect because, except for the higher nitrogen

and arsenic contents, the characteristics of

crude shale oil are not widely different from

those of conventional petroleum. The second

factor—the product mix—is much more significant. This is evidenced by the changes

that have occurred in the proposed configurations of shale oil refineries since the 1950’s:

the earlier studies placed much more emphasis on gasoline production. For example, early

designs by USBM called for the extensive use

of middle-distillate cracking and reforming to

yield gasoline, The ratio of gasoline to distillate yields was nearly 3 to 1.31 Most of the

refinery configurations that have been proposed more recently indicate a gasoline-todistillate ratio of about 1 to 4.”

The third factor—equipment and operating constraints—has become increasingly important in recent years. The modifications to

convert a conventional refinery to shale oil

feedstocks might not be economically justifiable unless the refiner could be assured of an

adequate supply of shale oil. The economic

desirability of building a refinery specifically

for shale oil would be thoroughly scrutinized.

Modular retorts, or even a few pioneer commercial plants, would not produce enough

shale oil in the mid-term to justify a new refinery unless the refiner was assured that the

operations would continue until his investment cost could be recovered. For this reason, the most recent studies have stressed

modifying existing facilities to make them

suitable for processing shale oil, rather than

building new ones. In some cases, this entails

only minor changes to installed equipment, in

others, the adaptation of an existing facility

by adding new units.

The basic unit operations in crude oil refining are:

● coking,

 hydrotreating,

 distillation,

 hydrocracking,

● catalytic cracking, and

● reforming.

The various refining schemes that have been

proposed for shale oil cannot easily be generalized because, depending on both the desired product mix and the possible operating

conditions, many configurations could be designed that would achieve the same results.

The one selected will largely depend on the
Ch 5– Technology 161

availability of equipment and the individual

economics of the particular refinery.

One significant difference among the various configurations described in the literature

is the relative arrangement of distillation and

thermal or catalytic treatment. Two general

approaches have been investigated:

1. distillation of the whole crude into its

components, then catalytic or thermal

treatment; or

2. catalytic or thermal treatment of the

whole crude, then distillation.

In the first approach the properties of the

finished products are better controlled. In the

second, the net load on successive processing

units is reduced, and, in general, the overall

yield of high-value hydrocarbon products is

increased. Most of the refining research to

date has been focused on the second approach. Three versions are shown schematically in figures 46 through 48. The scheme in

Figure 46.— Refining Scheme Used by the

U.S. Bureau of Mines to Maximize Gasoline

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U.S.A. during pilot-plant runs on Paraho

shale oil,34 had a gasoline-to-distillate ratio of

1 to 4. Both of these systems used an initial

coking step to upgrade the feedstock and to

supply a product stream more easily refinFigure 47. —Refining Scheme Employing Coking

Before an Initial Fractionation, Used by

Chevron U.S.A. in Refining Experiments

I T“ RpJY

SOURCE G L Baughman The Ref(nfng and Markeflrtg of Crude Sha/e 0{/

Figure 48.— Refining Scheme Employing

Initial H ydrotreating, Used by Chevron U.S.A.

in Refining Experiments

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able into finished fuels. The disadvantage of

coking is that there might not be a ready market for coke in the vicinity of the refinery, particularly if it were located in the oil shale region.

Another refining scheme that was investigated by Chevron is shown in figure 47. It

uses a fixed-bed catalytic hydrotreater to upgrade the shale oil before distillation. No coke

is produced because most of the heavier components of the crude shale oil are upgraded

into lighter and more valuable liquid fuels

during the hydrogenation process. This method may be more costly than the coking approach, but that can only be determined by
162 ● An Assessment of Oil Shale Technologies

operating experience and evaluating the economics.

Chevron also investigated the possibility of

substituting a fluidized catalytic cracker for

the hydrocracker in figure 48. A similar approach was used by SOHIO in processing

85,000 bbl of Paraho shale oil at its Toledo

refinery. 35 The chief difference between the

SOHIO runs and the Chevron experiments is

that SOHIO used an acid/clay treatment to

upgrade the distillation products into jet fuel

and marine diesel fuel for military applications. The residuum fraction from the column

was used for fuel in the refinery.

The approach in which the crude oil is

fractionated before hydrogenation or other

treatment is shown in figure 49. This scheme

Figure 49.— Refining Scheme Employing Initial

Fractionation, Used by SOHIO in Prerefining Studies

SOURCE. G L Baughman, The Refining and Market/rig of Crude Shale 0//

was used by SOHIO during the prerefining

studies carried out before 10,000 bbl of Paraho shale oil were refined at the Gary Western

refinery in Fruita, Colo.36 During the actual

refinery run, a combination coker/fractionator was used rather than the separate units

shown in the diagram.

The shale oil must also be treated to remove excess amounts of water, ash, and

heavy metals such as arsenic. Water must be

removed because it can cause cavitation in

pumps and explosions in processing units.

Ash, or particulate matter, must be removed

to prevent its deposition in pipes, heat exchangers, and catalyst beds. Recent studies

have shown that heating the crude oil to

about 165° F (75° C) then letting it stand for

about 6 hours allows the water and solid matter to separate from the oil. As noted, arsenic and other metals poison the hydrotreating

catalysts. A variety of processes have been

developed for their removal; consequently,

their presence no longer presents a technical

problem. ARCO has patented several catalytic techniques and methods for heat treating the oil in the presence of hydrogen. Recent studies by Chevron U.S.A. have shown

that an alumina guard bed preceding the hydrotreater will effectively remove both arsenic and iron from shale oil. 39

The quantity and quality of the fuels produced will be determined by both the configuration of the equipment and the operating

conditions used in the refining step. The fuels

produced by USBM at Anvil Points in the

1940’s were quite satisfactory.’” However,

some of the fuels from the Gary Western refining run in 1975 failed to meet certain military specifications, principally those for stability. 41 This has been attributed to the application of refining techniques unsuitable for

shale oil feedstocks, specifically inadequate

hydrogenation. Subsequent refining tests at

SOHIO’s Toledo refinery show that, with appropriate refining, fuels can be produced that

are of superior quality and that can meet all

applicable specifications. 42

Cost of Upgrading and Refining

The most recent estimates of the cost of upgrading crude shale oil to a transportable refinery feedstock have been prepared by Chevron U.S.A.43 The retorting complex that was

considered had a capacity of 100,000 bbl/d.

Conventional hydrotreating was the upgrading technique evaluated. Chevron considered

two possible locations for the upgrading facility: a newly built unit at the retorting site; and

a unit to be added to an existing refinery at

some distance from the retorts. In both cases,
Ch 5–Technology 163

the estimated cost for upgrading 1 bbl of

crude shale oil was $6.50, in first-quarter

1978 dollars. The product would be a highquality syncrude suitable as feedstock for

most refineries in the United States.

It is more difficult to estimate the costs of

the total-refining option for converting crude

shale oil into finished fuels. This is because in

addition to the properties of the crude oil consideration must be given to the location of potential refinery sites, the availability of refining equipment, the proximity and stability of

potential markets, the ease of product distribution, and other factors. Chevron considered some of these in its analysis of refining

costs, although in a relatively generalized

manner. Three total-refining options and two

refining capacities and refinery locations

were considered. For a l00,000-bbl/d refinery located in an urban area in the Rocky

Mountains (e.g., Denver), the refining cost

was estimated to range from $8.00 to $10.00/

bbl of crude shale oil. For a 50,000-bbl/d

refinery located in a remote area of the Rocky

Mountains (e.g., near the retorting facility),

the refining cost would be approximately

$10.00 to $12.00/bbl.* These are somewhat

higher than the costs for refining a high-quality conventional crude oil because of the additional amounts of hydrogen that would be

needed to reduce the nitrogen content of the

shale oil crude.

Another study compared the cost of shale

oil refining with those of refining Wyoming

sour crude oil and Alaskan crude. It was assumed that a refinery in the Rocky Mountain

region was modified for these feedstocks. The

increased costs to refine crude shale oil,

rather than the other crudes, was in the

range of $0.25 to $2.00/bbl.44 45

*Costs are in first-quarter 1978 dollars.

Markets for Shale Oil

Crude shale oil has three major potential

uses: as a boiler fuel, as a refinery feedstock,

and as a feedstock for producing petrochemicals, The output from a mature oil shale industry will probably be used for all three purposes. However, the relative importance of

the three markets will change with time as

the industry develops. In the mid-1980’s,

when shale oil first becomes available in significant amounts, its most likely use will be as

boiler fuel, with only a small quantity directed to nearby refineries that could be modified to accommodate the feedstock without

large capital expenditures. As more shale oil

becomes available, its use as a refinery feedstock will increase as conventional petroleum

becomes scarcer. At a later date, when the

market for boiler fuels declines, shale oil will

begin to be used for petrochemical production.

Shale Oil as a Boiler Fuel

Shale oil will most likely first be used as a

boiler fuel because of the relatively small

capital investments and very short leadtimes

that would be required. Because of Government regulation, the current trend in the utility industry is to replace oil- and gas-fired

boilers with coal-fired units, thus freeing the

natural gas for domestic consumers. In some

areas, it will be a two-stage transition, with

the gas first replaced by oil, and the oil later

by coal. During the transition, there maybe a

market for about 50,000 to 80,000 bbl/d of

crude shale oil near the oil shale region. In

addition, the refining industry has a small but

significant demand for boiler fuel because refineries are also changing from natural gas to

oil. Therefore, refineries located near the oil
—

164 ● An Assessment of 011 Shale Technologies

shale region are likely to be near-term shale

oil customers. In the long run, the largest

market for shale oil boiler fuel is likely to be

in the Great Lakes States. Transportation distances will probably preclude its use in the

other two major markets for boiler fuels—the

east and west coasts.

Shale Oil as a Refinery Feedstock

There has been relatively little research on

the refining of crude shale oil because building an oil shale plant takes about 5 to 7 years,

whereas a refinery operator can evaluate a

new potential feedstock in a few days, develop a feasible refining strategy within a matter of weeks, conduct the necessary pilotplant refining studies in a few months, and

modify the refinery to accommodate the new

feedstock in less than 3 years. Thus, neither

the developer nor the refiner has any inducement to study shale oil refining until they are

sure that the oil will, in fact, be forthcoming.

Another reason is that until quite recently,

shale oil was not considered a highly desirable refinery feedstock. During the 1950’s

and 1960’s, the refining industry tended to

maximize gasoline yields at the expense of

middle and heavy distillates. Because shale

oil is a good source of heavier distillates, not

of gasoline, it was not highly regarded. However, most projections indicate that gasoline

demand will peak in the early 1980’s and then

decline slightly, even though total demand for

refined products will continue to grow.46 This

will be the result of the increasing efficiencies of gasoline engines in automobiles and of

a greater use of diesel engines in automobiles

and light trucks. Also, because the current

supplies of conventional petroleum are becoming more like shale oil with respect to

their distillate yields, the refining industry is

being forced to adopt techniques that would

be equally suitable for shale oil.

For these reasons, shale oil’s desirability is

increasing, and its potential availability as a

premium feedstock has encouraged the refining studies that have been conducted by

Chevron and other organizations. These studies have dealt with four general types of

refining facilities:

1.

2.

3.

4.

The

a new refinery just for shale oil;

a new refinery for a mix of shale oil and

conventional crude;

an existing refinery modified for, and

dedicated to, shale oil; and

an existing refinery processing a mix of

shale oil and conventional crude.

first two approaches are precluded for

the foreseeable future because, as long as refined products continue to be imported, the

United States will have excess refining capacity. At least through the 1980’s, shale oil

will most likely be refined in existing refineries, either by itself or as a blend with conventional petroleum,

The shale oil produced by demonstration

facilities will probably be processed in local

refineries* or in more distant refineries

owned and operated by the energy companies

that participate in the oil shale programs.

The much larger output from a commercialize industry will be more widely distributed;

thus it will have to compete with other feedstocks, at least regionally. Recent studies

have indicated that the Midwest is the most

likely market area for large quantities of

shale oil. This includes the States in the Petroleum Administration for Defense District 2

(PADD 2), as shown in figure 50. There will

be secondary effects in other districts, as a

consequence of the supplies of shale-derived

fuels in PADD 2, because the conventional petroleum that it displaces will become available for use elsewhere.

The quantitative impact on the supply

situation in PADD 2 can be determined by refering to table 20, which indicates how the

district’s supplies of finished fuels were divided among domestic and foreign sources in

1978. As shown, the district consumed about

518,000 bbl/d of medium and heavy distillates

(jet fuels, diesel fuel, and distillate fuel oil)

from foreign sources. According to Chevron’s

*’I’hese could include the Gary Western refinery in Fruita,

Colo., the Little America refinery in Rawlins, Wyo., the Chevron refinery in Salt Lake City, Utah, ond others.
Ch 5–Technology ● 165

Figure 50.— The Petroleum Administration for Defense Districts

Includes Alaska

and Hawaii

SOURCE Natmna/ At/as, Department of the Intenor

Table 20.–Supply of Finished Petroleum Products in PADDs 2, 3, and 4 in 1978 (thousand bbl/d)a

PADD 2 Midwest PADD 3 Texas and New Mexico PADD 4. Rocky Mountains —

Foreign Domestic Foreign Domestic Foreign Domestic

sources sources Total sources sources Total sources sources Total

Gasoline. 976 1,540 2,516 422 604 1,026 33 219 252

Light ends 224 236 460 276 388 664 12 25 37

Jet fue l 81 131 212 50 71 121 7 29 36

Kerosine 17 27 44 19 27 46 0 2 2

Distillate fuel oi l 420 672 1,092 194 279 473 13 113 126

Residual fuel 011 150 173 323 237 340 577 4 38 42

Petrochemical feedstocks. 18 26 44 211 298 509 0 1 1

Special naphthas and still gas 60 98 158 114 165 279 2 14 16

Other s 138 232 370 102 146 248 4 31 35

Total 2,084 3,135 5,219 1,625 2,318 3.943 75 472 547

ap,ADO = pe/rOleum ,4dmlfllSlfa10fl tor Defense Dlstrlcl

SOURCE G L Baughman The Refmmg and Markef~ng of Crude Sha/e 01/

studies, refining will convert about 74 per- tricts. The same size industry would produce

cent of a crude shale oil feedstock to similar about 170,000 bbl/d of gasoline, which would

distillates.” A l-million-bbl/d industry would be equivalent to about 17 percent of the disyield about 740,000 bbl/d of medium and trict’s gasoline currently obtained from forheavy distillates. If it were marketed in PADD eign sources.

2, this production would completely displace

the foreign supplies and free an additional An alternative marketing strategy would

222,000 bbl/d of the fuels for use in other dis- be to sell the output from a major shale oil in-
166 ● An Assessment of 011 Shale Technologies

dustry in PADD 4—the Rocky Mountain region—and to supply any surplus fuels to adjacent districts such as PADD 2 or PADD 3

(Texas and New Mexico). As shown in table

20, the Rocky Mountain district consumes relatively little distillate fuel (about 20,000

bbl/d) from foreign sources. A l-million-bbl/d

shale oil industry could easily displace this

entire supply. The surplus production (about

720,000 bbl/d) could displace about 95 percent of the supply of foreign-derived distillates in both PADD 2 and PADD 3. The gasoline derived from the shale oil could supply

about 67 percent of the total gasoline demand

in the Rocky Mountain States.

As indicated previously, the capabilities of

the refineries in the Midwest and the Rocky

Mountain States will strongly affect the willingness of the refiners to accept shale oil

feedstocks. In some cases, shale oil could not

be accommodated without significant investments of capital. However, the receptivity of

refiners to shale oil will also be influenced by

the reliability of other feedstocks such as foreign petroleum. The area in which the supplies of crude are most uncertain is the northern tier of States, which includes Montana,

North and South Dakota, Minnesota, and

Wisconsin. These States have historically depended on refinery feedstocks from Canada,

but, in recent years, a significant reduction in

these supplies has led the refiners in this

area to look elsewhere. The result has been

the present interest in building a pipeline to

transport crude from Alaska and from foreign nations into the area. An alternative—a

pipeline from the oil shale region—could also

be built as the oil shale industry developed.

The area that covers Iowa, Missouri, Illinois, Indiana, Michigan, and Ohio also does

not have an adequate indigenous supply of

crude. However, unlike the northern tier,

these States have good pipeline systems with

adequate access to both foreign and domestic

crude supplies. The feasibility of marketing

shale oil in this area will largely be determined by the cost differential between it and

other crude supplies and by the differences in

the reliability of its supply versus that of

foreign crude. Recent marketing studies have

identified several large refineries in this area

that, with only minor modifications would be

able to handle crude shale oil. 48 Furthermore,

some of the refineries only have access to the

heavier petroleum crudes at present, and

their production is being limited by their capacity to process the large quantities of residuum from the distillation of these fuels. Shale

oil, with its relatively small yield of bottoms

fractions, would help alleviate this problem.

Shale Oil as a Petrochemical Feedstock

Three principal factors must be considered

in evaluating the suitability of shale oil supplies for producing petrochemicals:

● the yields of petrochemicals from shale

oil feedstocks;

 the ability of existing and future petrochemical plants to process the shale oil;

and

● the logistics of supplying the shale oil to

the plants.

Because shale oil is produced by pyrolysis, its

olefin content is approximately 12 percent,

which is appreciably higher than conventional crudes. Together with its fairly high hydrogen content, these characteristics make shale

oil, and its hydrogenated derivatives, appropriate feedstocks for petrochemical production.” 50 Steam pyrolysis has been used to

process crude shale oil, and the yields of

olefin products have been comparable with

those from many conventional crudes. Shale

oil syncrudes, with even higher olefin yields,

are considered to be premium petrochemical

feedstocks. These conclusions are based on

laboratory studies under carefully controlled

conditions. The feasibility of marketing shale

oil to the petrochemical industry depends on

the ability to replicate these conditions in

commercial chemical plants.

Historically, the primary feedstock for petrochemical plants has been natural gas liquids from the gulf coast. Because crude shale

oil is quite different from these liquids, it

would be difficult to switch traditionally de-
Ch 5–Technology ● 167

signed petrochemical plants to shale oil. However, the production of domestic natural gas

and its associated liquids is declining, and the

petrochemical industry is shifting to heavier

feedstocks such as naphtha and gas oils. The

supplies of these feedstocks are uncertain

and irregular. The availability of naphtha has

been affected by a growing demand for its

use as a gasoline blending agent in response

to the phasing out of tetraethyl lead. Gas oils

are also being used more frequently for home

heating fuels, which causes seasonal variations in their availability. Because of these

supply uncertainties, new petrochemical

plants are being designed to be highly flexible

with respect to feedstocks. As using heavier

feedstocks becomes more common in the industry, shale oil may become a highly regarded raw material.

The use of shale oil for petrochemical production is hampered by the distance between

the oil shale region and the petrochemical

plants. While refineries and oil-fired boilers

are distributed fairly uniformly across the

United States, the petrochemical industry is

concentrated on the gulf coast. This concentration will continue into the foreseeable future. Therefore, it will be necessary to either

move the shale oil to the coast, or to build

a new petrochemical complex in the Rocky

Mountain region. In the latter case, the halffinished products from the new plant would

still have to be transported to the coast for

final conversion to commercial chemicals.

The former approach is more likely but is impeded by the lack of a product pipeline system between the oil shale region and the gulf

coast, and by the high cost of alternative

modes of transportation.

In summary, tests have shown that crude

shale oil and its derivatives could be used to

produce petrochemicals. However, these materials cannot be considered to be viable feedstocks in the near future because existing

chemical plants are generally unable to process them and there is ‘no economical transportation link between the oil shale region and

the existing petrochemical plants.

Issues and Uncertainties

The technological readiness of the major

mining and processing alternatives is summarized in table 21. Estimated degrees of readiness are shown as judged by DOI in 1968,51

and as they appear under present conditions.

There are significant differences between the

two evaluations because much R&D work has

been conducted in the interim, and because

two new processing methods—MIS retorting

and concurrent recovery of associated minerals—have since entered the picture. As

shown, room-and-pillar, open pit, and MIS

mining methods are regarded as reasonably

well-understood. Open pit mining has not

been tested with Green River shales, but it is

highly developed for other minerals such as

copper and iron ores. It was evaluated on

paper for application to the shales on tract

C-a. Some highly relevent experience has

been obtained from the operation of largescale lignite (a form of coal) mines in West

Germany. 5z In these operations, the lignite is

covered by 900 ft of overburden, and stripping operations will soon extend to 1,600 ft.

This is comparable to the oil shale deposits,

which are covered by a maximum of about

1,800 ft of overburden.

Nevertheless, uncertainties remain with

respect to the effects of shale stability and

strength on mine design, mine safety, and resource recovery. The effects of large inflows

of ground water, such as have been encountered on tract C-a, could pose severe operational difficulties, especially with underground mines. In all mines, the logistics associated with moving many thousands of tons of

raw material and solid wastes could present

some formidable problems. Materials-handling systems exist that could be applied, but

they have yet to be tested in commercial oil

shale operations.
—. .

168 An Assessment of Oil Shale Technologies

Table 21 .–Technological Readiness of Oil Shale Mining, Retorting, and Refining Technologies

Technological readiness

Unit operation In 1968 In 1979 Developments in the Interim Remaining areas of uncertainty

Mining

Room and pillar

M I S

Open pi t

Othe r

Retorting

Abovegroun d

T I S

M I S

Multimineral

Upgrading and

refining. . . . . . . . .

Medium

Unknown

Low

Low

Medium

Low

Unknown

Unknown

High

Medium

Medium

Medium

Low

Medium

Low

Medium

Medium

High

SOURCE Ofhce of Technology Assessment

Mine design studies. Experience of Colony,

Mobil, and the six-company program at Anvil

Points

Oxy experience at Logan Wash Mine design

studies.

Established procedure for other minerals

Large-scale mines in West Germany. Mine

design studies for tract C-a,

Mine design studies No field experience

Pilot studies for Lurgi-Ruhrgas Semiworks

programs by Colony and Paraho Detailed

designs by Colony and Union.

Field work and lab tests by USBM. Field tests

by Equity, Geoknetics, and Talley-Frac.

National lab support

Oxy experience, Design studies for tracts C-a

and C-b. DOE and USBM design studies

Modeling and lab support by national

laboratories.

Pilot plant studies by Superior USBM lab

tests of product recovery methods. Nahcolite

scrubbing tests.

Studies and refinery runs by SOHIO/Paraho,

Chevron, and others. Marketing analyses

by Oxy and DOE.

AGR is regarded as having a medium level

of readiness, as it was in 1968. The understanding of its technical aspects has been improved since then by field tests in the Piceance basin, but the largest tests conducted to

date have been at the semiworks scale—

about one-tenth of commercial size. Their results do not permit accurate cost projections

for commercial-scale plants. Particular problems are noted with respect to the effect of

scaling up the semiworks design to commercial size. The on-stream factor—the fraction

of the time that the retorts could be expected

to operate at design capacity—is unknown.

The reliability of some associated systems

(emissions controls, product recovery devices, materials-handling equipment) is also

questionable.

Rock mechanics Ground water Deep shales

Logistics.

Rock mechanics Ground water Deep shales

Logistics

Rock mechanics Logistics Reclamation

All areas

Effects of scaleup on stream factor and recovery. Characteristics of emissions streams

Reliability of peripheral equipment Materials

handling.

Stream factor and recovery. Characteristics of

emissions streams Rock mechanics Deep

shales.

Effects of scaleup on stream factor and recovery Characteristics of emissions streams

Reliability of peripheral equipment Use of

low-Btu gas Rich shales. Mixed shales,

Fracturing Rock mechanics Deep shales,

Effects of scaleup on stream factor and recovery Characteristics of emissions streams

Reliability of peripheral equipment, Materials

handling Integration of recovery steps

Underground waste disposal Marketability

of byproduct minerals.

Effects of retorting conditions on crude

characteristics Cost effectiveness of alternate processes Use of pour point

depressants Effects of metals

Although understanding has increased

since 1968, TIS must still be regarded as

being in the conceptual stage. Many uncertainties remain, especially with respect to

economics and environmental effects.

MIS retorting, a new concept since 1968,

has advanced to a medium level of technological readiness, approaching that of above-

-ground retorts. This progress is largely a result of Oxy’s development efforts in Colorado,

but additional understanding has been obtained through simulations by USBM, DOE,

and the national laboratories, most notably

the Lawrence Livermore and Los Alamos

Laboratories. The remaining uncertainties

are similar to those for aboveground retorts,

except the materials-handling problems may
Ch 5–Technology ● 169

be less substantial with MIS methods. The

major uncertainties relate to the use of the

large quantities of low-Btu retort gas for power generation and to the application of the

technique to very rich or very deep shales.

The multimineral concept was also largely

unknown in 1968, although the presence of

sodium minerals was recognized. At present,

the aboveground system of Superior Oil is regarded as having medium technological readiness. Its uncertainties are much the same as

for other AGR methods, with the addition of

the potential difficulties with integrating the

systems for recovering mineral byproducts

with those for recovering oil and gas. The

marketability of the nahcolite, soda ash, and

alumina has also not been well-established.

The MIS concept proposed by Multi Mineral

Corp. is not specifically evaluated in the

table. It would share the same uncertainties

as conventional MIS, with additional potential problems introduced by the need to

evacuate a large underground retort, and because the oil shale resource is deeply buried.

Upgrading and refining systems were given

a high rating in 1968, which has been improved by additional study. No major problems are anticipated, although more needs to

be known about the feasibility of using pour

point depressants, the effects of retorting

conditions on the characteristics of the crude

oil, and the effects of metals (such as arsenic)

on refining catalysts. The major uncertainty

in the distribution area—the existence of an

adequate pipeline system to the most likely

markets—is not directly related to the nature

of the refining technology and is therefore not

indicated.

It should be noted that mining and retorting

(the major subprocesses having only medium

levels of technological advancement) require

only about 35 percent of the capital investment that is needed to establish an AGR complex. The remaining 65 percent is distributed

among upgrading units, byproduct recovery

systems, utilities, sidewalks, and other wellestablished items. Yet developers hesitate to

commit themselves to oil shale plants. The

reasons given are an uncertain regulatory

climate, an uncertain future for the price of

conventional petroleum, and the fact that all

of the components of a facility must work as

designed—not just the well-established ones.

With the present state of technological

knowledge, it is not clear that an oil shale

plant would perform as desired, nor that the

oil would be sufficiently cheap to compete

with its currently designated competitor—imported petroleum. Even though the future of

oil shale looks brighter, few companies are

willing to build large-scale plants immediately. They prefer to follow conventional engineering practice by proceeding to an intermediate step—the so-called modular demonstration retort.

The modular retort is the smallest unit that

would be used in commercial practice, A commercial-size oil shale facility would use several of these retorts in parallel to obtain the

desired production rate. The capacity of a

module varies with the developer. For Oxy, a

modular MIS retort might have a capacity of

only a few hundred barrels per day of shale

oil; a commercial facility would have several

dozen of these retorts operating simultaneously in modular clusters, each producing

several thousand barrels per day. A modular

Lurgi-Ruhrgas retort would have a capacity

of about 2,200 bbl/d. One or two such units

might suffice for the mined shale from an MIS

operation; a facility that used only AGR might

need a dozen comparable units. A commercial-sized plant that used Paraho retorting

might have seven or eight individual retorts,

each producing 7,300 bbl/d. A comparable

plant might use seven Union “B” retorts, each

producing about 9,000 bbl/d. Colony prefers

to bypass the modular demonstration phase

and to proceed directly to a commercial-size

facility, claiming that the TOSCO 11 technology is ready to be scaled up to such a capacity

for demonstration purposes.

Regardless of these differences, the several “next steps” that are proposed by the

developer’s have two points in common: the

production units must be large enough to simulate actual commercial practice, and the

equipment must be operated long enough to

obtain reliable data on its performance under

a complete spectrum of operating conditions.
170 . An Assessment of Oil Shale Technologies

R&D Needs and Present Programs

R&D Needs

Mining

Room-and-pillar mining and mining in support of MIS operations have been tested with

oil shale, and an extensive body of information has been assembled. To date, however,

all of the field tests have been conducted in

one area—the southern fringe of the Piceance basin. In each case, the deposit was

reached through an outcrop along a stream

course. The limited area in which mining

tests have been conducted is unfortunate because the characteristics of deposits in other

areas are quite different. They may be more

or less favorable to mine development. For

example, there is little ground water in the

southern fringe. In contrast, the deposits on

tracts C-a and C-b, nearer the basin’s center,

lie within ground water aquifers, and the inflow of water into the mine shafts has been a

problem on tract C-a. Similar problems were

encountered at the USBM shaft in the northern part of the basin. Work on this site was

also impeded by the presence of highly fractured zones, which are not common on the

southern fringe.

Similar surprises could be avoided in future projects if the suitability of the candidate mining techniques for developing deposits throughout the oil shale region were better

understood, especially in these areas where

near-term development is likely. This information could be obtained through coring and

rock mechanics studies, mathematical simulation, and experimental mining. Field testing

of mining methods would be expensive,

although overall costs could be minimized

through developing a single site that could be

used to test many mining alternatives. A

single shaft or adit, for example, could be

used to test room and pillar, longwall, block

caving, and other methods. It should be noted

that open pit mining, because of the necessity

for costly and large-scale operations, would

probably not be amenable to testing in a limited field program.

TIS Retorting

TIS is the most primitive of the processing

methods. It has some potentially valuable features but these cannot be evaluated because

of a lack of information. The potential impacts on surface characteristics and ground

water quality are especially unclear. The

R&D needs include:

●

●

●

●

●

●

●

●

development of less expensive drilling

techniques;

development of efficient and cost-effective fracturing and rubbling techniques;

development of methods for determining the success of a rubbling program

through, for example, surveys of the permeability increase that has been

achieved;

development of ignition methods and of

methods for maintaining a uniform burn

front;

study of the effects of heat-carrier composition, rate of injection, and temperature on product recovery;

study of the effects of creep* on retort

stability and product recovery;

determination of the effects of ground

water infiltration on retorting; and

evaluation of the long-term potential for

surface subsidence.

Valuable information is being obtained in the

Equity and Geokinetics projects, but these results are applicable only to specific types of

oil shale deposits—the Equity process to

shale in the Leached Zone; the Geokinetics

method to thin, shallow beds. Additional field

work in other types of deposits would aid in

evaluating the potential of TIS methods for

large-scale production. To minimize the cost

and duration of these tests, they could be supplemented with initial theoretical studies and

laboratory programs.

*Creep is the gradual change in the shape of a solid object induced by prolonged exposure to stress or high temperatures.
Ch 5–Technology ● 171

MIS Retorting

MIS is more highly developed, but more

testing is needed before its potential application to other areas of the Green River formation can be determined. The R&D needs are

similar to those for TIS. They are:

●

●

●

●

●

●

the development of better rubbling techniques;

the development of improved remote

sensing procedures for permeability,

fluid flow, and temperature;

the development of methods for creating

and maintaining a better burn front;

evaluation of the effects of heat-carrier

characteristics;

evaluation of the effects of creep and

subsidence; and

examination of the effects of ground

water infiltration, retort geometry, and

particle-size distribution.

Many of these needs will be addressed in the

MIS programs on tracts C-a and C-b and the

USBM shaft.

Aboveground Retorting

Several candidate retorting processes

have been tested in Colorado, but only for

relatively short periods, and in small-scale

facilities, More R&D is needed, and particular emphasis should be given to:

evaluating the effects of scaleup on the

flow patterns of solids and fluids within

the retort vessel;

determining the reliability and effectiveness of peripheral equipment such

as solids-handling systems, pollution

controls, and product separators;

examining the effects of heat-carrier

characteristics on product recovery and

equipment reliability; and

determining the reliability of mechanical

components such as Union’s rock pump;

Tosco’s retort vessel, separation trommel, and ball elevator; the Lurgi-Ruhrgas

screw conveyor; and the raw shale distributors and spent shale discharge

grates of all retorts that use gas as a

heat carrier.

Some of these needs could be addressed by

further laboratory-scale and semiworks testing. Others could be estimated by theoretical

calculations and modeling. All of them and especially the need for reliability studies, will

eventually have to be addressed in full-scale

retorting modules, either alone or as part of a

commercial-size complex.

Upgrading, Refining, and Distribution

Because crude shale oil is sufficiently

similar to conventional petroleum crude, no

substantial problems are anticipated in the

refining area. R&D on the effects of heavy

metals on refining catalysts and of retorting

conditions on oil properties could be conducted in the laboratory, provided that retorts were operating that could supply a product resembling the crude oil that will be produced in commercial operations,

In the upgrading area, the major need is related to the feasibility of using chemical additives to depress the pour point of crude shale

oil. The necessary R&D could be conducted in

the laboratory or in a pilot refinery, again

assuming the availability of a representative

crude shale oil.

R&D is also needed to determine the optimum distribution pattern for the finished

fuels, which will vary with the size of the industry, the location of the facilities, the need

for various fuels and feedstocks, and the

availability of a transportation system. R&D

is needed to determine optimal plans for likely combinations of these factors. Work has

begun in this area, and more work could be

conducted at relatively low cost, since it is

theoretical rather than experimental in

nature. However, it will not be possible to

define an optimum pattern for the actual

future industry until the sites of the production facilities are designated.

The System

All manufacturing and processing plants

potentially suffer from a lack of systems reliability. Because of the scale of operations and

the need for the coordinated performance of
.—. .—.— — .

172 An Assessment of Oil Shale Technologies

many components, it is certainly possible that

oil shale plants will have significant problems. On the other hand, they may not be

more severe than in other, more conventional

industries. R&D programs, such as mathematical simulations and industrial engineering studies, would help to eliminate some of

the uncertainties regarding the expected performance and reliability of oil shale systems.

Basic data on the lifetimes of equipment,

operating characteristics, and other factors

could be obtained from those minerals processing and refining plants that oil shale facilities will resemble. However, because of the

unique character of oil shale operations, predictions from these studies will be tentative.

It will only be possible to define performance

characteristics after large-scale oil shale

plants are operated at their maximum production capacities.

Present Programs

Some of the current R&D programs for

individual retorting technologies were described previously. An effort that has not

been discussed in detail is DOE’s integrated

research, development, and demonstration

program for oil shale.53 Its major objective is

to provide the private sector with the technical, economic, and environmental information needed to proceed with the construction

of pioneer commercial plants. Its specific

goals are:

● by mid-1981: to provide technical designs, cost data, and environmental information for construction and operation of at least one AGR module;

● by 1982: to design at least one commercial-size MIS retort that could be used on

the Federal lease tracts or in other locations; and

● by 1985 to 1990: to remove the remaining

technical uncertainties that impede commercial-scale use of the alternate technologies in the various types of oil shale

deposits.

In situ processing has been given the major

emphasis throughout the program, and much

of the technical R&D will be conducted in the

“Moon Shot” project that will address the

second goal. Initial support of AGR will focus

on designing the retort module and on surface

and underground mines to support single

plants and an industry of 1 million to 3 million

bbl/d. The decision to proceed with construction of AGR modules will be determined by

the economic outlook for shale oil in

mid-1980. DOE will consider a cost-shared

program if industry has not announced firm

plans to proceed without Federal participation. The program will also include resource

characterization studies that will help to

delineate the portions of the oil shale basins

where the different types of development

technologies would be most applicable. Other

studies will include assessments of air,

water, land, and socioeconomic impacts; of

occupational safety and health; and of methods for increasing the efficiency of water use.

These efforts should substantially advance

the understanding of the technological aspects of oil shale development. The budget of

over $387 million for fiscal years 1980

through 1984 should be adequate to address

most of the R&D needs identified in the previous section. This budget includes about $126

million for developing and operating a commercial-scale MIS retort, and half of the estimated $200 million cost of an AGR module. 54

The demonstration facilities are especially

important to the acquisition of firm engineering and economic data. Unfortunately, only

one in situ technology and one aboveground

retort will be tested, and it will be difficult to

evaluate fully the effects of resource characteristics on the feasibility of alternate mining

methods.
Ch 5–Technology ● 173

Policy Options

R&D

Some of the remaining technical uncertainties could be alleviated with additional smallscale R&D programs. These could be conducted by Government agencies or by the private sector, with or without Federal participation. If full or partial Federal control is desired, the programs could be implemented

through the congressional budgetary process

by adjusting the appropriations for DOE and

other executive branch agencies, by providing additional appropriations earmarked for

oil shale R&D, or by passing new legislation

specifically for R&D on oil shale technologies.

Demonstration

Full-scale demonstrations will be needed to

accurately determine the performance, reliability, and costs of development systems under commercial operating conditions. In general, potential developers would prefer to follow conventional engineering practice and

approach commercialization through a sequence of increasingly larger production

units. Union, Colony, and Paraho have progressed through this sequence to the semiworks scale of operation—about one-tenth of

commercial size.

If this conservative approach were continued, the next step would be a modular

demonstration facility. Although such a plant

would cost several hundred million dollars, it

would provide the experience and the technical and economic data needed to decide on

the commitment of much larger sums to commercial-scale operation. Union has expressed

its preference for this path; Rio Blanco and

Cathedral Bluffs are following it. Colony regards a pioneer commercial plant as the best

facility for proving the TOSCO II technology.

The two general approaches to funding

such demonstration programs are discussed

below. Selecting an option will depend on the

desired balance between information generation and dissemination, Federal involvement,

timing of development, and cost.

Private Funding

If left alone, the industry would develop in

response to normal market pressures and opportunities, and the Government’s expense

and involvement would be minimized. However, the Government would not be assured of

access to the technical, economic, and environmental information that it needs to formulate future policies and programs, although

some of this information could be obtained

through third-party reviewers or through licensing arrangements. Another disadvantage

is that industry may not risk even the relatively modest investment of a modular program

until economic and regulatory conditions

clearly favor development. For example,

Union and Colony have announced that they

will not proceed until Federal incentives are

provided and regulatory impediments removed. Industry may eventually proceed, but

perhaps not in time for the resource to contribute substantially to the Nation’s fuel supplies within the next decade.

Government Support

The alternatives are full Government funding of demonstration facilities, indirect funding through incentives to industry, and a

sharing of the costs with industry. The options are discussed in detail in chapter 6 and

summarized in chapter 3. In brief, Federal

ownership would provide the Government

with the maximum amount of experience and

information. It would also maximize Govern-
174 ● An Assessment of Oil Shale Technologies

ment intervention and the commitment of

public funds, and it might discourage private

developers from proceeding with independent demonstrations. Also, industry and Government would design, finance, and operate a

demonstration project in very dissimilar

ways. The Federal experience with a Government-owned facility may have little relevance

to the problems that would be encountered by

a private developer with the same production

goal, The Government’s experience would

therefore provide little guidance for evaluating oil shale as a private investment opportunity.

Incentives programs could involve tax

credits, purchase agreements, price supports, or other types of support, either singly

or in combination. They could be structured

to encourage the participation of specific

types of firms and could be combined with

regulatory changes, and possibly land exchanges or additional leasing, to control both

the growth and the nature of the ultimate

commercial industry. They would cost less

than Government ownership. They would also

tend to provide the Government with less information and with no operating experience.

However, disclosure requirements could be

inserted into the leases or the incentives legislation as a prerequisite for project eligibility y.

The cost sharing of demonstration facilities

would entail intermediate expenditures of

public funds and intermediate levels of information. The receptivity of industry to such

proposals would depend on how much the

Government would intervene in designing and

operating the projects. If industry responded,

the Federal investment that would be needed

for a single Government-owned plant could be

spread over several projects, thereby increasing the total amount of information generated.

Program Alternatives

Demonstration will require designing,

building, and operating full-size production

units, either as separate modules or incorporated in pioneer plants.

A single module on a single site.—This option would provide comprehensive information about one process on one site. Either

underground or surface mining experiments

could be performed, but probably not both.

The costs would be small overall but large on

a per-barrel basis, because there would be no

economies of scale. Some of the shale mined

could be wasted because the single retort

might not be able to process all of it economically. If the site could subsequently be developed for commercial production (e. g., a private tract, a potential lease tract, or a candidate for land exchange), the facility would

have substantial resale value. Otherwise, it

would be valuable only as scrap.

Several modules on a single site.—This

program might consist of an MIS operation,

coupled with a Union retort for the coarse

portion of the mined oil shale and a TOSCO II

for the fines. As with the single-module option, either surface or underground mining

could be tested, depending on the site, or

possibly both if the plant had a sufficiently

large production capacity. The total costs

would be larger than for the single-module

program, but unit costs would be lower. For

example, a three-module demonstration plant

would cost about 2. I times as much as a

single-module facility; a six-module plant

about 3.7 times as much. Different technologies could be combined to maximize resource utilization, and detailed information

could be obtained for each. However, all of

the information would be applicable to only

one site. If many modules were tested, the

demonstration project would be equivalent to

a pioneer commercial plant, except that a

true pioneer operation would probably not

use such a wide variety of technologies.

Single modules on several sites.—Several

technologies might be demonstrated, each at

a separate location. For example, an underground mine could be combined with a

TOSCO II retort on one site; a surface mine

with a Paraho retort at another. Total costs

could be large, as would unit costs, which

would be comparable with those of the single-
Ch. 5–Technology 175

module/single-site option. The principal advantage would be that different site characteristics, processing technologies, and mining

methods could be studied in one comprehensive program.

Several modules on several sites.—For

each site, a mix of mining and processing

methods would be selected that would be

most appropriate for the characteristics of

the site and the nature of its oil shale deposits. The maximum amount of information

would thus be acquired, in exchange for the

maximum amount of investment. Each project

would resemble the several-module/singlesite option; the collection would constitute a

pioneer commercial-scale industry.

Chapter 5 References

‘T. Ertl, “Mining Colorado Oil Shale, ” Quarterly of the Colorado School of Mines, vol. 69, No. 3,

July 1965, pp. 83-92.

ZRio Blanco oil Shale Project, ~etailed ~eVe~oPment Plan: Tract C-a, Gulf Oil Corp. and Standard

Oil Co. (Indiana), March 1976, pp. 7-2-1 to 7-2-20.

‘J. B. Miller, President of Rio Blanco Oil Shale

Co., letter to G. Martin, Assistant Secretary for

Land and Water Resources, Department of the Interior, Oct. 26, 1979.

‘U.S. Energy Outlook—An I~terim Report, The

National Petroleum Council, Washington, D, C.,

1972.

‘H. E. Carver, “Oil Shale Mining: A New Possibility for Mechanization, ” Quarterly of the Colorado School of Mines, vol. 60, No. 3, July 1965.

“J. J. Reed, “Rock Mechanics Applied to Oil

Shale Mining,’” Quarterly of the Colorado School

of Mines, vol. 61, No. 3, July 1966.

‘R. O. Bredthauer and T. N, Williamson,

“Mechanization Potential in Oil Shale Mining, ”

Quarterly of the Colorado School oj Mines, vol. 61,

INO. 3., July 1966.

8P. T. Allsman, “A Simultaneous Caving and

Surface Restoration System for Oil Shale Mining, ” Quarterly of the Colorado School of Mines,

vol. 63, No. 4, October 1968.

‘W. N. Hoskins, et al., “A Technical and Economic Study of Candidate Underground Mining

Systems for Deep, Thick Oil Shale Deposits, ”

Quarterly of the Colorado School of Mines, vol. 71,

No. 4, October 1976, pp. 199-234.

‘“C. E. Banks and B. C. Franciscotti, “Resource

Appraisal and Preliminary Planning for Surface

Mining of Oil Shale, Piceance Creek Basin, Colorado,” Quarterly of the Colorado School of

Mines, vol. 71, No. 4, October 1976, pp. 257-286.

IIJ. H. East and E, D. Gardner, “Oil Shale Mining, Rifle, Colorado, 1944 -1956,” Bulletin 611, U.S.

Bureau of Mines, 1964.

‘2P. W. Marshall, “Colony Development Operation Room-and-Pillar Oil Shale Mining, ” Quarterly

of the Colorado School of Mines, vol. 69, No. 2,

April 1974, pp. 171-184,

“C-b Shale Oil Project, Detailed Development

Plan and Relatea’ Materials, Ashland Oil, Inc., and

Shell Oil Co,, February 1979, p. IV-2.

“Oil Shale R, D, & D—Program Management

Plan, Department of Energy, Washington, D. C.,

June 25, 1979, p. C-3.

151bid.

‘

b

Ibid., p. C-2.

“Ibid.

18R. D. Ridley, “Progress in Occidental’s Shale

Oil Activities,” Eleventh Oil Shale Symposium Proceedings, Colorado School of Mines Press, Golden,

Colo., November 1978, pp. 169-175.

“D. R. Williamson, “Oil Shales: Part 5—Oil

Shale Retorts, ” Mineral Industries Bulletin, vol. 8,

No. 2, March 1965.

‘(’J. L, Ash, et al., Technical and Economic Study

of the Modified In Situ Process for Oil Shale, report prepared for the U.S. Bureau of Mines by Fenix and Scission, Inc., under contract No.

SO241O73, November 1976.

“J. H, Campbell, et al., “Dynamics of Oil Generation and Degradation During Retorting of Oil

Shale Blocks and Powders, ” Tenth Oil Shale Symposium Proceedings, Colorado School of Mines

Press, Golden, Colo., July 1977, pp. 148-165,

22R. L. Braun and R. C. Y. Chin, “Computer Model for In-Situ Oil Shale Retorting: Effects of Gas Introduced Into the Retort, ” Tenth Oil Shale Symposium Proceedings, Colorado School of Mines

Press, Golden, Colo., July 1977, pp. 166-179.

2tJ. H. Raley, et al., “Results From Simulated,

Modified In Situ Retorting in Pilot Retorts, ”

Eleventh Oil Shale Symposium Proceedings, Colorado School of Mines Press, Golden, Colo., November 1978, pp. 331-342.
—

176 ● An Assessment of Od Shale Technologies

“G. L. Baughman, Synthetic Fuels Data I-Iandbook, 2nd Edition, Cameron Engineers, Inc., Denver, Colo., 1976,

25R. D, Ridley, “A Marketing Perspective for

Shale Oil,” paper presented at the meeting of the

Commercial Development Association, Marcos

Island, Fla,, 1979.

zbR. F, Sullivan, et al., “Refining Shale Oil, ”

paper presented at the 43rd Midyear Meeting of

the Refining Department of the American Petroleum Institute, Toronto, Ontario, May 10, 1978.

‘71bid.

2W.S. patent Nos. 3,804,750: 3,876,533; and

4,029,571.

2YR. F. Sullivan, et al., Refining and Upgrading of

Syn~uels From Coal and Oil Shale by Advanced

Catalytic Processes, report prepared for the Department of Energy by Chevron U.S.A. under contract No. EF-76-C-01-2315, 1978.

1{)W. L. Nelson, “Visbreaking as Pour Point Reducer,” The Oil and Gas journal, Nov. 10, 1969, p .

229.

“J. D, Lankford and C. F. Ellis, “Shale Oil Refining, ” Industrial and Engineering Chemistry, vol.

43, No. 1, January 1951, pp. 27-32.

%upra No. 29.

‘

] Supra No. 31.

‘%upra No. 29.

“E. T. Robinson, “Refining of Paraho Shale Oil

Into Military Specification Fuels, ” Twelfth Oil

Shale Symposium Proceedings, The Colorado

School of Mines Press, Golden, Colo., August

1979, pp. 195-212.

‘“H. Bartick, et al., The Production and Refining

of Crude Shale Oil Into Military Fuels, report prepared for the Office of Naval Research by Applied

Systems Corp. under contract No. NOOO14-75-

C-0055, 1975.

“R. F, Sullivan and B. E. Strangeland, “Converting Green River Shale Oil to Transportable

Fuels, ” Eleventh Oil Shale Symposium Proceedings, The Colorado School of Mines Press, Golden,

Colo,, November 1978, pp. 120-134.

‘%upra No. 28,

‘%upra No. 29,

‘OH. C, Carpenter, et al., “A Method for Refining

Shale Oil,’* Industrial and Engineering Chemistry,

vol. 48, pp. 1139-1145.

“Applied Systems Corp., Compilation of Test Results, report prepared for the Office of Naval Research under contract No. NOO014-76-C-0427,

1976,

‘

2 Supra No. 35,

‘]H, A. Frumkin, et al., “Cost Comparisons—Alternative Refining Routes for Paraho Shale Oil, ”

paper presented at the 86th National Meeting of

the American Institute of Chemical Engineers,

Houston, Tex., Apr. 1-5, 1979.

%upra No. 25.

“’Pace Company Consultants and Engineers,

Inc., Shale Oil Refining Analysis, report prepared

by the Pace Co. for the Department of Energy and

Occidental Oil Shale, Inc., 1978,

%upra No. 25.

‘

7 Supra No, 43.

‘“Purvin and Gertz, Inc., Markets for Crude

Shale Oil in Central U. S., report prepared for Occidental Oil Shale, Inc., 1977.

“yIbid,

5’]C. F. Griswold, et al., “Light Olefins From Hydrogenated Shale Oil,” Chemical Engineering

Progress, September 1979, pp. 78-80,

“Prospects for Oil Shale Development—Colorado, Utah, and Wyoming, Department of the Interior, Washington, D, C., May 1968, p, 47.

52M. A. Weiss, et al., ShaJe Oil: Potential Economies of Large Scale Production, Workshop Phase,

The Massachusetts Institute of Technology, Energy Laboratory report No. MIT-EL-79-031-WP, July

1979, pp. 6-7.

‘

] Supra No. 14, at pp. 1-6.

5%upra No. 14, at pp. viii-ix.
CHAPTER 6

Economic and Financial Considerations

Introduction . ., . . . ., . . . . ., . 0 . .,,,,,..,

Page

179

The Nature of the Investigations. . .........180

Summary of Major Findings. . .............180

Development, Commercialization, and

Deployment . . . . . . . . . . . . . . . . . . . . . . . . . . 181

The Rationales for Federal Intervention. .. ..182

Impediments to the Commercialization of

Oil Shale . ,,..,,...,,.,....,.,,.,. , 183

Risks, Uncertainties, and Impediments

Associated With Oil Shale Development. .. 185

Plant Capital Cost Estimates . . . . . . . . . . . . . . 186

Increases in the General Rate of Inflation. .. .187

Uncertain Future Prices of World Crude. .. ..189

Choosing Goals for Oil Shale Development. .. 191

Information Base Goal . ..................191

Foreign Oil Displacement Goal. . ...........192

A Comparison of Alternative Financial

Incentives ● .., ,.O, .0. .,. . . . . . . . . . . . . . 193

Production Tax Credit . . . . . . . ., . .........197

Construction Grant. . . . . . . . , , . . . . . . . .. ...200

Low-Interest Loan. . . . . . . . . . .............203

Purchase Agreement . . . . . . . . . . . . . . , .. ...204

Price Support . . . . . . . . . . . . . . . . . .........206

Investment Tax Credit . ..................207

Accelerated Depreciation ., . . . . . . . . ......208

Increased Depletion Allowance. . ..........210

Page

Loan Guarantee . . . . . . . . . . . . . . . . . . ......212

Government Participation . ...............213

Government Ownership Versus Incentives

for Private Development . . . . . . . . . .. ....215

Which Incentives Are Most Efficient and

Effective? ● . . ● . ● . . . ,. . , ● ● ● ● , . . , ● ● . ● ● . 215

Are Financial Incentives Needed?. . ........216

Economic and Budgetary Impact. . .........217

Industry Costs. . . . . . . . . . . . . . . . . . . . . .. ...217

Cost to the Government. . .................218

Capital Market Impacts and Financial

Feasibility. . . . . . . . . . . . . . . . . . . . . ., .. ..221

Concerns. . . . . . . . . . . . . . . . . . . ...........222

Scenario Framework . . . . . . . . . . . . . . . . . . . . 222

Peak Financing Requirement . .............222

Aggregate Financial Feasibility. . ..........224

A Caveat . . . . . . . . . . . . . . . . . . . . . .........224

Finance Mix . ..............,...........225

Smaller Companies and NewEquity . .......225

Secondary Financial Impacts and Benefits. ..226

Balance of Payments and Strength of

U.S. Dollar . . . . . . . ..................226

Taxes . . . . . . . . . . . ......................226

Capital Costs Secondary Effects . ..........227

Financial Aspects of Policy Alternatives. . . . .227

Impact on Peak Financing . ...............227
Page

Impact on Private Sector Share of Peak

Financing. . . . . . . . . . . . . . . . . . . . . . . . . . 227

General Impact of Subsidies. . .............227

Summary.... . . . . ...............,......228

Effect on Inflation and Employment . .......228

Construction Industry and Equipment

Capacity *.***..* . . . . . . . . . .**..*..* . . 229

Chapter 6 References. . ..................231

List of Tables

Table No. Page

22. Cost Estimates for Oil Shale Processing

Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186

23. Evaluationof Potential Financial

Incentives for Oil Shale Development .,, 196

24. Summary of Companies’ Ordinal

Preferences for Incentives. . . . . . . . . . . . 197

25. Subsidy Effect and Net Cost to the

Government of Possible Oil Shale

Incentives (12-percentrate of return

on invested capital) . . . . . . . . . . . . . . . . . 197

26. Subsidy Effect and Net Cost to the

Government of Possible Oil Shale

27.

28.

29.

30.

Pag e

Incentives (15-percent rate of return

on invested capital) . . . . . . . . . . . . . . . . . 198

Peak Financing in Billions for Each

Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . 224

Finance Mix . . . . . . . . . . . . . . . . . . . . . . . 225

The Current DolIarImprovement in the

Annual U.S. Balance-of-Payments

Position Associated With Alternative

Development Rate Scenarios. . . . . . . . . . 226

Summary of Estimates of the

Improvement in Federal Tax Revenue

Attributable to Shale Oil Production

From the Taxes Paid byShale Oil

Companies, Their Employees, Their

Suppliers, and Their Suppliers’

Employees . . . . . . . . . . . . . . . . . . . . . . . . . 227

List of Figures

Figure No. Page

51. Increases in Capital Cost Estimates . . . . 188

52. A Summary of Variations in Each

Scenario. .o. o . . . . . . . . . . . . . . . . . . . . . 222

53. Year-by-Year Financing in Billions for

Various Scenarios . . . . . . . . . . . . . . . . . . 223
CHAPTER 6

Economic and Financial Considerations

Introduction

The loss of oil imports from Iran coupled

with large OPEC price increases during 1979

once more emphasized the vulnerability of

the United States to its continued dependence

on imported oil. Rapidly escalating world oil

prices combined with uncertain supplies and

dwindling domestic reserves have seriously

affected the balance of payments, the rate of

inflation, and the general health of the economy. While expert opinions may differ about

prices in the immediate future, they agree

that supplies will remain uncertain and

prices will continue to rise. The recently renewed interest in shale oil (and other synthetic fuels) as contributors to the domestic fuel

supply has arisen in response to these uncertainties.

The present debate over the proper economic policy to pursue with respect to oil

shale development centers around the following:

●

●

●

●

●

the potential it may have for alleviating

the Nation’s energy-supply problems;

the financial, environmental, and socioeconomic costs and risks that could be

encountered in developing an oil shale

industry;

a comparison of its benefits and costs

with those of other energy strategies

such as conservation, solar, increased

direct use of coal, other synthetic fuels,

expanded domestic exploration and production, or continued reliance on foreign

oil:

the implications of both alternative production goals and the rate at which the

industry is established for maximizing

the benefits and minimizing the costs

and risks of commercialization;

the relative advantages and disadvantages of different financial mechanisms

●

for achieving various production levels

and minimizing private and Government

risk; and

the major commercial and institutional

risks and obstacles that currently hamper commercial development, which of

these can be predicted, and in which

cases is information insufficient to adequately evaluate policy options.

Considering the amount of capital that would

need to be invested and profitably returned

over long periods of time, a rational and informed choice about the commercial production of shale oil (or any synthetic fuel) requires making reasonably confident estimates of the following factors and relationships:

●

●

●

●

●

the required capital and operating costs

for various levels of shale oil production,

and a comparison of these costs with

those for alternative strategies for obtaining equivalent benefits;

the future effect of OPEC pricing policies;

the corporate perceptions of specific

risks and deterrents that currently inhibit private commercialization;

the subsidies and incentives that would

most effectively, and at least cost, sufficiently reduce uncertainty to promote

development; and

the temporary or permanent subsidies

that would be required to maintain an industry.

These are all complex issues open to a variety

of interpretations. Several of these questions

may be unanswerable at this time with the information available.

179
180 ● An Assessment of Oil Shale Technologies

The Nature of the Investigations

This chapter reports the results of the fol--

lowing analyses:

 The capital and operating costs have

been estimated for commercial-size facilities in third-quarter 1979 dollars.

This has been done for both surface retorting and modified in situ (MIS) technologies. The total costs of various production levels have been calculated for

industries based on both generic technologies. The accuracy of current cost

estimates has been evaluated in the light

of the prior unreliability of such projections, and an attempt has been made to

disaggregate the factors responsible for

the escalating cost estimates for these

facilities.

. The effect of uncertain prices for OPEC

crude on shale oil commercialization has

been examined, a variety of projections

for these prices evaluated, and a probable rate of increase for future real

prices described.

● OTA has undertaken extensive qualitative and quantitative examinations of

the relative effectiveness and outcomes

of various possible financial incentives

for stimulating commercial development.

These were based on independently conducted mathematical simulations of industry economics, as well as on extensive discussions with private consultants, Government financial administrators, and industry representatives.

 The relative advantages and the merits

of several different strategies, development schedules, and production targets

have been examined with respect to

their comparative costs, risks, and benefits.

● A detailed study has been carried out of

the impact on capital availability and

pricing of oil shale development at several levels of production. The investigation

indicates the probable impacts that alternative levels of oil shale production

will have on the cost and availability of

capital, both for the U.S. energy sector

and the economy as a whole, given a variety of different growth and demand

characteristics for investment capital,

This examination also considers the relative impact that different Federal incentives will have on capital markets.

● The effect of various levels and paces of

oil shale development on the level of employment, the balance of payments, the

rate of inflation, and Federal tax generation,

Summary of Major Findings

The major conclusions of OTA’s economic analysis

of the oil shale industry are as follows:

● The commercialization of oil shale has been generally impeded in the past by several uncertainties. Among the most important are large and unreliable plant capital cost estimates, the insufficient number of high-grade private oil shale tracts

plus limited access to Federal oil shale lands, uncertainty about present and future environmental

regulations, and uncertainty over future prices for

oil.

● It is likely, given current market conditions, resource availability, and the regulatory climate that

without additional Federal action a shale oil production capacity of 100,000 bbl/d will be online

by 1990-92. It is probable, given similar conditions, that the production of 200,000 bbl/d by

that date will require financial incentives, direct

Government participation, or major changes in the

regulatory environment of the industry. The same

would be even more the case for a 400,000 -bbl/d

industry. Furthermore, the deployment of this size

industry by 1990 could require additional land ex-
Ch 6–Economic and Financial Considerations ● 181

●

●

changes or Federal leases. The deployment of a 1-

million-bbl/d industry by the same date would require aggressive action in all of these areas.

Given recent increases in the price of oil, the potential marketability of shale oil improved substantially during late 1979 and early 1980. In narrow

economic terms, the production of shale oil may be

price competitive with foreign crude at this time.

However, this conclusion is subject to several critical limitations, It assumes that current capital and

operating cost estimates are within 20 percent of

actual costs, that the price for oil will continue to

rise throughout the rest of this century by at least

a real 3 percent per year, and that developers require a real discount rate of no more than 12 percent. (The economics of shale oil and its potential

selling price are extremely sensitive to the discount rate assumed by the developers. )

If financial incentives to private industry are to be

employed, production tax credits, purchase agreements, and price supports have the most economic merit based on a variety of criteria. However, it

should be noted that the subsidy effect of purchase agreements and price supports are dependent on the contract price that is set. Consequently,

the success of these two incentives will depend on

how they are constructed and administered. Small

and moderate firms will require some kind of frontend subsidy if they are to significantly participate

in oil shale development. If such participation is an

important goal of Government policy, debt guarantees or debt insurance are probably the most efficient vehicles.

●

●

●

●

The deployment of a 400,000-bbl/d industry by

1990 would begin to markedly strain the capacity

of U.S. manufacturers to supply heavy equipment

to developers. To deploy a 1-million-bbl/d industry by that time would use between 15 and 30 percent of current U.S. annual production of this

equipment. There would be a similar strain on the

capacity of large integrated architectural/engineering firms capable of undertaking major process plant construction.

Existing capital markets and lending institutions

are able to supply sufficient capital for even the

rapid development of a large industry (1-millionbbl/d by 1990) without significant perturbations,

Oil shale development would provide a number of

economic benefits such as contributions to the national fuel supply and direct substitution for foreign oil imports. A production of 500,000 bbl/d

would reduce the balance-of-payments deficit by

about $5 billion current dollars if the price of foreign crude were $31/bbl.

Oil shale development, even at high rates of deployment, would have an insignificant impact on

national prices and rates of employment. However, the production of even 200,000 bbl/d by

1990 would noticeably increase local rents, land

prices, and labor costs. Even moderate developmental rates would favorably affect local employment levels and this effect would extend to the

region with the deployment of a 400,000-bbl/d industry by 1990.

Development, Commercialization, and Deployment’

In this assessment, the term commerciali- oil shale, it will be necessary for their attenuation is used to designate the process by tion to be focused on the period between the

which private industry adopts a technology

for commercial use after most of the technical uncertainties affecting its economic feasibility have been resolved. In the United

States, commercialization of new technologies is primarily undertaken by private firms

without direct Federal intervention. Nevertheless, during the past decade the amount of

direct Government involvement has risen

sharply. If Congress and the administration

decide to stimulate the commercialization of

time when the major technical problems have

been solved and the time when the technology

is commercially self-sufficient—the initial

phase. Once a decision about the advisability

of intervention has been made, the question

then is how the commercialization of the initial phase can best be accomplished.

Government sponsored development programs consist primarily of research and development (R&D) to solve the technical prob-
———— . ——— —— —

182 ● An Assessment of Oil Shale Technologies

lems of a process. Thus far, such programs

for oil shale have been directed to developing

specific techniques for mining, retorting, rubbling (in MIS processing), removing of impurities, and hydrotreating the shale oil.

Commercialization, in which a technology

is adopted and made economically viable by

private industry, involves the resolution of

the institutional and economic deterrents that

affect profitability. Efforts by the Government to promote commercialization assume

that the adoption by private industry of a

process, which is temporarily not commercially viable, will be expedited. The rationale

is that such assistance will enable an industry to become self-sufficient and profitable

without further subsidy. A Government-sponsored deployment program differs from one

to promote commercialization in that it does

not assume that an industry will ultimately be

self-sufficient or that incentives are temporary. The deployment of the synthetic rubber

industry during World War II is a well-known

example of such a program. In this case the

industry subsequently became profitable

without subsidy, but this was not the main objective of the program.

Both deployment programs and commercialization support for synthetic fuel plants

have been proposed. Although they have similar goals, these strategies imply very dissimilar relationships between Government and industry. Deployment programs are governmentally controlled. The function of private

firms is restricted to advising, constructing,

and, in some instances, operating the facilities. Private corporations provide services

for a fee to the Government, which buys the

products and services and retains ultimate

authority over the planning and the pacing.

Commercialization, on the other hand, implies

that the private sector makes the final decisions about adopting a technology.

The Rationales for Federal Intervention

From an economic point of view, Government involvement in commercialization may

be justifiable when private industry declines

to undertake an enterprise that meets major

social needs or benefits society. The penalty

for governmental inaction may take the form

of a forgone social benefit, such as a decrease in national security because of insufficient domestic suppies of oil, or of increased

costs to society, such as environmental damage because of inadequate regulation. Society would also have to pay if, as a consequence

of the Government’s failure to intervene, the

price of a resource increased at a later time.

The deliberate stimulation of a significant

level of oil shale production could be expected to have a number of social benefits. It

would help reduce dependence on foreign oil.

It would position the United States several

years closer to the deployment of a major

shale oil industry should this be made necessary by future political or economic events.

Stimulated production might also have a moderating effect on oil price increases, although

it is not clear what level of production would

be needed for this to happen.

Private industry declines to invest in an enterprise when it lacks confidence in the prospects for profitability. Higher expected profits are required of very risky projects than of

more certain ones. Three types of risk for oil

shale are discussed in this chapter:

1.

2.

3.

the possibility that capital and operating

cost estimates may seriously underestimate a project’s cost and thus jeopardize

its profitability or that the technology

will not perform as planned,

the possibility that world oil prices may

fluctuate in such a way that product

marketability will be interrupted at

some point in the time period required to

recoup the initial investment, and

the possibility that regulatory delays or

a change in environmental standards

may adverselv affect proiect economics. J J * ,

—
Ch. 6–Economic and Financial Considerations 183

If the Government is already intervening in

such a way as to penalize a new technology,

the private sector may be discouraged from

pursuing it, despite its usefulness. For example, the regulation of the prices of domestic

petroleum and natural gas that is now being

phased out undoubtedly penalized oil shale

development.

It is widely believed in oil shale industry

circles that the overall impact of Government

policy (e.g., regulations, permitting processes,

preferential treatment of conventional petroleum, and limitation of access to shale resources on Federal land) has been one of the

most important impediments to oil shale development,

A variety of groups and individuals oppose

Government stimulation of the oil shale industry (or other industries) because they believe

that the free play of market forces will make

much more efficient and productive market

decisions than will any federally inspired

stimulation program. Those sharing this perspective argue that favorable alteration of oil

shale economics by the Government will inhibit the use of the most efficient energy

sources, encourage less efficient management of the industry itself, increase the cost

of energy, and foster continued dependence

on fossil fuels. However, those who would

allow the market to decide whether shale oil

should be produced, also tend to argue that

taxes on developers, restrictions on resource

acquisition, and regulatory constraints

should also be radically reduced.

It does not necessarily follow from the failure of market mechanisms to promote commercialization that the Government will or

can do it better. Government intervention is

justified only if its benefits (appropriately

computed) are greater than its actual real

costs. Since the choice is not between efficient markets and inefficient Government or

efficient Government and inefficient markets,

but rather between inefficient markets and

inefficient Government, the question is which

will be more effective in a particular situation.

Impediments to the Commercialization of Oil Shale*

The successful commercialization of a new

technology ultimately depends on its profitability. Commercialization will not take place,

despite Government encouragement, if developers are unable to obtain a return on their

investment commensurate with returns available to them from other investments. Consequently, in determining the proper course to

pursue with respect to oil shale development,

the Government needs to give careful consideration to the prospects for profitable operation. An industry that requires permanent

subsidies is a different economic proposition

from one that needs them only for the first

commercial-size facilities. There are three

types of factors that influence self-sufficient

profitable operation: technical, economic,

and institutional.

Technical uncertainties primarily refer to

the difficulties associated with scaling up a

new process from pilot to commercial size.

This usually involves solving technical problems that could adversely affect operation

and thus increase the risk of financial loss,

e.g., a component may be required to perform

beyond the capacity of available equipment,

or existing mining techniques may be inadequate for the scale of commercial-size operations. With MIS technologies, the need to

properly rubble shale in order to achieve necessary burn characteristics (and thus a high

rate of shale oil recovery) is such a technical

problem. With surface retorting, an example

would be scale-up of 10 to 20 times of complex reaction systems handling massive quantities of solids.

Economic uncertainties are different for

those technologies that produce a substitute

for an older product than they are for those

that produce primarily new products. The

economic risks associated with shale oil

center around whether it can be produced
184 ● An Assessment of Oil Shale Technologies

and sold with sufficient profitability to compete with conventional crude. Uncertainty

about capital and operating costs has continually beset corporate decisionmaking with

respect to oil shale commercialization. In addition, developers are unable to accurately

predict shale oil’s marketing potential because of uncertainty over future prices for

OPEC crude. The recovery cost of most world

oil is unquestionably far lower than that of

shale oil, and will remain so over the life of a

first-generation shale oil facility. Oil price increases have begun to make shale oil very attractive. However, since these prices are, in

part, set by a cartel and bear little relation to

the cost of production, there is no certainty

that they will continue to rise in real terms. *

Commercial shale oil facilities producing

50,000 bbl/d require investments of around

$1.5 billion (third quarter 1979 dollars). In

order to recoup this investment, they will

have to function profitably for 10 to 15 years.

Given the 4 or 5 years such plants take to become operational, it is clear that even the

largest private developers would want to be

confident about the trend of international

prices over the next 15 years in order to undertake commercial operations.

Institutional uncertainties occur because

all technologies and economic activities take

place within an institutional context that can

act to facilitate or impede their commercialization. The extent to which this happens depends on the extent to which the technology

and its costs create conflicts over basic values or the use of scarce resources. At issue is

whether the aggregate impact of Government

policies such as leasing arrangements, taxes,

incentives, and environmental regulations

would be applied more or less favorably to oil

shale development than they would be to

other forms of energy. Clearly, Government

policy does not treat all energy sources

“neutrally.”

*Many analysts believe that the OPEC cartel has lost much

of its power to set prices and thal OPEC price decisions are

now follow ing rather than preceding market trends. Recent evidence of market prices rising above OPEC-established prices

supports this belief. So does the outcome of the December 1979

OPEC meetings,

Although not as severe as the polarization

that has been taking place over nuclear power, the debate over the development of oil

shale and other synthetic fuels is significant.

Proponents of solar power and conservation

continue to oppose fossil-based synthetic

fuels because their development supposedly

diverts funds from the pursuit of “soft”

energy strategies and discourages conservation. Environmental groups oppose development because of the possible deleterious effects on air, water, and land. Fiscal conservatives oppose Federal intervention on the

grounds that Government money should not

be used to subsidize private development.

Although it has been argued that the populace of the oil shale region is generally in

favor of development, local communities are

concerned about the impact that these facilities might have on their quality of life and the

local environment.

Developers believe, virtually without exception, that delays and costs associated with

the permitting process are a major disincentive to oil shale investment. They argue further that the possibility of new or more strict

regulations in the future is a severe impediment to development. The imposition of new

regulatory rules or standards after a plant is

in construction or operation could require extensive and costly modification of the facility’s design or operation. These expenses

could seriously harm a project’s economics,

and in extreme cases force the suspension of

operations. The need to compensate for significant regulatory risks and disincentives is

one of the primary arguments used to justify

Federal subsidies.

To understand the prospects for successful

commercialization, it should be recognized

that many of the technical, economic, and institutional impediments are interdependent.

In general, the potential for successful commercialization is limited by the margins available to accommodate a technology to these

impediments without encountering barriers.

Thus, if the relative economic advantage of a

process is very large, then extensive adjustments to environmental standards can be
Ch 6–Economic and Financial Considerations ● 185

made without reaching an economic barrier.

When a process has relatively low technical

performance requirements, it may be possible to reduce economic or institutional barriers by upgrading technical performance.

However, if technical performance goals are

high, production costs are close to or exceed

the selling price for competitive products,

and institutional barriers are restrictive,

then the technology will encounter serious

difficulties. Under these conditions, the usual

response of industry would be to postpone

commercial commitment while waiting for

technical improvements, reduced institutional barriers, or improved market prices for the

product.

Technical problems can be reduced

through further R&D. Economic uncertainty

can be averted through some form of subsidy.

Institutional barriers can be minimized

through altering administrative or regulatory

rules and timetables.

Although other considerations are extremely important (e.g., overall cost to the

Government, financial exposure, and administrative burden), the risks presented in commercializing a particular industry must be

seen, at least in part, from the point of view of

present and potential developers. The success of any Government program to stimulate

the commercialization of a new technology

depends, to a large degree, on the extent to

which the policy incorporates the developers

own perceptions of the risks, benefits, and

uncertainties associated with production.

Surface oil shale technologies are comparatively well-understood with only a few remaining technical uncertainties. They are, in

fact, very much the same today as they were

20 years ago, and present little room in which

to maneuver with respect to changing their

scale of operations or improving their performance. For example, there is apparently

no alternative to large-scale mining and the

disposal of sizable quantities of spent shale.

In real terms, these technologies are unlikely

to become significantly less costly than they

are now. Thus, the possibility of technical

tradeoffs from the technology itself is reduced, and the improvement of overall commercial prospects must come through the reduction of economic and institutional barriers.

Risks, Uncertainties, and Impediments Associated With

Oil Shale Development

The commercialization of oil shale faces

three primary economic risks and uncertainties:

the uncertainty over the costs of building

and operating commercial facilities;

the risk of unfavorable recovery-cost differentials relative to conventional crude

(except possibly those from such frontier

areas as Outer Continental Shelf development); and

the uncertain future selling prices of

world oil.

These are compounded by the partial connection between the costs of oil shale facilities and the rising price of energy,

There are three additional uncertainties

related to the carrying capacity and response

of the institutional systems within which the

oil shale industry operates that could seriously affect the economics of the industry. They

are:

●

●

the possibility (under conditions of rapid

large-scale deployment) of bottlenecks

and shortages of equipment, architectural and engineering construction capacity, and trained manpower for constructing and operating facilities;

the possible scarcity of available and

reasonably priced investment capital

during the period of construction; and
186 An Assessment of Oil Shale Technologies

the potentially unfavorable effects of

present or future Federal and State regulatory policies on commercial development.

Plant Capital Cost Estimates

50,000-bbl/d oil shale facility would require a capital investment of around $1.5 billion in 1979 dollars. Operating costs are estimated by industry at $8 to $13/bbl of crude

shale oil processed, exclusive of capital recovery. Such an investment would be undertaken cautiously even if the estimates of capital and operating costs for oil shale plants

were known to be accurate. However, during

the past 10 years, capital cost estimates have

increased much more rapidly than has the

general rate of inflation, and still do not appear to be totally reliable. The experience of

Colony Development is illustrative but not exceptional. Its direct capital cost estimates for

a 43,000-bbl/d facility increased from $225

million in 1972 to $1.3 billion in early 1979,

and were $1.7 billion in February 1980. (See

table 22.)

Cost escalations of this magnitude are not

unusual for large, capital-intensive facilities

involving complex novel technologies. As

demonstrated by experience with light water

reactors, many coal gasification plants, Canadian tar sands, and various weapons systems, cost estimates are likely to rise rapidly

as a process advances from initial to definitive engineering designs. Also, as with similar

projects, oil shale development is highly vulnerable to changes in the cost of capital and

labor. These costs have increased more rapidly in recent years than the composite rate of

inflation. In addition, oil shale development

will be particularly subject to regulatory requirements, permitting procedures, and possible environmental litigation that could delay

or arrest construction and substantially add

to costs.

A number of hypotheses have been offered

to explain these cost estimate increases.

Some argue that since the historically most

accurate method of estimating the price of

shale oil is simply to add $5 to the price of imported oil, oil shale companies are exaggerating their costs in order either to prepare the

market for high selling prices or to get large

governmental subsidies. This charge has its

basis in the observation that the rise in shale

oil cost estimates has paralleled foreign oil

prices, and seems to increase each time the

Government gives serious consideration to industry subsidies, Neither this nor any other

investigation has produced evidence that cost

increases are contrived, Most of the variations in cost increases and estimated prices

for oil shale can be explained by examining

four significant variables:

. increases in the general rate of inflation,

● escalations in the real costs of plant construction.

Table 22.–Cost Estimates for Oil Shale Processing Plantsa

Estimated cost

Time of estimate $ million

196 8 $ 138

196 8 144

1970 . , 250

1973 280

1973 : : 250-300

Early 1974. . 400-500

Late 1974 , 850-900

1976 960

1977 1,050

1979 : : 1,350

198 0 1,700

— —

Data source Scope and detail of estimate

Department of the Interior Initial

The 011 Shale Corp Initial

National Petroleum Council Initial

Department of the Interior Initial

Colony Development Operation Initial

Colony Development Operation Detailed (early version)

Colony Development Operation Detailed

The Oil Shale Corp. Update

The Oil Shale Corp. Update

OTA Update

The 011 Shale Corp. Update

aplanl~ “se underground rnlolog and above-ground retorting to produce approximately 50000 bbl Id Of shale 011 syncrude

SOURCE Office of Technology Assessment
Ch 6–Economic and Financial Considerations 187

more stringent environmental standards

for oil shale operations, and

increases in estimates as a consequence

of more complete and detailed knowledge of a facility’s actual design,

Increases in the General Rate of Inflation

Many developers believe that chronic inflation during the last 10 years has been the primary cause of the exceptional cost escalations. Although inflation rates were very high

between 1972 and 1976, this view is apparently incorrect. For oil shale developers facing nominal rather than adjusted real prices,

the overall impact of dollar inflation would

appear quite large. The rate of general price

inflation also tends to drive up the interest

rates on construction loans. However, as

shown in figure 51, during the period from

1972 to 1977, not more than 12 percent or approximately $100 million of the cost estimate

increases were due to changes in the general

price index. The rate of general inflation is

Figure 51 .—Increases in Capital Cost Estimates

Surface shale plant estimates

.

.

lncreases from Max

environmental

costs [ Min

.

1971 1972 1973 1974 1975 1976 1977

Year

“ DupontIndex This Index gives the gradient of change for Industrial process

plant costs Although not entirely appropriate for 011 shale plants, it IS the best

available Index However It probably somewhat understates plant cost escala

tions

SOURCE Edward W Merrow Cons frafnts on the Cornmercia/lzatlon of 0//

Sha/e 2293 DOE September 1978

important because of the way it affects the

perceptions of developers. The factors that

influence relative price changes are, however, considerably more significant.

Escalations of Plant Costs

Large plants are vulnerable during periods

of extreme inflation when the demand for

necessary equipment and services rises

sharply relative to their supply. Such a period

existed in 1974. From mid-1973 to 1975 the

general price index increased in excess of 20

percent, but chemical industry equipment increased by approximately 70 percent, and

certain key items such as compressors and

heat exchangers increased by almost 100

percent. It was during this period that the

cost estimate for the Colony oil shale plant approximately doubled.

The effects of severe sectoral inflation on

project costs are even greater than those suggested by the above numbers, which are

based on list prices that are often discounted.

Discounts are eliminated as industry inflation

accelerates.

In a crash program for synthetic fuels,

there will almost certainly be real cost escalations and overruns. The first few plants

committed could contract for a significant

part of the available U.S. manufacturing capacity for key items such as valves, pumps,

compressors, and pressure vessels. As additional plants reach the procurement stage,

equipment suppliers would be forced to quote

longer and longer delivery times. These entail

higher price contingencies for contractors to

cover unknown increases in supplier costs,

and can have a devastating impact on large

capital projects. Almost half the total perbarrel cost of synthetic fuels is estimated to

be solely the carrying cost of the capital investment. project owners will, therefore, be

willing to bid up the prices for essential

equipment in order to save time. A single

week’s delay could increase costs by millions

of dollars.

Because of the potential for extreme sectoral inflation, costs could increase dramati-
.—.—.—

188 . An Assessment of Oil Shale Technologies

cally in a crash program. Building 20 plants

could cost considerably more than twice the

cost of building 10 plants. Any savings in

design costs by building duplicate plants

would be wiped out by cost increases. Plant

construction costs during an all-out crash

program are likely to increase in real terms

by 50 percent or more.3

Increases Due to Environmental Regulations

The environmental legislation passed during the late 1960’s and early 1970’s, along

with the provision of substantial enforcement

power to the Environmental Protection Agency, altered the context in which large-scale

industrial development may now take place.

Without question, this legislation, which has

been paralleled by similar State laws, has

been and will continue to be very costly to industry. It is not possible, however, to accurately ascertain what the actual costs of

meeting these standards are, because the

costs are both direct and indirect. Most estimates usually include only the former cost

category. Cost estimates for meeting some of

the standards are discussed in detail in chapter 8.

In 1978, the RAND Corp. estimated that the

direct costs of pollution control technologies

for oil shale developers ranged between 6.5

and 15 percent of total capital costs. These

were primarily for eliminating hydrocarbons,

particulate, and hydrogen sulfide from the

retorting process, and for dust control and

spent shale disposal. By assuming a zero value for environmental costs in 1971, RAND

goes on to estimate that between 8 and 20

percent of the increases in estimated capital

costs or $65 million to $165 million between

1971 and 1978 were caused by environmental

factors.

These estimates do not include the possible

indirect environmental costs that might occur

because of:

● necessary siting changes,

● alterations of mining plans,

● disruption of construction schedules,

● less efficient facility operation, and

● costs of potential litigation.

Each of the above can have enormous impacts on plant economics; delays occurring

late in the construction stage are particularly

costly. A 6-month delay in the middle of construction could add more than $100 million to

costs. Additional environmental equipment

can substantially reduce reliability and the

on-stream factor, * if operations must cease

when environmental equipment fails. A reduction in the on-stream factor of 5 percent

will increase the required selling price of the

product by 7 percent. A construction delay

such as might be caused by environmental

litigation can be extremely costly after

ground has been broken. The costly delays

and disruptions described here will probably

characterize only a fraction of the projects

undertaken. Nevertheless, they constitute a

significant risk that must be included by developers in their contingency plans.

Environmental regulations add to developers’ estimates of uncertainty and risk. The

uncertainty is over how present regulations

will be interpreted, administered, and enforced; and the risk derives from the possibility of future regulations. Rather than making

an attempt to predict with some degree of accuracy what might be the indirect effects of

environmental standards on plant economics,

developers have increased the size of their

estimates as a hedge against uncertainty,

based on their informal sense of general risk.

Although environmental regulations have significantly augmented industry’s capital cost

estimates, they nonetheless are responsible

for less than than 20 percent of the overall

cost estimate escalations since 1971.

The Learning Curve for New Plant Design

The escalations due to improved knowledge about costs, as a consequence of more

complete engineering designs, appear to be

responsible for the largest increases in capi-

*The on-stream factor is the proportion of operating days

per year.
Ch 6–Economic and Financial Considerations ● 189

tal cost estimates. Between 40 and 50 percent

of the estimated increases between 1971 and

1977 were of this kind.

Forecasting the costs of constructing a

commercial facility for a new technology is

normally based on a series of engineering design estimates, each of which is presumably

more detailed and accurate than the previous

one. There are four types of such estimates.

They start with initial estimates, which are

“back of the envelope” predictions that give

only a rough indication of eventual costs; proceed through the preliminary design estimate

in which the plant’s subsystem flows are defined, but component subprocesses are not

defined; continue with the detailed design in

which estimates are prepared for specific

materials and components; and end with the

final design estimate in which precise costs

for all materials, components, and labor are

pulled together. The final design estimate

should accurately locate the cost of immediate construction to between plus or minus

[usually plus) 15 percent of the eventual cost.

The cost of preparing a final engineering

design estimate for a commercial-size oil

shale facility is between $12 million and $20

million. To date, only detailed design estimates have actually been carried out. The intention of this iterative estimation process is

to provide continually better design forecasts

based on continually more precise technical

data derived from increasingly larger developmental tests, As the designs become more

complete and the technical data improve, the

costs become clearer.

The cost estimate escalations that took

place between 1973 and 1976 occurred, in

part, because prior to the middle of 1974, no

final or detailed engineering design estimates

had ever been prepared. Colony Oil Shale Development Corp. ’s detailed design estimate

represented an 80-percent increase over the

preliminary design estimate made 10 months

earlier. The subsequent experience of other

developers with their more detailed designs

was similar,

Cost estimation increases are by no means

limited to oil shale facilities. Similar increases have characterized the development

of coal gasification, coal liquefaction, Canadian tar sands, light water nuclear reactors,

and a variety of new weapons systems. However, several characteristics of oil shale

plants present particular design and estimation problems. First, such plants are highly

site specific. The costs of transporting, mining, handling, and disposing of shale all depend on the nature of a site’s topography, geology, and surrounding terrain. Second, the

estimation of oil shale plant costs requires an

array of engineering, architectural, economic, and technical skills possessed by only a

few architectural and engineering firms.

The reliability, or on-stream factor, for the

plant after it is constructed, figures significantly in the eventual cost of production. Cost

estimates compute the cost of building the

plant, and then assume that it will be onstream about 90 percent of the time. There is

a high probability, however, that pioneer

plants will not operate as planned for some

time, or until such time as additional investments are made to correct their problems. For this reason, companies tend to build

only those designs that are known to work,

even though new but untried approaches may

promise appreciable savings.

As technical data improve and developers

complete more detailed design estimates, the

gradient for real cost escalations will level

off. It is probable, but not certain, that current cost estimates are fairly realistic and

that there will be no further substantial increases, other than normal inflation. However, no commercial-sized facilities have

been built, and cost estimates are unlikely to

become stabilized without industry experience in constructing and operating such facilities.

Uncertain Future Prices of World Crude

The market price of premium grades of

conventional crude oil is a major determinant

of the highest possible profitable selling

prices for syncrude from shale. Therefore,

present and future prices for conventional
190 ● An Assessment of 011 Shale Technologies

crude are among the basic factors that will

condition the economic viability of the oil

shale industry. A developer who commits

$1.4 billion to $1. i’ billion to a shale oil plant

with a very long payback period must be reasonably confident that the market value of the

product will exceed its production costs.

Uncertain future prices of international oil

prevent firms from accurately predicting

market values for shale oil. Since the Arab oil

embargo of 1973-74, the actions of the OPEC

cartel and high international demand have

pushed the price of world oil far above recovery costs.

Between September of 1979 and February

of 1980 the prices of world oil increased by

over 30 percent. In March of 1980, the posted

prices of the premium grades of conventional

crude (the counterpart of upgraded shale oil)

stood between $34 and $38/bbl. Their spotmarket prices (e.g., for Wyoming Sweet and

the best grades of Nigerian and North African oil) are currently between $40 and $52/

bbl. Sweet crude oils were recently sold from

the Elk Hills and Teapot Dome Petroleum Reserves for $43 and $50/bbl respectively.

These increases, along with the probability of

further escalations in the future, have substantially improved shale oil’s economic attractiveness. The future viability of shale oil

is predicated on the assumption that increases in its production costs will lag behind

the rising price of world market crude. On the

basis of the best current capital and operating cost estimates (compiled between November of 1979 and February of 1980), it appears

that shale oil may have reached parity with

conventional oil without subsidy. However,

this conclusion is subject to several critical

limitations.

First, this finding assumes that current

capital and operating cost estimates are, in

real dollar terms, within 20 percent of being

accurate. Given that such projects have

never been previously undertaken, still lack

final engineering design estimates, and are

prone to possibly severe inflation because of

associated heavy equipment costs, this may

be a very risky assumption.

Second, most analysts expect international

oil prices to increase by 3 or 4 percent per

year, over and above inflation. This will mean

that the price of oil will double, in real terms,

by 2000. However, because international oil

prices are still set, in part, by a cartel, the

future of the market cannot be predicted with

any certainty. Increasing or continued high

demand, decreasing world reserves, and

OPEC or producer-state governmental policies directed at conserving their reserves

through price rationing could result in sustained price inflation for imported oil. On the

other hand, prolonged recession in the industrial West or reduced international demand

could limit oil price increases in the future.

Recent events strongly indicate that OPEC’s

capacity to set international oil prices has

been substantially weakened. Nevertheless,

the play of market forces is still likely to maintain upward pressure on prices. In any event,

future incremental price increases are not

likely to be regular. Instead, temporary periods of oversupply and soft markets are likely

to alternate with shortfalls and high demand.

Therefore, short periods of stable prices will

probably alternate with rapid price increases.

Finally, the question of whether present

and future oil prices will allow profitable selling prices for shale oil without subsidy depends on the discount rate that firms are assumed to require in order to undertake development. The average real aftertax returns on

investment of U.S. industrial firms is generally between 6 and 10 percent. Given the

risks associated with a pioneering industry,

oil shale developers will require a larger

profit than that obtained from less risky projects. Industry sources generally maintain

that this would mean a real aftertax expected

profit of between 12 and 15 percent. Breakeven selling prices for shale oil are extremely

sensitive to the discount rate, which at 12

percent would make shale oil competitive

with conventional petroleum according to

OTA’s analysis. However, if developers require a is-percent rate of return to undertake investment, then subsidies will probably

still be necessary.
Ch 6–Economic and Financial Considerations ● 191

. -

Choosing Goals for Oil Shale Development

The Federal Government has a variety of

options available to stimulate oil shale development. In order of increasing Government

involvement, these include:

continuing present policies and providing no additional incentives;

encouraging precommercial modular

plants;

building and operating a number of Government-owned modules;

encouraging a few commercial-sized

plants; and

deploying a major industry.

Each option differs with respect to the cost

to the Treasury, the level of shale oil production, the risks of cost overruns and inefficiency, and the impacts on the physical and social

environments. They also vary with respect to

the extent and types of financial incentives

that would be most effective.

There are two major policy goals to be met

by an oil shale industry. One is to deploy

enough production capacity to answer the remaining uncertainties related to economic

and technological feasibility and environmental impacts, The other is to quickly displace

foreign oil imports.

Information Base Goal

Because no oil shale process has as yet

been commercialized, the economics, technical operability, and environmental impacts of

each of the processes are still not fully

known. If the most promising processes were

operated at either the precommercial modular scale or at commercial capacity many

questions could be answered and comparisons among the various processes would be

possible, Operating experience could be acquired by providing incentives to industry, by

operation of Government-controlled modular

test facilities, or through some combination of

both. A1though some questions could be answered by research, a moderate development

and production program would reliably answer most of the remaining technical, economic, and environmental questions. It would

also facilitate the selection of the most feasible oil shale and synthetic fuel technologies

available today; provide information for rational decisions regarding oil shale commercialization; and put the United States several

years closer to full-scale production capacity.

A modest program for stimulating the construction of a limited number of commercial

or modular facilities would be less likely to

fail, Such a strategy reserves judgment concerning the ultimate extent of development

until the processes have been tested. This has

the advantage of allowing policymakers to

evaluate commercial results and consider

alternatives for further reduction of oil imports prior to contracting for additional

facilities, and should improve the chances of

ultimately establishing a self-sufficient oil

shale industry. It should be noted, however,

that the information base strategy tends to ignore the fact that technology is not static but

is continually changing, By gathering data on

“today’s” processes, this approach may ignore possible (probable) future process developments. It is possible that complete information could be obtained on several processes in

the next 10 years only to discover that a new

process may be more productive. Should policy be to repeat the cycle and obtain more information, or to build the obsolete plant?

From an economic standpoint the choice is

not a simple one.

In the absence of time limitations, the overdemand for scarce capacity in construction

companies, in skilled labor, in plant materials, and in architectural engineering firms

would be reduced or even avoided. When

these are placed in short supply, costs escalate, the quality of design is lowered, and

fewer plants may be constructed.

ICF in a recent study for the Budget Committee of the U.S. Senate4 summarized the

benefits of proceeding with development in a
192 . An Assessment of 011 Shale Technologies

two-phased strategy by maintaining that such

an approach would:

● be an effective symbolic action showing

the seriousness with which the United

States intends to reduce energy imports;

● provide the opportunity through followon stages of development to reduce energy imports directly through shale oil production, while maintaining the option to

consider more cost-effective ways of import reduction; and

● provide the flexibility that has been

found to be critical in advancing new

technologies to a commercially viable

stage.

An information base strategy initially followed by review and possible subsequent additions, as discussed in this chapter, has also

been suggested by the RAND Corp., ICF, Cameron Engineers, Booz-Allen, and the Congressional Budget Office. It assumes that the principal goals are to create a viable industry,

minimize the cost to the taxpayer, and maximize the efficient use of capital.

If, however, the primary goal is to reduce

dependence on foreign oil by 1990, then the

extensive development of a large oil shale industry might be more advisable. Economic

analysts have examined whether producing

additional oil shale (or other synthetic fuels)

is more cost-effective than alternative approaches such as conservation. Their analyses depend on the assumption that the desirability of synthetic fuels is chiefly a matter of

price rather than availability. Another OPEC

oil embargo could change this assumption.

Foreign Oil Displacement Goal

If present trends continue, the United

States could import around 12 million bbl/d of

oil by 1990. It is beyond the scope of this

report to examine whether this import dependence could be reduced to the President’s

target of 8.5 million bbl/d through conservation, synfuel production, and conversion from

oil to coal. To estimate the desirability of the

contribution that shale oil could make to reducing import reliance requires examining: 1)

how cost-effective shale oil development is

compared with other energy strategies in

achieving import reductions; 2) whether the

costs and risks of a crash program to develop

a large industry outweigh its potential

benefits and whether such a program would

achieve its production goals; and 3) if a rapid

development strategy would have unacceptable environmental costs.

Establishing a large industry to replace

foreign oil would have both positive and negative effects. On the positive side, the economy

and national security would benefit from a reduction in oil imports; and in the oil shale region, employment would rise and an increased tax base would provide revenues for

community development. On the negative

side, such a program would be extremely

costly. It would necessitate investing in numerous plants, each with a capital cost of

around $1.5 billion. Technologically inferior

processes might be used because of insufficient time for supporting technical R&D, and

the accelerated construction schedule could

lead to cost overruns and managerial inefficiency. (The use of a “technologically inferior” process could, however, be compensated

by the inflation savings; a better process built

10 years later would probably cost much

more in real terms because of inflation of

plant costs.) Capital availability for other economic sectors could be restricted. It is also

questionable that mining and processing

equipment could be supplied within the construction time frame. Furthermore, it is possible that the lack of supporting environmental

R&D could lead to a conflict with environmental standards. On balance, the socioeconomic

effects could well be more negative than positive.

There is general agreement among the engineering and construction firms contacted

by OTA that a program to establish a large oil

shale industry (over 500,000 bbl/d by 1990)

would entail sizable cost overruns because of

high inflation in critical supply industries. It

would also impose severe time constraints on

a developer’s operations. Contractual agreements for these facilities would have to begin
Ch 6–Economic and Financial Considerations ● 193

immediately and continue under conditions of

tight scheduling for the next 8 to 12 years.

Various studies of the consequences of Federal funding to stimulate the commercial adoption of new technologies, including the 1976

study by the RAND Corp.,5 report that subjection to severe time constraints has rarely resulted in the establishment of a viable industry. Furthermore, a rapid development effort

would probably require the commercial operation of facilities before the technologies and

A major Government effort to establish an

industry based on a new technology under

time constraints does not allow sufficient

time to review progress, make cost-benefit

tradeoffs, and modify plans in response to

new knowledge, When a pressing national

emergency requires a crash program, the resultant inefficiencies entailed by these restrictions may be justified. However, when

the primary purpose is to establish a self-sufficient industry, crash programs should be

their economics were fully understood. avoided.

A Comparison of Alternative Financial Incentives

Before oil from domestic shale can significantly supplant imported supplies, any development program must take into account the

major technological, environmental/regulatory, and economic uncertainties that discourage private firms from undertaking such investments. To overcome these uncertainties,

Congress is contemplating implementing an

incentive program that would share in the

risks or subsidize the economics of oil shale

development. In evaluating alternative incentives and their probable effects on oil shale

development, the reactions and preferences

of developers must be taken into consideration.

In conducting this analysis, 10 alternative

incentive structures were examined:

●

●

●

Construction grant. The Government

provides a direct grant to cover a prespecified percentage of total construction costs, both a 50- and 33-percent

construction grant were analyzed.

Production tax credit. The developer receives a tax credit for each barrel of

shale oil produced, a $3/bbl credit computed on shale oil prior to upgrading was

analyzed.

Low-interest loan. The Government

lends the developer a prespecified percentage of capital costs at an interest

rate below the prevailing market rate;

the analysis assumed 70-percent Government financing at 3 percentage

points below the market rate.

Price support. With this incentive, the

Government guarantees the developer a

certain price for shale oil; the analysis

assumed $55/bbl of hydrogen-upgraded

syncrude (hydrotreated shale oil). If the

market price for the product falls below

the guaranteed price, the Government

would make up the difference.

Purchase agreement. The developer contracts with the Government to sell shale

oil at a price higher than the prevailing

market price; the analysis assumed a

price of $55/bbl of upgraded product.

Increased depletion allowance. The developer is allowed to claim a 27-percent

depletion allowance (at present it is 15

percent).

Increased investment tax credit. The developer can claim an additional investment tax credit of 10 percent,

Accelerated depreciation. The firm is allowed to depreciate its investment over 5

years.

Loan guarantee. The Government would

agree to pay off a loan in the event that

the firm defaults on its loan: the firm

would typically receive a lower interest

rate than that prevailing in capital markets.

Government participation. The Government would become an equity participant in an oil shale project.

To evaluate how effectively the different

incentives will promote the development of a
—

194 ● An Assessment of 011 Shale Technologies

viable oil shale industry, each was analyzed

in relation to three fundamental objectives of

the congressional incentive program. * These

objectives are:

●

●

●

Subsidizing the economics of shale oil

production. The mechanism by which

each incentive affects the perceived economics of oil shale development and how

well it functions as a subsidy was analyzed.

Sharing in project risks. The extent to

which each incentive allows the Government to share in the risks of oil shale development, and the extent to which it reduces the variance of the present value

of the aftertax income from a project

was analyzed. To conduct this analysis,

a project risk was assigned for four specific categories: the risk of unsuccessful

project completion, which stems largely

from technological and regulatory uncertainties; the risk associated with uncertain investment costs; the risk associated with uncertain operating costs; and

the risk associated with uncertain future

prices for oil from shale.

Facilitating access to capital. The extent

to which each incentive would sufficiently induce capital markets to lend the

large sums of money that will be required to develop an oil shale industry

was examined. This consideration is

particularly important for understanding which types of firms would benefit

from specific incentives (i.e., whether an

incentive will benefit less well-capitalized firms or those with limited ability to

incur debt).

Once it was determined how well each incentive met each of the program’s objectives,

it was examined in the context of two important policy guidelines:

● Efficient use of the Nation economic resources. To make efficient investment

decisions,** oil shale developers should

*Congress, before designing an incentive program, should

specify the relative emphasis to be placed on each objective.

**This definition of efficiency is in the somewhat narrower

sense of its use in economics.

●

pay the same prices for resources (i.e.,

land, labor, capital, and materials) that

are paid by firms engaged in other production activities in the general economy

(i.e., the prices paid should equal the value of these resources in alternative

uses). Similarly, the price received for

the shale oil by producers should equal

its value to the economy. This will be the

marginal price of crude oil, because upgraded shale oil and crude oil are almost

equally substitutable. Therefore, OTA

analyzed the extent, if any, to which

each incentive would interfere with developers’ perceptions of the market

prices of the productive resources consumed in shale oil production or the market price for the final product.

Minimal administrative burden. The cost

of administering an incentive program

represents a loss to the economy that

falls on the public and private sectors

alike. In addition, the administrative

burden affects the time required to implement a program as well as its overall

effectiveness. Therefore, OTA analyzed

the administrative requirements for

each of the incentives.

Finally, the analysis was structured to

assist Congress in developing an incentive

program to meet a third policy guideline: to

promote a healthy state of competition in the

industry, Because of the potential multiplicity

of objectives for an incentive program, and

the variety of types of firms involved, it is

probably necessary that the incentive program consist of a package of incentives. This

should allow firms in differing financial, technical, and tax circumstances all to benefit.

To clarify the competitive implications of a

program consisting of a combination of incentives, the kinds of firms that would most

benefit from each incentive were identified

based on the analyses of the incentives, a

review of industry statements, and discussions with industry representatives. Specific

examples of firm preferences for the different incentives have been documented. The effects of the various incentives on the program

objectives and the policy guidelines are sum-
Ch 6–Economic and Financial Considerations . 195

marized in table 23. The rank-order preferences of different shale oil developers for the

various financial incentives are summarized

in table 24. In order to make a comparison of

the incentives and evaluate their contributions to the objectives of the total program

and the policy guidelines, a computerized

simulation model developed by Professors

Wallace Tyner (Purdue University) and Robert Kalter (Cornell University]” was used to

test and measure each of them against the

case in which no incentive is offered. The

present calculations with the Kalter-Tyner

model were prepared for OTA by Resource

Planning Associates, Washington, D.C. A

complete description of the simulation model,

its capabilities, limitations, and how it was

employed can be found in appendix B. Using

the model, it was possible to estimate the following four variables (for all but the production tax credit and loan incentives):

. Expected profit. Expected economic

profit is defined as expected return in

excess of a company’s minimum required aftertax return on its oil shale investment. * OTA calculated both expected profit and the change in expected

profit relative to the no-incentive case.

 Risk. The risk of the investment refers

both to the probability of the investment

resulting in an economic loss (i. e., earning less than the minimum required rate

of return), and to the degree of variation

in possible profit outcomes, OTA measured this variation in absolute terms

(i.e., the ratio of change in expected

profit to standard deviation of expected

profits).

● Breakeven price. The breakeven price is

the constant price for hydrotreated**

shale oil at which it would just earn its

minimum required rate of return.

● Cost to the Government. The expected

cost to the Government of providing the

incentive is the gross subsidy to the firm

*Profi I was measured as the sum of each yea r’s cash flows,

dis(:ounted using the company’s minimum required aftertax

rate of return as a discount rate (see app, B).

* *In hydr~ treatment the physical properties of raw shale oil

are improved by adding hydrogen and removing nitrogen and

sulfur. The product is often referred to as syncrude.

less increased tax payments to the Government. * An incentive increases tax receipts if the present value of the tax payments is larger with the incentive than if

an equal investment was made without

the incentive. OTA estimated both the

actual cost to the Government and the

ratio of the change in expected profit to

cost.

With these computations, the way in which

a firm’s marginal tax rate** (and, for a lowinterest loan, its cost of borrowed funds) influenced expected profits was assessed, and

the sensitivity of expected profits to different

discount rates (defined as the minimum rate

of return necessary to induce private development) was determined,

The numerical results of this analysis,

which are summarized in tables 25 and 26,

were calculated using the best available data

for the cost of commercial oil shale facilities.

They thus provide a reasonable approximation of the magnitude of the probable effects

of each of the incentives. While these outcomes would not be expected for the operation of an actual facility, they would be for

the average operations of a number of facilities. Because of the uncertainties inherent in

the estimation, the most useful application of

these quantitative results is for establishing

comparisons among the incentives.

Congress is currently considering 10 major

kinds of incentives to be included in a domestic oil shale development program. The analysis of the specific effects of each of these on

the three program objectives and the three

policy guidelines is summarized below. The

discussion also includes a quantitative evacuation of the impact on expected profits, on

*Government cost was calculated in present value terms as

was private profit. Net cost for each year (i. e., subsidv less increased tax revenues) was discounted at the Government’s discount rate (assumed to be 10 percent in real terms). The resulting present value calculations were summed for all years.

**The marginal tax rate is the rate at which income from an

additional investment (e. g., an oil shale facility) is taxed by the

Government. For most firms, this is 46 percent. However, a

firm wiih excess tax deductions or credits from other operations would apply the excess to the oil shale investment, thereby reducing its marginal tax rate.
Table 23.–Evaluation of Potential Financial Incentives for Oil Shale Development

Effect of incentive on program objectives Extent to which incentive meets policy guidelines

Promotion of Minimization of Promotion of competition

Incentive —-.

Subsidy effect Risk-sharmg effect Financing effect economic efficiency administrative burden Effect on firms Firm preferences

1 Production tax Strong, subsidizes Moderate, shares risk Slight, improves Minimal administrative Benefits firms with

credit ($3/bbl) product price

2 Investment tax Strong, subsidizes

credit (additional investment cost

Slight adverse effect,

distorts product price

Supported by relatively

associated with price un- large firms

certainty (If tax credit varies

with product price)

project economics burden large tax Iiability and

strong financial

capability

Moderate: shares risk

associated with Investment

cost uncertainty

Slight, Improves

project economics

Moderate adverse effect;

distorts input costs,

favors capital-intensive

technologies

Minimal administrative

burden

Benefits firms with

large tax Iiability and

strong financial

capability

Supported very strongly by most firms;

however, firms that

would not be able to

use the investment

tax credit do not favor

its enactment

lo%) %

3. Price supper Strong, subsidizes Moderate; shares risk

associated with price

uncertainty

Moderate; improves

borrowing capability

Slight adverse effect,

distorts product price

Moderate

administrative burden

Benefits all firms

except those with

very weak financial

capability

Moderately supported

by a wide range

of firms

product price (If con

tract price IS higher

than market price)

4 Loan guarantee Slight, subsidizes

Investment cost

Moderate, shares risk of

project failure

Strong; improves

borrowing capability

Slight adverse effect;

distorts input costs:

favors capital-lntenswe

technologies

Slight adverse effect;

distorts input costs,

favors capital-intensive

technologies

Slight adverse effect,

distorts product price

supports)

No adverse effect

Moderate admin -

istrative burden

Benefits firms with

weak financial

capability

Supported by firms

with limited debt

capacity

5 Subsidized Interest Slight; subsidizes

loan (70% debt at Investment cost

3% below market

rate)

Moderate: shares risk of

project failure

Strong, Government

provides capital

Moderate administrative burdenBenefits firms with

weak financial

capability

Supported by firms

with Iimited debt

capacity

6. Purchase Strong, but less than

agreements price supports

Strong: shares risk of price

uncertainty

Moderate; improves

financial capability

Moderate (normally

more than price supports)

Moderate administrative burden

Benefits all btrms but

those with very weak

financial capability

Benefits all firms

Moderate, but less

than for price

supports

7. Block grant (33 & Strong, neutral

50% of plant cost) subsidy

None Strong; Government

provides capital

Supported by firms in

widely varying

financial

circumstances

8. Government Slight

participation

Strong, shares all project

risks

Moderate, reduces No adverse effect on firm Major adminstrative

burden

Benefits firms that are

very averse to risk

(e. g., smaller, less

well-financed firms)

Little support

firm’s capital require- decisions; however,

ment active Government

Involvement may lead

to inefficiency

Slight, improves Moderate adverse effect,

project economics distorts input costs,

favors capital-lntenswe

technologies

9 Accelerated de- Moderate, subsidizes

predation (5 years) Investment cost,

Moderate, shares risk

associated with Investment

Minimal administrative

burden

Benefits firms with

large tax Iiabilities

and strong financial

capability

Supported by large,

integrated oil

maximum subsidy ef - cost uncertainty companies

feet IS Iimited by Federal corporate income

tax rate and interaction with the depletion allowance

10 Percentage deple- Moderate, subsidizes None, Increases risk

tion allowance product price, value associated with price un-

(27%) of subsidy Increases certainty

as the need for the

subsidy decreases

Slight, improves Moderate adverse effect,

project economics distorts product price in

a variable and undesirable manner

Minimal administrative

burden

Benefits firms with

large tax Iiabilities

and strong financial

capability

Not supported

SOURCE Resource Planmng Assoclales Inc
Ch 6–Economic and Financial Considerations ● 197

Table 24. –Summary of Companies Ordinal Preferences for Incentives

Liberalizing

Price Ieasing

Produc - invest - guarantee/ and land

Company tion tax ment tax purchase Loan Low- Block Accelerated Government management Percentage

credit credit agreement guarantee Interest loan grant depredation participation terms depletion

.

Union 0il

Colony project

Tosco

ARCO

Superior

Occidental

RIO Blanco project

Gulf

Standard (Indiana)

SOHIO Natural Resources

EXXON

Standard (California)

Conoco

2

2

1

2

2

1

4

4—

3

3

1 3 4 4 — —

.

.

—

—

1 —

—

—

— —

— —

1 —

— —

— —

3

2

1

4

3—

4

3

3

3

1

4

1

1

1— — —

1

1

— —

— — —

2

2

5

—

1

1

3

3—

4

4

3

3

1—

2

1—

—

2

2

— —

5

2

5

2 1 — — —

— — —

— — —

NOTE Vo compan~ malcated any preference for the Percentage dei)letlon lncentlve

Rank orcered by preference 1 = most preferred elc

SOURCE Resource Planmng Assoclales Inc

Table 25.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (12-percent rate of return on invested capitalb)

Ratio of change

in expected

Total expected Change in Standard profit to

profit c

expected profit deviationdstandard Probability

Incentive ($ million) ($ million) ($ million) deviation of loss

Construction grant (50%) $707 $487 $205 2,4 0.00

Construction grant (33%) 542 321 210 1 5 0.00

Low-interest loan (700/0) 497 277 219 1 3 0 0 0

Production tax credit ($3) 414 194 219 0,9 001

Total Ratio of change

expected in expected

cost to profit to

Breakeven Government Government

price ($) ($ million) cost

$34.00 $494 98

38,70 327 98

43.40 453 61

42.60 252 77

Price support ($55) 363 42 171 0.8 001 NA 172 .83

Increased depletion allowance

(27% ) 360

Increased Investment tax

credit (20% ) 299

Accelerated depredation

(5 years) 296

Purchase agreement ($55) 231

None 220

40 247 0 5 0,05 45.70 197 71

79 216 0.4 0.05 45.80 87 90

76 215 0 4 0,05 46.00 79 96

11 126 0 1 0,03 NA o NA

o 219 0.0 0.09 48.20 0 NA

aAll monetary values are In constanf 1 ’379 dollars

bw,!h 12 percent annual ,nfla~lon a 12 percent real d{scoun[ rate IS approximately a 24-percent nominal aflerfax rate of return The calculahons assume a $35~bbl Price for conventional Premium crude that

escala[es at a real rate of 3 percent per year Thus [he predlcled $48/bbl breakeven price for the 12-percent discount rate WIII be reached In 11 years or {n the fifth year of producf(on Therefore In narrow

econom(c terms 011 shale planls starllng construcflon now which assume a 12-percent dlscounf rate WIII be profitable over the hfe of Ihe project without subsidy ( See discussion for caveats concerning

this conclusion I The calculal!ons are for a 50 000-bbl d plant cosllng $1 7 b[fl(on

cExpecled profl! IS the relurn in excess of a 12 percent discounted cash flow rate of return on !nveslment

dslan~ard devla[lon IS a measure of the dispersion of possible proflf ou~comes around expected Profl~

SOURCE Resource Planmng Assoclales Inc

firm risk reduction, on breakeven prices, and receive a $3/bbl credit on Federal income

on the cost to the Government. taxes. Projects operating after April 20,

1977, and in production between 1979 and

Production Tax Credit 2000, would be eligible. The $3/bbl credit

would be defined in real terms; that is, the

In the 96th Congress (1979), the Senate Fi- credit would increase with inflation. This

nance Committee approved a production tax proposed credit will be phased out on a slidcredit for alternative forms of energy. Under ing scale as the price of imported oil inthis proposal, producers of shale oil would creases.
198 ● An Assessment of 011 Shale Technologies

Table 26.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (l S-percent rate of return on invested capitalb

)

Ratio of change Total Ratio of change

in expected expected in expected

Total expected Change in Standard profit to cost to profit to

profit cexpected profit deviation standard Probability Breakeven Government Government

Incentive ($ million) ($ million) ($ million) deviation of loss price ($) ($ million) cost

Construction grant (50%) .

Construction grant (33%)

Low-interest loan (70%)

Production tax credit ($3)

Price support ($55). ., ...

Increased depletion allowance

(27%) .

Increased Investment tax

credit (20%) ,

Accelerated deprecation

(5years) .

Purchase agreement ($55).

None. . . .,

$281

119

81

- 6 1

- 8 8

$477

315

277

135

108

$135

140

153

153

122

3 5

2,2

1.8

0,9

0 9

0.00

0 1 9

0 2 3

0 6 3

0.77

$40.60

47.70

54.70

58.30

NA

$494

327

453

252

172

96

96

61

.54

63

-110 86 170 0.5 0,75 57.20 197 44

-13 1 65 150 0,4 0.77 58.80 87 75

-12 7

-15 0

-19 6

69

46

0

149

102

153

0.5

0,4

0.0

0 7 6

0 9 2

0.93

58.90

NA

61.70

79

0

0

87

NA

NA

aAll monetary values are In constant 1979 dollars

bwllh 12.0ercent annual Ifltlatlon a 15-oercent real dlscounl rate IS acmroxlmatelv a 27-oercent nominal afteflax rate ot return

cExPec(ed P(ofll IS the return In excess Of a 15.percenl discounted cas’h tlOW rale’of return on Inveslmenl

dstandard devla[lon IS a measure Df (he dispersion of possible profll OUtCOmeS around expected Profll

SOURCE Resource Planmng Associates Inc

This tax credit will strongly subsidize the

production of shale oil. By reducing a firm’s

tax liability, it effectively increases the unit

product price by an amount equal to the tax

credit per unit of production (i.e., per barrel)

divided by 1 minus the firm’s Federal corporate income tax rate. For example, if a company’s tax rate is 46 percent, a $3/bbl credit

becomes an effective price boost of $5.60. At

current imported oil price averages of $35/

bbl, the effective price with the credit would

be $42.60. This price boost could substantially improve a project’s economics by creating a higher aftertax cash flow throughout its

producing life, and a higher return on investment.

ing costs and the resultant project profitability, it may provide a sufficient asset base

against which firms may borrow for project

financing. However, it will not assist project

financing as strongly as a purchase guarantee or a debt guarantee.

The production tax credit also can enhance

economic efficiency, because it does not distort a firm’s perception of the market prices

for the economy’s productive resources (i.e.,

land, labor, capital, and materials), that are

consumed in development and production.

Moreover, if subsidizing oil shale development meets national objectives, this tax credit with a sliding-scale phaseout can be used

by firms as a baseline for making their decisions. To promote efficient investment and

production decisions, the price subsidy afforded by the tax credit should reflect the

premium society is willing to pay to encourage the development of oil shale resources.

Because it works through the existing tax

framework, implementing a production tax

credit should be relatively straightforward,

necessitating little or no administrative overhead. The chief administrative policies would

be to define a reference price for determining

the value of the credit, to set an inflation adjustment formula, and to develop a mechaAlthough the production tax credit does

not share in the risks of project noncompletion or price and cost uncertainties, it would

decrease the risk of incurring a loss by improving project economics. Therefore, it may

slightly improve the ability of firms to acquire

capital financing. However, this tax credit

alone would not encourage financial institutions to lend to a financially less secure oil

shale developer.

A production tax credit has a function similar to a price guarantee. Depending on lender expectations about investment and operat-
Ch. 6–Economic and Financial Considerations 199

nism for ensuring that firms accurately report the amount of shale oil produced. (However, reliance on tax-based incentives would

tend to reduce the Government’s control over

production levels.)

Large, integrated oil companies will most

readily benefit from this incentive (i.e., those

firms having both a sufficient Federal income

tax liability to use the credit and a strong

ability to raise debt). Moreover, in trying to

secure a competitive advantage in the oil

shale development industry, those firms that

have already undertaken investment in oil

shale, and that can accept exposure to the

risks of project noncompletion and investment and production cost uncertainties, may

favor production tax credits over all other incentives,

The production tax credit is supported by

most of the larger firms involved in oil shale

activities. The Atlantic Richfield Co. (ARCO),

Gulf, Union, and Occidental, all companies

with current oil shale investments, rank it

either first or second in their incentives preference lists. However, Standard of Indiana,

which is Gulf’s partner in Rio Blanco, ranks it

last, preferring incentives that deal with the

front-end investment uncertainties. Chevron,

which is just starting its oil shale development activities, directly opposes it in favor of

an investment tax credit that addresses the

investment cost risks, which Chevron feels

are considerable, (See table 24. )

In calculating the quantitative effect of this

incentive, the unit value of the subsidy (established as $3/bbl of unrefined shale oil) was

multiplied by the entire annual output; that

product was then subtracted from the income

tax obligation for each year of production. *

The results indicate that the $3/bbl tax credit

ranks fourth, behind the 50- and 33-percent

construction grants and the low-interest loan,

in its tendency to increase profitability and

reduce the risk of loss. In addition, because

obtaining the tax credit is simpler administra-

*In OTA’S analysis, the tax credit was calculated on shale

oil output prior 10 hvrirotrea t ing. Because of processing losses,

the output of hydrotreatd oil is 12 to 15 percent lower.

tively than obtaining a grant, it might be preferred by some firms.

Expected Profit

In comparison with no incentive, the $3/bbl

tax credit would increase the expected profit

of the 50,000-bbl/d facility by $194 million.

This increase was the fourth highest of the incentives tested. With the tax credit, the expected profit of such a facility would be $392

million, more than enough to induce its development. Moreover, this tax credit would retain its high ranking irrespective of a firm’s

marginal tax rate, unless it has excess tax

credits (i. e., the tax credit expires before the

firm has earned enough income to offset it).

Although some firms might hold excess tax

credits at the outset of production, few, if

any, would hold them over the entire lifetime

of a project, given the eventual large annual

income that can be expected, Therefore, an

excess credit situation would be likely to exist

for no more than a few years of the tax credit’s duration which could be short or long depending on the phase-out provisions.

The production tax credit is highly sensitive to the discount rate, however, because

the subsidy is spread over a project’s entire

lifetime, In fact, over the range of rates

tested, this incentive is one of the most sensitive to the discount rate: averaged over the

discount rates, each percentage point drop in

the discount rate resulted in a $20 million increase in expected profit.

Risk

Because the production tax credit does not

reduce the variation in possible future prices

and costs, it does not reduce the overall variation in possible profit outcomes. However, it

significantly reduces financial risk because it

boosts the expected profit. For this reason,

the production tax credit ranks fourth behind

both construction grants and the low-interest

loan in reducing the probability of loss in the

variation in profit relative to the change in

expected profit.
200 ● An Assessment of 0il Shale Technologies

Breakeven Price

In the absence of an incentive, the breakeven price was $48.20/bbl of hydrotreated

product, with the production credit it was

$5.60 less, or $42.60/bbl. This price ranks

third behind the breakeven prices for 50- and

33-percent construction grants and the lowinterest loans; nonetheless, it is still within

the commercially feasible range, given the

average discounted price of oil—$53.00/bbl

—over the production period.

Cost to the Government

The cost to the Government is commensurate with the credit’s strong effect on profitability. Overall, it is the fourth most costly incentive, ranking below the 33- and 50-percent

construction grants and the low-interest loan.

Moreover, the production tax credit is one of

the least cost-effective (as measured by the

ratio of change in expected profit to Government cost). It ranks below most of the other

incentives, including construction grants.

However, it offers two advantages over construction grants. First, the cost to the Government would be spread more evenly over time;

the production tax credit would require

about $49 million per year over a 20-year production lifetime, compared with $170 million

per year over a 5-year construction period for

the 50-percent grant. Second, it would be

much easier to administer for both oil shale

developers and the Government. Developers

would simply file for the credit on their tax

return, thus making the Government audit of

production records straightforward.

Construction Grant

Under a construction grant program, the

Government transfers a sum of money to a

firm undertaking an oil shale development

project. In return, the firm must only fulfill its

obligation to undertake the project within

some period of time. The size of the grant

would be some prespecified fraction of the investment costs. Alternatively, the Government could hold the inverse of a bonus-bid

lease auction (i.e., firms could bid the amount

required to operate a project capable of producing a specified quantity of shale oil). In

this case, with sufficient competition, firms

would bid on an amount equivalent to the negative expected present value of their projected aftertax income. Instead of bidding a

bonus to be paid to the Government, they

would bid a bonus to be received from the

Government. Those bidding the lowest bonuses, up to some aggregate bonus payout

from the Government, would receive the

awards.

A construction grant would make it possible for otherwise uneconomic projects to

have a profitable, positive expected present

value of aftertax income. The immediate effect of a grant will be to facilitate capital acquisition because less funds probably will be

needed from external sources. * In addition,

over the life of the project, there will presumably be lower debt repayment requirements.

A construction grant reduces the uncertainty

over investment costs but not over operating

costs or product prices. Thus, depending on

its size, a construction grant may significantly reduce the risk of project failure.

Moreover, it may reduce the amount of external financing needed, and because it improves project economics, it enables the firm

to borrow. However, it does not create an

asset on the firm’s balance sheet, and will

thus provide no assurance to lenders of a

firm’s ability to meet its debt repayment

obligations. * *

The construction grant is not economically

efficient since it affects a firm’s perception of

its investment costs, creating a bias in favor

of more capital-intensive projects. Moreover,

once the plant is constructed, output decisions will be based on the market price of oil

rather than the strategic value of domestically produced synthetic fuel. Finally, the construction grant will be costly to administer

*A construction grant program should not be confused with

a loan program or a program to facilitate financing. To assist

financing, the Government should consider a direct-loan or

loan-guarantee program.

*‘Unless a grant is to be paid at a future date and a firm borrows against it in the short term.
Ch 6–Economic and Financial Considerations ● 201

and may result in project delays if not processed expeditiously.

There will be problems in deciding the size

of grants without an auction. A firm can refuse the project if the grant is too small, If the

grant is too large, on the other hand, the firm

would receive excess economic rent* from

the project at society’s expense. To minimize

the cost to the Government, the grant should

equal the absolute value of the negative expected economic rent on the project (plus, for

a risk-averse firm, any risk premium).**

Second, even if the Government uses an

auction to distribute grants, firms will probably collect excess rents at the expense of

society. The grant program shares none of

the risks of oil shale development. If these

risks are as substantial as currently expected, firms may require large risk premiums in their bonuses to ensure against economic loss. Although necessary and efficient

from a firm’s perspective, the risk premium

represents an excessive transfer of income

from the public to the private sector. Also,

unless competition is high and firms have

equal access to technical information, bids

will not be driven down to the level of the negative expected economic rent. In this case,

firms may strategically bid more than this

figure in an attempt to receive higher than

the risk-free required rate of return for

undertaking the project.

The administrative requirements associated with this incentive could delay implementation of an efficient program for several

years. The construction grant is a neutral

subsidy; all firms should be able to use it.

They may, however, dislike the grant on ideological grounds. Those that are more riskaverse will be at a competitive disadvantage

in acquiring grants in an auction (i. e., their

requirement for higher risk premiums will

reduce the probability of winning a grant).

*Excess economic rent here indicates a situation where the

developer has recovered more subsidy than would have been

required to under ttike the project.

**A risk premium is the additional margin of profit required

by a firm in order to undertake development.

Construction grants are supported by firms

of widely varying size and financial condition.

In addition to those with more limited debt capacity, two financially strong companies,

Gulf and Standard of Indiana, also support

this incentive. Gulf supports only limited

grants; its partner in the Rio Blanco development, Standard of Indiana, supports frontend cash construction grants for up to 25 percent of project investment to help offset the

heavy initial capital requirements of early

projects. (See table 24.)

The effects of grants of 50 and 33 percent

of plant cost (estimated to average $1.7 billion including upgrading) were analyzed, assuming that the cost would be incurred over a

period of 6 years and that the Government

would pay its percentage of each year’s cost

at the end of the year in which the cost was

incurred.

On purely economic grounds, construction

grants would be ranked highly by oil shale

firms. Compared with the other incentives,

the 50-percent grant would offer the greatest

increase in expected profit, the greatest decline in risk of loss, and the lowest breakeven

price. The 33-percent grant also compares

well, ranking second in its effect on profitability, ability to lessen the probability of loss,

and breakeven price. For the Government,

however, construction grants would be

among the most costly incentives.

Expected Profit

In the simulations, (see table 25) the 50-percent construction grant yielded an expected

profit of $707 million. When compared with

an expected profit of $220 million when no incentive was employed this represents a gain

of $487 million, the largest of any incentive

tested. The 33-percent grant, although ranking second behind the 50-percent grant, resulted in $321 million in expected profit. Both

grant levels would therefore be more than

adequate to induce private development of

the 50,000-bbl/d oil shale facility.

In assessing the effect of a construction

grant on profitability, an analysis was made

f, 3-83 B - 80 - :4
202 ● An Assessment of Oi/ Shale Technologies

of its sensitivity to a firm’s marginal tax rate

and discount rate. An individual firm’s marginal tax rate was found to strongly influence

the grant’s effectiveness: the higher the rate,

the lower the value of the incentive to the

firm. Because the grant reduces the amount

of investment that is depreciated against corporate income tax, the developer has a higher

taxable income as a result of this subsidy. In

analyzing this incentive, the highest marginal

tax rate (46 percent) was used in the calculations; the value of the grants for firms with

lower marginal tax rates would therefore be

greater than that stated in this report.

It was found that the effect of construction

grants on profitability, however, would depend only slightly on the level of the discount

rate. The results were calculated using a 12-

percent discount rate, * but the expected increase in profit stemming from construction

grants changes very little with discount rates

of 10 and 15 percent. This is because the subsidy is concentrated in the construction

phase, thus is discounted over relatively few

years.

Risk

Because the Government shares so large a

portion of cost, construction grants have a

very pronounced effect on risk reduction. For

the representative facility, the probability of

loss dropped from 9 percent with no incentive

to O percent with both the 50- and 33-percent

grants. Thus, these grants rank highest in reducing the risk of loss. In addition, the construction grants result in the greatest reduction in the variation of profit outcomes (as

measured by standard deviation) relative to

change in expected profit.

Breakeven Price

The 50-percent construction grant also has

the lowest breakeven price, $34,00/bbl of premium syncrude, compared with $48.20/bbl

*On the basis of studies showing that the real, aftertax return for U.S. business averages from 5 to 10 percent, the 12-

percent rate was selected as representative. It reflects the risk

involved in oil shale investment compared with that of the average investment.

when no incentive was offered. The 33-percent grant results in the second lowest breakeven price, $38.70/bbl. Either price would

place the shale oil facility in the commercially

viable range. Given an initial oil price of

$35/bbl, and the expectation that the price

will rise over time (at 3 percent per year in

real terms), the price of oil at the start of production in 1986 would be $42/bbl. It is more

meaningful, however, to compare the breakeven price with a composite price of oil over

the production lifetime—$53.00/bbl.* Because the breakeven prices with both the 50-

and 33-percent grants are less than this

amount, the project would be viable.

Cost to the Government

Construction grants of 50 and 33 percent

would be among the most costly to the Government. In the simulations, the gross cost to

the Government for the 50-percent grant was

$170 million per year for each of the 5 years

of construction. The net cost, however, depends on the marginal tax rate of the recipient. Because the grant would reduce the

amount of investment subject to depreciation,

the Government would recover about onethird of the gross subsidy paid to firms with a

46-percent marginal tax rate, through increased income tax payments. With this tax

rate, the net cost to the Government for the

50-percent grant was higher than any other

incentive—$494 million** and third highest

for the 33-percent grant. However, the construction grants are the most cost-effective,

as measured by the ratio of change in expected profit to Government cost. The net

cost figures, however, do not include administrative costs, which could be significant.

To guard against cost overloading, the Government would have to establish precise accounting guidelines and be prepared to audit

all grant recipients. Furthermore, the grant

*The composite price is a constant price, which when substituted for the escalating market price, does not change the profit calculations (see app. A).

**All Government costs are calculated in present value

terms using a lo-percent real discount rate. This is the rate

adopted by the Office of Management and Budget (OMB) for

evaluating Government programs. (See OMB’S Circular A-95.)
Ch. 6–Economic and Financial Considerations ● 203

application procedure would tend to be timeconsuming for both the Government (complex

auditing procedures would be required) and

the applicant, (a well-documented application

would be required). Alternatively, the Government could simply offer to award $400

million ($80 million per year for 5 years) to

any company that is willing to build a 50,000-

bbl/d plant, the only stipulations being that

the plant must be completed and operated.

Low-Interest Loan

The effects of a low-interest loan are similar to those of a debt guarantee. Its primary

purpose is to assist firms in financing the

large capital outlays required for oil shale

projects. Those that otherwise would be unable to raise sufficient capital would benefit

most from this incentive.

With a low-interest loan incentive, the Government lends money directly to firms at a

lower interest rate than would be provided by

private lenders. The money may be obtained

from general funds, designated taxes (e.g.,

the extra-profits tax currently being considered in Congress), or through a Governmentfinancing authority (similar to the Federal

National Mortgage Assistance Program).

A low-interest loan and a loan guarantee

would have similar effects on project economics. Both would reduce the interest cost

of debt; as a result, the firm would have a

lower payout obligation and higher cash flow

over the life of the project. A low-interest loan

program could have a significant effect on

project economics. It provides access to capital for firms that otherwise could not borrow

in capital markets or that must borrow at

very high rates.

Its risk-sharing features are identical to

those of the loan-guarantee program. As the

direct lender, the Government shares the

risks of project failure and default on debt

repayment. The equity owners of the development firm remain exposed to the risks of project failure and loss of capital. With the lowinterest loan program there is only minor

sharing in the risk of investment cost uncertainty and none in the risks of operating cost

and product price uncertainty. Because the

Government lends directly to the firms, a subsidized interest loan facilitates direct access

to capital for financially weaker firms.

The effects on economic efficiency parallel

those of a loan guarantee. The reduced interest rate serves as a capital subsidy, thus, it

may favor relatively capital-intensive technologies. The primary effect on efficiency is

to encourage participation of a greater number of firms in oil shale development projects.

If increased competition leads to the testing

and development of a wider variety of technologies, future production costs for shale oil

may be lowered.

Because the low-interest loan incentive requires discretionary review and approval of

loan applications, it will be time-consuming

and laborious to administer. Delays in implementing an effective program may be encountered.

The firms that will most benefit from a lowinterest loan program will be relatively weak

financially with limited access to capital markets. If the Government were to make debt

available to all firms at less than market

rates (i.e., rather than at the AAA rate), all,

independent of financial condition, could presumably benefit from the incentive. Like loanguarantee incentives, low-interest loan incentives are preferred by companies with limited

debt capacity because they need subsidized

interest loans to raise project capital.

This type of loan could be structured in a

variety of ways. A loan for 70 percent of construction costs was analyzed. It was assumed

that loan funds would be made available during the years the construction costs would be

incurred (e.g., if construction takes 5 years,

funds would be dispersed over the 5-year

period at the rate of 70 percent of each year’s

cost per year. It was further assumed that the

developer would begin repayment at the end

of the first year of production, that the loan

would be issued at an interest rate of 3 percentage points below the prevailing market
204 An Assessment of 01/ Shale Technologies

rate (e.g., 9-percent nominal interest on the

loan when the market rate is 12 percent), and

that amortization would occur over a 20-year

period.

A low-interest Government loan would be a

very effective incentive, ranking close behind

the 33-percent construction grant and production tax credit in its effect on profitability.

It would act to significantly reduce the risk of

incurring a loss. However, it might be the

most costly to the Government; as such, it

could be less cost-effective than other highranking incentives.

Expected Profit

The subsidized interest loan resulted in an

expected profit of $497 million compared

with $220 million with no incentive. This $277

million increase is less than the increases induced by the 50- and 33-percent construction

grants but more than the $3/bbl production

tax credit. The size of the increase, however,

depends on both the marginal tax rate for individual firms and the access those firms

have to capital markets. For a firm with a 46-

percent marginal tax rate, the 3-percent before-tax difference between the Government’s interest rate and a firm’s borrowing

rate becomes a 1.5-percent aftertax difference, because interest payments are deductible. The aftertax spread would be 2 percent

for a firm with a 3-percent marginal tax rate.

Hence, the lower the marginal tax rate, the

more the loan is worth. In addition, the higher

the rate of interest on alternative sources of

debt financing, the more the loan is worth.

Because different firms may have different

borrowing rates, they might value the Government loan higher or lower than the value

OTA has computed.

Risk

The low-interest loan does not affect the

degree of variation in possible profit outcomes, because it does not reduce the variation in future costs or prices. However, it

does significantly reduce the risk of loss; with

the loan the probability of earning less than

12-percent return was 0.00, but it was 0.09

when no incentive was offered. Moreover, the

loan is effective in reducing the degree of

variation in profit relative to expected profit,

but to a lesser degree than the construction

grants and production tax credit.

Breakeven Price

The low-interest loan resulted in a breakeven price for premium grade synthetic crude

from shale oil ($43.40/bbl) that is only slightly

higher than the price resulting from the production tax credit ($42.60/bbl). However, it is

well below the price prevailing when there is

no incentive ($48.20/bbl), and lower than the

average expected market price over the production period ($53.00/bbl).

Cost to the Government

The low-interest loan costs the Government

more than any other incentive except the 50-

percent grant. It also results in the lowest

change in profit per dollar cost. The gross

outlay for the 70-percent loan is actually

larger than that for the 50-percent construction grant because both are computed on the

same construction costs. Loan repayments

after the completion of the construction

phase would also be higher than the increased tax receipts under the 50-percent

grant program. However, because the subsequent receipts are discounted more heavily

than the initial outlay, the net cost to the Government in present value terms would be almost as great for the 70-percent loan as for

the 50-percent grant. Moreover, it actually

could be higher than has been calculated, because some firms might default on the loan. *

Purchase Agreement

In a purchase agreement, the Government

signs a long-term contract with a prospective

*These conclusions are extremely sensitive to the choice of

Government discount rate. If Government cash flows were discounted at a rate of less than 10 percent, the loan would cost

less. For example, at a 5-percent real discount rate, the cost to

the Government is $2OI million compared with $453 million

when the discount rate is 10 percent.
Ch 6–Economic and Financial Considerations 205

oil shale developer to purchase some quantity

of shale oil or hydrotreated syncrude at a

contract price (either in nominal or real

terms). The Government may set the contract

price directly, negotiate it with firms, or invite contract price bids. If the contract price

is negotiated or set by competition, the Government can selectively apply the incentive to

the most efficient firms by granting the purchase agreement to firms bidding the lowest

contract prices. The Government can always

control the number of firms using the subsidy

by limiting the number of projects and the

quantity of shale oil production covered in

guaranteed price contracts.

The purchase agreement incentive and the

production tax credit subsidize shale oil production by providing (presumably) a higher

price to developers than they would receive

in the open market. Higher prices will benefit

a firm over the life of the project, or until the

specified quantity of shale oil has been purchased.

The purchase agreement reduces project

risk stemming from the uncertainty over future oil prices. Because the product price is

essentially fixed, the Government bears all

the risk of price variations. However, this incentive does not share in the risks of project

noncompletion or investment and operating

cost uncertainties,

It does offer some security to lenders, and

may provide a sufficient asset base for firms

to borrow against. As a result, the prospects

for project financing are improved for firms

with limited ability to raise debt. Like the production tax credit, the purchase agreement

also has distinct economic efficiency advantages. It does not distort the prices of resource inputs and thus encourages firms to

utilize efficiently the Nation’s economic resources. In addition, it does not arbitrarily favor any development technologies based on

differences in capital intensity or required

construction time. Because it works through

the product price mechanism, the extent of

the subsidy for shale oil is readily apparent,

and, in theory, should be set at a level that reflects the social benefit of domestic shale oil

production. Finally, when combined with a

competitive bid mechanism, the purchase

agreement also subsidizes only the most efficient firms.

Despite its advantage for economic efficiency, this incentive imposes significant

burdens on administrative efficiency. The

Government must determine the amount of

shale oil to be subsidized and the contract

price, and it must manage a system for allocating the price contracts. If competitive bidding is used to allocate contracts and set contract prices, managing the auction is another

major administrative requirement. Moreover,

because the mechanisms are less familiar to

industry than for such other incentives as the

tax credit, they will impose higher costs on

firms attempting to use and benefit from

them. Although purchase agreements entail a

considerable amount of administrative burden, its type and extent are strongly dependent on the particular mechanisms employed.

According to this analysis, all firms except

those with very weak financial ability should

be able to benefit from purchase agreements.

Unlike the tax credit, a firm’s ability to use

this incentive is not limited by the size of its

Federal tax liabilities. To some degree, those

that have not yet invested in oil shale development and are strongly averse to the risk of investment cost uncertainty may find this incentive less attractive than the investment

tax credit and the loan guarantee.

Expected Profit

In the simulations, a purchase agreement

of $55/bbl resulted in an expected profit of

$231 million compared with $220 million with

no incentive. The $11 million gain in profitability ranks behind gains achieved with all

the other incentives tested. The effect on

profitability is less than that of the $55/bbl

price support, because with the price support

a firm benefits when the price exceeds $55/

bbl (this occurs in the ninth year of production, assuming a 3-percent annual price increase). The subsidy effect of purchase

agreements (and also price supports) is tied to
206 . An Assessment of Oil Shale Technologies

the contract price. At such price, the purchase would cost the Government nothing.

However, its subsidy effect is also low. The

use of a higher contract price would have

substantially increased its incentive impact.

Risk

Because it eliminates all variations in

possible future prices, the purchase agreement results in a large reduction (25 percent)

in variations in possible profits. However, it

does not reduce the probability of loss as

much as the price support, because a company cannot benefit from upward variations in

price above the purchase agreement price.

Breakeven Price

Because this incentive establishes a minimum price above the breakeven price when

no incentive exists, there is no meaningful

breakeven price under the price support or

the purchase agreement.

Cost to the Government

At no direct cost, the purchase agreement

was the least costly incentive for the Government. Government costs are incurred from

the first year of production until the market

price equals or exceeds the fixed purchase

agreement price, If the market price increases over time, the cost to the Government

declines, and if the market price exceeds the

fixed price, the Government will regain part

of its subsidy through low-cost purchases of

shale oil. It can also recapture part of the

subsidy through the increased taxes that result from a developer’s larger taxable income. In analyzing this incentive, a high marginal tax rate for the company was assumed;

the cost to the Government would be higher

than calculated here if the company had a

lower marginal rate.

Price Support

A price support is currently being considered in several proposals before Congress. It

is similar to a purchase agreement, except

that the Government does not take title to the

shale oil; it simply pays the difference between the support price and the prevailing

free-market price. If the free-market price exceeds the contract price, the Government

pays nothing. The price support, like the purchase agreement and the production tax

credit, subsidizes shale oil production since it

is presumed to have a probability of being

higher than the market price of imported oil.

The effects on project risk and efficiency of

the price support are similar to those of the

purchase agreement: it reduces the risk of oil

price uncertainty, it improves access to debt

capital, and it improves project economics.

Like the purchase agreement, the price support entails significant administrative costs.

However, in general, those associated with

price supports are lower than those for purchase agreements.

Expected Profit

In the simulations (see table 25), a $55/bbl

price support resulted in an expected profit

of $363 million, which is more than enough to

induce a profit-maximizing firm to undertake

an investment in oil shale. The level of profit

presents a gain of $142 million over the case

in which no incentive is offered, placing the

price support midway in the ranking.

As with most of the other incentives, the

expected profit for individual firms using the

price support will depend on their marginal

tax rates. The price support will be worth

less to firms with high marginal tax rates

than to those with low marginal tax rates,

because the subsidized price increases taxable income.

Expected profit is also very sensitive to a

firm’s discount rate, because the price support begins only after the start of production

and continues for a number of years. The expected profit gain under this incentive varies

more with changes in the discount rate than it

does with a construction grant. On the other

hand, the price support represents a relatively larger sum in the early years of production

(assuming increasing oil prices) compared
Ch. 6–Economic and Financial Considerations ● 207

with the constant tax credit. Thus, the $55/

bbl price support is somewhat less sensitive

to changes in the discount rate than is the

$3/bbl production tax credit.

Risk

The price support is effective in reducing

risk because it eliminates the possibility of a

price for oil below the floor price. By reducing the variation in possible future oil prices,

it reduces the total variation in possible profit

outcomes. In the simulations, the variation in

profit with the price support was reduced by

over 20 percent compared with no incentive.

Given this reduction and the increased expected profits, the probability of incurring a

loss drops from 0.09 with no incentive to 0.01

with the $55/bbl price support. This reduction in risk is only slightly below that for construction grants, the low-interest loan, and

the production tax credit. (See table 25.)

Breakeven Price

Because this incentive establishes a minimum price above the breakeven price when

no incentive exists, there is no meaningful

breakeven price under the price support or

the purchase agreement.

Cost to the Government

The price support, which ranks fifth in its

net cost to the Government, would be spread

over most of the production life of the facility,

with a larger share in the early period if the

price of oil continues to rise. In the analysis,

the net cost figure of $172 million, which accounts for the partial recovery of the gross

subsidy through increased income taxes, was

calculated using a 46-percent tax rate. The

cost of this incentive to the Government

would be higher in the event of lower marginal tax rates.

Investment Tax Credit

Several oil shale developers view the investment tax credit as one of the most desirable incentives. These firms have indicated

that an additional 10- or 15-percent investment tax credit would be particularly attractive. (See table 24.)

Like the production tax credit, an investment tax credit strongly subsidizes the production of oil shale. Under current tax accounting procedures, it effectively reduces

the cost of an investment by the percentage of

the tax credit. That is, firms can deduct a

specified percentage of their capital costs

from their income tax liabilities during the

first year in which the project operates.

When construction is scheduled over several

years, a firm’s actual benefit is reduced by

discounting because the tax credit is not

taken until the project begins operation. The

investment tax credit increases net cash flow

early in the life of the project when companies often need such a boost. However, depending on the dollar value of the investment

tax credit relative to a firm’s tax liabilities, it

may take several years to fully utilize the tax

benefit if other revenues are not available on

which to use the tax writeoffs.

By reducing investment costs by a specified

percentage formula, the investment tax credit reduces the variance in investment cost,

and allows the Government to share in the

risk of capital-cost uncertainties. In the early

stages of oil shale commercialization, capitalcost uncertainty will be a major source of

risk,

As investment costs increase, the share

paid by the Government increases in proportion to the percentage rate of the tax credit.

Conversely, as investment costs decrease, the

Government’s share decreases. The investment tax credit does not share in the risks of

project noncompletion and price and operating cost uncertainties.

Although an investment tax credit will enhance a project’s profitability and return on

investment, it cannot overcome the financing

problems of firms with limited debt capability. Unlike the production credit, it does not induce lenders to provide the substantial

amounts of capital required for oil shale development.
208 . An Assessment of Oil Shale Technologies

The effect of the investment tax credit on

economic efficiency is less desirable than the

production tax credit, for several reasons.

First, it interferes with a firm’s perception of

the market prices for the resources used in oil

shale development. This incentive subsidizes

investment costs only, and so favors the more

capital-intensive development technologies.

In addition, because the value of the tax benefit decreases as the length of the construction

period increases, an investment tax credit incentive favors development technologies with

relatively short construction leadtimes.

Because the investment tax credit has been

part of the tax structure for several years, it

is particularly easy to implement. Analysis

has indicated that large, integrated oil companies (i.e., firms with large tax liabilities

and strong financial capabilities) will prefer

and benefit most. By inference, firms that

prefer an investment tax credit to a production tax credit are more averse to the risk

associated with investment cost uncertainty

than to the risk associated with product price

uncertainty.

Expected Profit

In simulating the impact of a simple IO-percentage point increase* in the investment tax

credit, it appeared unlikely that it would increase the profitability of oil shale ventures

enough to induce their development. In the

quantitative analysis, the hypothetical facility had expected profits of $299 million compared with $220 million without an incentive.

On the basis of the effect of profitability, the

increased investment tax credit ranked near

the bottom, above accelerated depreciation

and the purchase agreement.

The investment tax credit’s effect on profitability (like the production tax credit) is not

sensitive to the marginal tax rate unless a

firm has excess credits at the time the increased tax credit expires. However, unlike

the production tax credit, the investment

credit is claimed over a short construction

*The existing investment tax credit has an additional IO-percent tax credit for energy investment, However, this credit was

ignored in the calculations because it was due to expire in

1982.

period rather than a long production period.

Therefore, its value is relatively more sensitive to a firm’s overall tax credit situation.

This credit is, however, relatively insensitive

to a firm’s discount rate because all the tax

credit would be claimed early in the life of the

project and would thus be discounted over

relatively few years.

Risk

The investment tax credit was found to

have a slight effect on the risk of loss but virtually no effect on the variability of profit outcomes. With this incentive, the probability of

a loss dropped to 0.05, the same level as the

increased depletion allowance and accelerated depreciation.

Breakeven Price

At $45.80/bbl, the breakeven price of the

investment tax credit was slightly higher than

that of the increased depletion allowance

($45.70/bbl), and not significantly less ($2.20)

than the breakeven price with no incentive.

Cost to the Government

For this incentive, the cost to the Government ($87 million) was among the lowest,

ranking just above accelerated depreciation.

Compared with the depletion allowance, however, the cost of the tax credit would be incurred over a shorter period of time.

Accelerated Depreciation

Accelerated depreciation for tax accounting has been discussed by several firms as a

possible incentive for encouraging development projects. For example, they have suggested that oil shale investments be deducted

from income over a period of 5 years instead

of 10 to 15 years, as is now expected. Some

firms have even suggested the possibility that

the entire oil shale investment could be written off in the first year of project operation.

Accelerated depreciation functions similarly to an investment tax credit. It provides a

modest subsidy for development. However, in
Ch. 6–Economic and Financial Considerations ● 209

comparison with an investment tax credit, accelerated depreciation will have a weaker,

only moderate subsidy effect, which is limited

by the firm’s marginal income tax rate and

the interaction of depreciation with depletion

in tax computation procedures.

Shortening the period over which investment costs may be deducted from pretax income increases the present value of the tax

deductions and, thus, will lead to a higher

return on investment for a project. In addition, accelerated depreciation would improve

cash flow in the early years of a project’s

operation when firms are often short of cash.

In effect, the Government pays an increased

share of the investment cost through reductions in income tax liability. The share paid is

the present value of depreciation deductions

multiplied by the firm’s Federal income tax

rate, which thereby sets a ceiling on the subsidy effect of this incentive. The maximum

benefit would be obtained with an instantaneous writeoff; in this case, the share paid by

the Government would be equal to 0.46 multiplied by the cost of the investment (assuming

46 percent of the firm’s corporate income tax

rate).

However, the subsidy effect of accelerated

depreciation could be limited by the interaction of depreciation and percentage depletion

in computing Federal income tax liability.

Percentage depletion is a deduction from taxable income that is determined as a percentage of gross production revenue in any year.

However, the maximum deduction for percentage depletion allowed in any year is 50

percent of net income after subtracting all

other deductibles allowed by the Internal

Revenue Code. Such deductibles include depreciation. Thus, increasing the depreciation

allowance in any year would reduce the income ceiling on the depletion allowance and

could reduce the deduction allowed for percentage depletion. In this case, the benefit to

a firm from accelerated depreciation would

be somewhat offset by the reduction in the

tax benefits of percentage depletion,

Through accelerated depreciation, the

Government shares in the risk stemming from

the uncertainty of investment cost. In effect,

it pays a percentage share of the investment

costs of a project, thus reducing their variation. It has no effect on the risks stemming

from the possibility of project failure and the

uncertainty of production cost and price,

Accelerated depreciation will improve

project economics but, by itself, is not sufficient to facilitate a firm’s access to debt

markets. It does not provide an asset against

which firms may borrow.

Accelerated depreciation has a negative

effect on economic efficiency. * It interferes

with the perceived prices of the resource consumed in oil shale development. Because it

functions as a capital subsidy, it will favor

the more capital-intensive technologies. It

will not affect the production signal provided

by product price. Moreover, like the investment tax credit, accelerated depreciation

does not function through an easily observable mechanism (e. g., product price). Therefore, it will be relatively difficult for society

to ascertain the magnitude of the premium it

is paying to develop domestic oil shale resources.

Depreciation, which is familiar in tax accounting, would probably entail a minimal administrative burden to implement.

Large, integrated firms with strong financial positions will benefit most from this incentive. Their pretax income and tax liabilities from other business activities are sufficiently high that the accelerated depreciation

writeoffs can be taken as they become available. In addition, unless the accelerated depreciation is made retroactive, firms that

have not yet invested in oil shale development

will have a somewhat stronger preference for

this incentive than firms that have made investments with a longer depreciation schedule.

‘This assumes that the existing depreciation period is efficient. In actuality, depreciation probably inefficiently biases

against capital-intensive projects. Shortening the ciepreciat ion

period reduces some of this bias and hence promotes efficiency.
210 ● An Assessment of 0il Shale Technologies

Expected Profits

In the simulations, the accelerated depreciation schedule induced an increase in expected profit of $76 million, which was the

second lowest figure for any incentive tested.

The effect of accelerated depreciation on

profitability depends greatly on the tax situation of a firm: it will benefit firms with higher

marginal tax rates more than it will benefit

those with lower rates. This difference arises

for two reasons. First, the amount of tax savings for a given amount of depreciation is

directly proportional to a firm’s tax rate. Second, a firm with a high marginal tax rate and

with other income-producing investments will

be able to write off the depreciation against

other income, whereas a firm with a low tax

rate will be likely to have excess deductions.

In the latter case, the increased depreciation

deductions must be carried forward and are

thus worth less, through discounting, than

they would be if they could immediately offset

taxable income.

The value of this incentive is also affected

by the discount rate. The effect is slight,

however, because both the tax writeoff and

its timing are small. A 3-percentage point increase in the discount rate produced only a

lo-percent reduction in the change in expected profits.

Risk

Accelerated depreciation was found to

have little effect on the risk of oil shale investments. In the simulations, the probability

of incurring a loss did not drop significantly

nor did the absolute variation in possible

profit outcomes. Relative to change in expected profits, the variation in profit was

next to the lowest, ranking above the purchase agreement.

Breakeven Price

By analysis, the breakeven price with the

5-year depreciation incentive was found to be

$46.00/bbl compared with $48.20/bbl for the

12-year depreciation. This reduction in

breakeven price was the smallest of any incentive tested.

Cost to the Government

Of the incentives tested, accelerated depreciation is one of the least costly to the

Government and one of the most cost-effective. In the simulations, the net cost to the

Government was $79 million, and the ratio of

change in expected profit to the Government

was 0.96. Moreover, because the incentive is

granted through the existing tax system, the

cost of its administration would be negligible.

(See table 25.)

Increased Depletion Allowance

An increased percentage depletion allowance has been discussed as a possible incentive for encouraging oil shale development.

Firms have suggested that the percentage depletion allowance be increased to 25 or 27

percent.

The primary effect of an increased percentage depletion allowance would be to subsidize the economics of oil shale development.

Specifically, increasing the depletion allowance will increase the share of production

revenues that are shielded from the Federal

corporate income tax. The depletion allowance, like a product-price increase, will improve a firm’s cash flow throughout the producing life of a project. As a result, a firm’s

return on investment for a project is improved.

The depletion allowance might be assumed

to be as effective an incentive as the production tax credit because both function through

the price mechanism. However, it has several

undesirable characteristics as a subsidy. The

presumptions underlying its use as an incentive are that oil shale development is uneconomic and that the increasing (effective)

product price is the appropriate vehicle for

its subsidization.

To be an efficient subsidy through the price

mechanism, the value of the price subsidy

should decrease as the product price in-
Ch. 6–Economic and Financial Considerations ● 211

creases (i. e., as the need for the subsidy

decreases). However, the percentage depletion allowance has the reverse effect. As the

product price increases, the value of the

price subsidy also increases. Conversely, as

the product price decreases and the need for

the subsidy increases, the value of the subsidy actually decreases. This effect will make

it impossible to maintain the subsidy at a desired level.

In addition to its undesirable subsidy effects, the percentage depletion allowance has

poor risk-sharing characteristics. In fact, it

increases the risk associated with the uncertainty about future shale oil prices. Because

the value of the price subsidy increases with

the product price, this incentive magnifies the

effects on a firm of changes in the product

price. The variance of aftertax income increases as the percentage depletion allowance is increased. This incentive does not

share in the risks either of project failure or

of the uncertainties of investment and operating cost. The depletion allowance will improve project economics but will not significantly influence a firm’s ability to raise debt.

The effect of the percentage depletion allowance on economic efficiency is similar to

but more adverse than the production tax

credit. It does not affect the prices of resource inputs. Consequently, resources

should be combined in an economically efficient manner and a firm’s preference for specific oil shale development technologies

should not be influenced. However, in effect,

it alters the price perceived by a firm and

thus will influence its production and investment decisions. Moreover, the contrary manner in which the subsidy effect increases as

product price increases will make it difficult

for the Government to use this incentive to

promote efficient decisions that reflect the

social benefits of shale oil production.

Like accelerated depreciation, percentage

depletion is a familiar component of the U.S.

tax code, and would thus be very easy to apply. The firms that will benefit most from an

increased depletion allowance will be those

having large before-tax income and large tax

liabilities. Moreover, by inference, firms that

prefer an increased depletion allowance are

relatively unconcerned about risk of future

decreases in product price. Rather, they are

apparently betting in favor of continued longterm increases in the price of imported oil. No

firm seriously advocates this incentive. (See

table 24.)

In analyzing this incentive, an increase in

the depletion allowance from the current 15

to 27 percent was assumed. Such an increase

would be a significantly less effective incentive than the construction grants, the production tax credit, the low-interest loan, the

price support, or the purchase agreement.

Compared with these other incentives, the increased depletion allowance would result in

a much smaller gain in expected profits and

only a slight reduction in the risk of incurring

a loss.

Expected Profit

The increased depletion allowance resulted in a comparatively modest gain in expected profit—$140 million—compared with

no incentive. Because firms cannot claim

depletion deductions in excess of 50 percent

of taxable income, increasing the depletion

allowance above 27 percent does not result in

significant additional expected profit.

For firms with lower marginal tax rates,

the gain in expected profit would be even

smaller. In the simulations, for example, the

$140 million gain in profitability calculated

using a 46-percent tax rate would be reduced

to only $70 million if the tax rate were 23 percent. (See table 26.)

The effect of an increased depletion allowance on profitability is also more sensitive to

the discount rate than any other incentive

tested. This sensitivity stems from the increase in the incentive’s value that accompanies the increase in the real price of oil (and

hence revenues). Thus, a higher value in later

years is more sensitive to discounting than a

value that remains constant over time (as the

production tax credit does, for example).
————.——..—

212 An Assessment of 0il Shale Technologies

Risk

Although a higher depletion allowance actually increases the variation in possible profits, the gain in expected profits results in a

small reduction in the probability of loss. In

the simulation the 27-percent depletion allowance reduced the probability of loss to 0.05,

compared with 0.09 when no incentive was

employed. The increase in the variability of

profit outcome occurs because profits are

more sensitive to changes in future prices

with the higher depletion allowance.

Breakeven Price

Although the increased depletion allowance will result in a reduced breakeven price,

this reduction is likely to be small. In the

simulations, the breakeven price fell from

$48.20 to $45.70/bbl. (See table 25.)

Cost to the Government

The cost of this incentive to the Government is commensurate with its effect on expected profit. In the analysis, the increased

depletion allowance cost $197 million, which

makes it the fifth most costly incentive. Moreover, it is not a cost-effective option since it

results in the second lowest ratio of change in

expected profit to Government cost.

Loan Guarantee

Under a loan-guarantee incentive, which

has been frequently discussed in Congress

and by oil shale developers, the Government

guarantees to lenders to repay a specified

portion (e.g., 50 to 70 percent] of the project

debt if a firm defaults on its debt payments

because of the economic failure of its oil shale

project. A loan guarantee would be administered selectively by a Government agency

without charge or for a fee. Under a fee arrangement, a firm effectively buys an insurance contract to guarantee debt repayment,

A loan guarantee is primarily designed to

facilitate project financing and, as a result,

has only a limited subsidy effect on the economics of oil shale development. Indeed, the

only effect on project economics is to reduce

the interest rate on debt for firms with low

bond ratings. Thus, over the life of a project,

a firm’s debt service obligation will be somewhat reduced. A loan guarantee will be of little or no value in improving project economics

for firms with strong balance sheets that can

borrow at low rates.

This type of incentive requires the Government to share directly in the risks both of

project failure and of default by a firm on its

debt obligations. However, as long as a firm’s

equity contribution to total project investment

remains at a reasonable level (e.g., 40 percent or more), a loan guarantee does not unduly shield a firm from economic loss (i.e., the

incentive does not introduce moral hazard). *

In the event of default, the loan guarantee

does not protect equity owners against loss.

As a result, it encourages management to

operate in an economically efficient manner,

and provides only weak protection from the

risk of investment cost uncertainty—but only

if it is for a percentage share of the capital required for the project and if the firm can borrow at a lower interest rate than would otherwise be possible. A loan guarantee does not

share in the risks of operating cost and product-price uncertain y.

Of all the incentives that provide for private lending, it has the strongest effect in improving the ability of firms with limited debt

capability to borrow in capital markets. By

guaranteeing the fulfillment of a specified

portion of a firm’s obligations, the loan-guarantee program provides an asset that financially weaker firms may borrow against.

Given its limited effects on project economics, a loan guarantee has relatively minor effects on efficiency. It acts as a capital subsidy and so may favor more capital-intensive

technologies. It does, however, improve competition in oil shale development by removing

a major barrier to entry for less well-fi-

*Moral hazard would exist if the guarantee was constructed

as to eliminate so much corporate risk that project failure is encouraged+
Ch 6–Economic and Financial Considerations ● 213

nanced firms. Enhancement of competition

may lead to testing a broader set of technologies, and in the long run may result in higher

overall efficiency by reducing production

costs.

This incentive will present certain administrative problems, even though the Government has previously used loan-guarantee programs. A firm’s application must be selectively reviewed and approved, thus increasing

the potential for delay.

The loan-guarantee incentive benefits

smaller companies with an insufficient asset

base to back the major debt requirements for

undertaking an oil shale development project

(i.e., companies with a limited capability to

raise debt that would otherwise have to borrow at higher interest rates or be excluded

from oil shale development). In addition,

larger companies with a large asset base but

also large debt (i. e., a high debt/asset ratio)

may also need guarantees to embark on an oil

shale project. With the increasing debt/equity

ratios evident in the petroleum industry, a

growing number of firms fit this description.

Those with a strong balance sheet and large

asset base will not benefit from a loanguarantee program, and for competitive

reasons may not prefer its implementation.

Loan guarantees tend to be preferred by

firms that have limited debt capacity. Superior Oil backs them in principle, believing that

they will help some companies obtain financing to get their plants started. The Oil Shale

Corp. (Tosco) reported that it would need

them to obtain financial backing, and SOHIO

Natural Resources, a subsidiary enterprise

with limited debt capability, claims it could

also take advantage of them. Occidental, a

considerably larger firm, advocates any and

all types of loans or loan guarantees, especially nonrecourse loans. As would be expected, the largest and financially strongest

companies find loan guarantees less desirable. (See table 24. )

Government Participation

Government participation has been discussed as part of several bills being considered in Congress. Although it has certain

fundamental advantages if the primary purpose of an oil shale incentive program is to

share risk, it would meet strong resistance on

ideological grounds, and would be extremely

difficult to administer. Moreover, it may lead

to inefficiency in oil shale development and

production activities.

A Government participation program is

based on the assumption that oil shale development is economically sound but has very

high risks. Because of these risks, private

firms are assumed to be reluctant to undertake projects, or willing to undertake them

only with the expectation of high profits on

their investment to cover their risks. Government participation would provide a mechanism for it to share risks with private firms

thus encouraging them to commit capital to

oil shale projects.

In such a program, the Government would

provide a specified share of equity. From that

point on, it would simply be an equity partner

in the project and would share proportionately in any project losses or profits. Depending

on the terms of its agreement, the Government could either be a silent partner or participate in management decisions. The partnership could be managed through an existing agency or a separate, newly formed administrative unit (e.g., the proposed Energy

Security Corporation).

Because Government participation is simply a joint venture arrangement between the

Government and private firms, this incentive

would not provide any significant subsidy to

oil shale development. It would, however,

have the strongest effect of all the incentives

on the sharing of risk between public and private sectors. In this program, the Government

would share in the risks associated with all
214 An Assessment of 011 Shale Technologies

project uncertainties in proportion to its percentage ownership in a project. When the

project showed a loss, the Government would

lose; when it showed a profit, the Government

would win. Government participation would

reduce a firm’s exposure to economic loss. At

the same time, it would decrease the potential

gains for a firm. That is, the variance in a

firm’s expected present value of aftertax income would be proportionately reduced by

the multiple (1 – SG)2

, where SG equals the

share of Government ownership.

The extent to which Government participation would assist a firm in raising debt will

depend on the terms of its involvement in a

project. If the Government does not agree to

guarantee a firm’s project debt, its participation would have little effect on the firm’s

ability to borrow. Debt-financing support

would still come from the firm’s own asset

structure. Alternatively, if the Government

provided a share of project debt or guaranteed a share of project debt, a firm’s debt requirements would be reduced, and loans

could be more easily acquired.

A Government participation program

would have essentially neutral effects on the

economic efficiency of private sector investment and operating decisions. By simply creating a partnership or joint venture, the incentive neither changes cost or prices, nor

provides a project subsidy. * The primary effect of this incentive on economic efficiency

would be to reduce the effects of private sector risk aversion. However, economic efficiency may decrease if the Government decides to operate as an active partner in oil

shale development projects. Efficiency would

be reduced if Government participation, as a

result of inexperience or bureaucratic interference, contributed to inefficient managerial

decisions.

A Government participation program

would entail the greatest administrative burden of all incentives. A new Government bureaucracy would probably have to be created

*In theory, a Government participation program would be

combined with a block grant program to achieve a highly effective subsidy and risk-sharing incentive program.

to manage the program, with the likelihood of

lengthy delays in getting the program to operate effectively.

OTA’s analysis indicates that Government

participation would most benefit firms that

are relatively risk-averse, thus unable to finance an oil shale development project alone.

However, because private firms may join together in partnerships, there may be no incentive for them to enter a joint venture with

the Government as an active partner. If the

Government adopted a silent-partner role,

however, a firm could take full managerial responsibility for a project, while still receiving

the risk-sharing and financial benefits of the

joint venture. Such an arrangement is not

usually possible with any other private partner.

All firms except one oppose the Government participation incentive, primarily because of their fears of bureaucratic inefficiencies, of support of one technology to the

exclusion of another, and of administrative

problems. The only advocate, SOHIO, has

sought $15 million in Government appropriations to help fund its already approved fullsized module program.

The Government could also contract for the

construction of several modular plants it

would then operate, either alone or through

contracts. It could thus conduct operations to

obtain accurate information about technical

feasibility, project economics, and the relative merits of different processes. This would

be of assistance in evaluating its future policies toward oil shale, in disseminating technical information, and in improving its understanding of the value of its oil shale resources. After enough information had been

obtained, the facility could be scrapped or

sold to a private operator. This policy would

provide the Government with information and

experience. However, the cost would be much

higher than that of incentives to private developers.

Considering that the technologies to be

tested are proprietary, it is by no means clear

that the Government would have the legal
Ch. 6–Economic and Financial Considerations 215

right to publish all of the information. In addition, its experience in designing, financing,

managing, and obtaining permits for an oil

shale plant may not resemble that of private

industry. Thus, the information acquired may

be of little use to subsequent private developers.

Most of the information secured through

Government ownership could be made available as a condition of granting financial incentives to private firms. Furthermore, this

kind of Government intervention is likely to

discourage private developers from undertaking their own modular development and

R&D programs. Government programs of this

kind tend to reduce the benefits that a particular firm could obtain from R&D or modular testing. Finally, the information argument

tends to disregard the fact that patented and

licensed technologies make definite provision

for the dissemination of technical information

on both gratis and fee terms to possible users

of a process.

Government Ownership Versus Incentives for Private Development

Several factors favor incentives for private

development. One is the amount and timing of

Government financial support. With Government ownership, Treasury funds would be

used to supply front-end money during the

construction period. This would involve very

large initial outlays. With private ownership,

incentives such as loan guarantees, purchase

agreements, and production tax credits

would reduce and delay budget outlays much

more than would be possible with Government ownership. Furthermore, Government

expenditures would be spread over the life of

the project. Only the failure of a project insured by a debt guarantee would obligate the

Government for more than a small fraction of

plant cost. As noted previously, fee-based

guarantees would reduce this risk.

Another factor favoring private development is that limited incentives would encourage more efficient operation by leaving managerial and cost risk intact. Cost-plus contracting for a Government-owned facility could not

be expected to encourage efficiency. Incentives must be limited, however, because management efficiency would decline under high

levels of Government subsidy.

A final factor is that private ownership

and operation would develop industrial experience in designing, licensing, financing,

building, and running an oil shale plant. Government ownership may not realistically simulate industrial experience. The regulatory,

financing, litigation, and managerial experiences encountered by Government are usually much different from those of industry.

Constructing an oil shale plant requires

committing major physical and financial resources that would become unavailable for

other purposes. Under the private option,

funding would be diverted from alternative

private investments and consumption. The

Government option would, in the absence of

higher taxes or funding through revenue

bonds, either raise the Federal deficit or

withdraw funds from other programs.

Which Incentives Are Most Efficient and Effective?

As the above discussion of alternative fi- ations. In general, all incentive programs

nancial incentives indicates, there is no single must be properly administered in order to be

“best” subsidy. Firms in different circum- effective, This is particularly true of nontax

stances will tend to require different kinds of subsidies such as low-interest loans, debt

incentives to avert the risks that prevent guarantees, price supports, and purchase

them from undertaking commercial oper- agreements. These entail much greater ad-
216 ● An Assessment of 0il Shale Technologies

ministrative involvement than do tax credits,

accelerated depreciation, or increased depletion allowances. The absence of close supervision of nontax incentives can lead to oversubsidizing developers. On the other hand,

the creation of bureaucratic mechanisms

that are extremely time-consuming and complicated, or which make the acquisition of the

subsidy or its level dependent on future

events that the developer cannot foresee, will

radically reduce the subsidy effect of the incentives.

OTA has concluded that production tax

credits, purchase agreements, and price supports are the most viable subsidy mechanisms

to employ if the Government decides it is

necessary to provide financial incentives.

The subsidy effect of the purchase agreement

and price support incentives are relatively

low for the contract price ($55/bbl), which

was computer simulated in the present analysis. This should not detract from the qualitative merits of these incentives. Furthermore,

this analysis indicates that either loan guarantees or low-interest loans will be necessary

to ensure significant participation by smaller

or even moderately sized firms. The high cost

of providing low-interest loans suggests that

debt guarantees would be the best mechanism through which to ensure this participation.

Are Financial Incentives Needed?

The rationale for providing financial incentives is that hastening the commercialization

of oil shale technologies, which although not

immediately viable would probably be capable of commercialization at a later date,

serves the long-run economic and national interests of the United States, The assumptions

underlying this argument are that capital requirements, remaining technical uncertainties, risk of cost overruns, unstable regulatory environments, and uncertainties about

present or future profitable marketability indicate to developers that their capital would

be more profitably employed in alternative investments. An incentive or subsidy alters the

economics of commercial production by attempting to either sufficiently reduce the risk

or raise the profitability to encourage development.

Whether and to what extent oil shale development will require subsidization depends

on the present and anticipated future relationship between oil prices and the cost of

producing shale oil. Expectations concerning

these future trends involve a consideration of

such factors as: the developer’s confidence in

the accuracy of shale oil plant cost estimates,

world petroleum demand, OPEC cartel pricing decisions, the political stability of foreign

oil supply, and the rate of profit a company

requires to justify its investment relative to

alternatives.

Assuming that developers have some confidence in their present estimates of plant

costs, and that these estimates contain contingencies for regulatory delay and environmental litigation, then the primary consideration becomes the ability to market at an acceptable rate of return. Developers base their

evaluation of marketing potential on the required rate of return and the feasibility of obtaining this return given the price of competing OPEC crude. Until very recently, it was

accepted that the commercialization of shale

oil would require some form of subsidy.

In narrow economic terms it is no longer

clear that shale oil requires subsidy to compete profitably with conventional petroleum.

Price hikes during the end of 1979 and the

beginning of 1980 have increased average

posted spot prices for foreign and domestic

crudes by more than 30 percent. Wyoming

Sweet and the best grades of North African

crude now have posted prices of between $34

and $38/bbl. The spot-market prices for these

oils are between $40 and $50/bbl.

If it is assumed that developers require no

more than a 12-percent real return on their

investment, and that current capital and
Ch. 6–Economic and Financial Considerations 217

operating cost estimates are reliable, then

shale oil could probably be produced and

marketed profitably without subsidy. Predicted decreases in next year’s OPEC exports

(3 million bbl/d) along with the expectation of

continued real price increases of at least 3

percent per year, reinforce the belief that the

market outlook for shale oil will continue to

improve in the future. However, ruling out the

need for financial incentives would be unwise

for several reasons.

First, the present competitiveness of shale

oil assumes realistic capital and operating

cost estimates. For the reasons discussed

earlier in this chapter, this is still a risky

assumption, and construction and operating

costs are still escalating. Since a commercial

or modular facility has never been constructed or operated, scaling-up the technology will almost certainly add hitherto unforeseen costs as technical problems—even minor ones—are encountered. If it takes place

in the context of commercializing or deploying a large number of synthetic fuel plants,

the shortage of already scarce equipment

such as valves, compressors, and heat exchangers can be expected to further inflate

construction costs. World oil price increases

in excess of the 3- or 4-percent real annual

growth assumed by developers would push

construction costs up still further.

Second, the present competitiveness of

shale oil assumes that developers are willing

and able to accept an anticipated real discount rate (i.e., rate of profit) of 10 or 12 percent on an inherently risky investment. Given

the nature of the risk, it is questionable

whether developers would be willing to undertake the investment at this rate.

Finally, shale oil’s emerging competitiveness is related to recent oil price increases. If

these increases contribute to recession in the

industrialized West, petroleum demand can

be expected to decline. This could reduce

prices in real terms, thus reducing the competitiveness of shale oil. In the longer term,

however, it should move to parity with conventional crude as a result of dwindling oil reserves. However, shorter term price declines

could take place as they did during the years

immediately following the oil embargo of 1973

to 1974.

In the consideration of appropriate incentives, this relative change in the competitiveness of shale oil implies that emphasis should

be placed on the desirability of incentives

that help with financing, while reducing the

risk of extreme OPEC selling price reductions

in real terms. Debt guarantees, price supports, and purchase agreements are most

likely to provide such assistance.

Economic and Budgetary Impacts

The economic and budgetary impacts of oil

shale development will depend on the production levels and speed with which they are

met. Low production levels are unlikely to

have significant effects on Government

spending, on the national rate of inflation, on

the level of national employment, or on the

cost and availability of capital. To examine

these impacts, four growth-related production scenarios were prepared that distinguish

shale oil development by both the anticipated

level of production and the required degree of

Federal involvement. The

technical descriptions of

facilities, and the analytic

I ‘J – 2 “1 ~ ‘ - P _ ; ,

rationales, the

the envisioned

assumptions of

these scenarios are discussed in detail in

chapter 3. Briefly, the scenarios are:

Production target in bbl/d of

Scenario oil by 1990

1 . . . . . . . . . . . . . . . . . . . . 100,000

2 . . . . . . . . . . . . . . . . . . . . 200,000

3 . . . . . . . . . . . . . . . . . . . . 400,000

4 . . . . . . . . . . . . . . . . . . . . 1,000,000

Industry Costs

A standard commercial oil shale facility is

conventionally described as one that would

produce 50,000 bbl/d, with an on-stream
218 ● An Assessment of Oil Shale Technologies

operating factor of 90 percent, or 329 days

per year. Such a facility would actually consist of a series of integrated modular retorts

(normally five or six) each with a capacity of

between 8,000 and 12,000 bbl/d. No single

plant is likely to produce exactly 50,000 bbl/d.

At present, the plans of the Colony operators

call for a commercial facility with a 45,000-

bbl/d capacity, tract C-b is projected to produce 57,000 bbl/d, a 76,000-bbl/d plant is projected for tract C-a, Union Oil’s ultimate intention is to build a facility with a capacity in

excess of 75,000 bbl/d, and Superior and Geokinetics expect to operate commercially profitable plants with small production capacities—11,500 bbl/d and 2,000 bbl/d, respectively.

Determining the most efficient and cost-effective size for a commercial plant depends

on the amount, quality, and accessibility of

the shale resource on the tract, the method of

mining, the type of retorting technology, and a

variety of other factors that affect the cost of

shale extraction, transportation, waste disposal, and refining.

Current capital cost estimates for a 50,000-

bbl/d commercial-sized oil shale plant range

between $1.4 billion and $1.7 billion. In general, these plants are expected to represent

an approximately 20-percent economy of

scale in comparison with smaller (e.g., 9,000

to 12,000 bbl/d) modular plants. A very large

commercial facility of 100,000 bbl/d might

represent a 10- to 15-percent economy of

scale relative to a 50,000-bbl/d operation.

Whether and to what extent these economies

would actually be obtained would depend on

the particular properties of the development

site, the mining techniques used, the technology adopted, and how efficiently the projects

in question were managed.

The estimated costs of industries of different sizes are presented below. These estimates assume a 30:70 ratio of debt to equity.

They include the cost of hydrotreating and

upgrading to premium crude quality and minor transportation costs. They do not include

the cost of major pipeline construction or unit

train costs for transportation out of Uinta or

Piceance Basins. Estimates are in thirdquarter 1979 dollars and assume a 5-year

construction period for each plant.

Scenario 1 Scenario 2 Scenario 3 Scenario 4

In billions 100,000 200,000 400,000 1,000,000

of dollars bbl/d bbl/d bbl/d bbl/d

Loans, ... , ., 0.9-I .35 1.8-2,6 3.6- 4.2 9.0-13.5

Equity . . . ., . 2.1-3.15 4.2-5.9 8,4- 9.8 21.0-31.5

Total ... , . 3.0-4.5 6.0-8.5 12.0-14.0 30.0-45.0

Maximum

annual. , . . . 0.6-0,9 1.2-1.7 2.4-2.8 6.0-9.0

Given current estimates, an industry of 1

million bbl/d would cost roughly $30 billion in

third-quarter 1979 dollars. But these estimates are unlikely to be completely accurate.

Real cost escalations of 10 to 20 percent

would not be unexpected under the best of

circumstances. More importantly, if 1 million

bbl/d are deployed over a lo-year period,

capital cost increases for plant construction

are inevitable. Under such circumstances,

the demand for skilled labor, for pollution

control equipment, for valves, for mining

equipment, for compressors, for heat exchangers, and for other needed equipment

will completely outstrip supply. The consequences would be large price increases for

these goods and services as well as construction delays. Hyperinflation of the costs of required goods and services, equipment shortages, and consequent construction delays

could easily inflate total capital costs for facilities by 30 to 50 percent in real terms.

Therefore, the costs of this scenario could

easily reach $45 billion.

Cost to the Government

Each of the scenarios decribed above assumes a different extent of Federal involvement in the industrialization of oil shale. The

scenarios differ from each other in the

amount of the target production and the degree of governmental cost and financial exposure. The cost to the Treasury is, in turn, determined by the type and magnitude of the incentives that are provided. Those that have

been evaluated in this assessment vary substantially in the amount and kind of risk that

they avert for the developer. They also vary
Ch 6–Economic and Financial Considerations ● 219

with respect to their overall impact on project

economics and potential company profits.

In general, the incentives considered entail

costs to the Government that are directly related to their impact on a firm’s expected

profits. (See tables 25 and 26.) That is, sub

sidy costs to the Treasury are closely correlated with their influence on overall project

economics. However, the relation between

the effect of incentives on a firm’s profits and

the cost of the incentives to the Government is

not exactly linear. Some subsidies clearly

provide more financial encouragement with

less governmental cost and exposure than

others. The real cost to the Government is determined by: 1) the gross cost of the subsidy,

2) the amount of increased tax payments due

to additional production, 3) the Government’s

assumed discount rate (what it is assumed

could be gotten if the capital were employed

elsewhere), 4) the timing of the Government’s

payment of the incentive, and 5) the timing of

a developer tax or other payback to the Government.

Calculating the cost of incentives to the

Government is complicated by the difficulty

in determining the first three of these factors.

For example, the gross cost of the subsidy

(i.e., the size of the offered subsidy) is hard to

predict for several of the incentives. The

number of production tax credits that might

be taken by developers is not entirely predictable, nor is the extent of the financial obligation that the Government might incur under

debt insurance or guarantee programs. The

number of takers for price supports could

vary substantially depending on how they

were constructed, on the support price level,

and on future shale oil market conditions.

The amount of increased tax payment that

particular incentives might generate is also

difficult to predict. This is because the effective tax rate that firms pay on production

varies according to the circumstances of the

corporation in question. The range is potentially from O to 46 percent on Federal taxes.

Finally, the calculation of these costs

assumes that the Government’s discount rate

is known, and that the tax generation ability

of alternative Government uses of the moneys

is also known. Since there is considerable

disagreement among economists over the assumption of what the Government discount

rate should be, some uncertainty is introduced into the calculation. These calculations

assume a Government discount rate of 10 percent, which is the rate suggested by OMB.

Given these difficulties, the reported costs

to the Government of providing the incentives

should be viewed as illustrative of the probable average cost of providing the incentive to

a number of developers. It should also be remembered that these estimates do not include

the administrative cost of overseeing the incentive. Several percent could be added to

the cost of the incentive, in the cases of debt

guarantees, purchase agreements, block

grants, and low-interest loans. The costs to

the Government reported in this chapter

would apply only to first-generation facilities.

Subsequent plants would probably require

less governmental involvement and thus

lower governmental costs. If the incentives included fade-out provisions as oil prices rose

in real terms and shale oil became more competitive, then the Government’s costs would

also fall substantially for later plants—if the

price of world oil continues to rise faster than

the cost of building and operating shale oil

facilities.

In this chapter, the cost to the Government

of providing an incentive is the gross subsidy

to the firm less increased tax payments to the

Government. This cost was calculated in

present value terms. The net cost for each

year (i.e., the subsidy less tax revenues) was

discounted at the Government’s discount rate

(i.e., 10 percent). The resulting present value

calculations were summed for all years. The

nature of the Government cost calculations is

described in greater detail in appendix A.

Scenario 1: 100,000 bbl/d by 1990.—OTA’s

analysis indicates that the production of

100,000 bbl/d by 1990 will probably take

place without further subsidy beyond the general purpose tax credits that are currently
220 An Assessment of Oil Shale Technologies

available to any industrial or energy developer. Consequently, this scenario would not

require any additional cost to the Government.

Scenario 2: 200,000 bbl/d by 1990.—The

cost to the Government of subsidizing the

200,000 bbl/d envisioned in this scenario

would depend, in part, on which incentives

are used to stimulate production. As is shown

in table 25, the estimated cost to the Government of subsidizing a 50,000-bbl/d plant will

depend on the incentives chosen. If the Government chose to provide only one of the incentives considered in this chapter, then its

costs would vary between approximately $0

and $494 million in 1979 dollars. However,

this range should be adjusted in several

ways. First, the construction grant subsidies

are so costly and politically unpopular that

they should probably be dropped from consideration. Second, although the purchase

agreement is a powerful incentive in theory,

its impact when set at $55/bbl over the life of

the project is too low to have a significant influence on project economics. Consequently,

it should also be dropped from consideration.

Each of the remaining subsidies would

yield substantial profits if a 12-percent discount rate is assumed. Although all but the

low-interest loan will still yield a relatively

small loss if a 15-percent discount rate is

assumed, this is offset by the fact that the

present calculations assumed a l-year construction delay. The cost of this delay is $117

million. If such a delay does not take place,

then all of the incentives except the purchase

agreement will provide a small profit (or

small loss) in addition to the 15-percent discount rate (return on investment).

Thus, the cost of spurring the construction

of a 50,000-bbl/d plant with the use of a single

subsidy would be between approximately

$100 million and $400 million over the life of

the project. Therefore, the cost to the Government of stimulating the production of 200,000

bbl/d would be between $400 million and $1.6

billion.

If it were certain that any of the incentives

included in these ranges would induce the

desired level of production, the least costly

subsidy would be the best choice from the

Government’s perspective. Unfortunately,

this is not necessarily the case. As discussed

previously the particular corporate and financial circumstances of individual developers vary widely with respect to the specific

risks that they need or wish to avert. Therefore, their incentive needs may be quite different. Some firms may find it difficult to use

tax credits. Others may be too small or weak

financially to take advantage of price supports or purchase agreements. Instead, they

require some kind of financing subsidy such

as a low-interest loan or debt guarantee.

Some form of choice among possible incentives is probably necessary in view of these

differences.

If the Government provided a choice among

possible incentives, then the cost of financing

this scenario would probably be between $1.2

billion and $1.4 billion in 1979 dollars.

Scenario 3: 400,000 bbl/d by 1990.—0n

the basis of the same assumptions that were

used in the second scenario, the cost to the

Government of providing a single incentive

would be between $800 million and $3.2 billion in 1979 dollars. If developers were given

their choice among the incentives, then the

cost to the Government to stimulate this level

of production would be between $2.8 billion

and $3.2 billion in 1979 dollars.

Scenario 4: 1 million bbl/d by 1990.—The

costs to the Government discussed below assume that almost all of this production would

take place with incentives to private industry

rather than through direct Government ownership. However, since the list of incentives

being considered includes both a 33- and 50-

percent construction grant, the following

analysis captures the financial consequences

of Government participation. It also assumes

that an effort to deploy the industry by 1990

would put enormous strain on U.S. manufacturing capacity (e.g., valves, heat exchangers,
pressure vessels, and mining equipment), or

architectural-engineering schedules, and on

the reservoir of skilled workers. This would

delay construction timetables and produce

sizable cost overruns. The precise amount of

these overruns cannot be predicted.

Conversations with representatives of industry and major construction firms, plus an

examination of the available literature, suggest that such cost escalations could easily

reach or exceed 50 percent of the original

estimates. The calculations for the total

capital cost of this scenario include this

assumption. It is difficult to predict the effect

that such overall cost increases would have

on the cost of Government subsidies, since a

large part of the increases would be absorbed by the developers, Increases in the

total capital costs of the target production

would not translate directly into higher governmental costs, but would more likely reduce overall production because of project

failures. How much the Government’s costs

escalated would be sensitive to the particular

incentives used. They would also be affected

by the degree to which hyperinflation of overall plant costs and resulting project failures

reduced tax receipts.

In order to stimulate sufficient developer

commitment to stand a chance of meeting the

production target, firms would have to be

allowed to choose the incentive that benefited

them most. In which case, the total direct cost

to Government would probably be between $6

billion and $7 billion. However, it is likely that

project failures and construction delays

would prevent the production target from

being met. Consequently, the above estimate

of cost to the Government would be more likely to represent a production in 1990 of

500,000 to 750,000 bbl/d rather than the full

1 million bbl/d.

It should be noted that the above calculations do not include necessary administrative

costs nor do they capture all of the costs of

additional refineries, piping, and transportation facilities that would be required for the

third and particularly the fourth scenarios.

The estimates are in present value terms and

do not represent, except for the block grants,

payment by the Government of a single lump

sum. All the other incentives would allow

phased expenditures over a number of years,

thus, limiting the Government’s financial obligations during any one year. Most importantly, the calculations use OMB’s lo-percent discount rate, and assume that the gross amount

of the subsidies would be used in some equally productive manner if it was not spent on oil

shale. Assuming alternatively that these

moneys were used less productively, then the

real cost to the Government of the subsidies

would fall substantially. For instance. the net

cost to the Government of providing the lowinterest loan would be $453 million if a

Government discount rate of 10 percent is

assumed. The cost would be $201 million if a

5-percent discount rate is assumed.

Capital Market Impacts and Financial Feasibility

The capital outlays needed to develop a sizable shale oil production capacity are immense, e.g., $30 billion to $45 billion for just a

l-million-bbl/d capacity, This has led many to

question the financial feasibility of private

sector development and to argue that Government financial guarantees and/or direct Government participation are mandatory if there

is to be significant shale oil production capacity by 1990 or even by 2000. Still others have

asserted that even if the Government ensures

the necessary financing, its achievement

would mean severe distortions of the capital

markets, namely: 1) a significant increase in

capital costs (interest rates and required

return on equity), which would reduce other

business investment and 2) distortions in particular economic segments such as housing,

due to high interest rates and the “crowding

out” of mortgage financing. Yet proponents of

shale oil development argue that there are

significant long-run benefits to be gained.
These include capital market benefits in

terms of balance of payments, of inflation,

and of strength of the U.S. dollar.

Concerns

There is a clear need to address systematically the financial and economic issues of

shale oil financing. Thus, it is necessary to

consider: 1) the level of required financing

associated with alternative rates of shale oil

development, 2) the financial feasibility, 3)

the capital market impact in aggregate and

on particular capital market segments, 4) financial aspects of Government policy alternatives, and 5) the impact of shale oil on the

balance of payments, on inflation, on the

strength of the U.S. dollar, and on tax revenues.

Scenario Framework

The development envisioned in either scenario 1 or 2 would not entail significant

capital outlays, Thus these scenarios do not

involve issues of financial feasibility and

capital market distortions. Financial-economic considerations would, however, cause variations to scenario 3 (pioneer commercial industry) and scenario 4 (aggressive develop

ment). Two concerns within each scenario

are: the effects of delays and cost overruns

and variations in the timing of development.

Delays and cost overruns.—In the absence

of delays and cost overruns, it was assumed

that the prototypical plant would take 5 years

to build and cost $1.5 billion in 1979 dollars

(the upper end of current estimates for roomand-pillar mining with surface retorting). To

assess the effect of delays and cost overruns,

an adverse variation was considered to be a

2-year delay and a $600 million overrun.

Alternative plant initiation schedules.—

There are several ways to reach a target level for a given production capacity by 1990.

One is to initiate the necessary capacity at a

uniform rate, and stop adding capacity in

1985 to reflect the 5 years from initiation to

completion. Another is to add plants at a uniform rate, for example, 100,000-bbl/d capacity (two prototypical plants) per year in scenario 3 and 200,000bbl/d (four prototypical

plants) in scenario 4. Third and more realistic

is to gradually build up the development rate

from current levels to a target level of capacity additions. For each scenario, figure 52

shows the combinations of delay-overrun variations and capacity addition variations.

Figure 52.—A Summary of Variations

in Each Scenario

Uniform to 1985

/

100,000 bbl/d to 1985

and then no add it ions

No delay or overrun Uniform

/

Cost = $1.5 billion

\

(100,000 bbl/d

Time = 5 years per year)

/

Gradual buildup

4

Scenario

\

Uniform to 1985

\ Delay and overrun I

Y

Uniform

Cost = $2.1 billion

\

(200,000 bbl/d

Time = 7 years per year)

Gradual buildup

Peak Financing Requirement

While the total capital outlay to put a shale

oil industry in place may suggest financial infeasibility and the possibility of severe distortions in the capital markets, it is critical to

recognize that the total is spread over a number of years. Moreover, once there is significant capacity in place, much of the cash generation is available to finance further

growth, so that even a growing capacity becomes “self-financing” at some point.

The key issue of aggregate financial feasibility and capital market impact is the peak

annual financing requirement. The annual financing requirements for various scenario
Ch. 6–Economic and Financial Considerations . 223

——

variations* are plotted in figure 53. The peak lays and overruns. It would be no more than

financing requirements are summarized in $4.2 billion for the delay-overrun variation.

table 27. Scenario 4.—The peak annual financing

Scenario 3.—The peak annual financing requirement would be no more than $6.0 bilrequirement would be no more than $3 billion lion for a uniform addition of 200,000-bbl/d

(1980 dollars) for a uniform addition of capacity per year with no delays and over100,000-bbl/d capacity per year with no de- runs. It would be no more than $8.4 billion for

the delay-overrun variation.

The use of the phrase “no more than” in

*For more details on the scenario variations, the cost and the paragraph above reflects the fact that

revenue assumptions, the simulation methodology, and a de- very conservative assumptions about cost

tailed case-by-case development of the cash flows, see Bernell

K. Stone, Shale Oil Financing: An Assessment of Financing Re- and cash flow were used in each scenario in

quirements, Capital Market Impact, Financial Feasibility and order to make certain that peak financing reFinonciai Aspects of Policy Alterno tives. quirements are not understated.

Figure 53. —Year-by-Year Financing in Billions for Various Scenarios

#3: Uniform to 1985

5 -

4 -

3 -

2 - \

\

1 \

\

o

1

1985 \

– 1

– 2 -

+

#4: Uniform to 1985

10 -

9 “

8

-

7 -

6 -

5 -

4 -

3 -

\

\

1

\

\

o

I \

1985

– 1 -

– 2 -

– 3 -

–4 L

#3: Uniform

5 -

4 -

—.. /’ /

-t /

+.

3 -

0

2 -

1

0

–1

– 2

t

1

10

9

8

7

6

5

4

#4: Uniform

–1

– 2

– 3

- 4

[

?

#3: Gradual buildup

5

4 -

/ 0

/----- -

3 -

~%.

2 -

1 -

0 ‘

- 1

-2-

+

#4: Gradual buildup

8 -

,---

7 - /

6 -

,/’

/

5 -

4 -

3 -

2 -

1 -

0 ‘

– 1

– 2

– 3

- 4

[

= No delay version

————— = Delay version

SOURCE Off Ice of Technology Assessment
224 An Assessment of Oi/ Shale Technologies

Table 27.–Peak Financing for Each Scenario (billions of dollars)

Version No delay or overrun Delay and overrun

Scenario 3

Uniform to 1985 . . . . . . . $3.00 $3.00

Uniform. ... . . . . 3.00 4.20

Gradual buildup . . 2.40 3.90

Scenario 4

Uniform to 1985 .., ., . 6.00 6.00

Uniform. . . . . . . . . . . . . 6.00 8.40

Gradual buildup ... . . 4,95 7 3 5

SOURCE Off Ice of Technology Assessment

Aggregate Financial Feasibility

There is no significant problem of aggregate financial feasibility. Assuming that the

current rate of domestic business capital investment grows at a conservative rate of 4

percent into the mid-1980’s at the time of the

peak financing requirement, the $6 billion

would be less than 3 percent of total domestic

business investment and the $8.4 billion

would be less than 4 percent. *

While a figure of $6 billion to $8 billion

sounds like a large annual outlay, 3 to 4 percent of net domestic business investment

should cause no significant financial distortions in terms of interest rate shifts or capital

market flows. This amount is well within the

normal year-to-year fluctuation in domestic

business investment, and a small fraction of

year-to-year shifts in net domestic savings.

Likewise, it is within normal shifts in capital

flows from abroad. In fact, the international

capital markets are now recycling many

times this amount of petrodollars. Finally, it is

a small fraction of the total annual mortgage

financing market, where mortgage refinancing intermediaries annually recycle tens of

billions. Moreover, the experience of the past

3 years has shown that thrift institutions can

compete for funds at times of high interest

rates when rate ceilings are lifted. Hence,

*The annual rate of business expenditures for new plant and

equipment in 1979 is $174 billion ($180 billion seasonally adjusted annual rate in the fourth quarter). Hence, by the time of

peak financing in the mid-1980’s, business expenditures for

new plant and equipment should be well over $225 billion with

4-percent annual growth,

this level of financing should cause no significant distortion of the housing industry.

The capital flows are well within the financial capacity of the major petroleum companies. For instance, EXXON has announced a

$6.5 billion capital investment plan for 1980.

A survey of the 1979 annual reports of the 18

major integrated oil companies indicates capital investment programs exceeding $50 billion per year. Moreover, cases such as the

SOHIO financing of its Prudhoe Bay development, and its share of the Alaskan pipeline,

indicate an ability for private enterprises

with limited financial capacity to put together

creative financing packages without Government assistance, when there are promising

investment opportunities.

Hence, not only is there no aggregate problem of capital market capacity or distortion,

but there is also no significant problem of capacity or feasibility for the private sector to

provide financing as long as shale oil is a

profitable investment.

A Caveat

The analysis above has looked at an aggressive development scenario in a clearly

worst case for financial requirements and

found no significant problem. However, it has

ignored other possible sources of significant

additional financing. Were shale oil financing

to be only one of several Government-supported projects, each with comparable peak

financing requirements in the mid-to-late
Ch 6–Economic and Financial Considerations ● 225

1980’s, then there is a potential problem in

the sense of crowding out other domestic investment, distorting particular markets such

as housing, or significantly increasing interest rates necessary to induce domestic saving

and/or investment capital from abroad.

While consideration of financing induced by

other Government programs is beyond the

scope of this report, this possibility must

clearly be recognized, and an overall financial impact assessment made.

Finance Mix

Thus far the analysis has focused on the

total peak financing and secondary financial

effects. In general, the capital markets are

very efficient at shifting funds between capital market segments. Therefore, the major

macro impact depends on the amount of overall financing regardless of the particular mix.

Nevertheless, there are mix issues, especially

capacity to provide new equity and ability to

support debt without guarantees.

The investment tax credit implies that the

Federal Government automatically provides

up to 20 percent of the total investment. * A

scenario of further Government support of

development cost beyond the investment tax

credit could be an additional 20 percent for a

total Government share of 40 percent. These

two cases are summarized in table 28 assuming the remainder is 50-percent debt and 50-

percent equity. The actual share of debt in

the total financing is less, namely 40 percent

and 30 percent respectively.

Table 28 shows strikingly that there should

be no financing problem for the major oil companies. Both current earnings and retained

earnings (earnings after dividends) are many

times this amount for the 18 largest companies.

Debt capacity of the major oil companies is

also more than adequate. Even if peak needs

*The use of 20 percent here assumes that the extra IO-percent investment tax credit continues. Otherwise, this figure

will drop to 10 percent.

Table 28.–Finance Mix

Government sharing

Current Investment of construction

tax credit only costs 20%

Percent $ billions Percent $ billions

Government 20 1 6 40 3 2

Private deb t 40 3 2 30 2 4

Private equit y 40 3.2 30 2 4

Tota l 100 8 0 100 8 0

SOURCE Off Ice of Technology Assessment

were to persist for 10 years ($32 billion), the

current debt capacity would tolerate such

amounts in terms of debt-equity ratios and interest coverage. Hence, for the overall energy

industry, there is no significant problem of

providing either debt or equity, assuming that

the equity is primarily from retained earnings.

Smaller Companies and New Equity

For smaller companies, the financing burdens can be formidable. Likewise, the magnitude of equity financing for a single commercial facility is onerous. The new equity market is not likely to provide significant venture

capital for new enterprises or small companies in this area. Without Government assistance, a small company can participate only

via joint ventures. However, this limitation is

not unique to shale oil. Small companies cannot generally undertake billion dollar capital

investments in any industry. Moreover, such

companies generally lack the managerial and

technical resources to undertake such ventures successfully. While financing is an

obstacle for small companies, it is probably

not as severe as building the organization to

manage such a project.

Significant contributions to establishing a

large shale oil industry should not be expected from small companies. Both technical

and managerial talent and financial resources for major development reside in the

large energy companies.
226 ● An Assessment of Oil Shale Technologies

Secondary Financial Impacts and Benefits

In addition to the peak capital requirements and the direct impact on the capital

markets, there are also a variety of secondary financial effects—balance of payments,

strength of the U.S. dollar, inflation, and tax

revenue (net effect on the Federal budget).

Balance of Payments and Strength

of U.S. Dollar

Shale oil development has two balance-ofpayment effects—the direct effect of its production and the indirect effect from its influence on the world oil price.

Direct effect.—Producing shale oil will reduce the need for imports. There should be a

one-for-one substitution of shale oil for imported oil. At a $30/bbl current-dollar price

for imported oil in the mid- to late 1980’s, the

shift in balance of payments is $5.5 billion

(scenario 3 with no delay) to $7 billion (scenario 4 with delay) in 1990. It would rise to

$15.5 billion (scenario 3 with no delay) to

$27.0 billion (scenario 4 with delay) in 2000.

These effects are summarized in table 29.

Indirect effect.—The indirect effect arises

from price pressure exerted by domestic

shale oil production on the price of world oil.

Table 29.–The Current Dollar Improvement in the Annual U.S.

Balance-of-Payments Position Associated With Afternative

Development Rate Scenarios

Representative years

Improved source 1990 1995 2000

Scenario 3 with no delay or cost overrun and

annual capacity additions at the rate of

100,000 bbl/d

Direct substitution (billions) a

, ... ., ., ., $5.5 $10.5 $15.5

Scenario 4 with 2-year delay and a $600 million

cost overrun and uniform annual capacity

additions at the rate of 200,000 bbl/d

Direct substitution (billions) b

, ., ., ., ., ., 7,0 17.0 27.0

aThls assumes the current dollar price of world 011 IS $30/bbl In each year and corresponds 10

starf-of.year capaclly oi O 5 mllllon In 1990, 1 mllllon In 1995, and 1 5 mllllon In 2000 plus

50 000-bbl/d average production from phase-in of 100,000 -bbl/d capacity In each year

blhls assumes the Currerl[ dollar prtce of world 011 IS $30/bbl in each Year and corresponds 10

sfafl-ol-year lull produc!lofl capacity of O 6, 1 6, and 26 mllllon bbl/d respectively for 1990

1995, and 2000 plus 100000 bbl/d average produc!lon from phase-in of 200 000-bbl/d capacIly In each year

SOURCE Office ot Technology Assessment

For every dollar reduction in the price of

world oil (at current import levels of approximately 3 billion bbl/yr), there is a $3 billion

improvement in the balance of payments.

Taxes

The direct effect of any shale oil incentives

can be either a reduction in taxes and/or

Government payments to shale oil producers.

Hence, the direct effect of incentives is to increase the Government deficit. To the extent

that there is a net increase in economic activity, there are countervailing tax revenue benefits. These include: 1) the taxes paid by shale

oil producers, 2) the taxes paid by suppliers

to the shale oil companies, 3) the taxes paid

by workers for shale oil companies, and 4) the

taxes paid by workers for shale oil suppliers.

It is very difficult to assess the impact of

shale oil financing on Federal tax revenue.

One of the primary variables is the extent to

which shale oil production and related economic activity is incremental (net new domestic production) or substitutes for other economic activity.

Estimates of the incremental Federal tax

revenue are summarized in table 30. Two

cases are considered—loo-percent incremental domestic production and a more plausible 50-percent incremental production. The

effect is modest in 1990 due to the assumption

of no taxes by the shale oil producers. However, by 2000 it rises to several billion. These

figures exclude secondary activity such as incremental tax revenues due to servicing the

employees and suppliers. They also do not

reflect any benefits of higher employment in

reducing unemployment compensation and

welfare payments.

Any reduction in the Government deficit

will be a long-run benefit to the capital markets to the extent that it reduces deficit financing and the associated “crowding out”

of private sector financing by Government

debt.
Ch. 6–Economic and Financial Considerations 227

Table 30.–A Summary of Estimates of the Improvement in

Federal Tax Revenue Attributable to Shale Oil Production From

the Taxes Paid by Shale Oil Companies, Their Employees,

Their Suppliers, and Their Suppliers’ Employees

Representative years

1990 1995 2000

Scenario 3–uniform 100,000-bbl/d capacity

growth and no delay

Value of annual production (billions) $5,50$1050$155 0

Proportion of annual production paid in taxes 15 .20 25

Net tax Improvement. 100% new activity (billions) 83 2,10 388

Net tax Improvement 50% new activity (billions) 41 1.05 1,94

Scenario 4–uniform 200,000-bbl/d capacity

growth and delay

Value of annual production (billions) 700 1700 2700

Proportion of annual production paid in taxes. 15 .20 ,25

Net tax Improvement 100% new activity (billions) 1.05 340 67 5

Net tax Improvement. 50% new activity (billions) .53 1 70 3.38

Notes on the lax proportions

1 The proportions used here ( 15 20 and 25) are developed In delall m Bernell K Stone

S)ra/e 01/ F/nanc/rrg ArJ 4ssessrnenf of Fmamng Reqwrernenls Caplfa/ Marker knpm Fmanc/a/ Feas@//lly and Fmanc/a/ Aspects of F’o/Icy Allemahves They assume a 20 percent beforeIax rate of return for the compames 20 percent dlrecl labor expense 50 percent supplrer ex

pense and 10-percent other Supplrer direct labor payments are assumed to be 50 percent of

suppller revenue

2 The corporate and personal [ax rates used were 50 and 25 percent respectively

3 The propofllons assume no corporate Iaxes Irom shale 011 producers [n 1990 (due 10 acceler

aled depredation and [nvestment lax Credltsj a 25 percent elfectwe rate tn 1995 and a full 50-

percenl (ate In 2000

SOURCE Off Ice of Technology Assessment

Capital Costs: Secondary Effects

been noted that this should be minor since the

peak capital outlays are small as a proportion

of total business investment, and would require only a modest change in saving. The

various secondary financial effects (balance

of payments, Government deficit, inflation)

also impact capital market rates. The longrun effect of improved balance of payments,

reduced inflation, and reduced deficits will

be to reduce capital market rates—both interest rates and required equity returns necessary for any given level of savings. The

long-run reduction should be several percentage points. Moreover, while the short-run impact of higher inflation would be adverse, the

fact that capital markets are “anticipatory”

(i.e., future looking) means that current rates

will reflect not just current inflation but also

the future improvement in inflation, balance

of payments, and the budget deficit. Thus, the

long-run improvements could outweigh both

the short-run effect of inflation and the increased financing need. Consequently, the

overall effect of shale oil on capital market

rates is at worst a minor short-run increase

and a clear long-run decrease.

The direct effect of more capital investment is to raise capital costs. It has already

Financial Aspects of Policy Alternatives

Impact on Peak Financing

From the viewpoint of aggregate impact,

the most important Government action is that

which prevents or at least minimizes delays

(i.e., by removing environmental delays and

licensing delays once a plant is started), thus,

cost over-runs.

Impact on Private Sector

of Peak Financing

Government subsidies in the

Share

construction

and very early production stages reduce the

private sector share of peak financing but not

the overall impact. This is because the Government must raise its share via some combination of Government borrowing or more

taxes, either of which reduces funds available for private sector financing.

General Impact of Subsidies

The overall effect of subsidies and/or risk

reduction is to make investment more attractive and ensure more rapid development than

would otherwise take place. Subsidies also

make possible more rapid private-sector development once a basic industry is in place,

i.e., beyond the 1990 period.

Government willingness to subsidize, especially via production subsidies and minimum

price guarantees, sends an important message to savers and the world capital markets—namely that there will be a significant
228 ● An Assessment of O/1 Shale Technologies

U.S. shale oil industry with decreasing reliance on foreign oil. Hence it should reduce inflationary expectations, induce savings, induce investment from abroad, and strengthen

the U.S. dollar. These policies could, therefore, have an immediate and significant beneficial effect on the domestic capital markets

via their impact on future expectations.

Summary

There is no significant problem in provid- .

ing peak financing requirements even for

rapid shale oil development in terms of capacity of the capital markets, increases in

capital costs, or reallocations from other

industrial-financial sectors of the economy.

Major energy companies have the capacity to

provide any reasonable mix of debt and equity via retained earnings.

Long-run secondary effects on balance of

payments, strength of the U.S. dollar, inflation, and the budget deficit are all favorable.

The overall impact on capital markets should

also be favorable, especially given that current rates will reflect future expectations

about inflation and the balance of payments.

Effect on Inflation and Employment

Oil shale programs will undoubtedly be a

part of a larger synthetic fuels policy. All of

the legislation before Congress is concerned

with the development of a synthetic fuels industry as such. The development of oil shale,

were it to take place, would do so in the context of some particular array of policies concerned with such issues as conservation, oil

import reduction, coal conversion, and/or increased solar power usage. Furthermore,

shale oil development, like any other longterm financial commitment, will interact with

Government policy and economic trends in

numerous areas such as monetary policy,

fiscal policy, tax policy (the windfall profits

tax is particularly relevant), the characteristics of the balance of payments, and overall

capital availability. To evaluate how prices

and employment will be affected by oil shale

development, it would be necessary to examine these effects for all of the major synthetic

fuels proposals before Congress, and attempt

to assess the course of the U.S. economy over

the next 10 years. This task is outside the

scope of this report. However, the Congressional Budget Office in its September 7, 1979

report to the Senate Budget Committee has attempted to make such an analysis.

The impacts on prices and employment nationwide of the deployment of the first scenario (100,000 bbl/d) would be insignificant.

Even the realization of the second scenario

(200,000 bbl/d), would have negligible effects

on national inflation and employment. However, the inflationary effects of this production on the cost of the machinery and equipment necessary to the industry might be

small, although discernible and could be significant, particularly on the price of labor,

land, and rents, in the immediate geographical areas of development.

Even the third scenario (400,000 bbl/d)

would not have an appreciable effect on national inflation rates or employment levels, It

would substantially affect local prices, have

an enormous positive impact on local employment, and a definable one on regional employment. Depending on the phasing of the influx

of workers, the local expenditures by the developer, and the approach taken in dealing

with socioeconomic impacts, the inflationary

effect on land, labor, rent, and goods could be

very large, particularly on land and rents.

(See ch. 10.)

The prices for the machinery and equipment used for constructing the facilities

would escalate sharply. It has been estimated

that the construction of an industry with a

400,000-bbl/d capacity would use between 10

and 20 percent of the current U.S. manufacturing capacity for valves, pressure vessels,
Ch. 6–Economic and Financial Considerations 229

heat exchangers, and certain kinds of mining

equipment.6 This would clearly be inflationary for these industries. The extent would depend on the rapidity with which the industries could respond to the increased demand,

how much in advance of need the equipment

orders were placed, and the availability of

foreign substitutes.

It is likely that the fourth scenario (1

million bbl/d by 1990) will affect the national

economy somewhat differently from 1980

through 1985 than it will from 1986 through

1990. The short-run direct effect of shale oil

development will be to use resources with no

offsetting production. Hence, it would be

clearly inflationary, although the direct inflationary impact might be offset somewhat by

price pressure on world oil.

The long-run effect will be to reduce inflation because of the substitution of domestic

production for imports, the pressure on the

world price of oil, the improvement in the balance of payments, and the favorable impact

on the Federal budget. Moreover, because

capital markets set current rates on the expectation of future events, the anticipation of

reduced inflation can lower current capital

costs.

Simultaneously, however, this oil shale program could also exert inflationary pressure

on general prices over the longer term starting in the early to middle 1980’s because the

high demand created by the level of investment would probably create temporary bottlenecks in various sectors of the economy,

and shortages of materials and skilled labor.

The net effect will tend to push up the prices

of the essential elements of production.

Assuming that all other factors remain the

same, the tendency will be for the inflation

rate to fall by 0.05 to 0.1 percent and for the

level of unemployment to rise by 0.025 to 0.05

percent during the earlier period of development. During the latter half of the decade,

however, employment in the industry will

grow sufficiently to very slightly reduce the

national rate of unemployment (i.e., 0.015 to

0.025 percent). During this time, the tendency

will be for increasingly rapid investment to

exert only a small influence on the rate of inflation. It is unlikely that this impact would

exceed 0.1 percent. These figures should be

regarded as tendencies representing the direction of the impact—if nothing changes.

Given the high probability that all things will

not remain the same, these estimates should

be viewed with extreme caution. One fact is,

however, quite clear: oil shale development

by itself will have a very small impact either

on national rates of inflation or on employment.

Although the national impacts would be

quite small, the local, regional, and sectoral

effects would be much more substantial. Development of the magnitude envisioned in this

scenario would bring many operating, professional, and construction employees into the

area. This will unquestionably have an extraordinary impact on local prices, rents, and

land costs, as well as on local employment.

These issues are discussed in detail in

chapter 10.

Construction Industry and Equipment Capacity

Current construction equipment capacity

will severely hamper the ability to achieve oil

shale production at the level assumed in the

fourth scenario. It is apparent that limitations will be encountered in the following

areas:

. the capacity of design and construction

firms;

● the availability of various kinds of long

leadtime equipment such as pressure

vessels, valves, compressors, pumps,

heat exchangers, heavy mining equipment, and alloy components;

the capacity to move equipment to remote construction sites, and to transport

shale oil by rail and pipeline to markets

or refineries; and
230 An Assessment of Oil Shale Technologies

● the availability of sufficient numbers of

an adequately trained labor force to

meet construction schedules.

Meeting the production targets will necessitate substantial improvements in each area.

Such an expansion of capacity will require a

national commitment to divert resources from

other areas and uses, will create bottlenecks

in other parts of the economy, and will lead to

rapid inflation of costs in the relevant mining,

construction, and equipment industries. In

order to achieve this production goal the following annual manpower and equipment

needs would have to be met.

In these projections it is assumed that approximately 20 commercial facilities having

an average capacity of 50,000 bbl/d will be

constructed. Most would not reach the design

stage until at least 1982. Their construction is

unlikely to be started until between 1983 and

1984; and will not be completed until between

1989 and 1990. Consequently, many of the

projects will be designed and constructed simultaneously, thus, severely taxing the capacity of equipment suppliers and construction firms.

These projects because of their size, complexity, and the vast array of skills and expertise they require, will necessarily need to be

contracted to a limited number of large architectural-engineering firms. Only a few design

and construction firms have the managerial,

technical, and economic experience to construct such plants. An examination of the existing capacity of such firms by Engineering

News Record on April 12, 1979, indicates that

of the construction firms involved in building

manufacturing process facilities, only 21 contracted in 1978 for work having a total dollar

value near the level of expenditure required

to construct a small commercial oil shale

plant—$400 million per year.7 It can, therefore, be concluded that no more than 21 firms

have the current capacity for such work.

Many of these are already booked years in

advance. However, workloads between now

and 1985 will probably increase the number

of firms that are able to undertake projects of

this magnitude. There is also the possibility

that by combining together, smaller firms will

be able to undertake such projects.

In 1978, the construction industry contracted for $27.2 billion worth of new work,

only $21.6 billion of which was industrial

work. Thus, the annual construction costs of

the oil shale plants that would have to be built

between 1983 and 1990 to reach the millionbarrel-per-day target represents 35 percent

of the workload in 1978.

In particular, shortages of skilled labor can

be expected during efforts to deploy an industry of this size. In 1978, there were approximately 45,000 workers in the United States

having the necessary technical and professional skills (e. g., draftsmen, engineers, managers, and scientists). From 1983 to 1990,

shale oil plants producing 1 million bbl/d

would require 11,000 to 18,000 professional

employees, which is more than 36 percent

above process industry requirements in 1978.

At this time, the United States has a total construction work force of around 4.5 million.

During each year between 1983 and 1990,

constructing the plants would require an additional 130,000 workers. The need for such a

large labor force would act to hamper the

deployment of an industry of this size, and

would substantially inflate labor costs.
Ch. 6–Economic and Financial Considerations ● 231

Chapter 6 References

IThis discussion is indebted to that presented

by Robert Merrow, Constraints on the Commercialization of Oil Shale, RAND Corp., 1977,

zThis discussion in this section draws on material presented by Robert Merrow, Constraints on

the Commercialization of Oil Shale, RAND Corp.,

1977, and Synthetic Fuels: A Report Prepared for

the Budget Committee of the U.S. Senate, 1979.

‘Synthetic Fuels: Report by the Subcommittee

on Synthetic Fuels of the Committee on the Budget,

United States Senate, September 1979, p. 180.

Statement made by Cameron Engineers.

“Synthetic Fuels, Report by the Subcommittee

on Synthetic Fuels of the Committee on the Budget

of the United States Senate, Sept. 27, 1979, pp.

46-47.

‘Edward W, Merrow, Constraints on the Commercialization of Oil Shale, RAND Corp., September 1978, pp. 16-18.

‘Wallace E, Tyner and Robert J. Kalter, “A Simulation Model for Resource Policy Evaluation, ”

Cornell Agricultural Economics Staff Paper, September 1977.

‘“A Fluor Perspective on Synthetic Liquids, ”

Fluor Corp., 1979.
CHAPTER 7

Resource Acquisition
contents

Page

Introduction ****   **  be** *, *O** 238

The Evolution of Leasing and Land Exchange. 235

Leasing Programs ● .*****@***.,*.,*****,* 237

Land Exchanges . . . . . . . . . . . . . . . . . . . . .. ..241

The Adequacy of Private Lands.... ........241

Present and Potential Projects on

Private Land . . . . . . . ● ... ..........,...24 4

Present and Potential Projects on

Federal Land.... . . . . . . . . . . . . . . . . . . . . . 246

Is More Federal Land Needed? . ...........249

Policies ● ****, **, *.. *.. *,**, *,*.,*., 250

Chapter 7 References .. ..,.....,.........25 2

List of Tables

Table No. Page

31. Tracts Offered Under the Prototype Oil

Shale Leasing Program . . . . . . . . . . . . . . 240

Page

32. Distribution of the Oil Shale Resources in

Colorado and Utah. . . . . . . . . . . . . . . . . . 244

33. Estimated Shale Oil Production by 1990

in Response to Various Federal Actions. 250

List of Figures

Figure No. Page

54. Ownership of the Oil Shale Resources of

the Green River Formation . . . . . . . . . . . 235

55. Locations of the Tracts Offered for

Lease Under the Prototype Program . . . . 239

56. Privately Owned Tracts in the Piceance

Basin. ... ... ... ... ... ... .....,.. 243

57. Thickness of the Oil Shale Deposits in the

Piceance Basin That Yield at Least 25

gal/tonof Shale Oil. . . . . . . . . . . . . . . . . . 245

58. Location of the Sodium Mineral Deposits

in the Piceance Basin . . . . . . . . . . . . . . . . 246
CHAPTER 7

Resource Acquisition

Introduction

On May 27, 1980, the Department of the Interior (DOI) announced several oil shale decisions. Up to

four new tracts will be leased under the Prototype Program and preparations started for a permanent leasing program. At least one multimineral tract will be included in the renewed Prototype Program. Land exchanges will not be given special emphasis, and no decision will be made to settle mining claims until the

Supreme Court rules on Andrus v. Shell Oil (the oil shale mining claims discovery standard case). [Note:

This case was decided on June 2,1980 (No. 78-1815).] The administration will propose to Congress legislation to give DOI the authority to grant leases bigger than the present statutory limitation of 5,120

acres, to provide for offlease disposal of shale and siting of facilities, and to allow the holding of a maximum of four leases nationwide and two per State. -

The resources of the Green River formation

are owned by the Federal and State governments, by Indian tribes, and by numerous private parties. (See figure 54. ) Overall, the Federal Government owns about 70 percent of

the land surface, which overlies about 80 percent of the resources. The Federal land contains the thickest and richest oil shale deposits and essentially all of the large deposits

of sodium minerals. About 20,000 acres (less

than 1 percent) of the Federal land has been

allocated for private development through

the Prototype Oil Shale Leasing Program. In

the future, it may be necessary to involve

more public land for either private or governmental development, if certain technologies

are to be tested or if a large industry is to be

established rapidly. Releasing this land

would be affected by the laws that govern

leasing and land exchange, by unpatented

mining claims over most of the Federal land,

and by other factors.

This chapter deals with the issues surrounding the use of Federal oil shale land.

The following subjects are discussed:

● the possible need for committing more

public land;

Figure 54.—Ownership of the Oil Shale Lands

of the Green River Formation

PICEANCE BASIN

(COLORADO)

e

PRIVATE

FEE

zl~.

FEDERAL 79-.

UINTA BASIN

(UTAH)

INDIAN 8%

B

PRIVATE FEE 9%

STATE 6%

FE DE FiAL 77°.

GREEN RIVER BASIN WASHAKIE BASIN

(WYOMING) WYOMING-COLORADO)

@sATE%@’’’”o” SOURCE Map of the Ma/or 0// Shale Ho/d/rigs —Co/orado,Wyom/ngUtah,

Denver, Colo Cameron Engineers, Inc , January 1976

● leasing and land exchange programs

and their problems; and

● options for involving more Federal land.

The Evolution of Leasing and Land Exchange

The legal framework that governs the use both complex and unsettled. It incorporates a

of public land for oil shale development is series of laws and policies dating back two

235
236 . An Assessment of 0il Shale Technologies

centuries that reflect conflicting philosophies

about the role of the Federal Government as

trustee of the public land.

The Continental Congress created the public domain from lands ceded to the new Confederation by the individual States. In 1788,

the Constitution granted Congress the power

to dispose of the public domain (including surface, mineral, and other rights) for the common benefit of all the States. By 1850, the

public domain extended to the Pacific coast,

including the oil shale lands in Colorado,

Utah, and Wyoming. The Preemption Act of

1841 and the 1846 Lead Mines Statute authorized the transfer of public lands to private parties, and the Homestead Act of 1862

allowed settlement of Federal lands in the

West for agricultural purposes. Some tracts

along streams in the Piceance Basin were acquired by settlers under this Act. The Mining

Law of 1866 declared the mineral lands of the

public domain to be free to exploration and

open to appropriation by those prospectors

who found “lode-type” deposits on the land.

“Placer” deposits were excluded under this

Act but were subsequently opened to appropriation under the Placer Act of 1870. *

The Mining Law of 1872 combined, revised, and augmented the 1866 and 1870

laws, and subsequently governed disposal of

all minerals that are not otherwise explicitly

covered by other legislation. Prospecting was

recognized as a statutory right. Upon locating

a valuable mineral, a prospector could:

● stake a claim encompassing all or part of

the deposit;

● develop the deposit;

● mine, process, and sell the minerals; and

● obtain ownership to the land’s surface

and its mineral values by paying from

$2.50 to $5.00/acre, by performing about

$500 worth of development work on the

claim, and by carrying out at least $100

per year of “assessment” work until the

time that ownership was transferred by

a legal document called a patent.

*A lode deposit is confined by rock in the place where it was

originally formed. Placer deposits are lode deposits that have

been broken down, transported, and redeposited in alluvial

sediment as a result of exposure to flowing water or ice.

The Secretary of the Department of the Interior (DOI) was given authority to enforce the

provisions of the 1872 Mining Law and to

oversee the filing of claims and the granting

of patents. The Petroleum Placer Act of 1897

added “lands containing petroleum or other

mineral oils” to those subject to the location

and patenting provisions of the 1872 Mining

Law. This action led to a flood of claims for oil

and gas reserves, and large areas of public

land were transferred to private hands as a

result.

In the early 20th century, the philosophy of

free exploration and occupation of the public

domain came under scrutiny because of the

rise of the conservation movement and concern over the dwindling supply of strategic

materials, including oil. This led to two actions:

●

●

President Theodore Roosevelt’s executive withdrawals of public lands that

contained coal, timber, oil, water, and

other essential resources; and

DOI’s stricter enforcement of its requirements for granting of patents for

mining claims.

President Roosevelt’s withdrawals were protested in Congress, especially by representatives of the Western States, but Presidential

authority for such withdrawals was subsequently upheld by the Supreme Court. In l909

and 1910, President Taft withdrew the remaining public domain from appropriation by

oil and gas claims. More controversy ensued,

and in 1910, at President Taft’s request, Congress passed the General Withdrawal Act—

The Pickett Act—which authorized the President to withdraw public lands by Executive

order from settlement, location, sale, or other

entry. The withdrawals were to be temporary

and could only be made for the purpose of

evaluating the land for water powersites, irrigation, classification, or other public uses.

All lands thus withdrawn would remain open

for exploration, discovery, and appropriation

under those provisions of the Mining Law of

1872 that applied to metalliferous (metalbearing) ores.
Ch. 7–Resource Acquisition “ 237

In 1914, Congress severed known fuel and

fertilizer mineral rights from the rights to the

surface of lands appropriated for agricultural uses. The Stockraising Act of 1916 reserved to the Government all mineral rights.

The Mining Law and the other land-management laws had little effect on oil shale

prior to 1916 because interest in the mineral

was negligible. However, in 1914, the U.S.

Geological Survey began investigating the oil

shale deposits to determine their potential for

yielding fuels. Publication of the results in

1916 coincided with predictions of widespread fuel shortages as a result of diminishing petroleum reserves. Based on informal

representations that oil shale would be

treated as a locatable mineral under the

Petroleum Placer Act of 1897, more than

10,000 claims of 160 acres each were filed

before 1920. Filing for oil shale claims was

ended in 1920 with the passage of the Mineral Leasing Act. Also in 1920, DOI determined

that oil shale had been a locatable mineral.

Questions related to the valid location and

maintenance of these claims became a source

of contention that has endured to the present.

Leasing Programs

The Mineral Leasing Act of 1920 ended the

process of claiming Federal land for petroleum, gas, coal, oil shale, phosphate, and

sodium minerals. However, private firms

could be given an opportunity to develop

these minerals through leasing programs administered by DOI. The Secretary of the Interior was required to assess annual rentals

of 50 cents per leased acre, and the maximum

size of an oil shale lease tract was limited to

5,120 acres (8 mi2

). No individual or firm

could hold more than this acreage under

lease. * Except for these provisions, the Secretary was given broad discretionary powers

to select lease tracts and to shape the terms

of development leases. Five oil shale lease applications were filed with DOI after 1920.

Three leases were issued, but all were subsequently canceled.

In the early 1920’s, during the Harding administration, Secretary of the Interior Fall

was alleged to have accepted bribes from an

oil company in consideration of noncompetitive leasing of Naval Petroleum Reserve No.

3—the Teapot Dome field in Wyoming. In

1930, during the era of caution that followed

the Teapot Dome scandals, DOI’s Solicitor

suggested that oil shale lands be withdrawn

from leasing because shale oil was too expen-

*Shares in several leases could be held, but the total area

covered by the shares could not exceed 5,120 acres.

sive to produce compared with conventional

petroleum, and therefore any additional leasing could only result in speculation, The suggestion was adopted by the Secretary and

transmitted to President Hoover, who issued

Executive Order 5327, which withdrew the

oil shale lands from leasing under the Mineral Leasing Act. The order “temporarily” reserved the lands for the purpose of “investigation, examination, and classification, ” as

required by the Pickett Act under which it

was promulgated.

Since 1930, this temporary order has been

modified on a few occasions. In 1932, for example, President Hoover’s Executive Order

6016 permitted oil and gas leases on the oil

shale lands, and in 1935, President Roosevelt’s Executive Order 7038 authorized prospecting permits and development leases for

sodium-bearing minerals. The withdrawal

order has also been modified from time to

time to permit disposition of surface rights in

limited areas. With these exceptions, it remained in effect and essentially unaltered for

over 40 years, during which no oil shale

leases were issued.

In 1952, President Truman issued Executive Order 10355, which authorized the Secretary of the Interior to rescind the withdrawal order. Subsequent Secretaries, however, were reluctant to exert this authority
238 ● An Assessment of Oil Shale Technologies

for fear of creating the environment for a

leasing scandal like Teapot Dome. DOI’s hesitation was compounded by the uncertain

status of unpatented mining claims on much

of the Federal land and by a feeling that shale

oil was not needed.

In the 1960’s and early 1970’s pressure

from congressional delegates from Colorado,

Utah, and Wyoming, and urging from State

officials and the energy industry, contributed

to the formulation of two different but related

leasing attempts. The first was promulgated

between 1964 and 1968 as part of a comprehensive oil shale program in the Johnson administration under Secretary of the Interior

Stewart Udall. Secretary Udall’s lease offerings failed to attract private participation.

Other portions of his program were carried

forward into the Nixon administration, however, where they were supplemented by the

Federal Prototype Oil Shale Leasing Program

under the direction of Secretaries Hickel and

Morton. *

The Prototype Program officially began on

June 4, 1971, when President Nixon instructed the Secretary of the Interior to expedite a leasing program that would encourage oil shale development while providing for

environmental protection. On June 19, 1971,

Secretary Morton announced plans for the

Prototype Program and simultaneously released the preliminary environmental impact

statement (EIS). In April 1972, DOI designated six tracts of about 5,120 acres each,

which were offered for lease in 1974. Their

locations are shown in figure 55. Dates for

the sale of individual leases and other details

of the Program’s initiation are summarized in

table 31.

It is noteworthy that the initial development plans covered a range of technological

options: underground and surface mining,

aboveground and in situ retorting, and mining

in ground water aquifers and in dry zones. It

was estimated that the six tracts would be

producing a total of 250,000 bbl/d by 1980.

This goal was immediately set back because

*Both leasing attempts are discussed in detail in vol. 11.

no acceptable bids were received for the in

situ tracts in Wyoming. The lack of response

was related to the poor quality of the Wyoming resources and to the primitive status of

in situ technologies. In 1976, DOI proposed to

lease two other in situ tracts in the richer Colorado shales. Several sites were investigated

and a supplemental EIS was begun. The idea

was abandoned in 1977 when Colorado tracts

C-a and C-b switched from aboveground retorting (AGR) to modified in situ (MIS) processing. The reasons for this shift were technical problems with the fractured oil shale on

tract C-b and a ban on the disposal of mining

and processing wastes outside of tract C-a’s

boundaries. Development of both tracts was

resumed after a l-year delay and both are

now proceeding towards commercial operations.

Development of the Utah tracts has been

stopped by legal battles between the Federal

Government, the State of Utah, and private

firms over ownership of the lands encompassing the tracts. There are basically two types

of conflict. The first is related to the circumstances under which Utah was granted

statehood. Under the Statehood Enabling Act

of 1894, Utah was allowed to take title to four

sections out of each township with the intent

that the proceeds from their sale or use

would be applied to public education. For various reasons, selection of a large number of

these sections was delayed, and in some

cases whole townships were made ineligible

by their inclusion in Federal reservations. In

lieu of sections in these townships, Utah was

allowed to select other sections in other townships.

By the 1960’s, Utah’s stockpile of in lieu selections had reached 225,000 acres. Between

September 1965 and November 1971, Utah

applied for 157,225.9 acres of land in the oil

shale area. Included were the present sites of

lease tracts U-a and U-b. DOI declined to

transfer the title to this land, and litigation

ensued. To avoid delaying the Prototype Program’s initiation, DOI and Utah agreed that

the proceeds from the leasing of tracts U-a

and U-b would be held in reserve until the
Ch. 7–Resource Acquisition ● 239

Figure 55.— Locations of the Tracts Offered for Lease Under the Prototype Program

IDAHO

I

— . .

i

● Salt Lake City

o

1

\

GREEN

I RIVER

I

I

I

I

UTAH

\

‘) BASIN

WYOMING

● Rock Springs W-a &

W-b

lx” WASHAKIE /

BASIN

--—..

--n--r--”--—---

SAN D

I

I

WAS H

BASIN

COLORADO

25 MILES c

1 1 1 1 1 I $

u

(

I H%/ II

011 shale deposits of the Green Rwer formation

SOURCE T A Sladek, Recent Trends In 011 Shale–Part 3 Shale 011 Refln~ng and Some 011 Shale Problems, ” Minerals Irrdustr/es Bullet/n, VOI 18, No 2 March 197 5

case was decided. Utah also agreed to hold

the lessees to the terms of the Federal leases

if the State took title. The lawsuit proceeded

through the U.S. District Court and the Circuit Court, which ruled in favor of Utah, and

is now in the U.S. Supreme Court, where it

will be heard during the 1980 session. *

*On May 19, 1980, the U.S, Supreme Court, in a 5-4 decision,

reversed the lower court decisions and held that the Secretary

This case should not have unduly concerned the lessees because its outcome would

not have affected the leasing regulations.

However, the situation was complicated

when a mining company applied for a preferof the Interior could reject Utah’s applications for oil shale

lands as school land indemnity selections because the selected

lands were grossly disparate in value to the school land grants

that were lost to preemption or prior entry (Andrus v. Utuh, No.

78-1 522).
240 ● An Assessment of Oil Shale Technologies

Table 31 .–Tracts Offered Under the Prototype Oil Shale Leasing Program

Tract Location Date of sale Winning bidder Winning bid Development concept

C-a Colorado 1/8/74 Rio Blanco Oil Shale project $210,305,600 Open pit mining: aboveground retorting

(Gulf 011, Standard Oil of Indiana)

C-b Colorado 2/1 2/74 C-b Shale Oil project (Atlantic

Richfield, Tosco, Shell, Ashland)

U-ab

Utah 3/1 2/74 White River Shale Oil Development

(Sun 011, Phillips Petroleum)

U-bb

Utah 4/9/7 4 White River Shale Oil Corp.

(Sun Oil, Phillips, Standard of Ohio)

W-a Wyoming 5/14/74 None

W-b Wyoming 6/11/74 None

117,788,000 Underground mining: aboveground

retortinga

75,596,800 Underground mining, aboveground

retortingc

45,107,200 Underground mining; aboveground

retorting

In situ (suggested by DOI)

In situ (suggested by DO I)

alndlrec[ly healed retorfs (e g TOSCO It)

bsubsequently umhed for common development

ccomblna[lon 01 Indtrec[ly heated and dwec!ly heated retorls (e g TOSCO II and paraho or 9as combustion)

SOURCE OftIce of Technology Assessment

Photo credit OTA staff

Development on Federal Prototype Leasing tract C-b

ential State lease to the tract area. This might

have superseded the Federal lease and therefore obviated development of the tract by the

Prototype lessees. Another suit was initiated,

in this instance between the mining company

and the State of Utah. Proceedings have been

stayed pending resolution of the in lieu litigation.

A further complication was introduced by

the unpatented pre-1920 mining claims that

overlie most of the Federal oil shale lands, including the Utah lease tracts. In the early

1970’s, when the Prototype leases were sold,

DOI was confident that the unpatented

claims would be invalidated, and that the

Government would retain title to the lands in

question. In early 1977, however, a court

decision in favor of the claimants was issued

in a case involving unpatented claims in Colorado. Because this precedent could eventually have resulted in validation of the claims
Ch 7–Resource Acquisition 241

overlying U-a and U-b, the lessees sued for

and won a suspension in the lease terms, The

suspension is still in effect, pending a Supreme Court decision on the issue of unpatented claims. *

In summary, no permanent leasing program exists for the Federal oil shale lands,

and under the present Prototype Program,

four tracts have been leased, but two are inactive because of legal uncertainties. The

*On June 2, 1980, the U.S. Supreme Court decided in favor of

the Colorado claimants (Andrus v. Shell oil, No. 78-1815).

other two, Colorado tracts C-a and C-b, are

being developed for MIS processing, The lessees of tract C-a are also negotiating for a

demonstration of the Lurgi-Ruhrgas AGR

technology. If both tracts proceed to commercialization, they could produce a total of

133,000 bbl/d by 1987. With current plans,

one mining technique, one in situ process, and

one aboveground retort will be evaluated,

Open pit mining will not be tested, nor will

other in situ or AGR techniques. All of the

mining will be conducted in ground water

areas.

Land Exchanges

As discussed later, of the approximately

400,000 acres of privately owned land in Colorado, about 170,000 acres contain at least

10 ft of oil shale yielding 25 gal/ton. The total

potential oil yield from these richer tracts is

at least 80 billion bbl, which would support a

l-million-bbl/d industry for 240 years. However, much of the privately held land is located on the fringes of the oil shale basins,

and contains thinner, leaner deposits than

does the adjacent Federal land. Furthermore,

some of the private tracts are in small, noncontiguous parcels (mainly former homesteads and small mining claims) that could

not be economically developed. Private oil

shale development could be encouraged if

these lands were exchanged for more economically attractive Federal tracts.

The exchanging of private mineral-bearing

land for Federal land is allowed under section 206 of the Federal Land Policy and Management Act of 1976 (FLPMA). Exchanges

may be consummated provided that they are

in the public interest and that the properties

involved are within 25 percent of equal value.

The difference may be made up in cash.

There are two options that would be particularly suitable for the oil shale situations. The

first is the “blocking-up” of scattered or oddly shaped tracts by exchanging portions of

them for adjacent Federal land, thereby creating a tract geometry that could be developed economically. Superior Oil Co. proposed

such an exchange for its property in the

northern Piceance basin. In this case, a

stringer of Superior land that extended into

the Federal holdings was to be exchanged for

a parcel along the southern edge of the main

body of the Superior property. EXXON Corp.

has also proposed to exchange numerous

small tracts along streambeds in the Piceance

basin for about 10,000 acres of Federal land

near the basin’s center.

The second option would involve exchanging a large block of private land on the fringe

of the oil shale deposits for a substantially

smaller block of Federal land in the richer,

thicker areas. The Federal tract would have

to be much smaller, in general, because the

deposits under much of the Federal land are

at least 1,000 ft thick; deposits on private

tracts along the basin’s fringe are seldom

more than 250 ft thick.

The Adequacy of Private Lands

Most of the privately owned lands in the through the filing of mining claims for oil

Piceance and Uinta basins were acquired shale and other minerals under the Mining
—

242 ● An Assessment of Oil Shale Technologies

Law of 1872. The provisions of the law required that the mineral be “located” by the

prospector; that is, he had to sample the

deposit and demonstrate, through assay, that

it contained the mineral of interest. In general, the oil shales in Colorado and Utah are

deeply buried and therefore not visible from

the surface. However, some deposits are visible where streams have eroded through the

overburden. The early prospectors obtained

samples from these outcrops, assayed them,

filed claims for the outcrop and for the adjacent land (which, it was inferred, also contained the mineral), and eventually obtained

patents for the claimed land from the Government. Most of the original mining claims were

quite small, but over the years the individual

claims have been purchased by major energy

companies and consolidated into much larger

blocks that could be suitable for commercial

development.

The locations of the larger privately owned

patented or “fee” lands in the Piceance basin

are shown in figure 56. * Because the oil shale

deposits were first detected along the Colorado River, most of the fee lands are found

in the southern part of the basin. Because of

the location requirements of the 1872 Mining

Law, they are generally found along streambeds. Not shown in the figure are the numerous tracts of a few hundred acres that follow

the streams in the central and northern parts

of the basin. These were primarily early

homesteads and grazing lands, but many of

them have been acquired by the energy companies. They are still used for farming and

stock raising, which retains control of the

water rights.

The location of the private lands has several implications for oil shale development because, although they are extensive, they are

not so commercially attractive as the Federal

lands to the north. There are three reasons

why they are not so attractive. First, they are

much thinner and contain lower concentrations of kerogen than do the deposits on Federal land. This is because the oil shale re-

*The term “fee’” is derived from the Middle English word

~ie~: an inheritable or heritable estate in land.

sources were created on the bed of an ancient lake by the deposition of silt and organic

debris carried into the lake by rivers and

streams. The lake had a bowl-shaped cross

section (hence, the term “basin”), and more

sedimentation occurred near its depositional

centers, which lie north of the geometric

center of the basin—on Federal land. The

Federal deposits are therefore much thicker

and, as a consequence, more amenable to

large-scale development. The private lands,

on the fringe of the basin corresponding to

the shoreline of the ancient lake, are much

thinner.

Second, because the level of water in the

lake varied over time as the climate changed,

the lakeshore advanced and receded. When

the water level was high, organic matter was

deposited over a broader area and was converted to oil shale before it could be decomposed by exposure to the air. When the water

level was low, more inorganic silt was deposited, and any organic debris that was laid

down near the shoreline decomposed when

the shoreline receded. As a consequence, the

deposits on the basin’s fringe are much

leaner on the average than the deposits to the

north, and they occasionally are intermixed

with layers of rock containing essentially no

organic matter, This complicated stratigraphy reduces the average oil yield from deposits on private land, and makes them less suitable for commercial development.

The net effect of these two conditions is indicated in table 32 and illustrated in figure

57. As shown, the privately owned lands in

Colorado and Utah include about 340,000

acres of deposits at least 10 ft thick that

would yield at least 25 gal/ton of shale oil.

The total potential yield from these deposits

is about 100 billion bbl. In contrast, the Federal lands have 1.2 million acres of equivalent deposits with a potential yield of 460 billion bbl.

The third factor is that private lands contain essentially no commercially attractive

deposits of nahcolite and dawsonite—the sodium minerals that are potential sources of

aluminum, glass, and the chemicals used to
Ch. 7–Resource Acquisition 243

Figure 56.— Privately Owned Tracts in the Piceance Basin

d INTERNATIONAL NUCLEAR MEEKE R

Y7MOBIL

EQUITY

&ARCO EOUITY STANDARD OF

CALIFORNIA UNlON COLONY \

OCCIDENTAL

(4

#

@ N

Go

m

outline of the Green /?iver

formation

A Proposed oil shale project

SOURCE Map of theMa/or 0// Shale Ho/dlrrgs-Colorado, Wyom/rtgUtah, Denver. Colo Cameron Engineers, Inc , January 1978
—

244 An Assessment of 0il Shale Technologies

Table 32.–Distribution of the Oil Shale Resources in Colorado and Utah

— Ownership

Colorado Utah Total

— Federal Private Federal Private Federal Private -

Ouantity of land (1 ,000 acres). . . . . . . . 1,420 400 3,780 1,100 5,200 1,600

Deposits at least 10 ft thick and yielding at least 25 gal/ton

(1,000 acres). . . . . . . . . . . . . . . . . . . . . 600 170 600 170 1,200 340

Potential yield of shale 011 (billion bbl). . . . . . . . . . 390 80 70 20 460 100

SOURCE Adapted from Prospec(s for 0(/ .Sha/eOeve/oprnen(-Colorado, Urah, and Wyormng, Department of the Intertor 1968 pp A-1 and A-2

control air pollution from flue gases. As

shown in figure 58, the deposits of sodium

minerals stop short of the northern edge of

the major private holdings. The only significant exception is the land owned by Superior

Oil Co., which lies along the northern edge of

the sodium mineral resources.

Present and Potential Projects on Private Land

Colony Development Operation (a consortium of Tosco and Atlantic Richfield Co.) and

Union Oil Co. own some of the more commercially attractive private land. The two companies have been developing retorting technologies since the 1950’s and early 1960’s. In

the late 1960’s Colony proposed to build a

commercial-scale project on its property,

which would use underground mining and

aboveground processing in TOSCO II retorts.

The project was delayed by economic uncertainties, and then resurrected in the 1970’s

after the Arab oil embargo. It was subsequently suspended when more detailed economic studies indicated a much higher cost

for the project (and hence for its oil) than

previously anticipated. The retorting process

has been tested at the semiworks scale (about

1,000 ton/d), and is regarded by Colony as

being ready for commercial application.

The Colony project would produce 46,000

bbl/d with six TOSCO II retorts, each processing about 10,000 ton/d of ore. Because the

project would include a product pipeline

across Federal land, an EIS was required.

This was completed by the Bureau of Land

Management (BLM) in 1977. At present, Colony has many of the major permits required

to initiate the project, but it will not proceed

until the economic climate is improved by further increases in oil prices or Government incentives, and until regulatory uncertainties

are alleviated. 1

Union Oil Co. began developing retorting

technologies in the 1950’s. It owns about

30,000 acres of land in the southern Piceance

Basin, 20,000 acres of which contain oil

shale. Union tested its “A” aboveground

retort on this land between 1954 and 1958.

Since 1974, Union has been studying a project

that would use the Union “B” retort to extract 75,000 to 150,000 bbl/d of shale oil from

the company’s resources. The plant is to be

developed with a modular stage in which a

single “B” retort with a capacity of about

9,000 bbl/d will be tested. This project, the

Long Ridge Experimental Shale Oil project, is

in suspension until economic conditions improve sufficiently to warrant investment. A

minimum requirement at present is a production tax credit of $3/bbl of shale oil produced. 2 Union has obtained all of the key environmental permits required for the modular

project.

A third major oil project involving private

land is the Superior project, which would involve the simultaneous recovery of shale oil,

soda ash, alumina, and nahcolite from the sodium mineral deposits. As indicated previously, Superior has proposed to exchange a

long, thin portion of its tract for a parcel of
Ch 7–Resource Acquisition 245

Figure 57.—Thickness of the Oil Shale Deposits in the Piceance Basin

That Yield at Least 25 gal/ton of Shale Oil

RANGELY

r

MEEKER

ET

RIFLE

■

Private (Fee) lands ,

Federal 011 shale lease tracts

{

GRAND JUNCTION

%/

SOURCE Cameron Engineers, Inc
.

246 ● An Assessment of Oil Shale Technologies

Figure 58.— Location of the Sodium Mineral Deposits in the Piceance Basin

Is MEEKER

-

El Private (Fee) lands

m

Federal 011 shale lease tracts

--- Extent of the nahcohte deposits

)

++ Extent of the dawsorute deposits 5

SOURCE B Welchman,Sa//fre Zone 0// Sha/e and the /rrtegrated In SIfu Process, Houston. Tex The Multi Mineral Corp , May 1979 p 17
Ch. 7–Resource Acquisition ● 247

Federal land. BLM has issued a draft EIS for

the exchange, and recently completed a preliminary assessment of the value of the two

tracts in question, as required by the equivalent-value provisions of FLPMA. Superior’s

land was found to have a significantly lower

value than the Federal land to be acquired.

BLM has tentatively denied the application.

Superior is preparing a response to the denial

and BLM’s decision is open to review. If the

exchange were approved, the project could

produce about 11,500 bbl/d of shale oil, plus

the other byproducts, from a single Superior

aboveground retort. The resources on the

tract could support one additional retort of

the same size.

Tosco is also developing the Sand Wash

project on land leased from Utah. It is in its

early stages and is proceeding at a relatively

slow pace. Under its leasing arrangements,

Tosco is required to invest $8 million in tract

development over an 8-year period. The sinking of a mine shaft has begun and will be completed in about 1982. This will be followed by

an experimental mining phase lasting from 2

to 3 years.3 Thus, by 1985, Tosco could be

ready to build its retorting plant, which could

ultimately have a capacity of 50,000 bbl/d. If

a modular demonstration phase is included,

the plant could be completed by 1995. If precommercial experiments are not conducted,

as would be the case for Tosco’s Colony project, the plant could be completed as early as

1990. However, this would require accelerating the experimental, design, and construction phases, which Tosco may not be willing

to do in the absence of a highly favorable

economic outlook. Tosco has not stated a position in regard to the types of encouragement

that would be required, but as a member of

the Colony Development Operation, Tosco has

suggested a need for financial incentives and

regulatory modifications,

Other private firms are also engaged in

R&D activities on their tracts and on land

leased from Utah. These projects are discussed in detail in chapter 5. The Geokinetics

project, in which a true in situ (TIS) retorting

technique is being developed, is the only one

for which a commercial target—2,000 bbl/d

—has been announced. Occidental Oil Shale

is conducting experiments on its land in the

extreme southern Piceance basin. However,

the tests at the Logan Wash site are supporting the development of Federal lease tract

C-b. The Logan Wash site has no commercial

potential. Equity Oil Co. is developing another

TIS process on private land in Colorado, but

no production target has been announced.

If all of the presently active or suspended

projects on non-Federal land proceeded to

commercialization, the total production

would be 280,000 to 350,000 bbl/d. However,

this would require the following:

●

●

●

●

for Union: a production tax credit;

for Colony (and probably for Sand

Wash): incentives and alleviation of regulatory uncertainties;

for Superior: a land exchange and possibly incentives; and

for Geokinetics: the continued support

by the Department of Energy (DOE) of

the company’s experimental program.

There are other private tracts that have resources similar to those of Colony and Union.

These include the tracts owned by Chevron

(Standard Oil Co. of California), Getty Oil Co.,

Cities Service Corp., and others. However, no

projects have been announced for any of

these lands. In part, this reflects the technological positions of the other landowners—

they do not own advanced retorting technologies. They may plan to license the processes

of the other companies, once these have been

demonstrated, or to develop their own processes once the economic viability of the oil

shale industry appears assured. It appears

that economic conditions would have to improve significantly in order to motivate these

potential developers to complete their projects before, say, 1990. A much stronger set of

incentives may be required than would be

needed by Union or Colony, who already have

both good technological and resource positions,
—

248 An Assessment of Oil Shale Technologies

Present and Potential Projects on Federal Land

As discussed in volume II and mentioned

earlier here, only two projects are actively

being conducted as part of the Prototype

Leasing Program. Rio Blanco Oil Shale Co. is

developing tract C-a using MIS methods. A

demonstration of the Lurgi-Ruhrgas above-

-ground retort may be included. Tract C-b is

being developed as the Cathedral Bluffs

Shale Oil project. Occidental’s MIS technology is being used, and no plans have been announced for a concurrent demonstration of

AGR technologies. The White River project on

tracts U-a and U-b, which were unified for

joint development, is presently in suspension

pending resolution of ownership.

Paraho Development is also engaged in a

project involving Federal land at the DOE

research facility in Anvil Points, Colo. Anvil

Points was the site of Paraho’s retort development program. Paraho is attempting to extend the terms of its lease to include a modular demonstration program and to obtain

funding for the project. The outlook is uncertain, because an EIS is required and none has

yet been issued, despite four attempts by

DOE. Paraho’s management is also pursuing

a production tax credit to improve the

economic outlook for shale oil.

As mentioned earlier, EXXON Corp. has

also proposed to exchange its scattered holdings for a single tract of Federal land in Colorado. The future of this proposal is uncertain. If Superior’s land-exchange experience

is regarded as typical, preparation and review of the EXXON proposal could take as

long as 8 years. Four years is more likely.

DOE and the Department of Defense are

preparing a management plan for developing

Naval Oil Shale Reserve No. 1 (NOSR 1),

which is contiguous to the Anvil Points site.

This project is in the early stages, and the

potential production cannot be accurately estimated. However, if all of the preliminary exploration, design work, and permitting can be

completed by 1986, and if plant construction

were expedited, DOE believes that NOSR 1

could be producing at least 100,000 bbl/d by

1990.

Multi Mineral Corp. has proposed to use a

mine shaft on Federal land in the northern Piceance basin to develop an MIS process to recover shale oil, alumina, and nahcolite from

deeply buried deposits. The shaft was drilled

in 1978 by the U.S. Bureau of Mines to develop mining techniques for sodium minerals

and oil shale in the saline zone. * The proposal

involves a three-phase project that could lead

to a 50,000-bbl/d operation.

If all of the presently active and proposed

projects involving Federal land were completed, the total production could exceed

300,000 bbl/d, plus any additional production

from NOSR 1. However, only 57,000 bbl/d of

this production is assured, because only

Cathedral Bluffs is committed to commercialization. Rio Blanco is committed only to testing its development techniques at the precommercial level—approximately 2,000 bbl/d.

The decision to proceed to commercial levels

of production will depend on the technical

feasibility of the MIS and Lurgi-Ruhrgas

methods and on the existence of a favorable

economic and regulatory climate. Therefore,

achieving 300,000 bbl/d from these operations is likely to require the following:

●

●

●

●

for Cathedral Bluffs: continued technical progress and continuation of a favorable economic outlook;

for Rio Blanco: technical progress and

favorable project economics, perhaps including Federal financial incentives;

for Paraho: extension of the terms of the

Anvil Points lease and provision of a production tax credit;

for White River: favorable resolution of

the ownership dispute and possibly Federal incentives (Standard Oil Co. of Ohio

(SOHIO) is a participant in the White

*The Multi Mineral technology is discussed in ch. 5. The geology and stratigraphy of the oil shale basins are discussed in

ch. 4.
Ch. 7–Resource Acquisition 249

River project. SOHIO is also involved in

the Paraho operation.); and

● for EXXON: approval of the proposed

land exchange.

The potential production from tract C-a

could be expanded by 75,000 bbl/d if the lessees returned to their original open pit mining

plan. However, to allow maximum recovery

of the oil shale resource, lands outside of the

tract boundaries would have to be used for

waste disposal and the siting of the processing facilities. Such off tract land use is presently banned by Federal statutes, including

the acreage limitation of the Mineral Leasing

Act and the provisions of FLPMA, which

state:

Is More Federal Land Needed?

Nothing in this Act, or in any amendment

made by this Act, shall be constructed as

permitting any person to place, or allow to be

placed, spent shale oil, overburden, or byproducts from the recovery of other mineral

with oil shale, on any Federal land other than

Federal land which has been leased for the

recovery of oil shale . . .

As discussed in chapter 6, shale oil appears to be economically competitive, based

on the present and projected prices of foreign

crude oil and some premium-quality domestic

crudes. However, technical, economic, and

regulatory risks are inhibiting potential developers from making large capital investment commitments to shale development.

These uncertainties are aggravated by some

of the characteristics of the private lands

which, in general, are not so favorable as

those of adjacent Federal lands. Furthermore, the privately owned lands contain essentially no commercially attractive deposits

of sodium minerals. Assuming that these minerals could be extracted economically, they

could be sold as byproducts to enhance the

economic feasibility of a project. Whether

more Federal land must be provided depends

how much production is desired;

how rapidly the industry is to be created;

whether production of sodium minerals,

or testing of the “multimineral” technologies used to extract them, is desired;

how much technical, economic, and environmental information is desired to assist policymaking and the setting of environmental regulations; and

whether financial incentives are provided that will encourage the continuation of present projects on the Federal

lease tracts and also initiate projects on

private lands.

The need for additional Federal land will

depend strongly on the size of the industry

and the pace of its creation. It will also be affected by the other Federal oil shale policies,

especially those involving financial incentives. This is shown in table 33, which indicates how the industry’s capacity in 1990

might be affected by different Federal actions. As shown for case 1, about 60,000 bbl/d

could be achieved with no additional actions,

assuming that the Cathedral Bluffs project is

completed and that Geokinetics reaches its

production target. If economic conditions encourage Rio Blanco to continue and Sand

Wash to accelerate, production could reach

185,000 bbl/d by 1990. If incentives are

added (case 2) that assure completion of

these two projects, that encourage the Colony

and Union projects to resume, and that also

initiate a new project on private land, production would reach 360,000 bbl/d. This could be

expanded in case 3 to nearly 400,000 bbl/d if

the Superior land exchange is consummated

(or a lease issued for the desired parcel) and

test sites are provided for the Paraho and

Multi Mineral processes. All three of these

projects would involve providing access to additional Federal land.

If the ownership conflicts surrounding the

Utah lease tracts are resolved in a manner
—

250 ● An Assessment of Oil Shale Technologies

Table 33.–Estimated Shale Oil Production by 1990 in Response to Various Federal Actions

Case

Federal action 1 2 3 4 5 6 7 8

None. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . x

Incentives for first-generation developers . . . . x x x x x

Test sites for modular retortsb . . . . . . . . . . . . x x x x x x

Resolution of ownership issues on Utah tractsc. x x x x x

Offtract land used . . . . . . . . . . . . . . . . . . . . x x x x

Proposed land exchanges. . . . . . . . . . . . . . x x x

Incentives for second-generation developers

(or improved economics) . . . . . . . . . . . . . x x

Naval Oil Shale Reserves or expanded

Prototype Program or permanent leasing. . . . x

Production, bbl/d . . . . . . . . . . . . . . . . . . . 60,000- 360,000 390,000 490,000 560,000 620,000 850,00 0 1,000,000

185,000 f

aASSumeS the entry of one as-yet unannounced developer

blncludo~ the proposed superior 011 land exchange and a Ieasmg of Anwl POIIIIS by parafio DeVe@rrrerrl

CReSurnptlOrl of the tract U-a/(J-b project may also depend on the availablhty of Incentives and On other lmProvemenfs In Protect economics

aFor waste disposal from the o~n plt mme that was Ongmally proposed for traCt C-a

elncludes the proposed Supertor 011 and EXXON land mcharws fonly 59,000 bbllfj IS llrmly Cwnrnmed

SOURCE Off Ice of Technology Assessment

favoring the lessees, and if appropriate incentives are provided, the White River project could resume. This would add 100,000

bbl/d to the industry’s capacity. Production

could reach 560,000 bbl/d if Rio Blanco were

given permission to use offtract lands and

returned to its original open pit mining plan,

as assumed for case 5. If the EXXON land exchange were completed (case 6), production

would be increased by 60,000 bbl/d. As

shown for case 7, production might be increased to 850,000 bbl/d by providing subsidies that were sufficiently attractive to encourage the participation of the “second generation” of developers—those who are not as

technically advanced as Colony and Union, or

who lack resources of equivalent quality. The

total additional capacity indicated corresponds to about five additional major projects

on private land. The Government could also

become more directly involved in oil shale

development by leasing additional tracts or

by developing NOSR 1 (case 8). The industry’s

capacity in 1990 could then reach 1 million

bbl/d.

In summary, reaching 200,000 bbl/d by

1990 may not require the release of substantial tracts of Federal land, if the presently active projects are technically successful and if

the economic outlook remains favorable. Only

60,000 bbl/d of this capacity is assured.

About 400,000 bbl/d might be achieved if effective incentives were provided and test

sites allocated for retorting demonstrations.

Achieving 1 million bbl/d by 1990 might require subsidies, land exchanges, permission

to use offtract land for waste disposal and

facility siting, and the leasing of additional

tracts or the development of the Naval Oil

Shale Reserves.

● To amend the Mineral Leasing Act of proving economic feasibility. It might also

1920.—The Act could be amended to in- allow the inclusion of a suitable waste

crease the acreage limitations, or to set the disposal site within a tract’s boundaries

size of the tract according to the recover- while still providing adequate oil shale

able resources it contained. This might al- resources for sustained, large-scale operalow more economies of scale, thereby im- tions, thus avoiding the need for separate
Ch 7–Resource Acquisition . 251

●

●

●

offtract disposal authorization. The number of leases per person or firm could also

be increased. This might provide additional

encouragement to firms that do not own oil

shale lands because it would allow them to

acquire experience on one lease tract and

then apply it to another while the first was

still operating. A disadvantage would be

that the number of firms participating in

the leasing program could be reduced if a

few firms acquired all of the leases. One

option would be to increase the number to

one lease per State. This might encourage

a firm to develop a process in the richer deposits in Colorado and then apply it to the

poorer quality resources in Utah or Wyoming.

To amend FLPMA.—FLPMA could be

amended to allow including conditions

(such as environmental stipulations and

diligence requirements) in any oil shale

land exchange agreement. This would improve the Government’s control over the

exchanged parcel. It might also discourage

private participation.

To allow offsite land use for lease

tracts. —Legislation could be provided to

allow a lessee to use land outside of the

boundaries of a lease tract for facility siting and waste disposal. This might permit

larger, more economical operations (including perhaps an open pit mine) and

would maximize resource recovery on the

tract. However, subsequent development

of the offtract areas would be inhibited.

(DOI estimated that Rio Blanco’s offtract

disposal plan would reduce resource recovery from the disposal area by about 5

percent.)

To lease additional tracts under the Prototype Program.—There is no statutory limitation on the number of tracts that could

be leased under the Prototype Program.

However, DOI originally committed to leasing no more than six. Because two of the

original tracts were not leased, offering

two new ones might be justified, provided

that the technologies to be tested were different from the processes being developed

on the existing tracts. Leasing more than

two more tracts, or leasing for the purpose

of expanding near-term shale oil production, would encounter political opposition

by the critics of rapid oil shale development. Leasing could begin sooner than under a new leasing program, if some of the

potential lease tracts previously nominated

were offered. A supplemental EIS would be

required. Construction on the tracts could

probably not begin until about 1985 and

production no sooner than 1990. Consideration might be given to leasing a tract for

multimineral operations, a process that is

not being evaluated in any project at present. (One of the primary goals of the Prototype Program is to obtain information

about a variety of technologies. )

To initiate a new, permanent leasing program.—An advantage would be that more

production could be achieved than is possible under the present Prototype Program.

A full EIS and a new set of leasing regulations would be needed. Without the information to be acquired by completing the

present Prototype Program projects, it

might be difficult to prepare an accurate

environmental assessment and to structure

comprehensive leasing regulations. Production could probably not begin until after

1990. Abandonment of the Prototype Program would be implied, which might engender political opposition.

To expedite land exchanges.—The review

and approval procedures could be expedited by, for example, setting up a task

force within DOI specifically for oil shale

proposals.

Government development.—The Government could develop the Naval Oil Shale Reserves. Unless this were done by leasing to

private developers, it would involve competition with private industry, and would encounter political opposition. It would also

be very costly because the public would

have to pay the full cost of the facilities,

and it might discourage independent experiments by private firms. Information

useful in developing policies and regula-
252 ● An Assessment of Oi/ Shale Technologies

tions for the industry would be obtained.

However, because the Government’s experience with financing and operating a facility would be substantially different from

that of private developers, the information

might not be useful in evaluating private inChapter 7

IHO F. Coffer and A. Christianson, eds., EPA Program Conference Report: Oil Shale, EPA-600/

0-79-025, July 1979, p. 90

vestment decisions. Some of the information is being acquired in the present Prototype Program. It could also be obtained in

additional leasing programs or through licensing arrangements with the owners of

the technologies.

References

‘Ibid., at p. 27.

31bid.
CHAPTER 8

Environmental Considerations

Page

Introduction . . . . . . . . . . . . . . . . . . . . . ......255

Summary of Findings . ...................256

Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256

Water Quality. . ........................256

Occupational Health and Safety . ..........257

Land Reclamation. . . . . . . . . . . . . . . . . . . . . ..258

Permitting. . . . . ........................259

Air Quality . . . . . . . . . . . . . . . .. ... ... .+ ...259

Introduction . . . . . . . . . . . . . . . . . . . . . ......259

Pollutant Generation . . ..................259

Air Quality Laws, Standards, and Regulations 263

Air Pollution Control Technologies . ........269

Pollutant Emissions. . . . . . . . . . . . . . . . . . . . . .278

Dispersion Modeling. . ...................279

A Summary of Issues and Policy Options. ....288

Water Quality. . ........................291

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 29l

Pollution Generation. . . . . . . . . . . . . . . . . . . . . 292

Summary of Pollutants Produced by Major

Process Types. . ......................294

Effects of Potential Pollutants on Water

Quality and Use. . . . ...................295

Water Quality in the Oil Shale Region. .. ....296

Water Quality Regulations. . ..............297

Technologies for Control of Oil Shale Water

Pollution . ...........................304

Ultimate Disposition of Waste Water . .......308

Monitoring Water Quality . ...............309

Information Needs and R&D Programs .. ....311

Findings on Water Quality Aspects of Oil

Shale Development. . . . . ...............314

Pag e

Policy Options for Water Quality Management 314

Safety and Health. . . . . . . ................315

Introduction . . . . . . . . . . . . . . . . . . . . . ......315

Safety and Health Hazards . ..............316

Summary of Hazards andTheir Severity. ....322

Federal Laws, Standards, and Regulations. ..324

Control and Mitigation Methods . ..........325

Summary of Issues and R&D Needs . . . . . . . . . 326

Current R&D Programs. . .................326

Policy Considerations. . ..................327

Land Reclamation. . .....................328

Introduction . . . . . . . . . . . . . . . . . . . . . ......328

Reasons for Reclamation . ................329

Regulations Governing Land Reclamation. ...329

Reclamation Approaches. . ...............330

The Physical and Chemical Characteristics

of Processed Shale . . . . . . . . . . . . . . .. ....332

Use of Topsoil as a Spent Shale Cover . ......335

Species Selection and Plant Materials . . . . . . . 336

Review of Selected Research to Date. .......339

Summary of Issues andR&D Needs . . . . . . . . . 341

Policy Options for the Reclamation of

Processed Oil Shales. . .................342

Permitting. . . . . ........................343

Introduction . . . . . . . . . . . . . ..............343

Perceptions of the Permitting Procedure. ....344

Status of Permits Obtained by Oil Shale

Developers . . . . . . . . . . . . . . . . . . . .

The Length of the Permitting Procedure

Disputes Encountered in the Permitting

Procedure . . . . . . . . . . . . . . . . . . . . .

0.,. . 345

.,,. . 346

. . . . . 346
Page

Unresolved Issues. . .....................347

Attempts at Regulatory Simplification. .. ....348

Policy Options. . . ..............,.,....,.349

Chapter8 References. . ..................352

List of Tables

TableNo, Page

34.

350

36.

37.

38.

39.

40.

41.

42.

43.

44.

45,

46.

47.

48.

49.

50.

51.

52.

53.

Pollutants Generated bythe Colony

Development Project . . . . . . . . . . . . . . . . 262

PollutantsGenerated by the Rio Blanco

Project on TractC-a. . . . . . . . . . . . . . . . . 263

Pollutants Generatedbythe Occidental

Operation on TractC-b . . . . . . . . . . . . . . 263

The Federal and State Ambient Air

Quality Standards and Prevention of

Significant Deterioration Standards

That Influence Oil Shale Development . . 266

National Standards for Prevention of

Significant Deterioration of Ambient

Air Quality, . . . . . . . . . . . . . . . . . . . . . . . 267

National New Source Performance

Standards for Several Types of Facilities 269

EPA Standards for Best Available Air

PollutionControl Technologies for Oil

Shale Facilities. . . . . . . . . . . . . . . . . . . . . 269

Technological Readinessof Air Pollution

Control Technologies . . . . . . . . . . . . . . . . 276

Costs of AirPollutionControl . . . . . . . . . 277

Pollutants Emitted by theColony

Development Project . . . . . . . . . . . . . . . . 278

Pollutants Emitted by theRio Blanco

Project on Tract C-a. . . . . . . . . . . . . . . . . 278

Pollutants Emitted by the Occidental

Operation on TractC-b . . . . . . . . . . . . . . 279

ASummary of Emission Rates From Five

Proposed Oil Shale Projects. . . . . . . . . . . 279

A Comparison of Atmospheric Emissions

Used in Modeling Studies. . . . . . . . . . . . . 282

Modeling Results for Federal Oil Shale

Lease TractC-a . . . . . . . . . . . . . . . . . . . . 284

Models Used in SupportofPSD

Applications for Oil Shale Projects . . . . . 285

Areas of Inadequate Information and

Suggested R&D Responses . . . . . . . . . . . . 288

Generation Rates for Principal Water

Pollutants for Production of 50,000 bbl/d

of Shale Oil Syncrude. . . . . . . ..., . . . . . 294

Quality of Some SurfaceStreams in the

Oil Shale Region . . . . . . . . . . . . . . . . . . . . 297

Quality of GroundWaterAquifers in the

Piceance Basin. . . . . . . . . . . . . . . . . . . . . 297

Page

54. Effluent Limitations for Petroleum

Refineries Using BestPracticable

Pollution Control Technology. . . . . . . . . . 299

55. Effluent Limitations for Best Available

56

57

Technology Achievable for Petroleum

Refinery Facilities . . . . . . . . . . . . . . . . . . 299

New Source Performance Standards for

Petroleum Refineries . . . . . . . . . . . . . . . . 300

Colorado Water Quality Standards for

Stream Classification B2 . . . . . . . . . . . . . 301

58. Utah Water Qualitv Standards for

59

60

61

Stream Classification CW . . . . . . . . . . . . 301

Proposed Water Quality Criteria for

Designated Uses. . . . . . . . . . . . . . . . . . . . 302

Primary Drinking WaterStandards . . . . 303

Proposed Secondary Drinking Water

Regulations. ,.. .. ~.. .., ..~.... . . . . . 303

62. The Types of Contaminants in Oil Shale

Wastewater Streams and Some Potential

Processes for RemovingThem . . . . . . . . . 305

63. Relative Rankings of the Water

64.

65,

66.

67.

68.

69.

70.

Treatment Methods . . . . . . . . . . . . . . . . . 306

Estimated Costs of Water Pollution

Control in Oil ShalePlants. . . . . . . . . . . . 306

Sampling Schedule Summary for Surface

and Ground Water Monitoring Program

at Tract C-b During Development Phase. 312

Animal Studies on the Carcinogenicity of

Oil Shale and ShaleOil . . . . . . . . . . . . . . 320

Benzo(a)pyrene Content of 0il Shale and

Its Products and of Other Energy

Materials . . . . . . . . . . . . . . . . . . . . . . . . . 320

The Chemical and Physical Properties of

Processed Shales . . . . . . . . . . . . . . . . . . . 332

Estimates of Reclamation Needs Under

Various Levels of Shale Oil Production. , 338

Status of the Environmental Permits for

Five Oil Shale Projects, . . . . . . . . . . . . . . 345

List of Figures

59. Designated Class I Areas in Oil Shale Page

Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268

60, Computation Modules in Atmospheric

Dispersion Models . . . . . . . . . . . . . . . . . . 281

61. An Aboveground Spent Shale Disposal

Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307

62. Summary of Occupational Hazards

Associated With Oil ShaleDevelopment. 323
CHAPTER 8

Environmental Considerations

Introduction

The region where oil shale development

will take place is, at present, relatively undisturbed. The construction and operation of

plants would emit pollutants and produce

large amounts of solid waste for disposal. As

a consequence, air, water, and soil could be

degraded and the topography of the land

could be altered. The severity of these impacts will depend on the scale of the operations and the kinds of processing technologies

used, as well as the control strategies that

must be adopted to comply with environmental regulations.

Control strategies have been proposed for

purifying water and airborne emissions

streams, for revegetation, for protecting wildlife, and for other specific areas of environmental concern. However, control technologies that are applied to one area could

adversely affect another area. For example,

to control air pollution, airborne streams are

scrubbed to capture dust and gaseous contaminants. This produces sludges and wastewater that have to be disposed of along with

other wastes. All of these have the potential

to adversely affect the land and the water.

Airborne pollutants, such as trace metals,

might enter surface streams and ground

water in fugitive dust and or rainfall and

could alter the chemical and biological balances of the water systems. Plant and animal

life as well as human health could be harmed

both by an increase in water contamination

and by the entry of the contaminants into the

food chain. Similarly, without adequate controls, the piles of solid waste could contaminate the air and water through fugitive dust

emissions and by the leaching of soluble constituents into surface and ground water systems. Water quality could thus be degraded

by altered nutrient loading, changes in dissolved oxygen, and increased sediment and

salinity.

For these reasons, each potential environmental effect along with its control technology should be examined with respect to its net

impact on the total environmental system. To

do this requires full understanding of the

separate impacts on air, water, and land, the

interaction between the individual parts of

the ecosystem, and the efficacy of the control

strategies. Such an analysis needs a complete

and accurate data base which is as yet unavailable because no commercial oil shale

plants have been built. OTA’s environmental

analysis, therefore, is limited to examining

the effects that an oil shale industry would

have on the separate areas of air, water,

land, and occupational health and safety. In

order to provide a basis for policy analysis,

the effects are quantified wherever possible

and related to a production of 50,000 bbl/d.

For each of the areas examined:

impacts of oil shale operations are described;

applicable laws and regulations are

summarized, and their significance to oil

shale analyzed;

control strategies proposed for compliance with the laws and regulations are

described and evaluated; and

policies that could be focused on key issues and uncertainties are identified

and discussed.

255
256 ● An Assessment of Oi/ Shale Technologies

Summary

Air Quality

Because of the oil shale region’s rural character,

its air is relatively clean and unpolluted. Occasionally, however, high concentrations of hydrocarbon s

(possibly from vegetation) and particulate fro m

windblown dust occur. The development of a large oil

shale industry (or any industrial or municipal growth )

will degrade the air’s visibility and quality. Even i f

the best available control technologies are used an d

compliance is maintained with the provisions of the

Clean Air Act, its amendments, and the applicable

State laws, degradation will occur. It will take place

not only near the oil shale facilities but also in nearby

pristine areas (e.g., national parks, wilderness

areas). Some places may be affected more than

others from local concentrations of pollutants caused

by thermal inversions.

Findings of the analysis include:

● Oil shale mining and processing will produce atmospheric emissions including those pollutants

for which National Ambient Air Quality Standards

(NAAQS) have been established (i.e., sulfur dioxide, particulate, carbon monoxide, ozone, lead,

and nitrogen oxides); as well as various other currently unregulated pollutants (such as silica,

sulfur compounds, metals, trace organics, and

trace elements).

● Under the Clean Air Act, oil shale development will

have to comply with NAAQS and State air quality

standards; maintain air quality, especially visibility, in adjacent Class I areas (e.g., national parks);

comply with prevention of significant deterioration

(PSD) increments (these specify the maximum increases in the concentrations of sulfur dioxide and

particulate that can occur in any region); comply

with New Source Performance Standards (NSPS);

and apply the best available control technology

(BACT).

● A wide variety of control technologies could be applied to the emissions streams from oil shale processes. They are fairly well developed and have

been successfully used in similar industries. They

should be adaptable to the first generation of oil

shale plants. However, full evaluation will not be

possible until they have been tested in commercial-scale oil shale plants for sustained periods.

of Findings

●

●

●

The costs of controlling air pollution will be particularly sensitive to the strictness of the environmental regulations and to the design characteristics and size of each project. Preliminary estimates

indicate that air pollution control could cost from

$0.91 to $1.16/bbl of syncrude produced (roughly 3 to 5 percent of the selling price of the oil).

The only means for predicting the long-range impacts of oil shale emissions on ambient air quality

in the oil shale area and in neighboring regions are

mathematical dispersion models, which are the

Environmental Protection Agency’s (EPA) tool for

enforcing the provisions of the Clean Air Act. Modeling of oil shale facilities presents a number of

problems because of the topography and meteorology of the region, the chemistry of the emissions,

and the unknown quantities of emissions expected

from commercial-size facilities. In addition, dispersion models developed to date have been primarily for flat terrain. Thus, their predictions contain significant inaccuracies. More R&D needs to

be undertaken in this area.

Even with the use of BACT, the industry’s capacity

will be limited by the air quality standards governing PSD. A preliminary modeling study by EPA has

indicated that an industry of up to 400,000 bbl/d

in the Piceance basin could probably comply with

the PSD standards for Flat Tops (a nearby Class I

area) if the plant sites were dispersed. Additional

capacity could be installed in the Uinta basin,

which is at least 95 miles from Flat Tops, A 1-million-bbl/d industry could probably not be accommodated because at least half of its capacity

(500,000 bbl/d) would be located in the Piceance

basin. Policy options to address this limitation include the application of more stringent emission

standards, changes in PSD increment allocation

procedures, and amending the Clean Air Act.

Water Quality

Water quality is a major concern in the oil shale region, especially in regard to the salinity and sediment

levels in the Colorado River system. The potential for

pollution from oil shale development could come from
Ch. 8–Environmental Considerations ● 257

point sources such as cooling system discharges;

from nonpoint sources such as runoff and leaching of

aboveground waste disposal areas and ground water

leaching of in situ retorts; and from accidental discharges such as spills from trucks, leaks in pipelines, or the failure of containment structures, Unless these pollution sources are properly controlled,

the lowered quality of surface and ground water

resources could adversely affect both aquatic biota

and water for irrigation, recreation, and drinking.

Specific findings include the following:

●

●

●

Surface discharge from point sources is regulated

under the Clean Water Act, and ground water reinfection standards are being promulgated under the

Safe Drinking Water Act. Solid waste disposal

methods may be subject to the Toxic Substances

Control Act and the Resource Conservation and

Recovery Act. The general regulatory framework is

therefore in place, although no technology-based

effluent standards have been promulgated for the

industry under the Clean Water Act. Nonpoint

sources present regulatory and technological difficulties, and at present are subject to less stringent

controls.

Developers are currently planning for zero discharge to surface streams and to reinject only excess mine water. This eliminates point discharge

problems because most wastewater will be treated

for re-use within the facility, and untreatable

wastes will be sent to spent shale piles. The costs

of this strategy are low to moderate, and development should not be impeded by existing regulations if it is used.

A variety of treatment devices are available for the

above strategy, and many of them should be well-

-suited to oil shale processes. However, uncertainties exist regarding whether conventional methods

would be able to treat wastewaters to discharge

standards because they have not been tested with

actual oil shale wastes under conditions that approximate commercial production. There are also a

number of uncertainties regarding the control of

nonpoint pollution sources. For example, no technique has been demonstrated for managing

ground water leaching of in situ retorts, nor has

the efficacy of methods for protecting surface disposal piles from leaching been proven. It is not

known to what extent leaching will occur, but if it

did, it would degrade the region’s water quality.

● Although control of major water pollutants from

point sources is not expected to be a problem, less

is known about the control of trace metals and toxic organic substances. Research is needed to assess their potential hazards and to develop methods for their management. Other laboratory-scale

and pilot-plant R&D should be focused on characterizing the waste streams, on determining the

suitability of conventional control technologies,

and on assessing the fates of pollutants in the

water system. Extensive work is already underway; its continuation is essential to protecting

water quality, both during the operation of a plant

and after site abandonment.

Occupational Health and Safety

The oil shale worker will be exposed to occupational safety and health hazards. Many of these–

such as rockfalls, explosions and fires, dust, noise,

and contact with organic feedstocks and refined

products–will be similar to those associated with

hard-rock mining, mineral processing, and the refining of conventional petroleum. However, the workers

might be exposed to unique hazards due to the physical and chemical characteristics of the shale and its

derivatives, the types of development technologies to

be employed, and the scale of the operations. Potential risks include safety hazards that might result in

disabling or fatal accidents, and health hazards

stemming from high noise levels, contact with irritant

and asphyxiant gases and liquids, contact with likely

carcinogens and mutagens, and the inhalation of fibrogenic dust.

Specific findings include:

●

●

Only a few fatalities have occurred during the mining of over 2 million tons of shale and the production of over 500,000 bbl of shale oil. The accident

rate has been one-fifth that for all mining, and

much lower than that for coal mining. However,

this record was achieved in experimental mines

that employed, for the most part, experienced

miners. Whether safety risks will increase or decrease as mining activities are expanded cannot

be predicted.

Although the carcinogenicity of oil shale dusts and

crude shale oil has been demonstrated by some investigators, the conflicting results of other studies

combined with an overall lack of information pre-
258 ● An Assessment of Oil Shale Technologies

●

●

●

elude a determination of the severity of the risk.

The incidence of diseases in other industries indicates that exposure to these materials could be

hazardous.

The large variety of substances that will be encountered in retorting may present as yet undetected health hazards. Of special concern is the

possibility of carcinogens in shale oil and its derivatives, Possible synergistic effects from the

products of modified in situ (MIS) operations

(which combine mining with retorting) could increase the level of risk.

Shale oil refining poses no special hazards since

most of its problems will be similar to those experienced in conventional petroleum refining.

Health and safety hazards will be reduced by

using pollution control technologies for air and

water pollutants and by requiring specific industrial hygiene practices. These are required by law

and are expected to be implemented by oil shale

developers. However, it is essential that R&D on

the nature and severity of health effects keep pace

with the development of the industry. Such information will be useful in identifying and mitigating

long-term effects on workers and the public.

Land Reclamation

An industry will require land for access to sites,

for the facilities, for mining, for retorting, for oil

upgrading, and for waste disposal. The extent to

which development will affect the land on and near a

given tract will be determined by the location of the

tract; the scale, type, and combination of processing

technologies used; and the duration of the operations. The facilities must comply with the laws and

regulations that govern land reclamation and waste

disposal. Nevertheless, there will still be effects on

land conditions (through altered topography) and

wildlife (through changes in forage plants and habitats). In addition, unless appropriate disposal and

reclamation methods are developed and applied, the

large quantities of solid wastes that will need to be

handled could pollute the air with fugitive dust and

the water with runoff and Ieachates from storage

piles and waste disposal areas.

Specific findings include:

●

●

●

●

●

●

Several approaches can be used to reduce the

deleterious effects associated with the disposal of

spent oil shale. These include reducing surface

wastes by using in situ processing or returning

wastes to mined out areas; the chemical, physical,

or vegetative stabilization of processed shale; and

combinations of the above.

Research has shown that vegetation can be established directly on processed oil shales. However,

intensive management is required, including the

leaching of soluble salts, the addition of nitrogen

and phosphorus fertilizers, and supplemental watering during establishment. Revegetating spent

shale covered with at least 1 ft of soil is less susceptible to erosion and does not require as much

supplemental water and fertilizer. Adapted plant

species are required for either option,

The long-term stability and character of the vegetation is unknown, but research on small plots

suggests that short-term stability of a few decades

is likely if sufficient topsoil is added.

Reclamation plans will have to be site specific

since environmental conditions vary from site to

site, Proper management will be required in all instances, if only to maintain plant communities in

surrounding areas. H is even more important in

the reclaimed areas.

Shortages of adapted plants and associated support materials such as mulches probably would

occur if a large (ea. 1 million bbl/d) industry is established. The problem is compounded by the increasing demands from other mining operations

such as coal and other minerals.

The Surface Mining Control and Reclamation Act

provides for the kind of comprehensive planning

and decisionmaking needed to manage the land

disturbed by coal development. New reclamation

standards that are applied to oil shale should provide for postmining land uses that are ecologically

and economically feasible and consistent with

public goals.
Ch. 8–Environmental Considerations 259

Permitting

During the past 10 years an increasingly complex

system of permits has been developed to assist the

Federal, State, and local governments in protecting

human health and welfare and the environment. Permits are the enforcement tool established by Congress and the States to determine whether a prospective facility is able to meet specific requirements

under the law.

Operation of an oil shale facility requires more than

100 permits from Federal, State, and local agencies.

Included are those for environmental maintenance,

for protection of worker health and safety, and for the

construction and operation of any industrial facility

(e.g., building code permits, temporary permits for

the use of trailers, sewage disposal permits). Of

these 100 permits, about 10 major environmental

ones require substantial commitments of time and resources.

Findings of the analysis include:

● The time required for preparing and processing a

permit application depends on the type of action

being reviewed, the review procedures stipulated

under the law, the criteria used by agencies to

judge the application, and the amount of public

participation and controversy that is brought to

bear. If Federal land is involved, then an environmental impact statement (EIS) will most likely be

required. The EIS process may take at least 9

months after the developer applies for permission

to proceed with the project. In the case of the current Federal lease tracts, additional time was

needed to prepare detailed development plans

(DDP) for approval by the Area Oil Shale Super-

●

●

visor of the U.S. Geological Survey (USGS). Once

the requirements for an EIS and DDP are satisfied,

obtaining all of the needed permits can take more

than 2 years. The project would not necessarily be

delayed by the full length of the permitting schedule, because other predevelopment activities such

as engineering design, contracting, and equipment procurement could proceed in parallel, if the

developer were willing to accept the risk that some

of the permits might not be obtainable.

The principal problems encountered to date with

the permitting process are related to the needs of

the regulatory agencies for technical information

and to differing interpretations of environmental

law. Future problems may be more critical than

those encountered thus far. Several relevant regulations are still pending that may increase costs or

force changes in the design of process facilities or

control technologies. They may also add to the

control requirements. Another problem that might

emerge is the ability of regulatory agencies to handle the increasing load of permit applications and

enforcement duties.

Several attempts are being made to simplify reguAir Quality

Iatory procedures. These include the streamlining

of permitting procedures within specific agencies;

the design and testing of a permit review procedure for major industrial facilities that will coordinate the reviews by Federal, State, and local

regulators; and the proposed Energy Mobilization

Board to expedite agency decisionmaking and reduce the impacts of new regulatory requirements.

Colorado has recently announced a joint review

process designed to accomplish the first two of

these ends.

Introduction

The maintenance of air quality is necessary for the development of an environmentally acceptable oil shale industry. In this section:

 The types of atmospheric contaminants

produced by oil shale unit operations are

characterized.

●

●

●

Rates are estimated for the generation of

air contaminants.

The applicable Federal and State air

quality regulations and standards are

described.

The effects of these regulations and

standards on a developing oil shale industry are analyzed.
260 ● An Assessment of Oil Shale Technologies

● The air pollution control technologies

that may be applied to untreated emission streams are described and evaluated. The net rates at which pollutants

will be emitted in treated streams are estimated.

● Modeling procedures that may be used

to predict and monitor compliance with

air quality regulations are discussed.

● Potential problems that commercialscale operations may encounter in meeting standards are identified.

● Key findings are summarized.

● Policy options are discussed.

Pollutant Generation

Oil shale mining and processing will produce atmospheric emissions including those

pollutants for which NAAQS have been established: sulfur dioxide (SO2

), particulate,

carbon monoxide (CO), ozone (0 S), lead, and

nitrogen oxides (NOX

); as well as various

other currently unregulated pollutants, such

as silica, sulfur compounds, metals, carbon

dioxide (CO2

), ammonia (NH3), trace organics,

and trace elements. The following discussion

examines the types of pollutants generated by

each unit operation. Where data are available, the rates at which these contaminants

will be produced by different oil shale facilities are estimated.

Unit Operations and Pollutants

Mining can be carried out either using underground (room and pillar) or surface (open

pit) methods. The sequential steps in roomand-pillar mining are drilling, blasting, mucking (collection of the blasted shale), primary

crushing, and conveying the reduced shale to

the surface for retorting. Potentially hazardous substances (silica, salts, mercury, lead)

may be released during blasting. Methane

may be released from underground gas deposits, and CO, NOX

, and hydrocarbons (HC)

may be emitted by incomplete combustion of

the fuel oil used both for blasting and in mobile equipment. In addition, particulate can

be emitted as a result of blasting, raw shale

handling and disposal, and activities at the

minesite that produce fugitive dust (particulate matter discharged to the atmosphere in

an unconfined flow stream).

Atmospheric emissions are expected to be

much larger in open pit than in room-andpillar mining because of the significantly

larger quantities of solids that must be handled on the surface. The mine dust problem

will be further aggravated by road dust from

transportation of overburden, and windblown dust from all operations.

Storage, transport, and crushing of oil

shale result in the emission of particulate,

CO, NOX

, SO2, and HC from fuel in diesel engines, and particulate and silica from fugitive dust. Dust is the chief pollutant. The

amount generated depends on the grade of

ore, the extent to which its size must be reduced for retorting, the number of transfer

points in the transportation system, and the

level and effectiveness of control strategies

used.

Retorting technologies generate process

heat by the combustion of fossil fuels, which

produces a number of atmospheric emissions.

The amount of SO2 emitted depends on the

sulfur content of the fuels used in the plant

and the extent to which sulfur-containing

product gases are treated. The volume and

concentration of hydrogen sulfide (H2S), carbonyl sulfide (COS), and carbon disulfide

(CS2

) in the offgas streams from retorts depend on the type of retorting technology. COS

has been detected in the offgases from Lawrence Livermore Laboratory’s simulated MIS

retorts and trace quantities of COS and CS2

have been reported in the offgases from the

Occidental MIS process under certain operating conditions. It is not known whether the

retort offgases from the Paraho, Union “B,”

TOSCO II, or Superior processes contain COS

or CS2

.

The major source of NOX emissions is the

combustion of fuel in boilers, air compressors, and diesel equipment. The specific levels depend on the combustor design, the extent of onsite fuel use, and the nitrogen content of the fuels used to produce process heat

or steam. Most of the fuels consumed in oil
Ch. 8–Environmental Considerations ● 261

shale plants will be produced onsite. Both directly heated aboveground retorts (AGR) and

MIS generally produce sufficient low-Btu gas

to meet retorting requirements, plus an excess for other onsite uses such as power generation. Indirectly heated aboveground retorts produce less fuel gas, but it has a higher

heating value. In either case, it is possible

that some shale oil will be burned for process

heat. Since both retort fuels (gases and shale

oil) contain nitrogen, they could potentially

emit more NOX

.

HC and CO will be emitted primarily in the

exhausts of mobile equipment and in flue

gases from boilers and other combustors. HC

will also be emitted in vapors from oil storage

tanks, pumps, flanges, seals, and compressors, and CO by blasting and rubblization

during the preparation of MIS retorts. Emission levels from storage tanks should not vary

with the type of retorting technology. The

other HC and CO sources have a dependence

on retorting technology that is similar to that

described for NOX

. Equipment-related emissions are a function of the amount of solids

that need handling on the surface.

The quantities and the chemical properties

of the particulate emitted vary with retorting technologies. Retorts like TOSCO II that

require fine shale feed and produce very fine

retorted shale, produce the largest amounts.

The pyrolysis of an organic material like oil

shale kerogen produces a certain amount of

polycyclic organic matter (POM). POM, which

is found in conventional crude oils, has also

been found in the carbonaceous retorted

shales from TOSCO II, Union “B,” and Paraho indirect retorts. It is rarely found in retorted shale that has been subjected to a

strong oxidizing environment such as that encountered in the Paraho direct retort.

Trace elements (particularly the heavy

metals) may be released by retorting operations. Compared with average rocks, Green

River oil shale contains much higher levels of

selenium and arsenic; moderately higher levels of molybdenum, mercury, antimony, and

boron; and lower levels of cobalt, nickel,

chrome, zirconium, and manganese.l At typical retorting temperatures (ea. 900° F (480°

C)), it is generally accepted that most trace

elements are not volatilized. They leave the

retort in the spent shale product and in particulate entrained in retort gases and shale

oil. Possible exceptions are antimony, arsenic, beryllium, boron, copper, fluorine, lead,

mercury, nickel, selenium, and zinc, which

could leave the retort as vapor and be condensed in the liquid product.2 The heavy

metals in raw shale oil are of economic concern because they tend to destroy the effectiveness of the catalysts used for refining. *

Their removal is not expected to present any

major problems to the refiner. Several proprietary techniques are available for this purpose. It has also been recognized that refining

catalysts need careful disposal because they

may contain nickel, cobalt, molybdenum,

chromium, iron, and zinc, in addition to trace

elements captured from the shale oil. Emissions can occur during the onsite regeneration of these catalysts and during the disposal

of spent catalysts in landfill operations.

Upgrading, refining, gas cleaning, and

power generation produce such pollutants as

CS2

, COS, SO2, H2S, NH3, and HC; with HC

being the dominant fugitive emission.) Particulate such as fly ash are also produced.

The handling and disposal of raw and retorted shale could create serious fugitive dust

problems. This dust may contain harmful particulate and possibly POM. The problems

are most severe for technologies like TOSCO

II that produce very fine spent shale. Dust

production should be less of a problem with

aboveground retorts like those of Paraho and

Union “B” that produce coarse spent shale,

They should be even less significant for MIS

because spent shale will remain underground

and will not be subjected to wind erosion.

The Amounts of Pollutants Produced

It is difficult at present to estimate the

quantities of air contaminants that would be

*Refinery modifications to mitigate this problem are discussed in ch. 5.
262 . An Assessment of Oil Shale Technologies

produced by a commercial-size oil shale facility. The only field measurements that have

been made to date have been for the smallscale, short-term pilot-plant or semiworks

operations of Colony Development, Paraho,

and Occidental Oil Shale.4 These facilities do

not simulate normal operating conditions in a

full-size facility, and the measurements that

have been made have been mostly of the regulated pollutants. Only a few of the nonregulated pollutants such as trace elements have

been measured, and those measurements

that have been reported show considerable

variation. Pollution production estimates

must therefore be confined to regulated pollutants and must strongly rely on theoretical

calculations.

The quantities of pollutants produced in an

industrial facility can be estimated by applying pollutant generation factors to the mass

flows of material through the plant. The procedure used for the calculation, although an

approximation, gives estimates of the problem’s scope. Generation factors obtained

from the literature were applied to the mass

balances published for Colony’s proposed

TOSCO II retorting plant on Parachute Creek,

for Rio Blanco’s combination of MIS and AGR

processing on tract C-a, and for the Occidental MIS operation on tract C-b. All flows were

scaled to a uniform production level of 50,000

bbl/d of shale oil syncrude. The results are

summarized in tables 34 through 36. Note

that the tables show levels of pollutant generation, not pollutant release.

Of the three designs—Colony, Rio Blanco,

and Occidental—Colony produces the largest

amount of particulate. This plan uses both

the most underground mining and TOSCO II

AGR, which requires a fine shale feed and

produces a very finely divided shale. This

retorting method is also responsible for Colony’s exceptionally high production of HC. In

the TOSCO II retorting system, vaporized

shale oil and gases evolved during pyrolysis

are stripped of high molecular weight HC in a

condenser, and then burned to reheat the

heat carrier balls. Because combustion is incomplete, lighter weight HC are entrained in

the offgas stream from the ball heater.

In generating steam for power, the Occidental design in which large quantities of

low-Btu gas are burned produces the most

NOX emissions. Rio Blanco, which plans to

burn coke from the upgrading units, produces

less NOX but more particulate. Colony’s onsite pollutant production in this step will be

negligible because it plans to purchase most

of its electricity from offsite powerplants.

The emission of SO2

, produced in the NH3

and sulfur recovery processes, is about the

same for all three designs. Although both Colony’s and Rio Blanco’s CO emissions are higher than Occidental’s, the differences are not

significant.

Table 34.–Pollutants Generated by the Colony Development Projecta (pounds per hour)b

Operation Particulate so, NO, HC c o

Mining . . . . . . . . . . . . . . . . 1,480 0 250 50 440

Shale preparation. . . . . . . . . . . 15,940 0 0 0 0

Retorting c. . . . . . . . . . . . . . . . . . . . . . . 11,440 150 1,430 480 60

Spent shale treatment and disposal . . . . . . . 1,350 0 130 10 0

Upgrading. . . . . . . . . . . . . . . . . . . trace 10 20 10 trace

Ammonia and sulfur recovery d

. . . . . ., 0 32,200 0 0 0

Product storage . . . . . . . . . . . . . . . . . . . . . 0 0 0 150 0

Steam and power. . . . . . . . . . . . . . . . . . – — — — —

Hydrogen production . . . . . . . . . . . . . . . . . 10 30 80 trace 10

Total ... . . . . . . . . . . . . ., . . . . . 30,220 32,390 1,910 700 510

c3Tafj~ shows the ItIVtIt Of pOllUlafll generation, not pollufanf release

b Room .

a n d .p i llar mlnlng, TOSCO II retorting, scaled 1050,000 bbl/d Of shale oll syncrude production

cFlgures do not include components of the product gas and VaPOr stream

also, equivalent of H*S m retort 9as stream

SOURCE T C Borer and J W Hand, /derr//hcal/on and Proposed CorJlro/ 01 A/r Po//ufartfs from O/l Sha/e Operations, prepared by the Rocky Mountain

Diwslon, The Pace Company Consultants and Engineers, Inc for OTA, October 1979
Ch. 8–Environmental Considerations ● 263

Table 35.–Pollutants Generated by the Rio Blanco Project on Tract C-aa (pounds per hour)b

Operation Particulates so, NO. HC co

Mining. ,, .,,,.. ,. 1,050

Shale preparation. . . . ., . . . . 7,200

Retorting ., 8,900

Spent shale treatment and disposal 650

Upgrading. ., ., 7

Ammonia and sulfur recovery d ., ., ., 0

Product storage ., ., 0

Steam and power. ~ ~ ~ ~ 210

Hydrogen production –

Tota l 18,017

4

0

52

0

0

19,200

0

250

—

340

200

320

0

7

0

0

1,220 —

80

0

100

0

13

0

105

13 —

430

0

0

0

0

0

0

0 —

19,506 2,087 311 430

aTab[e shows lhe level of poilulanl generation not pollutanf release

bundergroun~ mlnlng modlfled [n SIfU and TOSCO II aboveground retorlng scaled tO 50000 bblld of shale oll syncrude

cFlgures do not !nclude components of The product 9as and vaPor stream

also, ~qulvalen[ Of H,S In retofl 9as s(ream

SOURCE T C Borer and J W Hand /deohf/cat/on and Proposed Corrtro/ of A/r Po//ufarrts lrorn 0// Shale OperaOorrs prepared by the Rocky Mountain

Owslon The Pace Company Consultants and Eng(neers Inc for OTA Oclober 1979

Table 36.–Pollutants Generated by the Occidental Operation on Tract C-ba (pounds per hour)b

Operation Particulate so, NO, HC c o

Minin g 4,540 0 300 120 180

Raw shale disposal ~ 450 0 100 10 0

Retorting c ~ 0 0 0 0 0

Upgrading. . 10 10 80 trace 10

Ammonia and sulfur recover y

d 

. , 0 24,000 0 0 0

Product storag e 0 0 0 80 0

Steam and power. . 20 trace 2,800 0 0

Hydrogen productio n 80 20 220 20 20

Tota l 5,100 24,030 3,500 230 210

aTa~ie shows [he level of ~oliufan[ generation not pollutant release

bunderground mlnlng modlfted in sdu retorting scaled to 50000 bbl d Of shale 011 syncwde

cFlgures do not Include components of tne product gas and vaPOr stream

dsol equivalent o! HIS m reforl 9as stream

SOURCE T C Borer and J W Hand Idenhkaflon and Proposed Cofltrol of +Vr Po//ufartk from 0// .S/ra/e Opera(/orm prepared by the Rocky Mountain

Ow!s!on The Pace Company Consultants and Eng[neers Inc for OTA Oclober 1979

It should again be noted that the tables

show the amounts of pollutants generated,

not the amounts released. Pollutant emissions

are regulated by laws and standards, which

are discussed in the next section. Compliance

with these laws and standards requires pollution control technologies, which are discussed later in the

Air Quality

and

Introduction

chapter.

Laws, Standards,

Regulations

The existing and proposed regulations and

standards governing air pollution from the oil

shale industry are discussed here because

they will affect the design and operating

characteristics of oil shale facilities. They

may also act to constrain the ultimate size of

the oil shale industry.

Air quality regulation is called for by the

Federal Clean Air Act of 1970, as amended in

1977, hereafter referred to as the “Act.” Regulations and standards arising from this Act

are implemented at the Federal level by EPA

and at State levels in conjunction with additional regulations and standards imposed by

the individual States. The following discussion first highlights major provisions of the

Act, and then analyzes those that are particularly significant for oil shale development.

Highlights of the Amended Clean Air Act

The Clean Air Act, as amended, establishes a national program to regulate air
.

264 ● An Assessment of Oil Shale Technologies

pollution in order to maintain or improve air

quality. The Act is universally applicable, but

its provisions are most strongly directed to

those areas having the cleanest air (nondegradation areas) and those where air pollution

may be hazardous to public health (nonattainment areas). The major elements of the program established by the Act are:

●

●

●

●

the establishment of NAAQS for criteria

air pollutants,

the submission by each State of a State

implementation plan (SIP) to achieve and

maintain Federal air quality standards,

the preconstruction review of major new

stationary sources, and

PSD.

National ambient air quality standards.—

Regulation under the Act focuses on six criteria pollutants: particulate, SO2

, CO, NOX,

03

,, and lead. Two types of ambient air quality

standards are designated: primary standards, which protect human health; and secondary standards, which safeguard aspects

of public welfare, including plant and animal

life, visibility, and buildings. The Act sets

forth an exact timetable by which primary

standards are to be met. Secondary standards are to be met on a more flexible schedule.

To achieve air quality goals, areas with air

cleaner than NAAQS were divided into

Classes I, II, and III. Certain Federal areas

that existed when the Act was passed (e.g.,

national parks, wilderness areas) were immediately designated as Class I areas where air

quality was to remain virtually unchanged.

All others were designated as Class II—areas

in which some additional air pollution and

moderate industrial growth were allowed. Individual States or Indian governing bodies

can redesignate some Class II areas to Class

III—areas in which major industrial development is foreseen and contamination of the air

up to one-half the level of the secondary

standards would be permitted. The States or

Indians can also redesignate Class II areas as

Class 1. Either type of redesignation is subject

to hearings and consultations with the managers of affected Federal lands (and States in

the case of Indian action).

The classification of an area with respect

to the ambient air quality has important consequences. The Act divided the Nation into

247 air quality control regions (AQCRs) so

that pollution control programs could be locally managed. Compliance with an NAAQS

is generally determined on an AQCR basis,

but EPA allows smaller area designations for

some pollutants, if that is more suitable for

controlling pollution.

These AQCR designations are highly significant. Regions that are found by EPA to be in

nonattainment status—areas where air pollution presents a danger to public health—

are subject to a particular set of restrictions

under the Act. On the other hand, nondegradation regions—where air is cleaner than the

standards—are subject to a different set of

regulations, which are intended for “prevention of significant deterioration. ” Regardless

of an area’s classification, almost every new

major source of pollution is required to

undergo a preconstruction review.

State implementation plan.—Each State

must submit an implementation plan for complying with primary and secondary standards. A State can decide how much to reduce

existing pollution to allow for new industry

and development. State plans must also include an enforceable permit program for regulating construction or operation of any new

major stationary source in nonattainment

areas, or significant modification to an existing facility. New processing plants and power

stations must also satisfy emission standards

set forth in the SIP.

Preconstruction review of major new stationary sources.—Under the SIP, each new

construction project is subjected to five types

of preconstruction review. The objective of

the review process is to determine:

● compliance with NAAQS and State Air

Quality Standards (AQS);

● compliance with any applicable NSPS;

 suitability for a nonattainment area;
Ch. 8–Environmental Considerations ● 265

●

●

The

suitability for a nondegradation area.

(PSD regulations, including the use of

BACT and PSD increments* will apply);

and

visibility.

major elements of these preconstruction

review procedures are:

● Review for compliance with NAAQS.

The applicant must submit plans and

specifications for review that show:

methods of operation, quantity and

source of material processed, use and

distribution of processed material, and

points of emission and types and quantities of contaminants emitted; a description of the pollution control devices to be

used; an evaluation of effects on ambient

air quality and an indication of compliance with PSD restrictions; and plans

for emission reduction during a pollution

alert. A permit will not be given if it is

shown that the source will interfere with

the maintenance of any ambient air

quality standard or will violate any State

air quality regulation.

 Review for compliance with NSPS. The

Act directed EPA to set national standards for fossil fuel powerplants, refineries, and certain other large industrial

facilities. If NSPS have been established

for the new source, it must be shown

that the facility will not interfere with

the attainment or maintenance of any

standard and that BACT will be used for

reducing pollution.

● Review in nonattainment areas. In nonattainment areas, a new facility may be

built only if: by the time operations commence total emissions from it, and other

new and existing sources, will be less

than the maximum allowed under SIPS;

the source complies with the more stringent of either emission limitations required by the State or achieved in practice by such a source; and the owner or

operator demonstrates that all other ma-

*In part BAC’I’ is required 10 assure that no single facility

wili consume the entire PSf3 increment.

●

jor stationary sources owned or operated by him in the State comply with

emission limitations.

Review in nondegradation areas. This

type of review, which concerns PSD, is

discussed below.

The prevention of significant deterioration.—All SIPS must specify emission limitations and other standards to prevent significant air quality deterioration in each region

that cannot be classified for particulate or

SO2

, or has air quality better than primary or

secondary NAAQS for other pollutants, or

cannot be classified with regard to primary

standards because of insufficient information.

Under these PSD standards, maximum allowable increases in concentration of SO2

and particulate are specified for each area

class. For the other criteria pollutants, maximum allowable concentrations for a specified period of exposure must not exceed the

respective primary or secondary NAAQS,

whichever is stricter.

A State can redesignate a Class II or III

area with respect to PSD only if it follows certain procedures. These include an assessment of the impacts of the redesignation, public notice and hearings of such a redesignation, and approval by EPA.

If a facility’s construction began after January 1, 1975, a special preconstruction review must be undertaken if it is located in a

nondegradation area. To obtain a permit for

such a facility, an applicant must demonstrate that it will not cause air pollution in excess of NAAQS or PSD standards more than

once per year in any AQCR. BACT must be

used for all pollutants regulated by the Act,

and the effects of the emissions from the facility on the ambient air quality in the areas

of interest must be predicted. The air quality

impacts that could be caused by any growth

associated with the facility must also be analyzed.

63-898 0 - 80 - 18
266 ● An Assessment of Oil Shale Technologies

Implications of the Clean Air Act for

Oil Shale Development

The following provisions of the Act have

particular significance for oil shale development:

● compliance with NAAQS and State AQS;

● maintenance of air quality, especially

visibility, in adjacent Class I areas (e.g.,

national parks);

● compliance with PSD increments;

● compliance with NSPS; and

● the application of BACT.

National Ambient Air Quality Standards.—Ambient air quality standards promulgated by individual States cannot be less

stringent than the national standards. Thus,

the States set the controlling standards if

there is an approved SIP. Utah’s standards

are identical to the national standards, while

Colorado and Wyoming have set more stringent standards for a number of the criteria

pollutants. Table 37 shows both the national

standards (the same for Utah), and Colorado’s and Wyoming’s standards. In addition

to the standards shown for Wyoming, the

State has also promulgated regulations to

limit ambient concentrations of H2S, hydrogen fluoride, and other pollutants. The standards are more relevant to large coal-fired

powerplants than they are to oil shale processing.

Since the national standards are primarily

directed to urban areas, they should not seriously restrict oil shale development in the

near future. The annual-average pollution

levels allowed by ambient standards are

much higher than the values normally measured in the oil shale development area. However, the short-term standards for particulate and HC are occasionally exceeded by

natural emissions such as windblown dust

and HC aerosols produced by revegetation.

Such naturally caused infractions of NAAQS

could have restricted regional development.

They actually did affect oil shale development

schedules on the four lease tracts

Colorado and Utah. According to

located in

the provitable 37.–The Federal and State Ambient Air Quality Standards and Prevention of Significant Deterioration

Standards That Influence Oil Shale Development (concentrations in micrograms per cubic meter)

Prevention of significant

Ambient air quality standards deterioration standards

Federal (primary) Federal (secondary) Federal

Pollutant human health public welfare Wyominga

ColoradoaUtaha

(Class 1) (Class II)

so,

Annual arithmetic mean, . .

24-hour maximum .. .

3-hour maximum . . . . . . .

Particulates

Annual geometric mean. . . .

24-hour maximum . . .

/VOX (as NO,)

Annual arithmetic mean. . . . .

Oxidants (as O,)

l-hour ., ., ., ... . .

co

8-hour maximu m

l-hour maximum . . . . .

Lead

Quarterly .

Nonmethane hydrocarbons

3-hour maximum (6-9 am). .

80

365

None

None

None

1,300

60

260

1,300

80

365

700

80

365

None

2

5

25

20

91

512

75

260

60

150

60

150

45

150

75

260

5

10

19

37

100 100 100 100 100 None None

240 240 160 160 240 None None

10,000

40,000

10,000

40,000

10,000

40,000

10,000

40,000

10,000

40,000

None

None

None

None

1,5 1.5 1,5 1.5 1 5 None None

160b160b

160b

160b160bNone None

astate amblen( alr ~uallly qandards are ,de”tl~al to the Federal prlrnary standards unless prlfllecl lrl llallcs The s!ncter standard IS the Conlro[llrlg standard

bNot a standard, a guide 10 show achievement of o] standard

cAllowable Incremental change m ambient Coflcefltratlon

SOURCE Olf{ce of Technology Assessment
Ch. 8–Environmental Considerations . 267

sions of the Act, the tracts and their environs

were nonattainment areas. As such, they

were not subject to any additional development. This potential barrier was cited by

some of the tract lessees in their requests for

activity suspensions in the fall of 1976.

In December 1976, EPA ruled that new development could proceed in a nonattainment

area if the developer would offset new emissions by reducing the same emissions from an

existing source in the same area. Although

possibly applicable to urban or industrialized

areas, such a policy was not relevant to the

oil shale regions because there are no substantial existing industries against which to

offset oil shale emissions. EPA made a subsequent ruling in July of 1977 that air quality

problems arising from natural sources would

not preclude oil shale development, providing

that facilities complied with emission and

PSD standards. The history of this ruling and

its effects are discussed in detail in the

analysis of the Prototype Oil Shale Leasing

Program. (See vol. II.)

A second consideration is the visibility protection afforded to Federal mandatory Class I

areas under the Act. Regulations are to be

promulgated by EPA by November 1980, and

by the States by August 1981. These regulations may affect the siting of future oil shale

facilities.

Compliance with standards for PSD.—PSD

standards exist for Class I, II, and III areas.

The oil shale area is a Class II region, which

means that some additional pollution will be

allowed, but pollution up to the level of ambient air quality standards will not be acceptable. EPA’s PSD standards define the maximum allowable increases in S02 and particulate concentrations. These standards are

shown in table 38.

In summary, an oil shale facility will have

to meet the PSD requirements for Class II

areas, and moreover, it will not be allowed to

degrade air quality in nearby Class I areas

beyond the limits specified under the PSD

provisions of the Act. Because most pollutants emitted by oil shale facilities can travel

long distances, the stringent PSD increments

Table 38.–National Standards for Prevention of

Significant Deterioration of Ambient Air Quality

(concentrations in micrograms per cubic meter)

Maximum allowable increase

Pollutant Averaging time Class I Class II Class Ill

Particulate s Annual 5 19 37

24 hour 10 37 75

so, ., Annual 2 20 40

24 hour 5 91 182

3 hour 25 512 700

aEpA IS presently developing Incremental standards tor HC CO O, NOX and pb

SOURCE Environmental Profechon Agency Work Group Po//ufIorI Cm(m) Guidance (or 01/ Sha/e

De(e/oprr?en/ Appendices 10 /he Rewsed Llraf/ EPA Clnclnna!l Ohto July 1979 p

0-17

for Class I areas could affect the siting of oil

shale facilities. Figure 59 shows the Class I

areas located near oil shale country in Colorado, Utah, and Wyoming. The two Colorado

areas nearest the oil shale deposits are the

existing Flat Tops Wilderness and the proposed Dinosaur National Monument.

Preconstruction review for oil shale facilities.—Under the Clean Air Act, each new oil

shale plant must be evaluated during a preconstruction review to determine its ability to

comply with NAAQS and PSD regulations.

Projected emission levels will be regulated by

EPA’s NSPS, State emission standards, and

the mandated use of BACT.

At present, there are no Federal emission

standards that deal specifically with oil shale

operations. However, NSPS have been developed for fossil-fuel-fired steam generators,

petroleum refineries, and Refinery Claus

Sulfur Recovery Plants. Table 39 lists the existing and proposed NSPS for these facilities

as a guideline to what might be considered

for oil shale plants. In addition, Colorado has

developed emissions standards for shale oil

production and refining that limit the sum of

all S02 emissions from a given facility to 0.3

lb/bbl of oil produced or processed. Plants

smaller than 1,000 bbl/d are exempt. Another

Colorado regulation limits H2S ambient concentrations from all shale oil plants to 142

micrograms per cubic meter (142 pg/m3 or 0.1

p/m). Utah and Wyoming do not have applicable emission limits. BACT standards have

been developed by EPA for those oil shale facilities that have applied for PSD permits, as
268 . An Assessment of Oil Shale Technologies

Figure 59.— Designated Class I Areas in Oil Shale Region

WYOMIN G

‘ -- —

- -

- -

-

DAGGETT I

.

MOFFAT

● GRI==STONE

VER;AL

—r-~-”

I I . I

UINTAH 1

<b

.. —. —.—. —. — .—. —

BONANZA I

g ● RANGELY MEEKER —,

LDINOSAUR I

.

●

-~k

. .

●

●

_ 1<

T

-1 ● ●

xl% RIO BLANCO A “ —. —.-

$’Y L

u -r

L

3: ● —* —* J

RIO BLANCO .

. —.—.3

“L.— . ~

J GARFIELD GLENkVOOD%J1

“—.—.—.— . SPRINGS

‘.-. I

‘RAND::YA* +

.—.—.—. — . i L>.—.

r

GRAND

s

LEGEND:

❑ FOREST AREAS

i

I

MESA ‘“;.vDELT~-’-r- &

I

.

L . —.—. — .–.5? (

I

I

.

I

. —. —. — . J

I MONTROSE

5

i

GUNNISON

AREA DESIGNATIONS

Federal Mandatory Class I Areas: 1, 2, 3,4, 6

Colorado Class I Areas: 5, 6,8

Draft Proposed (NPS) Class I Areas: 6, 8

CLASS I AREAS

1. Flat Tops Wilderness 5. Black Canyon of the

2. Mount Zirkel Wilderness Gunnison Monument

3. Maroon Bells—Snowmass Wilderness 6. Colorado National Monument

4. West Elk Wilderness 7. Arches National Park

8. Dinosaur National Monument

SOURCE: Environmental Protection Agency Work Group,~0//ut/orIc20~fr0/ Gwdarme /of 0// Shale ~eveloweflf Awerrdmes to (he Rev/seal Draft, U S. Environmental

Protection Agency, Clnclnnatl, Ohio, July 1979, p. D.41
Ch. 8–Environmental Considerations . 269

Table 39.–National New Source Performance Standards for Several Types of Facilities’

Operation Pollutant Removal or emission standardb

Status

Fossil fuel fired steam generators Particulates 0.1 lb/m Btu Existing

S02

, NOx 0.8 lb/m Btu for gaseous fuels; 0.3 lb/m Btu for liquid fuels

Petroleum refineries H2S 0.1 gr/scf (dry) Existing

HC Floating roof tanks or vapor recovery systems if true vapor

pressure IS between 1,5 and 11,1 lbt/in2

a and reporting

system only if pressure is less than 1.5 lbf/in2

a

Refinery Claus sulfur recovery plants H2S 0,1 gr/scf (dry) Existing

Sulfur 250 p/m SO, for oxidation systems, 300 p/m total sulfur and

10 p/m H2S for reduction systems

Gas turbines NOx 75 p/mat 15Y0 oxygen Proposed for units over 10

so, 150 p/m m/ Btu per hour

Gasification plants Sulfur 99,0% removal and 250 p/m total sulfur Guideline

HC 100 p/m

Field gas processing units H2S 160 p/m Proposed

so, 250 p/m for oxidation systems

Sulfur 300 p/m for reduction systems

apre~ented ~~ ~ g“lde to what mlghl be considered for oll shale facl[llles

bib, ,nza = ~ound~ ~er square Inch absolute p/m = ~er mltlron Scf = standard cubic feel

cStandards tor fossil fuel fired steam generators being fevlsed

SOURCE Environmental protection Agency Work Group Pol)ul/on Con/ro/ Gu@arme for OIJ Sha)e Deve/opmenl ,.lppendmes fo fhe RewseO Dra(f. EPA Clnclnnatl Oh!o July 1979 p D 34

shown in table 40. These standards specify

levels of removal efficiency for specific

pollutants, and in some cases also define the

maximum concentration that will be allowed

in the emitted stream.

In summary, oil shale facilities will have to

undergo preconstruction review. BACT will

be required for all pollutants regulated by the

Act, and plants will have to comply with ambient air quality and PSD standards for Class

II areas. Facility siting might be affected by

PSD standards in adjacent Class I areas. The

effects of visibility standards, which have yet

Table 40.–EPA Standards for Best Available Air Pollution

Control Technologies for Oil Shale Facilitiesab

.

Pollutant Removal requirement

Sulfu r 99.0% total recovery

Particulates. 99.O% from combustion

gas streams

99 80/o from materialshandling gas streams

Fugitive dust control

NOx Complete combustion

c o Complete combustion

HC Complete combustion

Maximum emissions

15 p/m H2S (reduction systems)

250 p/m SO2 (oxidation systems)

No standard

0.5lb/mBtu

No standard

No standard

ap m = pafls per mlllhon

~These s[andards hake been used In EPA s PSO Cleclslon process In the Pas!

SOURCE Enilronmenlal Proteclton Agency Work Group Po//olIon Cor?ko/ G~,dancr for 0/1 Sha/e

Lleveopmenf 4ppeoUmes to /he Rewsed Llraf! EPA Clnclnnah Ohio July 1979 p

D 35

to be promulgated, cannot be determined at

this time.

Air Pollution Control Technologies

In order to comply with the air quality laws

and regulations, oil shale facilities will have

to control their pollutant emissions. Various

aspects of pollutant control are discussed in

this section.

●

●

●

The control technologies that can be

used to reduce emissions of particulate,

H2S, sulfur compounds, NOX

, HC, and CO

are described, and their potential applications to oil shale mining and processing are discussed.

The technological readiness of these

techniques are evaluated.

The costs of air pollution control in commercial-scale oil shale plants are estimated.

Technologies and Applications

DUST CONTROL

Water sprays. —Water sprays can be used

to control fugitive dust. If adjusted properly,

no surface runoff will result. Water sprays
270 An Assessment of Oil Shale Technologies

are about 80-percent efficient for particles

larger than about 5 microns, * but less so for

smaller ones. Adding a wetting agent reduces

the surface tension and improves the wetting,

spreading, and penetrating characteristics of

the water, increasing efficiency to 90 to 98

percent. Chemical binders, such as latex or

bitumastics, can also be added. They aid in

particle agglomeration and also increase the

efficiency of removal. Water sprays, with or

without chemical additives, are potentially

applicable to raw and spent shale storage

and disposal, to crushing and screening, to

mining and blasting, and to surface transportation. They could also control traffic dust

from temporary roads, Larger, more heavily

traveled roads would probably need to be

paved.

Cyclones.—Cyclone separators remove

dust by means of centrifugal force. Single cyclones remove about 90 percent of the larger

particles, but less than 50 percent of those

smaller than about 10 microns. Their removal

efficiencies could be increased by using second-stage cleaning in scrubbers, filters, or

precipitators. Cyclones will be used largely to

clean retort gases, and possibly for primary

dust control in crushers and enclosed conveyors.

Scrubbers.— Wet scrubbers use water to

remove dust entrained in gas streams. Many

different types of devices are available, including spray chambers, wet cyclones, mechanical scrubbers, orifice scrubbers, venturi scrubbers, and packed towers. High-energy venturi scrubbers are probably the only

type that have sufficiently high removal efficiencies to satisfy emissions standards. Efficiencies between 93.6 and 99.8 percent have

been achieved for particles smaller than 5

microns, but these efficiencies entail high

pressure losses and constant gas flow rates.

Scrubbers require considerably more energy

than baghouse filters or electrostatic precipitators. Scrubbers for particulate removal will

*A micron is one-millionth of a meter. Removal efficiencies

for different particle sizes are important because effects on

respiration and visibility vary with the particle size.

probably be used for gas streams from retorts and solid heaters.

Baghouse filters.—Fabric filters are generally used where higher removal efficiency

is required for particles smaller than about

10 microns. A large number of bag-shaped filters would be needed to clean large gas flows.

In general, all of the filters would be enclosed

in the same structure, called a “baghouse,”

and would share input and output gas manifolds. As a gas stream passes through the

baghouse, dust is removed by one or more of

the following physical phenomena: intersection, impingement, diffusion, gravitational

settling, or electrostatic attraction. The initial filtration creates a layer of dust on the

bag fabric. This layer is primarily responsible

for this method’s high removal efficiency; the

filter cloth serves mainly as a support structure. The operation is very similar to that of a

household vacuum cleaner.

The efficiency of a baghouse filter depends

on the particle size distribution, the particle

density and chemistry, and moisture. Under

most conditions a properly designed and operated baghouse will achieve a removal efficiency of at least 99 percent for particles as

small as 1 micron. Baghouse filters are likely

to be used for dust removal from crushers,

screens, transfer points, and storage bins.

Electrostatic precipitators.—In electrostatic precipitators, an electrical charge is induced on the surface of a dust particle and

the particle is captured on a screen having

elements with the opposite charge. Dry precipitators have been used for many years;

wet precipitators and charged droplet scrubbers have been developed more recently. All

types are in common use in the electrical

power generating industry, in cement and

steel plants, and in many other industries.

Precipitators have removal efficiencies of up

to 99.9 percent, require little maintenance,

can handle large flow rates, and have low energy requirements. They might be used in several oil shale operations, including mine ventilation and the second-stage cleaning of dust-
Ch. 8–Environmental Considerations . 271

laden streams from crushers and conveyors.

A wet precipitator was used at the Paraho

demonstration plant for the combined removal of shale oil vapors and particulate from

the retort offgas. One is being used in the

Petrosix plant in Brazil for the same purpose.

HYDROGEN SULFIDE CONTROL

The systems for removing H2S that are likely to be used for oil shale operations can generally remove at least 98 percent of this pollutant. They will probably be applied to gas

streams from retorting and upgrading operations.

Stretford Process.—In this process, the

gas stream is scrubbed in an absorption

tower with a solution containing sodium carbonate, sodium metavanadate, and anthraquinone disulfonic acid (ADA). Reduction of

the metavanadate with H2S in solution causes

sulfur to precipitate. The metavanadate is regenerated by oxidation with the ADA, and the

reduced ADA is then regenerated by being

oxidized in an air stream. The process was

developed for coal- gas treatment, but it has

been used for many other purposes in a number of plants, especially oil refineries, in the

United States and Europe.

Any COS and CS2 that may also be in the

gas stream would not be removed in this process and their presence would interfere with

H2S removal. Therefore, before H2S removal

the gas stream would need to be pretreated to

remove these compounds.

Selexol and other physical absorption

processes. —In these processes, H2S is dissolved in a solvent and subsequently recovered. The solvent is recycled. The earliest

process, a simple water wash, was inefficient

because H2S is not very soluble in water.

Modern processes use solvents in which it is

more readily dissolved.

Absorption processes are usually used for

treating high-pressure gases and for reducing

the concentrations of H2S and other sulfur

compounds to extremely low levels. These

processes involve the selective absorption of

H2S from gases containing CO2

. This produces

an H2S-rich stream that can be processed in a

Claus plant (see below). Absorption processes

can also remove sulfur compounds, such as

COS, CS2

, mercaptans, and thiophenes, which

cannot be processed in a Stretford unit. Because of its low cost and simplicity, the Selex01 process is a good candidate for use in oil

shale plants.

Claus process.—The Claus process, which

is perhaps the oldest and best known method

for recovering sulfur from streams that contain both H2S and SO2

, has several variations.

With a feed stream containing only H2S, the

required S02 is obtained by oxidizing part of

the H2S to S02 by burning it in air, and then

mixing the combustion products with the feed

stream. The S02 and H2S are then reacted

with each other in a series of converters to

produce elemental sulfur, which is removed

by condensation. The feed stream must have

a relatively high concentration of sulfur compounds in order to achieve a high conversion

efficiency with reasonable equipment size.

This process has problems with both maintenance and downtime, thus backup units are

often needed. Problems arise from sulfur condensation in the supply and product pipelines. The procedures for startup and shutdown are time-consuming, and moisture and

CO2 in the feed gas are particularly troublesome.

The tail or treated gas from a Claus plant

still contains fairly sizable concentrations of

H2S and S02

. It can be recirculated, mixed

with a large volume of stack gas and released, or treated in other systems. In oil

shale plants, it is likely that the Claus plant

effluent would require further treatment before being released. Processes developed specifically for this purpose include the SCOT,

Beavon, and IFP techniques described below,

 SCOT (Shell Claus Offgas Treating) process. In this process, the offgas is heated

with a reducing gas such as hydrogen,

and the mixture is passed through a cobait-molybdate catalyst bed where all

the sulfur compounds are reduced to

H2S. The gas is then sent through an absorber where the H2S is dissolved and
272 . An Assessment of Oil Shale Technologies

concentrated. The concentrated H2S is

liberated from the absorbing medium by

heating and is returned to the Claus

plant.

The SCOT process is adversely affected by high concentrations of CO2

.

Since gaseous emissions from oil shale

processing are expected to be rich in

CO2

, higher rates of recycling, more complete fuel combustion, and perhaps

steam injection to dissolve the CO2 may

be necessary.

● Beavon process. In this process, the tail

gas from a Claus plant is mixed with hot

combustion gases and passed through a

catalyst where all the sulfur compounds

are converted to H2S. The H2S-rich gas is

cooled by a slightly alkaline buffer solution and then treated in a Stretford unit.

The Beavon process is also adversely affected by high CO2 concentrations in the

feed stream. Its use in oil shale plants

would require adaptations similar to

those needed for the SCOT process.

● IFP [Institute Francais du Petrok] process. The basic reaction in this process is

the same as in the Claus process except

that it takes place in a liquid rather than

a gaseous phase. The liquid is a polyalkylene glycol with a 5-percent concentration of a glycol ester catalyst. Both H2S

and S02 are very soluble in this liquid,

and efficient conversion to sulfur results. The most important operating variable is the H2S to S02 ratio which must

be at least 2. The process is flexible and

can accommodate wide changes in contaminant concentrations while maintaining constant conversion rates. Also, because the gases can be treated at higher

temperatures than in other processes,

heat losses are reduced.

SULFUR DIOXIDE CONTROL

The amount of SO2 that will have to be removed will depend on the prior degree of gas

treatment and the type of fuel used in processing. Most oil shale plants will probably use

desulfurized fuel for heating, processing, and

power generation. Where large amounts of

SO2 are emitted, such as in the tail gas of a

Claus plant, its control may be required. The

following technologies could be used for this

purpose.

●

●

●

Wellman-Lord process. This is a versatile process, widely used by many different industries, and should be adaptable

to the oil shale industry. Colony plans to

use it for a commercial-scale above-

-ground retorting plant.

This process relies on the reaction of

SO2 with sodium sulfate to produce sodium bisulfite. The bisulfite solution is

next heated in an evaporator. This reverses the reaction, liberating a concentrated stream of SO2

. The SO2 can then

be converted to either elemental sulfur

or sulfuric acid. The regenerated sodium

sulfate produced when the reaction is

reversed by heating, is dissolved and recycled. The current version of this process is considered to be a second-generation technique for SO2 removal. Previous

problems with sludge production and

scaling have been reduced.

Double alkali process. Double alkali

technology resembles conventional wet

stack-gas scrubbing methods but avoids

most of their problems by using two alkaline solutions, sodium hydroxide and sodium sulfite, to convert SO2 to sodium bisulfite. The spent scrubber solution is regenerated by using lime or limestone to

convert the bisulfite to sodium hydroxide

and a precipitate that is a mixture of calcium sulfite and calcium sulfate. The

precipitate sludge, which contains the

captured S02

, can be disposed of in

ponds.

Performance of the system is wellestablished, and over 99-percent S02 removal has been achieved with S02 concentrations in the treated flue gas of less

than 10 p/m. Potential environmental

problems are associated with waste disposal because the solid residue contains

soluble alkaline sodium salts that could

pollute surface and ground water in the

vicinity of disposal sites.

Nahcolite ore process. Nahcolite is a

mineral that contains 70 to 90 percent
Ch. 8–Environmental Considerations 273

sodium bicarbonate. It is found in the oil

shale deposits in the central Piceance

basin of Colorado. When crushed and

placed in contact with hot flue gases in a

baghouse, nahcolite converts SO2 to dry

sodium sulfate. Typically, 20 percent of

the required nahcolite would be used to

precoat the filter bags in the baghouse,

and the remainder would be sprayed directly into the flue gas stream. The sodium sulfate produced and any unreacted

nahcolite would be sent to disposal,

Pilot-plant experiments have shown that

S02 removal efficiencies are between 50

to 80 percent depending on flow rates

through the baghouse and the ratio of

nahcolite to SO2

.

NITROGEN OXIDES CONTROL

Nitrogen oxides are produced in the combustion of fuels, NOX control can be approached in two ways: by adjusting combustion conditions to minimize NOX production,

or by cleaning the NOX that is produced from

the stack gases, At present oil shale developers plan to design combustor conditions for

low NOX production. Gas cleaning systems

could be added in the future, if the need

arises for further NOX control, However, with

proper design and maintenance of combustion equipment, external control systems will

probably not be needed in order to comply

with existing regulations.

HYDROCARBON AND CARBON MONOXIDE CONTROLS

The emission of HC and CO will be caused

by the incomplete combustion of the fuel for

the boilers, furnaces, heaters, and diesel

equipment used in oil shale plants, The control of external combustion sources such as

boilers is primarily through proper design,

operation, and maintenance. Well-designed

units emit negligible amounts of CO and only

small amounts of HC. Instrumentation is

needed to assure proper operating conditions, and comprehensive maintenance programs will be needed to keep emission levels

from rising due to fouling and soot buildup.

The proper maintenance of diesel and other

internal combustion engines can similarly

keep HC and CO emissions very low. Treating

the flue gas from combustion sources for particulate or SO2 will also reduce HC and CO

emissions. With proper maintenance, it will

probably be unnecessary to further reduce

emissions from these sources.

Other emissions of HC will be caused by

preheating raw shale prior to retorting and

by storing crude shale oil and refined products. Incineration is probably the only realistic way to control them. Storage tank emissions can be minimized by using floating-roof

tanks, which can accommodate higher vapor

pressures than cone-roof tanks without the

need for venting.

OTHER EMISSIONS CONTROLS

Emission control by direct flame incineration systems (also called thermal combustion)

is widely used to reduce the amounts of HC

vapors, aerosols, and particulate in gas

streams. These systems are also used to remove odors and reduce the opacity of plumes

from ovens, dryers, stills, cookers, and refuse

burners. The operation consists of ducting

the process exhaust gases to a combustion

chamber where direct-fired burners burn the

gases to their respective oxides. A welldesigned plant flare system is a good example

of direct incineration control.

Catalytic incineration is also used for the

same purpose. The chief difference is that the

combustion chamber is filled with a catalyst.

On contact with the catalyst, certain components of the process gases are oxidized.

The use of a catalyst allows more complete

combustion at lower temperatures, thus reducing fuel consumption and allowing the use

of less expensive furnace construction. However, catalysts are generally selective and

may not destroy as many contaminants as direct flame incineration. In addition, because

of the potential for catalyst fouling and poisoning, gas streams may need to be cleaned of

smoke, particulate, heavy metals, and other

catalyst poisons,

Condensation is usually combined with

other air pollution control systems to reduce

the total pollutant load on more expensive

control equipment. When used alone, conden-
274 ● An Assessment of Oil Shale Technologies

sation often requires costly refrigeration to

achieve the low temperatures needed for adequate control.

Several methods can be used for cooling

the gas streams. In surface condensers, the

coolant does not contact the vapor or condensate; condensation occurs on a wall separating the coolant and the vapor. Most surface

condensers are common shell-and-tube heat

exchangers. The coolant normally flows

through the tubes; the vapor condenses on the

cool outside tube surface as a film and is

drained away to storage or disposal.

Contact condensers usually cool the vapor

by spraying a liquid, at ambient temperature

or slightly cooler, directly into the gas stream.

They also act as scrubbers in removing vapors that do not normally condense. The use

of quench water as the cooling medium results in a waste stream that must be contained and treated before discharge.

The equipment used for contact condensation includes simple spray towers, high-velocity jets, and barometric condensers. Contact condensers are, in general, less expensive, more flexible, and more efficient in removing organic vapors than surface condensers. On the other hand, surface condensers

recover marketable condensate and present

no waste disposal problem. Surface condensers require more auxiliary equipment and

need more maintenance.

Condensers have been widely used (usually

with additional equipment) in controlling organic emissions from petroleum refining, petrochemical manufacturing, drycleaning, decreasing, and tar dipping. Refrigerated condensation processes are being used for the recovery of gasoline vapors at bulk terminals

and service stations.

The Technological Readiness of Control Methods

As indicated, there are a wide variety of

control technologies that could be applied to

the emissions streams from oil shale processes. The selection of suitable technologies

for a given facility would be based on a number of factors. The degree of control needed

for each regulated pollutant would depend on

the size of the facility; its location; the nature

of the oil shale deposit; the mining, processing, and refining methods; the desired mix of

products and byproducts; the characteristics

of untreated emissions streams; and the emissions levels allowed by applicable environmental standards. The specific control equipment selected would be influenced by all of

these factors, plus such considerations as the

proximity to water and electrical power, the

availability of land for solid waste disposal,

the labor and material requirements for

maintenance, the ease of operation, the demonstrated reliability in similar industrial situations, the availability of equipment, the experience of the developer, and the cost.

An important consideration is the relative

technological readiness of each control method being considered. A developer needs confidence that a method can be directly transferred to oil shale operations from other industries without undergoing extensive R&D.

All of the techniques described previously

have been applied to industrial processes

similar to those encountered in mining, retorting, and upgrading of oil shale and its products. However, there are three characteristics of the potential oil shale industry that require extrapolating these technologies beyond the present levels of knowledge: the

scale of oil shale operations, the physical

characteristics of the shale, and the nature of

the emissions streams.

Scale of operation.—The proposed mining

operations are among the largest ever conceived and as such will require extraordinary

efforts to control air pollution. For example,

underground mining on tracts U-a and U-b

would have mine ventilation rates as high as

12 million ft3

/min. Cleaning this volume of gas

could be both difficult and expensive. The

large ventilation volume is required by mining

health and safety regulations and cannot be

reduced.

Open pit mines could be much larger than

underground mines. Problems with fugitive

dust would be increased by the larger quantities of solids that must be handled on the
Ch 8–Environmental Considerations ● 275

surface. Much relevant experience has been

gained through the extraction and processing

of other minerals such as coal, copper, uranium, and bauxite. The simpler control techniques (such as water sprays) have been

thoroughly demonstrated. However, the potential size of oil shale mines may create

problems for the more complex, collectiontype control systems that have worked well in

smaller mines. The cost of air pollution control for deeply buried oil shale deposits is not

known. The amount of overburden that must

be removed, and for which pollution control

would be needed may be prohibitively large.

Physical characteristics of the shale.—Oil

shale is a fine sedimentary material held

together by its kerogen content. When processed in certain retorts (such as TOSCO II or

Lurgi-Ruhrgas) the shale can disintegrate into

fine particles that are more difficult to collect

and control than other mineral dusts. Other

retorts (such as Union “B” or Paraho) will

produce a coarser product with fewer problems from dust. It is uncertain whether electrostatic precipitators will perform effectively in commercial-scale operations because

not much is known about the electrical properties of raw and spent shale particulate.

Characteristics of emissions streams.—To

date, the streams from small-scale versions of

discrete subprocesses (such as pilot retorts)

have been used to obtain preliminary evaluations of the efficiencies of pollution control

technologies. It is not known whether these

streams accurately represent the streams

that would have to be controlled in an integrated commercial-scale plant. For example,

it is not certain that the pollutants generated

by commercial-scale retorting, when combined with the pollutant streams from other subprocesses (such as upgrading), could be adequately controlled with conventional methods. Also, the effect of volatilized trace

elements on the catalysts used in the SCOT

and Beavon tail-gas cleaning systems and in

incinerators has not been determined, The

concentration of some of the pollutants generated by certain processes may be too low for

efficient control. For example, it is unknown

whether conventional H2S control methods

will work well with the low H2S concentrations in the offgas from MIS retorting. Removal efficiencies that are too low could have

conflicted with EPA’s previous BACT standards for oil shale facilities, which required

99-percent total sulfur recovery, no matter

how small the concentration of sulfur compounds in the raw gas stream.

The technological readiness of the major

control techniques is summarized in table 41.

The readiness of dust control methods is

shown to range from low to high, with a high

confidence in water sprays, cyclones, and

scrubbers and a medium confidence in baghouses and a low to medium confidence in

electrostatic precipitators. Similar ranges

are shown for the other control techniques,

The readiness of the nahcolite S02 removal

process is rated as low because only a few

test results have been published for its performance with oil shale streams. Also, the

technology is relatively new and has not been

used extensively in other industries.

The Claus H2S process is regarded highly

because it has a long record of successful

application worldwide. The SCOT and

Beavon tail-gas cleaning systems have a high

rating because they are generally used in

conjunction with the well-established Claus

systems. The fact that the feed to these systems would already have been treated in a

Claus unit removes some of the doubts about

the effects on their removal efficiencies of the

unique characteristics of oil shale emissions

streams. Combustion methods and evaporation controls to reduce HC and CO emissions

also have a high rating because they should

not be sensitive to any great extent to the

scale of operation or stream characteristics.

Fugitive HC and CO emissions are much more

difficult to control.

The other control techniques are given

medium ratings either because they have not

been tested with oil shale streams for sustained periods or because the effects on their

removal efficiencies of the projected characteristics of streams from commercial-scale
276 An Assessment of Oil Shale Technologies

Table 41 .–Technological Readiness of Air Pollution Control Techniques

Pollutant and control system Readiness rating Comments

Dust

Water sprays High Effective and in general use with wetting agents added as needed, Low cost, Increased water needs,

Road paving High Also reduces vehicle maintenance,

Cyclone separators High Low cost, Effective only for large particles.

Scrubbers High Low capital cost and maintenance requirements, High energy and water requirements needed for

high removal efficiency.

Bag house filters Medium High efficiency, Moderate energy and maintenance requirements, Low cost. Not suitable for hightemperature gas streams. Requires more area than other systems, Waste-disposal experience

lacking

Electrostatic precipitators Low to medium Efficiency sensitive to dust Ioading, temperature, and particle resistivity. Good removal efficiency,

Low operating costs and maintenance. Good for large gas volumes. High capital cost.

HtS

Stretford process

Selexol, purisol, rectisol,

istosoliam, fluor solvent, and

other physical systems

Claus process

Tail gas cleaning

SCOT process

Beavon process

IFP process

Medium Extensive application in refining industry, Good for large volumes of dilute gases, Being tested for

MIS gases,

Medium Being tested for coal gasification streams, No experience with oil shale emissions,

High Extensive experience in several industries. Needs concentrated feed streams. High maintenance

needs and downtime,

High Long experience with Claus plants.

High Long experience with Claus plants,

Medium Used with Claus plants that produce elemental sulfur May be applicable directly to retort gases,

so,

Wellman-Lord process Medium Thirty Installations worldwide High capital cost. High energy requirements,

Double alkali process Medium Used successfully in Japan since 1973. Waste disposal could be costly,

Nahcolite ore process Low Limited but successful testing to date,

NOx

Combustion control High Can easily be designed into new plants Low capital and operating cost,

Diesel exhaust control Medium Recirculation of exhaust gases can lead to maintenance problems. —

HC and CO

Combustion control High Use of excess air easily accomplished,

Evaporation control High Use of floating roof tanks is very effective but Increases capital costs,

Control of fugitive emissions Low Control is difficult because of the large number of dispersed sources

SOURCE T C Borer and J W Hand /derr//f/ca/lon and ProDosed Conlro/ of A/r Pllufarrk kern 0// .Sha/e OoeraOons DreDared bv the Rockv Moufltaln Ow!slon The Pace ComDanv COOSUltafltS and

Engineers Inc for OTA, October 1979

plants are still not known. In the case of the

Stretford process, work is underway by Occidental Oil Shale which, if successful, could

significantly improve its readiness.

In general, the control technologies appear

to be fairly well-developed, and should be

adaptable to the first generation of oil shale

plants. Full evaluation will not be possible until the methods have been tested in commercial-scale operations for sustained periods.

Costs of Air Pollution Control

The costs of controlling pollutants from

an oil shale plant would be particularly sensitive to the lifetime of a project, the plant design, the scale of operation, and the extent of

emission removal required by environmental

standards, Small-size, temporary plants such

as modular demonstration facilities would

probably be designed for minimum front-end

costs; therefore, control systems with small

capital requirements would be used rather

than those with low operating costs. The latter systems would be economically attractive

over the 20-year operating life of a commercial plant but not over the 2- to 5-year lifetime

of a modular plant. The design of the plant

would also have an effect on the costs of control. Systems to recover the byproducts sulfur

and NH3 could be included in an integrated

facility, for example, not specifically for air

pollution reduction but to increase plant reve-
Ch 8–Environmental Considerations . 277

nues. Additional control technologies would

be needed to satisfy environmental standards, but overall control costs would be considerably less than if byproducts were not recovered,

Another example of the effect of facility

design on control costs is whether the processes of upgrading and refining are included.

If so, other subprocesses such as retorting

could take advantage of the efficient control

systems that are an integral part of any modern refinery. If refining was not done onsite,

control systems would still have to be provided for the other operations. The same degree of removal efficiency could be achieved

but with higher costs.

The relation of the cost of pollutant control

to the degree of removal is usually not linear,

i.e., the costs generally are considerably

higher to increase a pollutant’s removal from

98 to 99 percent than from 90 to 95 percent.

Consequently, most control costs will be

strongly influenced by the degree of removal

required by environmental standards. Higher

removals will be more costly for individual

plants but would allow the region to accommodate a larger industry within the framework of the air quality regulations.

The Denver Research Institute (DRI) recently estimated the costs of environmental

control in the three projects for which pollutant generation was

through 36,5 DRI’s

terns were based

plans but in some

cover technologies

summarized in tables 34

hypothetical control sysprimarily on developer

cases were modified to

— having higher projected

removal efficiencies. Two regulatory scenarios were considered. Under the “less

strict” scenario for particulate control in the

Colony plant, for example, it was assumed

that particulate reductions from point

sources would average 98.5 percent, and that

for nonpoint sources of fugitive dust reductions of 92.2 percent would be required. The

average particulate reduction for the plant

was assumed to be 98.3 percent, Under the

“more strict” scenario, overall particulate

reductions of 99.5 percent were assumed for

point and nonpoint sources. With some differences, similar control scenarios were assumed for other regulated pollutants, and for

the other two oil shale projects. Results of

DRI’s analysis for the “more strict” case are

shown in table 42.

As can be seen, the control costs for individual contaminants vary widely from project to project. In each project, however, the

largest capital and operating costs are for

S O2 and particulate removal. Capital costs

for SO2 control equipment, for example, are

over $25 million for the tract C-a and C-b projects, which strongly rely on MIS retorting and

which will have to clean large quantities of

Table 42.–Costs of Air Pollution Control (thousand dollars)

Colony projecta

Tract C-b projectb

Tract C-a prolect’

Overall Capital Operating Overall Capital Operating - Overal l Capital Operating

reduction cost cost reduction cost cost reduction cost cost

Fugitive dust 92 2% $ 1,460 $ 564 98 4% $ 1,460 $ 577 Highd

$ 1,460 $ 543

Particulates 99. 5 % 29,40 0 6,49 9 80.2 % 5,79 2 1,530 99.6% 34,340 8,499

s o , 99,0% 9,910 7,240 99.0% 26,210 11,187 99.0% 29,800 12,844

N O , (e) (f) (f) (e) 12,866 3,882 (e) 12,866 3,882

HC and” CO, 50.5% f 7,785 3,766 56.5% 240 50 89.0% 878 182

Total. $58,555 $18,069 $46,588 $17,226 $79,344 $25,950

Cost per bbl of daily capacity $ 1,246 $ 817 $ 979

Cost per bbl of oil produced – $ 1,1 6 — $ 0.9 1 — $ 0.9 7

a47 000 bbl/d of shale 011 syncrude b

57 000 bbl/d of crude shale 011 c81 000 bb[/d Of crude shale 01[

dRoads are paved Water sprays used for disposal areas eMaxlmum reduction achievable through adlustmenl of combustion conditions

fLCIW reducflofl requlremen!s because of low-temperature retorflng and use Of Iow-flltrogen fuel In combustors

SOURCE Oata adapted from Denver Research lnshfule Pred/cfed Cosk of Enwomnerrfa/ CcJmro/s for A Commerc/a/ 01/ Sha/e /rrdus(ry Vo/urne /–Arr Engmeenrrg Arra/ys/s prepared for the Department of

Energy under confract No EP 78-S-02-5107 July 1979 pp 407-414
—— ——-

278 ● An Assessment of 011 Shale Technologies

dilute retort gas. A much lower capital investment (about $10 million) is needed for the Colony project because the TOSCO II retorts produce a much smaller volume of retort gas.

According to DRI’s analysis, the overall

costs of air pollution control range from $0.91

(C-b project) to $1.16 (Colony project) per bbl

of oil produced These costs would have been

considered very high in the early 1970’s when

oil was selling for about $4/bbl. They are less

significant under present conditions with oil

prices exceeding $30/bbl.

Pollutant Emissions

Controlled emissions rates are summarized

in tables 43 through 45 for three oil shale

projects for which pollutant generation rates

were calculated previously. It was assumed

that the raw emissions streams from the unit

operations in each facility would be treated

in control systems similar to those for which

DRI prepared cost estimates. In the Colony

project, for example, it was assumed that

dusty air streams from crushers and ore storage areas would be processed in baghouses,

as would the flue gas from the retort preheater. Flue gases from the retort and the spent

shale moisturizer would be treated in a hot

precipitator. A Stretford unit would be used

for removal of sulfur compounds. NOX and

CO emissions would be reduced by combustion controls on all burners, and HC emissions

would be reduced with floating-roof storage

tanks and a thermal oxidizer flare system.

Table 46 summarizes the rates of pollutant

emissions both for the three projects, and for

modular demonstration projects proposed by

Union Oil Co. and Superior Oil. The Union and

Superior results are presented for their acTable 43.–Pollutants Emitted by the Colony Development Project (pounds per hour)a

Operation Particulate so, NOx HC c o

Mining ., ., ., . . ., ., ... . .

Shale preparation, ., .,

Retorting, . . ., .

Spent shale treatment and disposal” ~ ~ ~ . ~ ~

Upgrading. ., . . ., ., . . ., .

Ammonia and sulfur recovery .. .

Product storag e

Steam and power. ~ ~ ~ ~ ~ ~ ~ ~ . . .

Hydrogen production .,

Total ., ., ...

10 0 2 5 0

b 50b

440b

60 0 0 0 0

120 140 1,430 270 50

40 0 130b10b

o

trace 10 20 10 trace

o 100 0 0 0

0 0 0 20 0

0 trace 20 trace trace

10 30 80 trace 10

240 280 1,930 360 500 +

aR~~m.and.pillar Mlnlng TIJSCO II retorftng scaled to 50000 bbl/d of shale oll syncrude production

bThese emissions are not included 10 Colony PSO permlf aPPllcatlOn

SOURCE T C Borer and J W Hand /defrf/f/ca(/on and Proposed Con/ro/ of AM Pollufarrfs From 0(/ Shale Operations prepared by the Rocky Mountain

Owlsion, The Pace Company Consultants and Eng[neers Inc for OTA October 1979

Table 44.–Pollutants Emitted by the Rio Blanco Project on Tract C-a (pounds per hour)a

Operation Particulate so, NOx HC c o

Mining ., . ., 20 0 340 6 435

Shale preparation. ., . ., . . . 26 0 0 0 0

Retorting. . , 92 52 320 98 0

Spent shale treatment and disposal’ ~ ~ ~ ~ ~ 32 0 0 0 0

Upgrading. ., ., ., ., ., 6 0 6 13 0

Ammonia and sulfur recovery, ... ., . 0 0 0 0 0

Product storage. ., 0 0 0 105 0

Steam and power ., ., . . . ~ 210 250 1,220 13 0

Hydrogen production ., ., – — — — —

Total ., ., ., . . ., ., ... -

386 302 1,886 235 435

auflde@~Ound Mlnlng M [s and Tosco II abovegfound retorting scaled 1050,000 bblld of shale oil Swcrude woduchofl

SOURCE T C Borer and J W Hand. /derrf/l/ca(/orr and %oposed Confro/ O( AM f’o//ufanfs from 0// S/ra/e Opera(/errs, prepared by the Rocky Mountain

Owlslon The Pace Company Consultants and Engineers Inc for OTA October 1979
Ch. 8–Environmental Considerations ● 279

Table 45.–Pollutants Emitted by the Occidental Operation on Tract C-b (pounds per hour)a

Operation Particulate so, NOx HC c o

Mining 20 0 300 10 180

Raw shale disposa l 80 0 100 10 0

Retorting , 10 0 0 0 0

Upgrading 10 10 80 trace 10

Ammonia and sulfur recovery. 0 240 0 0 0

Product storag e 0 0 0 80 0

Steam and powe r 20 trace 2,800bo 0

Hydrogen productio n 80 20 220 20 20

Total 220 270 3,500 120 210

a Underground mlnlng MIS retofilng scaled 1050000 bbl d of shale 011 syncrude production

bAssumes gas turbines for power generation

SOURCE T C Borer and J W Hand (der?hflcallon and Proposed Cofl(ro/ of AU Po//uranrs from 0// Shale Operal/ons prepared by the Rocky Mountain

Dlvlslon The Pace Company Consultants and Engineers lnc for OTA October 1979

Table 46.–A Summary of Emissions Rates From Five Proposed Oil Shale Projects

Pollutant emissions, lb/hr

Project and retortinq technology Shale oil production Particulates SO2 NOx HC co

Colony

TOSCO I I aboveground retort 50,000 bbl/d syncrude 240 280 1,930 360 500

Rio Blanco

MIS plus Lurgi-Ruhrgas aboveground retort 50,000 bbl/d syncrude 386 302 1,886 235 435

Occidental

MIS 50,000 bbl/d syncrude 220 270 3,500 120 210

Superior

Superior retort plus nahcolite and alumina recovery 11,500 bbl/d crude 75 347 172 20 47

Union

Union Oil ‘ ‘B’ aboveground retort 9,000 bbl/d crude 35 81 100 59 43

SOURCE T C Borer and J W Hand /deflflf/cat/on and ProDosed ConVo/ ot AK Pol/u(an(s From 0// Sha/e Operations prepared by the Rocky Mounlain Olvlslon The pace Company Consultants and Enav

neers Inc for OTA October 1979

tual design conditions, which provide about

one-fifth of the shale oil produced by the

other projects. Because emissions rates are

not always directly related to plant capacity,

the much smaller modular projects are not

expected to have equivalently lower rates of

emissions. In fact, S02 release from the

Superior project (11,500 bbl/d) is expected to

be significantly higher than from the three

50,000-bbl/d projects. In part, the high rate of

Superior’s emissions is related to the nature

of its process, which includes unique subprocesses for the recovery of nahcolite and

alumina. They also arise from the scale of

operation, which does not encourage the use

of large-scale, costly controls that would be

cost-effective for the larger operations at Colony and on the lease tracts.

EPA has granted PSD permits for the Colony and Union projects at the levels of operation listed above. Permits have also been

granted for modular-scale operations on C-a

(1,000 bbl/d) and C-b (5,000 bbl/d). EPA therefore expects the projected emissions rates at

these production levels to comply with all applicable Federal and State emissions regulations. However, it should be noted that the

evaluation of the environmental impacts of oil

shale development also requires a consideration of the effects of the emitted pollutants on

ambient air quality, which is protected by

NAAQS and PSD limitations. Without largescale operating facilities, the effects of emissions on air quality can only be predicted by

using mathematical models.

Dispersion Modeling

The Nature of Dispersion Models

The Clean Air Act, through the regulations

promulgated for attainment of NAAQS and
-——

280 ● An Assessment of Oil Shale Technologies

PSD standards, requires the use of mathematical models to relate the emissions from a

source and the resulting incremental impact

that the source causes on a point some distance away. At present, models are EPA’s

tool for enforcing the provisions of the Act

and are the only means for predicting longrange impacts of oil shale emissions on ambient air quality in the oil shale area and in

neighboring regions.

Air quality models are mathematical descriptions of the physical and chemical processes of transport, diffusion, and transformation that affect pollutants emitted into the atmosphere. In these models, specified emissions rates and atmospheric parameters are

used as input data, and the effects on groundlevel pollutant concentration and visibility of

plume rise, dispersion, chemical reaction,

and deposition are simulated. Some models

are designed to simulate small-scale airflow

patterns over complex terrain within a few

miles of the pollution source. These nearsource models can predict the effects of oil

shale emissions in the immediate vicinity of

the plant. They are used during preconstruction review to indicate the facility’s expected

compliance with PSD regulations.

Other models simulate broader airflow

behavior over distances of hundreds of miles.

These regional dispersion models could be

used to simulate the effects on a large area of

an entire industry, including numerous individual plants. Regional-scale models can be

used to predict impacts on air quality in nearby Class I areas. The time scale of the input

data and the output predictions should be appropriate to the size of the region being simulated. Small increments can be used for nearsource modeling; increments of several days

for regional dispersion models.

Most models incorporate a series of computational modules, as shown in figure 60. A

major difference between the models lies in

the manner in which the input data are manipulated and in the application of the computational modules. Usually, not all of the

modules are used in any given model. Nearsource models need to simulate complex air

flow near prominent terrain features, but can

usually ignore chemical reaction, aerosol

coagulation, deposition, and visibility effects,

which generally become most significant over

larger distances and longer time periods. In

contrast, regional models can sometimes ignore terrain features, but must consider longrange atmospheric conditions and their effects on chemical reaction, coagulation, deposition, and visibility.

A key feature that must be considered in

evaluating the use of any model to estimate

compliance with NAAQS and PSD regulations is its ability to simulate worst case conditions, which are those meteorological conditions that lead to the highest ground-level concentrations. These conditions vary depending

on the location of the emitting facility, its configuration, and the nature of the surrounding

terrain. Some candidate worst case conditions for the oil shale region include:

●

●

●

●

●

It

several days of atmospheric stagnation

during which emissions would accumulate under an inversion in a valley;

a looping stack-gas plume that would

bring maximum pollutant concentrations

directly to ground level;

a plume trapped in a stable atmospheric

layer and transported essentially intact

to nearby high terrain;

fumigation, when a plume is transported

from a stable layer at medium heights to

the ground level. (Fumigation conditions

normally persist for less than an hour.

They are usually the worst case for

emissions released from stacks); and

moderate wind conditions in which a

stable polluted layer spreads uniformly

and causes visibility reduction over a

large area. (This is usually the worst

case for emissions released near ground

level.)

is reasonable to assume that some worst

case conditions (e. g., several days of atmospheric stagnation) could occur several times

a year, while others might occur only a few

times over the lifetime of an oil shale project

and might not be detected during a 1- to 3-
Ch 8–Environmental Considerations 281

Figure 60.—Computation Modules in Atmospheric

Dispersion Models

‘m’ss’””ra’es~

Background

Plume rise

w

Source characteristics module

Atmospheric conditions !

*

t

+:%?: I Dispersion

Wmdfleld and other meteorological

data

1 I

I

+,

Reaction kmetlcs

Chemical reaction

Pollutant characteristics

module

I

I

$

I

I

I

Aerosol coagulation

mcdule I

t

Airborne concentration

module

1 i

Visibility module Deposition

lwocass

Y

(wet & dry)

module

GROUND

SOURCE E G Walther, et al The Eva/uaf/onof AI{ Oua//fy CJ/spers/on Mode /

/rrg for 01/ Sfra/e Deve/opmerrt prepared for OTA by the John Mu Ir ln -

stltute for Environmental Studies, Inc October 1979

year environmental monitoring program prior

to the start of constructing a project,

Gaussian models* and grid models are

commonly used to simulate near-source dispersion effects. Gaussian models were developed for the relatively simple air flow patterns over flat terrain. They can be modified,

with a significant loss of accuracy, to simulate complex flow around terrain obstacles,

and up and down valley floors. They can

simulate some worst-case conditions, such as

very low wind speeds, but not looping plumes

or variations in wind direction with in-

*A Gaussian model is based on a theoretical pattern of frequency dlstrihution in which a bell-shaped (or normal) curve

shows the d is! ribu lion of probabi]i ty associated with different

Isues of a va riahle quantit y— in this case pollutant concentrations.

creasing altitude. Their mathematical expressions are relatively simple, and can often

be run on a hand calculator. However, most

Gaussian models rely on straight-line simulation of pollutant trajectories and do not consider spatial, temporal, and vertical variations in atmospheric conditions. As a result

they tend to overestimate ground-level pollutant concentrations at distances greater than

30 miles from the source.

Numerical or non-Gaussian models such as

grid models are more useful for simulating

near-source complexities. They estimate pollutant concentrations at each point in a threedimensional pattern overlying the region of

interest. For detailed computations and high

accuracy, the spacing of the grid points must

be small and the time interval between successive iterations must be short. Because of

these characteristics and due to the complex

mathematical manipulations used, grid models require the use of high-speed computers,

and input data must include highly detailed

wind field information. Such information is

usually not easily obtainable without a very

expensive atmospheric monitoring program.

Grid models can also be used for simulating long-range effects over a large region if

information is available on conditions in the

upper atmosphere. In these applications, terrain details usually become less important.

Complex terrain features, which must be accurately simulated in near-source modeling,

can be simulated through use of an average

roughness factor. However, because of the

longer timespan being modeled, slow chemical reactions that involve, for example, SO2

and NOX, become significant. Aerosol size

distribution (critical in visibility analysis) and

the contributions of other polluting sources

are also important.

A critical problem in applying regional

models is caused by the fact that pollutants

pass through several meteorological regimes

on their path from source to deposition point.

Budget models, which divide the affected region into discrete air cells, can be useful

under these circumstances because they deal

only with the flow of air into and out of one

63-898 0 - 8CI - 19
282 ● An Assessment of Oil Shale Technologies

cell and with the reactions that occur within

the cell. If the cell size or iteration increment

is too large, important details such as rapid

deposition in transition areas between lowlands and mountains may be missed. These

deficiencies can be compensated for by using

time trajectory models, numerical fluid flow

models, box models, or sector average

models.

Problems With Dispersion Modeling in

the Oil Shale Region

Modeling of oil shale facilities presents a

number of problems because of the topography and meteorology of the oil shale region,

the chemistry of oil shale emissions, and the

unknown quantities of emissions expected

from commercial-size facilities. Dispersion

models developed to date have been primarily

for flat terrain. The terrain of the oil shale

region is very complex, including many valleys and canyons. Furthermore, some developers have proposed siting their plants in the

middle of a cliff face or near a canyon rim.

Simulating this geometry presents unique

modeling problems. In addition, the chemistry

of oil shale emissions is quite different from

that of powerplants in urban areas and may

lead to increased oxidant formation through

photochemical reactions between HC and

NOX

. * Thus, the conventional set of reactions

used to model urban photochemistry would

have to be augmented to accurately simulate

the oil shale situation.

Also, oil shale operations emit much fugitive dust. Proper modeling of these emissions

must consider the role of wind in creating the

emissions as well as its role in dispersing

them. In the mountainous areas downwind of

oil shale plants, precipitation may cause the

wet deposition of the oil shale emission, thus

lessening the regional transport of visibility

impacts but increasing impacts on groundlevel ecological systems.

Another problem in developing accurate

dispersion predictions for oil shale facilities

is the fact that the input data on emissions

can only be estimated, since no commercialize plants have yet been built. This problem

is exemplified in table 47, which presents a

summary of emissions data used in several

early modeling studies. These studies varied

widely with respect to the quantities of the

emissions that were assumed for various

types of retorting technologies and the levels

*Photochemical reactions are induced in the atmosphere by

u] traviolet radiation from the Sun.

Table 47.–A Comparison of Atmospheric Emissions Used in Modeling Studies

Total emissions (lb/hr)

Production capacity

Study and site Retort (bbl/day) Study date so* NOx HC Particulates

Battelle

Colorado TOSCO II 50,000 1973 143 732 300 1,285

Federal Energy Administration

Colorado TOSCO II 50,000 1974 1,332 1,464 317 741

Stanford Research Institute

Colorado and Utah TOSCO II 100.000 1975 3,111 4,078 600 650

Colony

Colorado TOSCO II 63,000 1975 282 1,806 324 829

317 1,746 304 842

Tract C-b

Colorado TOSCO II 45,000 1976 267 1,634 262 776

353 1,894 313 968

Tract C-a

Colorado TOSCO II 6,000 1976 26 322 112 148

56,000 265 994 185 573

Tracts U-a and U-b

Utah Paraho 10,000 1976 8.4 108 0.88 68

50,000 148 1,369 55 452

SOURCE Adapled from the Enwronmenlal Prolectlon Agency A f’relvmrrary Assessmertrof fhe Env/ronrnerUa/ hnpacfs from (7// .Sha/e L7eve/oprnenfs July 1977 p 110
Ch. 8–Environmental Considerations 283

of production, Even if the estimates for the

TOSCO II operations are scaled to the same

production capacity, they vary by as much as

an order of magnitude. Much of this discrepancy is associated with assumptions by analysts about environmental-control technologies and their efficiencies, Although individual modeling runs provide some insight into

site-specific air quality effects for a given

retort capacity under specific meteorological

conditions, substantial variations in the input-data assumptions prohibit comparing different retorts, levels of development, and

plant locations,

The Application of Dispersion Models to

Oil Shale Facilities

The application of flat-terrain models to

the oil shale region requires many adaptations in order to provide rough estimates of

the impacts of a particular facility on ambient air quality. Near-source models have

been used to estimate the effects of emissions

from single proposed facilities. Such effects

must be modeled to qualify for a PSD permit

from EPA. A preliminary study has also been

undertaken by EPA to estimate the regional

effects of several oil shale plants. Since only

estimates are available for the levels of emissions from commercial-size facilities, modeling results can only be considered approxima te,

One example of the use of near-source

models was a study performed for Colony Development by Battelle Northwest Laboratories. Colony was considering two plant locations: one in the valley of Parachute Creek,

the other on an adjacent site atop Roan Plateau. A model predicted that NOX concentrations near the valley site would exceed the

national standards; SO2 and particulate

would barely meet the standards. The model

predicted that the corresponding pollution

levels near the plateau site would be an order

of magnitude lower. Because of this prediction, Colony selected the plateau location.67

Another example is the work undertaken

for Federal lease tract C-a. Models were run

for widely different operating conditions, including completely different retorting technologies and levels of operations. As noted in

volume II, the tract C-a lessees originally contemplated open pit mining and aboveground

retorting in a combination of TOSCO II and

directly heated retorts (like the Paraho kiln).

In phase I, a single TOSCO II retort would be

used to produce from 4,500 to 9,000 bbl/d of

shale oil. In phase II, several TOSCO II and

directly heated retorts would be used to produce up to 55,800 bbl/d. The lessees conducted modeling studies that estimated the

air quality impacts of each development

phase. Both long- and short-term effects were

studied with an EPA Gaussian Valley model,

modified to account for the mixing-layer effects of rough terrain and for inversion episodes. Results were reported in the DDP in

March 1976.’

The lessees subsequently adopted a new

plan that was also phased but which involved

underground mining and MIS processing. The

lessees prepared a revised DDP and performed new modeling studies. Two mathematical models were used: long-term (annual)

effects were studied with an EPA model modified for high terrain and atmospheric stability; shorter term (3 to 24 hours) effects were

studied with a modified Gaussian model. As

in the earlier modeling studies, meteorological measurements made on the tract were

used as input data to the models. Worst case

predictions for both phases were reported in

the revised DDP in May 1977.9

The results of both sets of studies are reported in table 48. Predictions are presented

for both offtract ambient air quality and for

the incremental quality degradation. Also

shown are the relevant NAAQS (either primary or secondary, depending on which is

more stringent), the Federal PSD increment

limitations, and the corresponding Colorado

ambient air standards. All standards shown

are those that currently apply to the oil shale

region.

The models predicted that both phases of

both plans should be in compliance with applicable standards, However, the off tract

concentration of nonmethane HC was pre-
. —

284 . An Assessment of Oil Shale Technologies

Table 48.–Modeling Results for Federal Oil Shale Lease Tract C-a

Revised DDP (May 1977) Original DDP(March 1976)

National standards Colorado standards Ofttract ambient air Offtract increment Otftract ambient air Ofttract increment

Averag- PSO increment Ambient PSD Increment Phase lb Phase IIc Phase lb Phase IIc Phase ld Phase IIe Phase Id Phase IIe

Pollutant ing time NAAQSa Class II Air Category II MIS MIS/TOSCO II MIS MIS/TOSCO II TOSCO II Aboveground TOSCO II Aboveground

S o2 Annual 80 20 80 20 8 4 8 3 2 2 7 10 11

24-hour

1

365

2

365 91 102 8 5 3 23 28

3-hour 512

14

1,300 700

19

512 352 25 30 20

NOX

91

Annual 100 None 100

103 82 94

None 8 13 6

Particulates Annual

11

60

16 10 14

19 45

8

19 9 12 0 3 3 16 22

24-hour 150 37 150 37 10

10

12 1 3 34 41 22 29

Nonmethane

H C

f

3-hour 160 None 160 None 65 90 0.3 25 221

Lead Quarterly

129

15 None

156 64

15 None — —

o ,

— —

l-hour

—

240

—

None

— —

160 None — — — — — — — —

bcapacll 4000 bbl/d (MIS) aslrlcter Ot primary and secondary standards

\

ccapaclty 57000 bbl/d (MIS) + 19.000 (TOSCO 11) dcapaclty 9000 bbl/d (TOSCO l{)

ecapaclly 55800 bbl/d (TOSCO II and. e 9 ~ paraho) Not a standard a guide to show achievement of the O, standard

SOURCE Data adapted from onglnal and revised detaded development plan for tract C.a See refs 8-9

dieted to exceed the Federal and State guidelines during Phase I of the old plan. It should

also be noted that in the old plan the off tract

increment for HC is only slightly less than the

3-hour average guideline. In the new plan,

however, offsite concentrations and increments for both phases are well within compliance.

With respect to the effect of scale of operation, the table indicates that, in general, the

impact of the smaller scale phases of both

plans are nearly equal to those of the corresponding larger scale phases. This is explained by the lessees’ intent to use the first

phase of each plan to obtain reliable data on

emissions levels and dispersion characteristics, and then to use these data to design control technologies for the subsequent commercial phases. Also, final commitment to the

commercial operations was not to be made

until technical and economic feasibility studies, based on operating data obtained in the

early phases, could be completed. To avoid

unnecessary capital commitment in the initial

phases, the first facilities were designed for

minimum investment requirements.

It is difficult to interpret the technologyrelated effects of old and new plans for tract

C-a because the levels of operation are different, and different models were used to

simulate air quality impacts. However, a

qualitative comparison is possible. The table

indicates that the original concept (open pit

mining and aboveground retorting) would

have caused higher ambient levels of SO2

,

particulate, and nonmethane HC and lower

levels of NOX than the revised concept (underground mining, MIS, and limited above-

-ground retorting). Although the revised facility is to have 36 percent more shale oil capacity, ambient air impacts and PSD increments

are generally lower.

With respect to regional modeling, EPA has

used a modified Gaussian model to predict

the effects on air quality at the Flat Tops

Wilderness Area of oil shale operations at the

Colony site (50,000 bbl/d), on tract C-a (1,000

bbl/d), on tract C-b (5,000 bbl/d), and at the

Union site (9,000 bbl/d). * The total shale oil

production was about 65,000 bbl/d, of which

about 77 percent was assumed to come from

Colony’s TOSCO II retorts. The model was

limited in that only one source could be modeled at a time, so four runs were needed to

model the industry. In each run it was assumed that the wind was blowing from the

source directly to Flat Tops. The cumulative

impacts of the industry were estimated by

adding the increments from each source. Results indicated that about 20 percent of the

PSD increment for particulate would be consumed, and about one-third of the S02 increment. Simple linear scaling would indicate

that the industry would be limited to about

217,OOO bbl/d by the PSD restrictions on S02

,

and to about 325,000 bbl/d by the particulate

PSD.

*Flat Tops Wilderness Area is approximately 65 miles from

tract C-a, and 50 miles from tract C-b and the proposed Colony

and Union projects.
Ch. 8–Environmental Considerations 285

Such scaling is highly inaccurate for a

number of reasons. First, Gaussian models

tend to overestimate ground-level concentrations of SO2

, because they do not allow for formation of sulfate particles from S02 and their

subsequent deposition. Second, it is impossible for the wind to be blowing from four directions at the same time. Third, the projected SO2 and particulate concentrations at

Flat Tops were affected strongly by the Colony project, which is predicted to emit more

S O2 and particulate than the technologies

proposed by tract C-a, tract C-b, and Union. It

was EPA’s opinion that a better estimate

would be that as much as 400,000 bbl/d could

be accommodated in the Piceance basin by

the PSD standards for Flat Tops.10 EPA’s

analysis did not consider any project in the

Uinta basin, the eastern edge of which is

about 95 miles from Flat Tops. Therefore,

there are no estimates available of the additional capacity that could be installed in Utah

without exceeding the PSD restrictions at

Flat Tops. The proposed Dinosaur National

Monument, about 50 miles north of tracts U-a

and U-b, could also limit operations in Utah if

it is designated as a Class I area. *

Evaluation of Modeling Efforts

Table 49 lists the models used by oil shale

developers to support PSD applications for

their projects. EPA has accepted the results

of these studies as evidence of expected compliance with air quality regulations, and PSD

permits have been granted. Note that, with

*A Department of the Interior task force in September 1979

recommended Iha t the Dinosaur Nntional N!onument be designa led as a Class I n rcn.

the exception of the Colony project, only

small-scale plants were modeled. Some developers, such as Rio Blanco and the tract C-b

lessees, have also modeled the effects of commercial-scale operations at the same locations. However, EPA has not yet evaluated

the results of these studies for adequacy

under the PSD-permitting process.

The widespread reliance on the Gaussian

Valley model should also be noted. All of the

developers relied on this model for simulation

of near-source effects. PSD permits were

granted for the projects because the models

represented the state-of-the-art of nearsource dispersion, and because most of the

projects were of relatively small scale. The

models used are deficient in many respects.

For example, the Gaussian Valley model can

be used for estimating pollutant dispersion in

stable atmospheric conditions in complex terrain, However, as described previously, it

tends to overestimate SO2 concentrations and

cannot handle most worst-case conditions.

Also, Gaussian models when applied to complex terrain introduce error by a factor of 5

to 10 when computing concentrations on highterrain features. This factor of error in the

model’s capability, coupled with a 2 to 5 error

factor in estimating emission concentration,

increases the level of uncertainty in determining compliance with air quality standards. In a recent workshop conducted by the

National Commission on Air Quality, it was

recommended that the Valley model be used

only for screening purposes in complex terrain situations, and that it not be used for determination of compliance with NAAQS or

PSD standards. ’

Table 49.–Models Used in Support of PSD Applications for Oil Shale Projects

—

Maximum shale

Project Retorting technology 011 production Model used

Colony Development Operation TOSCO II 46,000 bbl/d Gaussian Valley model, modified for rough terrain, to study

effects of long-distance transport. Box model for effects of

trapping inversions near source.

Union 011 Co Long Ridge Union ‘‘B’ 9,000 bbl/d Modified Gaussian Valley model.

RIO Blanco 011 Shale (tract C-a) Modular MIS 1,000 bbl/d Modified Gaussian Valley model

C-b Shale 011 Venture (tract C-b) Modular MIS 5,000 bbl/d Modified Gaussian Valley model

Occidental 011 Shale Inc Logan Wash Modular MIS 5,000 bbl/d Modified Gaussian Valley model

SOURCE Ofllce of Technology Assessment
286 ● An Assessment of Oil Shale Technologies

Other models that have been used to predict emissions from proposed oil shale facilities include the CRSTER and the AQPUF2. *

The CRSTER model is generally used by EPA

to simulate effects of emissions from tall

stacks in complex terrain. It tends to overestimate pollutant concentrations where plumes

are intercepted by terrain features higher

than the plume rise height, ” The CRSTER

model used by Rio Blanco in their DDP could

not handle fugitive dust emissions, gravitational settling, separated stacks, chemical

reactions in the plume, some high-terrain

features, and a change of wind direction with

height. All of these variables are important to

accurate prediction of some near-source effects. The AQPUF2 model also used by Rio

Blanco in their DDP for short-term studies

was better able to simulate plume behavior in

complex wind fields and to compare the effects of emitting stacks a significant distance

apart from each other. The effect of wind

speed on the generation of fugitive emissions

was not simulated in any of the models used.

Research and Development Needs

The problems of modeling pollutant dispersion in the oil shale area are also encountered

in other regions with complex terrain, such

as the Ohio River Valley and the Four Corners

area of Colorado, Utah, Arizona, and New

Mexico. The Dispersion Modeling Panel at a

recent workshop conducted by the National

Commission on Air Quality recommended the

following research on the modeling of atmospheric dispersion in such areas:]

]

. Regional models should be developed

that can simulate effects at long distances from the sources, For SO2

, these

distances could approach 600 miles. Upwind pollutant concentrations should be

determined and used as input data to the

models.

● The regional models should allow the use

of a fine-resolution grid spacing near the

pollution sources, and a coarse spacing

at greater distances. Given this capabil-

*CRSrI’ER is a Gaussian model developed by EPA, AQPUF2 is

a segmented-plume Gaussian rough-terrain model,

●

●

ity, near-source effects and more distant

impacts could be modeled simultaneously.

Chemical reaction and deposition modules should be included wherever the

modeled region is large enough for these

effects to be significant.

A simulation of photochemical oxidant

formation and of the conversion of SO2 to

sulfates should be combined in the same

model.

More specific research needs can be identified for the oil shale region. The models used

to date have given only rough estimates of the

impacts of oil shale development on ambient

air quality. Because the models are only approximations, they cannot provide definitive

answers to crucial air quality questions. No

commercial-scale oil shale facilities exist that

could supply the data for verification. Furthermore, essential information is lacking on

meteorological conditions in locations other

than in the immediate vicinities of some of the

proposed development sites.

The models themselves need to be improved for the oil shale region. Near-source

models need to be modified to better simulate

chemical reaction, coagulation, deposition,

and visibility effects of oil shale plumes during stagnation periods. Models are also needed that can simulate the effects that several

facilities would have on air quality in a small

area having complex terrain. This capability

will be critical in evaluating the effects of

second-generation oil shale plants. A good

site for analysis would be the southeastern

corner of the Piceance basin. PSD permits

have already been issued for three projects in

this area, which contains much of the privately owned oil shale land in Colorado. More applications may be submitted in the near future. Models are also needed that can simulate the effects of wind rate on generation

and transportation of fugitive dust from storage and disposal areas.

Many of these improvements also are

needed by regional dispersion models. In particular, existing models should be modified to

simulate long-range visibility effects of oil
Ch 8–Environmental Considerations ● 287

shale plumes. This capability will be required

to respond to the forthcoming visibility regulations. Visibility models exist that deal with

the formation of aerosols and particulate

from SO2 and NOX

, but these models are applicable to examinations of urban smog and

powerplant emissions. Greater emphasis

would have to be given to HC reactions in

order to modify these models to simulate oil

shale plume effects.

The need to model the cumulative impacts

on regional air quality is particularly important. Each scenario should include specifications for the locations of oil shale plants, a

characterization of their pollution control

technologies, and estimates of their emissions

rates. The region’s meteorology would have to

be accurately characterized over periods of

several days, or for at least the time required

for the full impact of the combined emissions

to be experienced in nearby Class I areas.

Computational modules would have to be included for the effects of emissions, dispersion, aerosol dynamics, chemical reaction,

deposition, and visibility, The model also

should handle differences between daytime

and nighttime mixing heights and atmospheric chemistry, In addition, the regional

models would have to be validated, either

through tracer studies in the oil shale region

itself or by examining the ability of the model

to simulate the behavior of emissions from a

group of coal-fired powerplants or smelters.

One type of tracer study that could be used

to validate the models is the release of sulfur

hexafluoride, or a similar tracer compound,

followed by the monitoring of tracer concentrations at numerous ground-level locations.

A dense pattern of monitoring stations would

be needed to locate maximum concentrations,

because the widely varying wind patterns in

the oil shale region prevent any attempt to

characterize total wind fields by interpolating data from a few stations. Baseline measurements of pollutant concentrations and visibility parameters upwind from the source

would be required to accurately simulate the

chemical interactions of the tracer plumes.

The state-of-the-art of near-source and regional dispersion modeling is being advanced

by R&D programs under the sponsorship of

EPA and other organizations. The following

projects are of particular importance to evaluating the air quality impacts of oil shale

plants.

EPA is funding a project with DRI to

combine information on oil shale emissions and meteorology, and to use regional models to assess air impacts from several commercial-size oil shale facilities.

The model will also handle emissions

from other sources such as traffic, powerplants, and other mineral-processing

plants.

EPA is funding a project with the University of Minnesota to develop a simple

model of aerosol dynamics, including

conversion of gases to aerosols, that may

be of use in evaluating the effects of the

chemistry of oil shale plumes on visibility.

Los Alamos Scientific Laboratory is

funding a project with the John Muir Institute for Environmental Studies to develop a multiple-source visibility model

that could be applied to regional dispersion studies in the oil shale area. In a

related study, the University of Wyoming

and Los Alamos are funding a project to

develop a regional haze model which

might be useful in assessing visibility effects of oil shale plumes.

EPA is funding an in-house project at Research Triangle Park to develop a multiple-layer atmospheric model that is designed to explain regional O3 patterns in

the Northeast. It may also be useful for

explaining the high O3 concentrations

encountered in the oil shale area.

EPA is funding a project with Systems

Applications, Inc., to model the air quality effects of oil shale industries with

capacities of 400,000 bbl/d (including

tract C-a, tract C-b, Colony, Union, Superior, tract U-a, and tract U-b) and 1 million bbl/d. The model will handle all
288 ● An Assessment of 011 Shale Technologies

sources simultaneously and will model

visibility effects. The project is designed

as an extension to EPA’s early regional

modeling exercise. Its major objective is

to estimate cumulative impacts on existing and proposed Class I areas such as

Flat Tops.

A Summary of Issues and Policy Options

Issues

INADEQUATE INFORMATION

Extensive work has been undertaken in the

public and private sectors to determine the

degree of pollution control that will have to be

used by oil shale facilities to protect air quality. However, no large-scale facilities exist to

verify the predictions arising from this work.

Furthermore, the dispersion characteristics

of treated emissions streams cannot be accurately predicted because modeling and monitoring methods are not yet adequate. In its

present state of development, modeling can

be used, but the results must be carefully interpreted. Therefore, it is not known what impacts oil shale unit operations will have on

air quality at various shale oil production levels. Specific areas of uncertainty and some

suggested R&D responses are summarized in

table 50. Some of the uncertainties, such as

dispersion behavior, could be reduced somewhat by means of laboratory studies and

computer simulations; others, such as the

performance characteristics of control technologies, may necessitate full-size facilities

and extended programs under actual operating conditions. It is important that emissions

studies and monitoring and modeling programs keep pace with oil shale development.

LIMITS ON OIL SHALE DEVELOPMENT

The atmosphere has a finite carrying capacity; that is, it can only disperse limited

quantities of airborne pollutants. The effect

of the carrying capacity of air in the oil shale

region on the long-term development potential

of oil shale resources is unknown. A crude regional modeling study undertaken by EPA has

indicated that an industry of 200,000 t o

400,000 bbl/d could probably be controlled to

meet PSD regulations in the Piceance basin. It

is unclear whether a larger industry (the

order of 1 million bbl/d) could be established

in the Piceance and Uinta basins without violating air quality regulations.

Additional questions arise regarding the

manner in which PSD increments will be alloPerformance of control

technologies

Dispersion behavior

Trace element behavior

Table 50.–Areas of Inadequate Information and Suggested R&D Responses

Area of uncertainty Relevance Research need

Baseline air quality conditions and Inhibits accurate modeling of emis- Regional characterization studies, including measurement of visibility and

meteorological characteristics sions dispersion and deposition concentrations of criteria and noncriteria pollutants and determination of

meteorology, especially with respect to worst case conditions.

Emissions characteristics Prevents evaluation of control effec- Characterization of stream and fugltive emissions, beginning with pilot-plant

tiveness and cost and reduces studies and continuing with first-generation modules and pioneer commercialmodeling accuracy. size plants. Streams from individual unit operations should be Integrated to

simulate expected commercial conditions.

Inhibits modeling and cost Additional pilot-plant and demonstration-plant programs.

estimation.

Inhibits evaluation of near-source and Improvement in modeling and monitoring techniques for complex terrain,

regional air quality impacts. including development and validation of near-source and regional dispersion

models Models to be validated for the terrain and meteorology of the 011 shale

region and for emissions similar to those expected from 011 shale operations.

Inhibits evaluation of the effects of 011 Monitoring of trace element concentrations in process feed streams, treated

shale development on human health, emissions streams, and fugitive emissions. Examination of the effects of

plants, and animals. conventional control technologies on trace elements. Determination of the

relationships between trace element concentrations in soils and plants and

nutritional problems. Development of indicator species Studies of the synergistic effects of trace elements on vegetation

SOURCE Ofl[ce of Technology Assessment
Ch. 8–Environmental Considerations ● 289

cated to potential oil shale developers. The oil

shale region has been designated Class II, but

several Class I areas exist nearby that could

be affected by oil shale operations. The law

prohibits any facility to exceed the PSD limitation in any area, including the area in

which the facility is to be sited and any adjacent areas, Thus, oil shale developers will

have to demonstrate that their facilities will

satisfy both Class II PSD standards and Class

I standards.

Under the present regulatory structure,

PSD increments are allocated on a first-come,

first-serve basis. The first oil shale plants in a

given area could exhaust the entire increments. If this occurs, subsequent developers,

who might be delayed by the preliminary status of their processing technologies, will not

be able to locate in the same area, regardless

of the efficiency of their air quality control

strategies.

Under the provisions of the Act, new facilities can be located in a polluted area if they

are able to offset their emissions by reducing

the emissions of other industrial plants in the

same area. This strategy may be feasible in

urban industrialized areas, especially where

existing facilities are old and do not employ

state-of-the-art air pollution control methods.

It is not applicable to the oil shale areas at

present because there are few industrial facilities against which to offset new emissions.

It probably will continue to be inapplicable as

the area industrializes, because any new

plants will be built with the best available

control technologies to reduce emissions to

minimum levels. A subsequent oil shale developer would thus be forced to improve on these

control methods. It is uncertain whether this

could be done at reasonable cost.

These constraints could result in each oil

shale plant being surrounded by a buffer

zone in which no additional industrial activities (including oil shale development) would

be allowed. Without reliable regional air

quality modeling studies, it is impossible to

predict the width of these buffer zones, However, it is very possible that such zones could

substantially reduce the area of a given oil

shale basin that could be developed, and thus

limit the ultimate size of the industry that

could operate within the basin,

UNDEFINED REGULATIONS

The Clean Air Act stipulates a need to protect visibility in Federal mandatory Class I

areas. While regulations are to be promulgated by EPA by November 1980, and by the

States by August 1981, uncertainties still exist as to the potential implications for oil

shale development in regard to the siting of

future oil shale facilities. In addition, EPA is

presently developing incremental PSD standards for HC, CO, O3

, NOX, and lead. Oil shale

facilities will have to comply with these new

standards.

Another area of uncertainty concerns

emission standards for hazardous air pollutants under section 112 of the Clean Air Act,

To date, the emissions that are regulated are

asbestos, vinyl chloride, mercury, and beryllium. Controls have been required for industries that produce these substances at high

rates. To date, the oil shale industry has not

been included under the regulations for these

pollutants because it is expected that they

will be generated at low levels, if at all. However, EPA is in the process of developing hazardous emissions standards for POM, arsenic, and possibly other substances. It does not

appear at this time that these substances will

be regulated for oil shale operations, but the

regulations could be applied to oil shale if the

substances are found in the emissions

streams during future characterization studies. Furthermore, it is also possible that additional regulations could be promulgated for

substances that have already been detected

in these streams.

It should also be noted that a recent U.S.

Circuit Court of Appeals decision in the case

of Alabama Power, et al. v. EPA may result in

significant changes in the PSD regulations.

The definition of baseline conditions, fugitive

dust control requirements, and monitoring requirements are among the issues on which

the court has rendered a decision. As a result

of the decision, EPA proposed certain revisions to the PSD regulations on September 5,
290 . An Assessment of Oil Shale Technologies

1979. However, the effect of the court decision and the proposed regulations on the conditions for PSD permits for oil shale facilities

is unclear at this time.

Policy Options

LIMITS ON DEVELOPMENT

Siting constraints will probably not be

severe for an oil shale industry of 200,000 to

400,000 bbl/d. However, it appears likely that

a large industry (the order of 1 million bbl/d)

could encounter siting difficulties because of

the Class H status of the resource region, the

possibility that the initial facilities will exhaust the total PSD increments over large

areas, and the existence of Class I areas near

the region. If this appears to be the case,

there are several possible actions that could

be taken. These are briefly described below.

Retain the current regulatory structure.

This option would not alter existing air

quality standards and PSD regulations

as promulgated under the Clean Air Act.

Under existing law, all oil shale facilities

would have to undergo a preconstruction review before a PSD permit would

be granted. The use of BACT would be

required, and the developer would have

to demonstrate that air quality regulations would not be violated either within

the Class II area of development or in

nearby Class 1 areas. As indicated previously, the current policy of allocating

PSD increments on a first-come, firstserve basis might constrain the commercialization of those technologies that are

in the early phases of development, and

in addition might limit the ultimate size

of an oil shale industry within the resource region.

Coordinate issuance of PSD permits for

oil shale plants. This option would not

alter existing PSD regulations as promulgated under the Clean Air Act. However,

it would change the current approach to

the issuance of PSD permits for oil shale

plants by EPA. Rather than issuing PSD

permits on a first-come, first-serve basis,

EPA would encourage coordination with

all prospective oil shale developers prior

to their preparation of PSD applications.

This effort would seek a coordinated

strategy for maximizing shale oil production while maintaining the ambient air

quality at regulated levels. Implementation could be constrained by, for example, antitrust laws.

Alter existing regulatory procedure in allocation of PSD increments. Under this

option, EPA would allocate a portion of

the total PSD increment to each firm

when it applied for a PSD permit. The remaining portions of each increment

would be reserved for future industrial

growth. Although this option would

allow for a certain level of additional

growth, it could impose technical and

economic burdens on the individual applicants, because each proposed facility

would be required to maintain lower

emission levels than would be the case

under the existing regulatory structure.

Redesignation of the oil shale region

from a Class II to a Class III area. This

option would lower air quality but would

allow for more industrial development.

The action would be initiated at the

State level, with final approval being

necessary from EPA. The following criteria would have to be satisfied:

—the Governors of Colorado, Utah, or

Wyoming must specifically approve

the redesignation after consultation

with legislative representatives, and

with final approval of local government units representing a majority of

the residents of the area to be redesignated;

—the redesignation must not lead to pollution in excess of allowable increments in any other area; and

—other procedural and substantive requirements for redesignation under

State and Federal law must be satisfied.

While such an option would appear to

allow for about twice as much oil shale

development as is presently possible

under a Class II area designation, con-
Ch. 8–Environmental Considerations ● 291

straints would still occur because of the

nearby Class I areas.

Amend the Clean Air Act. This congressional option would exempt the oil Shale

region from compliance with certain

provisions of the Clean Air Act. Congress might direct EPA and the States in

question to redesignate the oil shale region from a Class 11 area to a Class 111

area, and to exempt the oil shale developers from maintaining the visibility and

air quality of nearby Class I areas. This

option would remove the major uncertainties surrounding the siting of oil

shale facilities within the resource region itself, and would remove any siting

barriers connected with the degradation

of nearby Class I areas. Such an option

would allow development up to the Class

III standards, which permit lower air

quality than Class II standards. Thus,

this option would allow an industry of up

to 800,000 bbl/d to be sited in the Piceance basin and an unknown amount in

Utah and Wyoming, but at the cost of increased air pollution.

IMPROVE TECHNICAL INFORMATION

Additional analysis is needed of the potential effects of oil shale development on air

quality. Such analysis will be useful in identifying long-term R&D needs in protecting air

quality and in identifying siting problems imposed by existing air quality regulations and

standards. Some options for improving the

quality of technical information might include: the further development of existing

R&D programs, the coordination of R&D work

by Federal agencies, the redistribution of

funds within agencies for air quality research, increased appropriations to agencies

to accelerate their air quality studies, and the

passage of new legislation specifically tied to

funding R&D relating to air quality impacts at

various levels of oil shale development.

Water Quality

Introduction

Development and operation of oil shale facilities could contaminate surface and ground

water from point sources such as cooling water discharges, nonpoint sources such as runoff and erosion, and accidental discharges

such as spills from trucks, leaks in pipelines,

or the failure of containment structures. The

pollutants could adversely affect aquatic

biota, irrigation, recreation, and drinking

water. The severity of these impacts will be

determined by the scale of operation, the

processing technologies used, and the types

and efficiencies of the pollution controls.

The water systems may be affected during

the operating lifetime of an oil shale facility,

and such long-term impacts as those from the

leaching of disposal piles could continue for

many years after operations ceased. Accurate prediction of the impacts requires an

understanding of the characteristics, transport routes, and fates of the pollutants that

might be released. Much work has been done

to describe the quantity and quality of surface and ground water resources in the oil

shale region. However, little is known about

the nature and ultimate impacts of the pollutants produced by oil shale processing. For example, a number of these pollutants may be

carcinogenic, mutagenic, and teratogenic.*

Information is not available on the risks

posed by these pollutants at the levels likely

to be encountered in the surface and ground

water affected by oil shale development.

In this section:

. The types of wastewaters produced by

oil shale operations are characterized.

● Rates for the generation of these contaminants are estimated.

● Potential impacts of effluent streams on

surface and ground water are identified.

*(krcino~ens cause cancer. Nlutagens cause mut[ltions in

offspring. ‘1’era togens cause fetal defects.
292 ● An Assessment of 011 Shale Technologies

●

●

●

●

●

●

●

The quality of surface and ground water

resources in the oil shale region is examined.

The applicable Federal and State water

quality regulations and standards are

described.

The effects of these regulations and

standards on a developing oil shale industry are analyzed.

The pollution control strategies that may

be applied are described and evaluated.

The net rates at which pollutants will be

emitted in treated streams are then estimated.

Procedures for predicting and monitoring compliance with water quality regulations are discussed.

Issues and R&D needs are summarized.

Policy options are discussed.

Pollution Generation

The following discussion examines the

types of effluents generated by various oil

shale processes. Where data are available,

the rates at which these effluents are produced by different types of facilities are

estimated.

Unit Operations and Effluent Streams

Mining will produce dusty air and gases

that must be cleaned to protect the miners.

Wet scrubbing of this mine ventilation air will

produce wastewater streams that will have

to be treated. If the shale deposits are located

in ground water aquifers, then mine drainage

water will be produced that must be consumed, discharged to a surface stream, or re1%0(0 credit OTA staff

Mine dewatering at tract C-a— water quantity has been greater than anticipated at this site
Ch. 8–Environmental Considerations ● 293

injected into the aquifers. The drainage waters will contain inorganic salts, chloride and

fluoride ions, and boron. They should not contain significant concentrations of dissolved

gases or organic chemicals, although dissolved H2S may be found in some locations.

Retorting produces water by combustion of

hydrogen, by release of moisture present in

the feed shale, and by chemical decomposition of kerogen. In some aboveground retorts

(such as TOSCO 11 and Lurgi-Ruhrgas), this

water is entrained in the retort’s gas stream

and is condensed when the product gas is

cooled. This “gas condensate” will be contaminated with NH3

, CO2, H2S, and volatile organics, but will not contain appreciable quantities of inorganic salts. In other processes

(such as in situ retorting or the Paraho or

Union “B” aboveground retorts) some of the

water may condense within the retort or in

the oil/gas separators. This “retort condensate’ will contain H2S, NH3

, CO2, and dissolved organics, plus inorganic salts that

have been leached from the shale in the retort, Trace elements and toxic metals could

also be present.

Upgrading will include several operations:

gas recovery, hydrogen generation, gas-oil

and naphtha hydrogenation, delayed coking,

NH 3

/acid-gas separation, foul-water stripping, and sulfur recovery. Gas recovery and

hydrogen generation produce little wastewater. However, hydrotreaters and cokers produce foul condensates that are contaminated

with dissolved gases and organics. Gases are

usually removed within the upgrading unit.

Thus, the principal pollutants in the final effluent stream are dissolved organic compounds.

Air pollution control.—Dust scrubbers and

water sprays will produce an effluent that

contains suspended solids and dissolved inorganic salts. Effluent streams from gas

cleaning devices will also contain solids and

salts as well as HC, H2

, NH3, phenols, organic

acids and amines, and thiosulfate, and thiocyanate ions, The principal sources of wastewater will be scrubbers and units for the recovery of sulfur and NH3

.

14 Different devices

produce significantly different quantities of

wastewater with different types and concentrations of contaminants. For example, a

Claus/Wellman Lord sulfur recovery system

would produce a neutralized acidic wastewater; 15 a Stretford sulfur absorption unit would

not.

Steam generation and water cooling.—

High-quality water must be used to generate

steam for power generation or process needs.

Generally, the boiler feedwater must be

treated to remove inorganic salts. The treatment (usually lime softening or ion exchange)

generates liquid wastes. In addition, the

water in a boiler becomes concentrated in

dissolved materials, and a portion must be

continually replaced with freshwater. The

chemical species in the boiler wastewater

(blowdown) will be similar to those in the raw

water, but they will be more concentrated.

Wet cooling towers will be used to cool the

water that is used in heat exchangers. Cooling towers work by evaporating a portion of

the water passing through them. This evaporation concentrates the chemicals that enter

with the feedwater, just as in a boiler. The

water that must be removed to control the accumulation of solids (blowdown) will be chemically similar to the feedwater but will also

contain chemicals that are added to control

the growth of algae in the tower.

Spent shale disposal. -Spent shale from

aboveground retorting will be exposed to

leaching by rainfall, snowmelt, or irrigation

water. If wastes are disposed of by backfilling mines, they may be leached by ground

water. Leachates from various spent shales

have been studied by a number of investigators. 16 17 Their properties vary widely with

the retorting process but in general they contain significant concentrations of total dissolved solids (TDS), sulfate, carbonate, bicarbonate, and other inorganic ions, and lesser

amounts of trace elements and organic compounds. They are alkaline, with pH values

ranging from 8 to 13. Their addition to the

naturally occurring waters in the oil shale region could result in significant water quality

changes, but the severity of the risk is diffi-
294 ● An Assessment of Oil Shale Technologies

cult to ascertain. For example, one leachate

was tested according to EPA procedures, and

the spent shale could not be classified as a

hazardous waste on the basis of its trace elements and toxicity .18 However, some spent

shales could be classified as hazardous because of the presence of organic residues. 19

Leaching of in situ retorts.—In situ retorting presents an environmental problem because ground water is found in many of the

deposits to which this process could be applied. The increases in permeability that

would result from mining, fracturing, and retorting would facilitate leaching after dewatering operations are discontinued. Soluble

materials in the spent shale would thus enter

the ground water and would eventually reach

surface streams. Such transport would take

long periods of time. However, if aquifers are

contaminated, cleanup would be virtually impossible.

Summary of Pollutants Produced by

Major Process Types

Approximate rates of generation of major

pollutants are summarized for four facilities

in table 51. * Five factors should be kept in

mind in reviewing this table:

●

●

●

The rates are for the generation of pollutants—not for their release to the environment. The rate of release will be determined by the strategies that are used

to remove the contaminants.

Retort condensates are not shown for

the AGR processes because it is assumed that the retorts will be operated

at temperatures that will avoid condensation of water vapors within the retort.

This should be achievable with most retorting systems. However, others (like

the Union “B”) may produce substantial

quantities of retort condensate.

No mine drainage water is shown for the

aboveground plants because it is assumed that they will not be sited in

ground water areas. This assumption re-

*See app. C for details,

Table 51 .–Generation Rates for Principal Water Pollutants for

Production of 50,000 bbl/d of Shale Oil Syncrude (tons/d)a

Type of retortinq facility

Aboveground Aboveground MIS/

direct indirect MIS aboveground

Gas condensates

N H3. 75.6 147 276 189

H 2 S 0.9 2 3 1 5 1.1

c o2 136 17.5 541 371

BOD : : 19.2 2 8 5 18,5 127

Subtota l 232 63 837 574

Retort condensates

N H3(b) (b) 3,5 2.4

H 2 S. . . (b) (b) – –

c o2

(b) (b) 48.2 331

BOD ., (b) (b) 10.1 7.3

Subtotal – — 62 43

Upgrading condensates

N H3. 134,2 1342 134,2 134,2

H 2 S 58.8 58.8 58.8 58.8

c o * 1,4 1 4 1 4 1.4

B O D 3.7 3 7 3 7 3,7

Subtota l 198 198 198 198

Blowdown and waste treatmentc

Ca/Mg/N a

d

6 0 6.3 12,2 11 2

Chloride . 5.3 5 7 0 9 0.8

Fluoride ., – — 0 3 0.2

Sulfat e 6.5 6.8 8.4 7 6

Subtotal 18 19 22 20

Mine drainage treatment

CO3 =/ HCO3 -e (f) (f) 23,1 23,1

Boron (f) (f) 0 1 0.1

Ca/ Mg/Nad. (f) (f) 145 14,5

Chlorid e (f) (f) 0.7 0.7

Fluoride . (f) (f) 0 5 0.5

Silica. ., ., (f) (f) 0 5 0.5

Sulfat e (f) (f) 126 12.6

Subtotal — — 52 52

Total , 488 295 1,171 887

a;ons per stream day

bAssumes above-ground retorts operated a! temperatures that do not Produce condensate

cln~]”de~ water pretreatment Above-ground plants use Colorado Rwer wafer MIS and MIS’

above-ground plants use mme drainage waler

dGalclum magnesium and sodium Ions

ecarbonale and bicarbonate IOnS

fAs~umes above-ground relorflng plants are not located w ground water areas

SOURCE

●

Of ftce of Technology Assessment

fleets present developer proposals. It

would not be valid for future plants in

the center of the Piceance basin.

No retort leachates are shown for the

MIS retorts because the rate of leaching

and the efficacy of control systems cannot be accurately estimated. One study

estimated that a commercial MIS facility

might yield over 2,000 ton/d of soluble

salts, but only crude estimates were

made of the rate of release.20
Ch 8–Environmental Considerations ● 295

 No rates are shown for trace elements,

heavy metals, or toxic organic chemicals

because these are produced in much

smaller amounts than the major pollutants. However, they can be both more

hazardous and more difficult to remove.

21-28

The estimates indicate that MIS processing

on tract C-b will produce the greatest quantity of wastewater contaminants for treatment,

mostly because of the large gas condensate

stream. A substantial difference is shown between the aboveground direct and above-

-ground indirect plants with respect to the

rates at which pollutants are generated in the

gas condensate streams: the directly heated

facility produces about four times as much

dissolved gas (largely CO2 and NH3

). This is

because more air is introduced into directly

heated retorts. The trend is consistent with

the even higher gas condensate production of

the MIS retorts, which are also assumed to be

directly heated.

Effects of Potential Pollutants on

Water Quality and Use

Salinity

Oil shale development could increase the

salinity in surface and ground water systems

through two processes:

Concentration of naturally occurring

saltwater as high-quality water is withdrawn for consumptive uses. (This effect

is discussed in ch. 9.)

Salt loading from leaching of waste disposal piles and in situ retorts, from release of saline mine or process waters,

and from ground water disturbances

caused by reinfection.

Salinity increases are a significant problem

because as water becomes more mineralized,

its municipal, domestic, ecological and agricultural utility is reduced. * If dissolved solids

“I’his is of ma jor importance because the Colorado River system is one of the most important river systems in the Southwest. I t serves :~pproxima tel~’ 15 m i]iion people. ~funicipalit ies,

agrirul t u re, energv proriuc t ion. i ncfus t rv and mining, recreaincrease over 500 mg/1, treatment for municipal and industrial water users becomes more

costly, and the yield of irrigated farmlands

might be reduced. 29 For public drinking water

supplies, EPA recommends limits of 500 mg/1

for dissolved solids and 250 mg/1 for both

chlorides and sulfates. 30

Oil and Grease

Because large amounts of shale oil will be

produced, processed, and transported, there

is a possibility of oilspills. If they cannot be

contained or removed, detrimental impacts

would occur to aquatic biota. Small spills,

such as from pipeline leaks, could cause local

damage. If undetected, the long-term impacts

could be substantial. Oil and grease in public

water supplies cause an objectionable taste

and odor, and might ultimately endanger public health.

Suspended Solids

Sedimentation problems will be increased

because large amounts of land will be disturbed, which will increase the area’s susceptibility to erosion. Suspended solids make

surface water cloudy and increase its temperature, thereby affecting aquatic life. Suspended solids in industrial waters can damage some types of equipment.

Temperature Alteration

An industry may alter stream temperatures by discharging warm waste streams, by

consuming cool water, or by lowering the

ground water table. Discharges from powerplants could also increase temperatures, but

the developers do not expect to do this. The

construction of new reservoirs could also

alter stream temperatures. While temperature is not a critical factor in water for industrial use, for drinking, or for irrigation,

tion, wildlife, Federal lands, and Indian reservations all compete for its waters. PresentIV, salinity of the Colorado River at

IIoover Dam is 745 mgl. Unless efficient control technologies

can be employed, estimates have indicated that a large oil

shale industry has the potential, due to salt loading and salt

corwent ration, to increase the salinity level a t Hoover Dam bv

several mg 1.
— —

296 ● An Assessment of Oil Shale Technologies

large variations would affect all aquatic life,

both directly and indirectly (e.g., by influencing their susceptibility to disease and toxic

compounds. )3] Because the Colorado River

system is large, and variations in water temperatures occur naturally, it is not expected

that oil shale development will significantly

affect its temperature. 32

Nutrient Loading

The potential sources of nitrogen and phosphorous are ground water discharge, runoff

from raw and spent shale, municipal wastes,

and chemical fertilizers used for reclaiming

land. These nutrients would adversely affect

nearby surface waters, but the effect on the

total river system is uncertain. The overall

impact will depend on where the facilities are

located and on the degree of waste treatment

used.

Toxic Substances

Sources of toxic trace elements and organic chemicals include stack emissions from

processing operations, chemicals used in upgrading and gas processing, leachates from

raw and retorted shale, and associated industrial and municipal wastes. These substances are of concern because of their potential impact on aquatic life, and on human

health through drinking water supplies and

irrigation. Concentrations of certain minerals

in the region’s water already exceed the limits set for certain water uses. * Oil shale development could increase these levels and

could also add other toxic contaminants. For

example, cadmium, arsenic, and lead, and

other heavy metals could be leached from

spent shale piles. Organic compounds (phenols, benzene, acetone) that are suspected

carcinogens and that have been identified by

EPA as high-priority hazardous water pollutants also are found in oil shale process

waters.

*For example, the boron content in Eva ma lion Creek, near

lease tracts U-a and U-b exceeds the irrigation standard. See

the next section on water quality in the oil shale region for a

more detailed discussion,

Microbial Contamination

The microbial contamination of surface

waters could occur if rapid population

growth overloads sewage treatment facilities. (See ch. 10 for a discussion of the problems of rapid growth.) Improperly treated

sewage containing viruses, bacteria, and

fungi could be released into the water system.

These problems could be controlled by the

construction or expansion of sewage treatment plants.

Water Quality in the Oil Shale Region

The current properties of the water define

how it must be treated before it can be used

in oil shale facilities. More importantly, they

define the level to which wastewater must be

treated before it can be discharged. In general, regulations do not permit the discharge or

reinfection of wastewater unless it is at least

as pure as the receiving stream or aquifer. As

indicated by the data in table 52, the quality

of surface streams is highly variable. It also

tends to deteriorate between upstream and

downstream reaches, as exemplified for Piceance Creek east and west of tract C-b. All of

the streams described in the table satisfy the

standards promulgated by EPA and the U.S.

Public Health Service for the maintenance of

aquatic life and wildlife. Moreover, with the

exception of Evacuation Creek, all are suitable for irrigation water supplies and for livestock watering. Evacuation Creek’s boron

content exceeds the irrigation standard, and

its dissolved solids level exceeds the livestock

watering standard. However, none of the

streams satisfies the standards for public

drinking water. The standard for dissolved

solids is exceeded by all the streams, especially Yellow Creek and Evacuation Creek.

Evacuation Creek also exceeds the standard

for boron, sodium, and sulfate ions. The sodium standard is also exceeded by Yellow

Creek, and the sulfate standard by all three

creeks and the spring.

Ground water is generally of poorer quality

than surface streams. The quality of alluvial

aquifers and of the upper and lower bedrock
Ch. 8–Environmental Considerations ● 297

Table 52.–Quality of Some Surface Streams in the Oil Shale Region (mg/l)

Basin Piceance Uinta Piceance Piceance Piceance Piceance Piceance Uinta

Piceance Creek Piceance Creek Spring at Evacuation

Stream Colorado River White River east of C-b west of C-b Yellow Creek WIIIOW Creek Wallow Creek Creek

Reference 14 15 16 16 17 16 16 15

Ammonia

Bicarbonat e

Boron

Calciu m

Carbonat e

Chlorid e

Dissolved solids

Fluoride

Hardness

Magnesium

p H

Silica

Sodiu m

Sulfat e

N A

b

1 6 8

N A

7 2

NA

205

734

NA

NA

19

NA

7 0

153

158

0 0 6

241

0088

72

0 2

42

551

0 0 3

299

29

8 2

13

78

188

NA

542

NA

70

0 0

16

718

1 0

NA

47

8 2

16

130

170

NA

601

NA

79

0 0

14

944

0.7

NA

69

8 2

17

160

300

0.153

1,470

0.642

3 1 9

118

124

2,430

2.09

541

112

8 7

1 0 5

746

550

0 1

606

0.2

143

0 1

4 0

995

1 7

576

53

7 9

13

138

350

0 1

540

0.6

161

0 1

0 8

910

1 4

516

28

7.9

13

125

310

0 0 6

575

1. 95

214

0 0

66

4,948

0 9

1400

209

7 9

10

972

2.889

aSee reterence IISI

bDala not ava(lable

SOURCE Office of Technology Assessme~t

ground water aquifers in the Piceance basin

near Federal lease tracts C-a and C-b is

shown in table 53. * Water from the alluvial

and upper aquifers could be used for irrigation, but its high dissolved solids content

could harm many crops, Water from the lower aquifer could be used only with very tolerant plants on permeable soil, and that from

some portions of the aquifer could not be used

at all because the lithium and boron concentrations would be toxic to many plants. Except for the lower aquifer, the ground water

resources could be used for livestock, All of

the water would be suitable for maintenance

of aquatic life and wildlife.

None of the aquifers meets drinking water

standards. Special problems are encountered with boron, which in one sample of lower aquifer water exceeded the drinking water

standard by a factor of 320. 34 Also, the average fluoride concentration in lower aquifer

water is about 28 times the drinking water

standard. 35 Dissolved solids concentrations in

the lower aquifer range from a level that

would satisfy drinking water standards (500

mg/1) to over 40,000 mg/1, A concentration of

63,000 mg/1 was reported for one sample. 36

“I’he grounci water resources of the Piceance basin are described in ch. 9. The bedrock aquifers are separated by the oil

shale deposits of the !vlahogany Zone. Alluvial aquifers are

genera]ly found near the surface in valley walls and floors.

Aquifer

Table 53.–Quality of Ground Water Aquifers

in the Piceance Basin (mg/l)

Alluvial Alluvial Upper Lower

Referenced 17 16 16 16

Ammonia 0337

Bicarbonate 573

Boro n 1 25

Calcium ., 102

Carbonate 11.4

Chlorid e 17.9

Dissolved solids 1,190

Fluorid e 0367

Hardness 600

Magnesium 8 3 9

pH 6 5

Silica NA

Sodium. 202

Sulfat e 467

aSee reference IIsl bDala not avadable

SOURCE Off Ice of Technology Assessment

N A

b

1,22 0

NA

57

NA

42

1,750

4 6

NA

80

NA

NA

490

430

NA

550

NA

50

NA

16

960

1 4

NA

60

NA

NA

210

320

NA

9,100

NA

7 4

NA

690

9,400

28

NA

9 5

NA

NA

3,980

80

Water Quality Regulations

Regulations for the maintenance of surface

and ground water quality have been promulgated under the Clean Water Act and the

Safe Drinking Water Act. They are implemented at the Federal and State levels, together with additional State standards. In the

following discussion, the provisions of these

Acts that are of particular significance to oil

shale are emphasized.

63-898 0 - 80 - 20
298 . An Assessment of Oil Shale Technologies

The Clean Water Act

The objective of the Federal Water Pollution Control Act (FWPCA) is “to restore and

maintain the chemical, physical, and biological integrity of the Nation’s waters. ” In 1972,

FWPCA was amended to establish a complex

program to clean up the Nation’s waterways

by limiting the effluents of all classes of polluters. These limits were to be tightened until

the ultimate goal of no pollution discharge

into navigable waters was achieved. The mining industry had difficulties meeting the requirements of this program. Congress responded to these problems, and to the recommendations of the National Commission on

Water Quality, by further amending the Act

in 1977. The amended Act, now called the

“Clean Water Act” refined FWPCA’s regulatory scheme for point sources and emphasized the control of toxic effluents. EPA, the

Army Corps of Engineers, and the States are

responsible for implementing and enforcing

this Act.

The goals of the Act are:

●

●

●

●

the discharge of pollutants into navigable waters shall be eliminated by 1985;

wherever attainable, water quality

which provides for the propagation of

fish, shellfish, and wildlife and for recreation in and on water, shall be

achieved by July 1, 1983;

discharge of toxic pollutants in toxic

amounts shall be prohibited; and

a major R&D effort shall be made to develop- the technology necessary to eliminate the discharge of pollutants into the

navigable waters, the waters of the contiguous zones, and the oceans.

To achieve these goals, emissions standards are to be set to limit discharges from

point and nonpoint sources, and ambient

standards are to be established for the quality of surface waters.

Effluent standards. —Different approaches are used for control of point and

nonpoint sources. Point sources release a collected stream of pollutants through sewers,

pipes, ditches, and other channels. These can

be monitored and regulated with some precision, and they are suited to the application of

control devices. Nonpoint sources are sites

from which there is uncollected runoff. Examples are irrigated fields and waste disposal

areas. They present regulatory and technological difficulties, and as a result, they are

subject to less stringent legal controls.

FWPCA established a complex regulatory

scheme to control pollution from industrial

point sources:

●

●

●

●

●

by July 1977, all nonmunicipal polluters

must use the “best practicable pollution

control technology currently available”

(BPT); public sewage works must use

secondary treatment;

by July 1983, nonmunicipal point sources

must use the “best available technology

economically achievable” (BAT), municipal sewage treatment plants must use

the “best practicable waste treatment

technology;”

special effluent standards for toxic pollutants must be met prior to the 1977

deadline;

new facilities must use the “best available demonstrated control technology;”

and

special restrictions, based on ambient

water quality standards, must be used if

the national effluent standards will not

meet water quality targets in a given

basin.

The 1977 amendments changed this framework: the July 1977 BPT deadline was extended until April 1, 1979, for point-source

polluters who demonstrated a good-faith effort to achieve compliance, and the BAT provisions were completely revised. Industrial

point-source pollutants were divided into

three classes—toxic, conventional, and nonconventional. Each is treated differently.

Toxic pollutants cause death, disease, behavioral abnormalities, cancer, genetic mutations, physiological malfunctions, or physical

deformations in any organisms or their offspring. Sixty-five toxic pollutants must meet

the BAT standards by July 1, 1984; others

must meet BAT standards within 3 years
Ch. 8–Environmental Considerations ● 299

after effluent limitations are established.

Conventional pollutants include biological

oxygen-demanding substances, suspended

solids, fecal coliform, and changes in pH.

They are subject to the application of “best

conventional control technology” by July 1,

1984. In general, this standard is less stringent than the BAT standard. Nonconventional pollutants—those classified as neither toxic nor conventional—will be subject to the

BAT standards no later than July 1, 1987.

Specific limits on these effluents must be

adhered to by individual polluters. In practice, effluent limitations are developed by

EPA for each industry. No discharge of any

pollutant from a point source is allowed unless a National Pollutant Discharge Elimination System (NPDES) permit has been

granted. To obtain a permit, the polluter must

meet the applicable effluent limitations, technology standards, and water quality goals.

Permits are obtained from EPA or from the individual States, if they have taken over the

regulatory role. Cancellation of permits for

noncompliance is one method of enforcing the

Act, because without a permit, many industrial operations cannot be carried out. It should

be noted that permits do not simply recapitulate the effluent guidelines; additional ambient standards may also be imposed.

Special attention is given to new sources

and to sources that discharge into publicly

owned treatment works. In practice, performance standards for new sources are often

equivalent to the 1983 BAT limitations developed for existing industries. Any new source

that complies with an applicable standard of

performance is not to be subjected to more

stringent standards during the first 10 years

of operation.

Expected effluent limitations for oil shale

facilities.—EPA has not yet developed standards of performance for oil shale facilities.

However, standards have been established

for petroleum refining, which has several

similarities. The BPT standards shown for petroleum refining in table 54 were based on

Table 54.–Effluent Limitations for Petroleum Refineries Using

Best Practicable Pollution Control Technology (BPT)

(pounds per 1,000 bbl of feedstock)

Average of daily values

Maximum for for 30 consecutive

Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand

(BO D5

) 192 102

Total suspended solids 132 8 4

Chemical oxygen demand 136 70

011 and grease 6 0 3 2

Phenolic compounds 0 1 4 0068

Ammonia as N 8 3 3 8

Sulfid e 0124 0056

Total chromium O 29 0 1 7

Hexavalent chromium 0025 0011

p H Must be within the range of 6.0 to 90

SOURCE E R Bales and T L Thoem feds j Pololoo Coflrro GUAInI-e lo,0 .Wk Lle~eoo

menl Append/x Envlro!lfnenldl ProtectIon Agency Cinclnnaft Ohio July 1979 0 D 9

the following wastewater management procedures:

●

●

sour water stripping to reduce NH3 and

H2S;

segregation of sewers;

no discharge of polluted cooling water;

and

oil, solids, and carbonaceous wastes removed just prior to discharge.

The BAT standards illustrated in table 55

were defined using additional treatment

Table 55.–Effluent Limitations for Best Available Technology

Achievable (BAT) for Petroleum Refinery Facilities

(pounds per 1,000 bbl of feedstock)

Effluent Iimitations

Average of daily values

Maximum for for 30 consecutive

Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand

(BOD 5 ) . 32 2.6

Total suspended solids. 3.0 2 6

Chemical oxygen deman d 168 134

011 and greas e 0 6 0 0.48

Phenolic compound s 0015 0010

Ammonia as N. 20 1 5

Sulfid e . 0066 0042

Total chromiu m 0 1 5 0.13

Hexavalent chromium, 0.0033 0.0021

p H Must be within the range of 6.0 to 9.0

SOURCE E R Bales and T L Thoem {eds I f%lutonCoofro/ Gwddnce Pm 0// 5?M/e Deve/oprnenf Appendix Enwronmental Protect(on Agency Cincinnati Ohio July 1979 p

c1 11
300 An Assessment o/Oil Shale Technologies

methods now practiced by some petroleum

refineries. These methods include:

●

●

●

●

●

●

●

●

use of air cooling rather than wet cooling

towers;

reuse of sour water stripper wastes;

reuse of cooling water in the water

treatment plant;

using treated wastewater as coolant

water, scrubber water, and in the water

treatment plant;

reuse of boiler blowdown as boiler feedwater;

use of closed cooling water systems,

compressors, and pumps;

use of rain runoff as cooling tower makeup or water treatment plant feed; and

recycling of untreated wastewaters

wherever practical.

NSPS for petroleum refineries, based on a

combination of BPT and BAT standards, are

shown in table 56. New sources must meet

discharge standards that reflect the greatest

degree of effluent reduction which the EPA

Administrator determines to be achievable

through application of the best available demonstrated control technology, process alterations, or other methods including, where

practicable, zero discharge systems.

Federal ambient water quality standards.—The Water Quality Act of 1965 required the States to adopt ambient standards

Table 56.–New Source Performance Standards for Petroleum

Refineries (pounds per 1,000 bbl of feedstock)

Effluent Imitations

Average of daily values

Maximum for for 30 consecutive

Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand

(BO D5

) 1 4 7 7.8

Total suspended solids . 9.9 6.3

Chemical oxygen demand ~ ~ 104 54

011 and greas e 4.5 2.4

Phenolic compounds 0.105 0.051

Ammonia as N 8.3 3.8

Sulfid e 0093 0042

Total chromium . , 0220 0.13

Hexavalent chromium . 0.019 0.0084

pH ., Must be within the range of 60 to 90

SOURCE E R Bales and T L Thoem (eds I Po//uOofl CofMro/ Gwdance for Od Sha/e L7eve/op

menl Append/x Environmental Protection Agency Clnclnnatl Oh[o July 197[1 p

012

for interstate waters. FWPCA required State

standards for intrastate waters as well. EPA

will develop the standards if a State fails to

do SO.

The ambient standards are the basis for

preventing the degradation of presently clean

waterways. The regulations provide, without

qualification, that “No further water quality

degradation which would interfere with or

become injurious to existing instream water

uses is allowable. ” Thus, if a stream is suitable for the propagation of wildlife; for swimming; or for drinking water, then it must remain suitable for these uses. Because small

increases in pollutant loads may not be inconsistent with protecting a possible present use,

the States are allowed to decide whether “to

allow lower water quality as a result of

necessary and justifiable economic or social

development. ” Such decisions cannot be applied to waters that constitute an outstanding

national resource (e.g., national parks, wilderness areas), and they cannot allow water

quality to fall below the levels needed to protect fish, wildlife, and recreation.

Before a State can issue a discharge permit it must have a program for reviewing and

revising its water quality standards. EPA established the following guidelines for State

review and revision:

● standards must be reviewed every 3

years and revised where appropriate;

● standards must protect the public health

and welfare, and not interfere with

downstream water quality standards;

 existing standards must be upgraded

where current water quality could support higher uses than those presently

designated;

● existing standards must be upgraded to

achieve FWPCA’s 1983 goal of fishable

and swimmable waters, where attainable. Attainability is to be determined by

environmental, technological, social, economic, and institutional factors; and

● existing water quality can degrade in

only specific instances, for example, if

existing standards are not attainable
Ch. 8–Environmental Considerations . 301

because of natural conditions such as

leaching.

Once an ambient standard is established, a

State must identify stream reaches for which

the 1977 effluent limitations are not sufficiently stringent. For such areas, the State

must determine the total maximum pollutant

loads that will allow the ambient standard to

be met, This information is used to set more

stringent effluent standards.

Current State standards for Colorado and

Utah.—In Colorado, streams may be assigned

to one of four categories. Drainage from lease

tracts C-a and C-b would discharge to the portion of the White River from the mouth of the

Piceance Creek to the Colorado/Utah State

line. This area is in Colorado’s water category B2. These waters are suitable, or are to

become suitable, for customary raw water

purposes (e.g., irrigation, livestock watering)

except for primary contact recreation, * The

water quality criteria for category B2 are

listed in table 57. Colorado also has an antidegradation policy applicable to all streams.

Utah has 11 stream classifications, Two

streams in and around oil shale tracts U-a

and U-b, Evacuation Creek, and the White

River, are classified as CW (i.e., warm water

fisheries). Their waters are suitable for all

*Prim:~rV ronttirl rerrc:)tifjn includes sw imrnin~, water skiing. and diving.

Table 57.–Colorado Water Quality

Standards for Stream Classification B2

Parameter Criteria for B2 streams

Settleable solids floating solids Free from

taste, odor, color and toxic

materials

Oil and grease Cannot cause a film or other

discoloration

Radioactive material Drinking water standards

Fecal conform bacteria Geometric mean less than 1,000

units per 100 milliliters

Turbidity Cannot increase more than 10

units

pH 60 to 90

Temperature Maximum 900 F

Change Streams 50 F

Lakes 30 F

SOURCE E R Bates and T L Thoem (eds I Po/JufIorI ConfroI Go(dance for 01/ Sbd/e De,e)op

rnenl Append/x Environmental Prolecl(on Agenc j Clnc(nnatl Ohio JuIy 1979 p

D 20

raw water uses (except contact recreation)

without treatment, but with coagulation, sedimentation, filtration, and disinfection prior to

use as domestic water supply. Temperature

limitations are also imposed. The water quality criteria for class CW are shown in table

58. In addition, Utah, like Colorado, has an

antidegradation policy.

Table 58.–Utah Water Quality Standards

for Stream Classification CW

Parameters Criteria for CW streams

Radioactive and chemical Drinklng water standards

Settleable solids. 011, floating solids, Free from

taste, odor, color, and toxic

materials, turbidity, etc

Total coliform bacteria Less than 5,000 units per 100

milliliters

Fecal conform bacteria Less than 2,000 units per 100

milliliters

pH 65 to 85, no Increase >0.5

Biochemical oxygen demand (BOD5

) Less than 5 milligrams per Iiter

Dissolved oxygen >6.0milligrams per liter

Temperature Maximum 680 F

SOURCE E R Bates and T L Thoem (eds I Polluf(on ComroI Gufdafice to{ Oh Shd,e Oeve/oj

ment Appendtx Enwronmental Pro fecllon Aqenc~ Clncnnaf Ohio JIJY 1979 p

021

Proposed State standards.—FWPCA required the States to designate areawide pollution control planning agencies. The Colorado West Area Council of Governments and

the Uinta Basin Council of Governments have

been designated for the oil shale region.

These agencies are to plan, promulgate, and

implement a program designed to protect surface water quality. Stream classifications

and water quality standards are to be developed. The multiple-use classifications proposed for streams, which may supersede existing classifications previously discussed, include:

●

●

●

●

The

Class I—aquatic life, water supply,

recreation, and agriculture:

Class II—water supply, recreation, and

agriculture;

Class III—recreation and agriculture;

and

Class IV—agriculture.

respective water quality criteria are

shown in table 59. The classifications and the

quality criteria will apply to all streams in the

oil shale region.
302 ● An Assessment of 011 Shale Technologies

Table 59.–Proposed Water Quality Criteria for Designated Uses

Parameter Water supply Aquatic life/ wildlife Recreation Irrigation Livestock

Alkalinity as CaCO 3 ., ., . –

Aluminum-total . . . . . . . . . –

Aluminum-dissolved ... ., –

Total ammonia as N, ., ., ., ., 0.5 mg/la

Unionized ammonia as N . –

Arsenic-total ., ., 0.01 mg/l

Barium-total, . 1,0 mg/l

Beryllium-total ., ... –

Boron ., ., . . ~ ~ ~ ., 1.0 mg/la

Cadmium-total ... ., ., ., ,0,01 mg/l

Chloride-total . 250 mg/l

Chromium-total . . . 005 mg/l

Fecal coliform ., ., 2,000/100 ml f

Color, ., ... ., ., .75 color unitsa

Copper-total. . ., ., .1.0 mg/l

Cyanide. . . . . ., . ., .020 mg/l

Hardness ., ., ., ., ., –

Iron-total. ., ., . –

Iron-dissolved ., ... ..03 mg/l

Lead-total . , 0.05 mg/l

Manganese-total . . ... .0,05 mg/l

Manganese-dissolved ., 0,05 mg/ l

Mercury-total. ., . .....0,002 mg/ l

Molybdenum-total —

Nickel-total ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ –

Nitrate-tl , 10 mg/l

Dissolved oxygen .. ~ ~ ~ ~ ~ ~ ~ ~ 40 mg/lf

pH . . . . . .. 5.0-9.0

Phenols ~ ~ 0.001 mg/l

Total PO4

-P ., ~ ~ ~ ~ ., –

Phthalate esters –

PCB ., ., –

Selenium-total ., . 0.01 mg/l

Silver-total. ., ., . . 0.05 mg/l

Silver-dissolved –

Sodium ., ., ~ ~ .270 mg/la h

Sulfate-total. ., . ., ., ., 250 mg/l

TDS ., ., 500 mg/la

TSS ... ., ., ., –

H 2S (undissociated) ., ., ., 0.05 mg/l

Temperature . ... ... ., –

Zinc-total. ... . 5.0 mg/l

30-130 mg/ l

a

0.1 mg/l

0.1 mg/la

—

0,02 mg/l

0.05 mg/l

—

1,1 mg/l

—

0.003 mg/l

—

0.3 mg/lf

2,000/100 mla

—

0.030 mg/l

0.005 mg/l

—

1.0 mg/l

0.3 mg/la

0.03 mg/l

1,0 mg/l

—

0,00005 mg/l

—

0.1 mg/l

—

5.0-6.0 mg/l min.

6.5-9.0

0.001 mg/l

0.025 mg/l - Iakesa

0.003 mg/l

0.000001 mg/l

0.05 mg/l

0,0001-0,0025 mg/lg

0.0001 mg/l

—

—

—

25 mg/l-medianj

0.002 mg/l

(k)

0.03 mg/l

—

.

—

—

—

—

—

—

—

—

—

—

200/100 ml —

—

—

—

—

—

—

—

—

—

—

—

—

2,0 mg/l min.

6.5-9.0 —

—

—

—

—

—

—

—

—

—

—

—

—

—

5.0 mg/lb, 20.0 mg/la C

—

—

0.1 mg/l

0.1 mg/l b

, 0.5 mg/lC d

0,75 mg/le

O.O1b, 0.05 mg/lC 

0.1 mg/lb, 1.0 mg/lC d

1 ,000/100 ml

0.2 mg/l b

, 5.0 mg/lC

0.2 mg/l

—

5 mg/lb, 20 mg/la C

—

5 mg/lb, 10 mg/lC f

0.2 mg/l b

, 10 mg/lC d

0.01 mg/lb, 0.05 mg/l C

0.1 mg/lf

100 mg/l

2.0 mg/l

4.5-9.0 a

—

—

—

—

(1)

2,0 mg/l

Unless otherwise mdtcaled the recommended cr!tena correspond with proposed State standards

aCWA 208 recommendation only (no proposed State standard)

bCon11nuou5 Irrlgatlon, atl sods (match WOCC proPosed State standards)

cshofl.~erm {rrlgatlon, neutral to alkaline fme Iexlured soils

dFor agrlcultura[ uses the WOCC except In a few Instances dld not dlshngulsh between lrrl9ation and hvestock uses The CWA 208 attempted 10 distinguish the differences Therefore, under

hvestock there are numerous differences between 208 and WOCC numbers Under Irrlgatlon The

lower recommended crlterla match Wf3CC numbers

eLong.term Irrlgatlon on sensltwe crops

fDlffers from proposed State standards

gLlmitlng concentration dependent on hardness

—

5.0 mg/la —

—

—

0.2 mg/ld —

—

5.0 mg/ld

0.05 mg/ld —

0.1 mgll

1 ,000/100 ml —

0.5 mg/ld

0.2 mg/1 —

—

—

0.1 mg/1 —

—

0.00005 mg/la

0.5 mg/1 —

NO, + NO, 100 mg/1

2.0 mg/1 —

—

—

—

—

O 5 mg/1

—

—

3,000 mg/la —

—

25 mg/ld

hMaxlmum concentration for a moderately restricted sodwm diet

Iwaler from which no detrimental effects WIII usually be nohced 500 mg/1

Water which can have detrimental effects on sensdwe crops 500-1000 mg/1

Waler that may have adverse effects on many crops and requires careful management

prachces f ,000-2000 mg/1

Water fhat can be used for folerant plants on permeable SOIIS wlfh careful management

prachces 2,000-5000 mg/1

IValue represents maxtmum Increase In amblenf concentraflon due 10 discharge

kC,old water maximum IS 200 C, warm water maximum IS 30° C, and both Categories hmlt temperature changes to 3° C

SOURCE E R Bates and T L Thoem (eds I Po//uf/orI Cmrfro/ Gu/darrce for 01/ Sfra/e Oeve/oprrrerrl Append/x, Enwronmental Protection Agency, Clncmnal{, Ohio. July 1979 pp D-29-D-30

The Safe Drinking Water Act of 1974 gram for ground water protection. It is administered by EPA and by the States.

This Act protects drinking water systems

through primary and secondary ambient The primary standards are intended to

standards, monitoring programs, and a pro- protect health to the extent feasible, given the
Ch 8–Environmental Considerations ● 303

restraints of existing treatment techniques

and their costs. Interim standards were issued by EPA during 1975 and 1976 and were

put into effect in June 1977 (see table 60).

These standards established both maximum

contaminant levels and monitoring requirements for 10 inorganic and 6 organic chemicals, radionuclides, microbiological contaminants, and turbidity. A study by the National

Academy of Sciences of the health effects of

drinking water contaminants is to be the basis

for revised primary standards. The study was

completed in June 1977, but the revised

standards have not yet been issued.

Secondary standards, published in 1977,

deal with contaminants that affect the odor

and appearance of water but do not directly

affect health (see table 61). They are not federally enforceable and are only guidelines to

the States. The States may include monitoring

requirements in their laws and regulations.

Table 60,–Primary Drinking Water Standards (mg/l)

Maximum concentration

Inorganic chemicals (except fluoride)

Arseni c

Bariu m

Cadmiu m

Chromiu m

Lea d

Mercur y

Nitrate (as N) ,

Selenlu m

Silver. . ,

Fluoride

(degrees Fahrenheit)

537 and belo w

53.8to 583 .,

584 to 63. 8

63.9 to 70,6

70.7 to 792

79 3 to 90. 5

Chlorinated hydrocarbon s

Endrl n

Lindan e

Methoxychlo r

Toxaphen e

Chlorophenoxys

2, 4-D (2, 4-dichlorophenoxyacetic acid).

2, 4, 5-TP (Silvex)

0 0 5

1 0

001

0 0 5

0 0 5

0002

100

001

0 0 5

2 4

2 2

2 0

1.8

1 6

1 4

0.0002

0.004

0.1

0.005

0.1

0.01

SOURCE E R Bates and T L Thoem (eds ) Po//u1/on Comrol Gwdaoce for 011 Shale Develop

menf Append/x Enwronmental Protecllon Agency Clnclnnall Ohio July 1979 pp D32-D-33

Table 61 .–Proposed Secondary Drinking Water Regulations

Pollutant Proposed level Principal effects

Chlorid e 250 mg/l Taste

Color 15 color units Appearance

Copper 1 mg/l Taste, fixture staining

Corrosivity (Noncorrosive) Deterioration of pipes, unwanted

metals in drinking water

Foaming agents O 5 mg/l Foaming, adverse appearance

Hydrogen sulfide O 05 mg/l Taste, brown stains on laundry

and fixtures

Manganese .005 mg/ l Taste, brown stains, black

precipitates

Odo r 3 threshold Odor

odor number

pH ., .. 65-8.5 mg/l Corrosion below 65. incrustations, bitter taste, lowered

germicidal activity of chlorine

over 8.5

Sulfate 250 mg/l Taste, Iaxative effects

Total dissolved

solid s 500 mg/l Taste, reduction in Iife of hot water

heaters, precipitation in cooking

utensils

Zin c 5 mg/l Taste

SOURCE E R Bales and T L Thoem teds I Po//ufIorI Conlrol Gwdance for 0/1 S/We Uevekm

rr?er?f Append/x Enwronmen[al ProtectIon Agency Clnclnnafl Ohio July 1979 0

D 33

Ground Water Quality Standards

Federal.—The Safe Drinking Water Act

applies to deep-well injection of waste into

aquifers with less than 10,000 mg/l TDS that

are, or could become, sources of public drinking water. Seepage from pits, ponds, and lagoons is not regulated at this time.

Colorado. -No specific standards have

been promulgated for ground water quality.

However, the basic standards applicable to

all other State waters do apply. Regulations

are being developed that will limit the discharge or injection of some contaminants.

Permits are now required for injection wells,

and they will be required in the future for

wastewater disposal in pits, ponds, and lagoons if there is a possibility of discharge to a

ground water system.

Utah.—Utah also has no special standards

for ground water. However, ground water is

considered part of the State waters, so general water quality standards do apply. Discharges to sources of potable water must not

cause the water quality to exceed drinking

water standards.
304 ● An Assessment of 0il Shale Technologies

Implications of Water Pollution Control Standards

and Regulations for Oil Shale Development

As indicated above, the primary objective

of the Clean Water Act is to eliminate the

discharge of pollutants into navigable waters

by the late 1980’s. In order to accomplish this

objective all potential polluters, including oil

shale developers, will be required to apply

BAT, BPT, and NSPS. Point source discharge

is well-regulated under the Act, and it is expected that oil shale developers would comply

with the stipulations promulgated in regard

to NPDES. As will be discussed in the following section, the pollution control technologies

that are being applied to oil shale wastewater

effluents are designed for zero discharge.

However, in some instances (e.g., excess water from mine dewatering) it will need to be

discharged back into surface waters or reinfected into underground aquifers. In this

case, water will have to be treated to meet

the standards stipulated under the NPDES

permit system or by the Safe Drinking Water

Act for reinfection—that is surface and

ground water quality criteria and water use

classifications will have to be maintained as

stipulated by the States and EPA. In addition,

it is expected that oil shale facilities will have

to meet NSPS comparable to those developed

for petroleum refining facilities.

Technologies for Control of Oil Shale

Water Pollution

Treatment of Point Sources*

Contaminants may be removed from wastewater by physical, chemical, or biological

means. For complex wastes, a series of devices using each of these principles will be

necessary.

Physical treatment devices apply gravity,

electrical charge, and other physical forces

to contaminants to remove them from wastewater. Typical operations are gravity separation, air flotation, clarification, filtration,

stripping, adsorption, distillation, reverse os-

*De!ails of the various technologies are described in app. D.

mosis, electrodialysis, thickening, and evaporation.

Chemical treatment devices use chemical

properties or chemical reactions to remove

contaminants. Such systems can destroy hazardous substances that are not amenable to

conventional physical and biological systems.

For oil shale wastewaters, the most important devices are those that could oxidize organic compounds or reduce salt concentrations. Included are ion exchange, wet air oxidation, photolytic oxidation, electrolytic oxidation, and direct chemical oxidation.

Biological treatment devices contact a

waste with a population of micro-organisms

that digest its organic contaminants. By controlling the size of the population, and by adjusting oxygen and nutrient levels and equalizing the conditions of the entering stream, it

is possible to develop and acclimate micro-organisms that can nearly eliminate many hazardous organic compounds. Biological treatment systems can be divided into two groups:

● aerobic processes (such as activated

sludge, trickling filters, rotating biological contractors, aerated lagoons, comporting, and stabilization ponds) in

which the population is maintained under oxygen-rich conditions and the organic compounds are decomposed to CO2

and water; and

● anaerobic processes (such as digestion)

in which oxygen levels are relatively low

and the organic compounds are degraded to CO and methane gas.

Treatment systems.—Most devices can remove some but not all contaminants. In a

treatment system, different wastewaters are

sent to different devices, each of which removes a specific type of pollutant, The relationships among contaminants, the streams in

which they are likely to occur, and the treatment processes of choice are shown in table

62. Although all contaminants may be found

in nearly all streams, the streams associated

with each contaminant have been limited to

those in which concentrations will be high
Ch. 8–Environmental Considerations 305

Table 62.–The Types of Contaminants in Oil Shale Wastewater

Streams and Some Potential Processes for Removing Them

Contaminant Stream . . , Potential process

Suspended solids Mine drainage

Retort condensate

Cooling tower blowdown

Oil and grease Retort condensate

Gas condensate

Coking condensate

Dissolved gases Retort condensate

Gas condensate

Coking condensate

Dissolved inorganics Mine drainage

Dissolved organics

Trace elements and

metals

Trace organics

TOXiCS

Sanitary wastes

Retort condensate

Gas condensate

Cooling tower blowdown

Ion exchange regenerants

Retort condensate

Gas condensate

Coking condensate

Hydrotreating condensate

Retort condensate

Gas condensate

Retort condensate

Gas condensate

Upgrading condensate

Retort condensate

Gas condensate

Upgrading condensate

Domestic service

Clarification

Filtration

Gravity separation

Emulsion breaking

Steam stripping

Chemical oxidation

Ion exchange

Reverse osmosis

Adsorption

Evaporation

Solvent extraction

Adsorption

Biological oxidation

Ultrafiltration

Reverse osmosis

Wet air oxidation

Chemical oxidation

Ion exchange

Adsorption

Ultrafiltration

Reverse osmosis

Adsorption

Chemical oxidation

Incineration

Biological treatment

SOURCE R F Probsleln H Gold and R E Hicks Wafer Reauwernertfs Po/kJ//on Effects and

Costs of Wafer Supp/y and Trealrnen( for the 0// Sha/e /ndusfry prepared for OTA by

Water Purlflcatlon Associates October 1979

enough to require removal prior to discharge

or reuse.

37 38

Many of the devices listed in table 62 have

been tested individually on oil shale wastewaters and have been found to provide some degree of control. 39-50 Of great importance is the

performance of these units when combined to

form a “treatment train” for a specific

wastewater. A separate train—consisting of

several individual treatment devices in

series—will be needed for each stream because, in general, each will contain different

types of contaminants, Each contaminant will

require a different type of removal process.

For example, retort condensates may contain

suspended solids, oil and grease, dissolved

gases, organics, inorganic, and trace elements. Mine drainage water may contain only

dissolved solids.

The removal efficiencies, reliabilities,

adaptabilities, and relative costs of some

point source control devices are summarized

in table 63. This information comes almost entirely from experience in other industries.

Few of the technologies have been tested with

oil shale wastewaters, and none has been

tested in the complex treatment trains that

will be necessary to deal with the wastes that

will be encountered in commercial-scale oil

shale plants. The degree of adaptability of

each technology is particularly important

because it indicates the likelihood that the

technique will transfer without difficulty to

the oil shale situation.

Most suitable technologies.—The following technologies appear most suitable:

●

●

●

●

●

●

for oil and grease: dissolved air flotation

or coalescing filters;

for dissolved gases: air or steam stripping;

for dissolved organics: rotating biological contractors or trickling filters for

first-stage removal, carbon adsorption,

or wet air oxidation for polishing;

for suspended solids: pressure or multimedia filtration;

for dissolved solids: reverse osmosis for

first-stage removal, clarification for second-stage, and ion exchange for polishing; and

for sludges: filtration and evaporation.

Costs.—Control costs depend on the operating characteristics of the oil shale facility

and on the treatment methods selected. The

only published cost estimates were prepared

for the Department of Energy (DOE). These

estimates, upgraded for OTA to include the

cost of treating excess mine drainage water,

appear in table 64. Total treatment costs

range from about $0,25 to $1 .25/bbl of shale

oil syncrude. The low estimate applies to

aboveground retorting plants; the high to MIS

facilities in ground water areas. Although

sizable, the control costs should not themselves preclude profitable operations.
306 ● An Assessment of Oil Shale Technologies

Table 63.–Relative Rankings of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost

011 and grease Dissolved air flotation

Coalescing filter

Clarification

90

99

80

Very high

High

Very high

Very high

High

Very high

Medium

Medium

High

Dissolved gases Air stripping

Steam stripping

Flue gas stripping

Biological oxidation

80

95

95

High

High

Very high

High

Medium

High

High

Medium

Medium

Medium

Medium

Medium

Low

Dissolved organics Activated sludge

Trickling filter

Aerated lagoon

Rotating contactor

Anaerobic digestion

Wet air oxidation

Photolytic oxidation

Carbon adsorption

Chemical oxidation

Electrolytic oxidation

95 BOD/40 COD

85 BOD

80 BOD

90 BOD/20-50 COD

60-95 BOD

64 BOD/74 COD

99 BOD

99 BOD

90 BOD/90 COD

95 BOD/61 COD

High

High

Medium

High

High

Medium

Medium

Medium

Very high

Medium

Medium

Medium

Medium

Medium

Medium

High

Very high

High

Very high

Very high

Low

Low

Low

Low

Medium

Very high

Very high

Medium

High

High

Suspended solids Clarification

Pressure filtration

Multimedia filtration

50

95

95

High

High

Very high

High

High

High

Medium

Medium

Low

Dissolved solids Clarification

Distillation

Reverse osmosis

Ion exchange

Electrodialysis

Low except for metals

99

60-9 5

High

10-4 0

High

Medium

Medium

High

Medium

Medium

Low

Medium

Low

Medium

Medium

Very high

Medium

High

Very high

Sludges Thickening

Anaerobic digestion

Vacuum filtration

Sludge drying beds

Evaporation basins

Filter press

Aerobic digestion

Product 6-8% solids

Low

Product 20-35% solids

Product 90% solids

Product 95% solids

Product 35% solids

Low

Very high

High

High

Medium

Very high

Very high

Low

High

Medium

High

Low

Low

High

Low

Medium

Medium

High

Medium

Low

High

High

SOURCE Adapted from 4ssessrnerU of 0// Sfra/e Rerorf Wasfewa(er Trealrneru and ConVo~ Tec/rno/ogy, Hamllfon Standard Owlslon of Uruled Technologies July 1978 pp 2-12 to 2-24

Table 64.–Estimated Costs of Water Pollution Control in

Oil Shale Plants ($/bbl of shale oil syncrude)a

torts. For an aboveground retorting facility,

the leaching problem may be reduced by disposal of the solid wastes in canyons, and capturing and treating any leachate that does occur. (See figure 61. ) It is hoped that the

moistened and compacted spent shale will be

impermeable to the flow of water. The top of

the pile will be covered with topsoil o r

another growth medium that will be permeable but that will not contain substantial

quantities of soluble contaminants. A n y

leachates that reach the catchment basin

would be treated. This method may be effective during the lifetime of the facility.

Above- Above-

-ground ground MIS/

Wastewater stream direct indirect MIS aboveground

Gas condensate $0.11 $0.13 $0.45 $0.31

Retort condensate – — 0.13 0.09

Upgrading

condensat e 0,12 0.12 0 1 2 0.12

Excess mine

drainage ., . – — 0-0.55 0-0.55

Total . . ., $0.23 $0.25 $0.70-1.25 $0.52-1.07

aplants produce 50,1NI btjltd Of syncrude Aboveground plants are assumed to be not located In

ground water areas Cost estimates include operating expenditures and capital amorhzatlon

They also include nonwastewater costs such as botler feedwater treatment costs

SOURCE R F Probste!n, H Gold and R E Hicks, Wafer Requwernerrk, Po//u(/on Effecls and

Cosk O( Waler Supp/y and rreatrnerrl for the 00 Sha/e /ndus/ry, prepared for OTA by

Waler Purlflcatlon Associates, October 1979

Tests of these control strategies have not

simulated conditions of commercial-scale disposal piles, and past research investigations

are limited in their applicability. Questions

persist concerning shale pile permeability,

Control of Nonpoint Sources

The major potential nonpoint sources are

leachates from aboveground storage of raw

or spent shale and from abandoned in situ re-
Ch 8–Environmental Considerations ● 307

Figure 61 .—An Aboveground Spent Shale

Disposal Area

~~

‘ + \

\’ --

1

Processed Shale =

-— Disposal Pile \ ’

Leachate Ditch - -

$

;

q%

+

// . , ,\

\ \

Drainage D!tch ,

\ \

/ ’

‘ /

‘ /

‘ / //;

/

.— - / ‘ /,$? //’.

/

;:::~&4/////7T~

y{//)’)’y”

?-#

Leachate Ditch

/

/ / /’

/ //

///

)/ ,/ / Q

-—— Leachate Catch Basin

.:”&/

— Retention Dam

—-

:&b

---–– \ (

ill\ \

\ , Emergency Spillway

‘\ \ ‘~.

\ / ‘\

‘\ \\ \

SOURCE: Surface Mining of Non-Coal Minerals, National Academy of

Sciences, Washington, D C., 1979, p. 126,

erosion potential, reclamation effectiveness,

and the balance between erosion and soil production rates. Water and leachates may percolate into underlying alluvial aquifers. *

These effects need careful monitoring at

pioneer commercial facilities.

The efficacies of these control strategies

after site abandonment are even less certain.

Long-term monitoring and custodial care may

be required to assure that contaminants are

not released from the catchment basin as a

result of dam failure or extraordinarily heavy

rainfall or snowfall,

For in situ processing, laboratory experiments indicate that high temperatures convert soluble solids in spent shale into insoluble mineral complexes. If such temperatures

could be achieved in commercial-scale oper-

*rI’here are other techniques as well, For example, preleaching of spent shale, capillarv brakes, and covering spent shale

with open pit overburden, See the section on land reclamation

in this rhapter for more detail.

ations, they might serve as a primary method

for reducing leaching. Several uncertainties

prevent assessing the feasibility of this approach. For example, the mineral complexes

produced in the field would have to remain insoluble for long periods of time even if the

retorts were backflooded. Also, to eliminate

leaching, all of the spent shale in the retorts

would have to be insoluble. Because control

of MIS retorting is difficult, portions of the

retorts may not become hot enough to produce the insoluble complexes. Control of retorting temperatures in TIS processing is

even less certain. Since there would be massive amounts of waste, increased percolation

by ground water, and thus greater leaching

potential, these uncertainties may mandate

the adoption of retort abandonment strategies.

Retorted shale can form a cement-like material if it is properly prepared, and water

slurries of finely crushed retorted shale could

be injected into burned-out retorts to fill void

areas and to make the spent shale impermeable to water flow. To prevent leaching,

the cement formed from the injected slurry

would have to have very low permeability;

otherwise, the cement itself might produce a

troublesome leachate, thereby compounding

ground water pollution, Distributing the slurry uniformly within the retort may also prove

difficult.

Another approach would be to pump freshwater through the retort to intentionally

leach out the soluble components. The leachates could be treated and then reinfected on a

downgradient from the retorts. It is possible

that leaching could be accelerated in this

way, but the process might be costly and timeconsuming and the technology has yet to be

developed.

“Hydrologic barriers” might be used to

prevent or control the flow of water into the

retort area, thereby preventing the dispersion of leachates. One possibility is drilling a

continuous series of holes around the retort

area and filling them with a cementitious

slurry. By itself, this technique may not be fully effective since the retorts may be in aqui-
308 . An Assessment of Oil Shale Technologies

fers in which water moves vertically. The effectiveness could be increased by cementing

(grouting) the retorts to seal their more permeable zones and fractures.

Another possibility would be to divert a

major portion of the ground water flow

around the retort area. In this “hydraulic bypass” option, artificial channels or barriers

would capture most of the ground water flowing toward the retort area, direct it around

the area, and then return it to the ground water system.

Ultimate Disposition of Wastewater

At present, no developer plans to discharge

wastewaters to surface streams; rather, the

final wastes will be disposed of by recycling,

evaporation, and reinfection. In the future,

consideration may be given to treating and

discharging all surplus process waters. This

would be much more expensive than treatment to industrial standards, but it would reduce the impacts of development by augmenting stream flows in a water-short region. If

this option is adopted, water treatment needs

will increase significantly and highly efficient

treatment methods will be necessary.

Recycling

Present developer plans call for treating

and recycling wastewaters whenever practical. This depends only on the ability of waste

treatment systems to purify the wastewaters

so that they could be reused in other portions

of the process. Nearly all of the wastewaters

could be reused after appropriate treatment

for cooling tower makeup, for dust control,

for shale disposal, for leaching, for revegetation, and for generating steam that could be

injected into either aboveground or in situ retorts. As discussed previously, efficient, reliable, adaptable, and cost-effective methods

appear to be available for the major contaminated streams. Their capability of treating

the wastes to discharge or reinfection standards is not relevant as long as the streams are

to be recycled.

Treated cooling tower wastewater could

be reused after dilution with other treated

streams. Treated gas condensates are also

suitable for cooling water because they

should have low concentrations of inorganic

contaminants and volatile organics. Retort

condensates could also be used after their

dissolved substances are removed.

Water quality criteria have not been established for dust control, shale disposal, or

revegetation, but water similar to river water

would probably be acceptable. It should be

possible and practical to treat gas condensates to this level. Treated retort condensates

should also be acceptable, although successful treatment has yet to be demonstrated.

Steam raising, for example, with the thermal

sludge system, is at present a more reliable

option. These condensates (either treated or

untreated) could also be used as a slurry

medium for grouting in situ retorts. Tests

would be needed to determine if the wastewater contaminants were truly immobilized

so that they could not be leached by ground

water.

Evaporation

Most of the wastewaters will be disposed

of in dust control and in the waste disposal

piles. The sludges and concentrates from

wastewater treatment will also be added to

the disposal piles. In essence, this converts a

point source of pollution, which would be

highly regulated under existing laws, to a

nonpoint discharge, which is not well-regulated at present. However, the treated wastewaters would be quite different from the raw

streams described in table 51. For example,

most of the NH3 and H2S will have been removed from the gas condensates and recovered as byproducts. The CO2 will also have

been removed and vented to the atmosphere.

The concentration of NH3 could be further reduced by biological treatment and by using

the treated condensates as cooling water.

The small quantity remaining may be useful

as fertilizer for reclaiming the waste disposal

areas. Most of the potentially harmful organ-
Ch. 8–Environmental Considerations 309

ic compounds could be removed by biological

treatment and the more resistant ones by adsorption. However, some organic matter is

likely to reach the shale disposal area. It is

not known whether the organics will remain

locked within the shale pile or will be

leached.

Similar treatment could be used for the retorting and upgrading condensates, although

the chemicals in the retort condensate could

pose some special treatment problems. If

thermal sludge systems were used, both the

inorganic and the nonvolatile organic contaminants would be reduced to a stable sludge

suitable for disposal in a sanitary landfill or

in a hazardous-waste disposal area. The volatile organics would be entrained in the steam

and subsequently incinerated in the retorts.

Reinfection

Reinfection may be legally allowed if the

quality of the injected water is at least as

high as that in the affected aquifer. Injection

of condensates or other highly contaminated

wastes would not be permitted without a high

degree of treatment, However, mine drainage

water might be reinfected if it had not been

degraded by evaporation or chemical change

while on the surface. Otherwise, it first

would have to be treated or diluted.

Until commercial-scale oil production begins, essentially all mine drainage water will

require disposal, probably by reinfection. It is

generally assumed that the chemicals in the

drainage water would not cause significant

changes in the quality of the source aquifers.

However, water quality could be degraded

because of the increased ground water flow,

the exposure of new mineral surfaces by

fracturing, and the changes in underground

microbial populations. If such changes occurred, the treatment or disposal conditions

would have to be adjusted to compensate for

them. 51 This might include treating the drainage to a purity higher than that of the source

aquifer.

Monitoring Water Quality

Because much surface water comes from

ground water discharge, it is necessary to

monitor both surface and ground water to

help prevent environmental damage. Monitoring provides a continuous check on compliance with regulations, a record of changes resulting from development, and a measure of

the effectiveness of pollution control procedures.

Surface Water Monitoring

Surface water monitoring should include:

●

●

●

●

A

instream sampling and chemical analysis to detect and characterize pollutants of point and nonpoint origin:

detection of spills and faulty containment structures that could result in accidental discharges;

measurement of streamflows to assess

effects of dewatering operations and

consumptive uses; and

measurement of aquatic biota to determine the changes resulting from development,

monitoring program is defined by the

number and location of sampling stations, the

parameters measured, the sampling frequency and collection methods, the accuracy and

precision of the analytical techniques, and

the quality assurance safeguards. Traditional monitoring methods may not be well-suited

for the oil shale situation. The uncertain

pollutant release rates and pathways and the

wide variations in regional water quality,

complicate the development of a suitable program and limit the use of conventional techniques.

The number and location of sampling stations depend on the objective of the monitoring program. For example, if the objective is

to detect changes over an entire basin, the

stations would be located in the lower

reaches of major tributaries. They could de-
310 An Assessment of Oil Shale Technologies

tect major changes but would be unable to

pinpoint their cause. In contrast, stations

near pollution sources could both measure

the local effects of pollutant discharge and

identify the source. An oil shale program

could include stations on major streams, as

well as on the minor tributaries that drain

each development site. Special stations are

also needed near solid waste disposal areas

to detect leaching.

The selection of chemical, physical, and

biological parameters to be measured will be

based on the types and concentrations of pollutants that might be discharged, the ease of

analysis, and the characteristics of the water

in the affected streams and aquifers. The

possible parameters include the concentrations of the pollutants themselves as well as

the levels of “indicator” parameters that provide a measure of the potential environmental

disturbance. These include pH, dissolved oxygen, hardness, temperature, flow rate, and

the characteristics of the aquatic biota.

Biological parameters are especially useful

because they reflect the stability and response of the ecosystem. Aquatic organisms

are natural monitors of water quality since

they respond in a predictable manner to the

presence of most types of pollutants. Changes

may indicate problems that are not easily

detected by direct measurements of water

quality. For example, heavy metals and some

organic compounds tend to concentrate in the

biota. Their levels in the tissues of certain

fish could help predict pollution concentrations that are not readily measurable in the

water itself. Communities that could be monitored include invertebrates, fish, algae, and

bacteria.

The sampling frequency can also vary.

Ephemeral tributaries, for example, could be

monitored only during periods of heavy rainfall or snowmelt; mainstream tributaries

could be monitored continuously. Frequent

monitoring of all possible parameters would

be very expensive and time-consuming.

Therefore, priorities must be established on

the basis of cost, utility of the data, and the

potential for severe environmental impacts.

Ground Water Monitoring

Observation wells are used to detect

trends in water quality and to measure the effects of operations such as wastewater reinfection. The locations of the monitoring stations should be selected according to:

● the locations of the potential pollutant

sources;

● the geology and hydrology of the site to

be monitored;

● the probable movement and dispersion

of pollutants underground; and

● the potential for hydrologic disturbances

of, for example, dewatering wells.

EPA has developed a monitoring methodology

for the oil shale area.52 The important considerations are:

●

●

●

●

●

●

The

the identification of potential pollutants;

the definition of hydrogeology, ground

water use, and existing quality;

the evaluation of the potential for infiltration of wastes by seepage;

the evaluation of pollutant mobility in

the affected aquifers;

the priority ranking of pollution sources

based on the mass, persistence, toxicity,

and concentration of the wastes; their

mobility; and their potential for harm to

water users; and

the design and implementation of programs for near-surface aquifers, deep

aquifers, and injection wells.

siting of wells for near-surface aquifers

is extremely important. They should be

placed down the ground water hydraulic gradient (i.e., “downstream”) from possible pollution sources such as reinfection wells, reservoirs, and disposal piles. The wells should

allow sampling from different depths, and the

chemical and physical parameters should be

selected according to hydrological characteristics as well as the properties of potential

pollutants. Deep aquifers should be monitored near dewatering wells, in situ retorts,

and reinfection wells. Monitoring of salinity,

TDS, and water level should be emphasized.

Monitoring deep aquifers in the Piceance

basin is especially difficult because the
— —

Ch, 8–Environmental Considerations ● 311

ground water flows through fractures and

faults and not through the more common uniformly porous media, A further complication

is the different permeability of adjacent

strata. Even flow rates are hard to measure

in a fractured-rock system, and it is difficult

to properly site the monitoring stations.

The monitoring of surface and ground water quality is exemplified by the program on

Federal lease tract C-b that has been underway since 1974. The sampling schedule and

water quality parameters are listed in table

65. Thirteen surface water gauging stations

have been constructed: nine on ephemeral

streams and four on perennial drainages.

Nine springs and seeps are also monitored.

Temperature and conductivity are measured

continuously at all stations on the perennial

streams. Dissolved oxygen, pH, and turbidity

are measured continuously at several of

these stations; other parameters are measured monthly, quarterly, or semiannually.

Water levels in alluvial aquifers are measured continuously at 18 test wells. Conductance, pH, temperature, and dissolved oxygen

will be measured monthly. The quantity and

quality of water in the deeper bedrock aquifers are measured at 17 wells in the upper

aquifer and 14 in the lower aquifer. Samples

are obtained for water quality twice a year,

and water levels are measured monthly. Water quality is also measured in reservoirs,

waste disposal piles, and mine sumps.

Information Needs and R&D Programs

Insights into the water quality impacts of

oil shale development have been obtained

from laboratory and pilot plant studies, from

a few field tests in the Piceance basin, and

from experience in related industries. Additional measurements and R&D programs are

needed to help reduce the level of uncertainty. Uncertainties will remain, however, until

experience has accumulated from commercial-sized modules and plants.

Need for Reliable Data on Wastewater Quality

Reliable data are lacking on the characteristics of the gas, retort, and upgrading

condensates from all of the proposed development technologies. The data should be

obtained with pilot plants that integrate several streams and several control devices and

that simulate commercial-scale conditions.

In commercial plants, wastewaters may be

mixed and the interactions of contaminants

from the different streams will affect treatability. Therefore, analyses of separate

streams are not sufficient.

More reliable estimates are needed of the

quality and quantity of the mine drainage

water that will be encountered in specific

areas. This information would help determine

how the water would have to be treated for

surface discharge, and would allow a comparison to be made between surface discharge and other disposal methods.

Studies of leachates are also needed; in

particular, on their ability to penetrate the

linings of disposal ponds and catchment basins.

Need for Assessing Control Technologies

Although individual methods have been

tested successfully on a small scale, the performance of an integrated treatment system

has yet to be evaluated with actual effluent

streams. This could be done, for example, by

testing relatively inexpensive pilot-scale systems as part of a retort demonstration program. These tests would help determine, for

example, if the dissolved organics in retort

condensates can be adequately controlled

with a series of conventional treatment processes. The distribution and control of trace

elements could also be assessed.

Need for Cost Information

According to present estimates, wastewater treatment costs are expected to be only a

small fraction of the total cost of shale oil pro-
—— —— — -.. —

312 An Assessment of Oil Shale Technologies

Table 65.–Sampling Schedule Summary for Surface and Ground Water

Monitoring Program at Tract C-b During Development Phase

Surface water Seeps and springs Ground water

Alkalinity ., ...

Ammonia ., ., ~ .,

Arsenic. ... ., ., . ., .,

Barium . ., ... .,

Beryllium .. .

Bicarbonate .......,. .,, ,,, ,. ,

BAD. , .,.,.,,......,,.. . . .

Boron ., ., ., .

Cobalt. .,..,.,,, .,, ,, ..,,.,,..,, .

Color ., .,, .,, ,, .,, ..,.... .,,,,,,

COD.. . . . . . . . . . . .

Coliform, total and fecal ., .,,.,,,,,. .,

Conductivity, specific, ,,. ,,

Copper. , .,, .,... ,.,.,, . .

Cyanide ..,.,,. .,, ,,, ..,.,, ,,,. ,

Dissolved oxygen .,,., .

Fluoride ., ., ., .

Hardness ,. .,.,, ,’,”’” .

Iro n

Lead. ...’.., , .,,,, ‘ ,

Lithium. ,.,, ,.,, ,,..,,.

Magnesium, ,.,’.. . . . . .

Manganese, ,, ,

Mercury. ., . . . . ., .,

Molybdenum .,.., . . . . . . ,,,

Nickel. , ,,. ,., ..., ,.

Nitrate . . . . . . . . . . . ,,.

Nitrogen (Kjeldahl), ,.,,.

Odor .,,,

Oil and grease, , , .,,, ,,.

Phosphate, , ...,, ,,.

Pesticides. .,... ,.., ,,.

Phenol ,.. ,,,. .,,. .,,,

Potassium, ., ., ., ..., ., .,

Radiation, alpha .,, ,,, ,,,

Radiation, beta ., .,

Sediment ,.. ,. ,“.

Silica ..,,, ,,. ,.., .,,,,

Sulfate ,. ,, ....,,

Sulfid e

Suspended solid s

Turbidity. . . . ,. .,.,,,, ,,, ,,,,..,

PA, ,, ., ..,.,.,, ..., ,,,

Total dissolved solids. . ,, , .

Water level .,

Stream flow. ,, . . . . . . . ..,’

Water temperature .,. .

Dissolved organic carbon ., . ,

M(Z), Q(O,PC)

M(Z)Q(o,PC)

M(Z)O(o,PC)

—

Q

M(Z) Q(o,PC)

—

M(Z~Q(o,PC)

—

—

Q

o

.

Q

Q

M(Z)Q(o,PC)

M(Z), Q(o,PC)

—

—

Q

Q

M(Z), Q(o,PC)

M(Z) Q(o,PC)

Q

Q

—

M(Z~Q(o.PC)

M(Z), Q(o,PC)

—

Q

M(Z~Q(o,PC)

—

Q

M(Z), Q(o,PC)

Q

Q

M(Z), Q(o,PC)

M(Z), Q(o,PC)

M(Z), Q(o,PC)

o—

—

M(Z), Q(o,PC)

M(Z), Q(o,PC)

—

M(Z) Q(o,PC)

M(Z) Q(o,PC)

M(Z) Q(o,PC)

o

Q

Q

—

—

—

Q

Q

—

—

Q

s

M

Q

—

M

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

Q

—

Q

—

.

Q

Q

s

s—

—

o—

—

—

M,Q

Q

—

Q,SA,A

M,Q

s

Q(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

(Lis a

A(AI)

—

SA(Al), SA(Aq)

Q(Al), SA(Aq)

SA(Aq)

—

Q(Al), SA(Aq) —

Q(AI)

Q(Al), SA(Aq

—

M(AI)

Q(Al), SA(Aq

Q(Al), SA(Aq

Q(Al), SA(Aq

Q(Al), SA(Aq)

Q(Al), SA(Aq)

O(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

Q(Al), SA(Aq)

—

Q(Al), SA(Aq)

—

SA(Aq)

A(Al), SA(Aq)

Q(Al), SA(Aq)

SA(Al), SA(Aq

SA(Al), SA(Aq

—

—

Q(Al), SA(Aq)

—

—

—

M,Q(AI)

Q(AI)

MES A

—

M, Q(Al), SA(Aq)

SA(Al), SA(Aq)

KEY A =AnnUa~y (Z) =Maorgaglng slationson~

SA = Semiannually (o) =Aflgagmg stations except major stahons

S= Semimonthly (PC) =F?ceance Creek gaging stations

O =Ouarferiy (Al) =Alluwal wells

M =Monlhly (Aqj =Oeepaquders

SOURCE E R Bales andT L Thoem(eds ) Pollution Con/ro/Gu/dancelor Oti Sha/e Deve/oprnerrl Apperrd/ces /o the l?ewsed L%a/(Reporl, comptiedby

Jacobs Envwonmental Orw~onfor Envvonmental Protection Agency C{nclnnah Ohio July 1979 pp C-84-C-85

duction. However, inadequate attention to Lower cost treatment options should also

water management could seriously impede a be explored. For example, the thermal sludge

project’s construction and operation. Thus, system could significantly reduce treatment

water treatment although not costly by itself costs by raising steam directly from process

could ultimately cause substantial cost esca- condensates. Another promising procedure

lations. is the removal of dissolved organics from
Ch. 8–Environmental Considerations ● 313

treated condensates in the cooling water circuit.

Discharging suitably treated wastewaters

(especially excess mine water) to surface

streams should be investigated as a mechanism for supplementing the region’s scarce

water resources. Some of the contaminants in

the treated wastes may require special attention, and means to remove them should be explored.

Need for Evaluating the Potential Impacts

of Effluent Streams

Information is needed on the impacts of the

pollutants on the environment. In particular,

research is needed on the effect of the leaching of spent shale and other solid wastes on

salinity, sediment loading, temperature, nutrient loading, and microbial populations of

surface waters. This work should address the

impacts that might occur both during the

operation of a facility and after the facility’s

useful lifetime.

Specific R&D Needs

Research is needed in the following specific areas:

●

●

●

●

●

●

characterization of the wastewaters, especially for the presence of trace metals

and organic chemicals produced by each

retorting process;

determination of the applicability of conventional treatment methods to oil shale

wastewater and development of new

treatment methods if necessary;

determination of the changes in ground

water quality and flows resulting from

mine dewatering;

development and demonstration of methods to prevent leaching of MIS retorts by

ground water;

studies to simulate and test the percolation of rainfall and snowmelt through

spent and raw shales and native soils

and to assess resulting leachates;

standardization of leachate sampling

techniques;

development of reliable models and testing them under simulated worst case

conditions, such as massive failure of a

containment structure; and

research on the restoration of aquifers

disturbed by in situ processing,

Current R&D Programs

Below is a partial listing of the ongoing and

proposed R&D programs by the Federal Government and the private sector:

Under EPA grants, Colorado State University is studying the water quality

within the oil shale areas, the leaching

characteristics of raw and retorted oil

shale, and the surface stability and water movement in and through disposal

piles. Specific objectives include developing procedures for assessing the quantity and quality of surface and subsurface runoff from solid waste piles.

Under an EPA contract, TRW and DRI

are studying the environmental impact

of oil shale development, including an

evaluation of technologies for wastewater control.

DOE’s Office of the Environment is assessing water quality aspects of the

Paraho process.

DOE and the State of Colorado are developing a program related to water pollution from MIS retorting.

Under EPA contracts, the Monsanto Research Corp. is investigating the treatment of retort wastewaters and is studying the potential of in situ retorting for

air and water pollution.

The National Bureau of Standards, in cooperation with EPA and other agencies,

is developing methods for measuring the

environmental effects of increased energy production.

In its oil shale program management

plan, DOE has proposed to:

—assess the effect of mine and retort

backfilling on ground water quality;

—study the leachability of raw and

spent shale and the effect of disposal

on surface and ground water quality;

6 3-89B ‘ - 80 - ? :
314 An Assessment of Oil Shale Technologies

●

●

—investigate the need for long-term

care of surface disposal areas; and

—design a solid waste disposal plan for

a commercial MIS facility.

The National Science Foundation is

sponsoring work to characterize the contaminants in spent shale and to develop

techniques for managing them.

EPA is preparing a pollution control

guidance document for an oil shale industry, that will consider all aspects of

surface and ground water quality.

Findings on Water Quality Aspects of

Oil Shale Development

Water quality is of major concern in the oil

shale region, especially in regard to the

salinity and sediment levels in the Colorado

River system. Oil shale development has the

potential for water pollution, the extent of

which will depend on the processing technologies employed, the scale of operation, the

types and efficiencies of the pollution control

strategies used, and the regulations that are

imposed.

Surface discharge from point sources is

regulated under the Clean Water Act, and

ground water reinfection standards are being

promulgated under the Safe Drinking Water

Act. Solid waste disposal methods may be

subject to the Toxic Substances Control Act

and the Resource Conservation and Recovery

Act. The general regulatory framework is

therefore in place, although no technologybased effluent standards have been promulgated for the industry under the Clean Water

Act .

Developers are currently planning for zero

discharge to surface streams and to reinject

only excess mine water. Most wastewater

will be treated for reuse within the facility;

untreatable wastes will be discarded in spent

shale piles. The costs of this strategy are low

to moderate, and development should not be

impeded by existing regulations if it is implemented.

A variety of treatment devices are available for the above strategy, and many of them

should be well-suited to oil shale processes. It

is less certain that the conventional methods

would be able to treat wastewaters to discharge standards because they have not been

tested with actual oil shale wastes under conditions that approximate commercial production. Furthermore, no technique has been

demonstrated for managing ground water

leaching of in situ retorts, nor has the efficacy of methods for protecting surface disposal piles from leaching been proven. It is

not known to what extent leaching will occur,

but if it did, it would degrade the region’s

water quality.

Although control of major water pollutants

from point sources is not expected to be a

severe problem, less is known about control

of trace metals and toxic organic substances.

Research is needed to assess the hazards

posed by these pollutants and to develop

methods for their management. Other laboratory-scale and pilot plant R&D should be focused on characterizing the waste streams,

determining the suitability of conventional

control technologies, and assessing the fates

of pollutants in the water system. Such work

is underway; its continuation is essential to

protecting water quality, both during the operation of a plant and after site abandonment.

Policy Options for

Water Quality Management

For Increasing Available Information

Options for increasing the overall level of

information regarding pollutants, their effects, or their control include the evolution of

existing R&D programs, the improved coordination of R&D work by Federal agencies, increasing or redistributing appropriations to

agencies to accelerate their surface and

ground water quality studies, and the passage of new legislation specifically tied to

evaluating water quality impacts. For example, pioneer plants receiving Federal assistance could be required to monitor water quality effects, with particular emphasis on nonpoint discharges. Procedures for implementa-
Ch. 8–Environmental Considerations . 315

tion could be similar to those for the existing

Federal Prototype Leasing Program. Mechanisms for implementing these options are similar to those discussed in the air quality section of this chapter.

For Developing and Evaluating

Control Technologies

The Government could expedite the availability of proven controls by accelerating its

efforts to design, develop, and test treatment

technologies for oil shale wastewaters. To be

most effective, this work would have to be

coordinated with private efforts to develop

the oil shale processing methods. This could

be done under cost-sharing arrangements, including tests at the sites of retort demonstration projects. (EPA is presently conducting a

program for retorting wastewaters under a

contract with Monsanto Research Corp. )

For Developing Regulatory Procedures

The present approach could be followed in

which regulations evolve as the industry and

its control technologies develop, An approach

could also be used in which standards would

be set that would not change for a period of

say, 10 years, after which they could be adjusted to reflect the experience of the industry. This would remove most of the uncertainty about environmental regulations that is

now deterring developer participation. However, the standards would have to be carefully established to assure that they were both

attainable at reasonable cost and adequate to

protect the environment. Mechanisms for implementing improved regulation of nonpoint

discharges include extension and modification of the Surface Mining Control and Reclamation Act for oil shale, special controls regulating nonpoint discharges under the Clean

Water Act, or applying the Resource Conservation and Recovery Act waste disposal

standards to low-grade/high-volume materials.

For Ensuring the Long-Term Management of

Waste Disposal Sites and Underground Retorts

These areas may require monitoring for

many years after the projects are completed.

Long-term management could be regulated

under the Resource Conservation and Recovery Act, which allows EPA to set standards

for the management of hazardous materials,

including mining and processing wastes. No

such action has yet been taken by EPA, but

Congress could direct it to do so. Congress

could also require the developers to guarantee such management by incorporating appropriate provisions in any bill encouraging

oil shale development.

Safety and Health

Introduction ●

Anticipating occupational and environmen- ●

tal health and safety hazards is an important

consideration in the development of an oil ●

shale industry. Anticipation and planning, especially in the early phases of the industry, ●

should guide efforts to reduce health and

safety risks and costs to society. To bring at- ●

tention to known hazards, and to point out potential ones, this section covers the following ●

subjects: ●

the health and safety hazards associated with oil shale operations;

the environmental risks if contaminated

air and water are released;

the applicable Federal health and safety

laws, standards, and regulations;

the control and mitigation methods that

could be applied to these risks;

the issues regarding the coordination of

monitoring and education efforts;

the R&D needs; and

the policy options.
316 “An Assessment of Oil Shale Technologies

Safety and Health Hazards

Occupational Hazards

Workers will be exposed to a number of occupational safety and health hazards during

the construction and operation of an oil shale

facility. Many of these hazards—such as

rockfalls, explosions and fires, dust, noise,

and contact with organic feedstocks and refined products—will be similar to those associated with hard-rock mining, mineral processing, and the refining of conventional petroleum. However, due to the physical and chemical characteristics of shale and shale oil, the

types of development technologies to be employed, and the scale of operations, oil shale

workers might be exposed to unique hazards.

They will be discussed as follows: safety hazards that might result in disabling or fatal accidents; and health hazards stemming from

high noise levels, contact with irritant and

asphyxiant gases and liquids, contact with

likely carcinogens and mutagens, and the inhalation of fibrogenic dust.

SAFETY HAZARDS

Mining.-The similarity of hard-rock mining to underground or open pit oil shale mining makes it possible to project likely occupational safety risks. During mining, accidents

result from rock and roof falls, explosions

and fires, bumps and falls, electrocution,

heavy mining equipment, and vehicular traffic. Hard-rock mining is a high-risk occupation; fatalities are five times more frequent in

the mining and quarrying industry than in

manufacturing. The frequency of disabling

injuries from underground mining (excluding

the coal industry) is two and a half times

higher than from manufacturing. 53 Minin g

coal is even more dangerous.

While most hazards to oil shale miners

would be similar to those experienced by

hard-rock workers, some are unique to oil

shale. A number of the oil shale facilities are

planning to use MIS processes in which part

of the deposit is mined out and the remainder

is then rubbled and burned underground. The

high temperatures and fires involved in MIS

may expose miners to risks that are not experienced in other underground mining activities. The hazard of mine flooding is not

unique to oil shale, nor would it be encountered in all oil shale mines. However, it could

be severe in mines that are developed within

ground water areas. While the mining zones

would be dewatered before mining could begin, there could be flooding if the pumps

failed.

Retorting and refining.—Potential hazards

associated with the retorting and upgrading

of shale oil include explosions, fire and heat,

bumps and falls, electrocution, and handling

hot liquids. However, the degree of risk for

workers involved in the processing of oil

shale and its derivatives would not be expected to be so high as in mining.

The processes involved in retorting and upgrading (e.g., materials handling, crushing,

solids heating and cooling, waste disposal,

and the handling of hot and hazardous liquids) are generally similar to those used in

other operations such as mineral processing

(e.g., limestone calcining, roasting of taconite

and copper ores, and leaching) and conventional petroleum refining. Although no comparative study has been undertaken, there

are few unique features associated with retorting, upgrading, and refining that would

justify expecting higher worker safety risks

than those in similar industries.

HEALTH HAZARDS

Mining. —During oil shale mining, as discussed in the section of this chapter on air

quality, hazardous substances including silica dust will be generated by blasting and

drilling. In addition, blasting, raw shale handling and disposal, and other activities at the

minesite will produce fugitive dust. Silicacontaining dusts are noteworthy because

they have been the single greatest health hazard throughout the history of underground

mining. Silica is highly toxic to alveolar

macrophages—’’scavenger” cells that move

about on the inside of the lung and engulf and

remove foreign particles that might damage

the lung. Silicosis, “shalosis,” and chronic
Ch. 8–Environmental Considerations ● 317

bronchitis* are among the diseases that may

result from the inhalation of oil shale dust.

A survey conducted by the U.S. Public

Health Service (USPHS) between 1958 and

1961 found excessive dust levels in 6 out of 67

inspected mines. 54 The chest X-rays of 14,076

miners employed in 50 hard-rock mines indicated that 3.4 percent had silicosis. ss * *

These measurements were made before modern mine hygiene practices were required by

the relatively recent occupational safety and

health regulations and a more recent study

undertaken by the Mining Safety and Health

Administration showed marked improvements in mine dust levels. This study examined 22 hard-rock mines, 8 of which were included in the USPHS study, and found none of

them in violation of the dust standards, 56)** *

Although few studies have been undertaken on the direct association between oil

shale mining in the United States and the incidence of lung disease, there are studies on

the prevalence of lung disease in oil shale

miners in Estonia. Estonia mined 25 million

tons of oil shale in 1973, and has had oil shale

operations for several decades. While the results of the Estonian studies are more intriguing than convincing, they do suggest an association between oil shale mining and pulmonary fibrosis—an increase in the amount of

fibrous material in the lung. One study also

indicated that chronic bronchitis was 2 to 2-1/2

times more prevalent in 189 Estonian oil shale

miners than in a similarly aged control population.” (A similar degree of excess bronchitis

has been observed in coal miners in the

*Sili~osis is a ~is~blin~ fibrotic disease of the lungs caused

by inhalation of silica dust and marked by shortness of breath.

“Shalosis” is a disease of the lungs and is related to specific exposures of oil shale mine dust. It resembles silicosis: its existence as a specific disease remains to be proved. Inflammation

of the bronchial tubes, or anv part of them, is known as bronchitis.

**The 3.4 percent is probably a low estimate; generally sick

individuals who have left the work force or moved for health

and other reasons are under-represented in such surveys. If

such individuals had been examined the incidence of silicosis

might have been higher.

***This study is expected to be released in the near future

along with a companion study undertaken by the National Institute of Occupational Health and Safety which examines the

health status of miners from 22 hardrock mines.

United States and England,

58 and in gold

miners in South Africa. 59)

In another study, postmortem examination

of 30 Estonian oil shale workers who died of

accidents and various other diseases 60 found

that all had pulmonary fibrosis and onefourth displayed classic silicotic nodules. * An

examination of 1,000 Estonian oil shale

workers failed to reveal any cases of pneumoconiosis, a pulmonary disease caused by inhaled dusts. However, the workers had been

involved in the industry for only 5 to 14 years.

Twenty years of exposure are usually required for the symptoms of the disease to be

detected by a chest X-ray. Because Estonian

industrial hygiene standards are not known,

the Estonian studies can only suggest an association between oil shale mining and lung disease. The Estonian studies provide no information about the risk levels to be expected in

mines maintained under U.S. health and safety standards.

Studies of occupational diseases among oil

shale miners in the United States have been

limited because relatively few people have

worked in the industry. A study was undertaken involving miners from the oil shale research center at Anvil Points, Colo., which

has operated intermittently since 1946.

Eighty-six workers were identified, but only

39 of them had been exposed to oil shale for

one or more years. Those 39 were compared

with 26 other workers from the facility (e.g.,

office workers, administrators) who had not

been directly involved in the mining operations. Results showed a twofold higher incidence of pneumoconiosis in the oil-shale exposed population. However, the interpretation of these results is complicated by the fact

that most of the oil shale miners had previously worked in uranium-vanadium mines or milling operations which are known to be causes

of pneumoconiosis.61 Further evaluation of

these populations was not performed because

of the age of the workers, their varying levels

of exposure, and their limited experience in

oil shale mining.

*Silicotic nodules are small lumps on the surface of the lung

formed as a response to deposition of silica specks.
318 ● An Assessment of Oil Shale Technologies

A separate study of employees at the same

facility between 1974 and 1978 found no adverse health effects.62 An examination of the

death certificates of 167 oil shale workers undertaken by the National Institute for Occupational Safety and Health (NIOSH) failed to

reveal any association between oil shale exposure and respiratory diseases.63 Because of

the limited number of workers studied, their

relatively short exposures to oil shale mining,

and in some cases their exposures to other

kinds of mining, no firm conclusions can be

drawn from these studies.

Some animal studies have demonstrated

relationships between oil shale exposure and

respiratory diseases, but the results conflict

with those of other experiments, making it

difficult to draw conclusions. One study indicated that Estonian oil shale had a weak fibrogenic* action in rats; both oil shale and

spent shale ash produced pulmonary fibrosis

in white rats after the dusts were deposited

into the trachea.64 Another study reported

pulmonary effects when Syrian hamsters

were exposed via intratracheal administration or inhalation to finely ground oil shale

dust and retorted shales.65 66 Increased alveolar microphage activity was also noted. The

same study found that retorted shale dust

was associated with inflammation, and frequently caused increases in the fibrous material in the lung (fibrosis] and excessive

growth of cells that line the lung cavities (epithelial hyperplasia). However, a 2-year study

with rats, which evaluated the effects of raw

or spent shale dust instilled intratracheally in

multiple exposures over an 8-month period,

found essentially no pulmonary fibrosis. The

investigator considered the results to be negative. 67

Another area of concern is the possible exposure to carcinogens (e.g., polycyclic aromatic hydrocarbons—PAHs) and trace elements that might be produced during mining.

The NIOSH mortality study mentioned earlier found that the percentage of oil shale

workers who had died from colon and respi-

*A fibrogenic substance is conducive to the generation of

fibrous materials in the respiratory tract.

ratory cancers was greater than the percentage in the white male populations of Colorado

and Utah.68 Whether oil shale exposure contributed to the higher incidence is unclear,

and the incidence rate among miners was not

higher than that of the white male population

in the United States.

A cancer morbidity study undertaken by

the Rocky Mountain Center for Occupational

and Environmental Health found more cytological atypia* in the sputum and urine of oil

shale miners than among controls, but no association was found between exposure and

skin diseases. These data will be further

studied to identify any associations between

such abnormalities and occupational exposures. Animal studies undertaken to date

have not demonstrated that oil shale dust is

carcinogenic.

A third potential health hazard to oil shale

miners is exposure to excessive noise levels,

particularly in underground operations carried out in relatively confined spaces. Noise

arises from numerous sources such as booster fans, pneumatic drills, blasting, conveyors,

and mining machines. The Bureau of Mines

studied 19 pieces of diesel-powered mining

equipment and found only 2 had noise levels

below the current standards (90 decibels),

and one of these exceeded the standard in an

underground environment. One study estimated that of the 37,000 workers employed in

650 metal and nonmetal mines, approximately 14,000 (38 percent) were exposed to dieselpowered equipment noise levels greater than

the standard.** Of these, 2,430 (17 percent)

were overexposed on a time-weighted-average basis.69 Evidence indicates exposure to

noise from a large number of mining machines would produce hearing loss if the exposures exceeded 8 hours per day.70 Higher

short-term noise exposures may occur during

*Cytological atypia are premalignant cell types observed in

the examination of the body fluids.

**A major health issue is the long-term effect of diesel smoke

exposure in underground mining environments. The National

Academy of Sciences is conducting a study in this area which

will be released in the near future. The health implications of

diesel equipment used in underground oil shale mines is unknown at this time.
Ch. 8–Environmental Considerations 319

blasting. High noise levels are a potential hazard not only to hearing, but to the cardiovascular and nervous systems as well, and pose

a safety hazard.

Retorting and refining. —Retorting oil

shale at high temperatures forms PAH-containing carcinogens of which 3,4-benzo(a)pyrene (BaP) is the most studied. PAHs are a

major potential health hazard for retorting

and refining workers in the oil shale industry

because of their carcinogenicity. The problems that might be encountered in oil shale refining are similar to those of conventional oil

refineries, where liquids and gases are transported in airtight pipes under strict maintenance to detect and repair leaks.

Crude oil contains an enormous variety of

potentially hazardous compounds, Even more

are produced during refining. Work crews involved in inspection, repair, and maintenance

are the most likely to be exposed to PAHs.

Other hazardous substances found in crude

oil include chlorine, sulfur, nitrogen, and

heavy metals (e.g., vanadium, arsenic, nickel,

and cobalt). Toxic contaminants evolved during the refining process include H2S, hydrogen chloride, hydrochloric acid, SO2

, sulfuric

acid, methane, ethane, methanol, nitric acid,

NOX

, mercaptans, CO, and benzene.

The high rate of cancer of the scrotum

found in 19th century chimney sweeps and

mulespinners* is of historical interest because it indicates that long exposure of scrotal skin to PAH-containing oils and soots can

cause cancer. In addition to scrotal cancer,

cancers of the skin, lung, and stomach have

also been observed after latent periods of up

to 20 years following exposure to PAH-containing substances. While the known carcinogen BaP was identified in Scottish shale oil,71

a study found only a low incidence rate (less

than 0.1 percent per year) of skin cancer for

5,000 Scottish oil shale workers between

1900 and 1922.72

*Mulespinners were workers who lubricated the “mules”

(spindles) in the Scottish spinning and weaving industry. Shalederived lubricants were commonly used in this industry.

Refined Scottish shale oils were known to

be carcinogenic, but the disease was largely

preventable by personal cleanliness. It is believed that the disease occurred because the

workers wore the same clothes on the job day

after day. The clothing was rarely, if ever,

laundered, and eventually it became impregnated with shale oil. Contact between the

soaked clothing and the areas where cancers

occurred was nearly continuous during each

working day. This factor, coupled with the

fact that daily bathing was rare, undoubtedly

contributed to the high incidence of cancer.

Two Estonian studies have shown an association between oil shale processing and

cancer. A study of 2,003 Estonian oil shale

workers with a total of 21,495 person-years

exposure during the period between 1959

and 1975 found a significant excess of skin

cancer (fivefold for females and threefold for

males). 73 An unusually high incidence of

stomach and lung cancer was found among

persons in the rural areas of Estonia where

the oil shale industry is located. ” There is no

information on the working conditions in Estonian oil shale operations; nor are data

available on the ambient concentrations of

shale-derived pollutants in the vicinity of the

plants. It is therefore impossible to relate the

Estonian experience to problems that might

be encountered in the United States.

Evaluating chemical carcinogenicity in animal experiments is an accepted method for

predicting carcinogenicity in humans. Investigations that tested the carcinogenicity of oil

shale and shale oil in laboratory animals are

shown in table 66. A conclusion that can be

drawn from these studies is that shale oil is a

carcinogen when painted on animal skins.

The experiment conducted by Biology Research Consultants (ref. 80 in table 66), in

which hairless mice were bedded in raw or

spent oil shale, found no carcinogenic hazard.

However, this study did not examine the oil

shale extracts (e.g., shale oil tar and coke)

with which carcinogenicity has been associated.

Both the Kettering Laboratory (ref. 79) and

Eppley Institute (ref. 81) studies conclusively
320 ● An Assessment of Oil Shale Technologies

Table 66.–Animal Studies on the Carcinogenicity of Oil Shale and Shale Oil

Organs

Nature of study Ref a Materials tested examined Tumerous animals/animals exposed

Skin painting study of mice, rats, and rabbits

Skin painting of mice

Skin painting of mice

Skin painting of mice

Skin painting of mice (Kettering study)

Exposure to shale dust (Biology Research

Consultants)

Skin painting of mice (Eppley study)

Intratrachael Instillation in hamsters (Eppley

study)

75

76

77

78

79

79

79

79

Scottish shale OilS “green 011’

‘‘blue oil’

‘‘unfinished gas oil’

‘‘Iubricatmg oil

CHCI 3 extract of Scottish oil shale

Scottish shale oil

Shale oil

Shale oil

Composite petroleum control

Crude shale oil

Hydrotreated oil

BaP control

Oil shale powder

Oil shale powder

Spent shale powder

Spent shale powder

Powdered corn cobs (control)

Powdered corn cobs (control)

Benzene extract of shale oil coke

TOSCO II effluent

Benzene extract of raw shale oil

Benzene extract of spent shale

Benzene control

None (control)

Raw oil shale

Spent shale

Shale 011 coke

TOSCO II effluent

BaP control

Saline control

None (control)

skin

skin

skin

skin

skin

skin

skin

skin

skin

skin

skin

skin

skin

lungs

skin

lungs

skin

lungs

skin

skin

skin

skin

skin

skin

(b)

(b)

(b)

(b)

(b)

(b)

(b)

9/100

1 2/100

1/50

3/50

0/20

6/10

1,284/10,000

(35%-90% tumerous)

(0%-8% tumerous)

39/40

5/37

27/27

0/12

2/24

0/12

1 /24

0/1 2

6/24

48/50

1 /50

0/50

6/50

0/50

0/100

0/100

0/100

0/100

0/ 100

27/1OO

0/ 100

0/200

a

See reference list bResplratory system

SOURCE Wllham Rom et al OcCuPdllOflallEflVlfOflmeflldl Healfh and .SaletY Aspecfs of a CO~rrJerCW 0// Wale lmlWy prePared for OTA by Rocky Mountain Center for Occupational and Enwronmental

Health Unwerslty of Utah Oecember 1979

show that crude shale oil, shale oil tars, and

shale coke have carcinogenic properties,

which may be related to their BaP content.

The second Eppley study (ref. 82), which investigated respiratory system carcinogenicity, found no effect. This contrasts to the

skin exposure experiments. Whether or not

oil shale and its derivatives are less of a

threat to the respiratory system than to the

skin deserves further study.

Although BaP may not be the only carcinogen in shale oil and its products, it is probably

the most potent. The study summarized in

table 67 shows that hydrotreating shale oil

Table 67.–Benzo(a)pyrene Content of Oil Shale and

Its Products and of Other Energy Materials

Substance BaP concentration, p/ba

Raw oil shale ., . ., . . . 14

TOSCO II retorted shale, ., . , 28

TOSCO II atmospheric effluent . . ., 140

TOSCO II retort coke . 129

Raw shale oil from Colorado, ., ., ., 3,200

Hydrotreated shale 011 (0.25% N2

) ., 800

Hydrotreated shale 011 (0,05% N2

) ., 690

Coal ., ., ., 4,000

Libyan crude 011 ., 1,320

Asphalt from conventional crud e 10,000-100,000

aParis per bllllon

SOURCE R M Coomes Carcmogenlc Tesflng of 011 Shale Materials TweMh 0// Sha/e Syrrposwm Proceedings Golden Colo The Colorado School o! Mines Press November

1979
Ch 8–Environmental Considerations . 321

significantly reduces its BaP content,’{ Such a

reduction should be reflected in a lessening of

its carcinogenicity, This predicted effect of

hydrotreating was confirmed by the animal

tests of the Kettering experiment (ref. 79,

table 66).

The Estonian epidemiological studies and

the animal studies show that crude shale oil,

shale oil tars, and shale coke are all carcinogenic. Most of the studies to date suggest

that carcinogenicity is restricted to the skin.

Occupational skin diseases from exposure to

certain industrial oils have long been a problem, as was seen in the case of the scrotal

cancer among chimney sweeps, One study

showed that the effects of oil contact with the

skin range from acute inflammation to keratosis (pitch warts which are regarded as a

premalignant skin change.)84 Studies of oil

shale retorting workers in the United States

in the early 1950’s did not reveal any problems with occupational skin disease, but

workers were exposed for a short time only. 85

A synergistic relationship has been found

between the ultraviolet radiation in sunlight

and coal-tar pitch volatiles in causing skin

diseases. A similar synergism might cause occupational skin diseases in oil shale workers

on the Colorado plateau, where ultraviolet

radiation levels are higher than at lower elevations.

Refining shale oil will be similar to other

refining operations. Available epidemiological studies do not lead to clear-cut conclusions about relationships between working in

refineries and cancer. A retrospective mortality study sponsored by the American Petroleum Institute that covered 17 U.S. oil refineries and over 20,000 workers was reported

in 1974,86) The study group included every

worker employed in the refineries for at least

one year between January 1, 1962, and December 31, 1971. A 94-percent followup was

obtained. There were 1,165 deaths; 1,145

death certificates were obtained. The standardized mortality ratio (SMR) for all causes of

death among refinery workers was 69.1 compared with the base rate of 100 for the U.S.

male population. The lower death rate among

refinery workers was attributed to the

“healthy worker effect;” i.e., employed workers are healthier on the average than the general population. Respiratory cancer increased with increasing exposure to aromatic HC, but was still lower than found in

the general population (SMR of 79.9).

On the other hand, two epidemiological

studies published by Canadian investigators

showed an increased cancer risk for refinery

workers. In a group of 15,032 male employees

who worked for the Imperial Oil Co. between

1964 and 1973, there were 1,511 deaths.

Eighty percent were ascribed to circulatory

system disease and to malignant abnormal

growths (neoplasm). Mortality from all malignant neoplasms in the exposed group was

greater than in the nonexposed group. Cancers of the digestive and the respiratory systems increased with duration of employment. 87

A further study examined 1,205 men who

had been employed for over 5 years by Shell

Oil Canada in East Montreal,88{ Their mortality rate was compared with death rates for

the Province of Quebec. The study group was

relatively small, and only 108 deaths were

observed. An increased incidence of cancer

of the digestive system (SMR of 117) was not

statistically significant, and there was no

evidence of excessive lung cancer (SMR of

35.4). An excess of brain cancer was found

among those who had been exposed less than

20 years, but it caused only three of the

deaths.

Societal Hazards

Air pollutants include particulate, gases,

and trace-metal vapors. Particulate which

contain absorbed PAH can be carcinogenic.

The sulfur and nitrogen-containing emissions

are respiratory irritants. Among the sulfurcontaining pollutants, the effects of acid

sulfates, sulfuric acid, and S02 dissolved in

aerosols are the best documented. All three

are irritants and can make breathing difficult. In addition, some epidemiological evidence relates chronic bronchitis and respiratory diseases to SO2 and to particulate con-
. — —— —— ————. .

322 ● An Assessment of Oil Shale Technologies

centrations in the air. Oxides of sulfur and nitrogen, transported from industrial areas,

may cause acidic rainfall that may reduce the

productivity of forest vegetation and kill fish

by increasing the acidity of lakes and

streams. NOX oxides can react with HC in the

atmosphere to produce O3

, photochemical

smog, and acid rain. Airborne NH3 may cause

headaches, sore throats, eye irritations,

coughing, and nausea in humans.

Among the trace elements that may be

emitted, mercury, lead, cadmium, arsenic,

and selenium are considered to be potential

air and water pollutants. Arsenic is a carcinogen, which when inhaled or ingested in

large amounts, may also cause peripheral

vascular disease and neuropathy. * Mercury

is a special problem because its vapors can

pollute the air and earth many miles from the

plantsite. It can also contaminate surface

streams and ground water aquifers. It can

enter the food chain through the actions of

micro-organisms, and can also pose a risk of

irreversible neurological damage to humans

who eat fish that have been contaminated by

mercury in streams.

Leachates from aboveground disposal

areas and burned-out in situ retorts also pose

potential problems. PAHs, salts, and metals

may dissolve in surface streams and ground

water and infiltrate public drinking water

supplies. Water-soluble salts in spent shale

contain as much as 40 percent of the total

benzene-soluble organic matter. All of these

materials can be dissolved in water and dispersed through soils. The exact nature of the

threat posed by these materials to human

health is unknown since, for example, PAHs

are found throughout nature. However, the

PAH content of spent shale leachates (up to

100 to 1,000 times higher than is found in normal ground or surface water) is a matter for

concern. Fluoride, if released in excessive

amounts in contaminated water, may cause

fluorosis (reduced bone strength and debilitation) and mottle tooth enamel.

*Neuropathy refers to pathological changes in the

peripheral nervous system.

The severity of these hazards will depend

on many factors. Many of the risks could be

very small if they are anticipated, and if appropriate control strategies are designed and

followed. If caution is not employed, or if

there are catastrophic failures in the control

systems during or after plant operation, damage could be severe and long lasting.

Summary of Hazards and Their Severity

The safety and health hazards that might

be associated with oil shale mining, retorting,

and refining are identified in figure 62. They

are ranked according to their known potential to cause injury or death. As shown, mining has the highest potential for accidents,

due to risks from rockfalls, explosions, moving equipment, and general working conditions. There were two fatalities during the

mining of over 2 million tons of shale and the

production of over 500,000 bbl of shale oil.

The accident rate has been one-fifth that for

all mining, and much lower than that for coal

mining. However, this record was achieved in

small-scale experimental mines that employed, for the most part, experienced hardrock miners. Whether safety risks will increase or decrease as mining activities are

expanded cannot be predicted. Risks might

increase as the work force expands to include

inexperienced miners and as large, rapidly

moving mining equipment is used. On the

other hand, the large mines proposed for oil

shale plants may reduce risks because of the

additional room in which to maneuver machines.

Fires and explosions are also identified as

a hazard in mining. Although no severe fires

have occurred to date, laboratory studies indicate that airborne shale dust can propagate

a methane explosion. Methane has been

found in low concentrations in some oil shale

deposits, especially those in the saline zone of

the Piceance basin. Oil shale dust is, however, far less explosive than coal dust.

Dust is a major health hazard. Its effect on

the respiratory system is well-known. Excessive noise is also a recognized hazard. Cancer
Ch. 8–Environmental Considerations ● 323

Figure 62.—Summary of Occupational Hazards Associated With Oil Shale Development

Relative Ranking

Occupational Risks Potential Effect Mining

Accidents Injury or death

Retorting Refining

A

explosions

Fires and Injury or death mnn

Hearing loss or

neurological damage

Lung disease

Noise

Dus t

Dus t Dermatitis

v

Chemical

Exposur e

Cancer

I I

Chemical

Exposur e

Dermatitis [ 1 I

I I I

Chemical

Exposur e

Poisoning

4.

Chemical

Exposur e

Irritant gases

KEY:

-Higher level of risk

D Medium level of nsk

a Lower level of nsk

SOURCE Off Ice of Technology Assessment
324 An Assessment of Oil Shale Technologies

from oil shale mining has not been identified

as a major hazard. Although the carcinogenicity of oil shale dusts and crude shale oil

has been demonstrated by some invesigators,

insufficient information and the conflicting

results of other studies prevent a determination of the severity of the risk. However, the

incidence of diseases in other industries indicates that exposure to these materials

could be hazardous. Worker health should be

carefully monitored if health damage is to be

avoided, and prevention techniques improved, as the oil shale industry develops.

Retorting is regarded as having medium

risks in all areas. This ranking primarily

reflects the low level of knowledge about

retorting and its health and safety effects.

However, the large variety of substances that

will be encountered in retorting (from raw

shale dust to trace-element emissions) may

pose as yet undetected health hazards. Of

special concern is the possibility of carcinogens in shale oil and its derivatives.

Possible synergisms in MIS operations (which

combine mining with retorting) could increase the level of risk.

In contrast, shale oil refining is regarded

as posing no special hazards in many areas

and only moderate risks in the others. This is

because most of the problems that will be

associated with shale oil processing should

be similar to those experienced in conventional petroleum refining.

Federal Laws, Standards,

and Regulations

This section discusses the Federal laws

and standards applicable to oil shale occupational health and safety, and some aspects of

environmental health. Other laws which govern specific impacts on air, water, and land

are discussed elsewhere in this chapter.

Occupational Safety and Health Act of 1970

This Act was passed to assure every working person “safe and healthful working conditions;” it established the Occupational Safety

and Health Administration (OSHA) under the

Department of Labor. Most OSHA standards

promulgated under the Act pertain to safety,

e.g., walking and working surfaces, fire protection, and personal protective equipment.

In addition, health standards have been promulgated to limit worker exposure to hazardous chemicals and physical hazards, such as

noise and crystalline silica.

OSHA recently published a policy for the

identification, classification, and regulation

of toxic substances posing occupational carcinogenic risks. Under this policy, a substance shown to cause cancer in two animal

studies can be classified as a “category I“

carcinogen and regulated to control worker

exposure to the lowest feasible levels.

Whether any two of the positive carcinogenicity results mentioned in table 66 are sufficient to cause a category I classification

awaits NIOSH review.

The Federal Mine Safety and Health

Amendments of 1977 (FMSHA)

These amendments apply to all metal and

nonmetal mines. They prescribe health and

safety standards “for the purpose of the protection of life, the promotion of health and

safety, and the prevention of accidents. ”

FMSHA established the Mine Safety and

Health Administration (MSHA) in the Department of Labor, and directed the Secretary of

Labor to develop, promulgate, revise, and enforce health and safety standards for workers engaged in underground and surface mineral mining, related operations, and preparation and milling. In addition, each mine operator is to have a mandatory health and safety

training program. FMSHA also authorized

the Secretary of Labor to require frequent inspections and investigations of mines: at least

four times a year in the case of underground

mines, and at least twice a year in surface

mines. Records of mine accidents and exposures to toxic substances are to be maintained by mine operators.

Section 101(a) of FMSHA requires that

standards on toxic material or harmful physi-
Ch. 8–Environmental Considerations ● 325

cal agents be set to “most adequately assure

. . . (on the basis of the best available

evidence) that no miner will suffer material

impairment of health or functional capacity

(even if such miner has regular exposure to

the hazards dealt with by such standard for

the period of his working life). ” NIOSH has

the responsibility to determine when the material or agents are toxic at the concentrations found in the mine.

Warning labels, protective equipment, and

control procedures are to be employed “to

assure the maximum protection of miners. ”

Medical examinations and tests, where appropriate, are to be provided at the operator’s expense to determine whether a miner’s

health is adversely affected by exposures.

Memorandum of Understanding Between

OSHA and MSHA

Because of the overlapping jurisdiction between OSHA and MSHA, an interagency

agreement was executed on March 29, 1979,

to allocate the responsibilities for mining

safety between the two agencies. The agreement established that as a general policy, unsafe and unhealthful working conditions on

minesites and in milling operations would

come under the jurisdiction of MSHA. Where

these do not apply, or where no MSHA standards exist for particular working conditions,

OSHA and its regulations would apply.

Where uncertainties arise about jurisdiction,

the appropriate MSHA District Manager and

OSHA Regional Administrator (or the respective State designees in those States with approved mine-safety plans) shall attempt to

resolve the matter. If they cannot do so, the

issue will be referred to the national offices

of the two agencies. If the issue cannot be

resolved at that level, it will be referred to the

Secretary of Labor for a final ruling.

The Toxic Substances Control Act

of 1976 (TSCA)

TSCA covers the manufacturing, processing, distribution, use, and disposal of chemical substances in commerce. However, it

should be noted that if specific operations are

regulated by other laws (e.g., Clean Air Act,

Clean Water Act) their authority would probably take precedence over regulations promulgated under TSCA. TSCA regulations

would be promulgated only when regulations

under the other Acts failed to remove a hazard. Also, chemicals that are not sold in commerce are considered “R&D substances” and

are exempt from some of the requirements

under the Act.

Under TSCA, EPA must require industry to

give notice 90 days prior to beginning the

manufacture of any new substance that is not

listed on EPA’s Inventory of Existing Chemicals. EPA can also require industry to test

the toxicity of chemicals already in commerce

that may pose an unreasonable risk to human

health or the environment. Shale oil and its

refined products are included in the inventory list and therefore are not subject to premarket regulations, but testing can be required under other sections of TSCA if the

Administrator of EPA determines such substances may pose an “unreasonable risk” to

health or the environment.

Control and Mitigation Methods

Some of the oil shale’s health and safety

hazards can be reduced by using the pollution

control technologies described elsewhere in

this chapter. Others will require specific industrial hygiene controls. The three major

control methods are:

●

●

●

worker training programs, including an

intensive training program for new workers and refresher courses for workers

throughout their careers;

the design and maintenance of safe

working environments; and

health monitoring programs, including

examinations and recordkeeping.

Initial training programs and refresher

courses are required by OSHA and MSHA.

These agencies also promulgate standards

for working environments. Health inspections

are sometimes included in OSHA/MSHA routine inspections, and special health inspec-
326 ● An Assessment of Oil Shale Technologies

tions can be made if the agencies determine

that a serious health hazard exists. At present, exchange of worker-health information

among companies is not required, although

some companies, especially in the coal mining

industry, have organized such programs to

provide data regarding occurrences of black

lung among miners who change jobs within

the industry.

Summary of Issues and R&D Needs

Issues

The effect of the scale of operation of future oil shale facilities on worker safety is

still unknown. As indicated previously, the oil

shale industry to date has a good safety record. It is not clear whether or not this record

can be maintained in large facilities and in a

large industry.

The protection of worker health and safety

in an industry that is developing with great

speed is also a major concern. To prevent undue risks, it is important that the health hazards of oil shale and its related materials be

identified, and that appropriate measures be

employed for their control.

R&D Needs

Research is needed in the following areas

in order to improve the understanding of the

potential effects of oil shale development on

the workers and on the public:

●

●

additional data gathering and analysis

are needed on the health effects of particulate generated during oil shale mining and processing. Studies should include: a) identification of absorbed

PAHs; b) determination of particulate

size distributions; c) evaluation of the

risk of fibrogenicity and carcinogenicity;

d) ranking of the unit operations in terms

of their degree of risk; and e) determination of their health effects on nearby

communities with respect to, for example, chronic bronchitis;

characterization of worker exposure to

PAHs, other chemical hazards, and

●

●

●

●

A

physical agents such as ionizing radiation, heat, and noise stress;

evaluation of devices for controlling

worker exposure, such as hermetic

seals, ventilation equipment, and personal protective equipment;

environmental monitoring to determine

ambient levels of PAHs, trace elements,

and other potentially harmful substances;

determination of the pathways followed

by PAHs, salts, toxic trace elements, and

other substances; and

additional controlled animal experiments to determine the toxicity, mutagenicity, and other characteristics of the

raw materials and products encountered in oil shale processing, and evaluation of their synergistic interrelationships.

mechanism that would aid in all of these

studies, and in other ones that evolve as the

industry is created, would be an oil shale

health registry or central repository for the

health records of oil shale workers. These

data would aid in the statistical work needed

to detect extraordinary health trends among

the workers. These, in turn, could be related

to working conditions and used to improve

preventive and protective measures.

Current R&D Programs

The following is a partial listing of the

health and safety R&D projects now underway both in the private sector and by Government agencies.

●

●

●

Tosco is studying the fire and explosion

potential of oil shale mining and processing.

The American Petroleum Institute is

studying the effects of oil shale on fetuses by exposing pregnant rats to raw

and spent shale dust and shale oil.

EPA is performing or contracting work

through 10 of its laboratories to support

the regulatory goals of the agency and to

ensure that an oil shale industry will be

developed in an environmentally accept-
Ch 8–Environmental Considerations ● 327

able manner. The EPA Cincinnati laboratory is studying the handling of raw

shale and the disposal of spent shale. Air

pollution, wastewater characteristics,

and water treatment methods are also

being studied and evaluated. The Las

Vegas laboratory is attempting to design

and implement an optimal wastewater

treatment system. The Athens, Ga., laboratory is characterizing retort effluents

and developing instrumentation and control systems. Biological and health effects studies are being conducted at the

Gulf Breeze and Duluth laboratories;

these are designed to determine pathways by which HC enters the food chain,

to characterize the aquatic life in the oil

shale region before oil shale development occurs, and to determine the carcinogenic, mutagenic, and fetal effects

of oil shale and its derivatives and

wastes. EPA is also preparing pollution

control guidance documents for the oil

shale industry.

 DOE is conducting source characterization studies to determine emissions properties and their health effects. Included

is an extensive program for sampling retort liquids, solid products, and wastes.

Streams to be sampled include mine vent

gases, mine air, retort water, raw and

retorted shale, process water, and particulate, Biological testing will be conducted to include short- and long-term

animal exposure tests and medical and

epidemiological studies of oil shale workers.

● The U.S. Department of Agriculture is

sponsoring work related to the social

consequences of oil shale development

and the revegetation of solid waste disposal areas.

● The National Science Foundation is

sponsoring projects to characterize the

contaminants in spent shale and to develop techniques for managing them.

Policy Considerations

The major issue surrounding the health

and safety aspects of oil shale development is

the paucity of information on the nature and

severity of the health effects of oil shale, its

derivatives, waste products, and emissions.

The effect of the scale of operation of oil

shale facilities on worker safety is also unknown. Policy options for addressing these

issues follow,

Inadequate Information

Additional study is needed to determine the

effects on human health of the various chemical substances and particulate encountered

during the mining and processing of oil shale

and its products and wastes. Such information would be useful in identifying and mitigating long-term health effects on workers

and the public. It would also be useful in setting new standards for worker health and

safety. Options for increasing the amount of

information include expanding existing R&D

programs; coordinating R&D work by Federal

agencies; increasing appropriations to agencies to accelerate their health effects studies:

and passing new legislation specifically calling for study of the health and safety aspects

of oil shale development. Methods for implementing these options are similar to those described in the air quality section of this

chapter.

Health Surveillance

Collection and maintenance of oil shale

workers’ health records in a health registry

would facilitate hazard identification and

planning to reduce risks. The registry might

be located in a regional medical center, with

or without Federal agency input. Funding

could be provided by Government, labor, or

the oil shale developers, or by a cost-sharing

arrangement between these groups. The reg-
 ...

328 ● An Assessment of Oil Shale Technologies

istry location could be the focus of regular

meetings to exchange health and safety information and to disseminate basic scientific

findings that apply to the oil shale industry.

Exposure Standards

As information about chemical health hazards is developed and analyzed, NIOSH and

MSHA should determine whether exposure

standards are necessary to protect worker

health and safety. In addition, sampling methods should he in place to monitor exposures.

Worker-Education Campaigns

Worker education is already a part of the

mining industry. Information about newly

identified risks should be conveyed to workers as soon as possible.

Land Reclamation

Introduction

An oil shale industry will use land for access to sites, for facilities, for mining, for retorting, for oil upgrading, and for waste disposal. The extent to which development will

affect the land on and near a given tract will

be determined by the location of the tract; the

scale, type, and combination of mining and

processing technologies used; and the duration of the operations. Comparatively little

land will be disturbed by the retorts and upgrading facilities themselves, but much larger

areas will be disrupted by mining activities

and waste disposal operations, particularly if

the deposits are developed by open pit mining

in conjunction with aboveground retorting,

which produces retorted shale as a process

waste.

It has been estimated that a l-million-bbl/d

industry using aboveground retorts would

process approximately 600 million tons of

raw oil shale per year, and would require the

disposal of approximately 10 billion ft3 

of

compacted spent shale. Less of the surface

would be disturbed by in situ retorting, although the surface would nevertheless be disturbed by drill pads. However, the disturbance would be different and less drastic than

from an open pit operation. At the same time,

the amount of subsurface disturbance for a

given level of oil production would be increased because, although with an in situ

process relatively little oil shale is mined, oil

recovery rates are lower and some leaner oil

shales would be retorted. Subsurface disruption from underground mining and in situ development could affect aboveground conditions through subsidence in the mined-out

areas. But this might not happen until long

after operations at the site have ceased.

Oil shale plants must be built to comply

with the laws and regulations that govern

land reclamation and waste disposal, Nevertheless, there will still be effects on the topography (ultimately the terrain could be modified to a landscape unlike the original) and on

wildlife (through changes in forage plants

and habitats). In addition, unless appropriate

control methods are developed and applied,

as required by law, the large quantities of

raw and retorted shale could pollute the air

with fugitive dust and the water with both

runoff and the effluent that has percolated

through raw shale storage piles and waste

disposal areas. Solid wastes such as catalysts, water treatment sludges, and refinery

coke, will be produced in relatively small

amounts, but will contain toxic components

that could degrade water quality unless properly controlled. Similar care will be needed to

remove, store, dispose, and revegetate the

large amounts of overburden that will be

handled in open pit mining operations.

Several avoidance and mitigation strategies have been proposed to minimize the overall land impacts of oil shale development. Oil

shale plants, access corridors, and disposal

areas could be sited to avoid esthetic deterioration and improve the feasibility of land

reclamation and revegetation programs; and
Ch 8–Environmental Considerations ● 329

mining and in situ retorting could be designed

to decrease surface subsidence or reduce its

rate. In addition, most development plans

propose to protect existing wildlife habitats

and migration routes, where possible, and to

enhance the characteristics of adjacent

areas to promote wildlife readjustment. Reclamation and revegetation techniques have

been developed and tested on a small scale

over limited periods of time for aboveground

solid waste disposal, and backfilling mines

has been suggested to reduce the quantity of

solid material that must be disposed of on the

surface.

As with air and water control methods, a

number of uncertainties surround the feasibility of methods for minimizing land disturbance and its effects on wildlife. At issue are

the feasibility of land restoration and revegetation techniques, and the adequacy of strategies to control the leaching of solid waste

and raw shale piles. The methods for disposing of solid wastes by backfilling mines and

for controlling leachates from solid waste disposal piles and underground retorts were discussed previously in the water quality section. In this section the reclamation and revegetation of processed shales on the surface

are examined.

Reasons for Reclamation

The primary purpose of reclaiming the solid wastes is to reduce their detrimental effects. These include: changes in the landscape, the disruption of existing land uses,

the loss of the biological productivity on a

given land surface, and the degradation of air

and water quality by erosion and leaching. In

addition, secondary impacts such as fugitive

dust would affect not only the immediate area

but adjacent areas as well.

Regulations Governing Land Reclamation

In order to ensure that mining operations

will incorporate reclamation concepts and

minimize adverse effects, legislation has been

passed and regulations have been promulgated governing oil shale mining, processing,

and waste disposal,

Each State in the oil shale region has reclamation laws that apply to all mining operations. USGS has regulations that control oil

shale operations only on Federal lands. In addition, the Department of the Interior (DOI)

established environmental stipulations governing lands under the Prototype Oil Shale

Leasing Program that include additional specific reclamation standards. The Surface

Mining Control and Reclamation Act

(SMCRA), passed in 1977, provides a system

of comprehensive planning and decisionmaking needed to manage land disturbed by development. However, the Act applies only to

coal, and the detailed reclamation standards

promulgated under it may not be appropriate

to oil shale in all cases. However, it provides

a guide to measure the strictness of other

laws applicable to oil shale for matters that

are not specific to coal.

The Colorado Mined Land Reclamation Act

is administered by a board and division within the Department of Natural Resources. It

requires permits for each mine operation,

stipulates application procedures and criteria for permit approval, requires surety (e.g.,

performance bonds), and sets procedures for

enforcement and administration. The Act’s

performance standards are similar in concept to those established by the Federal Coal

Act. They are not, however, as detailed since

they must apply to all minerals from oil shale

to sand and gravel (except for coal, which has

been amended to correspond to the new Federal requirements); and, in some cases, they

are not so strict. For example, an operator

may choose the postmining use of affected

land; whereas, the Federal standard requires

approval of such use by the permitting authority according to strict criteria. Also, an

operator may substitute other lands to be revegetated if toxic or acid-forming materials

will prevent their successful vegetation, and

the mitigation of such conditions is not feasible. Mining would probably be prohibited

under similar conditions by Federal standards, if they were applicable to oil shale.

63-898 L - 80 - 22
330 ● An Assessment of Oil Shale Technologies

The Utah Mined Land Reclamation Act is

administered by the Board of Oil, Gas, and

Mining. It provides for various powers of the

board, administrative procedures, surety,

and enforcement. However, the Utah law only

establishes general reclamation goals and

does not set detailed environmental performance standards as do SMCRA and the Colorado law. These goals include minimizing environmental degradation or “future hazards to

public safety and welfare” and establishing

“a stable ecological condition comparable

with . . . land uses. ” They are open to broad

discretionary interpretation by the Oil, Gas,

and Mining Board.

The Federal standards that do apply to oil

shale are limited to Federal lands;* they do

not govern operations on private land, and

are in no way comparable to the detailed

standards that apply to coal under SMCRA.

For example, 30 CFR 231.4 establishes very

general goals requiring reclamation to

“avoid, minimize or repair” environmental

damage. Specific details must be set by sitespecific leases. It is not applicable to true in

situ oil shale methods using boreholes and

wells, thus will not govern spent shale leaching for this technology. Part 23 of title 43

authorizes, but does not require, the Bureau

of Land Management (BLM) District Managers to formulate reclamation requirements

and USGS Mining Supervisors to set standards for mine plans.

More important are specific lease stipulations. Environmental stipulations have been

included in the Prototype Oil Shale Leases

governing operations on current Federal

lease tracts. The reclamation and revegetation performance standards that are included

take into account the experimental nature of

the program. For example, lessees are given

10 years to demonstrate a necessary revegetation technology; however, operations must

cease if such technology is not developed. The

lease and the environmental stipulations are

administered under the broad discretion of

the Area Oil Shale Supervisor, who has re-

*About 70 percent of the oil shale land, containing about 80

percent of the resources, is federally owned.

quired “best available control technologies”

to minimize all environmental damage.

In summary, while reclamation is required

under State laws, there are no performance

standards specific to oil shale. Regulations

vary and are not so strict as the general requirements of the Federal coal law. There are

additional requirements that pertain to Federal leases.

Reclamation Approaches

Several reclamation approaches can be

used to reduce the deleterious effects asso

ciated with the disposal of spent oil shale.

These include returning surface wastes to

mined-out areas; the chemical, physical, or

vegetative stabilization of processed shale;

and combinations of these approaches.

Reducing Surface Wastes

Mine backfilling was discussed in the section on water quality. As was indicated, the

disposal of wastes underground will be more

expensive than surface disposal, but there

could be less surface subsidence caused by

the collapse of overburden materials above

the mined-out rooms.

Chemical or Physical Stabilization

One approach that can be used to reduce

erosion on disposal sites is to use chemical or

physical methods to stabilize the processed

shale. Chemical stabilization may be short

term—from a few months to a couple of

years—or longer term. Short-term methods

consist of spraying biodegradable chemicals

on the surface; these reduce wind and water

erosion by binding particles together. Such

chemicals have been used along with revegetation to achieve temporary stability. 89 T h e

chemicals do not appear to inhibit seed germination; however, they are expensive and, at

best, temporary.

Longer term stabilization consists of adding materials such as emulsified asphalt or

processed limestone to induce chemical reac-
Ch. 8–Environmental Considerations ● 331

tions that harden the mixtures. Hardening

can be accomplished by wetting of shales

processed at high temperatures, followed by

compaction. The hardened products have the

advantages of relatively high resistance to

erosion and reduced leaching of soluble salts

into the ground water. Their disadvantages

are that they are esthetically unattractive

and cannot support vegetation unless covered

by a suitable plant growth medium. The longterm effects of chemical stabilization are at

present unknown.

Erosion can be reduced physically by covering the processed shale with a layer of

rocky material. Like the chemical approaches, physical methods inhibit the establishment of a vegetative cover, are not esthetically pleasing, and restrict the future uses of

the land.

Vegetative Stabilization

Vegetation offers the most esthetically

pleasing and productive means of stabilizing

waste materials. It also allows for multiple

land use. In addition, vegetation theoretically

offers a means of continually adapting to the

changing environmental conditions that are

likely to occur on the disposal site over time.

Vegetation will also reduce the overland

flow of water and sedimentation during intense storms by increasing the permeability

of the soil. This will increase the infiltration

of water, thus reducing surface water and

pollution and flood hazards. Vegetative cover

Photo credit OTA staff

A variety of plant life will be required for revegetation of spent shale areas
332 ● An Assessment of Oil Shale Technologies

will tend to ameliorate micro-climatic conditions and also reduce wind erosion and extremes in soil temperatures.

Combinations of Stabilization Methods

Perhaps the most effective means of stabilizing waste piles will be combinations of

approaches such as hardening the processed

shales by chemical means and then establishing vegetation on a friable soilcover atop the

solidified wastes. The vegetative stabilization

of soil-covered spent shale appears to be the

preferred reclamation approach because the

chemical and physical properties of processed shale make it much less amenable to

supporting plant growth that resembles the

diversity and density of the present natural

vegetation ecosystems.

The Physical and Chemical

Characteristics of Processed Shale

The physical and chemical characteristics

of the processed shale are determined by the

source of the raw shale; its particle size after

crushing; and the retorting parameters such

as temperature, flow rate, and carbonate decomposition, which vary with different retorting processes.

The characteristics of processed shales

that make them undesirable as a plant

growth media are:

● small particle size (texture), which encourages erosion; and compaction or cementation, which results in low permeability to water and poor root penetration;

● high pH (i. e., high alkalinity), which discourages plant growth by making essential nutrients insoluble and therefore unavailable;

● high quantities of soluble salts, including

elements toxic to plant growth that inhibit water and nutrient uptake; and

● the dark colors of some spent shales,

which absorb solar radiation thus producing high temperatures that inhibit

seed germination and dry the soi l

through evapotranspiration.

The characteristics of spent shale from

several processes are summarized in table 68

and discussed below.

Texture

Raw shale that is finely crushed, as in the

TOSCO II process, produces a fine silty spent

shale that is highly susceptible to erosion.

However, if the shale is coarsely crushed as

in the gas combustion processes, a coarsetextured spent shale is produced that is less

susceptible to erosion. The resistance to wetTable 68.–The Chemical and Physical Properties of Processed Shales

Processing

Process temperature Color Texture a

Salinity b

pH

TOSCO II ., . . . ., . . . . LOW Black Fine 18 9.1

Gas Combustion . . ., ., ., . . High Gray Coarse 14 8.7

Paraho

Directly heated. ., ., ., ., High Gray Coarse 7 12,2

Indirectly heated . . . . ., . . . Low Black Coarse 10 12,3

Union

“A” retort . . . . . . . . . High Gray Coarse 3-4 11,4

‘‘B’ retort ., ... ., Low Black Coarse 13 8.5

Lurgl-Ruhrgas ., ., ., . . Low/high Gray Fine/coarse 3-7 11-12

aFl”~.[~Xlu~@ processed Shales are predornlrranlly smaller Ihiln 2 mm while coarse-[ extured processed shales are r)redomlnantly larger than 2 Inrn

bThe electrical ~OfrdUCtlVltY (rnrnhO/Crn) of a safuraled extract prepared frOrn spent shale Partlclw sfnaller than p mm

SOURCE Planf Resources Inshwie The free/arrrallorI oJProcessed O// Shale, prepared for OTA, January 1980
Ch 8–Environmental Considerations ● 333

ting of the spent shale originally produced in

the TOSCO process90 91 has been overcome by

introducing steam in the last step of the process. Spent shales produced by retorting at

higher temperatures have not been reported

as resistant to wetting,

The capacity of spent shales to retain

water is moderate. Infiltration rates on finetextured spent shale (TOSCO II) range from

near zero to as high as 3 to 4 cm/hr.92 93 Those

for uncompacted coarse-textured spent shale

are higher.94 Rates of from 2 to 4 cm/hr will be

sufficient for the surface runoff to be absorbed from most low-intensity storms but not

from high-intensity ones that occasionally occur during the summer. Moistening and compacting the spent shales may achieve close to

zero infiltration rates which could be important for reducing the leaching of salts into the

ground water. Compaction is more desirable

for spent shales deep in the pile, beyond the

plant rooting zone; uncompacted materials

may be preferable near the surface directly

under the topsoil layer.

Erosion Control

Because small particle size encourages

erosion, erosion control is needed to prevent

sediments and toxic elements from entering

the aquatic ecosystems downstream, or the

increase of dust in the air. Additionally, erosion removes the surface layers that encourage plant growth, which take time to develop.

The steepness of the slopes, their length,

the drainage provided, control structures, the

density of vegetation on the slopes, and the

types of spoils and soil materials on the site

will affect the extent of erosion. Mulching,

surface manipulation, and the timing of topsoil placement, followed by the immediate establishment of vegetation, will usually reduce

erosion rates.95 Flatter or shorter slopes will

also aid in erosion control. The recommended

design slope of 4: I (horizontal: vertical) with

20-ft benches every 50 ft of vertical rise is

considered prudent and necessary. A slope of

3:1 was found to be the maximum allowable

for slope stability.”

Water diversion and sediment and drainage catchments are proposed to collect materials washing off site in order to prevent their

entering the aquatic ecosystem. It is likely

that sediment basins will require long-term

maintenance to prevent their filling up and

releasing toxic substances.

Furrowing, pitting, and gouging are other

useful methods of surface manipulation. Shallow furrowing on the contour cuts down on

erosion losses. Pitting and gouging not only

control erosion but also act as a moisture collector.’” They are particularly useful in dry

areas and where vegetation is dependent on

snowmelt. A variation of gouging is accomplished by using a land imprinting machine.’”

On soil-covered processed shales, the depth

of the depressions will be determined by the

thickness of the soil cover necessary to prevent the processed shale from being exposed.

Mulches of various types have been used

both to establish vegetation and to reduce the

temperature of the soil surface. 99 Hydromulch, applied at a rate of 1,500 lb/acre is

one that is preferred in some studies. 10’) However, it is expensive and, in some cases, has

been reported to provide little beneficial effect on already established stands. ’()’ A

cheaper natural mulch applied at a rate of

3,000 lb/acre,102 such as native hay or straw,

is more likely to be used, but it must be taken

from a certified weed-free field to prevent introducing weedy species. It is uncertain that

sufficient mulch will be available, especially

weed-free hay, for an oil shale industry of 1

million bbl/d within 10 years.

Straw or hay mulches often need to be stabilized by the addition of emulsified asphalt

(300 gal/acre), ’03 or by crimping into the soil.

Rock mulches have been found to be superior

to barley straw with respect to plant survival

and growth. 104 Excelsior type materials, are

also very effective, but they are costly and attract rodents. ’05
. .

334 ● An Assessment of Oil Shale Technologies

Cementation

Processed shales retorted at high temperatures and then moistened harden within

about 3 days in a reaction similar to that

which takes place in cement. 106 The product of

spent shale cementation is still susceptible to

weathering, and the reaction generally takes

place deeper in the waste pile where the

process is accelerated by compaction, heat,

and high pressure. If shale hardened by this

process were to be exposed by erosion, it

might prove to be impenetrable to moisture

and plant roots.

Alkalinity

Processed shales retorted at temperatures

of about 500

0 C (900

0 F) are less alkaline (pHs

ranging from 8 to 9*), than those retorted at

750° to 800° C (1,400° to 1,500° F) (pHs of 11

to 12). In general, the higher the alkinity of its

leachates, the lower the concentrations of

soluble salts in the processed shale. At higher

pHs many plant nutrients are insoluble, and

plants will generally not grow in a strongly alkaline soil medium.

If processed shales are to be used directly

as a growth medium, their alkalinity must be

reduced. This can be done by leaching following deposition and proper compaction, or by

adding costly acids or acid-formers. 107 Exposure to the atmosphere over a period of several months to several years will reduce it naturally.

Nutrient Deficiencies

Spent shales have been shown to be highly

deficient in the forms of nitrogen and phosphorous available to plants. 108 Therefore nitrogen and phosphorus fertilizers need to be

added. These can be applied at any time of

year but spring fertilization has been recommended to prevent burning and to reduce fertilizing weedy species. 109 It will probably be

necessary to fertilize with nitrogen for several years until the ecosystem begins to fix

and recycle its own nitrogen. 110

*PH is a means of expressing acidily or basicity. It ranges

from 1, highly acidic through 7, neutral, to 14, highly alkaline.

Another means of assisting plants to survive in nutrient-deficient soils is by inoculating them with selected strains of fungi that

produce mycorrhizae. Mycorrhizae are structures that combine the plant root and a fungus to increase the survival and growth of

plants in nutrient-deficient soils by increasing

nutrient uptake and resistance to a variety of

stresses.

Free-living soil microbes are expected to

begin recolonization of the disturbed area.

They will be valuable in fixing nitrogen from

the atmosphere and recycling organic forms.

How soon this will begin is not known. It is

known, however, that wetting and drying

stored topsoil deteriorates the conditions favorable to such microbes. For this reason,

prior to use topsoil should be deeply buried to

prevent the wetting and drying that occurs

near the surface. 11 1

Plant species used to reclaim spent shales

possibly will require inoculation with mycorrhizal fungi to enhance their growth and survival. 112 Colonizing species on disturbed lands

are often nonmycorrhizal. 113 It has also been

found that with increasing soil disturbance or

the addition of processed shale, the ability of

the soil to be infected with mycorrhizal fungi

decreases. The most successful revegetation

species become mychorrhizal only late in

their establishment. There appears to be no

significant effect of the seed mixture, the fer-,

tilizer, the mulch, or irrigation on a soil’s potential for mycorrhizal infection following its

disturbance. 114

Salinity

Because spent shales are often quite salty,

they present major problems for establishing

vegetation, and for the water quality from

surface runoff or drainage through them. 115-120

High concentrations of salt in the soil media

restrict water and nutrient uptake. * These

can only be lowered by leaching with supplemental water.

*Electrical conductivity is a measure of a soil’s salinity. A

conductivity of 4 mmho/cm is considered saline, and above 12

mmho/cm, highly saline.
Ch. 8–Environmental Considerations ● 335

Leaching

Depending on the characteristics of the

spent shales, about 5 acre-ft of water per

acre will be needed for leaching and plant

growth. 122 This is based on a net requirement

of 48 inches of leaching water and an 80-percent irrigation efficiency. The actual supplemental water needed will vary with annual

precipitation, evaluation, and aspect, To ensure adequate infiltration and to prevent erosion, it should be continually applied at low

rates (e. g., 2 to 3 cm/hr) and in a spray form.

Leaching will probably not be uniform over

the entire surface, therefore surface monitoring and additional localized leaching may be

needed.

Toxicity

High concentrations of boron in spent shale

can be toxic to plants. On the other hand, the

elements molybdenum, selenium, arsenic,

and fluorine (also found in shale) are generally not toxic to plants. However, when these

elements are taken up by plants, they can become toxic to grazing animals. Susceptibility

to such toxicity varies among animal species

as well as within a species. It is dependent on

the concentration of the elements within the

plant, the size of the animal, its daily diet, and

its general physiological condition. The conditions that encourage the uptake of these elements by plants, and their resulting toxicity

in animals are complicated and poorly understood. Proper management should help to

avoid or alleviate the problems with livestock.

This can be achieved by restricting livestock

grazing to seasons when the elements are

present at low concentration in the plants, by

varying the mix of plant species to be used in

the grazing areas, and by feeding sequestering supplements to reduce the toxicity of

the elements. The management of wildlife,

however, is very difficult and problems will

persist in this realm.

The dominant soluble ions in spent shale

are sodium and sulfate, with abundant calcium, magnesium, and bicarbonate also present. Of the trace elements identified in processed shale leachates, selenium and arsenic

are not cause for concern, but fluorine,

boron, and molybdenum are more serious. ’z]

Plants grown on processed oil shales and soilcovered processed shales in northwestern

Colorado have been found higher in molybdenum and boron than plants grown in ordinary soil, although their selenium, arsenic,

and fluorine contents were moderate. 124

Excessive Heat

The color of the processed shale reflects

the amount of residual carbon on the retorted

particles. Black and gray processed shales

are produced by low- and high-temperature

processes, respectively. The color influences

the surface temperatures of the plant growth

media which, in turn, affects seed germination and the plant-water relationship. The

dark-colored material warms up earlier in

the spring, inhibits seed germination more,

and creates drier soils than does lighter colored processed shale. Temperatures of up to

78° C (196° F) have been reported for the

TOSCO II material. 125 126 The color can be

modified to a certain extent by the use of surface mulches or a covering of topsoil-like material, which reduces many of the salinity and

alkalinity problems as well as the need for

supplemental water.

Another temperature problem encountered

in the massive disposal of spent shales is that

the processed shales will probably go into the

disposal pile at temperatures in excess of 40”

C (98° F). This will create a heat reservoir, It

is not known how long it will take to cool, If a

spent shale pile is warmer than normal soils

within the area, the site would be drier than

expected because of the increased potential

for evapotranspiration.

Use of Topsoil as a Spent Shale Cover

An alternative to revegetating directly on

spent shale is the establishment of vegetation

on a cover of topsoil or topsoil-like overburden material placed over the spent shale.

Such a soil cover offers several advantages.
— —

336 ● An Assessment of 0il Shale Technologies

Because it does not have the problems of high

salinity and alkalinity, no supplemental water

is required for leaching. The material is a

more suitable medium for plant growth because it has greater water-holding capacity,

more nutrients, and promotes a more intimate

relation with plant roots.

Economics and a possible lack of longevity

are the primary disadvantages of using a soil

cover. Additional costs would be incurred for

segregating suitable materials from those

with undesirable properties, for transporting

and storing materials, and for surfacing over

the spent shales. In time, the natural geological process of erosion may eventually cut

through the soil cover and expose the spent

shale. An artificial soil profile using overburden materials between the topsoil and the

spent shale would greatly reduce, if not eliminate, the problem. With proper management

most erosion should be localized. However,

with improper management such as overgrazing, reductions in vegetative cover could occur that would allow larger areas to be exposed. If erosion were gradual over a few

hundred years, the vegetation possibly would

adapt to the thinning soil cover, and natural

leaching and weathering could render the

spent shale a more suitable growth medium.

Despite these disadvantages, the use of a soil

cover will provide for the more rapid establishment of a vegetative cover that will persist longer than would vegetation established

directly on spent shale.

The depth of the soil cover needed will vary

from site to site, but will generally range from

1 to several ft in thickness. 127 128 Soil surveys

of the Piceance basin indicate that sufficient

soil and soil-like material exists in the disposal sites, particularly those with deep alluvial

deposits, and this should provide adequate

cover material.

The selection of topsoil or topsoil-like overburdens will have to be based on chemical

and physical analyses. This is important because the soil types and their toxicities vary.

The treatment of the soil cover will be similar

to the treatments of soil used for the reclamation of surface-mined coal areas, about which

there is more knowledge.129 Soil surveys of the

basins will also be useful in deciding what

materials to use. It is doubtful that the capillary rise of salts will be a problem unless soils

are continually exposed to saturated conditions. This might happen if improper engineering of the disposal site created seeps or

allowed pending.

Species Selection and Plant Materials

The selection of plant materials to be used

in reclaiming processed shale is determined

by several factors, the most important of

which is species adaptability. Adaptability

(suitability) is intimately tied to the ability of a

plant to complete its entire lifecycle, and to

reproduce itself from year to year over a long

period. The plant’s growth form, drought resistance or tolerance to stress, mineral nutrition requirement, and reproduction characteristics must all be considered. In addition to

being adapted to the growth medium, plants

must also be adapted to local temperatures,

elevation, slope, aspect, and wind conditions.

They should be able to survive the weeds and

animals that may invade the site. Palatability

to livestock and wildlife as well as availability of seed and competition among species

being planted are also important factors.

In addition to the results of actual revegetation test plots, several information sources

and guides are available to assist in the selection of species adapted to conditions likely to

be encountered in oil shale reclamation.130-134

These include the Plant Information Network

computerized data bank located at Colorado

State University. 135

In general, mixtures of various grasses,

forbs, shrubs, and in some cases trees, are

desirable because they offer a greater range

of adaptation. 136 Mixtures may include species adapted to each of the different microclimates, moisture levels, and soils. The results

of using a well-planned mixture can be a fastestablishing, long-term cover that is less vulnerable to pests, disease, drought, and frost.

Recommended mixtures used in test plots

may include both indigenous (native) and in-
Ch. 8–Environmental Considerations ● 337

troduced perennial species. In one study, a

mixture of native and introduced species displayed the highest productivity and allowed

the least amount of invasions by weeds.’}’ Although a mixture of non-native species had a

higher plant density, it also allowed the greatest invasion of weeds. 138 Weeds are undesirable in that most are annuals (complete their

lifecycle in 1 year) dependent on precipitation; they are therefore an unreliable erosion

control. They also compete with the more desirable perennial species (species that persist

for several years) for water and nutrients.

These annuals are expected to disappear

with natural succession over a few years.

Species selection is complex and involves,

in addition to considerations of the species

itself, a tradeoff among many interacting factors. 139 These include: Federal, State, and local reclamation requirements; rehabilitation

and land use objectives; the nature of the site;

the timing of the program; species compatibility; mechanical limitations in planting; seed

and seedling availability; maintenance after

planting; and cost,

Seeds

Planting seed by drilling or broadcasting is

a common way of establishing vegetation in a

reclamation plan. Seed is available commercially from collectors and seed companies. ’40

While many commonly used seeds are available from dealers under contract, procedures

for cultivating wildland plants for seed production have generally not been developed.

Also, certain varieties of the native plant

species may not be available from commercial sources. Until reliable seed production

techniques are developed (which may require

up to 10 years), seeds for propagating native

plants will generally have to be collected

from wildland populations. This may be a

problem for a large oil shale industry, since

seed production from wildland populations

can be unpredictable from year to year; some

native species produce abundant seed crops

only in years when conditions are especially

favorable.

Seeding is best done in late fall or early

spring when soil moisture is high, although

the operation of seeding equipment in the

spring may be hampered by wet soil conditions.’” Seeding rates may vary from 10 to 30

lb of pure live seed per acre depending on

slope and whether the seed is broadcast or

drilled. Drier exposures and broadcast techniques require more seed.

Another problem in propagating plants

from seed is dormancy of seed. Extensive

treatment of the seed may be required in

order to overcome it. For these reasons, vegetative propagation is a necessary alternative

to seed propagation for producing planting

stock of native species.

Containerized Plants

Container-grown plants have been successfully used in several oil shale revegetation

studies. 142-144 They offer several advantages

over seed: 145

they make efficient use of scarce seed or

seeds especially adapted for harsh sites,

plant survival and growth are optimized

by rapid root growth into the surrounding soil,

well-developed plants are generally able

to withstand grazing or other stresses,

and

they can be inoculated with fungi just before seeding to ensure the development

of mycorrhizae.

Container-grown plants can be hardened to

the fluctuating and more extreme environmental conditions they will encounter at the

revegetation site by gradually exposing them

to drier conditions and greater temperature

extremes. The higher cost of container-grown

stocks is offset by their better survival rate. 146

They are recommended for fall or early

spring planting on harsh sites where establishment of seeds may be difficult or impossible due to erratic or low precipitation or

other environmental stresses. Bare root stock

is another alternative, but can only be used

with sufficient soil moisture to ensure good

root penetration into the growth medium. 147
——

338 ● An Assessment of Oil Shale Technologies

Timing of Reclamation

Initiation of revegetation efforts will be

delayed during the first 3 to 10 years of

operation until sufficient waste materials

have been compacted and require further

stabilization. Disposal will likely begin at one

end of a canyon and fill up in strips rather

than gradually filling the entire canyon. This

will allow early stabilization of narrow strips

of land thereby minimizing the size of active

disturbance.

Once revegetation begins, reclamation

needs will gradually increase as portions of

disposal sites are prepared for planting. At

full production, reclamation needs would depend on processing rates and method of disposal. (See table 69.)

Complete filling of canyon disposal sites

may take up to 30 years or more depending on

processing rates and the sites’ disposal capacities. Early revegetation of narrow strips

will permit the evaluation of reclamation

techniques, and allow for any modifications

that may be needed during subsequent revegetation efforts.

Cost of Reclamation

Estimates of average reclamation costs

range from $4,000 to $l0,000/acre depending

on the site conditions and the land use to be

achieved. If disposal is completely on the surface, this represents only about 1.4 to 4.4

cents/bbl of shale oil for a 50,000-bbl/d operation.

Protection of the Reclaimed Site

The reclaimed areas should be protected

by proper management and monitoring to ensure that stability is maintained. Protection

will be needed whenever the vegetation on

the site may be threatened by livestock

(including feral horses), wildlife, invading

weeds, or human activity. This can be done

largely by controlling the degree of use.

The impact of livestock use on the erosion

of revegetated spent shale is unknown; it is

possible that erosion of the finer processed

shales on steep slopes could be substantial.

Erosion from livestock use on soil-covered

shales would be less of a problem. This asTable 69.–Estimates of Reclamation Needs Under Various Levels of Shale Oil Production

Production level (bbl/day)

50,000 50,000 b

100,000 250,000 1,000,000

Required annual disposal area (acres)c

698-79 6 279-318 —

138-159 344-398 1,378-1,592

.

Water requirements

(5 acre-ft/acre) 349-398 acre-ft/yr 140-159 acre-ft/yr 690-795 acre-ft/yr 1,720-1,990 acre-ft/yr 6,890-7,960 acre-ftlyr

Fertilizer

Nitrogen (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr t 1,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yr

Phosphorus (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr 11,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yr

Seed (30 lb pure Iive

seed/acre) 2,094-2,388 lb 837-954 lb 4,140-4,770 lb 10,320-11,940 lb 41,340-47,760 lb

Containerized plants

(300/acre) 20,940-23,880 pits/yr 8,370-9.540 pits/yr 41,400-47,700 pits/yr 103,200-119,400 pits/yr 413,400-477,600 pits/yr

Mulch

Wood fiber ( 1,500

lb/acre) 104,700-119,400 lb/yr 41,850-47,700 lb/yr 207,000-238,500 lb/yr 516,000-597,000 lb/yr 2,067,000-2,388,000 lb/yr

straw (3,000 lb/acre) 209,400-238,800 lb/yr 83,700-95,400 414,000-477,000 lb/yr 1,032,000-1,194,000 lb/yr 4,134,000-4,776,000 lb/yr

w/asphalt binder (300

gal/acre) 20,940-23,880 gal/yr 8,370-9,540 gal/yr 41,400-47,700 gal/yr 103,200-119,400 gal/yr 413,400-477,600 gal/yr

aAll numbers are approximate Actual needs will vary with aridity of the she (elevallon, slope, and aspecl) adapled planl Sr)ecles selected and SJrl arnertdrnenls rewed

bASSumeS bo.percen! Cllsposal In underground rnlne Worklws

CASSUMeS disposal ~lle 451 meters 11 so ft) deep Acreage esflrnales Were based on Po//uIIorI Conlro/ Gu(darrce for 0// S/ra/e Deve/oprnenl Environmental protection Agency. Clnclnnatl Ohio. JUIY 1978 P

3-68

SOURCE Plant Resources lnshtute The Rec/arna//orr ofl?ocessed 0(/ S/ra/e prepared for OTA January 1980
Ch. 8–Environmenlal Considerations ● 339

pect of postmining land use will require careful monitoring. Indirect methods for protecting a site against livestock include adding less

palatable species to the seed mixture, providing salt blocks and permanent water supplies away from the seeded areas, controlling

livestock numbers, herding, fencing, and, if

necessary, repellents. l48

Photo credit OTA staff

Reclaimed sites will have to be protected from wildlife

Protection against wildlife will also be required. This includes large herbivores as well

as small burrowing animals such as pocket

gophers that can be expected to move into the

revegetated area. If not controlled, overutilization of vegetation may occur and toxic

compounds may be brought to the surface by

burrowing animals. 149

Monitoring and subsequent management

must also ensure that refertilization, seeding,

and additional control of erosion or weeds,

are provided if necessary, Similarly, monitoring plant succession, productivity, and utilization should all be included in the reclamation management plan. 150

Review of Selected Research to Date

Research undertaken on the topic of oil

shale reclamation falls into two categories:

●

●

baseline studies that describe the ecological characteristics of the existing environment in the oil shale basins, and

characterization studies of processed

shale and the testing of reclamation

methods.

Data from both types of research are needed

in designing, directing, and assessing past

and future reclamation studies.

Baseline Studies

A general description of the vegetation of

the oil shale basins can be found in chapter 4.

Additional descriptions that contribute to the

baseline data are available for Federal lands

from BLM’s Unit Resource Analysis151 and

Management Framework Plans. 152 More specific vegetation inventories have also been

made for site-specific areas within these

basins such as transmission and pipeline corridors, Land classification systems have also

been developed for the piceance basin,153 154

Eighteen phyto-edaphic units (plant-soil units)

were identified. 155 The description of each

unit provides information on soil, vegetation,

climate, aspect, and landform interpretations

and hazards of land use. A section on reclamation considerations is provided to identify the most hazardous characteristics of the

unit (e. g., the potential for erosion and slumping) that need special attention and care, particularly after disturbance as a result of oil

shale development. Management recommendations and alternatives are supplied to overcome the identified limitations.

Other information on plant community relationships (phytosociology) is currently being

gathered by Colorado State University for the

Piceance basin. This will help the land managers and reclamation specialists to select

the proper species to be used in reclamation.

Such studies are lacking for the basins in

Wyoming and Utah, and few physiological

studies have been conducted with existing

plant species at the proposed disposal sites or

with plant materials to be used in reclamation to determine their tolerance limits to the

various adverse conditions likely to be en-
340 ● An Assessment of 011 Shale Technologies

countered. Little is known about the natural

genetic differences that exist in native plant

communities. These might make the plants

more or less adaptable to adverse environmental conditions encountered in oil shale

reclamation.

Reclamation Studies

Investigations to determine the management needed to produce conditions favorable

to the establishment and growth of plants on

processed shales were initiated by private industry in the mid-1960 ’s. ’5’ These were based

on previous knowledge developed by range

managers, biologists, and numerous arid and

semiarid studies, as well as other baseline information from the oil shale basins.

Where possible, the sites for reclamation

tests have been selected to simulate, as closely as possible, the environmental conditions

to be encountered during the reclamation of

disposal sites used for large-scale production.

Sites have been selected in high- and lowrainfall areas, with various combinations of

slope, aspect, and processed shale materials.

However, most revegetation experiments

have been hampered by a lack of processed

shale. This shortage, coupled with the high

costs of transporting retorted shales to field

sites (in some cases from as far away as

California), have restricted both the size of

the test plots (2 to 5,000 ft2

), and the type of

processed shale evaluated.

To date, field studies using spent oil shales

as plant growth media have centered on the

TOSCO II, Union “A” and “B,” and Paraho

materials.

157-162 These studies show that with

intensive treatments plant growth can be established directly on spent shales, although

use of a soil cover is more successful.

It is difficult to compare the results of

revegetation studies with the various processed shales because the experimental designs varied so widely. Different plant species were used, and fertilizer, mulch, slope,

aspect, and soil cover also varied. Most of the

early (1965 to 1973) revegetation studies for

Colony used spent shale from the TOSCO II

process. 

163 During these studies the basic

chemical data needed to design a reclamation

program were incorporated into greenhouse

and small field plots (100 ft2

). Revegetation

work on other processed shales, all of which

are coarser, had been confined to Union Oil

plots planted in 1966 and Colorado State University plots planted in 1973. In the late

1960’s and early 1970’s, larger field plots

(41,000 ft2

) were built using many of the results

of the earlier experiments, including the effects of soil supplements such as fertilizer

and organic matter.

Since the early 1970’s, studies have been

conducted on disturbed soils without processed shales to determine the establishment

of plant species, microbial activity, and longterm successional trends. These studies were

encouraged by the finding that the revegetation of soil-covered processed shales was

more successful than revegetation directly on

processed shales. This was because the soil

cover does not have the adverse chemical and

physical properties of processed shale that

inhibit plant growth.

Supplemental water has been used to establish plants in most of the processed shale

revegetation studies. The addition of 10 to

13 inches of water during the first growing

season with no subsequent irrigation has

resulted in the establishment of a vegetative stand and the persistence of adapted

species for several years. The salt leaching

requirement (5 acre-ft of water per acre) is in

addition to this supplemental water. Only

limited success in seeding and transplanting

into spent shale without supplementary water has been reported. 164 However, establishment without supplemental water might be

achieved by mulching with straw or hay and

allowing salts to be leached by natural precipitation prior to seeding or planting, although the time period required for this could

be unreasonable. Micro-watersheds consisting of low-level diversion barriers o r

mounded spent shale have also been proposed and initiated to concentrate water for

plant growth.165
Ch. 8–Environmental Considerations ● 341

Several researchers have worked on the

problems of leaching soluble salts from the

processed shales and the surface stability of

several retorted shales including TOSCO

II.

166-172 It appears unlikely that salts will

migrate to the surface by capillary rise in

most areas of low precipitation. Only in areas

where soils were saturated by supplemental

water was there temporary desalinization of

surface layers. When the supplemental water was discontinued, surface salinity began

to drop due to leaching from natural precipitation. From these studies a better understanding has developed of solutions to the

problem of establishing a self-sustaining

vegetative cover.

Several studies are continuing, and a new

successional study has been initiated173 t o

evaluate the long-term feasibility of using

processed shales directly as plant growth

media and the influence of various depths of

soil cover over spent shale. It has been set up

in the Piceance basin to obtain information

related to the reseeding of disturbed areas in

order to reestablish a diverse, functional

ecosystem in as short a time as possible.

Various seed mixtures, ecotypic varieties of

native species, microbial activities, seeding

techniques, fertilizer levels, irrigation, and

mulching treatments are being evaluated. In

addition, the rate and direction of plant succession is being monitored to identify significant trends in vegetation changes, and to determine how these trends are influenced by

the various treatments and practices, 174

Few studies have been conducted on raw

shale. This is because in the past it has been

assumed that most raw shale of commercial

quality will be retorted. Additionally, the raw

oil shales are hard and resilient. When

mined, the shale fractures into coarse fragments that have extremely low water-holding

capacities, which renders them undesirable

growth media. For these reasons, it is likely

that raw shale of noncommercial quality

would be buried deeper in the disposal piles

and not used as a growth medium,

Summary of Issues and R&D Needs

Research to date has shown that with intensive management vegetation can be established directly on processed oil shales. The

primary requirements are the leaching of

high levels of soluble salts with supplemental

water, the addition of nitrogen and phosphorus fertilizers, and the use of adapted

plant species. However, the establishment of

vegetation on spent shales covered with at

least 1 ft of soil is preferred because it is less

susceptible to erosion and does not require as

much supplemental water and fertilizer.

Adapted plant species are required for either

soil-covered or spent shales.

The long-term stability and the self-sustaining character of the vegetation is unknown, but if sufficient topsoil is applied the

results of research on small plots indicates

that short-term stability of a few decades appears likely. Monitoring and subsequent management must ensure that any necessary refertilization, seeding, and erosion and weed

control be provided. The reclamation management plan must also include monitoring

plant succession, productivity utilization, and

the presence of high concentrations of elements toxic to plants and animals.

Whether or not the revegetation of spent

shales is considered successful depends on

the desired land use and the performance

standards applied to measure the success.

For example, the reestablishment of vegetation that reduces erosion and is productive,

self-sustaining, and compatible with surrounding vegetation might be considered successful for livestock but not for wildlife use.

The minimum requirements for vegetation

should be to stabilize the disposal sites so that

the detrimental effects caused by erosion can

be minimized. Where ecologically feasible,

multiple land use of disposal sites should be

encouraged.

Reclamation plans will have to be site specific since environmental conditions vary
342 ● An Assessment of 011 Shale Technologies

from site to site. Proper management will be

required in all instances, if only to protect

plant communities in surrounding areas from

harm. Proper management is even more important in the reclaimed areas. If the vegetative cover were completely lost, the negative effects would increase. The conditions

would not be as severe as those without any

reclamation because they would be reduced

by restrictions in slope, catchment and diversion dams, and other mitigation completed in

the early stages of reclamation.

If revegetation completely failed, productive land use would be severely reduced or

eliminated. It is doubtful that, after once

being reclaimed, conditions would deteriorate to the point of eliminating all vegetation

from a disposal site, although a natural succession of species would occur that would

favor those that had superior adaptability to

the harsh conditions. Weedy or unpalatable

species of less use to livestock and wildlife

would undoubtedly invade the sites.

The types of reclamation needs for a largescale industry (1 million bbl/d) are similar to

those generated for a small industry (50,000

bbl/d), but differ in the amounts of materials

that will be required and the rates at which

they must be supplied. It is probable that

shortages of adapted plant materials and associated support materials (such as mulches

and greenhouse facilities) would occur at the

higher production rates. The problem is compounded by the fact that demands for plant

materials are increasing from other mining

operations such as coal and uranium. The

severity of the shortages will depend on

whether the oil shales are processed in situ or

surface retorted, and whether the processed

shales are disposed of underground or on the

surface. Surface reclamation needs will be

somewhat less demanding with MIS processing or with underground disposal of surfaceretorted shales.

Research on the reclamation of processed

shales is continuing. Areas of major concern

requiring additional study include:

● the selection and propagation of species

especially adapted to conditions likely to

●

●

●

●

●

●

be encountered in the reclamation of the

spent shales. This should include the

identification of ecotypic variations,

seed production by cultivating adapted

wildland plants, and research to determine species performance under abnormal conditions (e.g., drought, salinity,

and high temperatures);

the role and use of soil microbes and

mycorrhizal fungi in soil building and

plant growth. Successful reclamation

will depend on developing a protocol to

select and/or maintain the essential

mycorrhizal fungi in disturbed habitats

or to develop methods to reinoculate

these fungi in habitats where they are

absent;

the plant succession for large areas of a

few hundred acres in size under natural

and disturbed conditions, including the

influence of animals on revegetated surfaces;

the toxicity of elements such as fluorine,

boron, molybdenum, selenium, and arsenic to plants and grazing animals. A program to monitor these elements should

be established on newly reclaimed areas

at least for the first few years;

the probable heat retention within the

disposal pile and its effect on reclamation timing and revegetation;

the rates of erosion on large, reclaimed

areas of a few hundred acres in size. Information is needed on how much water

runs off the area following snowmelt in

the spring and after high-intensity summer storms, including how much sediment and soluble salts will be contained

in the water; and

the viability of vegetation on raw shale,

Policy Options for the Reclamation of

Processed Oil Shales

For Increasing Available Information

More information is desirable on reclamation methods and the selection of proper plant

species for revegetation programs. Options

for obtaining this information include the
Ch. 8–Environmental Considerations 343

evolution of existing R&D programs by the

U.S. Department of Agriculture (USDA), EPA,

and other agencies; the improved coordination of R&D work by these agencies; increasing or redistributing appropriations to accelerate reclamation and revegetation studies;

and the passage of new legislation specifically for evaluating the impacts of land disturbance. Mechanisms are similar to those

discussed in the air quality section of this

chapter.

To Develop Reclamation Guidelines for Oil Shale

SMCRA provides for comprehensive planning and decisionmaking to manage disturbed

land. However, in general, the reclamation

standards promulgated under the act are

only appropriate for coal, but not necessarily

for oil shale. Thus, new reclamation guidelines specifically for oil shale may be desirable, with standards for postmining land uses

that are ecologically and economically feasible and consistent with public goals. If the

Act were amended to encompass oil shale,

Congress could direct that reclamation guidelines be developed by DOI’s Office of Surface

Mining, either alone or in conjunction with

other agencies. Alternatively, Congress could

pass new legislation calling for the preparation and implementation of reclamation

guidelines for oil shale.

To Expand the Production of Seeds and

Plant Materials

While many common seeds are available

from commercial dealers, procedures for cultivating specific wildland plants for seed production have generally not been developed.

Also, seeds of certain native plant species are

not commercially available.

A shortage of seeds could be a problem for

a large oil shale industry. For example, the

USDA’s plant materials centers often require

up to 15 years to identify and develop

adapted species for release to commercial

suppliers or to industry for trial plantings.

Furthermore, the centers intentionally limit

their activities so that they will not compete

with commercial producers. Thus, they have

not developed mass production capabilities,

nor have they adopted some of the more recent propagation technologies (such as micropropagation, cutting, and fungal and bacterial inoculation) that are used commercially. In

order to meet the future demands of a large

oil shale industry, it may be necessary for the

centers to expand their facilities and propagation capabilities. This could be costly in

terms of facilities, technologies, and personnel. Policy mechanisms for expanding cooperative agreements between the centers and

commercial producers need to be developed.

These activities would not only benefit oil

shale, but also most other reclamation and

arid and semiarid revegetation projects as

well.

Permitting

Introduction the States to determine whether a prospective facility is able to meet specific requireDuring the past 10 years an increasingly ments under the law. The operation of an oil

complex permitting system has been devel- shale facility requires well over 100 permits

oped to assist the Federal, State, and local and other regulatory documents from Federgovernments in protecting human health and al, State, and local agencies. They include the

welfare and the environment. Permits are the permits for maintaining the environment and

enforcement tool established by Congress and for protecting the health and safety of work-
344 . An Assessment of 0il Shale Technologies

ers, and in addition, those that would be

needed for any industrial or commercial activity: building code permits, permits for the

use of temporary trailers, sewage disposal

permits, and others. Of these, a few—the major environmental ones—require substantial

commitments of time and resources. The major environmental permits that must be obtained prior to the operation of an oil shale facilit y are:

●

●

●

●

●

●

●

●

●

●

a PSD permit required under the Clean

Air Act;

an Air Contaminant Emissions permit required by the State of Colorado;

a Special Primary Land Use permit—

which is required for plant siting in Rio

Blanco County;

a Mined Land Reclamation permit required by the State of Colorado;

an NPDES permit required under the

Clean Water Act;

a section 404 Dredge and Fill permit under the Clean Water Act if the operation

affects navigable waters;

a Subsurface Disposal permit as required by the State of Colorado if water

is reinfected;

a permit for the disposal of solid wastes

generated by the facility required under

RCRA;

testing of effects, recordkeeping, reporting, and conditions for the manufacture

and handling of toxic substances as stipulated under TSCA; and

an EIS as required by the National Environmental Policy Act-if an oil shale plant

involves a major Federal action significantly affecting the environment.

The responsibilities for reviewing and approving applications are distributed among

many Federal, State, and local agencies. Federal agencies include EPA, the Department of

the Treasury, DOI (including BLM and USGS),

the Department of Defense (e.g., the Army

Corps of Engineers), and the Interstate Commerce Commission. State entities in Colorado

include the Department of Health, the Department of Natural Resources, and the State

Engineer. Because of varied and overlapping

regulations and statutes it has often been difficult to know which agency must be contacted, and which permits are required from

which entity.

The following discussion examines:

●

●

●

●

●

●

how various parties view the permitting

process;

the current status of oil shale developers

in obtaining the needed permits;

the time required for preparing and

processing permit applications;

the disputes encountered so far in obtaining such permits;

the potential difficulties that might be

encountered by a developing oil shale industry; and

possible policy responses to permitting

issues.

Perceptions of the Permitting Procedure

The various parties interested in environmental permits for oil shale facilities have

widely divergent views concerning the effectiveness and problems of the permitting procedure. Industry is concerned about the

length of time it takes to obtain permits and

the uncertainty of obtaining them. The environmental community is watchful of the procedure’s effectiveness in enforcing the law;

and the regulators themselves are troubled

by their limited personnel and budgetary resources.

The high cost of oil shale projects makes

unexpected delay costly, and industry is concerned with uncertain agency decision schedules or with unpredictable litigation that can

delay or prevent project construction. Furthermore, some regulations and standards

have not yet been set because of a lack of sufficient knowledge about the impacts of shale

operations and the effectiveness of their control. Developers are particularly worried

about the effects of new regulations (such as

for visibility maintenance as part of the PSD

process) on process design and project economics. They are concerned that new regulations could necessitate costly retrofits to ex-
Ch 8–Environmental Considerations . 345

isting plants or even the cessation of operations. For facilities under construction, the

new regulatory requirements may mean redesign or addition of environmental control

equipment or strategies. These uncertainties

increase the risk that a project, once started,

may not be completed. Prospective developers also express their frustration over the

lengthy and expensive procedures for preparing permit applications (including monitoring

and modeling requirements) to meet some environmental statutes. This discontent is sometimes compounded by overlapping agency

jurisdictions and by repetitive paperwork.

The environmental community asserts

that, given the complexity of oil shale operations, the extensive application and review

procedures are necessary to fully assess environmental impacts, the effectiveness of control measures, and compliance with environmental law. They suggest, in fact, that agency

enforcement of environmental laws is too

often compromised by weak regulations and

by a lack of essential information on which

both to base permitting decisions and to enforce the conditions of the permits. Informed,

meaningful public involvement in the processing of environmental permits is therefore promoted by environmental groups to ensure

that all points of view are represented in

agency proceedings. It is particularly important, these groups hold, that the technical

analyses on which agency decisions depend

are subjected to independent scrutiny. However, they believe that adequate provisions

are seldom made for public participation, and

access is not provided to the information

needed to evaluate the applications. They

note that few agencies have an affirmative

public involvement process. They find it is

often difficult to follow and monitor agency

decisionmaking.

The regulators feel overwhelmed by the increasing number of permits and by the complexity of the review. They believe that their

personnel and financial resources are too

limited for the present caseloads and certainly will be dwarfed by any rapid increase in

applications arising from an expanding energy industry, EPA’s Region VIII, for example,

includes not just the oil shale region, but most

of the Western coal and uranium resources.

Regulatory personnel also contend that they

are handicapped by inadequate technical information about the technologies that they

must review and assess.

Status of Permits Obtained by

Oil Shale Developers

The number of permits needed for a given

facility depends on its site; on whether it involves Federal land; on the scale, type, and

combination of processing technologies used;

and on the duration of the operations. As

stated previously, the permits range from

those required for a temporary trailer to the

major environmental permits required under

Federal and State regulations and standards.

Table 70 shows the status of the major perTable 70.–Status of the Environmental Permits for Five Oil Shale Projects

Regular open

Project Type of tract EIS DDP approval PSD permit mining permit NPDES permit

R IO Blanc o Federal lease tract Final programmatic YesaFor 1,000 bbl/d Yes 1st phase

C-a Issueda

Cathedral Bluffs Federal lease tract Final programmatic YesaFor 5,000 bbl/d Yes 1st phase

C-b Issueda

Long Ridge (Union) Private Not applicable Not applicable For 9,000 bbl/d Yes Not requiredb

Colony PrivateCNot applicable Not applicable For 46,000 bbl/d Not yet applied Not requlredb

Superio r Private/Federal d

Not applicable Not applicable Not yet applied Not yet applied Not yet applied

aLlllgallon proceeding over aopro JaI of the momhed DDP

bThese operallofls do not plan 10 discharge 10 Surf aCe StreaMS

cExchange of Federal land and plpellne rlgh[ of way otier BLM and ‘equesled

‘Land exchange requested

SOURCE Office of Technology Assessment
346 ● An Assessment of 011 Shale Technologies

mits obtained by five oil shale developers.

These facilities are presently in different

stages of commercial development. The Rio

Blanco, Cathedral Bluffs, Colony, and Superior projects involve Federal land, while the

Union project is located on private holdings.

DDPs for tracts C-a and C-b had to be approved by USGS because they are part of the

Federal Prototype Oil Shale Leasing Program.

Four of the projects have already been

granted PSD permits for their facilities. Note,

however, that with the exception of the Colony project, only small-scale, first-phase construction air emissions have been approved.

All of the facilities have to obtain Mined

Land Reclamation permits. Rio Blanco, Cathedral Bluffs, and Union have all been approved

for commercial-scale modular operations.

Colony and Superior have not yet applied.

NPDES permits are required under the Clean

Water Act if a plant discharges to a surface

stream. So far Rio Blanco and Cathedral

Bluffs have received such permits for the

first phase of their commercial development.

The Length of the Permitting Procedure

The time required for preparing and processing a permit application depends on the

type of action being reviewed, the review procedures stipulated under the law, the criteria

used by agencies to judge the application, and

the amount of public participation and controversy. If Federal land is involved, then an

EIS will most likely be required. This process

may take at least 9 months after the developer applies for permission to proceed with

the project. * Then the applications for the

necessary construction and operation permits can be prepared and filed. In the case of

the current Federal lease tracts, additional

time was needed to prepare the DDPs for approval by the Area Oil Shale Supervisor of

USGS.

Once the requirements for an EIS and DDP

are satisfied, obtaining all of the needed per-

*The programmatic EIS for the Prototype Leasing Program

took 4 years. Preparation of the draft EIS for the proposed Superior land exchange required 2 years.

mits can take more than 2 years. The preparation and review of the PSD application is

perhaps the most comprehensive and timeconsuming step. Baseline air monitoring is required, along with extensive dispersion modeling to estimate the effect of the plant’s emissions on the region’s air quality. Once this

work is completed and an application submitted to EPA, the approval process, as stipulated under the law, can take as long as 1

year. However, EPA tries to rule on the application within 60 days, and to date an average

of about 90 days has been required. (This includes internal staff review and a period for

public comment. )

It should be noted that a project would not

necessarily be delayed by the full length of

the permitting schedule, because other predevelopment activities such as detailed engineering design, contracting, and equipment

procurement could proceed in parallel, if the

developer were willing to accept the risk that

key permits might eventually prove

obtainable.

Disputes Encountered in

the Permitting Procedure

to be unThe principal problems encountered to

date are related to the needs of the regulatory

agencies for technical information, to differing interpretations of environmental law,

and, according to developers, to a lack of responsibility for timely action on the part of

the agencies.

Occidental’s application for a Subsurface

Disposal permit for its sixth experimental

MIS retort on its property near De Beque,

Colo., was delayed for several months by the

Colorado Water Quality Control Commission’s consideration. (The commission had not

required permits for the first five retorts. )

The commission was concerned about the potential for ground water contamination by the

abandoned MIS retorts and was not satisfied

with the evidence presented by Occidental

that pollution would not occur. Additional

technical information was requested, and the

commission insisted on a cooperative environ-
Ch. 8–Environmental Considerations ● 347

mental monitoring and research program involving DOE, the State of Colorado, and several universities. The dispute was resolved

when Occidental agreed to the program and

the investigators were given access to Oxy’s

site for sampling and experiments.

As work began on tracts C-a and C-bin late

1977, soon after DOI approved the modified

DDPs, a dispute arose among several environmental groups, permitting agencies, and the

lessees over the timing of required permits.

EPA initially informed the lessees that air

quality and State mining and reclamation

permits would not be required until the mining of actual in situ retorts began, The environmental groups maintained that construction commenced with shaft-sinking and construction of the surface facilities needed for

the MIS retorts. This work had already begun

and, according to the environmental groups,

permits should have been in hand, They further contended that the interpretation of

“commencement of construction” used by the

agencies evolved during meetings that were

not open to public participation,

EPA’s recently appointed Regional Administrator subsequently redefined “commencement of construction” to mean collaring of

the shaft, an early activity in shaft-sinking

operations, However, the State reclamation

agency maintained that the developers were

not responsible for the previous interpretation of the law, Therefore, operations could

proceed, The State air pollution division postponed the deadline for application submission until the developers could submit the detailed engineering plans required for an emissions permit, but did not delay the construction. EPA issued the permit in an expeditious

manner and work was not significantly delayed. Because a clear precedent was established, it is unlikely that this dispute will arise

again. It took several months to resolve, but

activities on the tracts continued during this

period.

Finally, there has been protracted legal action between three environmental plaintiffs

and DOI and the lessees of tracts C-a and C-b

over the need for an EIS prior to DOI’s approval of DDPs that were submitted by the

lessees in 1976. This dispute has thus far not

delayed construction on the tracts, It does,

however, exemplify the type of uncertainty

that, the developers maintain, discourages

them from initiating oil shale projects. The

plaintiffs claim that no statement to date has

adequately analyzed the effects of these

plans. Defendants believe that the 1973 programmatic EIS appropriately evaluated the

1976 plans and the alternatives to their approval. The Federal district court agreed

with the defendants. The case was heard by

the 10th Circuit Court of Appeals which also

ruled in favor of the defendants.

Other than these disputes, there have been

no substantial interruptions that could be

directly related to permitting. The only

lengthy application review period involved

Colony Development Operation’s PSD air

quality permit. EPA did not expedite its review of this permit because the applicant indicated it was still inactive, awaiting more

favorable project economics. In addition, 1-

year suspensions were requested in 1976 by

the lessees of the Federal tracts partially

because the baseline air quality conditions on

the tracts exceeded the primary NAAQS for

particulate and the guideline for HC. However, the suspensions were granted for reasons not related to the permitting process.

Unresolved Issues

Although many precedents have been established, there remain unresolved issues

that sustain a level of uncertainty that may

discourage some developers from proceeding,

whether on private or Federal land. These uncertainties may be more critical than those

encountered thus far. Several regulations are

still pending that may increase costs or force

changes in the design of process facilities or

control technologies. They may also add to

the control requirements. The pending regulations include:

● recordkeeping, reporting, and stipulations governing the manufacture and
348 ● An Assessment of 01/ Shale Technologies

handling of toxic substances as required

under TSCA;

disposal practices and standards for solid waste under RCRA;

emission and ambient air standards for

hazardous air pollutants under the

Clean Air Act as amended;

visibility protection requirements for

mandatory Class I areas under the Clean

Air Act as amended;

possible application of the Safe Drinking

Water Act to the brackish ground waters of the Piceance Basin; and

possible application of SMCRA, or similar Federal-reclamation laws, to noncoal

minerals.

Some environmental groups maintain that

the effects of development are so poorly understood that development will entail significant risks. They believe that adequate regulations cannot be promulgated because knowledge is lacking about the severity of the risks

and about the methods for their control. R&D

and further experience with the industry’s

operations may result in the implementation

of new regulations that will further reduce

the economic attractiveness of oil shale projects. This, however, is an uncertainty which

is inherent in any new industry.

Another problem that may emerge is

whether regulatory agencies will be able to

handle the increasing load of permit applications and enforcement duties. Budgets and

personnel are limited, and the States in particular have experienced difficulty finding

and keeping competent technicians and professionals. Increased oil shale operations,

coal mining, oil and gas development, coalfired powerplants and synthetic fuel facilities, uranium mines and mills, and other mineral development in the region will further

tax their resources. The dissatisfaction expressed to date may be insignificant compared to that which is likely as agencies become more overloaded.

Attempts at Regulatory Simplification

Several attempts are being made to simplify regulatory procedures. A case in point is

the action of EPA’s Region VIII office to

streamline the PSD permit application process. The office evaluated its experience with

processing such permits and found that in a

few cases, there are long review times when

the applicant was not in a hurry to obtain a

permit because the future of the project was

uncertain. An example is the application for

the Colony project, which has been suspended for several years. In other instances,

delays resulted when the agency was deluged

by permit applications prior to the enactment

of new, stricter regulations. An example is

the situation that arose in 1978 when the

older PSD regulations, which did not require

extensive baseline air quality monitoring,

were replaced by new regulations that required monitoring for a l-year period. When

this happens, the agency’s resources are

overwhelmed and applications are delayed.

Other delays resulted when applications

were incomplete (information was lacking) or

when the information that was provided was

deemed inadequate by the agency. The first

informational problem could be easily reduced by a quick review of the application for

completeness. The second is more difficult,

because it involves scientific and technical

judgment. It reflects, to an extent, the fact

that the oil shale processes are new technologies and their effects are not totally understood. Standardized procedures are not always available for determining compliance

with the law. This difficulty could be reduced

by developing standard procedures wherever

possible. This has been done already in some

areas of the PSD process where, for example,

the developers are required to use standard

dispersion models authorized by EPA.

The Region VIII office recently issued a policy statement that addresses its efforts to im-
Ch 8–Environmental Considerations ● 349

prove the permitting procedures. A key element is designing a standard application that

defines the specific data needs and recommends procedures for obtaining the data.

There is also an effort to educate developers

in using the application by holding public

workshops on the permitting procedure. Also,

at the Federal level, one focus of the proposed

Energy Mobilization Board is to expedite

agency decisionmaking and reduce the impacts of new regulatory requirements that

may emerge after construction or operations

begin.

The State of Colorado, with funding from

DOE, is designing and testing a permit review

procedure for major industrial facilities that

will coordinate the reviews by Federal, State,

and local regulatory agencies. The procedure

is also planned to expand the public’s opportunities to become involved in all phases of

project planning and review. It is being tested

with a controversial molybdenum project

near Crested Butte, Colo. A handbook will be

developed on completion of the test. This may

aid in applying similar methods to the permitting process for oil shale plants. *

Policy Options

The policy options presented here range

from working to better understand complex

regulatory processes, through using the results of such work to reduce the complexities,

to waiving the laws or regulations. This range

encompasses actions over which there is little

disagreement through those which involve extreme controversy. Few would argue that regulatory procedures could be improved, while

many would resist changes that could result

in weakening environmental protections.

Study the Causes of Permitting Delays

Further study of the permitting procedure

could help to identify and eliminate some of

the causes of regulatory inefficiency. Such

“Colorado hopes this joint review process, which provides

for concurrent rather serial review of applications, will also

reduce the time needed for review.

studies have been conducted by EPA’s Region

VIII office for the PSD process. The National

Commission on Air Quality is conducting a

more comprehensive evaluation of alternative means for achieving the goals of the

Clean Air Act with more manageable regulatory procedures. Similar studies could be

made of other laws and regulations.

Increase the Resources of the

Regulatory Agencies

Increasing the personnel and financial resources of the Federal regulatory agencies

would allow them to improve their response

capabilities. The agencies could also provide

technical assistance to the State and local

regulators to aid in their decisionmaking

processes, However, a simple increase in

agency funding, without a methodology for

coordinating the expanded resources, would

not guarantee that procedures would improve.

Improve Coordination Among Agencies and

Between Agencies and the Public

The permitting process might be improved

if coordinated reviews were conducted by the

various agencies. This strategy would help to

identify and reduce jurisdictional overlaps

and to reduce personnel needs and paperwork loads, A major advantage would be the

opportunity for sharing analytical responsibilities and results. The public hearings that

are required for many separate permits could

also be consolidated. The strategy could be

patterned after the voluntary joint review

processes that are being developed in Colorado and other States. However, unless the

approach were mandated, it is questionable

that interagency cooperation would be significantly improved.

Another approach would involve the establishment of a regional environmental monitoring system to determine baseline conditions

within all areas to be affected by oil shale

projects. The system could better characterize baseline conditions than could individual,

uncoordinated monitoring programs. It might
350 ● An Assessment of O// Shale Technologies

reduce the duration and the cost of the advance monitoring programs that are required

of permit applicants. Site-specific measurements would still be required to characterize

biological communities, soils, hydrology, and

geology for projects involving Federal land.

Baseline surveys could be conducted by Federal agencies on potential lease tracts to

shorten the time between a leasing decision

and commercialization. The cost of the program could be included in the cost of the

lease. Individual monitoring of stack emissions, water discharges, and reclamation efforts would also still be needed as the projects proceeded.

Improved coordination of public participation might also shorten review time by reducing controversy, political confrontation, and

litigation. Procedures might include advance

public notification of the status of permit applications, the dissemination of technical information and R&D results, and the more direct involvement of the public in an agency’s

decisionmaking process through, for example, workshops and public meetings. It is possible that increasing the public’s awareness

of the characteristics of a project might lead

to perceptions of greater risk. On the other

hand, education could lessen nonproductive

discussions and confrontations. In any case,

it may be difficult to educate the public in the

technical aspects that determine whether an

application satisfies the standards. To maintain a high level of participation, some intervener groups may seek financial and technical assistance. This would be controversial,

especially from the point of view of the developers.

Clarify the Regulations and

the Permitting Procedure

One option would be to expedite promulgation of standards for visibility and hazardous

emissions under the Clean Air Act, and to set

the as yet undefined NSPS for oil shale

plants. Additional regulations could also be

defined under RCRA, TSCA, and other laws.

These actions would eliminate many of the

regulatory uncertainties and would allow the

developers to integrate controls for the new

standards into their plant designs. If it is desired to reduce developer risks, new standards should be firmly established and not

subject to change for an extended period.

This may not be appropriate, since early experience with the industry may indicate a

need to modify the standards to achieve the

desired level of protection. In addition, they

may be difficult to establish. Excessively lax

standards would not adequately protect the

environment; excessively strict ones might

unnecessarily preclude development. These

hazards are particularly applicable to setting

NSPS.

Another approach would be to simplify the

permitting procedures themselves, based on

information from the investigations suggested

under the first option. This would have the

advantage of retaining the protection of the

existing laws while making it easier to comply

with them. However, problems (such as the

uncertain status of applications in progress)

might arise during the transition from the old

regulatory system to the new. It is also often

difficult to isolate the substance of environmental protection laws from the implementation procedures. Any proposed changes in the

procedures would need careful examination

by the agencies, the developers, and the public.

A third approach would be to establish detailed, standardized specifications for permit

applications. This would reduce the problem

of insufficient data being provided with the

applications and the delays that would be

caused when agencies request the additional

information they feel is necessary for a thorough review. Fully comprehensive standardized forms are probably not possible, and

some interactions after an application is submitted will still be needed.

A fourth option would be to have a moratorium on new regulations until some of the

actual effects of development are determined

on the Prototype Program lease tracts. (Monitoring of environmental effects and development of control techniques is one of the major
Ch 8–Environmental Considerations 351

objectives of the Program. ) A disadvantage is

that the regulatory uncertainties would remain. An advantage is that the regulations

could be promulgated from a better knowledge base,

Expedite the Permitting Procedure

The proposed Energy Mobilization Board

would expedite permitting by negotiating a

project schedule with a developer and then

enforcing the schedule by making regulatory

decisions if the responsible agency does not

do so within a specified period. Proponents of

this strategy point out the advantages of a

central authority that could provide a single

point of contact between the developer and

the regulatory system. Opponents feel that

such an authority would add another layer of

bureaucracy, would increase controversy

over the projects that are expedited, and

would ultimately not have substantial effects

on permitting delays.

Another method would be to limit the period during which litigation can be initiated

against a particular permitting action, This

mechanism could be similar to that employed

in the case of the Trans-Alaska oil pipeline. It

would reduce the risk of agency actions being

subjected to legal challenges that could jeopardize a project’s completion schedule. It

should be noted, however, that legal mechanisms already exist in some specific laws to

limit the period of litigation, The expediting

strategy could extend this protection to most,

if not all, of the relevant statutes,

Limit the Application of New Environmental Laws

and Regulations

Plants already under construction, or that

are operating, could be exempted from the

provisions of new environmental laws and

regulations. This approach—’’grandfathering ”—is embodied in the legislation for the

Energy Mobilization Board. It would remove

many of the regulatory uncertainties. However, it is surrounded with controversy because new regulations might be needed to

deal with problems that could not be discovered until after operations begin. Many of the

present laws contain provisions to exempt existing facilities from new requirements.

These include either automatic exemption

clauses or economic criteria against which

the new regulatory requirements must be

tested.

Waiving Existing Environmental Laws

This strategy would exempt a project from

the provisions of some or all existing environmental laws and regulations that might delay

or prevent its construction and operation.

This measure would remove virtually all of

the problems and delays associated with the

permitting. However, it would have serious

political, environmental, and social ramifications since it could arbitrarily preempt environmental protection under the law. Furthermore, the waivers might give an undeserved

competitive advantage to the developers who

received them. The allocation of the waivers

would be highly controversial, The extent to

which this action would speed the deployment of the industry is unclear.
—.- .

352 An Assessment of Oil Shale Technologies

Chapter 8 References

‘Environmental Protection Agency, Trace E]ements Associated With Oil S~ale and Its Processing, EPA-908/4-78-003, prepared by TRW and DRI

under contract No. 68-02-1881, May 1977, p. 2.

2

T. C. Borer and J. W. Hand, Identification and

Proposed Control o~ Air Pollutants From Oil Shale

Operations, prepared by the Rocky Mountain Division, The Pace Co. Consultants and Engineers,

Inc., for OTA, October 1979, p. 38.

‘Environmental Protection Agency, Monitoring

Environmental Impacts of the Coal and Oil Shale

Industries: Research and Development Needs,

EPA-600/7-77-015, February 1977, p. 138.

%upra No. 2, at p. 20.

‘Denver Research Institute, Predicted Costs of

Environmental Controls for a Commercial Oil

Shale Industry: Volume I—An Engineering Ana]ysis, prepared for the Department of Energy under

contract No. EP-78-S-O2-51O7, July 1979.

‘Environmental Protection Agency, A Preliminary Assessment of the Environmental Impacts

From Oil Shale Development, prepared by TRW

and DRI under contract No, 68-02-1881 (EPA-600/

7-77-069), July 1977, P. 104.

7Battelle Northwest Laboratories and Dames

and Moore, Environmental Impact Analysis: Appendix 13—Air Studies, prepared for Colony Development Operation, October 1973.

‘Rio Blanco Oil Shale Project, Detailed Development Plan Tract C-a: Environmental Protection

and Monitoring, vol. 4, March 1976.

‘Rio Blanco Oil Shale Project, Detailed Development Plan Tract C-a: Environmental Protection

and Monitoring, vol. 3, May 1977.

‘[statement by Terry Thoem, Environmental

Protection Agency, Region VIII, as reported in the

minutes of the 25th meeting of the Oil Shale Environmental Advisory Panel, Grand Junction, Colo.,

May 2 and 3, 1979, pp. 130-131,

I INational Commission on Air Quality, Report of

the Atmospheric Modeling Review Panel of the

National Commission on Air Quality, (preliminary

draft), to be published in February 1980.

121bid.

1‘Ibid,

“E, F, Bates and T. L. Thoem (eds, ), Pollution

Control Guidance for Oil Shale Development, revised draft report, Environmental Protection

Agency, Cincinnati, Ohio, July 1979, p, 4-46.

15 Colony Development Operation, An Environmental Impact Analysis for a Shale Oil Complex at

Parachute Creek, Colorado, vol. I, 1974.

1hJ. C. Ward, G. A. Margheim, and G, O. Lof,

Water Pollution Potential of Spent Oil Shale

Residues, report for the Water Quality Office, Environmental Protection Agency, Colorado State

University, Fort Collins, Colo., 1971.

17National Academy of Sciences, Mining and

Processing of Oil Shale and Tar Sands—A Working Paper Prepared for the Committee on Surface

Mining and Reclamation, Washington, D. C., 1979,

p. 89.

1%upra No. 5,

‘

g

Ibid.

2(}Supra No. 17, at p, 91.

21J. P. Fox, K. K, Mason, and J. J. Duvall, “Partitioning of Major, Minor, and Trace Elements During Simulated In Situ Oil Shale Retorting in a Controlled-State Retort, ” Proceedings of the Twelfth

Oil Shale Symposium (J. H, Gary, cd.), Colorado

School of Mines Press, Golden, Colo., 1979, pp.

58-71,

22F. C, Hass, “Analysis of TOSCO II Oil Shale

Retort Water, ” paper presented at ASTM Symposium D-199.33 on Analysis of Wastes Associated With Alternative Fuel Production, Pittsburgh, Pa., June 4-5, 1979,

21E. W. Cook, “Organic Acids in Process Water

From Green River Oil Shale, ” Chemistry & Industry, May 1, 1971, p, 485.

“G. W. Dawson and B, W. Mercer, “Analysis,

Screening and Evaluation of Control Technology

for Wastewater Generated in Shale Oil Development,” Quarterly Reports, Batelle Pacific Northwest Laboratory, Richmond, Wash., January

1977-March 1979.

25Water Purification Associates, A Study of

Aerobic Oxidation and Allied Treatments for Upgrading In Situ Retort Waters, contract No, EW78-C-20-0018 with Laramie Energy Technology

Center, Department of Energy, Quarterly Status

Report, August 1979.

2%upra No. 14.

27Supra No. 21,

%upra No. 22.

“National Academy of Sciences, Water Quality

criteria, 1972, Environmental Protection Agency

publication (EPA-R-3-73-033), Washington, D, C.,

March 1973.

1{]Ibid,

‘lSupra No. 14, at p. 3-64.

‘21bid.

“J. B, Weeks, et al., Simulated E~~ects of OilShale Development on the Hydrology of Piceance
Ch 8–Environmental Considerations 353

Basin, Ccdoraclo, Professional Paper 908, U.S. Geological Survey, Washington, D, C., 1974, p. 34.

“Ibid., p. 44.

“)Ibid,, p. 39.

“]Ibid., p. 40.

Wupra No. 14.

%upra No. 6.

“A. L. Hines, The Role of Spent Shale in Oil

Shale Processing and tbe Management o-f Environ -

mental Residues, Department of Energy, report

TID-28586, ERDA-Laramie Energy Research

Center, Laramie, Wyo., April 1, 1978.

‘“B. W. Mercer, et al., “Assessment of Control

Technology for Shale Oil Wastewaters, ’” paper

presented at Environmental Control Technology

Symposium, Department of Energy, November

1978.

“lB. L, Harding and K. D. Lindstedt, et al., Removal of Ammonia and Alkalinity From Oil Shale

Retort Waters, prepared for Laramie Energy

Technology Center, Department of Energy, contract No. DE-AS20-78-ET-13096, April 1979.

“K. D. Lindstedt and E. R. Bennett, Report on

Characterization and Treatment of Retort Waters

From In Situ Oil Shale Retorting, Civil, Environmental, and Architectural Engineering Dept., University of Colorado, August 1977.

“Osmonics, Inc., “Application Test Report”

(Study of the Application of Reverse Osmosis to

Treatment of Oil Shale Wastewaters), report in

preparation for Laramie Energy Technology Center, Department of Energy, 1979.

‘“Water Purification Associates, A Study of Reverse Osmosis for Treating Oil Shaie Process Condensates and Excess Mine Drainage Water, quarterly progress report, prepared for Laramie Energy Technology Center, Department of Energy, contract No. DE-AC2O-79LC1OO89, September 1979.

“E. A. Ossio, et al,, “Anaerobic Fermentation of

Simulated In Situ Oil Shale Retort Water, ” American Chemical Society Division of Fuel Chemistry

Reprints, vol. 23, No. 2, 1978, pp. 202-213.

“R. R. Spencer, Anuero&c Treatment o-f Wastewater Generated During Shale Oil Production

(draft report), BattelIe Pacific Northwest Laboratory, 1979.

%upra No. 24.

%upra No. 25.

‘“B. Harding, et al., “Study Evaluates Treatments for Oil-Shale Retort Water, ” Industrial

Wastes, September/October 1978, pp. 28-33.

“lA. B. Hubbard, “Method for Reclaiming

Wastewater From Oil Shale Processing, ” American Chemical Society Division of Fuel Chemistry

Reprints, vol. 15, No. 1, March-April, 1971, pp.

21-25.

“Supra No. 14, at p. 3-44,

‘

)

’ Ibid., p. 5-5o.

‘

] National Safety Council, Accident Facts, stock

No. 021.57, Chicago, 1977.

“R. H. Flinn, et al., Silicosis in the Metal Mining

Industry: A Reevaluation, 1958-1961, Public

Health Service, Pub. No, 1076, 1963.

“Ibid.

“

)

Personal communication with George Weems,

Supervisory Physical Scientist, Industrial Health

Branch, Denver Technical Support Center, Mining Safety and Health Administration, Department of Labor, Jan. 22, 1980.

“1. P. Maripuu, Puusaar, “Spirographic an d

Roentgenofunctional Characterization of Pulmonary Emphysema in Bituminous Shale Miners, ”

Gyg. Tr. Prof. Zabol., vol. 15, No. 12, 1971, pp.

51-53.

‘{{W. K. C. Morgan and N. Zapp, “Respiratory

Disease in Coal Miners, ” American Review o.f I?es -

piratory Diseases, vol. 113, 1976, pp. 531-559.

‘)OL. M. Irwig and P. Rochs, “Lung Function and

Respiratory Symptoms in Silicotic and Nonsilicotic Gold Miners, ” American Review of Respirator y

Diseases, vol. 117, 1978, pp. 429-435.

‘I(’V. A. Kung, “Morphological Investigations of

Fibrogenic Action of Estonian Oil Shale Dust, ” Environment tal Health Perspectives, vol. 30, 1979 ,

PP. 153-156 .

“W. E. Wright and W. N, Rem, “A Preliminary

Report: Investigation for Shalosis Among Oil

Shale Workers, ” presented at Park City Environmental Health Conference, Park City, Utah, Apr.

4-7, 1979.

‘)’J. Rudnick and G. L. Voelz, “An Occupational

Health Study of Paraho Oil Shale Workers,”’ presented at Park City Environmental Health Conference, Park City, Utah, Apr. 4-7, 1979.

“J. Costello, “Morbidity and Mortality Study of

Oil Workers in the United States, ” Environmental

Health Perspectives, vol. 30, 1979, pp. 205-208,

%upra No. 107.

‘)7L. M, Holland, D. M. Smith, and R, G. Thomas,

“Biological Effects of Raw and Processed Oil

Shale Particles in the Lungs of Laboratory Anireals, ” Environmental Health Perspectives, vol.

30, 1979, pp. 147-152.

‘)’)L. M. Holland, W, D. Span, and L. L. Garcia,

“Inhalation Toxicology of Oil Shale-Related Materials, presented at Park City Environmental

Health Conference, Park City Utah, Apr. 4-7,

1979.
— —

354 . An Assessment of Oil Shale Technologies

b7R, A. Renne, J. E. Lund, K, E. McDonald, et al,,

“Morphologic Effects of Intratrachially Administered Oil Shale in Rats, ” presented at Park City

Environmental Health Conference, Park City,

Utah, Apr. 4-7, 1979.

‘8Supra No. 63.

b9B. T. Scheb, “Noise in the Mining Industry: Its

Effects, Measurement, and Control, ” Proceedings

of the Symposium on Industrial Hygiene for A4ining and Tunneling, American Conference of Governmental Industrial Hygieniests, Cincinnati,

Ohio, 1978.

‘[’M. Blick, et al., “Noise,” Medicine in the A4ining Industries (J. M. Rogan, cd.), published by F. A.

Davis, Philadelphia, Pa,, 1974, p. 244.

711. Berenblum and R. Schoental, “Carcinogenic

Constituents of Shale Oil, ” British Journal of Experimental Pathology, vol. 24, 1943, pp. 232-239.

72A. Scott, “The Occupation Dermatoses of the

Paraffin Workers of the Scottish Shale Oil Industry, ” British Medical Journal, vol. 1, 1922, pp.

381-385.

7JM. Purde and S, Etlin, “Cancer Cases Among

Workers in the Oil-Shale Processing Industry, ”

presented at Park City Environmental Health Conference, Park City, Utah, Apr. 4-7, 1979.

“M. Purde and M. Rahn, “Cancer Patterns in

the Oil Shale Area of the Estonian Soviet Socialist

Republic, ” Environmental i+ea)t~ Perspectives,

vol. 30, 1979, pp. 209-210.

75A, Leitch, “Paraffin Cancer and Its Experimental Production, ” British Medical Journal, vol.

2, 1922, pp. 1104-1106.

7bI. Berenblum and R. Schoental, “The Difference in Carcinogenicity Between Shale Oil and

Shale, ’’British Journal of Experimental Pat~ology,

vol. 25, 1944, Pp. 95-96 .

“C. C. Twort and J. M. Twort, “Classification of

Four Thousand Experimental Oil and Tar Skin Tumors of Mice, ” Lancet, vol. 1, 1930, pp.

1331-1335.

“J, M. Holland, et al., “Skin Carcinogenicity of

Synthetic and Natural Petroleums, ” Journal of Occupational Medicine, vol. 21, 1979, pp. 614-618.

7YR. M. Coomes, “Carcinogenic Testing of Oil

Shale Materials, ” Twelfth Oil Shale Symposium

Proceedings, Golden, Colo., The Colorado School

of Mines Press, November 1979.

“

)

Ibid.

“Ibid.

821bid.

‘

]

Ibid.

‘“J. J, Zone, “Cutaneous Effects of Shale Oil,”

presented at Park City Environmental Health Conference, Park City, Utah, Apr. 4-7, 1979.

85D. J. Birmingham, Interim Report on the Shale

Oil Study, Public Health Service, Cincinnati, Ohio,

1955.

8bTabershaw-Cooper Associates, Inc., A Mortality Study of Petroleum Refinery Workers, project

OH-1, Medical Research Report No. EA-7402,

American Petroleum Institute, September, 1974.

87N, M. Hanis, K. M. Stavraky, and J. L. Flowler,

“Cancer Mortality in Oil Refinery Workers, ”

Journal of Occupational Medicine, vol. 21, No. 3,

1979, Pp. 167-174,

88G. Theriault and L. Goulet, “A Mortality Study

of Oil Refinery Workers, ’’Journal of Occupational

Medicine, vol. 21, No. 5, 1979, pp. 367-370.

89M+B.BIOChand D. Kilburn (editors), processed Shale Revegetation Studies, 1965-1973, Colony Development Operation, Atlantic Richfield

co., 1973.

‘(’W. R, Schmehl and B, D. McCaslin, “Some

Properties of Spent Oil Shale Significant to Plant

Growth,” Ecology and Reclamation of Devastated

Land, vol. I (R. J, Hutnik and G, Davis, eds.), published by Gordon and Breach, New York, 1973,

PP. 27-43.

“’J. C. Ward and S. E. Reinecke, Water Pollution

Potential of Snow~all on Spent Oil Shale Residues,

prepared by the Environmental Engineering Program, Department of Civil Engineering, Colorado

State University for the Bureau of Mines, Laramie

Energy Research Center, under grant No.

0111280, 1972,

‘

z

Ibid.

“James R. Meiman, Infiltration Studies in the Piceance Basin, Colorado, Thorne Ecological Institute, technical publication No. 12, 1975.

‘AIbid,

‘

5 Forest Service, Users Guide to Soils, Mining

and Reclamation in the West, general technical

report INT-68, Intermountain Forest and Range

Experiment Station, U.S. Department of Agriculture, 1979.

“W. J. Culbertson, et al., Processed Shale

Studies: Environmental Impact Analysis, Appendix 5, Colony Development Operation, Atlantic

Richfield Co., 1974.

‘

7 Supra No, 95,

“R. M. Dixon, “Soil Imprinting for Increasing

Land Productivity, ” presented at the 33rd Annual

Meeting of Soil Conservation Society of America,

July 30-Aug. 2, 1978, Denver, Colo, Also printed in

the Journal of Soil and Water Conservation, 1978.

‘gSupra no. 89.

‘(WRio Blanco Oil Shale Co., Revegetation Program 1978 Annual Report, submitted to Rio Blanco

Oil Shale Co., Denver, Colo,, by NUS Corp., Den-
Ch. 8–Environmental Considerations 355

ver, Colo., March 1979.

II)]C. Wayne Cook, Rehabilitation Potential and

Practices of Colorado Oil Shale Lands, progress

report for period June 1978- May 31, 1979, prepared for the Department of Energy by Colorado

State University under contract No. EY76-S-02-4018, 1979.

I“zC. Wayne Cook, et al., Revegetation Guidelines for Surface Mined Areas, Colorado State

University, Range Science Department Science

Series No. 16, 1974.

‘

()] Ibid.

‘(”R. R. Ericsson and P. Morgan, “The Economic

Feasibility of Shale Oil: An Activity Analysis, ”

Bell Journal of Economics, vol. 9, 1978, pp.

457-487.

“]5Supra No. 1.

‘

(

’

t) Supra No. 96.

11]71bid,

W5upra No. 90.

%upra No. 100.

‘loR. C. Woodmansee, et al, “Nitrogen in Drastically Disturbed Lands, ” Forest Soils and Land

Use (C. T. Youngberg, cd.), Department of Forest

and Wood Sciences, Colorado State University,

Fort Collins, 1979, pp. 376-392,

‘

]] Supra No. 101.

“

z

Ibid.

11 ‘F. B. Reeves, et al,, “The Role of Endomycorrhizae in Revegetation Practices in the Semi-Arid

West: A Comparison of Incidence of Mycorrhizae

in Severely Disturbed vs. Natural Environments,

American Journal of Botany, vol. 66, No, 1, 1979,

pp. 6-13.

“’Supra No. 101.

‘}%upra No. 16.

“’Supra No. 90.

1l’H. P. Harbert III, et al., Vegetative Stabilization of Spent Oil Shales: Vegetation, Moisture,

Salinity and Runoff 1973-1976, 1978,

I l~H. p. Harbert 111, et al., ~YSimeter study on

the Disposal of Paraho Retorted Oil Shale, Industrial Environmental Research Laboratory, Office

of R&D, Environmental Protection Agency, Cincinnati, Ohio (EPA-600/7-79-188), 1979.

IIqW. A. Berg, et al,, Vegetative Stabilization of

Union Oil Company Process B Retorted Oil Shale

2975-1978, Colorado State University Experiment

Station, technical bulletin No. 135, 1979,

121)J. T, Herron, et al., Vegetation and Lysimeter

Studies on Decarbonized Oil Shale, Colorado State

University Experiment Station, technical bulletin

No, 136, 1980.

12]L. A. Richards (cd.), Diagnosis and Improvement of Saline and Alkali Soils, U.S. Department of

Agriculture Handbook No. 60, 1954.

‘221. F. Wymore, Water Requirement for Stabilization of Spent Shale, doctoral dissertation, Colorado State University, Fort Collins, Colo., 1974,

‘z’D. D. Runnells, et al., “Release, Transport,

and Fate of Some Potential Pollutants, ” in Trace

Elements in Oil Shale, report No. COO-4Ol 7-2, Environmental Trace Substances Research Program,

University of Colorado, Denver, Colo., 1978, pp.

49-97.

‘“M. K. Kilkelly, et al., “Trace Elements in

Plants Growing on Processed Oil Shales, ” in

Trace Elements in Oil Shale, report No,

COO-4017-2, University of Colorado, Denver, Colo.,

1978, pp. 98-134.

‘

25 Supra No. 16.

‘2hSupra No. 117.

‘271bid,

‘28Supra No, 100.

‘2%upra No. 96.

‘30Fish and Wildlife Service, The Plant Information Network: Volumes I-W, U.S. Department of

the Interior FWS/OBS-77/38-41. Supporting computer data base located at the Department of Botany and Plant Pathology, Colorado State University, Fort Collins, Colo.

1“C. M. McKell, et al., Selection, Propagation,

and Field Establishment of Native Plant Species on

Disturbed Arid Lands, Institute for Land Rehabilitation, Utah Agricultural Experiment Station,

Utah State University, 1979.

1‘zSoil Conservation Service, Plant Materials for

Use on Surface Mined Lands in Arid and SemiArid Regions, U.S. Department of Agriculture

handbook SCS-TP 157, Lincoln, Nebr. (in press).

‘

]

’ Forest Service, User Guide to Vegetation,

Mining and Reclamation in the West, general technical report INT-64, Intermountain Forest and

Range Experiment Station, U.S. Department of Agriculture, 1979.

‘ “A. Plummer, et al., Restoring Big-Game Range

in Utah, Utah Division of Fish and Game publication No. 68-3, 1968.

l’5Supra No. 130.

‘%upra No. 133.

‘%upra No. 101.

“nIbid,

‘Y5upra No. 133.

1’OK. A. Crofts and C. M. McKell, Sources of

Seeds and Planting Materials in the Western

States for Land Rehabilitation Projects, Utah Agri-
356 ● An Assessment 01011 Shale Technologies

culture Experiment Station Land Rehabilitation

Series No. 4, Logan, Utah, 1977.

‘“’ Supra No. 133.

‘“2 Supra No. 101.

1“Supra No. 100,

‘“’N. C. Frischknecht and R. B. Ferguson, Revegetating Processed Oil Shale and Coal Spoils on

Semi-Arid Lands, interim report, EPA-600/

7-79-068, Environmental Protection Agency, Cincinnati, Ohio, 1979.

‘“R. W. Tinus, et al. (eds,), Proceedings of the

North American Containerized Forest Tree Seedling Symposium, Great Plains Agricultural Council

publication No. 68, 1974,

‘%upra No. 131.

‘“71bid.

““Supra No. 132.

“’Supra No. 117.

‘%upra No. 132.

“]Bureau of Land Management, Piceance Planning Unit Resource Analysis, September 1970.

“’Bureau of Land Management, White River

Management Framework P~an, January 1972.

‘s’K. C. Vories, A Vegetation Inventory and

Analysis of the Piceance Basin and Adjacent

Drainages, master’s thesis, Western State College, Gunnison, Colo., 1974.

‘“J. A. Tiedeman, et al., Phyto-Edaphic C~assification of the Piceance Basin, Colorado State University, Range Science Department Science Series No. 31, 1978.

I“Ibid.

“’)Rocky Mountain Oil and Gas Association Oil

Shale Committee, Summary of Industry Oil Shale

Environmental Studies and Selected Bibliography

of Oil Shale Environmental References, Denver,

Colo., 1975.

15%upra No. 89.

“HJ. M. Merino, et al., “Reclamation of Spent Oil

Shale,” Mining Congress ]ournal, vol. 63, No. 10,

1977, pp. 31-36.

‘%upra No. 117.

‘fWupra No. 118,

“)lSupra No. 119.

“)2Supra No. 120.

‘

(]] Supra No. 89.

‘

[)’ Ibid.

““C. M. McKell, Achieving Effective Revegetation of Disposed Processed Oil Shale: A Program

Emphasizing Natural Methods in an Arid Environment, Utah State University, Agriculture Experiment Station Land Rehabilitation Series No. 1,

1976.

‘Wupra No. 16.

‘t)7Supra No. 89.

‘%upra No. 117.

“%upra No. 90.

‘%. C. Lipman, “Union Oil Company Revegetation Studies, ” Environmenta~ Oil Shale Sym -

posium, Colorado School of Mines, Oct. 9-10,

1975, pp. 165-180.

‘

7

’ Supra No. 119.

“2Supra No. 118.

“]Supra No, 101.

“’Ibid.
CHAPTER 9

Water Availability

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

359

Summary of Findings . . . . . . . . . . . . . . . . . . . . 359

Analysis of Water Requirements for Oil

Shale Facilities . . . . . . . . . . . . . . . . . . . . , .. 361

Introduction . . . . . . . . . . ., . . . . . . . . . . . . . . . 361

Process and Facility Models Analyzed .. ....361

Water Requirements . . . . . ., . ............362

An Evaluation of Assumptions in the Estimates363

Range of Water Requirements. . ...........366

Water Resources: A Physical Description. .. .367

SurfaceWater . ........................367

GroundWater. . . . ..................,.,.373

AIIocationoftheColorado River

SystemWaters ● **.**.*.***** . ........374

Compacts, Treaties,andLegal Mechanisms. .375

Surface WaterAllocations. . ..............376

Doctrine ofPriorAppropriation . ..........377

Introduction . ................,,,.......377

SurfaceRights . .................,......377

Ground WaterRights. . ..................379

FederalReservedRights . ................37 9

Page

Physical AvailabilityofSurfac@ Water for

Oil ShaleDevelopment. . ...............380

Introduction . ..........................380

The Availability ofSurface Waterinthe

Upper Colorado RiverBasin . ............382

Water Availability inHydrologic Basins

Affected by OiIShaie Development . ......385

Water AcquisitionStrategi@s andTheirCosts 388

PerfectionofDeveloperWater Rights .......388

Purchase ofSurplusWaterFrom FederaI

Reservoirs. . . . . . . . . . . . . . . . . . ..~..”.”.389

Purchase ofIrrigationRights . .............389

GroundWaterDevelopment. . ..........,..391

InterbasinDiversions. . ..................392

IntrabasinDiversions. . ..................393

Summary ofSupplyCosts. . ...........000.394

Legal andInstitutiona~Considerations .. ....395

TheLawoftheRiver. . ...................39 5

The Doctrine ofPrior Appropriation . .......396

FederalReservedRights Doctrine . .........396

Environmental Legislation . ...............397

InstreamWaterFlow . ...................39 8
— .—

Page

Intei@askTmsnsfers ● ● * * ● . . . ● ● . ● ● ● ● ● ● ● ● ● 398

Salinity Standards . . . . . . . . . . . . . . . . . . . . ..398

Critkdllqainties.,•• . . ● . . . . . . . . ● . . ● ● 388

Virgin Flow ● .*..*, ● ..*,.** .**.**,. ● .**. 399

TechnologyMix . .....................,.400

ConventionalDepletions. . ................400

GroundWaterDevelopment .. ., ... ... ....4oo

ThelmpactsofUsingWaterfor oil

ShaleD8ve10pment. . .......0..........401

Introduction . . . . .........0.........,...401

ImpactsFromtheConstruction andOperation

ofWaterSupplyFaciIities . .............401

ImpactsFromChangesinSurface Flows. ....4oI

ImpactsonWaterQuality . ....,..........402

hnpacXsonRiverEcology , ..............,.402

TransferofWaterFromIrrigated Agriculture402

GroundWaterDevelopment. . ............,403

I MethodsforIncreasingWaterAvailability ..405

MoreEfficientUse . .................,...405

WeatherModification . . . . . . . . . . . . . . . ....4o7

Polioyoptions .*,..*** ● *....... ● ***.*,, , 407

TheDeterminationofWaterNeeds ... ... ...4o7

ReservoirSitingandDirect-Flow Diversions. .4O8

FinancingandBuildingNewReservoirs .. ...410

Financingandhnplementing MoreEfficient

PracticesandWaterAugmentation. .. ....410

FederalSourcesofWaterfor OilShale

Deve~opment. . . . . ...................,412

TheAlkxationofWaterResources . ....,...412

lnterb@nDiversions. . ...............,..41 2

Chaptel Preferences. . . . . . . . . . . . . . . . . . . . 412

List of Td!M98

%IM8NO* Page

71. Process Models fur Oil Shale Facilities 361

72. Water Requirements for Mine

Drahag@Production for 50,000-bbl/d

Oil Shale F@iities . . . . . . . . . . . . . . . . 362

73. ACo~atiwnof tie Water Reqtir~

mentsofthe Various Subprocesses . . . 363

74. BredxhwnafWate rRequirements

and Water Production for 50,000-bbl/d

Oil Shele Facilities . . . . . . . . . . . . . . . . 364

75, Likely Ra~esof Water Requirements

adhdinelhaimge Production for Oil

Shale Facilities Producing 50,000 bblld

of Shale Oil Syncrude . . . . . . . . . . . . . . 367

.

Table NO. Page

78.

77.

78.

79.

80.

81.

82.

83.

84,

85.

86*

WaterRequirements for A@iveand

Proposed 011 Shale projects ., . . . . . . . 367

Estimates of Surface Water

Allocations tothe C)il Shale States . . . . 376

Present and Projected Water

Depletions for Activities Other Than

Oil Shale Development in Colorado,

Utah, and Wyoming. . . . . . . . . . ., . . . . 384

Estimation of Surplus Surface Water in

Colorado, Utah, and Wyoming at

Present andin2~. , . . . . . . . . . . . . . . 385

Maximum Shale Oil Production Based

on Surplus %rface Water in2000 . . . . 385

Water Requirements by Hydrologic

Subbasin for a l-Million-bbl/d Industry

in2000. . . . . . . . . . . . . . . . . . . . . . . . . . 386

Examples of the Charges for

Purchasing Surplus Surface Water

From U.S. Bureau of Reclamation

Reservoirs . . . . . . . . . . . . . . . . . . . . . . . 388

Estimated Construction Costs for

Proposed Reservoirs Within the Colorado River Water Conservation

District ● **. **. O . * * . * * * * . ***..,... 389

Summary of Cost Estimates for

Intrabasin Diversions Within the Oil

Shale Area ● ● ● ● ● ● ● ● ● ● ● ● . ● ● ● ● ● ● ● ● . ● 394

Summary of Approximate Water

Supply Costs for Several Acquisition

Strategies ● ● ● ● ● ● ● ● * ● ● c s c c ● ● ● Q ● ● ● ● 395

Projected Salinity Changes in the

Lower Colorado River Because of Oil

Shale Development . . . . . . . . . . . . . . . . 402

List of Figures

Figure No. Page

63. ‘“ ‘- - -

64*

65.

66.

67.

68.

Major Hydrologic Basins of the

Colorado River System , ....,....,., 369

The Upper and Lower Colorado River

Basins .*** **. ,.4,0 , ** , *.*c G* 370

Annual Average Virgin Flow of the

ColoradoRiverat Lee Ferry, W. . . . . 371

Ma\or Dams and Reservoirs on tha

Colorado River and Its Tribu~rim, . . . 372

FIowsofthe Colorado River~t~n ~ð

1953 and 1978 ● ● . ● ● ● ● ● ● ● ● ● ● * ● ● % ● * . 373

Bedrock Ground Water Aquifen in

Colorado’ sPiceance Basin ,., ., ...., 374
CHAPTER 9

Water Availability

Introduction

The oil shale deposits are located within

the Upper Colorado River Basin, which includes the Colorado River and its tributaries

north of Lee Ferry, Ariz, These waters are

critical resources in the semiarid region.

They are used for municipal purposes, irrigated agriculture, industry and mining, energy development, and maintaining recreational, scenic, and ecological values. In the past,

natural flows within the basin along with

water storage and diversion projects have

generally been adequate to satisfy demand.

In the future, however, water resources may

be taxed by rapid population growth, by accelerated mineral-resource development, and

by increased recreational activities. Eventually, the availability of water may limit regional growth including the expansion of industrial developments such as oil shale.

This chapter analyzes the availability of

water in the oil shale region. The following

subjects are discussed:

Summary

Surplus surface water will be available to supply

an industry of at least 500,000 bbl/d through 2000

if:

●

●

●

additional reservoirs and pipelines are built;

and

demand for other uses increases no faster than

the States’ high growth rate projections;

and

average virgin flows of the Colorado River do not

decrease below the 1930-74 average (13.8 million acre-ft/yr).

Otherwise, surface water supplies would not be adequate for this level of production unless other uses

were curtailed, interstate and international delivery

obligations as presently interpreted by the Government were not met, or other sources of water were

estimated water requirements for oil

shale facilities and their related growth;

the surface water and ground water resources of the oil shale region;

the laws, compacts, treaties, and other

documents that allocate the waters of

the Colorado River system;

the appropriation doctrine of Colorado,

Utah, and Wyoming for distributing

water supplies within State boundaries;

the Federal reserved right doctrine:

the physical availability of surface

water for oil shale development;

strategies and costs for utilizing water

supplies;

the uncertainties affecting water resource assessments;

the impacts of water use;

some methods for increasing water

availability; and

the policy options that might be implemented to increase the availability of

water.

Findings

developed. On the other hand, if the reservoirs and

pipelines are built, flows do not decrease, and the

region develops at a medium rate (which the States

regard as more likely), there should be sufficient

surplus water to support an industry of over 2 million

bbl/d through 2000.

In the longer term, surface water may not be adequate to sustain growth; surplus water availability is

much less assured after 2000. If the river’s flows do

not decrease, and if a low growth rate prevails, demand will exceed supply by 2027 even without an oil

shale industry. With a medium growth rate, the surplus will disappear by 2013. A high growth rate will

consume the surplus by 2007, again without any oil

shale development. This is a potentially serious problem for the region, and its implications for oil shale

359
360 ● An Assessment of 011 Shale Technologies

development are controversial. On the one hand it is

argued that there is no surplus surface water and

this should preclude the establishment of an industry. On the other hand, it it maintained that the

facilities in a major industry could function for much

of their economic lifetimes without significantly interfering with other users, and in any case would use

relatively little water. (A 1-million-bbl/d industry

would accelerate the point of critical water shortage

by about 3 years if only surface water were used. )

Other findings are:

● Depending on the process used, production of

50,000 bbl/d of shale oil syncrude would consume 4,900 to 12,300 acre-ft/yr of water, including water for related municipal growth and

power generation.

● A million bbl/d industry would require about

170,000 acre-ft/yr. * This would be about 1

percent of the virgin flow of the Colorado River

at the boundary of the Upper Basin, about 3

percent of the water consumed at present by all

users in the Upper Basin, and about 2 percent

of projected consumption in 2000.

● Potential oil shale developers already own rights

to substantial quantities of surface water. In

1968, for example, five companies claimed

rights to enough water to produce several million bbl/d of shale oil.

● Existing developer rights would probably not

assure supplies because surface water is overappropriated and oil shale rights could be interrupted during shortages. More reliable supplies

could be provided through purchase of surplus

water from existing Federal reservoirs, purchase of irrigation rights, ground water development, and importation of water from other hydrologic basins.

● Costs of the most expensive water supply option, importation from other basins, could exceed $0.80/bbl of shale oil produced. Other

strategies would cost less than $0.50/bbl of oil.

These costs include the amortized costs of res-

* I+>or comp:]rison, irrigated [agriculture along the White

River and the Colorado River consumes about 549,000 acreft/yr to produce 3 percent of Colorado’s crop production. This is

equ ivn]ent to the wn ter needs of a 3. 2-mill ion-bbl/d oil shale in-

(iustrv.

●

●

●

●

●

ervoir and pipeline construction and the cost of

treating the water to industrial standards. Development of high-quality ground water would

be least expensive but would be limited to specific areas.

All strategies that relied on surface water would

require construction of new reservoirs and pipelines, principally in the White River basin in Colorado and Utah. About 180,000 to 230,000

acre-ft of new storage would be needed for a 1-

million-bbl/d industry. Active capacity of existing reservoirs in the Upper Basin is about 34.7

million acre-ft. New construction for oil shale

would increase storage by less than 0,6 percent.

If a 2-million-bbl/d industry were developed,

flows of the Colorado River would be reduced,

and its salinity could increase by approximately

2 percent. Studies by the U.S. Water and Power

Resources Service (WPRS)* and the Colorado

Department of Natural Resources (DNR) indicate that the economic losses from these

changes could reach $25 million per year by the

year 2000–the equivalent of $0.04/bbl of oil

produced.

Sale of irrigation water to oil shale developers

would reduce farm production. At present, developers do not plan to purchase such water in

significant quantities. Therefore, effects on the

farming industry should be small, especially

compared with the effects of competition for

labor and the purchase of farmlands for municipal growth.

Studies by USBR and DNR indicate that environmental impacts of water-resource development for oil shale should be small overall on the

Upper Basin but could be large in some areas.

Fish habitats and recreational activities along

the White River are expected to be the most

severely affected. Impacts on the Lower Basin

are not expected to be substantial.

Regional development could be limited by water

availability after 2000. Importation of water

from other basins, conservation by municipal,

agricultural, and industrial users, and possibly

*Formerly the U.S, Bureau of Recltimation (USBR), For ease

of reference, most citations in this ch{)pter are to the USBR.
Ch 9–Water Avai/ability ● 361

weather modification could make additional

quantities available. The extent of the increase

cannot be predicted accurately, and the strategies could be impeded by legal, institutional,

and economic factors.

Analysis of Water Requirements for Oil Shale Facilities*

Introduction

Water will be used for oil shale mining and

retorting, for shale oil upgrading, for revegetation and spent shale disposal, and for supplying the increased population and other related activities that will accompany the establishment of a shale oil industry. More

water will be needed for final refining but

this operation can be carried out at other locations. In the early years of the industry,

some shale oil will probably be refined in the

oil shale region and nearby in Denver and

Salt Lake City. Water is also scarce in these

areas. However, the refineries are presently

consuming water for processing conventional

petroleum. Shale oil will merely displace the

conventional feedstocks, thus its refining will

not add significantly to water requirements.

In the long run, the output of a major industry —— . . —..

*’I’his ,in[ilysis :)ssumf:s th:it th(? qu:intlly of wtit(;r rernokfx!

for il giken purpose from [I stre:]m or ;lquifcr ( the w;] ter requirement] is numcri(:allv WIUH 1 tt) the qu:]nl i tv m:ldc un:)~t~ ililt)l[~ for SUt)S[>(]U[:Ilt 11S(?S IIh[: u :]ter (consumption ].” “1’his

:) ssu mp t ion is (’onsis t en t w i t h prcscn t (ievclopcr ~)li] ns for ~,[?ro-

(Iis(’h[i r~c w.{i ter m:i n:igcmen t svs terns,

would be refined in the Midwest where water

is abundant.

Estimates of water consumption vary widely. In the following section the most recent

estimates for alternative technologies on specific sites are analyzed, and then compared

with estimates of regional water availability

in order to identify the level of shale oil production at which water resources might limit

further development.

Process and Facility Models Analyzed

Facilities that use six retorting processes

are described in table 71. The processes were

selected for analysis because of their advanced development and because data have been

published on their water requirements. The

processes fall into three generic classes:

directly heated aboveground retorting (AGR),

indirectly heated AGR, and modified in situ

(MIS) retorting. The facilities modeled are:

1. TOSCO 11 indirectly heated AGR,

2. Paraho directly heated AGR,

Table 71 .–Process Models for Oil Shale Facilities

— —

ReferTechnology Study encea

TOSCO Ilb

Colony 3

TOSCO Ilb WPA/DRl 1

Paraho direct McKee-Kunchal 4

Paraho direct WPA/DRl 1

Paraho Indirect McKee-Kunchal 4

Union ‘ ‘B’ b

Eyring/Sutron 10

Oxy MIS Oxy 5,9

Oxy MIS WPA/DRI 1

Oxy MIS + Lurgi WPA/DRl 1

Colorado Iocation

Davis Gulch

Davis Gulch

Anvil Points

Anvil Points

Anvil Points

Parachute Creek

Tract C-b

Tracts C-a or C-b

Tracts C-a or C-b

Shale

grade

gall ton

35

35

30

29

30

34

24

25

25

Shale 0il capacity

47,000 bbl/d syncrude

47,000 bbl/d syncrude

87,000 bbl/d syncrude

99,170 bbl/d crude

76,000 bbl/d syncrude

100,000 bbl/d syncrude

57,000 bbl/d crude

57,000 bbl/d crude

81,000 bbl/d crude

Byproducts, ton/d

AmOther major product Coke Sulfur monia

LPG 4,330 bbl/d 800 173 135

LPG 4,330 bbl/d 800 173 134

Low-Btu gas 32 billion 650 136 290

Btu/d

Electricity 155 mWc

o 132 146

Low-Btu gas 6 billion 650 136 290

Btu/d

(d) d

Electricity 350 mWe

o 92 0

Electricity 97mWc

o 144 281

Electricity 140 mW o 172 281

‘See reference I ISI dl eod of chapter bElec:rlcify purchased ‘Open cycle qas ‘urblnes ‘Data not provioed ‘Commned cycle system

SOURCE R F Probste!n e: al W’dfer l?e~wre~eofs PO I u?mri Effects dod COSIS O( kV.a[er SIIDply Jnd Tfe~fmem for foe 011 Sha/e ,ndwfr~ reporl prepared for OTA by Water Purllcaf,on Associates Oclo~er

+ ~79 D 4
— —

362 An Assessment of Oil Shale Technologies

3.

4.

5.

6.

Paraho indirectly heated AGR,

Union Oil “B” indirectly heated AGR,

Occidental Oil Shale’s directly heated

MIS retorts, and

a combination of directly heated MIS

retorts and Lurgi-Ruhrgas indirectly

heated AGR.

The water requirements of these facilities

were scaled to a common basis of 50,000

bbl/d of synthetic crude oil. Thus, units for

upgrading crude shale oil to a high-quality

synthetic crude are included. Each facility

generates sufficient electric power for its

own needs, and all solid waste dumps are revegetated. Wastewater is recycled wherever

practical, and only excess mine drainage

water is discharged or reinfected. Disposing

of solid wastes by slurry backfill, either to the

mine or to the burned-out in situ retorts, is not

included. The effects of byproduct coke, ammonia, sulfur, or gas are not evaluated. True

in situ processes are not analyzed because no

data are available.

With the exception of the Union “B” plant,

each estimate discussed in this section is derived from a published conceptual design, 1-9

either the developer’s or one that has been

modified to put plant material and energy balances on a consistent basis. Although little information has been published, the Union

process is considered here because plans for

a plant have been announced. ’() However, the

data cannot be treated with the same confidence as for other processes.

A number of other studies’ ’-” have been

completed but are not discussed in this section. Although they were based on data supplied by the developers, their conclusions did

not agree because different retorting procedures, products, production rates, power

supply modes, shale grades, and disposal procedures were assumed.

Water Requirements

The water requirements of the six oil shale

facilities, after scaling, are summarized in

table 72. As can be seen, even facilities that

use similar processes (e. g., indirect AGR) require different amounts of water. However,

when the requirement for each subprocess is

represented as a percent of the total, there is

a correlation among different plants that use

similar kinds of technology, as shown in table

73. It is noteworthy that:

 Mining and dust control require considerably more water in AGR than in either

MIS or MIS/AGR. This is because about

Table 72.–Water Requirements and Mine Drainage Production for 50,000-bbl/d Oil Shale Facilities (acre-ft/yr)

Retorting technology

Study

Reference

Unit operation

Mining and handling.

Power generation .,

Retorting and upgrading

Shale disposal and

revegetatio n

Municlpal use

Net water requirements

In acre-ft/yr . ,

In bbl water/bbl 011.

Mine drainage water

In acre-ft/yr .

In bbl water/bbl oil,

Paraho direct TOSCO II

McKeeKunchal WPA/DRI Colony WPA/DRl

4 1 3 1

Paraho

Indirect Union ‘'B” Oxy MIS MIS/AGR

McKee- EyringKunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl

4 9 5 9 1 1

816 941 1,045 1,045

665 (b) 1,233 1,233

2,616 2,375 5,038 3,821

1,644 1,385 3,895 3,956

645 645 594 594

6,386 5,346 11,805 10,694

271 2.27 5.02 4.53

(b) (b) (b) (b)

(b) (b) (b) (b)

934 – 483 483 338 326

761 1,233 (b) (b) (b) (b)

3,487 1,470 9,234 2,502 3,601 3,051

4.020 3,090 2,818 1,103 1,103 1,461

731 731 775 775 775 818

9,933 6,524 13,310 4,863 5,817 5,656

4,22 2 7 7 5.66 2.06 2.47 2.40

(b) (b) 6,440-16,1004.032-6,452 12,326 8,454

(b) (b) 2.74-6,86 1,56-2.50 5.25 3.60

a.$ee reference IISI at end of chapter

bNot apPllcab[e for projector Site analyzed

SOURCE R F Probslem et al Wafer Reqwrenrerrfs Po/M/on IIfecfs arm Costs of Wafer Supply and Treafcnenf (or the 0/( Shale hrdusfry reporl prepared for OTA by Water Punhcallon Assoc!ales October

1979 p 8
Ch 9–Water Availability c 363

Table 73.–A Comparison of the Water Requirements

of the Various Subprocesses

Generic technology (in percent)

Indirect and

Subprocess direct AGR MIS/AGR MIS

Mining and handling 9-18 4-1o

Power generation 8-12 ( a (a)

Retorting and upgrading 35-44 54 51-69

Disposal and revegetation 26-40 26 19-26

Municipal us e 5-12 14 6-16

a~ot applicable ‘or project or slfe

SOURCf

●

●

R F Probsfeln et al Waler Ftequfremerrls PoI/ufIorI EVec[s am Costs of Waler Sup

Dly and r[ewrnenl for Ihe O// Shale /ndu$vj reporl orepared for OTA by Water Purlhca

IIon Associates October 1979 D 9

four times as much shale is mined and

handled in aboveground processing. The

larger amount of material also results in

high water requirements for disposal

and revegetation.

No water is needed for power generation

in MIS and MIS/AGR because power will

most likely be generated by burning lowBtu gases in open-cycle gas turbines that

do not need to be cooled. Even if combined-cycle systems were used, very little cooling water would be needed. Cooling water is needed for AGR because solid-fuel steam-cycle systems will probably be used,

Municipal water needs are proportional

to the number of mine and plant employees. For the same output, more workers

are required for MIS (about 1,800) than

for AGR (about 1,400 to 1,700). It is assumed that the MIS/AGR process would

require slightly more workers (about

1,900) than either technology by itself.

Retorting and upgrading require the most

water. All the technologies need comparable

amounts of water for upgrading, therefore,

the differences among alternate technologies

reflect differences in retorting efficiencies.

The large differences between similar above-

-ground technologies result from specific operating characteristics, especially the methods

for heating the retort and for disposing and

reclaiming the spent shale, More water is required for indirect than for direct AGR because indirect heating has a significantly

lower overall thermal efficiency,

Spent shale disposal and reclamation require large amounts of water in the TOSCO II

and Paraho indirect designs (about 4,000

acre-ft/yr), while the estimate for the Paraho

direct process is about 60 percent lower,

Largely because of this difference, the overall requirement for Paraho direct is only

about 5,900 acre-ft/yr, while the TOSCO II

and Paraho indirect designs need about

10,500 acre-ft/yr or almost twice as much.

The requirements for MIS retorting and

upgrading are similar to those for indirect

AGR. However, because little water is needed

for mining and waste disposal, overall water

requirements for MIS are similar to those for

direct AGR; that is, about 5,800 acre-ft/yr.

For similar reasons, the requirements for

MIS/AGR are similar to those for MIS alone.

It has been assumed that none of the AGR

plants will produce mine drainage water. The

MIS and MIS/AGR facilities, however, are

assumed to produce such water in substantial quantity. This difference is not related to

the technologies but rather reflects the siting

assumptions made for the various plants. The

MIS and MIS/AGR facilities are on tracts C-a

and C-b in the ground water areas of the central Piceance basin, while the AGR operations are in drier areas along the southern

fringe of the Piceance basin or the eastern

portion of the Uinta basin. Mining in ground

water areas produces mine drainage water

that must either be used, discharged, or reinfected. The amount produced varies with location, Estimates for tract C-b range from

4,032 to 16,100 acre-f t/yr16 and for tract C-a

to at least 18,100 acre-ft/yr. 17 This water

should be regarded as an alternate water resource and not as part of the process. Similar

operations in other locations may not produce

comparable amounts of water.

An Evaluation of Assumptions in

the Estimates

Detailed breakdowns of the water required

and produced by each principal operation in

each model facility are shown in table 74.

(Table 72 was derived from these data.)
364 ● An Assessment of 011 Shale Technologies

Table 74.–Breakdown of Water Requirements and Water Production for 50,000 -bbl/d Oil Shale Facilities (acre-ft/yr)

Paraho

Paraho direct TOSCO II indirect Union ‘ ‘B’ Oxy MIS MIS/AGR

McKee- McKe e

=

EyringKunchal WPA/DRl Colony WPA/DRl Kunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl

Water required

Mining and ore handling

Power generation

Retorting and upgrading

Cooling tower makeup

Retorting

Upgradin g

Other boiler makeup

Steam and treatment

los s

Service and fire water

Potable and sanitary

Disposal and reclamation

Shale moisturizing

Disposal and

compaction

Revegetation

Municlpal demand

934 (a)

952d1,850d

483

(c)

483

(c)

338

(c)

326

(c)

816 941

832b(c)

1,045

1,850b

1,045

1,850d

3,849 3,854’

— o

— 939d

1,224 490e

3,861

1,884

939

557

3,939

668

939

557

4,406 –

— —

— —

1,401 1 ,71Ob

6,875e

2,731

939d

985e

806

3,753

939d

525

4,494’

2,731

939d

551e

3,626e

1,873

939

529’

— 50

— 69

— 39

572

60

34

572

60

34

39

(a)

113

587

2,111

161

109

67

31

75

60

28

— —

— —

— —

(c) (c) 2.859 2,920 (c) – (c) (c) (c) (c)

1,664 972

413

1,61 4b

1,614b

428

608

1.485b

428

608

1,485°

— 2,870

4,020 220

1,829b

1,829b

1,208

1,610

1 ,937b

346

757

1 ,937b

346

757

1 ,937b

1,239’

222d

2,045d

Total required 9,979 9,378 16,182 15,105 13,542 8,479 16.920 12,405 12,300 10,962

Water produced

Power generation 167d (c) 617a 617d 191d617d (c) (c) (c) (c)

Retorting and upgrading

Cooling tower

blowdown . 768 1,653e 1,240 1,319 880 (a) 625e

(a) 1,038e

907e

Retort condensate 127 (a) (a) (a) 388 240 1,243 2,419 1,243 852

Gas condensate 752 542 728 728 125 – (a) 3,072 2,157 1,480

Upgrading

condensate s 540 l 0 3

d

103 103 618 (a) l 0 3

d

103 103 103

Boiler and treatment

wast e 270 487e

557 557 309 (a) 486e

384 530’ 513e

Service water effluent (a) 30 27 27 (a) (a) (a) 241 26 27

Potable and sanitary

effluent (a) 26 26 26 (a) (a) (a) 161 23 20

Surface runoff’ (a) 222 188 188 (a) (a) (a) (a) 201 177

Municipal effluent 969d

969d891 891d1.098d1,098 d1, 162d1, 162d

1, 162d

1,227d

Total produced 3,59 3 4,032 4,377 4,456 3,609 1,955 3,619 7,542 6,483 5,306

Net consumption

In acre-ft/yr 6,386 5,346 11,805 10,649 9,933 6,524 13.301 4,863 5,817 5,656

In bbl water/bbl oil. 271 2 2 7 5,02 4 5 3 4 2 2 2.77 5 6 5 2.06 2.47 2,40

Mine drainage

In acre-ft/y r (c) (c) (c) (c) (c) (c) 6,440-16,1004,032-6,452 12,326 8,454e

In bbl water/bbl 011 (c) (c) (c) (c) (c) (c) 2.74-6.86 1.56-2,50 5 2 5 3.60e

atiot prowded bincludes mlnlng and re10flm9 cNot apphcable ‘Esllmated by OTA ‘Modd)ed lor OTA

SOURCE R F Probsteln ef al Waler Reqwrerrrenls Po//u(/orr Effects and Cosfs of VLXer Supp/y and Trearmertl for [he Od Shd/e /rrUIJs/ry reporl prepared for OTA by Waler Purlflca[lon Associates October

1979 p 14

Paraho Direct sign assumed that a water-cooled steam cycle

would be used; the Water Purification Associates/Denver Research Institute (WPA/DRI)

design assumed that low-Btu gas would be

burned in open-cycle gas turbines that require no cooling water.

The two estimates for Paraho direct are

reasonably consistent. However, the McKee/

Kunchal water management plan is not sufficiently detailed for a thorough evaluation to

be made of the differences that appear. The

two designs differ principally in the mode of

power generation. The McKee/Kunchal deThe retorts are also operated differently. A

higher retorting temperature is assumed in
Ch 9–Water Availability ● 365

the WPA/DRI design, and the water produced

during retorting is vaporized and exhausted,

In the McKee/Kunchal design, lower temperatures cause partial condensation of the retort

water. Also, upgrading was not considered by

WPA/DRI, and it was necessary to adapt estimates from the TOSCO II plant design,

The chief uncertainty is the claim of minimal water needs for spent shale disposal. The

WPA/DRI design, which was based on this

claim, uses a conservative estimate of 5 percent by weight of water for compaction and

a separate estimate for revegetation. The

McKee/Kunchal estimate is not directly comparable because it combines compaction and

revegetation. However, the total values are

reasonably consistent.

Paraho’s claim that proper compaction can

be obtained with small water additions is

based on evidence from disposing about 150

ton/d of spent shale. It is uncertain that sufficient moisture could be extracted from the atmosphere to dispose of 72,000 ton/d, the output of a 50,000-bbl/d plant.

TOSCO II

Although the Colony water management

plan is very detailed, neither Colony nor

WPA/DRI assumed onsite power generation.

OTA’s analysis assumed that about 85 MW of

power would be generated by a steam-cycle

system.

A principal difference between the designs

is that WPA/DRI substituted a bag filter and

electrostatic precipitator for Colony’s venturi

wet scrubbers, thereby reducing water consumption. Both designs assumed that the

spent shale is moisturized to 14 percent by

weight of water to allow proper compaction.

For revegetation, both designs assumed an

average value of 608 acre-ft/yr over the 20-

year life of the plant. During the first 10

years, little revegetation would be done and

water would be used only for compaction and

dust control. In the second 10 years, revegetation programs would be expanded and

water needs would increase.

Paraho Indirect

It is not possible to fully evaluate the

Paraho indirect estimates because the

McKee/Kunchal report lacks a detailed water

management scheme. Compared with TOSCO

H, retorting and upgrading requirements appear low. Also, the requirement for revegetation is much higher than for all other retorts.

The reason given is the high carbon content of

the spent shale, but this conclusion is not supported by Union’s experience with similar retorted shale. The high estimates for revegetation may have been made to offset low estimates for compaction. l8

Union Oil “B”

Because only crude data are available,

judgment should be reserved on the low estimates for mining, retorting, and upgrading,

The Environmental Protection Agency (EPA)

recently published a considerably higher estimate for mining and processing that would

lead to a total consumption more in line with

estimates for other processes. 19 Unfortunately, the higher estimate cannot be verified because no background information was supplied. An older EPA document20 provides a

value for mining and processing consistent

with the Eyring/Sutron estimate. The relatively large requirement for spent shale disposal

is a consequence of Union’s method for cooling the hot retorted shale by immersing it in

water,

Occidental (Oxy) Modified In Situ

The older Oxy estimate differs significantly from the WPA/DRI design in both water requirements and water production. Oxy’s requirements are higher for cooling water, for

raw shale disposal, and for revegetation, It

appears that these uses were deemed appropriate for disposing of excess mine drainage

water. Much less water is wasted in the

WPA/DRI design and in the newer Oxy plan.

Also, the production of retort condensate was

not estimated in the older Oxy plan. The

WPA/DRI estimate (2,157 acre-ft/yr) was

based on Oxy’s estimates of the steam flows
366 ● An Assessment of 0il Shale Technologies

to the retorts. (Much more condensate would

be produced if ground water entered the retorts during their operation. ) WPA/DRI also

assumed that the retort gases are not compressed prior to gas cleaning. This reduces

the cooling water requirement, although it increases the cost of the gas cleaning equipment. The net difference (considering condensate production and cooling water reduction)

is about 6,700 acre-ft/yr, which accounts for

most of the discrepancy between Oxy’s older

plan and the WPA/DRI study. In general, the

WPA/DRI results agree quite well with Oxy’s

current water management plan.

Modified In Situ/Aboveground Retorting

The only published water management

plan for a combined facility is that of the Rio

Blanco project on tract C-a. Details are not

sufficient for a thorough evaluation and the

plan is now obsolete because Rio Blanco has

since revised its approach. The WPA/DRI

model, which combines MIS with Lurgi-Ruhrgas retorts, is similar to the current plans for

the tract.

The principal difference between OTA’s

process model and those of Rio Blanco or

WPA/DRI is that OTA has assumed surface

disposal of the spent shale, whereas the

others assumed that the waste is returned as

a slurry to the burned-out in situ retorts. In

OTA’s analysis, it is assumed that the vapor

losses during moisturizing are the same as in

underground slurry disposal. The estimates

for both revegetation and upgrading were

linearly scaled from the TOSCO II requirements. The accuracy limitations noted in the

MIS discussion also apply here.

Municipal Use

It is assumed that the total population

growth will be 5.5 times greater than the

number of employees.

21 Because this large

multiplier is applied to uncertain employment

figures, the estimates of municipal water

needs are approximate. An aggregate requirement of 175 gal/person/d has been

assumed, with consumption at 40 percent of

this figure, The net requirement—70 gal/person/d—is conservatively high. The average

requirement for all the facilities considered is

about 700 acre-ft/yr.

Mine Drainage Water

Probably the largest uncertainty of all,

because it is highly site dependent, is the

amount of mine drainage water produced. As

noted above, estimates for the Federal lease

tracts range from 6,400 to over 18,000 acreft/yr. This water should satisfy the processing

needs of the technologies proposed for tracts

C-a and C-b. However, these needs could

probably not be satisified by ground water on

sites along the edge of Piceance basin.

Range of Water Requirements

The most likely ranges of the quantities of

water that will be consumed by the three generic technologies and by the combined plant

are indicated in table 75, Also shown are the

likely ranges of mine drainage water production on tracts C-a and C-b. Overall, the requirements range from 4,900 to 12,300 acreft/yr—the equivalent of from 2.1 to 5.2 bbl of

water consumed for each barrel of oil produced. Given this range, a l-million-bbl/d industry could require from approximately

100,000 to 250,000 acre-ft/yr. Actual water

requirements would be determined by the

mix of technologies used. In table 76, these

requirements are estimated for an industry

that would result if present projects, both active and proposed, were completed. Some features of this industry are:

●

●

●

Indirect AGR, the method with the highest unit water requirement, constitutes

51 percent of the total production.

Direct AGR and MIS, which require less

water, constitute only 33 percent of production. The balance is provided by MIS/

AGR, which has an intermediate requirement.

About 43 percent of the production will

result from mining in ground water

areas in the central and northern Pice-
Ch. 9–Water Availability ● 367

Project

RIO Blanco

Cathedral Bluffs

Long Ridge

Colony

Sand Wash

EXXON

White River

Superior

Table 75.–Likely Ranges of Water Requirements and Mine Drainage Production

for Oil Shale Facilities Producing 50,000 bbl/d of Shale Oil Syncrude

Water requirementsa

Average shale grade,

Technology gal/ton Acre-ft/yr Barrels per barrel of 011

Directly heated AGR 29-32 4,900-7,800 21-3 3

Indirectly heated AGR 32-35 9,400-12,300 40-5 2

Directly heated MI S 23-27 4,900-5.900 21-2 5

MIS/AG R 23-25 5,700-6,700 2.4-29

Location Water production

Mine drainage wate r C-a/ C-b 4,000-16,100 1 6-69

a~el ~a[ef ~eqUlre~enls Low end assumes higher shale grade open cycle power systems high relorl efficiency and lower waste dls Posal and ‘eclama

lion needs High end assumes lower shale grade sleam cycle or comt)lned cycle systems low retorhng efficiency and higher disposal and ‘ec

Iamaflon needs

SOURCE R F Probsleln el al Wafer Re~wreme~fs PoI/ufIorI Ef(eck and Cos(s of Wafer SW@y and Treafrner?( for fhe 0// S/ra/e (ndus[ry re?orl pr e

oared for OTA by Waler Purihcahon Assoclales October 1979 p 22

Table 76.–Water Requirements for Active and Proposed Oil Shale Projects

Location

Central Piceance basin

Central Piceance basin

Southern Piceance basin

Southern Piceance basin

Uinta basin

Central Piceance basin

Uinta basin

Northern Piceance basin

Deposit

Design capacity

Barrels Percent

Technology per day of total

Wet

Wet

Dry

Dry

Dry

Wet

Dry

Wet

MIS/indirect AGR 76,000

MIS 57.000

Indirect AGR 75,000

Indirect AGR 46,000

Indirect AGR 50,000

Indirect AGR 60,000

Direct AGR 100,000

lndirect AGR 11,500

16

12

16

10

10

13

21

2

Water requirements acre-ft/yr

For 50,000 For design Weighted

bbl/d capacity contribution

6,200 9,424 - 992- –

5,400 6,156 648

10.850 16.275 1,736

10,850 9,982 1 085

10,850 10,850 1 085

10,850 13,020 1,411

6.350 12700 1,334

10,850 2,496 217

Total 475,500 100 80,903 8,508

SOURCE Off Ice of Technology Assessment

ance basin. These plants could obtain The following sections will use these estitheir process water from the aquifers in mates in conjunction with estimates of surthe mining zone. Surface water would plus surface water availability and other

not be needed. critical factors to identify the level of shale oil

The total production from this combination production at which water scarcity might re-

(475,000 bbl/d) would require 80,903 acre- strict development. The issues section of this

ft/yr, On this basis, a 50,000-bbl/d plant chapter discusses the industries that might

would need about 8,500 acre-ft/yr; a l-mil- result if a different mix of technologies were

lion-bbl/d industry about 170,000 acre-ft/yr. used or if ground water were developed,

Water Resources: A Physical Description

Surface water is obtained from rivers and Surface Water

streams; ground water from underground

aquifers. In some instances, these sources The Colorado River system, which includes

are physically connected and should not be the Colorado River and its tributaries, supevaluated independently. For example, if the plies surface water to the oil shale region.

ground water supplies in most Western The Colorado River flows 1,440 miles from

States were fully utilized, surface flows source to mouth. Its drainage area of 244,000

would decrease. m i

2 includes parts of seven States and Mex-
368 ● An Assessment of Oil Shale Technologies

ice. The waters of the Colorado River system

are divided between the Upper Colorado

River Basin (which includes parts of Colorado, Utah, Wyoming, Arizona, and New

Mexico), and the Lower Colorado River Basin

(which includes parts of California, Nevada,

Arizona, New Mexico, and Utah). (See figures

63 and 64. ) The basins are divided at Lee

Ferry, Ariz., 1 mile south of the Paria River

near the border between Arizona and Utah.

Six major streams enter the Colorado River

in the Upper Basin, From north to south, these

are the Green, the Yampa, the White, the

Gunnison, the Dolores, and the San Juan. The

drainage area of the Upper Basin has been divided into a number of hydrologic subbasins,

each corresponding to the watershed of a major river. Oil shale development may directly

affect three of these subbasins: the Green

River basin in the southeastern corner of

Wyoming; the White River basin, which includes parts of western Colorado and eastern

Utah; and the basin of the Colorado River

mainstem in Colorado.

Water quality in these streams is highly

variable. The quality in most of the upstream

reaches of major tributaries is good to excellent although some smaller streams that receive discharge from saline ground water

aquifers are of very poor quality. Water quality is significantly poorer in most downstream

areas. The gradual deterioration is caused by

flows of naturally saline streams into the

river system and by man-related discharges

from settlements, mineral development sites,

and irrigated farmlands, Water quality and

the problems it causes are discussed further

in chapters 4 and 8.

The Colorado River system drains an extensive area, but its flows are relatively

small. The average annual virgin flow* at Lee

Ferry was 13.8 million acre-ft/yr between

*Virgin flow is the flow that would occur in the absence of

human activitv. Most of the water availability analyses in this

chapter deals with the 1930-74 average because of its common

use in other water resources analyses. The effects of different

assumptions rega rcling virgin flow are discussed in the issues

sect ion,

Upper Colorado River near Rifle, Colo.

Photo credit OTA staff
Ch 9–Water Availability 369

Figure 63. —Major Hydrologic Basins of the Colorado River System

MONTAN A

/

OREGO N

WYOMIN G

r

I

NEVAD A UTAH UPPER COLORADO

L \ RIVER BASIN

L

SOURCE U S Bureau of Reclamation Cr/f/Ca/ Wafer PrOb/erns Facing the E/eVen western ~fafes— Wesfwldestudy VO/u~e/ &faln ffeporfNTIS NO PB-263 981 Den

ver ColoAprtl 197 5

1930 and 1974, in contrast to about 180 mil- nicipalities, agriculture, energy production,

lion acre-ft/yr for the Columbia River and 440 industry and mining, recreation, wildlife,

million acre-ftlyr for the Mississippi River. Federal lands, and Indian reservations all

Despite its relatively low flows, the system is compete for its waters.

one of the most important in the Southwest. It Flows vary seasonally, increasing with

serves approximately 15 million people. Mu- spring snowmelts and heavy rainstorms in
—

370 ● An Assessment of Oil Shale Technologies

Figure 64.—The Upper and Lower Colorado River Basins

i I \ 1

. CASPER

- 1

/“ /’+“ “L‘ja~e

t:” +

Great -..

k

Salt .’

I -1,.-.

w ‘a’”

● DENVER

(

I

,.

MEXIC O

t 1

100 MILES

SOURCE: C. W. Stockton and G. C. Jacoby, “Long-Term Surface-Water Supply and Streamflow

yses,” Lake Powell Research Pro/ect Bu/let/n No. 18, March 1976, p.2

i

Trends In the Upper Colorado River Basin Based on Tree-fllng Anal.
Ch 9–Water Availability ● 371

the late summer and fall and declining during

the rest of the year. They also vary from year

to year, as shown in figure 65. Flow records

and examination of vegetation growth cycles

indicate that they may also vary over a much

longer period, spanning decades or even centuries. The fact that virgin flows at Lee Ferry

between 1906 and 1974 averaged about 15.2

million acre-ft/yr while between 1930 and

1974 they averaged only 13.8 million acreft/yr is evidence of this long-term variability y.

The flow variations are significant because

they reduce the accuracy of long-term projections of water availability. They also furnish

a rationale for building reservoirs to offset

seasonal fluctuations and stabilize supplies

during dry years. Several reservoirs have

been built in the Upper Basin for this purpose. The five largest were built by the Federal Government under the Colorado River

Storage Project Act (CRSP) of 1956: Lake

Powell in Arizona and Utah, Flaming Gorge in

Utah and Wyoming, Fontenelle in Wyoming,

Navajo in New Mexico, and the Curecanti

Unit (which includes the Crystal, Morrow

Point, and Blue Mesa Reservoirs) in Colorado.

These projects have been completed and are

now being filled, When full, the existing

reservoirs will have a maximum active storage capacity of about 35 million acre-ft/yr.

Lake Powell is by far the largest, and will

have an active capacity of about 25 million

acre-ft. Other reservoirs have been authorized by Congress but funds have not yet been

appropriated for their construction. These include the Savery Pothook, Fruitland Mesa,

and West Divide projects. The locations of the

existing CRSP reservoirs are shown in figure

66.

Reservoirs have been effective in dampening the fluctuations in the virgin flows. This is

illustrated in figure 67, which compares actual measured flows of the Colorado River at

Lee Ferry with the corresponding estimates

of virgin flows for the period 1953-78. The

Flaming Gorge and Navajo Reservoirs began

filling in 1962; Lake Powell in 1963, and

Fontenelle in 1964. During prior years, actual

flows varied widely, from 6 million acre-ft/yr

to over 17 million acre-ft/yr. In 1962, the acFigure 65.—Annual Average Virgin Flow of the Colorado River at Lee Ferry, Ariz.

2 6 -

2 4 -

2 2 — HISTORI C

20- FLOW—

—

PAST DEPLETION

)

PLUS CRSP STORAGE

AVERAGE

VIRGIN FLOW

u<

PROGRESSIVE 10 YEAR

r

1922-78

AVERAGE OF VIRGIN FLOW AVERAGE

r ‘ (Plotted at end of year) VIRGIN FLOW

iL

[~ ~

i

F1

1

IL N. N

omo

\

\

—

I

WATER YEAR

——

ill

0

%

—

—

4

II

1!-1-

0

b

m

SOURCE Upper Colorado River Commlsslon. Thlrt/efhAnnua/Reporf. Salt Lake City, Utah, Sept 30, 1978, p 44
372 ● An Assessment of Oil Shale Technologies

Figure 66.— Major Dams and Reservoirs on the Colorado River and Its Tributaries

WYOMING,, t1

NEVADA

● cARSOmJ CIT’Y

Y

# - a., -... -- MM Hew

r

o

Ii

o Colorado River Storage Project Act Dam and Reservoir

SOURCE Upper Colorado River Commlssmn, Th/rf/ethAnnua/ Report, Salt Lake City. Utah, Sept 30, 1978. p. 44
Ch 9–Water Availability ● 373

u

— Actual Flow

— - — Vlrgln Flo w

? 1

;

-r

~::

--

i%%ggg;g$:$

YEAR

SOURCE Upper Colorado River CommlsslonTtrfrtfethAnnua/ Report Salt

Lake City Utah, Sept 30.1978. p 44

tual flow dropped substantially, partly because of low virgin flow and partly because of

the start of reservoir filling. In 1968, the actual flow approached 8 million acre-ft/yr and

has remained within the range of 8.23 million

to 10.14 million acre-ft/yr ever since. Between

1968 and 1978, virgin flows ranged from 5.5

million to 19.3 million acre-ft/yr. Actual flows

have not yet stabilized because the reservoirs

are still filling.

Ground Water

Ground water resources occur near the

surface in alluvial (floodplain) aquifers and

more deeply buried in bedrock aquifers. In

most areas, alluvial aquifers contain relatively little water. The amount in bedrock aquifers is unknown but is though! to be very

large. It has been estimated that bedrock

aquifers in the Piceance basin could contain

as much as 25 million acre-ft in storage. This

is nearly twice the annual virgin flow of the

Colorado River at Lee Ferry and is equivalent

to the storage capacity of Lake Powell. The

primary bedrock aquifer near Federal tracts

U-a and U-b in Utah is estimated to contain at

least 80,000 acre-ft.

The actual quantities of ground water that

could be used for oil shale development are

uncertain. The amount available is determined by the location of the aquifers relative

to potential plantsites, the water quality, and

physical characteristics such as the depth

and the recharge rate. The physical characteristics determine the quantity of water

that can be stored or extracted, the rate at

which water can be added or withdrawn, and

the change in water levels that will result

from withdrawing a given volume of water.

The principal aquifers of the Piceance basin are located in the Uinta and Green River

geologic formations. (See figure 68.) The system is characterized by two bedrock aquifers, the “upper” and the “lower,” that are

separated by a 100- to 200-ft-thick confining

layer of rich oil shale known as the Mahogany

Zone. In addition, alluvial aquifers occur in

gravel, sand, and clay along the bottoms of

stream and creek valleys.

The bedrock aquifers are recharged by

springtime snowmelt, which replaces an estimated discharge of 26,110 acre-ft/yr. Water

enters the upper aquifer along the basin

margins above an altitude of 7,000 ft and

moves downward through the Mahogany

Zone to recharge the lower aquifer. Generally, ground water in both of these aquifers

flows from the recharge areas toward the

discharge areas in the north-central part of

the basin. In the discharge areas water

moves upward from the lower aquife r

through the Mahogany Zone to the upper

aquifer and is discharged both to the alluvium and by springs along the valley walls.

Ultimately, the discharged ground water

flows into Piceance and Yellow Creeks and

then into the Colorado River system. 22
— —

374 ● An Assessment of 011 Shale Technologies

Figure 68.— Bedrock Ground Water Aquifers in Colorado’s Piceance Basin

West East

8000’ 1

7000’

6000’

5000’

4000’

1

I Vertical Exaggeration x PO Wasatch formation

3000’ I

– 8000’

- 7000’

—

- 6000’

- 5000’

- 4000’

3000’

2

~

6 miles

Datum is mean sea level

m9 : ...”O “9 e .,’e. n n El -. . . ., 0, u:::.:.:.: ....O.O.O

Sand & gravel Sandstone Marlstone Marlstone, contains High

&/or conglomerate &/or siltstone oil shale & saline minerals rewstivity zone

LEGEND

SOURCE Department of the Intenor, Draft Envlronrnental Sfaternenf-Proposed Deve/opmenfof 0// Sha/e Resources by fhe Co/onyDeve/oprnenfOperaf/onIn Co/o.

rado, Bureau of Land Management (1975), p Ill 34

Despite the large resources, little ground little water is withdrawn, and the ground

water development has taken place to date. z water system is in hydrologic equilibrium.

The major economic use is for watering live- That is, the rates of recharge and discharge

stock. In addition, natural seeps and springs are equal and the amount of water in storage

supply water to vegetation and wildlife in does not change significantly over time.

many of the valley floors. Overall, relatively

Allocation of the Colorado River System Waters

Because of competing demands, disputes preme Court decisions, and international

over the proper allocation of water resources treaties has been developed to govern distrihave permeated the political, social, econom- bution of the system’s waters. Together, the

ic, and legal histories of the seven States in provisions of this framework comprise “the

the Colorado River system. As a result, a com- law of the river.” Their interpretation is cruplex framework of interstate and interra- cial to an understanding of the water availgional compacts, State and Federal laws, Su- ability problem.
Ch. 9–Water Availability . 375

Compacts, Treaties, and

Legal Mechanisms

The Colorado River Compact of 1922

The major provisions of this compact are:

1.

2.

3.

It divided the river system into the Upper

and Lower Basins, and allocated 7.5 million acre-ft/yr to each basin for beneficial consumptive use, Authority was

also given to the Lower Basin to increase

its annual use by 1 million acre-ft.

It did not recognize a specific obligation

to provide water to Mexico. However, a

framework was established whereby

any future obligation would be shared

equally between the Upper and Lower

Basins.

The Upper Basin was prohibited from reducing the flow at Lee Ferry to below an

aggregate of 75 million acre-ft in any 10-

year period. The Upper Basin was not to

withhold water, nor was the Lower Basin to demand water that could not reasonably be applied to domestic and agricultural uses.

The Boulder Canyon Project Act of 1928

This Act provided for the construction of

Hoover Dam and its powerplant, and for the

All-American Canal. Its major provisions are:

1.

2,

3.

It suggested a specific framework for

apportioning the water supplies allocated by the compact of 1922 among the

Lower Basin States of California, Arizona, and Nevada. (The States did not

adopt this framework, but it was later

imposed on them by the Supreme Court

decision in Arizona v. California, as discussed below.)

It required California to reduce its annual consumption to 4,4 million acre-ft

plus not more than half of the surplus

water provided to the Lower Basin. (This

requirement was met through the California Limitation Act of 1929.)

It authorized the Secretary of the Interior to investigate the feasibility of projects for irrigation, power generation,

and other purposes.

The Upper Colorado River Basin

Compact of 1948

In this compact, the Upper Basin States apportioned the water allocated under the compact of 1922. The negotiators recognized the

problem inherent in allocating water on a

strict quantity basis because of flow fluctuations from year to year. As a result, water

was apportioned on a percentage basis to all

States except Arizona. Major provisions of

the compact are:

10

2.

3.

Arizona was guaranteed 50,000 acreft/yr, The remaining water was apportioned as follows:

● to Colorado: 51.75 percent,

● to New Mexico: 11.25 percent,

● to Utah: 23.00 percent, and

● to Wyoming: 14.00 percent,

It recognized that new reservoirs would

be needed to assist the Upper Basin in

meeting its delivery obligation to the

Lower Basin. Such reservoirs, however,

would increase evaporative losses from

the river system as a whole, thus reducing the quantity of surplus water available to the Lower Basin. The compact

provided that charges for such evaporative losses be distributed among the Upper Basin States. Each State was to be

charged in proportion to the fraction of

the Upper Basin’s water allocation that

was consumed in that State on a yearly

basis, and its maximum consumptive use

was to be reduced accordingly.

It provided for the division of water between pairs of States on a number of

specific rivers. The compact did not deal

with the White River, which delivers approximately 500,000 acre-ft/yr to the

Utah State line and which could supply

water for energy development.

Mexican Water Treaty of 1944-45

As part of negotiations over apportionment

of water from the Rio Grande, Tijuana, and
376 ● An Assessment of 0il Shale Technologies

Colorado Rivers, the United States guaranteed to deliver at least 1.5 million acre-ft/yr of

water to Mexico. However, in times of severe

drought or in the event of a failure in the

delivery systems, Mexico could receive less

than 1.5 million acre-ft/yr.

Colorado River Storage Project Act of 1956

This Act provided for several new storage

reservoirs to assist the Upper Basin States in

meeting their delivery obligation to the Lower

Basin, while simultaneously increasing water

consumption in the Upper Basin. The five

CRSP reservoirs that have since been built

were described in the earlier discussion of

the fluctuating flows of the river.

The Supreme Court Decree in

Arizona v. California

This decision (376 U.S. 340 (1964)) imposed

upon the Lower Basin States the water distribution framework that had been suggested by

the Boulder Canyon Project Act of 1928. The

Lower Basin’s water allocation of 7.5 million

acre-ft/yr was to be apportioned as follows:

● to California: 4.4 million acre-ft/yr,

● to Arizona: 2.8 million acre-ft/yr, and

● to Nevada: 0.3 million acre-ft/yr.

The decree also required that approximately

1million acre-ft/yr from the allocations to

California and Arizona be diverted for the

five Indian tribes located along the lower Colorado River.

Colorado River Basin Project Act of 1968

This Act instructed the Secretary of the Interior to propose criteria for the coordinated

long-range operation of reservoirs built under

the Boulder Canyon Project Act and the CRSP

Act. Criteria were subsequently established

and now form the basis for operation of the

reservoirs. (These operating criteria are of

importance in estimating water availability in

the Upper Basin States, as discussed below.)

The Act also identified the Mexican Water

Treaty as a national obligation, to be considered in developing any subsequent water

projects. It prohibited the Secretary from

studying importation of water into the Colorado River Basin until 1978. (This moratorium

was subsequently extended to 1988 by the

Reclamation Safety of Dams Act of 1978.)

Surface Water Allocations

Each of the above documents assumes different values for the quantity of virgin flow

past Lee Ferry. They therefore differ with respect to the total amount of water to be apportioned. In general, each State can interpret the law of the river so as to maximize its

water-resource position and can develop its

water programs on that basis. Consequently,

an analysis of the opportunities for further

growth in the Upper Basin States is clouded

by uncertainty, and it is not possible to predict with any exactitude the maximum size of

the oil shale industry that could be accommodated.

The annual virgin flows assumed in some

of these documents are shown in table 77.

Table 77.–Estimates of Surface Water Allocations to the Oil Shale States (millions of acre-ft/yr)

Virgin flow

Source of virgin flow estimate at Lee Ferry Colorado Utah Wyoming Total

Colorado River Compact of 1922 . . . . . . ... ., . . 180 5.06 2.25 1.37 8.68

Mexican Water Treaty of 1944 -45...... . . . 16.2 4.12 1.83 1,12 7,07

Upper Colorado River Basin Compact of 1948. , ., ., 15,6 3.81 1.70 1.03 6.54

Colorado River Basin Project Act of 1968 . . 14.9 3.45 1.53 0,93 5.91

Average flow 1930 -74. . . . . . . . . . . . . . . . . . . . . . . . . 13.8 2.88 1,28 0.78 4.94

Assumes dehvery of 823 mllhon acreft/yr to Lower Basin Slates and Mexico 7500000 acre-ft/yr 10 Lower Basin (per 1922 compact) plus 750,000 acre-ft/yr 10 Mexico (per Mexican Waler Trealy of

1944-45) less 20 OOOacre-ff/yr Inflow from the Pana River below Lake Powell = 8230000 acre-ft/yr Neglecfs evaporafwe losses from Upper Basin reservoirs Assumes apportionment among the 011 shale

Slates according to the Upper Colorado Rwer 8asm Compact of 1948

SOURCE Ofhce of Technology Assessment
Ch 9–Water Availability 377

Also shown is the average virgin flow at Lee

Ferry between 1930 and 1974. For each flow

figure, the corresponding gross quantity of

surface water allocated to each oil shale

State is also shown. It was assumed that the

Lower Basin States receive 8.23 million acreft/yr out of the Lake Powell Reservoir above

Lee Ferry, as called for in the operating criteria prepared under the provisions of the

CRSP Act of 1968. As indicated, the quantity

of surface water available to the three States

under the terms of the various documents

could be as low as 4.94 million acre-ft/yr and

as high as 8.68 million acre-ft/yr. The lower

figure is more realistic for planning purposes,

Doctrine of Prior Appropriation

Introduction

The water rights policies of Colorado,

Utah, and Wyoming are, in general, similar.

Their respective constitutions hold that water

is the property of the public, not the landholder, and that it is the State’s responsibility to

apportion rights to use water among competing users, Each State administers surface

water rights and some ground water rights

according to a doctrine of prior appropriation, This differs from the riparian doctrine

that prevails in most Eastern States under

which water rights are automatically the

property of the owner of the land on which

the water is found. Under the prior appropriation doctrine, water rights are severable

from the land, and one may own water rights

without owning any land whatsoever.

Surface Rights

The key elements of the doctrine of prior

appropriation are: the specific types of water

rights, the seniority system for determining

priority of use, the preference system for distinguishing among types of water uses, options for transfer of water rights between

parties, and policies for determining the

abandonment of water rights.

Types of Water Rights

There are two categories of water rights:

conditional and absolute. A potential user acquires a conditional water right by filing for a

conditional decree from the State water

courts and then proceeding diligently towards the actual use of the water. An absolute water right is created when a holder of a

conditional right perfects that right by actually diverting the water and applying it to a

beneficial use. Beneficial uses have been defined to include any use in which water is not

wasted.

Within each category there are two types

of water rights. A direct flow or diversion

right permits the diversion of water from a

stream followed by its immediate application.

A storage right permits the impoundment of

water for later application. None of the three

States recognizes the right of private parties

to require that sufficient stream flows be

maintained for the protection of instream

uses, such as rafting and fishing. However, a

Colorado law permits that State to obtain water rights for sufficient flows to preserve the

natural environment to a reasonable degree.

In Colorado, the water rights are adjudicated by the State Water Courts and administered by the State engineer. The right to appropriate water is limited only in that property rights of other parties cannot be impaired. A conditional right is automatically

granted if the user proceeds with due diligence towards perfection of the right and if

the rights of other users are not jeopardized.

Neither the courts nor the executive branch

of government has discretionary authority

over the type, place, or quantity of use. Furthermore, the State has no power to remove a

stream or any portion of its waters from appropriation. The State engineer only monitors

the system to assure that rights are protected

and water is not wasted.

53-898 ‘1 - 3 f) - 2 ‘,
—

378 ● An Assessment of 011 Shale Technologies

In Utah and Wyoming, a permit system is

employed in which the right to appropriate

water must be approved by the State engineer. He must consider the water rights of

others, but is also allowed to consider public

interest or public welfare when passing on an

application for appropriation. Thus, in contrast to Colorado, the governments of Utah

and Wyoming have discretionary authority to

approve some uses and deny others. Use of

this power has been minimal.

It is noteworthy that the continuation of

conditional decrees requires only due diligence and not actual use. In the past, rights

have been granted liberally by all three

States and as a result, the quantities of water

covered by conditional decrees far exceed

the available resources. Not all of the conditional decrees have been perfected, and relatively little of the claimed water is actually

being used. Consequently, surplus surface

water appears to be available in the oil shale

region. However, all of it has already been

claimed, in part by oil shale developers. Similar situations prevail in Utah and Wyoming.

Seniority of Water Rights

The prior appropriation doctrine is based

on the principle of “first-in-time, first-inright. ” Thus, the more senior (older) the water right, the higher its priority for the use of

limited resources. If shortages occur, user

rights that are junior in terms of the initiation

date are curtailed to assure water supplies to

users with more senior rights. Only when the

most senior rights have been satisfied do less

senior users have any rights to water.

The date of a right, assuming the appropriation goes forward diligently to completion, is the date of the first act evidencing an

intent to take water for beneficial use. In general, this is the date on which the application

for a conditional decree was filed. In Colorado, a State statute makes most water

rights a matter of public record. Rights to surface water are established solely by the actions of individual users, but these rights are

legally protected only if they are formalized

by water court decrees in Colorado or by the

permitting process in Utah and Wyoming.

Preference Systems

A preference system has been established

in each State to apportion water among different beneficial uses during times of shortage. Under its provisions, drinking water or

municipal users have first preference, agriculture is second, and industry is third. The

preference system overrides the seniority

system; water rights with a lower preference

may be condemned in favor of a higher preferred use, even if the preferred water right

is junior to the displaced right. In most cases,

just compensation would be required for displaced senior water rights.

Transfer of Water Rights

Water rights are considered real property

and may be sold or transferred. 24 They are

conveyed by deed and may be severed from

the land on which the water was originally

used, In Colorado, such transfers are reviewed by the water courts and may only be

denied if other users would be harmed. In

Utah and Wyoming, application for transfer

is made before the respective State engineer,

who decides whether harm will occur to

other users and also considers public interest

and other factors. Sale and transfer of water

rights is complicated by the need to protect

junior appropriators, seasonal rights of some

users, appurtenance (right-of-way) of water

rights to land, and preferred use as defined

by the individual States,

Abandonment of Water Rights

In all three States, absolute water rights

may be partially or completely lost by abandonment. In Colorado, failure to use an absolute right for a period of 10 years constitutes

prima facie evidence of abandonment. The

status of water rights is reviewed periodically by the division engineer in each of the

State’s water divisions. In Utah and Wyoming, abandonment is defined as nonuse for a
Ch 9–Water Availability 379

period of 5 years. Unlike Colorado, these

States have no provisions for a continuing review of the status of water rights.

Ground Water Rights

In Colorado, tributary ground wate r

(ground water that is hydrologically connected to the surface water system) is treated

essentially the same as a surface flow and

thus is subject to the prior appropriation doctrine. Nontributary ground water (ground

water that does not reach surface streams) is

divided into two categories: designated

ground water basins and nondesignated

ground water areas, Nontributary ground

water resources in designated basins are

controlled by a permit system through the

State Groundwater Commission. Nontributary ground water in nondesignated ground

water areas, on the other hand, is subject to

prior appropriation. Permits for wells must

be obtained from the State engineer, and

ground water rights must be adjudicated by

the water courts to assure legal protection,

just as with a surface right. Small wells (less

than 15 gal/rein) for livestock or domestic use

have been defined by law to cause no injury

and are exempt from such regulations.

In Utah, all ground water is subject to the

appropriation doctrine. Rights are administered by the State engineer and permits for

wells may be sold as any other water rights.

In Wyoming, permits must be obtained for

any ground water use. Livestock watering

and domestic uses have preference over all

other rights, regardless of seniority.

Federal Reserved Rights

The Federal reserved rights doctrine originated in the Supreme Court decision in Winters v. United States (207 U.S. 564 (1908)) regarding Indian water rights. It was held that

when Indian reservations were established

by treaty with the United States, sufficient

water to supply all Indian lands was also

reserved. The Court did not quantify sufficiency. Rather, it reflected the opinion that

Indian reservations were created to transform a nomadic people into permanent setlers and that those people required sufficient water for irrigation. 25

A major effect of this decision is that the

vater rights set aside for Indian reservations

vere interpreted to be superior to those of all

ther subsequent appropriators who obtained their rights under State law, even

though the Indian tribes had not yet put their

rights to beneficial use. Federal rights were

thus entered into the prior appropriation

system of each affected State, together with

11 other applicants and appropriators.

In Arizona v. California, the Court exended the reserved right doctrine to Indian

reservations created by Executive order and

to other Federal reservations such as national recreation areas, wildlife refuges, and

national forests. In addition, the Court addressed the question of the quantity of water

reserved for Indian use. It held that water

was intended to satisfy the future as well as

the present needs of Indian reservations, and

ruled that sufficient water would be reserved

to irrigate all the practicably irrigable acreage on the reservations. 26

A further Supreme Court decision in

United States v. New Mexico (98 Sup. Ct. 3012

(1978)) attempted to resolve the uncertainty

over the qualification of Federal reserved

water rights for areas other than Indian reservations. The Court concluded that the doctrine applied only to the original purposes of

the reservations, and that reserved water

rights could not be used for other purposes. 27

For example, the rights associated with a national forest could be used for maintaining

the forest and its wildlife, but not for industry, farming, or oil shale development.

While the Supreme Court has served notice

that it will interpret the purpose of Federal

reservations narrowly, a number of uncer-
.—

380 ● An Assessment of 011 Shale Technologies

tainties remain concerning the quantities of be used, whether the use must take place on

water that could be claimed to serve these the reservation, and whether rights can be

purposes. With regard to Indian reserva- sold or leased for uses outside the reservations, for example, it is still uncertain how tion.

much water will be claimed, how much will

Physical Availability of Surface Water for Oil Shale Development

Introduction

The size of the industry that could be supported by surplus surface water is affected

by the following factors:

●

●

●

●

●

●

The

The

the long-term average virgin flow in the

Colorado River system (this determines

the gross quantity of water that is available);

the compacts and other documents that

constitute the law of the river (these determine how the gross water supply is allocated among the basins and States);

the demands of other users (these consume part of the allocation to each State,

the remainder is the surplus);

the oil shale technologies employed

(these determine how much water the industry would need);

the siting of the facilities (this determines how the industry’s water demands will be distributed among Colorado, Utah, and Wyoming); and

the timing of their construction and the

duration of their operation.

final factor is particularly important.

region’s surface water resources are

finite, and they are not large. In the past, they

have generally been adequate, when supplemented by reservoir storage, to satisfy the demands of all users. At present, there is plenty

of surplus water for a very large oil shale industry, but the surplus is shrinking because

of population growth (both in the Upper Basin

and in the urban areas to which its waters

are exported), accelerated mineral resource

development, increases in irrigated agriculture, and expansions of other activities.

In the future, there may not be enough

water for oil shale unless the demands of

other users are partially curtailed. When this

will occur is not known. If it happens before

the plants are built or during their useful life,

then social and economic dislocations would

result. If, on the other hand, it occurs after

conservation and the development of other

energy sources have sufficiently diminished

the demand for liquid fuels, then the disturbances caused by the temporary presence of

an industry may not be overwhelming.

This section evaluates whether the surface

water resources in the Upper Basin are physically adequate, and legally available, to support a large industry. Availability is analyzed

for the Upper Basin as a whole, and for the

hydrologic subbasins that are likely to be affected. The factors analyzed were highlighted

above. Following is a summary of the assumptions made and of the sources of supporting

information.

Virgin Flow

An annual average flow of 13.8 million

acre-ft/yr past Lee Ferry is assumed. This is

the running average between 1930 and 1974.

Virgin flows have been calculated since 1896,

and the 1896-1974 average is considerably

higher-15.2 million acre-ft/yr. However, the

natural flows (the basis of the calculated

virgin flow) have been measured more accurately since 1930, and the 1930-70 average is

considered a better estimate. The effects of

flow fluctuations around the 13.8 million

acre-ft/yr average are discussed in the issues

section.

Law of the River

It is assumed that the allocation to the Upper Basin is determined by the operating cri-
teria promulgated for CRSP reservoirs by the

Department of the Interior (DOI). These criteria require a minimum discharge of 8.23

million acre-ft/yr from the Lake Powell Reservoir into the lower Colorado River. This incorporates the Lower Basin’s allocation

under the Colorado River Compact of 1922

(7.5 million acre-ft/yr), plus one-half of the

Mexican treaty obligation (750,000 acre-ft/

yr), less the contribution of the Paria River

(20,000 acre-ft/yr), which discharges into the

Colorado River between Lake Powell and Lee

Ferry. The Upper Basin States do not agree

with these criteria. The effects of other interpretations of the law of the river are discussed in the issues section.

It is also assumed that flows allocated to

the Upper Basin are distributed according to

the Upper Colorado River Basin Compact of

1948. As indicated previously, this compact

allocated 50,000 acre-ft/yr to Arizona and, of

the remainder, 51.75 percent to Colorado, 23

percent to Utah, 14 percent to Wyoming, and

11.25 percent to New Mexico,

Demands of Other Users

Section 13(a) of the Federal Nonnuclear

Energy Research and Development Act of

1974 directed the U.S. Water Resources

Council to assess the water requirements of

emerging energy technologies and the availability of water for their commercialization.

Studies were to be undertaken at the request

of the Energy Research and Development Administration (ERDA), In 1977, ERDA requested three such “l3(a)” assessments, one

directed to the water-resource aspects of oil

shale development and coal gasification in

the Upper Basin. Oversight for these projects

was transferred to the Department of Energy

(DOE) in 1978.

The Upper Basin 13(a) assessment was organized under the management of DNR of the

State of Colorado. DNR’s work has been reviewed by an interagency, intergovernmental

steering committee that includes representatives of the Arizona Water Commission, the

Colorado Water Conservation Board, the

New Mexico Interstate Stream Commission,

the Utah Division of Water Resources, the

Wyoming State Engineer’s Office, the U.S.

Soil Conservation Service, the Department of

Commerce, DOE’s Denver Project Office, the

Region VIII Office of the Department of Housing and Urban Development, USBR, and EPA.

Technical assistance and studies were provided by USBR (hydrologic modeling), the U.S.

Fish and Wildlife Service (USFWS) (fishery

and recreational impacts), the U.S. Heritage

Conservation and Recreation Service (recreational data), Los Alamos Scientific Laboratory (economic modeling), the U.S. Soil Conservation Service (agricultural water consumption and conservation), the U.S. Geological Survey (USGS) (water quality), and several private contractors.

Because of this broad support and review

base, DNR’s estimates of present and future

water depletions appear to be the best available for the period between 1980 and 2000.

OTA has relied on the values provided for

“conventional’” (nonoil shale) depletions to

define the baseline water-demand conditions

under which the oil shale industry could be

established. DNR”s results have also been

used to evaluate water-supply options in the

areas in which oil shale development is most

likely to occur.

DNR projected water consumption patterns for conventional activities in 2000

based on low, medium, and high regional

growth rates. The medium-growth scenario,

which was based on declared plans by the

various users for expanding their water

needs, is considered by the States to be the

most realistic. The high growth rate scenario

was derived from the medium scenario by assuming that announced projects would be

finished sooner than expected or would consume more water than anticipated. A few

projects not considered in the medium-growth

scenario are included in the high-growth scenario. The low-growth scenario was derived

by assuming project delays or lower than anticipated water consumption. In this section,

OTA considered only the medium growth
382 ● An Assessment of 011 Shale Technologies

rate. The low and high rates are considered

in the issues section.

Oil Shale Technologies

It is assumed that the technology mix used

by any future industry will resemble that of

the projects presently active or proposed. The

characteristics of this industry were described in table 76. About 51 percent of the

facilities use indirectly heated AGR, 33 percent directly heated AGR and MIS, and 16

percent a combination of MIS and indirectly

heated AGR. On this basis, each plant would

require about 8,500 acre-ft/yr for production

of 50,000 bbl/d of shale oil syncrude. The effects of other technology mixes are discussed

in the issues section.

Distribution of Facilities

If the siting pattern of the present projects

were extended to a major industry, 68 percent of the production would be based in Colorado, 32 percent in Utah, and none in Wyoming, Although they are of lower quality, some

development of Wyoming shales may occur if

a major industry is established. Therefore, it

was assumed that approximately 5 percent of

future production will come from Wyoming,

about 70 percent from Colorado, and about

25 percent from Utah. This assumption determines which hydrologic subbasins will be impacted. It also determines how much of the

production could be sustained by the extensive ground water resources of the Piceance

Basin. In this section, it is assumed that all of

the plants rely on surplus surface water. The

possible substitution of ground water is

discussed in the issues section.

Timing and Lifetime of the Projects

It is assumed that the facilities will be installed before 2000, regardless of the industry’s size. As discussed in the other chapters,

establishing a large industry this quickly may

be difficult.

The Availability of Surface Water in the

Upper Colorado River Basin

Water Consumed by Conventional Activities

At present, the following activities consume surface water in the Upper Basin:

.

●

●

●

●

●

●

thermal power— for steam-electric power generation;

agriculture— for irrigation, watering

stock, and other agricultural purposes;

wildlife and recreation—for maintenance of fish, wildlife, and recreational

areas;

minerals—for extraction, processing,

and transporting ores and concentrates;

municipal and industrial—for domestic,

commercial, retail, and manufacturing

facilities, including final processing of

raw materials into finished products;

and

exportation— for diversion and transportation to other basins or to other

areas within the Upper Colorado River

Basin.

Water consumption patterns for these activities, at present and as projected to 2,000,

are shown in table 78. Agriculture presently

depletes nearly 71 percent of the total, water

exports are the second highest category at 24

percent, and the remaining 5 percent is distributed fairly evenly among the other uses. A

comparison with the year 2000 projections indicates shifts both in the absolute quantities

of water consumed and in the distribution of

consumption among the various activities.

The following trends are indicated:

●

●

●

Agricultural water consumption is projected to increase by 19 percent. However, agriculture’s share of total consumption is projected to decrease to 61

percent from its present level of 71 percent.

Thermal power’s water consumption is

projected to increase by a factor of 6.

Exportation of water is projected to in-

—— —..

384 An Assessment of Oil Shale Technologies

Table 78.–Present and Projected Water Depletions for Activities Other Than

Oil Shale Development in Colorado, Utah, and Wyoming (thousand acre-ft/yr)

Present Year 2000

Colorado Utah Wyoming Total Percent Colorado Utah Wyoming Total Percent

Thermal power . 10 7 18 35 1,2 74 64 83 221 5,7

Agricultur e 1,197 527 279 2,003 70.7 1,380 671 330 2,381 61.3

Wildlife and recreation 15 9 6 30 1,1 28 9 20 57 1,5

Minerals . , 19 12 21 52 1.8 33 12 64 109 2.8

Municipal and industrial 21 10 4 35 1,2 49 19 8 76 2.0

Exportatio n 541 132 7 680 24,0 757 262 22 1,041 26.7

Tota l 1,803 697 335 2,835 100.0 2,321 1,037 527 3,885 100,0

SOURCE

●

Colorado Oepariment of Natural Resources, Upper Co/orado Rwer Regmn See//on 13 (a) Assessmen/ A Report (O (he U S Wa/er Resources CouncI/ drafl August 1979

crease by 53 percent. The proportion of

total depletions exported, however, will

remain at about 25 percent.

At present, the oil shale States together

consume about 2.84 million acre-ft/yr.

The total depletion would increase 37

percent to 3.89 million acre-ft/yr.

These trends are considered below in conjunction with law of the river allocations t o

estimate the quantities of surplus water that

would be available to support additional regional growth.

Estimation of Surplus Water in the

Upper Basin

Surplus water is defined as the difference

between the water allocated and the total

water consumption, which includes water

used for beneficial purposes plus reservoir

evaporative charges. * As discussed previously (see table 77), the oil shale States should be

entitled to a total of 4.94 million acre-ft/yr:

2.88 million to Colorado, 1.28 million to Utah,

and 0.78 million to Wyoming. In table 79, estimates are given for the quantities of surplus

surface water at present and in 2000. At

present, approximately 1.66 million acreft/yr of surplus water is available. By 2000

the surplus would be reduced to abou t

469,000 acre-ft/yr. These surpluses are legally available to the States. If all the present

*The term “reservoir evaporative charges” refers to the

total amount of water that evaporates from certain reservoirs

in the Upper Basin, The States are charged on a percentage

basis for losses from reservoirs that are built to serve the entire Upper Basin. Evaporation from reservoirs built for a specific State are charged entirely to that State.

surplus were reserved for oil shale development, an industry of about 9.76 million bbl/d

could be accommodated. The projected surplus in 2000 would support a 2.76-millionbbl/d industry without disrupting other users.

A more precise analysis, which considered

seasonal flow fluctuations, return flows from

irrigated fields, effects of fill rates, and sustained depletions on reservoir evaporation,

was performed for DNR with USBR’s Colorado River system simulation model. The model

predicted a natural discharge from Lake

Powell of 8.63 million acre-ft/yr in 200 0

—400,000 acre-ft/yr more than the minimum

discharge requirement, but 69,000 acre-ft/yr

less than the year 2000 surplus shown in

table 79. The surplus would support an oil

shale industry of 2.35 million bbl/d in the Upper Basin. However, the industry’s total capacity would be further reduced by the Upper

Colorado River Basin Compact of 1948 that

governs how water can be distributed among

the individual States in the Upper Basin. The

effects of this compact are indicated in table

80, where the 400,000-acre-ft/yr surplus is

distributed among Colorado, Utah, Wyoming,

and New Mexico according to the compact’s

percentage formula. As shown, the total

shale oil capacity would be 2.09 million bbl/d:

1.22 million in Colorado; 541,000 in Utah; and

320,000 in Wyoming.

It is important to note that these calculations apply to average flow conditions in the

Colorado River system. During dry years, natural flows out of Lake Powell might not be sufficient to satisfy the delivery requirement to

the Lower Basin and might have to be aug-
Ch 9–Water Availability ● 385

Table 79.–Estimation of Surplus Surface Water in Colorado, Utah, and Wyoming at Present and in 2000 (thousand acre-ft/yr)

— —

Present Year 2000

Colorado Utah Wyoming Total Colorado Utah Wyoming Total

Total water usea

1,803 697 335 2,835 2.321 1,037 527 3,885

Evaporation ” 259 115 70 444 334 148 104 586

Total consumption 2,062 812 405 3,279 2,655 1.185 631 4,471

Allocatlonc

2,880 1,280 780 4,940 2,880 1,280 780 4,940

Surplus. 818 468 375 1,661 225 95 149 469

aDala from table 78

bE~~lmated ~harge~ for CRSp ,e~er,,olr~ pre~enI ,alue~ ~roilded by R~la”d Fls~her (jjorado River waler Conserval, on Dlslrlc[ year 2000 estlmales by [he Colorado Depa’lmeot of N?lucd Resources

cAssumes 13 8 milllon acre-ft yr vl~gln flow al Lee Ferry 8 23 mlll~on acre If yr Lake Powell discharge cllslrlbutlon of flows and evaporative charges per the oerceltage (am) ula of !he Uoper Colorado

Rwer Basin Compact of 1948

SOURCE Otffce 01 Technology Assessment

Table 80.–Maximum Shale Oil Production

Based on Surplus Surface Water in 2000a

Assumed virgin flow at Lee Ferry, million acre-ft/yrb

138

Surplus surface water available, acre-ft/yrC

New Mexic o 451000

Colorad o 207,000

Uta h 92,000

Wyomin g 56,000

Total 400,000

Shale 011 capacity, million bbl/dd

Colorado 1 22

Uta h 0 5 4

Wyomin g 0 3 3

Total 2 0 9

— — aAs~umes 823 mllllon acre If yr annual U(scharqe ~rom Ldke Powe!l D[sfrlbutlon among the UP

per Basin Slates according 10 Ihe Upoer Coloraco Rwer Basin Compact of 1948

b

1930 74 annual average

c Based on year 2000 deplello~ orojectlons for nono{l shale users Medium growfh rate

scenario

dBa~ed on 8 soo acre ft ~ yr for production 0150000 bbl d Of shale 011 syncrude

SOURCE Olflce ot Technology Assessment

mented by discharge from the Upper Basin

reservoirs. As noted earlier, these were built

to allow the Upper Basin States to satisfy

their delivery requirements to the Lower

Basin. Their active capacity is expected to be

about 35 million acre-ft in 2000. If virgin

flows dropped to say, 12.9 million acre-ft/yr

and stayed there, * the reservoirs could offset

the 0.9-million-acre-ft/yr shortfall for only

about 39 years.

In summary, surplus surface water legally

available to the oil shale States could support

a shale industry of about 2.1 million bbl/d

through 2000. This conclusion is based on one

*’I’his []ppears to be the lower limit for long-term virgin flows

in the Colorado River system. See the issues section of this

chapter.

interpretation of the law of the river, one set

of depletion estimates for conventional users

in 2000, one assumed value of virgin flow,

and an industry that employs a technology

mix similar to that being developed in the

present projects. If a different basis were selected, the estimated capacity of the industry

could be significantly different. Some other

bases are discussed in the issues section of

this chapter.

The conclusion also does not account for

regional and local supply impediments that

could affect facility siting and thereby determine the ultimate size of the industry. The

next section evaluates water availability with

respect to specific development sites within

specific hydrologic basins in the oil shale

area.

Water Availability in Hydrologic Basins

Affected by Oil Shale Development

Oil shale development is likely to affect

three hydrologic subbasins: -

●

●

the Green River basin in the southwestern corner of Wyoming, which includes

the northern mainstem of the Green

River and its tributaries;

the White River basin, which encompasses the northern portion of the Piceance basin and the eastern portion of

the Uinta basin, and whose tributaries

include the White and Yampa Rivers to

their confluence with the Green River in
386 ● An Assessment of Oil Shale Technologies

●

The

eastern Utah, plus streams flowing north

out of the Piceance basin into these

rivers; and

the Colorado River mainstem basin,

which includes the Colorado River mainstem in Colorado, streams that flow

south from the Piceance basin into the

Colorado, and upstream tributaries at

higher elevations.

impacts on these subbasins can be estimated only after certain assumptions are

made regarding the locations of the oil shale

plants and the timing of their construction. If

the trend indicated by the present oil shale

projects were continued, about 40 percent of

the shale oil production would come from the

White River basin in Colorado, 30 percent

from the Utah portion of that basin, and 25

percent from the basin of the Colorado River

mainstem in Colorado. The remaining 5 percent might come from as-yet unannounced

projects in Wyoming’s Green River basin. The

water requirements for a l-million-bbl/d industry distributed in this manner are indicated in table 81. Also shown are the water

requirements for conventional uses in 2000,

as projected by DNR under its medium

growth rate scenario. As shown, the industry

would increase the total water consumption

in the three subbasins by about 10 percent.

The increases in the Green River and Colorado mainstem basins would be relatively small,

but water demands in the White River basin

would increase by nearly 150 percent.

The Adequacy of Surface Water Resources

by Hydrologic Basin

In the Green River basin, water depletions

for a l-million-bbl/d oil shale industry would

be approximately 8,500 acre-ft/yr. Two major

Federal reservoirs within this basin, Flaming

Gorge and Fontenelle, have well over 100,000

acre-ft/yr of surplus water in storage that is

available for sale to industrial users such as

oil shale developers. Consequently, there is

more than enough water available within the

basin to provide for projected growth. It is unlikely that any new reservoirs will be needed.

Oil shale development would have a greater effect on the White River basin. With a 1 -

million-bbl/d industry, depletions would approach 200,000 acre-ft/yr by 2000. About 60

percent would be used for oil shale. These depletions would strain the water resources of

the White River because its total annual flow

at the boundary of the basin is only about

568,000 acre-ft/yr, 61 percent of which occurs between April and July. Although several oil shale plants could be supplied from existing resources, new reservoirs would be

needed and river flows would be substantially reduced.

According to DNR, only about 6,000 acreft/yr could be obtained from streams within

the Piceance basin because of their low

streamflows. A l-million-bbl/d industry would

require an additional direct-flow diversion of

4,500 acre-ft/yr from the White River below

Table 81 .–Water Requirements by Hydrologic Subbasin for a 1-Million-bbl/d Industry in 2000

Water for conventional Oil shale industry Increase due to

Subbasin uses, acre-ft/yra

Oil capacity bbl/d Water acre-ft/yrbTotal water acre-ft/yr 011 shale, percent

White River, Colo. and Utah 80,000 700,000 119,000 199,000 149

Colorado mainstem, Colo. . 1,220,000 250,000 42,500 1,262,500 3 5

Green River, Wyo . 482,000 50,000 8,500 490,500 1 8

Total. ., 1,782,000 1,000,000 170,000 1,952,000 9.5

aconventlonal “~e~ ,flclude th~r~a[ power agriculture Wlldllfe and recreallon, minerals muruclpal and (ndus(nal and exporfs Eshmates for the Colorado Depafiment of Nafural Resources medium 9rowfh

rate scenario

bBased on 8 5i30 acre . ft/yrfor producflon of 50000 bblid Of shale 011 Swcrude

SOURCE Off Ice of Technology Assessment
Ch. 9–Water Availability ● 387

Meeker, a reservoir with an active capacity

of 60,000 acre-ft on the south fork of the

White River in Colorado, and a 120,000-acreft reservoir on the White River mainstem in

Utah. An industry of more than 2 million bbl/d

would require these facilities plus a 35,000-

acre-ft reservoir on the White River mainstem between Meeker and Piceance Creek, a

total of 35,000 acre-ft of active capacity in

several smaller reservoirs along ephemeral

streams in the Piceance basin, and a reservoir of about 10,000 acre-ft/yr along Piceance

Creek. All reservoirs would store spring

runoff. Water from the White River would be

pumped to the reservoirs in the Piceance basin during the rest of the year.

Within the Colorado mainstem basin, oil

shale development would increase water depletions only slightly. However, large water

demands would be imposed by the growth

rates projected for other uses, especially irrigated agriculture. Reservoirs may be needed

to supply both irrigation and oil shale development. DNR considered four siting schemes

for reservoirs in this basin.

In the first scheme, reservoirs would be

built at high elevations along tributaries like

the Roaring Fork and Eagle Rivers. Springtime runoff would be trapped for release over

the dry months. The released water would be

recovered from the Colorado River below Rifle and pumped to the oil shale plants. The

only appreciable inflows to the reservoirs

would occur in the spring and large active capacities would be needed to sustain outflows

during the dry seasons. Total capacities

might exceed 50,000 acre-ft for a l-millionbbl/d industry.

The second scheme also involves reservoirs

on upstream tributaries but at lower elevations to permit capture of agricultural return

flows and of water from secondary streams.

A total storage capacity of 30,000 to 50,000

acre-ft would be needed. The third scheme involves direct flow diversions from the Colorado River below Rifle, in conjunction with

reservoirs on the Colorado mainstem or in

side canyons in the Piceance basin. A l-million-bbl/d industry could be supplied with a

30,000-acre-ft/yr diversion and a 15,000-

acre-ft reservoir. The reservoir could be located in a dry canyon because it would be

supplied with pumped water from the Colorado mainstem and would not rely on local

stream flows.

In the fourth scheme, 50,000 acre-ft/yr of

surplus water would be purchased from existing USBR reservoirs (such as Reudi Reservoir) and pumped to the oil shale facilities.

This would supply all of the water required

for that portion of a l-million-bbl/d industry

projected for the Colorado mainstem basin.

Larger levels of production could be supported by any of the other three schemes,

with reduced storage and diversion requirements.

In summary, new storage requirements for

a l-million-bbl/d industry could range from

180,000 acre-ft, with reservoirs in the White

River basin and no storage in the Colorado

mainstem basin, to about 230,000 acre-ft for

storage in both basins. The maximum storage

requirements would be encountered if highaltitude reservoirs were built. Less storage

would be needed if most water was obtained

by direct diversions from the mainstem rivers. The additional reservoirs would increase

reservoir capacity in the Upper Basin by

about 0.6 percent. Evaporative losses from

the new reservoirs should also be charged

against the industry. Their precise magnitude

would depend on the characteristics of the

new reservoirs and their sites, but should add

only a small percentage to each shale plant’s

annual water requirements.
388 An Assessment of Oil Shale Technologies

The following

either alone o r

Water Acquisition Strategies and Their Costs

strategies could be use d

in combination to suppl .- .v

water to oil shale facilities:

● perfection of conditional water right decrees,

● purchase of surplus water from Federal

reservoirs,

● purchase of water supplies and water

rights from irrigated agriculture,

 ground water development, and

. interbasin diversions.

A brief discussion of each strategy and its

associated costs follows. Constraints and impacts are discussed later.

Perfection of Developer Water Rights

Description

Most potential oil shale developers have already acquired water rights. Some were obtained by direct filings through the prior appropriation system. These are now in t h e

form of conditional decrees both for storage

and for direct-flow diversions. Exact yields

are not available because they are considered proprietary information by the companies. The rights are believed to be large but

relatively junior. The oldest was acquired in

1949.

Other rights were purchased from irrigated agriculture. Most of these are relatively senior absolute rights that were perfected

by the seller. To avoid a declaration of abandonment, some developers have allowed the

sellers to continue to use the water for farming. Little information is available regarding

the potential yields of these rights. However,

total historic consumption, which would determine the quantities of water that could be

transferred to oil shale development, could be

as low as 10,000 to 20,000 acre-ft/yr.28

An idea of the extent of developers rights

can be gotten by examining their water positions in 1968.29 Conditional storage rights held

by some potential developers at that time are

tabulated below:

Developer Storage rights, acre-ft

EXXON , ... , . . . . . . . . . . 122,00 0

Mobil ... , . . . . . . . ... , , 66,000

Getty Oil. ., . . . . . . . . . . . 53,000

Sinclair. . . . . . . . . . . . . ., 51,500

Tosco . . . , .. 0.., ., . . . . 34,600

Total, ... , . . . . . . . . . . 327,100

These companies also owned conditional decrees to over 1 million acre-ft/yr of directflow diversions from the Colorado and White

Rivers and their tributaries. Substantial

rights were also held for ground water. Superior Oil, for example, held conditional decrees to over 2,400 acre-ft/yr of ground water

in the Piceance basin.

The rights of the limited sampling of companies shown above could support an industry of nearly 8 million bbl/d and would be sufficient for the shale oil production levels projected for the near term.

Developers who do not presently own

rights could file for new ones. In general, this

option is considered undesirable because the

quantity of water covered by rights issued to

date already exceeds the resources of the

river system. Any new rights would be junior

to those of all other users and therefore the

most likely for curtailment during water

shortages.

Filing for new rights might be feasible for

near-term development, however, because of

the improbability that all of the water covered by present conditional decrees will be

put to use for several decades. The long-term

feasibility of this strategy is highly uncertain

because supply curtailments will become

more likely as regional growth proceeds. To

assure supplies in the long term, new filings

would have to be merged with other strategies.
Ch 9–Water Availability ● 389

costs

The costs of acquiring these kinds of rights

are negligible, comprising only legal fees for

recording the water claim, and for pursuing

any resultant litigation, and small annual investments to demonstrate due diligence. The

costs incurred by developers when they purchased their current irrigation rights are

unknown but were probably small. Therefore, the costs of water supplies obtained

through the prior appropriation system comprise only the costs of transporting the water

from the diversion point to the oil shale site,

Transportation costs are discussed later with

respect to intrabasin diversions.

Purchase of Surplus Water From

Federal Reservoirs

Description

Oil shale developers could also purchase

surplus water from reservoirs operated by

USBR and other entities. Various amounts of

water are presently available from existing

reservoirs in the oil shale area. As noted

previously, the Flaming Gorge and Fontenelle

Reservoirs in the Green River basin have sufficient surplus water for much more shale oil

production than is likely to occur in the basin

in the near term. This water is not being used

for any purpose and could be made available

to oil shale developers.

In the basins of the White River and the

Colorado River mainstem, surplus water in

storage is adequate for initial development.

For example, Green Mountain and Reudi Reservoirs in the Colorado mainstem basin could

supply about 100,000 acre-ft of surplus

water, which would be sufficient for nearly

600,000 bbl/d of shale oil production. However, existing reservoirs could not support a

larger industry unless other users were partially curtailed. Therefore, new reservoirs

would have to be built. New pipelines would

also be needed in all three basins to divert

water to the oil shale plants.

costs

Reservoir construction costs are highly

site-specific and are reflected in the charges

for purchased water. These charges vary

widely from reservoir to reservoir. Although

charges for existing reservoirs are known,

only rough estimates are available for new

reservoirs,

Some examples of long-term contracts for

water from existing USBR reservoirs are

shown in table 82. As shown, charges in the

late 1960’s were from $7 to $11/acre-ft while

previous charges were less than $1/acre-ft.

The highest charge, $22.54/acre-ft in 1972, is

for a small diversion from the Emery County

reservoir. Because future contracts will be

negotiated individually, water costs cannot

be accurately predicted, although it seems

unlikely that they would be much higher than

$25/acre-ft.

Table 82.–Examples of the Charges for Purchasing Surplus Surface Water From U.S. Bureau of Reclamation Reservoirs

Year of Quantity of Unit cost,

Project/reservoir River basin Purchaser contract diversion, acre-ft/yr $/acre-ft

Seedskadee/Fontenelle

Seedskadee/Fontenelle

Emery County

Glen Canyon/Lake Powell

Glen Canyon/Lake Powell

Navajo

Navajo

Navajo

Missouri River/Bighorn and Boysen

Boulder Canyon/Lake Mead

Green

Green

Central Utah

Colorado

Colorado

San Juan

San Juan

San Juan

Yellowstone

Lower Colorado

State of Wyoming

State of Wyoming

Utah Power & Light and others

Resources Co and others

Salt River project

New Mexico Public Service

Utah International

Southern Union Gas Co.

Various

Colorado River Commission

1962

1974

1972

1969

1969

1968

1968

1968

1967-71

1966

60,000

60,000

6,000

102,000

40,000

20,200

44,000

658.000;

30,000

$0.4 0

5 0 0

2254

7.00

7.00

7 0 0

7 0 0

7.00

11,00

0 5 0

SOURCE R F Probsleln H Gold and R E Hicks Wa(er Requ/remenfs Po/Iu/Ion Effecfs and Costs O( Wafer Supply arm Treamefl( for [he (7II Sha/e Indusky eporl prepared for OTA by Water Punflcallon

Associates October 1979
—. ——

390 ● An Assessment of Oil Shale Technologies

Some cost estimates for new reservoirs in

Western Colorado are summarized in table

83. Unit construction costs in 1979 dollars

vary from $120 to $740/acre-ft of storage

capacity. To obtain estimates of water costs

from these reservoirs, assumptions must be

made about financing methods and operating

characteristics of the reservoirs. A rough

estimate can be made if it is assumed that

storage and delivery capacities are equal,

and 10 percent of construction costs are

charged to water purchasers per year. Then

the charges for the water would range from

about $10 to about $75/acre-ft, which is substantially higher than costs from existing reservoirs.

Table 83.–Estimated Construction Costs for Proposed

Reservoirs Within the Colorado River Water Conservation District

Storage Unit capital

capacity, Construction costs,

acre-ft costs, million$ $/acre-ft

Haypark , ,

Azur e

Toponas, .,...,.. , ,

Iron Mountain ,

Yoeman Park . ~ ~ ~ ~

Bear Wallow. .

Kendig, ., ., . ., ~

Una. . . . . .

Yamcolo ,,. ,.

Bear, .., ,,. .

Grouse Mountain .

Rampart. .

California Park

Rangely ..,, .,, ,

Dunkley. . . . .

Pothook .,,

20,000

30,000

18,000

60,000

7,000

49,000

15,000

196,000

9,000

12,000

79,000

12,000

37,000

55,000

57,000

60,000

$ 6 0

11.4

3,3

2 8 9

4 9

11.9

5.0

363

5.8

30

9.2

4.0

52

112

13,2

8 5

$300

380

180

480

740

240

320

190

640

260

120

350

140

200

230

140

SOURCE R F Probslem H Gold and R E H!cks Wafer Reqwremenfs pollution Effecfs, and

Cos/s of Wafer Supp/y and Trearmerr/ for (he 0// .Sha/e /rrdus/ry report prepared for OTA

by Water Purlhcatlon Associates October t979

Purchase of Irrigation Rights

Description

Most oil shale developers have indicated

that they plan no further purchases of irrigation rights. However, the strategy warrants

discussion because large quantities of water

are currently consumed by farming and the

water laws allow rights to be transferred

from willing sellers to willing buyers.

The feasibility of using irrigation rights for

oil shale development is site specific and

depends on their cost in comparison with

other strategies, the proximity of irrigation

diversions to potential plantsites, and the

seasonal nature of irrigation rights. Transfer

is unlikely in the Green River basin, for example, because adequate and inexpensive water

appears to be available from existing Federal

reservoirs. On the other hand, it could occur

in the White River and the Colorado mainstem basins because of the limitations of existing storage capacity.

In the White River basin, irrigated agriculture consumes about 37,000 acre-ft/yr, This

amount of water could supply a 250,000-bbl/d

oil shale industry. If this water were transferred to oil shale, additional storage would

probably be needed because of the seasonal

nature of irrigation rights. These rights

generally rely on direct diversions from a

river, and river flows might not be sufficient

during dry seasons to satisfy the oil shale

water requirement.

In the basin of the Colorado River mainstem, irrigated agriculture currently consumes about 430,000 acre-ft/yr, which is

much more than would be required for any

projected level of oil shale development. Purchase of irrigation rights would reduce, but

probably not eliminate, the need for new storage capacity. Irrigation water from the Colorado mainstem could also be diverted to oil

shale facilities in the White River basin, thus

reducing the need for new storage in that

basin. Some new interim storage would be

needed near the plantsites. In any case, new

pipelines would be needed to transport water

from current diversion points to the oil shale

facilities.

costs

It is important to distinguish between the

purchase of a specific quantity of water for

use in a given year and the purchase of a

water right that would authorize use in all

future years. In recent years, the cost in Colorado of purchasing irrigation water for one

.
Ch. 9–Water Availability ● 391

year’s use has ranged from about $10 to

$25/acre-ft, which is similar to the costs of

purchasing water from existing Federal reservoirs. 30 The cost of purchasing a water

right for use in perpetuity, however, could

range from $1,000 to $2,500 for each acreft/yr covered by the right.31 If capital to purchase the right were borrowed at lo-percent

interest, annual costs might range from $100

to $250/acre-ft. These costs are substantially

higher than current prices for single-year

diversions. The reason is that most farming

could not be conducted without irrigation.

Selling water rights essentially puts a farmer

out of business.

Ground Water Development

Description

Ground water aquifers could be feasible

water sources for oil shale development if

they are favorably located relative to plantsites, if the water quality is suitable for industrial applications, and if physical characteristics (such as burial depth, storage

volume, and discharge rates) are advantageous. Although knowledge is incomplete, existing data suggest that selected aquifers in

the Upper Basin are worthy of consideration

for some, if not all, potential oil shale

facilities.

In the Piceance basin, for example, up to

25 million acre-ft is estimated to be stored in

two major bedrock aquifers that are separated by rich oil shale beds. This resource is

currently being used in limited amounts for

livestock watering, for irrigated agriculture,

and for localized domestic consumption. The

water is generally high in dissolved solids and

fluoride. For this reason, its use for conventional purposes will probably not increase. It

is likely that an oil shale industry would be

the only large-scale application for which this

ground water would be suitable. * With prop-

*W~ter in the upper aquifer generally contains less than

2,000 mg/1 of dissolved solids, while in the lower aquifer these

may range from 1,000 to 63,000 mg/1. The fluoride content is

typically from 10 to 70 mg/1. Federal drinking water standards

recommend a dissolved solids limit of 500 mg/1 and a fluoride

content of !ess than 1.0 mgll.

er pretreatment, much of it could be upgraded for such use. If this were done to the

fullest extent, the aquifers could supply a 1-

million-bbl/d shale oil industry for from 200 to

500 years, depending on the processing technologies used.

Less is known about ground water in the

White River basin in Colorado and Utah and

about Utah’s water resources in general. It is

known that the Uinta basin contains large artesian aquifers, one of which discharges in

the vicinity of Federal lease tracts U-a and

U-b. The water is not potable but could be

treated for use in oil shale processing.

Because bedrock aquifers in the Piceance

and Uinta basins often coincide with minable

oil shale zones, ground water will be an important consideration in most development

plans. Even if ground water is not intentionally developed for use as process water, it will

be produced on most tracts during mine dewatering and the preparation of in situ retorts. In many locations, the water could satisfy all processing needs, In some areas, an

excess will be produced that will have to be

disposed of through evaporation, by reinjection, or by discharge to surface streams. Purifying excess ground water to discharge

standards could be costly.

In the Piceance and Uinta basins, yields

from test wells vary with location from less

than 1,000 to over 4,000 acre-ft/yr. Two to

four of these wells would be sufficient to satisfy the needs of an oil shale plant producing

50,000 bbl/d by directly heated AGR. Several

additional wells would probably be drilled to

provide backup capacity.

costs

The cost of ground water development will

vary with site, with water quality, and with

the water management program of the developer. In a recent study the geohydrologic

characteristics of three wellsites in the

Piceance basin were analyzed, and estimates

were prepared of drilling capital and pumping costs.32 For two of the sites, which had

prolific water-bearing zones extending to
.—. —

392 ● An Assessment of 011 Shale Technologies

about 1,000 ft below the surface, a minimum

cost of about $30/acre-ft was estimated for

delivery of 1,500 to 4,000 acre-ft/yr. The third

site contained much less permeable rocks,

which reduced maximum flows and thus increased costs. The estimate of the maximum

flow from this well was 700 to 900 acre-ft/yr,

with a minimum cost of about $90/acre-ft. In

the DNR study, water costs from a well yielding 3,000 acre-ft/yr from a depth of 500 ft

were estimated to be $22 to $30/acre-ft. 33

Another estimate is about $55/acre-ft for a

l,000-ft well yielding 1,500 acre-ft/yr. 34

The costs of well drilling and pumping

could, therefore, range from $20 to $60/acreft, assuming that aquifers occur at reasonable depths and in reasonably permeable formations. These costs are comparable to those

for surface water. Ground water could offer

a major economic advantage in that wells

could be located near the oil shale facilities,

thus avoiding transportation costs. On the

other hand, the poor quality of some ground

water would necessitate costly purification.

Water from some aquifers is highly saline

or brackish. It would not need to be purified

for use in dust control and spent shale compaction, but would have to be for use as boiler

feedwater or cooling water. Purification can

be quite costly. For example, treating brackish water to cooling water standards can cost

from $200 to $300/acre-ft,35 and treatment to

boiler feedwater standards can cost from

$650 to $ 1,000/acre-ft. 36 These high treatment

costs would not be needed for all of a plant’s

water supply, because some requirements

could be satisfied with water of any quality.

If the overall water management plan of an

AGR facility is considered, a brackish ground

water supply would add about $250 to $530/

acre-ft to the costs of water acquisition.

Thus, the overall costs of ground water development and use could range from $20 to

$600/acre-ft/yr. The lower estimate corresponds to a high-quality ground water from

permeable rocks at reasonable depths. The

higher estimate corresponds to brackish water from relatively impermeable formations.

Interbasin Diversions

Description

Interbasin diversions move water from one

major hydrologic basin to another. Exports

from the Upper Basin to the cities of Colorado’s Front Range Urban Corridor (Denver,

Colorado Springs, etc. ) are examples of interbasin diversions. Diversions could also be

used in the future to increase overall water

availability in the Upper Basin by relocating

water from other major basins such as the

Columbia River Basin or the Upper Missouri

River basin. * As an illustration, diverting 1

percent of the net water supply of the State of

Washington in the Columbia River Basin

would provide 2 million acre-ft/yr of additional water to the oil shale area, an amount

equal to two-thirds of the present water consumption in all of the Upper Basin States.

costs

Costs of interbasin diversions vary with

pipeline construction and pumping costs,

which in turn depend on the route, diameter,

and length of the pipelines; on the number

and capacity of pumping substations; and on

the cost of purchased power for the pumps.

These costs are highly project-specific, but, in

general, decrease with pipeline throughput

and increase with distance. Variations in unit

costs can be illustrated by considering two

alternate pipelines; one providing water to a

single oil shale plant and the other supplying

water to an entire industry. An oil shale plant

producing 50,000 bbl/d by directly heated

surface retorting would consume about 6,000

acre-ft/yr of water. This quantity could be

transported to the site in an 18-inch-diameter

pipe at a unit cost of about $12/acre-f t/mile.

In comparison, about 240,000 acre-ft could be

conveyed through a 90-inch-diameter pipeline

at a unit cost of $1 .90/acre-ft/mile.37

*Under the CRP Act, the Secretary of the Interior was required not to undertake reconnaissance studies of any plan for

the importation of water into the Colorado River Basin until

1978. The Reclamation Safety of Dams Act of 1978 extended

this moratorium until Nov. 2, 1988. Thus. no water imports

from other major basins will be allowed until well after 1988,
CH. 9–Water Availability ● 393

Four options illustrate typical distances

and costs that might be encountered with interbasin diversion for a large oil shale industry. One option would be to bring water to

the White River basin from the Oahe Reservoir on the mainstem of the Missouri River in

South Dakota. The distance would be 500 to

600 miles, and the unit costs would be $950 to

$1,150/acre-ft. A second alternative would be

to transport water from the Missouri River at

Kansas City to the John Redmond Reservoir in

Kansas, then to Denver, and finally over the

Rocky Mountains to the White River basin.38

The pipeline would be about 700 miles long,

and the unit transportation cost about

$1,130/acre-ft. A third option would be to

transport water about 800 miles from the Columbia River Basin to the White River basin.

Unit costs would be about $1,520/acre-ft. A

fourth possibility would be to divert water to

the White River area from the Yellowstone

River, a distance of approximately 400 miles,

This would cost about $750/acre-ft,

In summary, interbasin transfers for a

large industry would require 400- to 800-milelong pipelines and would entail unit costs of

$750 to $1,500/acre-ft. Exact costs vary widely but are, in general, quite high. To these

costs must be added the purchase price of the

water that is moved through the pipeline.

Intrabasin Diversions

Description

The total cost of a water supply includes

the cost of acquiring the water and the cost of

moving it to the oil shale facility. As indicated

above, transportation costs can outweigh acquisition costs if the facility is far from the

water source. The costs of transporting

water acquired in the oil shale area will also

be high, although less than for transfers from

other major basins. The following discussion

describes some of the typical intrabasin diversions that could occur within the oil shale

region, and estimates the costs of moving

water through such diversion systems. This

cost can then be added to the purchase price

of the water to obtain the overall cost of

developing a given water supply.

Intrabasin diversions redistribute water

within a major hydrologic basin such as the

Upper Basin, They include transfers between

individual subbasins such as the basins of the

Green River, the Colorado River mainstem,

and the White River. Intrabasin diversions

are not an acquisition strategy, but are a

method for relocating acquired water to oil

shale plants. Except for selected tracts using

ground water and for the few oil shale plants

built very close to major tributaries, new intrabasin diversions will be needed.

Intrabasin diversions would not reduce the

strain on the resources of the Colorado River

system. They would simply redistribute water

among individual subbasins. They could be

used, for example, to augment the sparse natural flows of the White River with surplus

surface water from the Colorado River mainstem. They could also be used to transport

stored surplus water from Federal reservoirs

in the Green River basin to developments

along the White River or the Colorado River

mainstem. Such diversions would be required

regardless of whether the oil shale water supplies are obtained from new or from existing

reservoirs,

costs

The costs of transporting water by an intrabasin diversion pipeline will depend on the

fees charged by the supplying reservoir and

the costs of building and operating the pipeline between the reservoir and the plantsite.

Some USBR estimates of the unit costs of selected intrabasin diversion projects are summarized in table 84. Reservoir charges and

operating costs for the pipeline are estimated, but not the costs of acquiring the

water that is moved through the pipeline, Several types of supply systems and flow rates

are shown, and both existing and new reservoirs are considered. The range of unit transportation costs is from $70 to $550/acre-ft. If

the highest and lowest are excluded, the

range is reduced to from $180 to $440/acre-ft.
394 ● An Assessment of 0il Shale Technologies

Table 84.–Summary of Cost Estimates for Intrabasin Diversions Within the Oil Shale Area

Data source Type of reservoir

Unit transportation cost,

Destination Flow volume, acre-ft/yr $/acre-ft

USBRa

New Tract C-a 57,000

USBR New

$240-390

Tract C-b 18,000 260-280

USBR New Tracts C-a and C-b 75,000 240-440

USBR Existing Tracts C-a and C-b 75,000 310-350

USBR New Tracts U-a and U-b 8,000 280-400

USBR New Tracts U-a and U-b 36,000 70-160

USBR Existing Tracts U-a and U-b 36,000 190-230

USBR New Tracts C-a, C-b, U-a, and U-b 111,000 180

DNRb

Existing Green River basin 14,000 280

30,000 260

DNR New Colorado River mainstem basin 29,000 550

84,000 400

DNR New White River basin 141,000 380

240,000 360

au s EIUreaU of lleclarnallorr ,41(er~a(iw Wafer Sources /or Pro/otype Od Shale Oeve/opmen( Salt Lake City Utah September 1974

Dcolora(fo ~pa~ment of Natural Resources Upper Co/orado t%ver L3asm Sec/(on 13(a) Assessrneru A RepOfl fO (he (/ S wafer Resources CourJc// (Oraff) August 1979

SOURCE Office of Technology Assessment

Summary of Supply Costs ●

Estimates of the costs of supplying indus- ●

trial-quality water to oil shale sites by means

of the several acquisition and transportation

strategies discussed previously are summa- ●

rized in table 85. The strategy costs include

the costs of purchasing the water, of transporting it from the point of acquisition to the ●

point of use, and of treating it for use in the

facilities. The estimates are approximate.

They were derived using the following assumptions: •

● All surface water acquired in the oil

shale region is transported over substanWater for interbasin diversions is purchased at a cost of $25/acre-ft.

Surface water is of good quality and

does not require substantial purification

prior to use.

Ground water quality is variable. Only

brackish ground water must be treated

prior to use.

All ground water is developed in the immediate vicinity of the oil shale plants.

Pipelines to points of use are of insignificant length.

Surplus water from existing reservoirs

costs $25/acre-ft. Water from new reservoirs costs $100/acre-ft.

tial distances through intrabasin pipe- The lowest cost strategy is the development

lines. of good quality ground water. Unit costs

Table 85.–Summary of Approximate Water Supply Costs for Several Acquisition Strategies

Component cost, $/acre-ft Strategy costs

Strategy Purchase Transportation Treatment $/acre-ft $/bbl of oila

Perfection of conditional decrees . . . . . . nil $180-440 nil $180-440 $0.09-0.23

Purchase from existing Federal reservoirs ... $ 2 5 180-440 nil 205-465 0.11-0.24

Purchase from new Federal reservoirs, ., ., 100 180-440 nil 280-540 0.14-0,28

Purchase of senior Irrigation rights ., . , 100-250 180-440 nil 280-690 0.14-0,36

High-quahty ground water . . 20-60 nil nil 20-60 nil-0.03

Brackish ground water . . . . . . . . . . 20-60 nil $250-530 270-590 0.14-0.30

Interbasin diversions ., ., 25 750-1,500 nil 775-1,525 0.40-0,79

aAssumes that 8500 acre-ft/yr IS consumed per 50,000-bbl/d Plant

SOURCE R F Probslem H Gold and R E Hicks, Waler Requirements Po//u(Iorr E/lecls, and Cos(s of Wafer .SWIp/y arrd Trealmerrf for fhe 0// S/ra/e induslry report prepared for OTA by Water Purification

Associates Oclober 1979
Ch. 9–WaterAva/labd/[y ● 395

range from essentially zero to about $0.03/bbl

of oil. The perfection of conditional water decrees is more costly, with unit costs ranging

from $0.09 to $0.2/bbl of oil. It is comparable

to purchasing surplus water from existing

Federal reservoirs. Purchasing water from

new Federal reservoirs is comparable in cost

to developing brackish ground water—about

$0.14 to $0.28/bbl of oil. Water obtained by

purchasing senior irrigation rights costs a little more. Interbasin diversions are by far the

most expensive, with unit costs from $0.40 to

$0.79.The higher unit cost for interbasin diversions was calculated under the assumption that water would be transported for 800

miles from the Columbia River Basin.

Except for interbasin diversions, the costs

of water supplies range from essentially zero

to about $0.36/bbl of upgraded shale oil. Such

water costs, which would have seemed unattractively high in the early 1970’s when oil

prices were about $3.00/bbl, are less consequential with current oil prices.

Legal and Institutional Considerations

The previous sections evaluated the physical and economic requirements of several

water supply strategies. The feasibility of any

of them also depends on a number of legal

and institutional factors, some of which are

examined below.

The Law of the River

As discussed previously, water development in the Upper Basin will be constrained

by the following factors:

● The operating criteria for Federal reservoirs in the Upper Basin, which require

a minimum discharge of 8.23 million

acre-ft/yr from Lake Powell.

● The Upper Colorado River Basin Compact of 1948, which limits the percentage of total Upper Basin depletions that

can be consumed by each State.

Different assumptions about virgin flow, regional growth rates, processing technologies,

and plantsites can lead to widely different

projections of the maximum size of the oil

shale industry that could be supplied by surplus surface water in 2000. Assuming 13.8-

million-acre-ft/yr virgin flow, medium growth

rates, and an industry with an average water

requirement of 8,500 acre-ft/yr per plant, the

limit appears to be about 2 million bbl/d.

This estimate assumes that the States in

the Upper Basin concur with the constraints

identified above. This is a questionable assumption because several aspects of the law

of the river are in direct conflict and not all

have been accepted by the States, particularly in the Upper Basin. For example, the Colorado River Compact of 1922 assured delivery of 7.5 million acre-ft/yr to both the Upper

and Lower Basins. This would be possible

with virgin flows of at least 15 million acreft/yr; it would not be possible with the lower

flows that have prevailed since 1930. The delivery obligation of the Mexican Water Treaty of 1944-45 is another source of conflict.

The treaty has not been a constraint on the

Upper Basin States because of their low

water demands in the past. However, it could

significantly affect future development programs. If the obligation were imposed on the

Upper Basin under the percentage formula of

the Upper Colorado River Compact of 1948,

Colorado’s share would be 388,000 acre-ft/yr,

Utah’s 173,000 acre-ft/yr, and Wyoming’s

10 105,OOO acre-ft/yr. If the Upper Basin States

were able to avoid the obligations through litigation, much higher levels of regional growth

and energy development would be possible.

The States may choose to follow this path.

For example, Colorado Governor Richard

Lamm maintains that Colorado and the other

Upper Basin States are not responsible for

satisfying the Mexican treaty obligation. 39

The director of the Colorado Water Conservation Board describes the State’s position as

follows: 40
396 ● An Assessment of Oil Shale Technologies

There has been a considerable amount of

study, together with a considerable amount

of speculation, concerning the amount of

water which is still available to the State of

Colorado under the terms of the Colorado

River Compact and the Upper Colorado River

Basin Compact. The problem with any study

is that no one can actually define the precise

amount of water to which Colorado is entitled under the terms of the compacts. In addition to existing uncertainties concerning

the compacts, the Mexican Treaty of 1944

further complicates any water supply study.

There are some basic disagreements among

the various states of the Colorado River Basin as to the obligation of each State for the

release of water to satisfy the Mexican Treaty. At some future time it appears likely that

these differences will be taken to the United

States Supreme Court for resolution.

Analysis of the legal position of the States in

this controversial matter is beyond the scope

of this assessment. It is possible, as the above

citation implies, that resistance to supply

obligations could be directed at the Mexican

treaty itself. However, because the treaty is a

national commitment, it is more likely that

resistance will be manifested against the

operating criteria for Federal reservoirs in

the Upper Basin. These criteria have been implemented by DOI through requirements for

minimum annual discharges from Lake Powell. The 8.23 -million-acre-f ft/yr discharge requirement incorporates both the Lower Basin

allocation of 7.5 million acre-ft/yr and the Upper Basin’s share of the Mexican obligation.

The Upper Basin States do not agree with the

operating criteria. 41 42

The Doctrine of Prior Appropriation

As stated earlier, most of the water rights

held by potential oil shale developers are

either conditional decrees, which are large in

quantity but junior in date of appropriation,

or absolute irrigation rights, which are small

but senior. Under the appropriation doctrine,

only the irrigation rights would provide

secure water supplies. They would be limited

to about 10,000 to 20,000 acre-ft/yr. If the

more junior decrees were perfected, they

could be curtailed during dry periods to provide water to more senior users, with severe

economic repercussions unless sufficient

water storage had previously been constructed. Any new rights obtained through

the prior appropriation system would be extremely junior and even more susceptible to

curtailment. Any large-scale use of ground

water for oil shale development would have

to protect the water rights of senior surface

water users.

Thus, the prior appropriation doctrine reduces the attractiveness of developing water

supplies through perfection of existing or future conditional decrees. Given the constraints of the appropriation system, it appears that the most reliable strategies would

be additional purchase of highly senior irrigation rights, purchase of surplus surface water from reservoirs, ground water development in selected areas, or interbasin diversions.

Federal Reserved Rights Doctrine

Under this doctrine, water has been set

aside for use on Federal lands, but the

amounts of water affected have not yet been

quantified. An important aspect of the doctrine is that Federal rights, when perfected,

will be senior to most others. Any more junior

user will face curtailment in times of water

shortage. The doctrine is an example of the

constraints imposed by prior appropriation.

The doctrine would affect any acquisition

strategy that relied on flows originating

within the Upper Basin. The only strategies

that would avoid the doctrine’s constraints

would be the development of nontributary

ground water, interbasin transfers specifically for use in oil shale facilities, or the purchase of irrigation rights that are senior to

the Federal rights. The latter would be difficult because many of the potential Federal

rights date back to the late 19th century.

It is possible, although uncertain, that the

Federal reserved rights could be used to

assist oil shale development. Because the
Ch. 9–Water Availability ● 397

Supreme Court has decided that the affected

water may only be used to further the purposes for which a reservation was established, it appears that the only relevant rights

would be those that might be claimed for the

Naval Oil Shale Reserves in Colorado and

Utah. These reserves were established in the

1920’s and the rights, if they could be implemented, would be quite senior. However, the

legal position of the rights in Colorado is complicated because the reserves do not border

on the Colorado River and they contain little

ground water. The Government has indicated

that it intends to claim water for the Colorado

reserves; the claim is in the early stages of

litigation by the State,

Environmental Legislation

There are a number of environmental laws

which do not directly restrict water use but

which could affect the siting of facilities, the

scale of operation, and particular water acquisition strategies, It is difficult to predict

their effects on development of water resources in the oil shale region, but it is important to note their existence and to recognize

that they could be of considerable consequence. Included are the following laws:

●

●

●

The Fish and Wildlife Coordination Act.

This Act required that all Federal agencies which direct, impound, or modify

water bodies must consult with USFWS.

Plans for water resource development

are reviewed by the Service to assure

that they include appropriate protective

measures for fish and wildlife.

The Endangered Species Act, Under this

Act, Federal agencies are to conserve

threatened or endangered species. In

the Upper Basin there are species of endangered fish—the humpback chub and

the Colorado River squawfish—which

might influence the siting of reservoirs

for energy development.

The National Wild and Scenic Rivers

Act. This Act is designed to preserve

portions of selected streams in a natural

state. The addition of any streams in the

●

Upper Basin to this system might affect

their future use for energy development,

The Wilderness Act. This Act establishes a National Wilderness Preservation System composed of federally

owned wilderness areas as designated

by Congress. The Act also stipulates the

conditions under which reservoirs and

other facilities can be built within these

areas. As a consequence of this Act, reservoirs and other water facilities needed

for energy development might be restricted in certain areas.

These laws should not reduce the availability of water within the Green River hydrologic

basin because there are presently no known

endangered species or designated water

areas within this basin. Furthermore, flows

of the Green River will be insignificantly affected by the projected levels of shale oil production.

In contrast, environmental legislation

could constrain oil shale development in the

White River basin. High levels of shale oil

production are projected for this basin, and

the associated water requirements could significantly reduce river flows. Furthermore,

the Colorado River squawfish, a federally

designated rare and endangered species, is

known to inhabit the lower portions of the

White River. In addition, the Flat Tops Wilderness area, an existing Federal wilderness,

includes portions of the headwaters of the

north and south forks of the White River. Flat

Tops could affect oil shale development in

that reservoirs and other structures would

not be permitted within the wilderness area,

except under presidential approval.

Water availability within the basin of the

Upper Colorado mainstem might be affected

by the Endangered Species Act, the Wilderness Act, and the National Wild and Scenic

Rivers Act. The Colorado River squawfish inhabits the Colorado River from the backwaters of Lake Powell upstream to the confluence of Plateau Creek. The humpback chub

is found in the Colorado mainstem downstream from the Colorado/Utah State line.
398 . An Assessment of Oil Shale Technologies

This basin also contains three designated

wilderness areas, and additional areas are

being considered for inclusion in the wilderness system pursuant to the ongoing Roadless

Area Review and Evaluation (RARE II) review. ’ New reservoir storage would probably

not be permitted in these areas. However,

they are in high-elevation watersheds and

thus would probably not contain potential

sites for reservoirs. In addition, several

rivers within this basin are being considered

for wild and scenic designation.

Thus, these environmental laws might affect the siting of storage reservoirs and limit

the amount of water that could be diverted

from certain rivers. Water supply strategies

that require extensive storage, such as the

purchase of irrigation water, could be affected.

Instream Water Flow

Instream flow requirements are legally

considered only in Colorado, where the State

has retained the right to obtain water for

preserving the natural environment to a reasonable degree. Instream rights are subject

to the prior appropriation system, and have

priority over consumptive rights only if they

are more senior in time. The State recognized

instream rights in 1973, and thus these rights

are quite junior and should not impede the

perfection of rights held by oil shale developers, some of which date back to 1949. However, if the oil shale industry were to file for

additional surface rights they would be junior

to the instream rights and would have a lower

priority in times of water shortage. Other

water acquisition strategies—such as the

purchase of senior irrigation rights, transbasin diversions, and ground water development—would not be significantly affected.

The purchase of surplus water from Federal

reservoirs would be affected only if the

*The Forest Service, in its RARE 11 program, is evaluating

over 66 million acres of land to determine their suitability for

designation as wilderness. During the period of initial evaluation and up to final disposition of the wilderness recommendation by Congress, these lands will be in some form of restrictive

management.

perfection of instream rights reduced the

amount of surplus water available for sale.

On the other hand, minimum flow bypasses

around reservoirs and dams are required for

aquatic life under the Clean Water Act. Depending on the interpretation given this Federal statute by the States, the total amount of

surplus surface water could be decreased.

Finally, USFWS is engaged in a study to develop strategies for reserving flows to maintain fish and wildlife habitats. Although they

are not yet part of the legal system, such

strategies might ultimately reduce surface

water availability for any type of growth in

the oil shale region.

Interbasin Transfers

Several legal barriers constrain interbasin

transfers of water to the oil shale region. The

Yellowstone River Basin Compact of 1950 (65

Stat. 663) requires approval of Wyoming and

Montana before transfers of Yellowstone

water can occur. Moreover, the Colorado

River Basin Project Act of 1968 (82 Stat. 885)

specifically prohibits the Secretary of the Interior from undertaking feasibility studies of

any plan to import water into the Colorado

River Basin until 1978. This moratorium on

water feasibility studies was extended under

the Reclamation Safety of Dams Act (92 Stat.

2471) until November 1988. Thus, until this

moratorium

occur.

is removed no new imports can

Salinity Standards

The States within the Colorado River system are committed to maintaining salinity at

or below the average 1972 levels in the lower

mainstem of the Colorado River. They have

developed salinity criteria for three points in

the Lower Basin—Hoover Dam, Parker Dam,

and Imperial Dam. The criteria have been approved by EPA, but are tentative and subject

to revision.

Salinity criteria could constrain oil shale

development because such development has
Ch. 9–Water Availability ● 399

been linked, through theoretical calculations,

to salinity increases in the river system. Increases could occur through either of two

mechanisms: salt loading (in which saline

wastewaters are discharged from an oil shale

plant) or concentration (in which waters of

higher than average quality are removed

from the Upper Basin tributaries for use in oil

shale processing). Salinity increases from

concentration are discussed in the next section of this chapter; those from salt loading

are discussed in chapter 8.

It is possible that salinity criteria could affect oil shale operations if such operations

acted to increase the salinity in the lower

mainstem. If this were the case, acquisition

strategies that increase the total depletions

from the river system would be constrained.

These would include the perfection of surface

water rights and the purchase of stored surface water. Ground water development

would be little affected, and interbasin diversions would not be constrained as long as the

salinity of incoming water was lower than

upstream surface flows within the basin. The

transfer of senior irrigation rights would

probably not be impeded because, as discussed in chapter 4, irrigation return flows

are the chief man-related source of salinity in

the Colorado River system. A reduction in

these flows through diversion to oil shale

processing should decrease the salinity of the

lower mainstem.

In summary, the effects of emerging salinity standards cannot be predicted with any

confidence. Certain water acquisition strategies would feel them more than others. They

should not severely affect any strategy if

water released from oil shale sites is treated

to achieve the discharge standards promulgated under the Federal Water Pollution Control Act.

Critical Uncertainties

The previous analyses have calculated that

an oil shale industry of up to 2 million bbl/d

could be supported to the year 2000 by surplus water that is legally available to the oil

shale States. This calculation is based on four

key assumptions:

The long-term average virgin flow is 13.8

million acre-f ft/yr—the running average

between 1930 and 1974.

The industry continues to use a mix of

mining and processing technologies similar to that which would be used if presently active and proposed projects were

completed.

Water demand for conventional uses in

the Upper Basin increases at a medium

rate.

The industry relies solely on surface

water; ground water is not ‘developed.

Following is a discussion of how the industry’s capacity might be affected if other

assumptions were made in these areas. Consideration is also given to the problems of

water availability beyond 2000.

Virgin Flow

As noted, the flows of the Colorado River

vary widely. Estimates of future water availability have been based on the flows measured at Lee Ferry after 1930 because earlier

estimates of virgin flow were less accurate.

(Before 1922, flows were not measured at Lee

Ferry; they were estimated from the measured flows of upstream tributaries. ) However, it is not clear that the flows encountered in the past will continue into the future.

The 13.8-million-acre-ft/yr average could sustain a large industry through 2000, but if the

long-term average decreased by 3 percent, to

13.4 million acre-ft/yr, there would be no

surplus surface water available then. Measurements of tree rings in the Colorado River

Basin suggest that the long-term average flow

may be closer to this level than to 13.8 million

acre-ft/yr. 43 On the other hand, if the flows increased to 14.2 million acre-ft/yr, 3 percent

above the 1930-74 average, there would be

sufficient surplus water in 2000 for a 4-

million-bbl/d industry. The average flow be-
—.

400 ● An Assessment of Oil Shale Technologies

tween 1906 and 1974 was 15.2 million acreft/yr. The average between 1922 (when flows

were first measured at Lee Ferry) and 1974

was 14.2 million acre-ft/yr.

Technology Mix

The industry’s actual average water requirement may be substantially higher or

lower than the 8,500 acre-ft/yr per plant that

would result if present trends continued. An

industry based solely on directly heated AGR

would consume only about 4,900 acre-ft/yr

per plant. The amount of surplus surface water projected for 2000 would be sufficient for

a 3.5-million-bbl/d industry if only this technology were employed. On the other hand, an

industry of indirectly heated AGR facilities

(at 12,300 acre-ft/yr per plant) could produce

only 1.4 million bbl/d from the same surplus.

Conventional Depletions

Although the medium growth rate for conventional water uses is regarded by the

States as most likely, it is possible that

demands could increase at a much higher or

lower rate. DNR analyzed the effects of low,

medium, and high growth rates. Although the

medium rate would allow an industry of up to

2 million bbl/d, a high rate would reduce the

surplus surface water by 247,000 acre-ft/yr

in 2000. Only a 550,00@ bbl/d industry could

be accommodated. On the other hand, a low

growth rate would increase the surplus by

326,000 acre-ft/yr and would allow an industry of up to 3.9 million bbl/d.

In any case, surplus water availability is

much less assured after 2000. If the low

growth rate prevails, demand will exceed

supply by 2027, even without an oil shale industry. With a medium growth rate, the

surplus will disappear by 2013. A high

growth rate will consume the surplus by

2007, again without oil shale development.

The implications of this potential problem for

oil shale are controversial. On the one side it

is argued that possible long-term water shortages should preclude the establishment of an

industry. On the other side, it is maintained

that a major industry could function for much

of its economic lifetime without interfering

with other users, and in any case would use

relatively little water. (A l-million-bbl/d industry would accelerate the point of critical

water shortage by about 3 years. )

Ground Water Development

If the presently active and proposed projects were completed, more than 40 percent of

the shale oil production would come from

ground water areas in the central and northern Piceance basin. If additional Federal

leasing were pursued, a much higher percentage of the industry’s facilities would be sited

in this area. Ground water will have to be developed on these sites in order to allow mining

or in situ retorting. The ground water extracted would have to be reinfected into the

source aquifer, or treated for discharge to

surface streams, or used in the facilities. If it

were used as process water, the need for surface water would be substantially reduced. If

15 percent of the roughly 25 million acre-ft in

the Piceance basin bedrock aquifers were

used for oil shale, it could support a l-millionbbl/d industry for 20 years. However, this

rate of consumption would exceed the recharge rate for the aquifers. Thus, the

ground water levels would decrease and

some of the surface streams that are supplied

by ground water discharge would dry up.

This would have relatively minor economic

ramifications because the rate of ground

water discharge is only about 20,000 acreft/yr. The environmental effects woulds be

mixed, as discussed in the next section.
Ch.9–WaterAva i

The Impacts of Using Water for Oil Shale Development

Introduction

The use of water by an oil shale industry

will cause economic, social, and ecological

changes in both the Upper and the Lower Basins of the Colorado River system. The effects

of salinity increases are of special concern

because salinity levels in the Colorado River

have been identified as a matter of national

concern.

44his section discusses the salinity

increases that are expected to result from

use of surface water for oil shale development. The overall impacts of water diversion on the Upper and Lower Basins are then

discussed. Because of time restrictions, OTA

did not perform an independent analysis of

these impacts, However, assessments have

recently been completed by DNR, USBR,

USGS, and USFWS. The following discussion

is largely based on the results of these

studies.

Impacts From the Construction and

Operation of Water Supply Facilities

Construction of dams, wells, and diversion

facilities would create jobs and increase disposable income. However, pressures on housing and on community facilities and services

would result. Both the positive and the negative effects would diminish once construction

was completed. Operation of the facilities

would require fewer than 10 employees per

plant, out of a total work force of approximately 1,500. Consequently, relatively few of

the socioeconomic impacts that may accrue

from creating an oil shale industry can be

associated with the water supply systems.

New reservoirs will flood land that may

presently be used for farming or grazing or

that may have special scenic or ecological

value. Homes, farms, businesses, roads, and

utility lines would have to be relocated, and

riparian and aquatic systems could be disturbed. These impacts should be minor compared to those of the mining and processing

operations. Because the reservoirs will be

relatively small, the overall impacts would be

small compared to those that were associated

with the construction of existing reservoirs.

(The new reservoirs needed for a l-millionbbl/d industry would increase the total water

storage in the Upper Basin by 0.6 percent. )

These impacts will be site specific and have

not yet been analyzed.

Impacts From Changes in Surface Flows

Extraction of surface water will decrease

the instream flows of the Colorado River and

its tributaries. These changes will have direct

effects on water users and indirect effects on

water quality and aquatic ecosystems. The

direct effects are considered in this section;

the indirect effects in the section that follows.

Decreased flows would reduce hydroelectric power production at specific CRSP reservoirs. According to the DNR assessment, revenue losses could reach $7 million per year in

2000 as a result of a 2.44-million-bbld/ industry. ’5 Flow reductions would also decrease deliveries to the Central Arizona project and

force the agricultural industry in the Lower

Basin to rely on more expensive ground water

pumping. Net farm income would be reduced

by about $2.3 million per year by 2000 as a

result of a 2.44 million-bbl/d industry.46

According to USBR, environmental impacts

in the Lower Basin depend more on reservoir

operating criteria than they do on the quantity of water in a particular stream, and flow

reductions in the Lower Basin would have significant effects only in that portion of the Col-
402 ● An Assessment of Oil Shale Technologies

orado River between Glen Canyon Dam and

Lake Mead.47

Reductions in instream flow will also affect

recreational use of some stream reaches.

Although most recreational activities, such as

rafting, boating, and kayaking, would remain

unchanged in 2000 even with high levels of oil

shale development, negative impacts would

occur in two river reaches. In the Colorado

River between Rifle, Colo., and its confluence

with the Gunnison River, rowing and rafting

conditions would be degraded from the present fair condition to poor if a 2.44-millionbbl/d industry were established. Fishing conditions would be reduced from fair to poor

with substantially lower levels of development. In the White River from Meeker, Colo.,

to Ouray, Utah, conditions for canoeing, kayaking, and fishing would be reduced from excellent to good. Adverse public reaction

should be expected. Secondary impacts on

tourism and recreational service suppliers

may occur, although no detailed analysis of

these impacts has been undertaken.

Impacts on Water Quality

Withdrawal of water of relatively high

quality from upstream tributaries of the Colorado River system will increase salinity levels in the lower reaches of the Colorado River

by making the water unavailable for dilution

of more saline streams that enter the river

below the withdrawal point. Some of the estimates that have been made of this salt concentration* effect are summarized in table

86.

48-54 Included for each source are estimates

of salinity increases for the project or industry originally analyzed and estimates scaled

to a common basis of a l-million-bbl/d indus-

. try. As shown, a l-million-bbl/d industry in

the Upper Basin could increase salinity levels

at Lower Basin measuring stations by 0.2 to

2.4 percent. The estimates incorporate widely differing assumptions regarding plantsiting, types of processing technologies, water

requirements, and quality of water diverted.

A very approximate average salinity increase for a l-million-bbl/d industry might be

about 1 percent.

It should be noted that similar effects

would be experienced if the same amount of

water were used for other purposes. The University of Wisconsin study cited in table 86

estimated that diversion of 300,000 acre-ft/yr

of upstream water to oil shale would increase

salinity at Imperial Dam by about 20 mg/l. If

the same quantity of water were used for irrigation, the salinity increase would be about

57 mg/1. Exportation of the water from the Upper Basin would increase salinity by about 24

mg/l. 55

The economic losses, including damage to

agricultural, municipal, and industrial users

*Increases in salt loading are discussed in ch. 8.

Table 86.–Projected Salinity Changes in the Lower Colorado River From Oil Shale Development

Salinity increase from 011 shale

Shale 011 capacity

Source of estimate Reference modeled, bbl/d Measuring station

Colorado Department of Health 48 1,000,000b

Glen Canyon Dam

National Academy of Science s 49 800,000 Hoover Dam

1,600,000

Stanford Research Institute ., ., 50 250,000 Hoover Dam

Unversity of Wisconsin 51 1,000,000 Imperial Dam

Department of the Intenor 52 1,000,000 Hoover Dam

Bureau of Land Management 53 47,000 Hoover Dam

U S. Bureau of Reclamatio n 54 1,300,000 Imperial Dam

2,440,000

Present

salinity, mg/la

609

745

745

850

745

745

850

For model

Industry

mg/l

4

2

4

1

20

10-15

0 1

7

15

For 1 million bbl/d

mg/l Percent

4 0.7

1,6 0 2

2 5 0 3

4 0.7

20 2 4

10-15 1 3-20

2 6 0.3

5 0 6

6 0 7

aData from reference 59

Calculated from estimates for Increases in the White River and the Colorado Mainstem

SOURCE Off ice of Technology Assessment
in the Lower Basin could reach $5.4 million

per year in 2000 for a 2.44-million-bbl/d industry. This estimate is based on a salinity increase at Imperial Dam of 18.1 mg/l—l.8 percent of present salinity levels.’”

The full salinity impacts of water used in

the Upper Basin are not felt until much later

in the Lower Basin because of the dampening

effects of Lake Powell and Lake Mead. For

example, the Colorado River Basin Salinity

Control Forum estimates that the full effects

do not occur until after 17 years. The forecasts for 2000 therefore underestimate salinity effects on the Lower Basin, In addition, an

assumption of the USBR analysis is that three

authorized desalinization plants will be in

operation by 2000, removing over 700,000

ton/yr of salt.

To a lesser extent other water quality parameters will be affected by the use of water

for oil shale development. Sediment loading

will increase in some reaches as the result in

changes in land use associated with the

dams, pipelines, and roads for the water supply facilities. Changes in river flow from reservoir operation could alter sediment transport and the biochemical oxygen demand in

some reaches. These impacts have not yet

been assessed in detail.

Impacts on River Ecology

Changes in instream flow can affect the

aquatic ecosystem including the habitat of

sport fish and rare and endangered species.

Of special concern are the effects on rainbow

trout, a major sport fish, and the Colorado

River squawfish and humpback chub which

are endangered species. Analyses of the impact of water use for oil shale on the rainbow

trout, the squawfish, and numerous other fish

species have been undertaken by USFWS

and the U.S. Heritage and Conservation Service,

57 but the effects on the humpback chub

have not been assessed due to lack of criteria

in the USFWS study, These assessments do

not include studies of the complete aquatic

ecosystem and exclude impacts on the ecology of smaller streams at high elevation so no

conclusions can be drawn on impacts on

these streams at present.

Limited effects on fishery habitats were indicated for the Upper Basin as a whole, except for the White River. For rainbow trout in

the Green River, the fry, juvenile, and adult

stages would be little affected by a 2.44-

million-bbl/d industry. Spawning conditions

would remain poor. Adult Colorado River

squawfish in the Yampa River would not be

affected, but conditions for squawfish fry in

the same stream would improve from their

present poor level to fair. Conditions for adult

squawfish in the White River would degrade

from their present level of excellent to good.

Assessment of impacts on plants, invertebrates, and other components of the aquatic

ecosystem have not been undertaken,

Transfer of Water From Irrigated

Agriculture

Although it is not necessary to take water

from irrigated agriculture to supply oil shale

developments, such transfers are legally permitted. Because the economic value of an

acre-foot of water to an oil shale developer is

much greater than to irrigated agriculture,

transfers of water rights could occur in some

areas. These transfers would have social and

economic ramifications, including a redistribution of income. Farm income would be reduced, but these reductions would be countered by a regional income gain because of increased employment in the oil shale industry,

According to DNR, the gain would be 10 to

100 times greater than the 10SS.

58 The number

of farming families would also be reduced.

Significantly larger impacts would be experienced, however, from factors not directly related to water use patterns, such as the competition for local labor and the purchase of

agricultural lands for municipal expansion.

Irrigated agriculture diverts large quantities of surface water, but only a portion is

actually consumed. The balance eventually
——.

404 ● An Assessment of 01/ Shale Technologies

returns to the water systems through agricultural return flows and/or percolation into

ground water aquifers. Oil shale developers

can only purchase rights to the consumptive

portion of the diversion. Therefore, if irrigation rights were transferred to oil shale development, less water would be diverted from

surface streams, and stream flows would increase. The effects of these increases were

not modeled for DNR because of their small

size and because a significant diversion of

agricultural water to oil shale development is

not anticipated in most areas. If significant

effects occurred at all, they would most likely

be in the White River Basin, where fish habitats and recreational opportunities would be

improved as a consequence.

Ground Water Development

The impacts caused by well-drilling and

maintenance would be similar to those for the

construction of reservoir and pipeline facilities for surface water development—relatively small and of short duration. After the

wells are drilled, only a few workers would

be needed for maintenance. The number

would be small in comparison with the estimated total work force of an operating oil

shale plant. Unlike purchase of irrigation

rights, ground water development should not

have significant effects on the economic base

of the oil shale region.

Stream flows would not be significantly reduced for the overall basin, although substanPhoto credit OTA staff

Pumping water from the White River for agricultural purposes
Ch. 9–Water Availability ● 405

tial reductions would occur in those areas in

which ground water discharge supplies a major portion of surface flows, For example,

some streams in the Piceance basin are fed

by ground water discharge during most of the

year. Aquifer drawdown as a result of

ground water development would reduce

flows in these streams, and in some cases

would completely eliminate them except during the spring snowmelt. Fishery habitat in

these streams would be severely affected.

According to DNR, the overall effects of

ground water development on fish habitats

and recreation would be much less than

would be encountered with water acquisition

strategies that relied solely on surface water

diversions. 5

’ However, heavy dependence on

ground water could lead to using underground water resources faster than the rate

of recharge and in some instances to mining

geologically old water. The use of such water

constitutes an irrevocable decision to exploit

a nonrenewable resource, hence precluding

its use for other purposes in the future.

Oil shale projects that use low-quality

ground water may produce a net decrease in

salinity in Colorado. For example, the Superior Oil project in Colorado’s Piceance basin

will use water from the lower bedrock aquifer that has a salinity concentration of about

26,000 mg/l—about 30 times the salinity of

the Colorado River at Imperial Dam. Withdrawal of this water would reduce the quantity of salts discharged into Piceance Creek

by about 24,500 ton/yr. As a result, the salinity of Piceance Creek would decrease by

about 1,040 mg/l. Salinity in the near reaches

of the White River, into which Piceance Creek

discharges, would be reduced by about 40

mg/l.

60 Salinity at Glen Canyon Dam would

decrease by about 1.6 mg/1—about 0.3 percent of its present level.

Methods for Increasing Water Availability

Sufficient water should be physically available in the Upper Basin to support a large oil

shale industry while simultaneously satisfying the needs of other users. However, water

scarcity could constrain regional growth

after 2000. Additional surface flows could be

provided through conservation (i.e., more efficient use of water), interbasin diversions, and

possibly by weather modification. Water use

efficiency and weather modification are discussed below; interbasin diversions were discussed earlier.

More Efficient Use

By reducing demand, water conservation

would increase net water availability. Opportunities exist in municipalities, in irrigated

agriculture, and in industrial activities including oil shale development.

Municipal

Because municipalities in the oil shale region consume little water, conservation strategies would have to be focused on the larger

cities in Colorado’s Front Range Urban Corridor that import water from the Upper Basin. For example, if Front Range cities lowered consumption by 20 percent, exports

would be reduced by about 100,000 acreft/yr. 61 Demand could be reduced by methods

such as restricted lawn watering or imposed

peak-use surcharges, seasonal pricing differentials, and price incentives. Recycling systems could also be considered, but implementation could be hindered by high costs and

their unfavorable image.

Irrigated Agriculture

Present irrigation methods are inexpensive

to the farmer but relatively inefficient. Even

small improvements could release large

quantities of water for other purposes and

decrease the quantity and perhaps salinity of

agricultural return flows. Losses from canals

could be reduced by adding impermeable linings or pipelines. Sprinkler systems or trickle

irrigation would reduce evaporation from
406 ● An Assessment ot 011 Shale Technologies

field soils. Losses to noncrop vegetation could

be reduced by eliminating the vegetation.

Crop evapotranspiration and loss of cropcaptured water could be reduced by substituting

crops that need little or no irrigation water.

Few of these strategies could be introduced

on a large scale, however, without substantial economic, social, and environmental penalties. Mechanical irrigation, for example,

would be very expensive, as would fabricated

pipelines. Vegetation removal could threaten

the ecological balance along stream courses

and manmade waterways. Dryland farming

might not be technically or economically feasible. Furthermore, conservation could be

risky because if a farmer did not use all of the

water covered by his water rights, abandonment could be declared.62

Estimating possible reductions by conservation is technically straightforward. Estimating likely reductions is much more difficult because of the social and economic

complications. DNR concluded that reductions would probably not exceed 120,000

acre-ft/yr even with vigorous programs.

Industrial

Oil shale plants will use water efficiently.

This is a consequence more of the nature of

the processing technologies and the desire to

avoid having to treat excess process water to

discharge standards than it is of an interest

in water conservation. * However, different

technologies consume different amounts of

water for the same production rate and the

overall requirements of the industry could be

reduced by encouraging the use of processes

with the lowest water requirements. It is

unlikely that technologies would be chosen

solely on this basis because water costs are a

very small fraction of total processing costs.

*The U.S. Water Resources Council states that an AGR plant

would consume about 89 percent less water than a steam- electric powerplant with the same net energy output, 25 to 87 percent less than a comparable coal gasification plant, and 40 to

90 percent less than a comparable coal liquefaction facility.’)’
Ch 9–Water Availability ● 407

Offsite powerplants to support municipal

growth could adopt conservation methods

without substantially increasing power costs.

It has been estimated that water requirements for power generation in the oil shale

States will increase by as much as 221,000

acre-ft/yr before 2000, If the new powerplants relied on a combination of wet and dry

cooling, water consumption could be reduced

by about 175,000 acre-ft/yr, sufficient water

for production of 1 million bbl/d of shale

oil. 6 5

Weather Modification

Cloud seeding could be used to enhance

precipitation and thereby increase surface

water and ground water resources. The results of three major projects during the last

two decades suggest that overall increases in

snowfall could range from 5 to 20 percent. It

appears that if snowfall were increased by

10 percent, runoff might increase by from 5 to

20 percent and might add up to 2.0 million

acre-ft/yr to normal surface flows. Ground

water aquifers would also be affected because they are recharged principally from

snowpack. USGS has estimated that a 10-

percent increase in snowfall in the Piceance

basin would add over 10,000 acre-ft/yr of

ground water that could be withdrawn with

out disrupting the aquifer equilibrium.66

Preliminary cost estimates range from $1

to $10/acre-ft of additional runoff, There

would be additional costs for capturing and

transporting the augmented flows, and storage facilities would still be needed, Any additional runoff would be subject to the prior appropriation system because the augmented

flows would be indistinguishable from natural flows. Because of the problem of uncertain ownership, the delivered water cost

might well exceed the costs of other supply

methods.

The consequences of weather modification

are not well understood, but a successful program could be expected to have widespread

effects on the region’s ecosystems. Species

composition, vegetation growth rates, and

wildlife habitats might be altered. Although

there could be recreational benefits from increased snowfall and higher streamflows, agriculture and transportation could be hampered. Losses in precipitation to areas beyond the zone of augmented rainfall or snowfall could have severe ecological, agricultural, and economic impacts. There could be

legal difficulties if cloud seeding were linked

to drought in downwind areas.

Policy Options

The distribution of water from the Colorado River system is governed by a complex

framework of interstate and interregional

compacts, State and Federal laws, Supreme

Court decisions, and international treaties.

Policy decisions affecting the use of this

water for oil shale development must take

into account both the provisions of these

documents and the need to protect the rights

of competing water users. A number of policy

options that would affect the availability of

water for an oil shale industry in the Upper

Colorado River Basin are examined below.

Their implementation could involve actions

by Congress, the administration, State governments, and the oil shale developers.

The Determination of Water Needs

In order to more accurately assess the total

amount of surplus surface water that will be

available for additional growth in the Upper

Basin, the amount needed by all projected

users must be determined. The uncertainty

about the future availability of water supplies to the Upper Basin would be reduced if

the necessary determinations were carried
408 ● An Assessment of Oil Shale Technologies

out by Congress, by Federal and State governments, and by private developers. Some possible options are:

The development of a water management

system.—Preliminary water management

studies have been conducted by the Bureau of

Reclamation and by individual developers

and other users. However, no systematic

basin-wide evaluation of water management

alternatives has compared water supply options with respect to their water and energy

efficiency, their costs and benefits, and their

environmental and social effects. Such an

assessment—involving Federal, State, and local governments; regional energy developers;

other users; and the general public—may be

an appropriate prelude to actions to construct new water storage and diversion projects. It could be especially useful in evaluating and coordinating such controversial options as the importation of water. Funding

could be provided by DOI, DOE, or other

agencies. The study could be managed by the

Bureau of Reclamation or by Colorado River

Compact Commission.

The determination of the amount of water

needed by the Federal Government.—This

could be done for Federal lands for which

water rights are set aside under the Federal

reserved rights doctrine. One possible alternative for Congress is to provide legislation to

facilitate this determination in coordination

with one of the administration’s task forces

devoted to evaluating Indian and Federal reserved water rights.

It is anticipated that the largest Federal

claims in the oil shale region will be for the

Naval Oil Shale Reserves. The U.S. Navy has

made a preliminary filing with the Colorado

water court for 45,OOO acre-ft/yr. In addition,

small amounts of water may be needed for diversions, impoundments, wells, and stream

flows. Although filings are being made under

this doctrine, most indications are that the

total amount of water that will be claimed by

the Federal Government in the oil shale region will not be excessive. The exact quantities, however, have not been determined.

Because the extent of future filings is unknown, reliable estimates of water availability for regional growth cannot be made. The

uncertainty would be reduced if there were

some indication in the near future of the

amounts that will be claimed under this doctrine.

The determination of water needs by the

Colorado State Government.—In Colorado,

the requirements for instream flows are

legally considered only where the State has

retained the right to obtain water for preservation of the natural environment. Colorado

recognized instream rights in 1973; thus,

these rights are junior and should not impede

the perfection of rights held by other users

prior to this date. However, such rights could

affect the amount of water available to users

who file in the future for additional surface

rights— any additional rights would have a

lower priority in times of water shortage. The

State is presently in the process of filing for

rights for instream water needs. Completing

this process would further clarify the total

amount of water available for development in

this region.

The determination of water needs by municipalities, private developers, and other

water users. —Water rights in the oil shale

States have been granted liberally. As a result, the quantities of water covered by conditional decrees far exceed the available resources of the river. At the same time, not all

the conditional decrees have been perfected,

and relatively little of the claimed water is actually being used. If it could be determined

how much of the water allocated under the

conditional decrees will actually be beneficially used in the near term (for municipal,

agricultural, or industrial purposes), then the

Upper Basin States would have a clearer indication of the actual amount of surplus water

available.

Reservoir Siting and

Direct-Flow Diversions

All water acquisition strategies that rely

on the large-scale development of surface

water resources within the oil shale area
would necessitate the construction of new

reservoirs and direct-flow diversions (e.g.,

pipelines). Such construction might be hampered, delayed, or even disallowed under provisions of the Endangered Species Act, the

National Wild and Scenic Rivers Act, and the

Wilderness Act. Potential problems could be

reduced through several mechanisms.

Identification of endangered or threatened species. —The Endangered Species Act

provides for the Federal identification of endangered and threatened species of fish,

wildlife, and plants; prohibits private activity

that imperils such species; and requires Federal agencies to avoid any activities that

would jeopardize such species or result in the

destruction of critical habitats. A number of

studies are underway to identify endangered

and threatened species in the Upper Basin.

To date, two federally designated rare and

endangered fish species have been found in

the waters of the oil shale region. The Colorado River squawfish inhabits the lower portions of the White River and the Colorado

River from the backwaters of Lake Powell upstream to the confluence of Plateau Creek.

The humpback chub lives in the Colorado

mainstem downstream from the Colorado/

Utah State line, Additional species requiring

protection may be found in the future.

The Act may be interpreted as restricting

activities that might adversely affect the

critical habitats of such species, although

none has been declared for the squawfish or

the humpback chub. Knowing their approximate locations would be helpful because the

timely siting of reservoirs and direct-flow

diversions could be affected by agency interpretations involving instream flows. Should

construction of these facilities begin before

the critical areas were identified, there could

be opposition to their completion, and water

supplies from a particular reach of a river

could be delayed or interrupted. If the locations of all designated critical habitats were

identified by DOI and the required biological

opinions obtained, the facilities could be sited

to minimize interference and delay.

Designation of rivers to be set aside under

the Wild and Scenic Rivers Act. —Any river

area possessing one or more scenic, recreational, archeologic, or scientific values and in

a free-flowing condition, or under restoration

to such condition, may be considered for inclusion in the Wild and Scenic Rivers System.

A number of rivers have already been designated under this legislation, and Congress is

considering adding others. To date none in

the oil shale region has been designated; however, several within the Colorado mainstem

basin are being considered for wild and scenic designation. The amount of water that

could be diverted from specific river reaches

could be reduced if these rivers are set aside,

thus an early designation of rivers eligible

under this legislation would be of value in

planning for future shale oil production.

Given this information, direct-flow diversions

could be sited downstream to those portions

of rivers designated as wild and scenic

rivers. This would avoid a direct conflict

within a given river stretch but could add to

the water supply cost.

Designation of wilderness areas.—The

Wilderness Act created the National Wilderness Preservation System to provide “the

benefits of an enduring resource of wilderness” for the whole Nation. In keeping with

the purpose of preservation, the use of these

areas is highly restricted. To date four areas

in the White River basin and the Colorado

mainstem basin have been designated under

this legislation. Also, additional areas are

being considered for inclusion in the system

pursuant to the ongoing RARE II review. New

reservoir storage would probably not be permitted in these areas, once designated. Since

they are located at higher elevations in upper

watersheds, they would probably not contain

potential sites for reservoirs; however, additional wilderness areas at lower elevations

could pose problems in siting storage facilities. A complete listing of wilderness areas

that might be considered in the near uture

would aid potential developers in locating

their facilities in other areas.
410 w An Assessment of Oil Shale Technologies

Financing and Building New Reservoirs

New reservoir and storage facilities would

need to be constructed if a large shale industry were to be created. There area number of

possible policy options for the financing and

construction of such facilities.

Federal financing. —Congress could provide for the construction and funding of new

Federal water projects through two mechanisms. First, Congress could appropriate

funds for those Federal water projects that

already have been authorized. Several projects have been evaluated by WPRS (formerly

USBR), and their construction approved. Actual construction of these projects cannot

begin until they are funded. However, not all

of these projects have been evaluated for

their suitability to supply water for oil shale

development, and some project features may

not be optimally located to serve oil shale

projects.

A second option available to Congress is

the passage of legislation that would specify

the construction and funding of new, not

previously authorized Federal water projects. However, unless language was included

to expedite construction, these projects

would require a long review process. They

could, however, be designed and sited with

their purposes as water sources for oil shale

(as well as other possible uses) in mind. An

example would be constructing irrigation reservoirs with additional capacity for oil shale

requirements.

Under either option, DOI, through USBR,

could operate these reservoirs in accordance

with State water laws. Their costs could be

recovered over the operating life of the facilities from revenues generated by selling

water to oil shale developers and other users

and in accordance with authorizing legislation.

State participation. —A State organization,

such as the Colorado River Water Conservation District (CRWCD), could finance and construct new storage facilities. CRWCD holds

large storage decrees in the basin of the Colorado River mainstem. The river district

maintains that these decrees will likely be

used as a source of supply for an oil shale industry. Several possibilities exist for the

funding of reservoirs. One possible funding

arrangement might be to sell water from existing State-administered reservoirs, such as

Green Mountain and Reudi, to oil shale developers at very high cost (e.g., $250/acre-ft/yr).

The short-term needs of many potential oil

shale developers, depending on the siting of

their facilities, could be met from such existing reservoirs. The profits from such sales

could be used as leverage capital for marketing public revenue bonds. The capital generated from these bonds could then be used to

finance the new reservoir facilities that

would be needed by an oil shale industry in

the longer term. A second funding scheme,

which has been practiced by CRWCD in the

past, is to sell options for water from proposed reservoirs to potential water users,

thus raising the funds needed for the construction of the reservoirs.

Developer financing.—Reservoir and storage facilities could be financed and constructed by the oil shale industry itself.

Financing and Implementing

More Efficient Practices and Water

Augmentation

Surface flows in the Upper Basin could be

increased if water conservation procedures

were practiced by irrigated agriculture,

municipalities, and industry. Weather modification is another possibility. Since carrying

out these approaches could be quite costly for

a particular developer or municipality, their

chance of being implemented might improve

if Federal and State governments were to

supply some special funding or incentives.

The following are some possible ways this

could be done.

Funding and implementing water use

practices.—Techniques for more efficient

water use in irrigation and farming were illustrated earlier. As noted, farmers would be
taking risks by adopting water conservation

strategies because capital recovery would be

uncertain and they might lose water rights.

At the sometime, improvements in irrigation

and farming practices could substantially reduce the demands for water in the Upper

Basin. A number of options are available that

would encourage such improvements. Congress could provide financial incentives,

through such mechanisms as tax advantages,

to those farmers who used water more efficiently, Technical assistance teams specializing in conservation techniques could also be

provided to cooperating farmers by the Federal and State governments. In addition, Congress could give direct financial assistance

through grant programs, administered either

by Federal or by State agencies.

Individual municipalities could institute

voluntary education programs and regulatory

strategies aimed at reducing overall water

consumption. Regulatory programs could restrict the watering of lawns and promote the

use of water-saving devices. Cities could establish peak-use surcharges, seasonal pricing

differentials, and price incentives to reduce

usage. Local municipalities could also adopt

water conservation techniques for their

wastewater treatment facilities.

Municipal conservation techniques, whether voluntary or mandatory, are costly. Financing is needed to pay for administrative

personnel as well as to produce and distribute educational materials. While these programs would probably be administered at the

local level, they could be financed at the Federal or State level by direct grants or costsharing programs. To help pay for carrying

out costly conservation procedures in municipal wastewater treatment facilities, Congress

could provide tax incentives for such expenditures.

Although oil shale facilities are expected to

be efficient water users, a number of waterconserving techniques could be used to minimize overall consumption. For example, some

development technologies require less water

than others—directly heated AGR has the

lowest requirement (4,900 acre-ft/yr for

50,000 bbl/d of shale oil), while indirectly

heated AGR has the highest (about 12,300

acre-ft/yr for the same output). Total industry

consumption could be reduced by encouraging the use of the lowest water-consuming

process. One congressional option would be

to provide financial incentives to those facilities that implemented this process.

Another would be to provide tax advantages

to any facility that introduced specific waterconserving techniques. Also, through Government contracts, Federal agencies could specifically fund R&D by developers to improve

the efficient use of water.

Funding of weather modification programs.—A number of Federal agencies, including the Departments of Commerce and of

the Interior, have sponsored programs relating to winter orographic weather modification, The Federal Government could continue

to fund programs in the Upper Basin with the

aim of eventually increasing overall regional

surface flows. If programs are funded, they

should include work to better understand the

impacts of weather modification.

Weather modification programs, although

costly, could be undertaken by a State organization, municipality, or private developer.

However, the ownership of any additional

surface runoff would be uncertain under the

current water appropriation system, and

legal complications could arise if cloud seeding were linked to drought in other areas. It is

unlikely that a particular municipality or private developer would undertake such a program without some assurance that a portion

of any additional runoff would be available

for its own use.
412 • An Assessment of 0il Shale Technologies

Federal Sources of Water for

Oil Shale Development

Congress, under its constitutional powers,

could make water available for oil shale developments from Federal water projects, or

potentially from the reserved right doctrine.

If Congress decides that water from congressionally funded projects should be made

available for oil shale development, then any

legislation enacted should provide that the

term “industrial use or purpose” includes the

use of water for oil shale development. * Congress could also amend the authorizing legislation for those projects from which water for

oil shale development might be sought to permit the use of their water for that purpose. In

such a case, legislation may be required if the

project authorization does not list among the

contemplated purposes for its water “industrial purposes” or some other category that

could encompass oil shale facilities. The objective of such legislation would be to overcome any administrative reluctance to permit

the use of water for oil shale development

under an authorization that did not specifically mention it.

The power of Congress over reserved waters is more limited than its power over waters in congressionally funded projects. The

use of water under the reserved right doctrine must be “in furtherance of the purpose

of the reservation. ” For this reason, Federal

water rights do not seem to be likely sources

for oil shale development, except perhaps in

the case of lands set aside for the Naval Oil

Shale Reserves. This matter, however, is in

the early stages of litigation. New reservations of land set aside for the purpose of making water available for oil shale development

would not appear to be a feasible alternative,

*A Memorandum of Understanding exists between DOI and

the State of Colorado with respect 10 the use of water from existing or authorized WPRS (formerly USBR) projects. The State

desires that the water not be changed from agricultural, municipal, or light industry uses to energy production (including oil

shale), that are inconsistent with State policies. Under this

memorandum, the State will review any application to redistribute water from conventional uses to energy production. The

memorandum could be superseded by congressional directives

of overriding national importance.

since Federal reserved water rights are subject to rights vested prior to the date of the

reservation.

A final option available to Congress would

be to deny Federal water for oil shale development, if it decides that such development

should not be given a high priority.

The Allocation of Water Resources

If Congress were to pass legislation encouraging the development of an oil shale industry it might wish to address the issue of

how the necessary water would be supplied

and how oil shale legislation might affect

water allocation.

Water in the oil shale region is presently

distributed by a complex framework of interstate and interregional compacts, State

and Federal laws, Supreme Court decisions,

and international treaty and administrative

decisions. Within Western States, water

rights are apportioned by the States to competing users according to a doctrine of prior

appropriation under which water rights are a

form of property separate from the land.

If control over the water supply for oil

shale is to be left to the States, then Congress

should probably so specify in oil shale legislation to avoid any question of the preemption

of State water laws. Legislation that would

confirm preservation to the States of the

same power over water for oil shale as they

have over other water supplies should require the developer to comply with State procedures in securing a water supply and provide that the established State appropriation

system has the same authority to grant, deny,

or place conditions on water rights and permits as would prevail in the absence of the

legislation.

If Congress were to attempt to remove the

water supply for oil shale production from

the control of the States, strong legal and

political resistance would ensue. Such resistance could delay oil shale development.
Interbasin Diversions

Interbasin diversion is a technically feasible although costly* option for bringing additional water to the oil shale region. There are

also serious political obstacles to this alternative. The Reclamation Safety of Dams Act

of 1978, amending the Colorado River Basin

Project Act, prohibits the Secretary of the Interior from studying the importation of water

into the Colorado River Basin until 1988. If it

were decided to pursue this option as a

means of supplying water to an oil shale industry coming on line in 1990, this prohibition

would have to be lifted.

Interbasin diversions could be used to

relieve the water problems of the region in

several ways. Water could be transferred directly to the area, either exclusively for oil

*The cost of supplving water by interbasin transfers is estimated to be no more than 5 percent of the total cost of producing a barrel of shale oil.

Chapter 9

1

T. D. Nevens, et al., Predicted Costs of Environmental Controls for a Commercial Oil Shale industry: Volume 1, An Engineering Analysis, Department of Energy, Washington, D. C., July 1979,

2R. E. Hicks and R. F. Probstein, “Water Management in Surface and In Situ Oil Shale Processing, ” paper No. 39e, 87th National Meeting of the

AIChE, Boston, Mass., August 1979.

3Colony Development Operation, An Environmental Impact Analysis for a Shale Oil Complex at

Parachute Creek, Colorado, vol. I, Denver, Colo,,

1974.

4

J. M. McKee and S. K. Kunchal, “Energy and

Water Requirements for an Oil Shale Plant Based

on Paraho Processes, ” Colorado School of Mines

Quarterly, vol. 71, No. 4, October 1976, pp. 49-64.

‘C-b Shale Oil Venture, Oil Shale Tract C-b Modifications to Detailed Development Plan, report

submitted to the Area Oil Shale Supervisor,

Grand Junction, Colo., February 1977.

‘The Ralph M, Parsons Co., “Water Flow Diagram for Treatment of Mine Drainage Water,”

personal communication to Water Purification

Associates from C-b Shale Oil Venture, July 1978.

‘Rio Blanco Oil Shale Project, Revised Detailed

shale development or for all users. Alternatively, the water needs of Colorado’s eastern

slope cities, presently being supplied in part

from the Upper Colorado River Basin, could

be met from other hydrologic basins. The

water presently being exported from the Upper Basin then could be used for oil shale development. In a third application of interbasin transfers, all or a portion of the

750,000 acre-ft/yr presently being supplied to

Mexico by the Upper Basin States under the

Mexican Water Treaty of 1944-45 could be

taken from another hydrological basin (perhaps the Mississippi basin). The water thus

freed in the Upper Basin could be assigned in

part to oil shale development (750,000 acreft/yr would be sufficient for a 3,000,000- to

7,500,000-bbl/d shale oil industry).

The transfer of water from another hydrologic basin could have detrimental impacts on

that basin, and

cede diversion.

References

impact analysis should preDevelopment Plan, Oil Shale Tract C-a, report submitted to the Area Oil Shale Supervisor, Grand

Junction, Colo., May 1977.

8Rio Blanco Oil Shale Project, Supplemental Material to Revised Detailed Development Plan, Oil

Shale Tract C-a, report submitted to the Area Oil

Shale Supervisor, Grand Junction, Colo., September 1977.

9

Eyring Research Institute and Sutron Corp., An

Analysis of Water Requirements for Oil Shale

Processing by Surface Retorting, report TID27954, Energy Research and Development Administration, Washington, D. C., Aug. 5, 1976.

10R. F. Probstein and H. Gold, Water in Synthetic Fuel Production: The Technology and Alternatives, MIT Press, Cambridge, Mass., 1978.

1lGolder Associates, Inc., Water Management

in Oil Shale Mining: Volume 1, report prepared for

the U.S. Bureau of Mines, Washington, D, C., NTIS

No. PB-276 085, September 1977.

12Cameron Engineers, Inc., Draft Working

Paper for a Case Study of Oil Shale Technology:

Oil Shale Retorting Technology, prepared for

OTA, Washington, D. C., March 1978.

“University of Oklahoma, Energy From the
414 ● An Assessment of Oil Shale Technologies

West: Policy Analysis Report, prepared for the Environmental Protection Agency, report No, EPA600-7-79-083, Washington, D. C., March 1979.

14U.S. Bureau of Reclamation, Critical Water

Problems Facing the Eleven Western States—

Westwide Study: Volume I, Main Report, NTIS No.

PB-263 981, Denver, Colo., April 1975.

15Colorado Department of Natural Resources,

The Availability of Water for Oil Shale and Coal

Gasification Development in the Upper Colorado

River Basin—Summary Report (Draft), Denver,

Colo., November 1979.

16Supra No. 5.

17Supra No. 7,

18Supra No. 9.

‘YE. F. Bates and T. L. Thoem (eds), Pollution

Control Guidance for Oil Shale Development, Revised Draft Report, Environmental Protection

Agency, Cincinnati, Ohio, July 1979.

20K. W. Crawford, et al., A Preliminary Assessment of Environmental Impacts From Oil Shale Development, report No. EPA-600/7-77-069, Environmental Protection Agency, Cincinnati, Ohio, July

1977.

21W, J. Ramsey, I. Y. Borg, and R, L. Thornton,

Institutional Constraints and the Potential for Oil

Sha]e Development, report No. UCRL-52468, Lawrence Livermore Laboratory, University of California, Livermore, Calif., July 1978.

“J. B. Weeks, et al., Simulated E~~ects of OilShale Development on the Hydrology of Piceance

Basin, Colorado, professional paper 908, U.S. Geological Survey, Washington, D. C,, 1974, p. 1.

“Colorado Department of Natural Resources,

Upper Colorado River Region Section 13(a) Assessment: A Report to the U.S. Water Resources Council (Draft), January 1979, p. 3-26.

“’’Statement of Roland Fischer, SecretaryEngineer, Colorado River Water Conservation

District, Glenwood Springs, Colorado, ” Hearings

on Water Availability for Energy Development in

the West, Subcommittee on Energy Production

and Supply of the Senate Committee on Energy

and Natural Resources, 95th Cong., 2d sess.,

March 1978, committee print 95-134, p, 146.

%upra No, 23, at p. 8-17.

“)Ibid.

“Ibid.

‘

a

Ibid., p, 8-14,

“Cameron and Jones, Inc.,

Quarterly Report, vol. 5, No. 1,

1-28.

30Supra No. 13, at p. 156.

“Supra No. 23, at p. 9-63.

%upra No. 11.

Synthetic Fuels

March 1968, pp.

“Supra No, 23, at p. 9-69.

“R. F. Probstein, H. Gold, and R. E, Hicks,

Water Requirements, Pollution Effects, and Costs

of Water Supply and Treatment for the Oil Shale

Industry, prepared for OTA by Water Purification Associates, October 1979, p. 43.

“H. Gold, D. J. Goldstein, and D. Yung, “The Effect of Water Treatment on the Comparative

Costs of Evaporative and Dry Cooled Steam-Electric Generating Plants, ” Proceedings of the

WWEMA 1977 Industrial Pollution Conference.

‘“F, B. Suefert, et al., Conceptual Designs for

Water Treatment in Demonstration Plants, Department of Energy, Washington, D, C., 1979.

%upra No, 34, at p. 36.

‘8Geraghty and Miller, Inc., Issues Relative to

the Development and Commercialization of a Coal

Derived Synthetic Liquids Industry, Volume 111-3:

Availability of Water for the Development o_f a

Coal Liquefaction Industry, report No. FE1752-18, submitted to the Hudson Institute, Inc.,

Croton-on-Hudson, New York, May 1977.

%upra No. 13, at p. 100.

‘oF. Sparks, “Water,”’ Rocky Mountain News,

editorial, Aug. 2, 1979.

“lSupra No. 24, at p. 153.

‘

zColorado Department of Natural Resources,

Upper Colorado River Region Section 13[a) Assessment: A Report to the U.S. Water Resources Council (Summary Report), August 1979, p. 1 xi.

‘iC. W. Stockton and G. C. Jacoby, “Long-Term

Surface-Water Supply and Streamflow Trends in

the Upper Colorado River Basin Based on TreeRing Analyses, ” Lake Powell Research Project

Bulletin No. 18, March 1976.

“National Academy of Sciences, Mining and

Processing of Oil Shale and Tar Sands, Washington, D. C,, 1979, p. 104,

‘

5 Supra No. 42, at table 10-7.

“U.S. Bureau of Reclamation, Impacts on the

Lower Colorado River Region Resulting From

Alternative Levels of Emerging Energy Development in the Upper Colorado River Region (Draft),

September lg7g, p. 17.

‘

7 Supra No, 46, at p. 24.

“Economic Impact of the Oil Shale Industry in

Western Colorado, Subcommittee on Public Lands

of the Senate Committee on Interior and Insular

Affairs, 93d Cong,, 2d sess., Jan. 19, 1974, p, 110.

‘gSupra No. 44.

50E, E. Hughes, et al., Oil Shale Air po]~ution control, report prepared for EPA by Stanford Research Institute, May 1975.

Sluniversity of Wisconsin-Madison, Oil shale

Development in Northwestern Colorado: Water
and Related Land Impacts, Madison, WJis., July

1975, p. 225.

“Department of the Interior, Final Environmental Statement for the Prototype Oil Shale Leasing

Program, GPO stock No. 2400-00785, Washington,

D. C., 1973, p. 111-76.

‘

) Bureau of Land Management, Draft Environmental Impact Statement—Proposed Development of Oil Shale Resources by the Colony Development Operation in Colorado, Department of

the Interior, Dec. 12, 1975, p. IV-91.

%upra No. 46, at p. 21.

‘%upra No, 48.

%upra No, 51, at p, 20.

“Supra No, 15, at p. xiii.

“3Supra No, 42, at p. 1 xxxviii.

%upra No. 42, at p. xc,

‘

>

’’ Bureau of Land Management, Dra_ft Environmental Statement—Proposed Superior Oil Company Land Exchange and Oil Shale Resource Development, Department of the Interior, 1979, p. 70,

‘)lSupra No. 23, at p. 9-79.

“2Supra No. 13, at p. 148.

‘

){ Hearings on Water Availability for Energy Development in the West, Subcommittee on Energy

Production and Supply of the Senate Committee

on Energy and Natural Resources, 95th Cong,, 2d

sess., March 1978, committee print 95-134, p. 26.

“Ibid., at p. 62,

‘%upra No, 42, at p. 4-4,

‘Wupra No, 22.
CHAPTER 10

Socioeconomic Aspects
Page

Introduction . . . . . . . . . . . 419

The Setting .......... . 420

Historical Background . .................,420

The Oil Shale Country Today . .............421

Early Planning for Oil Shale Development. , , .423

Mechanisms to Manage Growth . ..........426

Local Infrastructures. . ..................426

Private Sector Contributions . .............429

State Programs. . . . . . . . . . . . . . . . . . . . . ... , 430

Evaluation of State and Local Mechanisms. ., 436

Federal Programs............................ ....................438

PossibleConsequencesofOil

ShaleDevelopment. . ..................443

GeneralEffectsofRapidPopulationGrowth........... 443

AnticipatedGrowthintheColorado Oil

ShaleRegion ......... . . . ...................................447

Needs Arising FromAnticipatedGrowth ....449

Needs From Oil ShaleDevelopment. . .......452

PotentialEffectsofAccelerated Development 460

Issues andPolicyApproaches . ............462

SummaryofIssues . .....................46 2

PolicyApproaches . ....................,464

Chapter l0References. . .................470

List of Tables

TableNo. Page

87. ComparisonofBasicto Local Service

EmploymentMultipliers. . . . . . . . . . . . . 424

88. BaselineData-Selected Social

andEconomicStudies . . . . . . . . . . . . . . 425

89. ImpactData—Selected Social and

EconomicStudies . . . . . . . . . . . . . . . . . . 427

90, RevenuesoftheColoradoOilShale

TrustFund, FiscalYears 1975-79 . . . . . 432

91. ExpendituresoftheColorado OilShale

TrustFund,FiscalYears 1975-80 . . . . . 432

92. AppropriationsFromthe OilShale

FundsbyObject,FiscalYears 1975-80. 433

93. Projects Funded by the Colorado Oil

ShaleTrustFund, 1975-80. . . . . . . . . . . 434

94. Wyoming Programs to Mitigate Social

and Economic Impacts. . . . . . . . . . . . . . 437

95*

96.

97.

98.

99.

100.

101.

102.

103.

1040

AllocationofOilShaleTrust Funds,

Fiscal Years 1975-80 . . . . . . . . . . . . . . .

SelectedFederalProgramsUsed by

WesternStatesforAssistance With

SocialandEconomicEffectsofEnergy

Development. . . . . . . . . . . . . . . . . . . . . .

PopulationGrowthofColorado Oil

ShaleCounties, 1970-77. . . . . . . . . . . . .

PopulationofColoradoCommunities

AptToBeAffectedbyOilShale

Development 1977. . . . . . . . . . . . . . . . .

SelectedDemographicIndices ofOil

ShaleCountiesofColorado,July1975..

PopulationProjectionsbyDevelopment

ScenariofortheOilShaleCounties of

Colorado . . . . . . . . . . . . . . . . . . . . . . . . .

ProjectedPopulationGrowth of

Selected Oil ShaleCommunities,

1979-85. . . . . . . . . . . . . . . . . . . . . . . . . .

PriorityNeedsIdentifiedby OilShale

Counties andCommunities, 1980-85 . . .

ActualandProjectedPopulation and

EstimatedCapacityofOilShale

CommunitiesinColorado. . . . . . . . . . . .

SelectedPolicyOptions, 1978Reportto

Page

438

439

447

448

448

449

4 5 1

4 6 0

460

thePresident ........ . . . . ......... 466

List of Figures

Figure No. Page

69. CountiesoftheOilShale Region .,.... 422

70.Communities intheColorado OilShale

Region. . . . . . . . . . . . . . . . . ......... 423

71. Energy-RelatedEmployment, Tax

Revenues, andNeedforPublic Services

in an AreaAffectedbya Large-Scale

EnergyDevelopment . . . . . . . . . . . . . . . 444

72. PopulationProjections forColoradoOil

Shale Counties byDevelopment

Scenario, 1980-2000 . . . . . . . . . . . . . . . 450

73. PopulationProjectionsfor SelectedOil

ShaleCommunitiesinColoradoby

DevelopmentScenario, 1980-2000 . . . . 451

74. ProposedRoadFromRangely to

TractC-a. . ., ., . . . . . . . . . . . . . . . . . . . 456
CHAPTER 10

Socioeconomic Aspects

Introduction

An oil shale industry will bring new people

into the oil shale region. As a result, the social

fabric will be changed in ways both beneficial and detrimental, Growth problems arising from the simultaneous development of oil

shale and other energy resources are likely to

be more difficult to solve than those from

shale development alone.

The 3,200-mi2 area where near-term development will take place is rural and sparsely

populated. The three counties in Colorado

have only one community with over 5,000 residents. Even without expansion of the oil

shale industry populations are projected to

increase significantly. If a major oil shale industry is created within the next two decades

there could be average growth rates of up to

40 percent per year in the early stages of development. Such a rapid population influx

would have inevitable social and economic

consequences. Among the benefits would be

increased employment and expanded community services. Direct employment in the shale

industry and the stimulation of support industries and services would increase wages. The

larger tax base would permit the counties

and municipalities to extend and upgrade

their facilities and services. As long as the

public and private sectors could keep pace

with the growth, most residents probably

would welcome it, Among the negative consequences could be a strain on public services

and facilities, an increase in crime and other

manifestations of social stress, certain private-sector dislocations such as business failures, and in the eyes of some, a deterioration

in their quality of life. If these negative outcomes overwhelm the capacity to adjust, a

boomtown situation would result, similar to

what has happened in other western and

plains communities during the rapid development of energy resources,

Time, money, and technical help ar e

needed to ameliorate the detrimental aspects

of sudden growth. Communities need time to

catch up, particularly if extensive construction of private and public facilities—such as

housing and water and sewer systems—is involved. Both Federal and State governments

and oil shale developers are providing impact

mitigation funds and technical support, To

date in Colorado, upwards of $50 million of

public and private funds have been invested

in preparations for shale development

growth. Programs to administer these resources have been successful, but they have

yet to be tested under conditions of sustained

rapid growth. Assuming that present plans

can be realized in a timely fashion, a total of

about 35,000 people could be accommodated

in existing communities in the 1985-90 period.

Any development that brought more than this

number into the area would cause widespread problems unless the growth were

carefully timed to the region’s ability to accept the new migrants, or plans for additional

new communities were quickly implemented.

The maximum growth rate that can be sustained by these communities before boomtown symptoms emerge, and the nature of the

appropriate Federal role with regard to social and economic impacts are major issues.

The Federal Government now is involved with

impact identification, evaluation, and mitigation, but additional activities are controversial, Possible congressional policy options

would be to continue present financial support to mitigation programs, to increase efforts to manage growth through regulation,

and to expand Federal involvement in mitigation programs, including passage of new legislation directed to energy development in

general or to oil shale impacts in particular.

419
—

420 ● An Assessment of Oil Shale Technologies

The Setting

Historical Background

Oil shale country covers about 17,000 mi2

in the tristate area of Colorado, Utah, and

Wyoming. (See ch. 4 for a description of the

geography of the region.) Archeological evidence reveals that people probably have lived

there for at least 10,000 years. ’ The ancestors of today’s Ute Indians arrived at an as

yet undetermined time. The Utes were a nomadic people who lived in a few permanent

settlements and had many scattered hunting

camps. The earliest direct contact between

these indigenous people and Europeans was

most probably with Spanish explorers, and

British and French fur trappers and traders.

Trade between the Indians and the Europeans existed from the 1600’s onward.

In the late 1700’s and early 1800’s, contact

with Western explorers, traders, hunters,

and trappers increased. In 1776, the Escalante-Dominguez expedition passed through

the region in search of an overland route to

California. 2 In 1868, John Wesley Powell led a

party across Berthoud Pass, into Middle

Park, and eventually to the White River valley. A small group wintered at a site near

Meeker, Colo., which is now called Powell’s

Park. ) The number of people entering the

area rapidly increased during the mining

boom of the mid-1800’s. Settlement was made

easier when transportation was improved.

The Denver and Rio Grande Western Railroad obtained the route through the Colorado

River valley to Salt Lake City. The Colorado

Midland and the Denver and Salt Lake City

railroads explored the White and Yampa

River valleys as alternative routes, although

neither was built,

The United States obtained title to the land

as part of the Mexican Cession of 1848. From

the time of the Cession until the 1880’s the

United States engaged in a number of treaty

negotiations and councils with the Indians.4

The treaties ceded the mineral lands to the

United States and established reservations

for the different bands of Utes. The final

treaty was ratified by Congress in 1880.

Under its terms, the White River Utes were

given land in Utah in the southern part of the

Uintah Indian Reservation to which they were

removed in September of 1881. Congress declared the former Ute lands as public domain

on June 28, 1882.

While the ownership questions were being

debated, squatters appropriated some land illegally. In 1879, when miners founded Carbonate in the Flattops area north of Glenwood

Springs, Colo., they displayed their awareness of this by naming their first building Fort

Defiance. Coal camps were established west

of Glenwood Springs along what came to be

known as Coal Ridge Hogback. While silver

and gold lured the miners, the rich grasslands

attracted cattle and sheep raisers. Large

beef herds roamed free; one in 1888 was

numbered at 23,000. 5 The great runs lasted

until the turn of the century, when they

became uneconomic owing to severe winters

combined with overgrazing.

Ranching, mining, and recreation became

the economic cornerstones of the region. Although no great precious metal strikes were

made, coal mining formed a stable industry

for many decades. Coal was produced for the

railroads and for the steel mills of Pueblo,

Colo. (See ch. 4 for the history of oil shale and

related mineral exploration. ) Farms and

ranches were established as homesteading

flourished. Hay production in the valleys

became profitable, especially with the advent

of irrigation. The visits of Theodore Roosevelt

to the Flattops area in the early 1900’s, with

their attendant publicity, gave impetus to

tourism.’ Communities grew, with Rifle,

Meeker, and Rangely, Colo., as centers of

trade. The town of Meeker was incorporated

in 1885. A trading post was built at the location of Rangely in the early 1880’s. Oil was

discovered nearby in the early 1900’s and

production began in the early 1920’s. Smaller

communities sprang up along the valleys.

West of Rifle, the town of De Beque was incorporated in 1890. Grand Valley, founded in
Ch. 10–Socioeconomic Aspects Ž 421

1882, soon became a farming center. To the

east of Rifle, New Castle was the hub of the

coal communities. Many of the residents today are descendants of the early settlers, Oil

shale country, therefore, is an area with

stable communities populated by many longestablished families.

The Oil Shale Country Today

Agriculture, mining, and recreation have

continued as the main economic activities. z

Livestock grazing is the leading agricultural

use, followed by dry land farming, and irrigated cropland production. Hay and winter

wheat are major crops. The best irrigated

land is in Mesa County, Colo., outside the immediate oil shale area, where orchards have

long been established. Mineral resource production, mostly oil and gas, and recently coal,

constitutes the major mining activity. Tourism, fishing, and hunting have long been the

mainstays of the recreational sector, and

with the expansion of winter sports areas in

the mountains, year-round recreation has

become important. In recent decades, trade,

manufacturing, and construction industries

have grown, along with public and private

services. Economic indices, such as retail

sales and per capita and family income, have

reflected a steady economic growth. a

The oil shale region encompasses about

eight counties. (See figure 69. ) In Colorado,

these are Rio Blanco, Garfield, and Mesa;

some social and economic effects from expanded oil shale development may also be felt

in Moffat County, north of the Piceance basin.

The counties in Utah that will be affected are

Uintah, Daggett, Grand, and Duchesne. The

tricounty area of Colorado covers 9,563 mi2

,

has a limited transportation system, and includes about a dozen communities that could

be affected by oil shale industry expansion,

(See figure 70.)

Stretching along the southern edge of oil

shale territory, Mesa County is the transportation and service center for the western

slope of Colorado. Grand Junction, the largest

city of the region, is the site for the offices of

several energy companies. Interstate 70 (segments of which are not yet completed) extends eastward up the valley of the Colorado

River and westward into Utah; it is 260 highway miles to Denver and 285 to Salt Lake

City. The only airport on the western slope

able to accommodate commercial jets is in

Grand Junction. The Denver and Rio Grande

Western Railroad also has extensive facilities there.

Garfield County lies adjacent to Mesa

County on the north. It encompasses the Roan

Cliffs along the southern border of the Roan

Plateau, and is the site of most of the private

oil shale holdings. The Colorado River flows

through the eastern part of the county, and

transportation is readily available along this

corridor. Glenwood Springs, the county seat,

is located in the eastern portion. Rifle, Grand

Valley, Silt, and New Castle are communities

affected by the present modest scale of oil

shale development. Rifle is the home of many

oil shale workers from tracts C-a and C-b. A

vanadium plant is located nearby, and coal

development activities have recently increased along the valley. The Naval Oil Shale

Reserve at Anvil Points lies between Rifle and

Grand Valley. If present trends continue, the

Rifle vicinity will experience the most growth.

Rio Blanco is the county most likely to experience the major effects of expanded oil

shale development. Lying between Garfield

and Moffat Counties, it is where the richest

oil shale deposits in the United States are

located. Most of these are on Federal lands in

the Piceance basin. Rio Blanco is the least

populated of the three, and has the most limited surface transportation. The White River

flows along the northern part; the two major

communities, Meeker (the county seat) and

Rangely, lie within the river valley. Rangely is

a center for oil and gas development activities. The primary north-south highway goes

from Rifle through Meeker and Craig and

then on to Wyoming. The main east-west road

goes from Meeker to Rangely, before turning

north to Dinosaur, where it passes into Utah.

A State highway goes south from Rangely

through Garfield County and eventually to
— —

422 . An Assessment of 0il Shale Technologies

Figure 69.—Counties of the Oil Shale Region

—— —

A CROO K

I

w .

L1

.-

“1Q**

e0°

. I

●

w

x

o

I.

1: -./ I 1-. . *

--l i

SOURCE The Natlona/ At/as, Department of the Interior

Grand Junction. A county road extends along

the Piceance Creek valley and another goes

eastward from Meeker up the White River

valley to recreation areas. These are the only

improved roads to serve the 3,263 mi2 of Rio

Blanco County.

Moffat County, which occupies the extreme northwest corner of Colorado, abuts on

Wyoming to the north and Utah to the west.

Its county seat, Craig, is in the east-central

portion. The population of Moffat County has

approximately doubled in the past decade

with most of the growth centered in Craig.

Coal development and the construction of a

760-MW coal-fired electric generation plant

account for most of the expansion, which is

expected to continue with a possible doubling

in the size of the powerplant. Because Moffat

County lies to the north of the principal oil

shale areas, it will probably only experience

indirect effects from shale development. The

town of Dinosaur, however, which is located

18 miles northwest of Rangely in the extreme
Ch 1O–Socioeconom/c Aspects ● 423

Figure 70.—Communities in the Colorado Oil Shale Region

VERNAL

32 mi.

I

r

——_———— ———— 4

— J

— — ‘“F su — — — — — — — — — — — —

— 

—.” —

JUNCTION

SOURCE 0il Shale Tracf C-b SOCIO Ecomnic Ajssessment 76 VOI II

southwestern corner of the county, could be

directly affected. It has already grown from

oil and gas exploration, and oil shale activities in Utah as well as the Piceance basin

could further accelerate its growth.

In sum, the oil shale region of Colorado,

Utah, and Wyoming is a large area with a

small population. Most of the residents are

found in widely separated communities that

are linked by a few highways. Before the recent increase in energy-related industrial activity, the main economic base was ranching

and farming, supplemented by tourism, recreation, and mining. A large number of new residents have migrated to Moffat County, to the

north of the oil shale region. The fastest

growth from expansion of the shale industry

will most likely take place in the least populated county, Rio Blanco, which contains the

richest oil shale deposits. Garfield County is

apt to experience major impacts from its

growth.

Early Planning for Oil Shale Development

Concern about the social and economic effects on Colorado communities of large-scale

oil shale development was expressed in the

late 1960’s.9 As a result, planning activities

began in the early 1970’s. The environmental

impact statement (EIS) filed in conjunction

with the Prototype Leasing Program examined some social and economic elements.
424 ● An Assessment of Oil Shale Technologies

However, its lack of detail prompted industry

to take the initiative to undertake additional

analysis. In 1972, an Oil Shale Regional Planning Commission was formed, which took an

inventory of the area and of shale technologies. Contracts with consulting firms produced several planning documents. ’” The responsibilities of the Commission were assumed later by the Colorado West Area Council of Governments (CWACOG). An awareness of the need to prepare for growth

prompted these early planning efforts, but as

work proceeded, an atmosphere of uncertainty arose. When the lessees requested suspensions, expansion of the oil shale industry became questionable in the minds of many who

were charged with the responsibility of preparing for its consequences. ”

Local programs to minimize possible adverse affects were begun after the leasing of

tracts C-a and C-b. The C-a lessees, Rio Blanco Oil Shale Co. (Gulf Oil and the Standard

Oil Co.—Indiana), prepared an impact analysis for their operation. ’2 They hired a consultant, the Foundation for Urban and Neighborhood Development (FUND), to survey community attitudes toward energy development

in Rangely, Meeker, and Rifle. The lessees

also engaged a planning firm, the Gulf Oil

Real Estate Development Co. (GOREDCO),

that—with the participation and direction of

the community—prepared a comprehensive

development plan for Rangely. The master

plan was completed in 1976 and subsequently

adopted by the town, certified to the county,

and incorporated in the county plan. Through

FUND an attorney was engaged to update

and codify Rangely’s municipal ordinances.

The lessees also contributed to the improvement of the county road leading to tract C-a,

and paid for the design and preparation of

cost estimates for a 22-mile extension from

the tract more directly to Rangely.

In 1976, the lessees of the C-b tract (at that

time consisting of Ashland, Atlantic Richfield,

Shell, and Tosco) published a baseline description and an impact analysis study. ’3 Like

the tract C-a lessees, they hired a consulting

firm, Quality Development Associates (QDA),

to prepare socioeconomic monitoring reports

and to work with local citizens on strategies

for managing growth. The lessees were also

members of a private development, the Colony project. Several socioeconomic reports

were prepared as part of this joint effort, l4

and, under the direction of Atlantic Richfield,

early plans were prepared for Battlement

Mesa, a proposed new town to accommodate

workers from the Colony project. ’5

The tracts C-a and C-b lessees each contributed $40,000 to help establish the Rio

Blanco County Planning Department. The

money was used to prepare a comprehensive

plan that was adopted and certified to the

communities in the latter part of 1976. Both

groups of lessees funded development of a

growth-monitoring model by CWACOG, and

the original tract C-b partners and one of the

C-a partners participated in the preparation

of a tax study. Planning was also underway in

Utah between 1970 and 1975. For example, in

1975 a socioeconomic analysis was published

by the White River Shale project that dealt

with the effects of the proposed development

of a 100,000-bbl/d industry in Utah. 16

The value of the early studies varied because each had a different emphasis, coverage, and set of basic assumptions. Comparing

the multipliers used to derive projected

growth illustrates these differences. To obtain an estimate of new employment fostered

by a project (local service employment), the

expected work force for the project (basic

employment) is multiplied by some factor

(multiplier). Table 87 compares the multipliTable 87.–Comparison of Basic to Local Service

Employment Mutipliers

—

Multipliers used

Construction Operating

IIlustrative studya

phase phase

1. Prototype EIS . 63 77

2. C-a (Rio Blanco) Social & Economic

Statement . 5 5

3 C-b Soclo-Economic Assessment 5 to 1 0 1 5

4. Colony EIS. ., .29 97

5. Uinta Basin Study 3 to 10 10 to 1.5

d~ee (e! 1 T for iUII htle of the sludles

SOURCE Of ftce of Technology Assessment
Ch. 1O– Socioeconomic Aspects Ž 425

ers used in five of the early studies,17 Thes e The differences occurred for several reavary so much that a single increment of em- sons. In the EISs, socioeconomic factors reployment can result in a twofold to threefold ceived little emphasis because at that time

difference in the projected populations. (The they were not considered—as is now the case

five studies are compared in greater detail in —essential to environmental impact analysis.

tables 88 and 89. ) In general, the EISS assumed that existing

Table 88.–Baseline Data–Selected Social and Economic Studies (each dot indicates the inclusion in the study of this category of data)

—. —

Title of studyb

C-a social C-b

Prototype EIS and economic socioeconomic Colony EIS Uinta Basin Data categories —

a

Existing economic/demographic data

Population and employment

County population

Number of households by county

Number of households by community

Labor participation by county

Education

Enrollment by county

Enrollment by school district

Enrollment by city

Student/teacher ratio

Median school years attained

Dropout/turnover rates

Employment by industry

Total employed–sector by county

Total employed–sector by city

Total employed–sector by region

Employment–other energy Industry

Family/lndwldual Income Indicators

Median family Income by county

Per capita Income by county

Unemployment rate by county

Poverty status by county

Rate of population growth

By county and community

Projected without 011 shale

● ● ● ● ●

● ● ● ●

●

● ● ● ● ●

●

●

●

●

● ●

●

●

● ●

●

●

●

● ●

●

● ●

●

●

● ●

● ●

Existing public services/facilities

Education

Age of school buildings by district

Certified staff

Excess pupil capacity

Public safety

Fire/pollee protection by area

Manpower/number of vehicles

Water

Estimated depletion (1970) by region .,

Status of projects by State

Source, storage capacity, number of taps per population served

by community

Status of water rights

Wastewater and solid waste disposal

Treatment facilities by community type/population served/design capacity

Transportation

Existing roads/airports by county

Status of current projects

Average weekday traffic counts

Health

Facilities/manpower by county

Mental health facilties

Recreation and land use

Resource Inventory

9

●

●

●

●

●

●

●

●

● ●

●

●

● ●

●

●

●

●

●
426 ● An Assessment of Oil Shale Technologies

Table 88.–Baseline Data–Selected Social and Economic Studies –continued

Title of studyb

C-a social C-b

Data categoriesa

Prototype EIS and economic socioeconomic Colony EIS Uinta Basin —

Recreational facilities by typ e

Land by ownership by count y

Agricultural land by county

Government structure/fiscal information

County/municipal government finance

Revenues and expenditures by count y

Municipal revenues and expenditure s

Property tax valuation, average mill levy, and total levy by county

Distribtion of levy revenues by count y

Sales tax Information .,

Retail trade informatio n

School district finances

Total expenditures by county.

Total and per capita expenditures by districts

Comparison of per pupil expenditures and mill levies by districts .,

MiII levy by fund. assessed value revenue by source, by district

Bonding principal and remaining capacity

Housing

Inventory and costs

Estimated housing by county

Status of available units by type

Value of owner-occupied units.

Value of other unit s

Projected needs by tenure by county

Characteristics by type by cit y

Public opinion

Local opinion regarding

Socioeconomic environment and quality of life .,

Attitudes about changes In quality of life and society.

Attitudes about perceived advantages/disadvantages

of 011 shale developmen t

●

● ●

● ●

● ●

●

●

●

●

●

●

● ●

● ● ●

●

●

●

●

●

●

●

dBala ~ategorles are for Il[ustra[lon NO a!tempt has Deen made 10 Include all of the !nformallon In these studies

Dsee ~ef I 7 for Ilsf(ng of full Ilfle

SOURCE Olflce of Technology Assessment

mechanisms could deal with most consequences of growth. When it became apparent

they could not, subsequent studies went into

greater detail about the effects of the expected growth and possible remedial actions.

Not all of the studies, however, included the

same types of information. For example, community facilities and local government data

were not made a part of the C-a analyses because they were in the Rangely master plan.

Little attention was paid in any of the studies

to other resource development projects anticipated or underway in the region. As a

result, all of them are deficient in analyzing

the cumulative effects of industrial expansion.

Mechanisms to Manage Growth

Local Infrastructures Rangely, Rifle, and Grand Junction have fulltime city managers, and Grand Junction and

In Colorado, Garfield, Rio Blanco, and Rifle have city planners. Rio Blanco County

Mesa Counties all have planning councils, has adopted an ordinance applying to land

professional planning staffs, and approved use that, in certain circumstances, requires

countywide comprehensive plans. Meeker, filing an impact analysis statement specifying
Ch. 10–Socioeconomic Aspects Ž 427

Table 89.–impact Data–Selected Social and Economic Studies (each dot indicates the inclusion in the study of this category of data)

Title of studyb

C-a social C-b

Impact categoriesaPrototype EIS and economic socioeconomic Colony EIS Uinta Basin

Population/employment projections

Total basic population projections

Project-related employment projectionc

,.

Estimated family size for construction and service populations

Timelag included for local service employment forecasts ........,.

Estimation of community choice for residence and allocation of population

Community facilities/services projections

Education

Site and plant costs, personnel needs, salary requirements

Projected numbers of pupils and room requirements.

Projected increase in demand for teachers and classrooms

Public safety

Fire and pollee needs and costs

Cumlative impact on faci!ities and personnel

Water

Expected needs by technology

Needed Improvements and estimated costs–one municipal system

Projected site, plant, personnel, and salary requirements

Capacity and expansion by towns, depletion by sector by region

Solld waste disposal and wastewater

Transportation

Healt h

Mental health

Recreation

Land loss by State by technology

Projected open space and recreational needs and costs

New sites and facilities needed (project development area)

Local government fiscal need projections

School district financing needs

County and municipal government finances

Estimated Federal, State and local revenues by tax source by State

Projected total revenues and expenditures, by tax source/per capita

Facility and personnel costs, valuation and taxes levied

Impact by development pattern or project phase

Housing

Projected housing requirements

Types needed by development phase

Demand by community........

Land use requirements by units per acre, total units, and type

Public construction expenditures and tax receipts by State

Recent construction by communities

● ●

● ●

● ●

●

● ● ●

● ● ●

● ● ●

● ● ●

● ● ●

●

●

● ●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

●

● ●

● ●

●

●

●

al mPacl Cdleqorles are ‘or III usfra!lon OPI y No atlem Df has Deen made 10 Include al’ of lhe Intormatlon avd(lablc In these st( IdIP$

bsee ,e; I j’ for a Ihstlng Of fdll tl[ c

c

See [ext for a Otscusslon of Ihe elf ferences m the projecl(ons as d Iuncllon of the multlp.lers used In each study

dsee ~exl for an explanation of Irle lac~ Of IIfoma!oo for Ine C a socia dnd econom~c study column

SOURCE Off Ice of Techno ogy Assessment

actions that will be taken to alleviate any

adverse effects of changes in land use.18

In the early planning stages, special groups

were created in Rio Blanco and Mesa Counties and the Rifle area. The most active,

called the Impact Mitigation Task Force, is in

Rio Blanco County. It was initiated following

a series of informal meetings between industry representatives, their consultants, and

county officials, and consists of about 30

members organized into a core group and two

advisory panels. The core group, which meets

monthly, is composed of the county commissioners; the city manager and mayor from the

two municipalities, Rangely and Meeker; and

representatives from industry, the Federal

and State governments, and CWACOG. It has
428 . An Assessment o/ 011 Shale Technologies

Photo credit OTA staff

Monthly meeting of the Rio Blanco County Impact Mitigation Task Force

been officially designated to serve in an advisory capacity to the county commissioners.

One advisory panel represents Meeker and

the eastern part of the county, the other

Rangely and the western portion. Many different interests are reflected, including agencies such as the sanitation district and the

public schools, and less formally organized

groups such as youth. The advisory panels,

which also meet once a month, discuss different growth-related topics, and forward their

concerns to the core group. They have prepared needs assessments on a variety of general subjects and have reviewed specific

issues such as housing for teachers.

The Rifle area organization was formed in

mid-1977 with a core group and series of

working panels. When first established, it

was called the Development Impact Committee, and consisted mainly of Rifle residents. A

county commissioner from the area was a

member but countywide communication was

not extensive. Most of the development and

planning management activities were carried

out through the Rifle planning and administrator’s offices. In the fall of 1979, the organization was enlarged to involve other communities along the Colorado River valley. The

core group was broadened to include all of

the county commissioners and representatives from each of six towns. To advise the

core group, a West Garfield Impact Committee was created composed of 19 voting members chosen to represent a wide range of interests. The Impact Committee will undertake

planning activities and recommend to the

core group which projects they support for

submission to the State for funding assistance. Prior to the establishment of this process, requests were made through the cities

directly to the county commissioners.

In December 1977, Mesa County organized

an Impact Assistance Team. Fifteen members, representing local, State, and industry

interests, review funding requests made to

the county commissioners. Applicants must

provide information to the team justifying

their requests. Responsibility for setting

priorities rests with the commissioners.
Ch. 1O–Socioeconomic Aspects ● 429

The Functions of the Local Planning Processes

The work of the special groups has centered around three areas: physical planning

and development, information generation and

transfer, and screening and placing priorities

on requests for funding. As an illustration of

the first function, the Rio Blanco advisory and

core groups, using population forecasts provided by CWACOG, have reviewed the ability

of local public facilities, such as sewer and

water systems, to handle larger loads, and

have helped plan expansions where appropriate. Needs for housing, schools, recreational

facilities, and downtown redevelopment have

also been considered. Each planning group

has struggled with the implications of comprehensive land planning for its region.

Because energy development often involves

uncertainties about factors such as the timing

of construction and the size of work forces,

obtaining accurate information is important

to officials and residents, The best estimates

available are required and, in this regard,

most groups receive frequent updates from

industry representatives about the status of

their projects. Sharing information also involves communication between local officials

and citizens. The advisory groups provide a

public forum for the presentation, analysis,

and discussion of issues, which allows individuals to help determine future growth patterns. The core groups, especially when

screening requests for impact mitigation

funds, help establish a consensus among local

interests on priorities and policies.

An important function of each group is recommending to their respective county commissioners which project applications should

be forwarded to the Federal and State governments for consideration for funding. The

Rio Blanco County structure is unique in this

respect, The involvement of the task force

core group and advisory panel members with

local officials, industry representatives, consultants, CWACOG, State legislative and executive staff, and Federal agency personnel

broadly allocates responsibility for decisions.

Having the task force place priorities on applications for financial assistance validates

the process and formalizes the responsibility.

This consideration of the functions of Colorado’s local planning mechanisms illustrates

several general questions related to socioeconomic effects. Among them are:

Ž Who identifies the consequences of

growth?

● Who judges whether these are positive

or negative?

● Who determines which ones require redress?

Local entities address all three questions in

the model presently operating in Colorado. In

some instances, these are established governmental units, such as planning offices; in

others, unique panels with broad community

representation. The latter arrangement has

several advantages. It allows individuals

close to the communities to judge the balance

between positive and negative impacts, and

provides an opportunity for citizens with different interests to propose solutions to local

problems, Many share the responsibility of

deciding which difficulties are severe enough

to require assistance beyond that available

from local resources. The assumption underlying the model is that those affected should

have the prerogative of deciding what a negative impact is and how it might be ameliorated.

Private Sector Contributions

Throughout the West, energy development

industries are contributing significantly to

growth management. 19 As previously noted,

several oil shale developers have voluntarily

contributed to projects in communities affected by their activities. The Rio Blanco Oil

Shale Co., for example, spent over $700,000

in direct grants and purchases of services to

assist the Rangely area and over $135,OOO in

support of Rio Blanco County. The Colony Development Operation invested about $3 million to acquire land and plan for the new

town of Battlement Mesa. Industry has also

adopted programs to deal with particular
430 . An Assessment of 0il Shale Technologies

problems. To reduce traffic and contribute to sistance to real estate developers for conhighway safety, the tract C-b lessees operate struction of apartment units in Rifle and

buses for their workers from Rifle to the Meeker, and for a mobile home park in Rifle.20

tract. They have also provided financial asPhoto credit OTA staff

Apartment units in Rifle, Colo., developed with industry assistance

State Programs

Colorado

Colorado’s programs largely involve financial and technical assistance. Financial support is directed to municipal, county, and private agencies with money obtained from two

main sources, lease revenues collected by the

Federal Government and severance taxes collected by the State. Technical assistance is in

the form of information gathering and dissemination, advisory services, program coordination, and similar support activities.

AGENCIES INVOLVED IN MITIGATION PROGRAMS

Two State governmental groups are involved in Colorado’s programs for impact

mitigation: the Division of Energy and Mineral Impact in the Department of Local Affairs

(DLA) and the Joint Budget Committee (JBC) of

the General Assembly.

JBC is a legislative committee composed of

members from both houses of the Colorado

General Assembly. It is responsible for drafting the State budget and forwarding it to the

Assembly for final action. In 1974, the General Assembly created the State Oil Shale
Ch. 10–Socioeconomic Aspects ● 431

Coordinator’s Office, 21 which subsequently

evolved into the Governor’s Socio-Economic

Impact Office (SEIO). SEIO, the lead agency

for coordination within the State government,

is now the Division of Energy and Mineral Impact in DLA. The Division reviews requests

for Oil Shale Trust Fund assistance (described below), and recommends projects for

funding to JBC. It is also responsible for contract negotiations and for administering appropriations. The Division also handles mitigation programs for communities experiencing boomtown impacts from other types of development. DLA coordinates State and local

mechanisms in several ways:

●

●

●

reliance on local and regional groups to

take an advocacy role in presenting local

needs to State agencies,

review of requests by State-level agencies involved with or that might be affected by mitigation projects, and

administration of appropriations and

contracts through field representatives

in concert with local officials and contractors.

Financial Assistance.–

Federal Revenues. —Under the provisions

of the Mineral Leasing Act of 1920, as

amended,

22 each State receives 50 percent of

the proceeds from the sale or lease by the

Federal Government of public lands within

the State. Colorado has created two distinct

funds to receive these revenues: one for those

returned from oil shale lands and another for

those returned from lands other than oil

shale. The former is called the Oil Shale

Trust Fund and the Oil Shale Interest Earned

Fund; the latter is the Colorado Mineral Leasing Fund.

● Oil Shale Trust Fund and Interest

Earned Fund. Colorado’s Oil Shale Trust

Fun d

23 was created in 1974 to receive

those revenues specifically coming from

lease payments, royalties, and bonuses

on the two Federal oil shale tracts in

western Colorado. To date, the Oil Shale

Trust Fund has received payments corresponding to the first three bonus payments paid to the Federal Government

by the tract lessees. Under the bonus offset provision of the Prototype Leasing

Program, expenditures for certain development work on the lease tracts can be

credited against the final two payments.

Since the lessees have proceeded with

development, it is likely that 100 percent

of the final two bonus payments will be

offset, and that, therefore, neither the

State nor the Federal Government will

receive any additional lease payments in

cash. (See table 90 for a summary of the

Fund’s revenues.)

The State statute creating the fund

specifies that the income shall be disbursed as follows:

. .. for appropriation by the General

Assembly to state agencies, school districts, and political subdivisions of the

state affected by the development and

production of energy resources from oil

shale lands primarily for use by such

entities in planning for and providing

facilities and services necessitated by

such development and production and

secondarily for other state purposes.24

The Oil Shale Trust Fund is not technically a trust since there is no statutory

requirement that the principal be kept

intact. However, JBC has maintained the

principal at approximately $60 million,

Upgrading of facilities in Rangely, Colo., utilizing

Oil Shale Trust Fund monies
432 ● An Assessment of Oil Shale Technologies

Table 90.–Revenues of the Colorado Oil Shale

Trust Fund, Fiscal Years 1975-79

Lease/bonus Interest Total annual

Year i ncomea

earned income

FY197 5

b ... . ... $24,607,02 0 0 $24,607,02 0

FY197 6

b

... ... .. 24,607,020 $2,685,600 27,292,620

FY1977 b

......... 24,607,020 3,811,271 28,418,291

FY1978 b

o 4,219,970 4,219,970

FY197 9

c

... .. ::. o 5,999,918 5,999,918

asee[ext for discussion ofoffsefllng prowstonsapplymglo 197879

bSummaryafld S/afus Repoflo/ (fie Mlflera/ Lease amj Severance Tax Fund, Second Annual Re

port lolhe Colorado Slale Legislature Eleparfmenl otLocal Affam 1979

cStatefreasurer sotflce

SOURCE

●

Office of Technology Assessment

and appropriations have been madeonly

from interest earnings and from the

principal in excess of $60 million. The interest earned by the State is set aside as

the Oil Shale Interest Earned Fund, a

special account established in 1975. 25

Loans as well as grants from the interest

fund are permitted; the authorized purposes for appropriation of the interest

earnings are identical to those of the

principal fund. (See table 91 for a summary of expenditures.)

Colorado Mineral Leasing Fund. Colorado’s share of public land monies collected by the Federal Government for

leasing of minerals other than oil shale is

placed in the Colorado Mineral Leasing

Fund.

26 The fund was created in 1977 to

be used for planning, construction, and

maintenance of public facilities, and the

provision of public services. Priority is to

be given to “those. .. political subdivisions socially or economically impacted

Table 91 .–Expenditures of the Colorado Oil Shale Trust Fund,

Fiscal Years 1975-80

Amount of Amount Outstanding

Year appropriation expended commitments

FY 1975 a $ 451,187 $325,926b

o

FY 197 6

a 

, , , 10,385,300 10,029,381 $ 2,000

FY 1977a

4,239,646 3,283,408 47,332

FY 1978a

6,464.793 4,702,737 993,510

FY 197 9

a

8,929,090 6,306,940 2,622,150

FY1980c

10,446,102 Not available Not available

asumma~Yafld~ldluS ~ePof/ Ofjhe /dmera/ [ease and Severance rar Fund Second Annual Re

porf lo fhe Colorado State Leglsldture Oeparlmenlof Local Affairs 1979

b$ I ~~ P61 of the $.$51 I !37 orlglnal approprlahon was returned 10 the 011 Shale Trust Fund

COe~drfmenl of Locdl Affatrs Dlwon of Energy and Mined Impact

SOURCE Offfice of Technology Assessment

by the development, processing, or energy conversion of minerals” that are

leased from the Federal Government

and/or that are subject to State severance taxation.

27 The State statute provides for an automatic distribution of the

monies to the public schools, to the counties where the leased lands are located

(except that no county can receive more

than $200,000 in any calendar year), to

the Colorado Water Conservation Board

Construction Fund, and to the Local Government Mineral Impact Fund.

State revenues.—In 1977 Colorado levied

a severance tax on the production and export

of metallic minerals, molybdenum ore, oil and

gas, coal, and shale oil.28 Proceeds are allocated to different accounts according to the

mineral being taxed. To date, most of the income has been derived from oil and gas, molybdenum, and coal. Two new funds were established at the time of passage of the severance tax: a State Severance Tax Trust Fund

and a Local Government Severance Tax

Fund. When shale oil revenues are realized,

they will be distributed as follows:

● 40 percent to the State General Fund,

 40 percent to the State Severance Tax

Trust Fund, and

● 20 percent to the Local Government Severance Tax Fund.

Although separate legislation created the

Local Government Mineral Impact Fund and

the Local Government Severance Tax Fund,

for practical purposes they have been combined into an Energy Impact Assistance Fund

that is administered by the Division of Mineral and Energy Impact.

Mechanisms for Disbursement.–

The Colorado General Assembly makes appropriations from the oil shale principal and

interest funds based on the recommendations

of JBC. Requests for financial assistance from

the oil shale funds are initiated at the local

level. Priorities for needs are assigned at the

local level and forwarded to JBC. In addition,

the requests are reviewed by the Division of

Mineral and Energy Impact. JBC receives the
Ch. 1O–Socioeconomic Aspects ● 433

requests in public hearings and subsequently

corresponds with local officials if clarification is needed. After analyzing the requests,

JBC incorporates, as a series of line items in

the appropriations bill, the sums recommended for expenditure from the oil shale

funds. (See tables 92 and 93 for a listing of

the general categories under which these

monies have been expended and the projects

that have been funded.)

In contrast to the legislative process controlling the oil shale monies, disbursements

from the Energy Impact Assistance portion of

the Mineral Leasing Fund are at the discretion of the executive director of DLA. Obligations are made by contracts negotiated and

administered by field representatives from

the Department. DLA uses the same local and

regional review process followed in the oil

shale appropriations procedure for the identification of needs and the ranking of funding

requests. It is assisted by a statewide energy

impact assistance advisory committee that

makes recommendations to the executive director of DLA.

Technical Assistance.–

Information gathering and dissemination,

program coordination, regional planning, and

advisory services are the main types of technical assistance provided to local planners.

For the oil shale region, this assistance comes

from CWACOG and DLA.

Table 92.–Appropriations From the Oil Shale Funds by Object,

Fiscal Years 1975-80

Amount appropriated Percent of total

Purpose FY 1975-80ab appropriation

Road, bridge, and drainage

School s

Water

Sewer

Health and mental health

Municipal facilitie s

Recreation

Coordination and planning

Tota l

$14.298736

9,262,714

9,402,403

2,802,058

440,668

3,013500

370,000

1,190,788

35.1

22.7

2 3 0

6 9

11

7 4

0.9

2 9

$40,780.867 1000

aSumnrary and Sralus Repor( ot the Minera/ lease and Severance Tax Fund Second Annual Re

port 10 Ihe Colorado Stale Leg,slafure Department of Local Affairs 1979

bstale Approprlafton Acf for FY 197980 IS B 5251

SOURCE Office of Technology Assessment

Colorado West Area Council of Governments.—CWACOG is a clearinghouse for the

municipalities and counties of northwestern

Colorado. With respect to energy development, it provides communities with information about industry plans and government

assistance programs, and makes local groups

aware of the responses of neighboring jurisdictions to impact problems. It also assists the

mitigation task forces in preparing their

needs assessments and in assigning priorities

to the final requests submitted to the State;

and it is the central agency through which

grant applications to both State and Federal

agencies must pass.

CWACOG uses a growth-monitoring system to project future employment and total

population figures. Industry work force information and economic and demographic

multipliers are combined for these forecasts.

The computer model can accommodate updated information, and can supply outputs

such as projections based on alternative

assumptions and growth scenarios. The system provides a single source of data for government and industry officials.

Field Representatives for DLA.—Field personnel are located in several areas of Colorado that are experiencing energy-related

growth. They help organize community mitigation teams and coordinate local, county,

and regional requests for funding assistance.

They also negotiate and administer contracts

involving the expenditure of impact funds.

They serve a valuable function by expediting

State funding, advising local officials about

current assistance programs, and monitoring

the progress of authorized work.

Utah

Between 1970 and 1977, the population of

Utah increased by 20 percent. Unlike other

Western States, however, most of this growth

was from a high birth rate, with immigration

accounting for only 4 percent of the increase.

Although there has not been a large migration

to the State as a whole, energy development
434 . An Assessment of 0il Shale Technologies

Table 93.–Projects Funded by the Colorado Oil Shale Trust Fund, 1975-80

FY 1975 FY 1976 FY 1977

Recipient

Mesa County schools (Re-51 )

Moffat County schools (Re-1 )

Garfield County schools (Re-2)

RIO Blanco County planning

Garfield County planning

Mesa County planning

Garfield County schools (Re-1)

Mesa County schools (Re-49JT)

Meeker schools

Colorado West Area Council of Gov’ts

Office of the Governor

Administration

State Impact Report

Amount Recipient Amount

$42,575 Water Construction fund $2700,000

(Colorado Water Board)

12,389 Piceance Creek Road 1,873,091

10,000 RIO Blanco County schools (Re-1) 1,189,000

10,000 Garfield County schools (Re-2) 1,000,000

10,000 Moffat County schools (Re-1) 670,000

8,000 Bonanza Road 497,909

7,260 Rulison Bridge 471,000

4,000 Roan Creek Road 467,595

781 Mesa County schools (Re-51) 400,000

De Beque Bridge 299,658

87,187 Garfield County schools (Re-1) 200.000

92,734 Colorado West Area Council of Gov’ts. 200,000

(technical assistance)

Garfield County schools (Re-16) 121.057

Routt County Road 100,000

Oil Shale Coordinator’s Off Ice 100,000

Town of Hayden, streets 50,000

Mesa County schools (Re-49) 36,000

Rio Blanco County schools (Re-4) 10,000

Recipient Amount

Piceance Creek Road $2,135,000

Roan Creek Road 665,858

Rangely sewer 460,000

Craig Hospital 230,000

Craig water tank 215,000

Mesa County schools (Re-49) 147,000

011 Shale Coordinator’s Off Ice 106,000

Garfield County planning 100,000

Moffat school leases 51,456

Mental health services 34,000

Hayden school site 25,000

Colorado West Area Council of Gov’ts 25,000

Delta County 17,000

De Beque sewer 15,000

New Castle sewer planning 6,666

Silt sewer planning 6,666

FY 1978 FY 1979 FY 1980

Amount

$608,000

532,125

500,000

479.000

450,000

4501000

438,750

435,400

350,000

280,000

275,000

273,757

250,000

135.000

125,000

122,000

114,079

100.000

95,857

75,000

74,000

66,825

62,500

41,000

30,000

25.000

25,000

20,000

15,000

10,000

6,500

Recipient Recipient Amount Recipient Amount

De Beque water

Grand Valley Bridge

Rangely streets

Carbondale sewer

Moffat County–Sunset School

Hayden Elementary School

Rifle sewer

Meeker streets

Mesa County schools (Re-51)

Hayden water

Craig City Hall

Garfield County schools (Re-2)

Moffat County bypass

Roan Creek Road

Craig water

Oak Creek water

Oil Shale Coordinator’s Office

Rangely sewer

Mental health center

Carbondale Municipal Building

Moffat–modular rooms

Rifle lift station

Colorado West Area Council of Gov’ts

(Planning)

Hayden drainage

Meeker Hospital

Craig drainage

Delta County water

Hayden recreation

Walden water

Rifle planning

Silt planning

Rifle water 2,056,000

County Road 24 1,000,000

Rangely streets 900,000

Craig High School 750,000

Colorado Water Conservation Board 600,000

Rifle bypass 500,000

Meeker sanitation 368,000

Meeker pool 350,000

Meeker streets 320,000

Mesa County airport water 293,250

Garfield County airport 260,000

Grand Valley water 250,000

Fruita sewer 200,000

Transportation planning, CWACOG 198,000

New Castle water 196,000

Silt water 151,000

Impact Coordinator’s Office 114,079

Colorado Northwest Community

College 110000

Mesa County sewer 104,450

Regional School Fund 100,000

Rangely Hospital 50,811

Mesa County transportation 25,000

RIo Blanco County Impact Coordinator 17,500

Silt planning 15.000

Rifle school construction

Rifle bypass

Meeker sewage treatment expansion

Silt water Improvements

Meeker streets and drainage

Mesa County sewer system

Improvements

C-a to Rangely Road engineering

De Beque water system

Rifle senior center

Grand Valley sewage treatment plant

Dinosaur water system

$2,750,220

2,000,000

1,440,000

1,400,000

800,000

796,787

300,000

300,000

172,500

141,206

66,153

SOURCE Summary and Status of the Mineral Lease and Severance Tax Fund Second Annual Report 10 the Colorado State Legislature. Colorado Department of Local Affairs 1979
Ch. 1O– Socioeconomic Aspects ● 435

activities have been responsible for rapid

population increases in certain rural counties

and communities. Until the recent boom, the

population in most of these areas had decreased over several decades, As a consequence, the communities have been ill-prepared to respond effectively to current

changes.

The oilfields of eastern Utah attracted people to Duchesne and Uintah Counties, although oil drilling there has peaked and the

growth is now waning, Area residents hope

that the present emphasis on synthetic fuels

will lead to a boom from oil shale and tar

sands development. 29 Increased coal mining

has caused growth in Carbon, Sevier, and

Emery Counties. In 1960, the population of

communities in these counties was under

1,000; several even declined during the

1960’s. Because there are no larger towns in

the area that can provide housing and other

services, they have been forced to absorb all

the migration. A resurgence of uranium mining along with oil exploration has stimulated

growth in San Juan, Grand, and Garfield

Counties. The towns of Blanding, Moab, and

Monticello, which have all gained new residents, are expected to continue growing.

Utah created a Community Impact Account

in 1977 to assist areas affected by energy

development. 30 It is a “revolving account for

loans and grants to state agencies, political

subdivisions of the state, and special service

districts which are or may be socially or economically impacted by mineral resource development . . ."31 Revenues come from a portion of the State’s share of Federal mineral

lease payments, Projects are chosen by a

board comprised of chairpersons of several

State boards, councils, committees, and departments. The board establishes the criteria

for awarding grants and loans, determines

the order in which projects will be funded,

and serves as the sponsoring agency. The

chief criterion for determining which projects

to support is urgency of need. To date, almost

all support has been for water and sewer

projects. Only those communities already impacted have received assistance even though

the legislation creating the account specified

that those expecting large population increases are eligible for help. The Uinta basin,

where the oil shale deposits are located, has

not received any funds from the account even

though it is undergoing oil and gas exploration and development. Because the Community Impact Account is the only funding source

in the State designed to respond to problems

associated with energy development, requests for help have far surpassed the available monies. In mid-l979, with only $4 million

available for distribution, a total of $11 million had been requested.

Adequate water supplies are one of the

paramount needs in the energy-impacted

areas of Utah. Several towns have had to

place moratoriums on additional building

because water systems cannot service increased demands, and during summer

months many communities are forced to ration the available water. To help solve these

problems, the City Water Loan Fund32 w a s

created by the State legislature in 1975. It

provides interest-free loans to cities for the

construction of water supply and water treatment facilities. The fund provides up to 80

percent of the amount needed with the only

qualification that the community be incorporated. Originally the revenue came from

taxes on the sale of alcoholic beverages, but

recently the funding source was changed to

State mineral lease royalties; the amount

varies from around $2 million to $2.5 million

annually. Surprisingly, the fund has pretty

well been able to keep up with the demand for

loans. Every application has received a loan

offer, even though not always the amount requested, A problem that might arise in the

long term could be that a loan taken out during a time of boom would have to be paid by

the remaining, smaller population during a

subsequent time of bust. Also, since the loans

are just for water-related projects, help is

limited to only this one problem area.

Wyoming

Some of the largest growth in the Western

States has been in Wyoming. Between 1970
436 Ž An Assessment of Oil Shale Technologies

and 1978, the population in all but one of

Wyoming’s 23 counties increased. In contrast, in 15 of the 23 it declined in the decade

between 1960 and 1970. Much of the recent

growth has been related to energy development, although some reflects the trend of settling in rural areas for simpler living patterns

or for retirement. From 1970 to 1978, population expanded 30 percent or more in eight

counties. These are distributed in three

distinct geographical areas. Lincoln, Uintah,

Carbon, Sweetwater, and Teton Counties lie

in the west and southwest where there are

coal, uranium, and oil deposits and the only

large oil shale deposits in the State. Most of

the growth in Campbell and Converse Counties, in the Powder River basin in central

Wyoming, has been from the opening of coal

and uranium strip mines. Platte County, in

southeastern Wyoming, is the site of a 1,500-

MW coal-fired plant.

Wyoming has several programs for managing growth. The major tool, designed for large

development activities, is the Wyoming Industrial Development Information and Siting

Act.

33 This Act, passed in 1975, requires that

any project with construction costs in excess

of $63,588,000 obtain a siting and construction permit from the Industrial Siting Council,

a board appointed by the Governor. Before a

permit is granted, the developer must submit

a plan for the alleviation of social, economic,

and environmental impacts, and can be required by the council to undertake their mitigation. For example, applicants can be asked

to provide direct loans and grants to a political subdivision. Another management device,

created by the Joint Powers Act,34 allows two

or more agencies, such as cities, counties,

and school districts, to form a Joint Powers

Board that can create, expand, finance, or

operate facilities. This not only makes possible combined financing by the participating

political entities but also makes them eligible

for Joint Powers Loans. There is no ceiling on

a loan, and the terms must be no longer than

40 years at an interest rate of not less than 5

nor more than 10 percent.

Wyoming also has an array of mitigation

programs. (See table 94.) They are funded by

Federal mineral lease revenues and State

severance and excise taxes. Most are administered by the Farm Loan Board, composed of

the Governor, secretary of state, auditor,

treasurer, and state superintendent of public

instruction. Allocation of funds is specified in

most cases by the taxing legislation, and

there are few discretionary programs. One

alternative available to local communities to

generate discretionary revenue is an optional

l-cent sales tax.35 It has been used successfully in several communities although approval

by the local voters must be sought every 2

years. Case studies of boomtowns in Wyoming indicate that there are major differences in the effects of rapid growth, and to

accommodate these differences, flexible policies are needed. This is especially true for

providing such human services as day care

centers, youth assistance and senior citizen

programs, and alcohol counseling. Too few

funds are available to alleviate the social impacts accompanying rapid growth.36

Evaluation of State and Local Mechanisms

State policies regarding social and economic effects vary. In Colorado, local initiative is

central in the mitigation process. The State

and its oil shale counties and municipalities

have been preparing for increased shale development for nearly 10 years. However, in

the past, this development has been interrupted or delayed by market changes, regulatory modifications, and technological complications, which has made planning difficult. In

addition, oil and gas, coal, electric generation, and uranium industries are all expanding at the same time as oil shale. This complicates the identification of impacts specifically attributable to shale development and

adds to the potential for disruption.

An elaborate planning infrastructure is in

place in the Colorado counties and municipalities. Over $40 million has been appropriated for oil shale impact mitigation, with
Ch. 10–Socioeconomic Aspects ● 437

Table 94.–Wyoming Programs to Mitigate Social and Economic Impacts

— .

Implementing

Name of mitigation program Objectives Funding agencies Comments

Wyoming Industrial Development Information and Siting

Act ( 1975)

Joint Powers Act ( 1975)

Provide information about new Industrial Not applicable Wyoming Siting

facilities costing over $63,588,000 council

Siting and construction permits required before building starts

Allows different political entitles to join Joint Powers Loans from Farm Loan Board

Council can require applicants

to take actions to mitigate

adverse socioeconomic

Impacts

Some towns and counties have

difficulty cooperating Smaller towns lack manpower to

prepare detailed applications.

Grant funds extremely limited.

competition keen

Requires feasibility study.

authorizing legislation, and

vote to approve any public

debt (such as bonds) before

construction can begin.

$160 million will probably be

together to finance and operate public

facilities through a Joint Powers Board

FLB. a FLB is restricted

to $60 million in

outstanding loans

(FLB) a

Wyoming Government Royalty

Impact Assistance Account

( 1976)

Wyoming Water Development

Program ( 1975)

Grant program for communities in areas

of mineral development

Mineral Leasing Act of

1920, as amended b

FLB

Encourage optimal development of

human, Industrial, mineral, agricultural, water, and recreational

resources through projects and

facilities for water storage,

distribution, and use

1 1/2 -percent excise tax

on coal

Revolving loan account,

up to $100 million can

be outstanding

Water Development

Commission, Dept

of Economic Plannlng and Development, FLB, local

agencies

Coal Tax Revenue Account FLB

(1975)

Grants to political subdivsions in areas

Impacted by coal development for

2-percent severance tax

on coal expended before synthetic

Public facilities. 50 percent must Maximum cumulative tax fuel development occurs

go for streets and highways revenues limited to

$160 million

Capital Facilities Revenue

Account ( 1977)

Permanent capital facilities by legislative

appropriation, 30 percent for school

district capital construction

entitlements, formula allocation to

community colleges, remainder

for highways

Capital Facilities

Commission

Used mostly for major State

facilities (university, prison),

1 1/2-percent excise tax

on coal, trona, and

uranium

Maximum tax revenues

limited to $250 million

approval of bonds needed for

school construction

Wyoming Community Program delayed by litigation.

Development only recently implemented

Wyoming Community Development Authority ( 1975)

To provide funds for private mortgages

at low interest through mortgage

Mortgage monies generated through issuance

lending institutions of bonds

Authority granted for up

to $250 million in

bonds c

Authority

alhe Farm Loan Boaro conssk of [he Governor secrelarv of slate aud!lor treasurer artd slate SuDer(fltefldefll of oubl~c /nstruct(on

bsee .eKt for a OIScusslon O! Federal flnanclal ass!slance ~r09rdmS

‘The 1980 Wfomlng Ieqlslalure oas under conslderalton rdtstoq lms amount 10$750 mltl{on

SOURCE O!flce of Technology Assessment

over 90 percent allocated to the four counties

of Mesa, Garfield, Rio Blanco, and Moffat.

(See table 95.) Most of the remainder has

gone for the State’s support services. As a result, the region is prepared for reasonable

growth and is awaiting expanded oil shale development. However, the ability of existing

strategies to deal with a large or sudden population influx, such as might occur with a

rapid expansion of the industry, is as yet untested. Although the State has ambitious programs, the General Assembly has adopted a

cautious approach to the expenditure of the

Oil Shale Trust Fund monies. While not required to do so, JBC has elected to retain a

principal of $60 million in the trust fund. This

has caused some discontent in the oil shale

region where expenditure of the full amount

would accelerate preparations for growth.

Because the trust fund is disbursed by legislative appropriation, intrastate political differences also come into play. The General

Assembly has greater representation from

the eastern, more densely populated, urban

parts of the State; thus western slope Senators and Representatives can be outvoted. Impact mitigation, in this case, is subject to the

political compromises of the Colorado appropriation process.

Utah and Wyoming have not been preparing extensively for oil shale development im-
.

438 ● An Assessment of 0il Shale Technologies

Table 95.–Allocation of Oil Shale Trust Funds,

Fiscal Years 1975-80

Percentage of total appropriation

County or agency FY 1975-79 FY 1980

Garfield County –

285 –6 1 9

Mesa Count y 130 124

Moffat County 11 2 0 6

R IO Blanco County 4 0 0 2 4 3

Subtotal–oil shale region 927 -

9 9 2

Delta Count y 0 1

0

a

Jackson County 0 0 5 0

Routt County 3 7 0

Subtotal–all counties...... 9 6 6 9 9 2

Division of Energy and Mineral Impact 2 1 0.6

CWACO G 1 2 0 1

Total 100 100

For example, Douglas and Wheatland in

Wyoming have experienced few of the negative effects identified in the literature as

boomtown impacts. Rock Springs and Gillette,

on the other hand, appear to be at the opposite end of the spectrum, with the former

being the classical example of a town disrupted by energy development. Yet these four

communities are undergoing the same types

of industrial growth (primarily coal, oil, and

gas prospecting and production) and have the

same kinds of impact assistance available to

them.

17 A conclusion from these cases is that

the capability of adapting to rapid growth appears to be highly site specific.

dThe 1979 Gepera( Assembly adopted Ihe policy 10 allOCa[e trust funds Oflly tO Ihe counties In Ihe

Immediate 011 shale vtctnlly

SOURCE OTA bdSW on data for FY 197579 from Summary and Status Report of the Mineral

Lease and Severance Tax Fund Second Annual Report to the Colorado Stale Legislature, Department of Local Affairs 1979 and FY 1980 from State Appropriation Act for

FY 19791980 (S B 525)

pacts. Both States, however, have had to

come to grips with other energy industry expansion, and presumably could use programs

similar to the ones now established for coal

and uranium mitigation to adjust to oil shale

growth. They emphasize a more centralized

process with State government playing a

larger part in the determination of needs and

the allocation of assistance. Utah may be

limited by a lack of funding, although the

bonus payments from the U-a and U-b lease

sales—now being held in escrow pending the

outcome of the ownership question—should

be available in the future. The State may experience difficulty from a lack of adequate

local infrastructures capable of handling

rapid growth. Evaluation is complicated for

Utah as it is for Colorado by similar uncertainties about the future timing, pace, and

size of the industry. Wyoming has many programs that could be adapted for oil shale impact mitigation. At present, its funding levels

appear to be adequate.

No State facing social and economic problems from energy development is able to anticipate which communities will be able to adjust to growth and which may be disrupted.

Whether towns will suffer from rapid growth

or take it in stride depends on a unique set of

complicated factors within each community.

Federal Programs

Only a few of the over 1,000 existing Federal programs are designed to deal with socioeconomic impacts. A 1978 Report to the President 38 lists 160 that were judged “potentially

applicable to energy impact issues. ” They are

administered by 20 departments or other Federal agencies. About two dozen programs

that are of importance to the Western States

have been identified by Murdock and Leistriz. 39 (See table 96. ) Only those that contribute to the alleviation of negative impacts from

oil shale development are examined in detail

here, Federal programs can be placed in two

broad categories: financial and technica l

assistance .

Financial Assistance

Section 35 of the Mineral Leasing Act of

1920

40 is a major source of Federal financial

assistance. This legislation originally provided for the Federal Government to return

3 7

1/2 percent of the revenues it receives from

mineral leases on public lands to the States in

which those lands are located; these monies

were to be used by the legislatures of the

States for support of public schools and

roads. In 1976, this section was amended by

the passage of the Federal Coal Leasing

Amendments Act41 and the Federal Land Policy and Management Act42 (also known as the

Bureau of Land Management Organic Act or
Ch. 10–Socioeconomic Aspects ● 439

Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effects of Energy Development’

Name of program Implementing agency Objectives Comments

Assistance in planning and growth management

Comprehensive planning Community Planning and Strengthen planning and declslon-making Urban orientation overall, smaller cities

assistance Development, HUD capabilities of States, local governments, and counties receive funding through

HUD 701 program and areawide planning organizations States Funds allocated on basis of past

National Housing Act of population which IS a disadvantage to

1954, as amended (40 rapidly growing communities

U S C 461) Some State and local concern over recent

decline in funding levels —

Community development block Community Planning and

grants–small cities Development, HUD

Housing and Community

Development Act of 1974

Title I (42 U S C

5301-531 7)

Economic development– Economic Development

planning and technical Administration (EDA),

assistance Commerce

Public Works and Economic

Development Act of 1965,

as amended (42 U S C

3151, 31 52) Title III

Assist communities in providing decent

housing and a suitable Iiving environment, expand economic opportunities

Foster multicounty planning and

Implementation capability, solve problems of economic growth through project

grants, feasibility and other studies, and

management and operational assistance

Primarily for urban areas, most funds

allocated by formula Some discretionary

funds for special-purpose grants to small

communities

Provides 100-percent funding that can be

used as local matching contribution for

other programs

Can also be used for facility construction

as well as for planning

Criteria for project selection makes it dif -

ficult for energy-impacted communities

to obtain funding

Competition for funds is keen.

Technical assistance– Off Ice of Personnel Aid in problem-solving and delivering Few communities appear to have taken

personnel sharing Management Improved services by sharing profession - advantage of program.

Intergovernmental Person- al administrative, and technical Time involved in Iocating and negotiating

net Act of 1970 (5 U S C expertise. for an individual may be a constraint for

3371-3376) small counties and communities

Water quality planning Office of Water and Waste Develop water quality management plans Funds limited to planning only

sec 208 grants Management, Environmental

Clean Water Act, as Protection Agency (EPA)

amended (33 U S C 1251

et seq. )

Assistance in expanding public facilities and servicesc

.

Water and waste disposal sys- Farmers Home Administration Provide amen! ties, alleviate health Sewer and water systems cannot serve

terns for rural communities (FMHA), Agriculture hazards promote orderly growth of rural areas with a population in excess of

Consolidated Farm and areas by providing new and Improved 10,000 population, priority is given to

Rural Development Act, water waste disposal facilities communities of less than 5,500 in -

sec 306 (7 U S C 1926) habitants

Community facilities loans FmHA Agriculture Construct, enlarge, or Improve community Targeted for areas with Iow-income rural

Consolidated Farm and facilities residents

Rural Development Act, Priority to projects enhancing public safety

sec 306 (7 U S C 1926) (fire, pollee, rescue services), health

care facilities needed to meet life/safety

codes, public buildings and courthouses,

recreation facilities, new hospitals

Construct Ion grants for Office of Water and-Waste Assist in construction of municipal sewage Funds allocated to States on a

wastewater treatment works Management, EPA treatment works population-based formula No funding of

Clean Water Act as collector systems in ‘‘communities not in

amended (33 U S C 1251 existence” in October 1972

et seq ) Some difficulty allocating funds on a timely

basis

Economic development and EDA, Commerce Assist State and local governments to

..- —..——.

Targeted to communities experiencing

adjustment assistance arrest and reverse long-term economic economic decline but funds are available

Title IX– EDA deterioration, address dislocations from to energy-impacted areas

Public Works and Economic Federal actions, from compliance with Flexibility an advantage

Development Act of 1965, environmental requirements, and from

as amended (42 U S C severe changes in economic conditions

3121 et seq ) — — —
440 . An Assessment of Oil Shale Technologies

Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effects

of Energy Developmenta—continued

Name of program Implementing agency Objectives Comments

Outdoor recreation Heritage Conservation and Financial assistance for planning, Limited funding restricts the number of

‘‘ BOR program’ Recreation Service, Interior acquisition, and development of outdoor projects that can be supported

Land and Water Conserva- recreation areas and facilities A popular program

tion Fund Act of 1965,

et al. (16 U .S. C. 1-4

et seq. )

Planning and site acquisition FmHA, Agriculture Assist in developing plans for growth Newly Implemented,

Sec. 601 program management and housing and in Currently Iimited to coal and uranium

Power Plant and Industrial acquiring sites for housing and public Impacts,

Fuel Use Act of 1978 facilities

(Public Law 95-620)

Assistance for housing

Rural housing loans FmHA, Agriculture To assist rural families through guar- Loans are regarded as a ‘ ‘source of last

Housing Act of 1949, as anteed/insured home loans resort to be used only if commercial

amended. Title V, sec. lending Institutions cannot finance

502 (42 U.S. C. 1471 et housing.

seq., 42 U.S. C. 1480;

42 U.S.C. 1472)

Rural housing site loans FmHA, Agriculture Assist public or private nonprofit Priority given to housing for low- and

Housing Act of 1949, as organizations to acquire and develop land moderate-income families

amended. Sees. 523 and to be subdivided on a nonprofit basis for

524. (42 U.S. C. 1490c homes.

and 1490d)

Rural rental housing loans FmHA, Agriculture Provide economically designed and conHousing Act of 1949, as structed rental and cooperative rental

amended. Sees. 515 and housing for rural residents,

521. (42 U.S.C. 1485,

1490a)

dThe ~rogram~ l,~fed are ,Ilus(rdtlve of the types of aid avadable In Western States no attempt has been made to Include all possible Federal Pro9rams used by lmPacted communities

bGeneral ~ategor[es are based on the format used by Murdock & Le!slr[tz Errergy L7eve/opmerrf Irr Ihe b$’es(e~rr Umled S/aleS–hnPaC/ On Rural Areas (A y prae9er Publishers 1979)

CRevenue ~har, ng acts suc~ as the Local Government Funds Act (publlc Law g4.5fj5) are not Included see [ext for a discussion of the Mineral Leasing Act Of 1920 aS amended

SOURCE Office of Technology Assessment

FLPMA). The Federal Coal Leasing Amendments Act increased the States’ share of

royalty and lease proceeds to 50 percent, and

specifically directs the legislatures, when

distributing these proceeds, to give priority to

those subdivisions of the State where leasing

occurs under the Act. At the same time, the

purposes for which the funds could be used

were broadened to include “planning, . . .

construction and maintenance of public facilities, and . . . provision of public services." 43 FLPMA further amends the 1920 Act

to authorize the Secretary of the Interior to

make loans to States and their political subdivisions. The amounts of the loans are not to

exceed the revenues anticipated by the States

or their jurisdictions for any prospective 10-

year period. Loans are to be repaid, at 3-percent interest, from these proceeds. The language of the Coal Leasing Amendments Act

that allows broader use of the funds and specifies their application to affected areas is

also extended to the loans.44

Section 601 of the Power Plant and Industrial Fuel Use Act of 197845 established the

Energy Impacted Area Development Assistance Program (popularly, the sec. 601 program). Its objective is to “help areas impacted by coal or uranium development activities by providing assistance for the development of growth management and housing

plans and in developing and acquiring sites

for housing and public facilities and services. 4 6

The lead agency designated to administer the section is the Farmers Home Admin-
Ch. 10–Socioeconomic Aspects ● 441

istration (FmHA). The Governor of a State

wishing to participate must designate energyimpacted areas and prepare a State investment strategy for allocating the funds. Grant

applications for impact aid must be consistent with the State investment plan. Local governments, councils of local governments, and

State agencies are among the eligible applicants. Grant funds will pay 100 percent of the

costs of developing plans for managing

growth and/or plans for new housing, and up

to 75 percent of the cost of acquiring or developing sites for housing, public facilities, or

services.

Three criteria are specified for designation

as an impacted area. First, employment in

coal or uranium development activities must

have increased, or be expected to increase

over 3 years, by 8 percent or more from the

preceding year. Second, the increased employment must result in a housing shortage or

inadequate public facilities and services.

Third, the available State and local financial

resources must be inadequate to meet the

current needs or those projected for the following 3 years. Within the oil shale region,

the purchase of land by the city of Meeker for

the construction of low- and moderate-income

housing was included as a priority project in

the 1979 Colorado investment strategy.

Technical Assistance

THE FEDERAL REGIONAL COUNCIL

The Energy Impact Office of the Federal

Regional Council (FRC), Region VIII, oversees

Federal technical assistance programs. The

Office was created early in 1978 to coordinate the response of Federal agencies to local

needs. In addition to the development of an

improved system of service delivery, the FRC

efforts are designed to evaluate Federal legislation for impact assistance and to collect impact data and related information. The agencies comprising the Federal Regional Council

are the Departments of Agriculture; Commerce; Energy (DOE); Health, Education, and

Welfare; Housing and Urban Development

(HUD); the Interior; Labor; Transportation;

the Community Services Administration, and

the Environmental Protection Agency (EPA).

Senior staff members of these agencies make

up an Intergovernmental Committee that

assists the Energy Impact Office.

Dissemination of information and interagency coordination are the main functions of

the Federal programs. Several examples can

be cited. FRC has a representative in the Oil

Shale Environmental Advisory Panel (OSEAP)

who serves as contact with this group. The

Federal Assistance Program Retrieval System (FAPRS) is a computerized information

bank, keyed to programs described in the Catalog of Federal Domestic Assistance. The Energy Impact Office uses it to help communities identify various Federal assistance programs and determine their eligibility for aid.

DOE’s Office of the Regional Representative,

Region VIII, in cooperation with FRC, publishes an annual Regional Profile—Energy Impacted Communities47 that collates data on

the energy impacted areas.

OFFICE OF THE AREA OIL SHALE SUPERVISOR

The Office of the Area Oil Shale Supervisor of the U.S. Geological Survey (USGS)

also provides technical assistance to communities by serving as a clearinghouse for information about social and economic impacts

and programs for their alleviation.

Summary of Federal Support Initiatives

At the present time, there is no single Federal policy with respect to the social and economic effects of energy development. At the

regional level, the Federal point of view is

best expressed in the Region VIII DOE Regional Profile. The edition of March 1979 reiterates a position taken in earlier volumes:

The Region VIII office maintains the position that local communities and counties

must take the initiative to become involved in

assessing, planning for, and mitigating adverse energy related impacts. To effect a

team effort involving industry, Federal,

State, and local government, the initiative

and follow-up must first be taken by local

leadership,”
442 ● An Assessment of Oil Shale Technologies

Several programs are operating that address limited aspects of socioeconomic effects but, at present, none directly addresses

the impacts that may come with synthetic fuel

development or the specific consequences of

accelerated shale oil production. A wide variety of assistance is available through avenues

not specifically designed to deal with energy

development impacts. These various Federal

programs have different emphases and

modes of providing help, and impacted communities must compete with everyone else for

the limited funds available.

These regular Federal programs usually

require elaborate proposal development but

small towns with limited manpower often do

not have the expertise to prepare grant applications. Furthermore, many programs

have lengthy review processes before decisions are made, which can be a disadvantage

for boomtowns. For example, EPA grants for

sewer facility upgrading take about 3 years

from the time of application to the time of

decision; if a community does not get a grant,

this time is lost entirely and the town can only

fall further behind in its effort to keep up with

its growth. In addition, although the specific

programs may be adequately meeting the

needs for which they were designed, their

limited nature means that the cumulative impacts of all types of industrial development

are not being addressed.

At present, the major role of the Federal

Government is providing revenues for mitigation; these monies come primarily from the

Mineral Leasing Act of 1920, as amended. A

somewhat expanded Federal impact mitigation role is found in section 601 of the

Powerplant and Industrial Fuel Use Act of

1978. The extent and nature of any additional

Federal involvement in impact mitigation are

controversial. On the one side, it can be

argued that social and economic impacts are

State and local problems. They should be

viewed as the inevitable consequences of industrial development, and the Federal Government need not be involved with their amelioration. This viewpoint, opposing Federal involvement, also contends that specific Federal mitigation programs would increase bureaucracy, and cites the public’s growing displeasure with the perceived intervention of

Federal agencies in the daily life of the citizenry as a reason for not expanding Federal

activities. On the other side is the position

that national requirements are the root

causes of the local impacts, therefore an expanded Federal role is appropriate. Several

Western States contend that because expanded domestic energy production is a national goal, for reasons of equity the Federal

Government should assume a more direct role

in the alleviation of negative impacts from

this development.

Assuming additional Federal involvement

is desired, how can the Government most appropriately assist impacted communities?

One position is that providing financial

assistance is sufficient programmatically and

only the amounts need to be increased; new

programs and regulations are not desirable.

Another position is that Federal regulation

could be used to mitigate impacts by, for example, pacing industry’s growth rate through

leasing policies. A third position is that the

Government should be substantially involved

in mitigation programs that use Federal

funds. Part of this issue includes the question

of when and where the Federal Government

might to be involved. The provisions of the

Powerplant and Industrial Fuel Use Act suggest that it should step in only when State and

local governments cannot handle impact

problems. A similar position is that Federal

participation should be confined to areas requiring long-term commitments, such as housing, sewer, and water systems. Another possible Federal approach could be to help specific groups (such as retired persons on fixed

incomes or young adults seeking to enter the

job market) who may be particularly hard hit

in boomtowns. 49
Ch. 10–Socioeconomic Aspects ● 443

Possible Consequences of Oil Shale Development

General Effects of

Rapid Population Growth

The recent development of energy resources has caused large numbers of people

to move into established rural communities

within short periods of time. All parts of a

community are affected by this kind of

growth. Local government agencies are

pressed to provide additional services. A major difficulty is that the expanded facilities

and services are needed before new tax revenues can be realized. A 3- to 5-year lag appears to be the average between the time the

increased services and facilities are required

and the time additional revenues can be generated. (See figure 71. ) In the long run, however, local governments should benefit from

the increased tax base resulting from energy

development.

Local governments need help in the early

stages of rapid growth. One traditional

means of raising the needed funds is by issuing bonds. While this remains important, experience indicates that it is far from adequate. First of all, State law usually places

limits on the amounts of indebtedness that

counties and communities can incur through

bond issues. Second, the assessed valuation

upon which bonding limits are based increases over the life of a project but funds

are needed during the early stages when the

population is growing rapidly. Third, local

I

4

._

----

—
444 . An Assessment of Oil Shale Technologies

Fiqure 71 .— Energy-Related Employment, Tax Revenues, and Need for Public Services in an Area

EMPLOYMENT

-.

Affected by a Large-Scale Energy Development

CONSTRUCTION I

PHASE

I

I

OPERATION

PHASE

I I

Energy-Related I

Employment

L

I

I

PUBLIC SERVICES

TAX REVENUES

TIME

SOURCE S H Murdock and F L Leistritz. Energy Development in the Western United States, 1979, Praeger Publishers

residents are often afraid to approve bond

issues because of the instability of the boom

cycle. People who have moved in during construction, and who are among those needing

new services and infrastructure, usually

leave at the end of the construction period.

Longtime residents are fearful that they will

be left to discharge debts incurred during this

period. Consequently, voters in many of the

most severely impacted communities have rejected bond issues. Similar difficulties are

found with loan and loan-guarantee programs. In this instance, the statutory or constitutional limits on the debt that rural communities can incur is an obstacle to the use of

the loans to meet front-end funding needs.

Yet another statutory limitation can be a

ceiling on the expansion of local government

budgets. For example, in Colorado most small

towns are prohibited from “the levying of a

greater amount of revenue than was levied in

the previous year plus seven percent . . ."50

The practical effect of this restriction on mill

levy increases is to limit municipal and county budgets to a 7-percent-per-annum growth.

Finally, the ability of local governments to

respond may be complicated because the development and the population growth may be

in different places. When the project is in one

taxing jurisdiction and the community in a

different one, there is a jurisdictional mismatch. In this case, the town that must provide increased facilities and services cannot

look forward to larger revenues from taxes

on the new industry.

In the private sector, housing can be a major problem. It usually is in short supply; its

prices are often greatly inflated; and land

may not be available for new construction because of terrain, price, or public ownership.

Shortages of construction financing and

mortgage money are common and, in some

cases, new employees may not qualify for

mortgages. The need for temporary housing

for construction workers can exacerbate

these problems. Mobile homes often fill this

need but their siting and providing services to

the sites add to the difficulties faced by local

government. Industry has, in several instances, sought to assist by supplying capital
Ch. 10–Socioeconomic Aspec!s ● 445

for housing construction. Because public

housing is statutorily limited to low- and moderate-income groups, Federal Government

agencies cannot provide much help.

Other affected parts of the private sector

are the local retail trade and service industries. These businesses often anticipate increased income from energy development.

What may not be expected are increases in

labor costs, taxes, and competition. In some

cases, this sector has not been able to meet

the new demands; business failures have

been the most extreme consequences. More

common have been difficulties in getting and

keeping help, providing the goods that customers want, and expanding stores and shops

to keep up with the increased business. Like

local governments, retail businesses should

profit in the long run from energy development; their dislocations occur during the

early periods of rapid growth when services

cannot keep up with the new demands.

Those parts of the community that provide

services to the residents also are affected. In

many areas, this support sector is inadequate

prior to any sudden growth. For example,

doctors and dentists are not readily available

in many rural regions. School systems, while

established, cannot offer broad curricula,

and may have difficulty attracting and keeping personnel. The number of public safety

professionals often is limited. Sheriff’s offices

and town police departments seldom have

large forces; fire protection is usually provided by volunteer departments. Recreation

facilities may be lacking. Social welfare services may depend on itinerant professionals,

such as a public health nurse or social worker who visits the communities periodically.

The functions of a community’s social infrastructure often are carried out through informal social networks. In rapid growth situations, these networks can break down simply because of the increased number of newcomers. If there are no established formal

structures, then the services cannot be provided. For example, in many rural communities the school is the center of recreational

activities, and there are few structured programs. Increased demands to use the school

gym cannot be met because there aren’t

enough hours in the day or enough basketball

courts to accommodate the large number of

new players, Established informal recreation

patterns can thus be disrupted and nothing

takes their place until a formal community

program can be set up. The effects of rapid

population growth on the various aspects of
446 ● An Assessment of 011 Shale Technologies

Photo credit OTA staff

Adequate recreational areas are often lacking in boomtowns

the existing community support systems are

among the more ubiquitous social impacts of

energy development activities.

Rapid growth inevitably causes social

changes; those communities experiencing excessive strains on their social structure from

sudden growth have been called modern

boomtowns. 51 A well-documented example is

the Rock Springs—Green River (Sweetwater

County) area of Wyoming.52 Here the population grew from 18,391 in 1970 to 36,860 in

1974. Among the consequences were:

●

●

●

Housing availability fell far short of demand. In 1974, between 4,500 and 5,000

families were living in mobile homes,

many on scattered, isolated tracts in unincorporated parts of the county.

These housing areas often lacked adequate water, sewer, and other facilities.

Health care became a major problem.

An estimated 40 percent of the residents

had to seek medical care outside the

county; the mental health clinic caseload

●

●

●

It

expanded ninefold as alcoholism, suicide

attempts, and divorce rates soared.

Local government was overwhelmed

with difficulties. Costs for capital construction of public facilities, such as

water and sewer treatment plants, were

greater than the communities’ borrowing capacity, and demands for public

services, such as fire and police protection, were beyond the available resources.

Schools could not keep up with the pupil

increases. The school districts were already bonded up to the legal limit and

were not able to provide the needed additional services.

As a result of the boomtown conditions,

industry was unable to recruit and retain employees. Employee turnover in

1973 ranged from 35 to 100 percent, and

productivity declined. Cost overruns resulted from construction delays. 53

is difficult to determine whether a community will be able to respond adequately to
Ch. 10–Socioeconomic Aspects Ž 447

the pressures of growth; however, some generalizations have been drawn from case

studies of towns like Rock Springs and Green

River. Boomtowns have been described as

having the following characteristics: 54

●

●

●

●

●

●

●

●

●

●

●

a small population base, usually under

10,000 residents;

geographic isolation from urban areas;

rapid population growth;

a shift in economic activities away from

agriculture, trade, and services to constructing and operating energy-related

industries;

demand for temporary and permanent

housing that exceeds supply, with accompanying price escalation;

increased symptoms of social stress

such as crime, truancy, child abuse,

alcoholism, and suicide;

inability of the public sector to provide,

in a timely fashion, services and facilities such as streets, water, and sewers;

dislocations in the private sector such as

business failure, labor shortages, and

cost increases;

strain on health services from increased

need for access to professionals and facilities;

high employee turnover with accompanying decline in productivity; and

in the early stages, a lack of community

concern for planning and growth management.

Alterations in human relationships underlie the changes accompanying rapid growth.55

Some social and behavioral scientists contend that these are among the most pervasive

and significant consequences of growth and

are the basic causes of boomtown symptoms.

56 Among the alterations that have been

identified in the social roles individuals must

fill are increased anonymity, impersonalization, and specialization. At the institutional

level, greater bureaucratization, centralization, and orientation of community units

toward systems outside the local social structure have been found. 57 Among the psychological factors identified in boomtowns are

value conflicts between established residents

and in-migrants, and shifts in personal interaction patterns such as the deterioration of

longtime friendship patterns, At the social institution level, dramatic realinements of political party membership, and an atmosphere

of uncertainty about the future that undermines established systems of social control

have been documented.58 On the other hand, a

comparison of the experiences of four Colorado boomtowns found a picture of resilience

and adaptability suggesting the “hope that

people can adjust to changes instead of being

overwhelmed by them . . . ."59

Anticipated Growth in the

Colorado Oil Shale Region

As a sparsely populated, rural region,

western Colorado is vulnerable to boomtown

conditions. The three oil shale counties had a

population of 90,748 at the time of a special

census in 1977. Growth between 1970 and

1977 ranged from 5 percent for Rio Blanco

County to 27 percent for Garfield County; the

largest growth (58 percent) was in Moffat

County, to the north of the oil shale region.

(See table 97.) None of the communities in the

immediate area had a population over 3,000,

(See table 98.) There are 2 to 19 persons per

square mile and a high proportion of older

residents. (See table 99. ) Sixteen percent of

the residents of the oil shale communities in

Rio Blanco and Garfield Counties are over 65

years old, which is over sixty percent higher

than the national average. 60

The first step in attempting to forecast

whether there might be disruption is to gauge

the magnitude of possible migration to the

area. As indicated earlier in the chapter,

Table 97.–Population Growth of Colorado Oil Shale

Counties 1970-77

Population Population Percent

County 1970 1977 change

R IO Blanc o 4,842 5,100 5.3

Garfiel d 14,821 18,800 26.8

Mes a 54,374 66,848 22.9

Moffa t 6,525 10,303 5 7 9

SOURCE U S Bureau of Census data
448 . An Assessment of 0il Shale Technologies

Table 98,–Population of Colorado Communities

Apt To Be Affected by Oil Shale Development, 1977

Location Population

Rio Blanco County

Meeker ., ., ., 1,848

Rangel y 1,871

Garfield County

Glenwood Spring s 4,051

Grand Valley, . : ., 377

New Castl e 543

Rifle. ... 2,244

slit : : : ., 859

Mesa County

De Bequ e , . 264

Grand Junction ., ., 25,398

Moffat County

Crai g ,. 6,677

Dinosau r 347

SOURCE 1977 special census

Table 99.–Selected Demographic Indices of

Oil Shale Counties of Colorado, July 1975

Number of people Percent aged

County per square mile 65 and over

R IO Blanc o 2 8.3

Garfiel d 6 105

Mes a 19 1 1 9

Moffat ., : : ., . : ., 2 8 3

SOURCE Bureau of the Census City and County Data Book 1977

CWACOG has a growth-monitoring system

that provides projections of future growth.

Because this organization serves the day-today needs of the individual counties and communities, the projections are frequently modified in an attempt to reflect the current situation. To an outsider, there appear to be several sets of data none of which coincide since

it is possible for a town to be using one set of

projections to plan for additional housing,

another to determine water and sewage

treatment requirements, and a third to estimate the costs of providing public services.

Although this arrangement creates some confusion as to which projections are the most

accurate, it is important to modify projections

when the assumptions change. As an illustration, Rangely’s projections have been overestimated in the past because they have assumed a new road would be built from the

town to tract C-a. Since the road was not

being constructed when the most recent housing projections were made, the CWACOG

housing data took this into account and

Rangely’s figures were adjusted downward;

but because these revisions are not reflected

in all of the projections, discrepancies can be

found between different sets of data.

Each year, CWACOG prepares for the region an official set of projections to the year

2000, based on the following information:

●

●

●

●

●

baseline population data from the 1970

regular and a 1977 special U.S. census;

energy company employment projections

with a family multiplier (2.0);

support industry worker multipliers with

accompanying family multipliers (2.5);

base worker distributions assigned by

county and community; and

cohort survival factors.

Three population projection scenarios are derived using these factors:

Scenario I—

Scenario II—

Scenario III—

Natural population growth without energy development;

Growth with energy industry development, as presently planned;

Growth with energy development

including shale oil ‘production of

500,000 bbl/d in 1990 and 750,000

bbl/d in 1995and 2000.

The first scenario is a conservative estimate of growth with a population induced

from non-energy-related employment figures.

Its major benefit is to provide a lower limit

against which to compare the growth scenarios. The second scenario, growth with

energy development, contains base worker

projections from 18 companies including 6

that expect to proceed with oil shale development. These are the developers of tracts C-a

and C-b, Superior, Union Oil, Paraho, and Colony (Atlantic Richfield and TOSC O).

61 This

scenario has been selected by the CWACOG

Board as the officially endorsed set of projections because it reflects the stated plans of

companies active in the region. The third scenario illustrates an upper limit generated by

assumptions for a rapidly deployed oil shale

industry.

The latest official CWACOG projections

for the oil shale counties, published in Novem-
Ch. 10–Socioeconomic Aspects • 449

ber 1979, show that Rio Blanco and Garfield

Counties are expected to have sharp population increases under the energy development

scenario. (See table 100 and figure 72. ) The

number of people in Rio Blanco County is forecast to be, by 1985, four times the 1977 special census count, while the number in Garfield County is seen as nearly tripling. Moffat

County is projected to have a large increase

in the early 1980’s but this growth is attributed to coal and electric generation development, not to oil shale, Mesa County is expected to grow without extreme fluctuations,

but the number of people is projected to nearly double by 1990 over the 1977 figure.

CWACOG prepares projections for individual communities as well as for the counties.

(See figure 73.) For the energy development

conditions (Scenario II), these figures reveal:

Rifle’s population is projected to grow by

1985 to over six times the 1977 count.

Meeker’s population is projected to grow

by 1985 to over seven times the 1977

count.

Rangely’s population is projected to

grow by 1985 to over three times the

1977 count.

The projections for Scenario III, assuming

an industry producing 500,000 bbl/d of shale

oil by 1990 and 750,000 bbl/d by 2000, disclose exceptionally high growth for the region. By 1985, Rio Blanco County is projected

to have almost 8 times the number of people

counted in 1977; Garfield is forecast to have

3

1

/2 times its 1977 count. Mesa and Moffat

Counties are not forecast to have such spectacular growth, although Mesa County’s population is seen as growing to almost 3 times

the 1977 figure by 2000.

The populations of Rifle, Meeker, and

Rangely are projected to increase from

around 2,000 to over 22,000 by 1985, with a

net increase of approximately 18,860 residents for Rifle. Like the counties, the biggest

increments for the towns occur in the early

years, between 1980 and 1985. Under Scenario HI, the projected growth for these three

communities exceeds 500 percent in the period between 1980 and 1985. (See table 101. )

Needs Arising From Anticipated Growth

The projections are used by the counties

and communities to prepare plans for their

Table 1OO.– Population Projections by Development Scenario for the Oil Shale Counties of Colorado

RIO Blanco Garfield Mesa Moffat —

1977

Actual s

a

5,100 18,800 66,848 10,303

1979

Estimate d

b

5,580 22.000 75,000 10,925

1985

Scenario I

c

51779 28,181 101.005 11,509

Scenario II 22,809 50.559 107,855 15,306

Scenario Ill 40,501 66,820 128.460 18,892

1990

Scenario I 6,177 32,080 121,091 13,311

Scenario II 19,522 56,909 128,308 17.090

Scenario Il l 35,881 71,621 147,583 24,302

2000

Scenario I 6,973 45,344 161,266 16,914

Scenario l l 20,318 83,012 169,882 20,693

Scenario Il l 44,303 95,365 190,484 27,905

aFrOrn a 1977 spec[al U S census

b End of {he ~ea[ ~sf(mate prepared (n July 1979 Dy the Colorado West Area COUflCll of Governments

cBdsed on (he followlng

Scenar!o I – Natural poputal(on growth w,thoul energy development

Scendrlo 1: - Growth with energy development accordng to employment forecasts from 18 lnduslr,es acflve (n the region io!tlclal 1980 CWACOG projechons I

Scenarto III –Energy development lncludlng shale 011 production of 500000 bbl d m 1990 and 750000 bbl d In 1995 and 2000

SOURCE Colorado Wesl Area Council of Governments
450 ● An Assessment of Oil Shale Technologies

Figure 72.—Population Projections for Colorado Oil Shale Counties by Development Scenario, 1980-2000

32,000

28,000

24,000

6

F

~ 16,000

8 12,000

L

8,000

4,000

/

/’ /

//-

/,

110,000

100,000

90,000

80,000

z 70,000

0

~ 60,000

-1

z 50,000

:

40,000

30,000

20,000

10,000

1977 1980 1985 1990 1995 2000

RIO BLANCO COUNTY

J I 1 I 1 1

1977 1980 1985 1990 1995 2000

MOFFAT COUNTY

KEY

POPULATION

1977 SPECIAL CENSUS

SCENARIO I—WITHOUT

ENERGY DEVELOPMENT

SCENARIO II—WITH

PRESENTLY PLANNED

ENERGY DEVELOPMENT

SCENARIO III—WITH

PLANNED ENERGY DEVELOPMENT

AND OIL SHALE INDUSTRY

OF 500,000 bbl/d IN 1980

AND 750,000 bbl/d IN 1995

AND 2000

OFFICIAL 1980 CWACOG PROJECTIONS

200,000

175,000

150,000

z

Q 125,000

%

+ 100,000 CL

: 75,00 0

50,000

25,000

1 1 1 I I

19771980 1985 1990 1995 2000

GARFIELD COUNTY

I I 1 I 1

1977 1980 1985 1990 1995 2000

MESA COUNTY

SOURCE Colorado West Area Council of Governments
Ch. 10–Socioeconomic Aspects ● 451

17,000

16,000

15,000

14,000 E

Figure 73.— Population Projections for Selected Oil Shale Communities in Colorado

by Development Scenario, 1980-2000

11,000

I

I

10,000 1’ ~-

9,000

8,000

7,000 /“ / ‘

- x

”

– –

––– 

x

1/

3,000 —

2,000

; / n o

–e n

.

1,000 —

i I 1 1 I

1977 1980 1985 1990 1995 2000

MEEKER

KEY

@ POPULATION

1977 SPECIAL CENSUS

o 0 SCENARIO I—WITHOUT

ENERGY DEVELOPMENT

x— —x ——x SCENARIO II—WITH

PRESENTLY PLANNED

ENERGY DEVELOPMENT

● - - *--- - O SCENARIO III—WITH

PLANNED ENERGY DEVELOPMENT

AND OIL SHALE INDUSTRY

OF 500,000 bbl/d IN 1990

AND 750,000 bbl/d IN 1995

AND 2000

BASED ON JULY 1979 PROJECTIONS

18,000

17,000

16,000

15,000 E

14,000

13,000

12,000

11,000

10,000 E

9,000

E

I

8,000

7,000

6,000 IJ

:

 ,

)%

5,000

- x— — — — — —x

//

4,000

F

//

3,000 / /

2<000 a)

1,000 k

 -

1977 1980 1985 1990 1995 2000

RANGELY

26,000 —

24,000 — .0

22,000 —

# @ ~

20,000 —

9%. /*””

~ 18,000 — fi ‘-0” ““

~ 16,000 .

If

~ 14,000” — /-A

/

~ 12,000 —

/

//-

: 10,000 — /x- -

- ‘

-

8,000 — If /

6,000 — ;/

4,000 —

e

o m

2,000 — .

I I I 1 I

1977 1980 1985 1990 1995 2000

RIFLE

SOURCE Colorado West Area Council of Governments

growth. There are over 20 documents that

identify specific needs expected to arise in

the period between 1980 and 1985. * Examples in the following discussion have been

taken from these various planning documerits. ”Z

Needs for the entire region are mainly in

the areas of health and education; over 90

percent of them are for improving schools

and upgrading hospital facilities. Technical

assistance for CWACOG is also included.

*13ec:ausc the needs appear in plans prepared by different

groups al different tlmtx, a v[{ rle tv of CL I’ACOG pro j ert i ons

hate been emploved (see discussion at the beginning of the preceding sect ion). E’or this re:)son, i t is di ffirul t to I ink speci fir re-

(lu i remen ts di re( t Iv t o the CL$’ A (;(X; populo t ion scenarios.

Table 101 .–Projected Population Growth of

Selected Oil Shale Communities, 1979-85

Projected Projected

population population Percent

Community 1 979’ 1985b Increase

Rifle ., 3,200 22,060 589

Meeker : 2,250 16,745 644

Rangely 1,900 14,088 641

aEsllmale at end of year

bCWACOG Scenario Ill (does not Include tnnge areas around each town)

SOURCE OTA based on projections from the Colorado West Area Councd ot Governments

Compilation of regional requirements is complicated by overlapping or differing jurisdictions for a number of services. For example,

the Valley View Hospital, located in Glenwood Springs, in a recent needs assessment
452 ● An Assessment of Oil Shale Technologies

included as a service area the central part of

Garfield County. This portion of the county

encompasses Rifle, site of the Clagett Memorial Hospital, and overlaps the Grand River

Hospital District in which the Rifle hospital is

placed. School districts, although not overlapping, encompass a number of different communities, which makes it difficult to separate

their requirements from those of the municipalities. Sanitation and recreation districts

with differing boundaries add to the complications.

For Garfield County, planning documents

contain over two dozen projects needed between 1979 and 1984: 41 percent of them are

in the area of education; 19 percent in the

health and medical services; 15 percent in

public services, especially water supply projects; 11 percent each in mental health and

public facilities, the latter primarily roads;

and 3 percent for welfare services.

Rio Blanco County and its communities,

Meeker and Rangely, expect large growth

from expanded shale development. For the

period from 1980 to 1985, planning groups

have identified five categories of needs for

the county. About half are for public facilities

and services: roads, highways, and bridges;

airport improvements; trash compactors; a

public safety building; and similar projects.

Educational necessities, hospital improvements, recreational projects, and support for

the planning infrastructure make up the remainder.

Needs From Oil Shale Development

Several different kinds of energy industry

activities are taking place in the region.

Unless it is rapid, the expansion of the oil

shale industry, in and of itself, may not

disrupt the communities of western Colorado;

combined with accelerated coal development,

oil and gas exploration and production, the

installation of electric generation plants, and

the possibility of other synthetic fuel activities, the effects could be devastating. Separating the potential consequences of shale

development from the combined effects is difficult, and local planners do not try to do so.

The following discussion emphasizes oil shale

development while recognizing that it will occur in the larger context.

Mesa County

The effects on Mesa County depend on the

location of development. At present, between

30 and 40 percent of the employees at Logan

Wash facilities operated by Occidental Oil

Shale, Inc., live in the Grand Junction area,

and further development along the southern

rim of the Piceance Basin would add to these

direct effects in the county. Otherwise, they

are likely to be indirect, taking the form of

demands on the transportation and service

sectors, both public and private, and on support industries. Benefits, such as increased

revenues and cash flow, will occur when

shale workers go to Grand Junction to purchase goods and services.

De Beque is the Mesa County community

now experiencing direct effects of oil shale

development activities. It is the nearest community to Logan Wash and exemplifies several of the problems associated with boomtown

growth. It is located in Mesa County, while

Logan Wash is in Garfield County; thus tax

revenues from the energy development accrue to a jurisdiction different from the one

receiving the impacts. De Beque has had difficulty preparing for increased growth, particularly in dealing with the effects of inflation. A 1976 study detailed the improvements

needed by the water supply system. It

estimated the costs at $608,000; when bids

were opened in 1978, they came to $787,000;

but only $500,000 was available. The city

was unable to assume any additional debt

and had to turn to the State for help. When

completed, the facilities will be adequate for

the present population but would have to be

expanded if a large number of new residents

were to be accommodated.

Garfield County

In 1975, the Colony Development Operation

proposed that a new residential community,
Ch. 10–Socioeconomic Aspects ● 453

to be called Battlement Mesa, be constructed

south of the Colorado River near Grand Valley. The Garfield County commissioners

granted zoning approval for the development

of 7,000 housing units for up to 21,000 residents, to be constructed over a 10- to 15-year

period. Colony invested a little over $3 million

in land acquisition and related activities for

Battlement Mesa. The new town was designed to serve the Colony shale activities on

Parachute Creek; actual development of the

site was suspended when the company chose

not to move ahead with its plant. It is probable the new town will be constructed in the

1980’s.

RIFLE

Rifle is the community displaying the most

visible effects of shale development activities.

It is estimated to have grown by about 1,000

residents from the 1977 census figure of

2,244. Using the increase in the value of

building permits as an indicator, it has grown

about 45 percent in the past 2 years, A population of 10,000 has been used as the target

for planning purposes, and city officials feel

this number could be accommodated within

the next 3 to 5 years. Over 40 projects have

been identified as needed between 1979 and

1984 to ease the effects of this expected

growth. About half of these are for public facilities, mostly water supply projects and

public buildings. About 10 percent are for

roads, and another 10 percent for public

services, such as a new fire-rescue vehicle.

Educational expansion, including programs

and buildings, account for another 10 percent, with housing, health, and recreation

projects representing the remainder.

Rifle is beginning to display some symptoms of boomtown stress. The incidence of reported spouse and child abuse is increasing.

Statistics maintained by the police department show a rise both in the number of juvenile crimes and in cases of substance abuse;

alcohol abuse is the biggest problem. Mental

health personnel note an increase in the number of individuals having problems in their relations with other people. Consistent data colPhoto credit OTA staff

View of Rifle, Colo.
454 ● An Assessment of Oil Shale Technologies

lected over several years are not available in

these categories, but what has been obtained

points to the emergence of increasing social

and psychological stress.64

A large number of retired persons live in

the area, and more than 20 percent of the

population is estimated to be over 60 years

old. A number of programs have existed for

several years for these residents, and they

themselves are active advocates for their interests. Should the current rate of inflation

be compounded by increased costs from rapid growth those who live on fixed incomes

would suffer even more than they are now.

For some time, Rifle has had severe traffic

congestion. The main highway to the north

goes through the middle of town, passing the

elementary and high schools. Dust and exhaust fumes, particularly from trucks, have

polluted the downtown area. It has taken a

long time to correct the problem because of

the necessity to coordinate plans with the

State highway department. City services have

been hampered by a lack of adequate office

space. Rifle is in the first stage of a planned

three-stage water expansion project. The entire project will accommodate 10,000 residents, in increments of 3,000 to 3,500 per

stage. The sewer system is also currently

being upgraded.

Sufficient land is available for about 1,700

new housing units; construction has been

underway in recent years. The junior high

school building is being expanded and, on

completion of the addition, will become a

combined junior-senior high school, A new

elementary school is needed and the city has

applied to the State for assistance in its construction. The hospital needs to expand its

outpatient facilities. The nursing home is

operating almost to capacity, and will soon

require repairs and renovation.

OTHER GARFIELD COUNTY COMMUNITIES

Grand Valley reflects the types of difficulties faced by communities living with the

uncertainties of energy development. Several

years ago, in anticipation of growth from increased oil shale development, the school was

expanded. Because the expected growth did

not come to pass, the school is presently

operating below capacity; and the citizens,

while desiring it, view current promises of

development with some skepticism.65 Like Silt

and New Castle, Grand Valley has had to

place a moratorium on new building because

the water and sewer systems are operating

at, or beyond, capacity. The town applied for

an EPA construction grant for a new sewage

treatment facility in 1976 but did not know if

it would receive the funds until 1979. In the

interim, it tried to obtain money from the Colorado Department of Health, but was unsuccessful. Although the EPA grant, plus assistance from the Oil Shale Trust Fund, has now

been received, the site had not been approved

in mid-l979.

Silt is one of the fastest growing communities in the valley. The population doubled

between 1970 and 1977—from 434 to 859—

and the town planner believes it was close to

1,000 at the end of 1979.66 The CWACOG projections estimate 1,211 by the end of 1980

under energy development conditions (Scenario II). Current plans call for public facilities to accommodate 2,800 residents by the

mid-1980’s. These facilities include an improved water supply and an expanded sewer

system. The sewer system improvements are

currently in the design phase and the water

system is already being upgraded. Like many

small communities, the town lacks sufficient

skilled manpower. There is only one police officer and no budget for additional personnel.

Only two people are in the public works department, and they cannot keep up with the

increased workload.

In New Castle, ultimate growth probably

will be limited by the availability of land,

since the town is located in a fairly narrow

part of the Colorado River valley. The official

CWACOG energy development projections estimate a population of 1,055 in 1985 and

1,608 by 2000. The city is now improving its

water supply and distribution system to permit additional growth; a moratorium on new

water taps was necessary after a new elementary-junior high school facility was

opened. A revitalization of coal mining in the
Ch. 10–Socioeconomic Aspects ● 455

area could combine with oil shale development to add to growth pressures in the town.

Because Glenwood Springs, the county

seat, is located in the eastern part of Garfield

County, the community will experience more

secondary than direct effects. The city has

been growing mainly from recreational development in the Aspen and Vail areas. If the

communities down the Colorado River valley

are unable to cope with rapid growth, the

consequences will extend to the Glenwood

Springs area.

In sum, Garfield County has received most

of the growth so far from oil shale development. This growth has been combined with

the expansion of other industries and, as a

result, the county has been pressed to meet

the needs of the new populace. All the communities in the area have increased population, and three have had to place moratoriums on new construction because of inadequate water and sewer systems. Rifle should

be able to accommodate a population of

10,000 if current plans can be completed, but

is already beginning to experience some of

the symptoms of boomtown conditions. If accelerated growth occurs, Rifle will need additional funds in order to make public facilities

and services available to the new residents,

and will have to increase its efforts to prevent

social and individual stress.

Rio Blanco County

In anticipation of future growth, a significant planning effort has been underway for a

half-dozen years, zoning and other growthcontrol laws have been enacted, and support

for these measures appears widespread.

Roads have been a longstanding need but

their cost has proven a barrier to construction. Extension of County Road 24 from the

C-a tract site to Rangely was proposed by the

developers in their early plans (see figure 74);

however, the State legislature has been reluctant to appropriate funds for construction, A

feasibility study of 10 alternatives was made

and 1 was recommended to the State: planning for it is now underway, Timing is critical; if the C-a tract begins production and the

road is not available, permanent employees

will choose to live in Meeker or Rifle, both of

which are now closer. Without this access,

the opportunity to allocate some of the county’s growth to the Rangely area will be forfeited.

MEEKER

Meeker grew about 15 percent between

1970 and 1977; its estimated population in

1979 was 2,250 to 2,300.67 The community’s

physical infrastructure (e.g., water, sewer,

streets), when current improvements are

completed, could support between 4,000 and

5,000 residents; this figure may be reached in

1982 or 1983. However, the growth rate could

accelerate. For instance, the draft EIS for the

proposed Superior development, in projecting

cumulative growth for its own and seven

other energy projects,68 places Meeker’s population at 5,077 in the first year of operation,

a doubling of the present estimated population in one calendar year. Even this projection

could be low, since there are more than this

number of possible projects under consideration by different industries for the area.

Of the needs identified by local officials, 55

percent are for public facilities and services,

15 percent for the schools, 19 percent for recreational projects, 9 percent for day care and

senior citizens’ support, and 2 percent are for

hospital projects, Housing so far has kept up

with demand. In the immediate area, four

subdivisions are under construction, and a

mobile home park has been approved. Under

review, but not yet approved (in late 1979),

were another mobile home park and a number of smaller subdivisions, none of which is

presently within the Meeker water service

area. Furthermore, the town is presently

committed to the subdivisions now being built

for 100 percent of its available water taps.

Although the streets within the large subdivisions will be built by the developer, the town

must provide the main arteries to those

areas. The wastewater treatment plant is

committed almost to capacity, and planning

has started for its expansion.
456 ● An Assessment of Oil Shale Technologies

Figure 74.— Area of Proposed Road From Rangely to Oil Shale Tract C-a

SOURCE 1977 Ad Addendum to the RIO Blanco Oil Shale Project Social and Econmic Impact Statement.
Ch. 10–Socioeconomic Aspects ● 457

The construction of water and sewer facilities is an example of the kinds of projects requiring adequate leadtime. If Meeker fails to

begin preparing to expand its water supply

and sewage treatment capacity now, it will

not be able to absorb increased growth in 3 to

5 years. These kinds of improvements also

serve as examples of the financing difficulties

faced by rural towns. In constructing its present water system Meeker created a $2.4 million debt that requires an annual debt service

equivalent to 20 mills of the property tax levy.

Photo credit: OTA staff

Approximately $760,000 will be required to

expand the storage capacity of the water system and $2.5 million to upgrade the wastewater treatment plant. Thus, the city is facing a potential additional debt of over $3 million in the next 3 to 5 years.

Meeker also reflects some of the administrative difficulties faced by growing towns.

Colorado’s statute, which restricts spending

by municipalities (except home-rule cities) to

a 7-percent increase over the annual property tax revenues,69 means for Meeker that the

maximum the town can increase its spending

is about $3,000 per year. Recently, the annual

inflation rate has approached 16 percent,

which makes such a small increase essentially nil in real revenues. The statute does provide for some administrative relief with the

approval of the State DLA but an application

for an exemption filed by the city in 1976 was

turned down. A manpower shortage plagues

the city government. During the summer,

when demands for labor are highest, the

town has used inmates from the jail for assistance. According to the town manager, all of

the municipal government staff but two are

paid salaries lower than the HUD poverty

guidelines for rural Colorado.70

Overall the incidence of symptoms of social

stress has not been increasing at the rate

seen in other towns. A shift in the types of

crimes committed has been noted, with increases in thefts, bad checks, and drug-related incidents; and a rise in the number of

runaways has occurred in recent years. The

number of cases reported by the police has increased at a faster rate than the population

growth. ” The hospital outpatient services are

operating at capacity; an additional emergency room and laboratory are pressing needs.

The school district is operating below its total

capacity but some of the individual schools

are full. A new elementary school will be

needed between 1981 and 1982.

Attitudes about growth have been divided.

In a survey conducted in 1974, 35 percent of

the respondents agreed and 53 percent disagreed with a statement that the majority of

growth from resource development should occur in Meeker. The town manager said in

197 9

72 that he felt the community wishes

enough growth to pay the indebtedness incurred by construction of public facilities and

to provide new amenities such as a larger supermarket and expanded recreation facilities.

RANGELY

Rangely finds itself in the paradoxical position of desiring additional growth but foiled in

its efforts to obtain it. The biggest difficulty

has been gaining improved access to oil shale

activities. The proposed road to tract C-a was

discussed above. -

- ‘ - -

ences with oil and

town receptive to

the residents feel

Rangely’s earlier experigas booms have made the

energy development and

that growth from an ex-
458 ● An Assessment Oil Shale Technologies

panded oil shale industry would be beneficial.

In addition to the access road, a dozen projects are judged to be needed by 1985. Half of

these are for public facilities, such as a water

supply pipeline to areas of new home construction. With improvements, the water system could serve a population of about 11,000

and the sewer treatment facilities are adequate to serve 10,000 people if the sewer

mains can be upgraded. Because of the need

for these improvements, however, the capacity of the town between 1985 and 1990 is estimated at only 6,000 residents. 73 Like most

rural health care facilities, the Rangely

Hospital has had to defer some maintenance

and equipment needs in order to meet operating expenses but will have to take care of

them before services can be provided for a

larger clientele.

Recent school construction has provided

sufficient capacity to absorb more pupils, but

this again reflects Rangely’s paradox. If the

town is unable to attract more families, the

expansion of the schools will leave the buildings half-full and the remaining residents

burdened with the debt of the expansion. The

optimism of the citizens is reflected in their

willingness to approve construction of a new

indoor recreation facility that opened in the

late spring of 1979.

The Rangely area has a strong feeling of

identification with eastern Utah. The town is

located about 15 miles east of the border. It is

a little over 45 miles to Vernal, Utah, less

than the distance to Meeker (57 miles) and to

Grand Junction (85 miles). The road to Grand

Junction goes over Douglas Pass (8,628 ft),

making the route less appealing than the flatter highway to Utah. For these reasons, it is

easier for Rangely residents to travel to Vernal. Colorado officials have sometimes acted

in a way that the residents view as reinforcing their links with Utah; it took about 40

years to get the State to build the road over

Douglas Pass. If the region experiences rapid

Photo credit OTA staff

Recreational facility in Rangely, Colo.
Ch. 10–Socioeconomic Aspects • 459

growth from oil shale development, the feelings of being ignored could add to other negative impacts. Moreover, if the oil shale activities are in Utah but the workers live in Colorado, a prime example of the problems of jurisdictional mismatch will occur.

In sum, Rio Blanco is the least populated

county with the most limited highway system.

Planning is well advanced with provision for

extensive community participation. Some urgent needs, such as improved access to the

Federal oil shale tracts, have not been met

with as rapid a response as the local citizens

might have wished; the State legislature has

been reluctant to appropriate the large sums

necessary for these projects. Rangely desires

growth but will not receive much if a road to

tract C-a is not constructed; Meeker is less inclined to have more growth than it has already gotten from coal development, yet may

have to absorb new population from oil shale

activities.

Summary

The socioeconomic consequences

shale development depend, among

of oil

other

things, on the location of the activities. Increased development of the private lands

along the southern rim of the Piceance basin

will lead to growth in Garfield and Mesa

Counties and the communities of the Colorado

River valley. Additional activity on the Federal lands in Rio Blanco County will mostly affect Meeker and Rangely, although Rifle

could grow as well from this expansion. In

Moffat County, Craig could be influenced by

activities in the northern section and, if development occurs in Utah, Dinosaur and Rangely

would be directly affected. Growth will tend

to concentrate in established communities

where services are already available. The

limited surface transportation system will

also foster concentration. In Rio Blanco County it is encouraged by a zoning policy that is

intended to direct growth to Meeker and

Rangely.

The needs by county and community between 1980 and 1985 are summarized in table 102. The table shows clearly where the

local leaders see the greatest constraints on

growth: water supply systems for the municipalities, schools, and medical and health

services and facilities. Several towns indicate a need for more personnel. Rifle and

Meeker are the communities with the largest

number of priorities. Assuming that the projects now underway are completed, Rifle

should be able to absorb, between 1985 and

1990, up to 10,000 people, The other Garfield

County communities in the oil shale vicinity

could accommodate about 7,000 and the

rural areas between 1,500 and 2,000 persons. If construction were started immediately, the new town of Battlement Mesa might

house 2,500 people by 1985. In Mesa County,

De Beque might be able to accommodate a

total of 700 to 1,000 but most workers from

the southwestern part of the Piceance basin

will probably reside in the Grand Junction

area. In Rio Blanco County, both Meeker and

Rangely are judged to be capable of providing

for 6,000 persons apiece, ” A total of 2,000

people might live in the rural areas. Altogether, by 1985 Garfield County could accommodate about 21,000 and Rio Blanco about

14,000, for a total of 35,000 residents. (See

table 103, )

Other than the planning efforts o f

CWACOG, no systematic evaluation of the

full range of consequences for the entire region is being undertaken. For example, the

draft EIS for the proposed Superior Oil Co.

project 75 discusses, in the section on cumulative impacts, seven other activities that might

interact with the Superior development. However, a total of 30 energy-related projects are

identified by CWACOG and impact studies as

possibly affecting the region. Similarly, planning documents give attention to individual

counties or communities but do not address

areawide problems in detail. For instance,

the relationships and responsibilities of local,

State, and Federal government agencies are

critical for communities facing boomtown

conditions, but they are not dealt with in any

of the plans. Jurisdictional mismatches also

are seldom addressed. Development on pri-
460 ● An Assessment of Oil Shale Technologies

Table 102.–Priority Needs Identified by Oil Shale Counties and Communities, 1980-85’

Source of request

Regional ... ., . . .

Mesa Count y

De Bequ e

Garfield County .....

Grand Valle y

New Castl e

Rifl e

Sil t

Rio Blanco County

Meeker .

Rangely .

Me//at County .,

Dinosaur

● ● ●

●

● ●

●

●

● ● ●

● ● ●

● ● ●

● ● ●

● ● ●

●

● ●

●

●

●

●

●

● ●

● ●

●

● ● ● ●

●

● ●

● ● ●

● ● ●

● ●

● ●

● ●

● ●

● ● ● ●

● ●

● ● ● ●

● ● ● ● ●

● ●

● ● ●

●

‘See ref 62 for Iwhng of sources of needs

blnclude~ ~uppofl for plannlng Infrastructure dfld personnel needs of local a9encles

SOURCE Olflce of Technology Assessment

Table 103.–Actual and Projected Population and Estimated

Capacity of Oil Shale Communities in Colorado

Population

1977 1980 1985-90

Location a

census b projected capacity d

Garfield County

Rifl e 2,244 4,362 10,000

Sil t 859 1,211 2,800

New Castl e 543 831 1,000

Grand Valley 377 589 3,000

Battlement Mes a

e — 198 2,500

Other, – – 1,700

Subtotal f 

., ., 4,023 7,191 21,000

Rio Blanco County

Meeke r 1,848 2,779 6,000

Rangely : : 1,871 2,223 6,000

Other 1,381 1,542 2,000

Subtota l 5,100 6,544 14,000

Tota l 9,123 13.735 35,000

aDoe~ not Include Mesa or Moffal Coun!les both of wh[ch are more distant from the area of devel

opment

bActua[s from a special U S census

cEnd 01 (he year projecl(ons by [he Colorado wt’Sl Area COUIICIIOf Governments

dEs(lma!ed by OTA from various plannlng and needs asSeS5Menls documents assumes comPleIlon of cu{renlly planned projects (e g hous[ng water and sewer system expansions street

and road (mprovemenls elc ) eA new [own construc[jon anticipated 10 begin In fhe early IWO s

f(ncludes only the lmmedlate 011 shale ~lclnlty

SOURCE Olf(ce of Technology Assessment

vate oil shale holdings in Garfield County

could cause rapid growth in Mesa County,

and workers in Utah could reside in Colorado;

neither problem has been systematically analyzed.

Potential Effects of Accelerated

Development

The response of a given community to

growth depends on a number of elements.

Among these are:

●

●

●

●

●

the absolute numbers and abruptness of

the population influx;

the attitudes of both long-term residents

and newcomers;

past experiences with boom and bust

cycles;

the ability of local political structures to

prepare for population growth; and

the availability of assistance—financial

and other—for mitigation of impacts.
Ch. 10–Socioeconomic Aspects ● 461

Whether the consequences of growth are favorable or unfavorable depends on whether

the people can adapt to the stresses accompanying change. This ability is unique to each

community and must be viewed as part of a

dynamic set of complex events. Conclusions

about the possible effects of future oil shale

development must recognize the complex and

changing nature of the different communities

and of the events impinging on them.

Industrial expansion in western Colorado

will have positive as well as negative consequences, In the economic sphere, a primary

benefit will be increased economic activity.

The direct effects of increased employment,

higher wages, and stimulation of support industries and services would be felt throughout the region. Both the public and private

sectors would benefit from industrial and

services expansion. Towns and counties

should enjoy a broader tax base. A sense of

identity and pride, combined with an anticipation of the advantages of growth, have already been manifested. Planning activities,

such as the preparation of the master plan

for Rangely, have contributed to the public’s

expectations for the future. The successful

operation of the task forces that propose solutions for growth problems is tangible evidence of increased sociological and psychological cohesion. The confidence that many

local officials express in their community’s

ability to deal with growth is also an indication that, to date, the social consequences of

oil shale development have been positive. The

involvement of the oil shale developers in

growth management efforts shows industry’s

responsiveness to the social effects of its expansion.

Oil shale development has been and will

continue to take place concurrently with

other activities, especially energy-related

ones, such as coal, uranium, oil, and gas production. Dealing with the cumulative effects

of all the growth may prove difficult. In addition, the nature of new oil shale ventures is

unclear, Factors of particular importance for

social and economic adjustment will be the:

●

●

●

●

●

●

number—how many new oil shale developments occur;

size—how large the facilities will be;

location—where shale mining and processing activities take place;

timing—when each is built and how this

relates to other development;

rapidity—how quickly any new ventures

are built; and

type—the nature of the technology and

ancillary processes chosen.

The position of the State regarding both oil

shale development and social and economic

impact mitigation is also not certain. Until

more is known about these factors, the exact

nature of the population in-migration that will

accompany new development cannot be adequately projected, nor can the full dimensions

of the consequences, both positive and negative, be forecast. So long as oil shale development continues according to the plans

already laid, the people of oil shale country

should be able to adjust to the resulting

growth. Only if expansion occurs suddenly or

to a greater degree than now planned will

boomtown consequences occur. (See ch. 3 for

a further discussion.)
462 • An Assessment of Oil Shale Technologies

Issues

Summary of Issues

Identifying and Evaluating Social and

Economic Impacts

In the usual course of economic

and Policy Approaches

development, Government assistance in coping with

the consequences of growth is not a prime

concern. One question underlying energy development is the distinction between effects

that can be handled by local communities—

that is, those that can be considered a normal

concomitant of development; and those that

are problems because they cannot be readily

solved by local resources—boomtown effects.

An example of criteria used to make this

distinction is found in section 601 of the

Powerplant and Industrial Fuel Use Act of

1978. These include increased employment of

8 percent or more per year in coal or uranium

activities, a resulting or projected housing

shortage, and inadequate State and local financial resources to meet needs over a 3-year

period.

Thus far, Federal agencies have assisted in

the identification of boomtown conditions

mainly through data-gathering and information-sharing activities. With respect to evaluation, the position is that “local communities

and counties must take the initiative to become involved in assessing, planning for, and

mitigating socioeconomic impacts . . . .“76

The process of evaluating impacts involves

their classification as either positive or

negative. This requires making value judgments about what is good or bad for particular individuals, communities, regions, and the

Nation. Often there are conflicts—what is

seen as good for the Nation may entail difficulties for individuals or disruptions of communities. Additionally, what is judged as a

positive impact for one group may appear as

a negative one for a different group.

The process is further complicated because the basis for distinguishing positive

from negative impacts is seldom clearly delineated, and the assumptions underlying the

definitions of the two classes are rarely

spelled out. As an illustration, concepts such

as the “degradation of the quality of life” are

used; and a variety of indices, like an increase in the number of visits to a mental

health clinic, are cited to support the finding

of “degradation.” Yet there is hardly ever

verification of the causal chain presumably

linking rapid population influx to the indices

and thence to perceived changes in the quality of life.

Finally, several of the most important

boomtown consequences are hard to measure

(for example, the ability of newcomers to adjust to an established community); and the

changes in the social structure may not be

manifested immediately. A question that has

not received great attention is whether the

long-term basic changes are more important

than the immediate ones occurring at the

onset of a boom.

The debates about oil shale development

include conflicts involving these kinds of

value judgments. On the one hand is the need

for synthetic fuel production; on the other are

the boomtown consequences for communities.

Who participates in the definition of positive

and negative impacts and in the resolution of

the value conflicts that emerge is an important issue. At present, in Colorado, local

groups play a large part in this evaluation.

They identify the impacts they believe will affect their communities, decide which ones are

severe enough to require corrective action,

and participate in the decisions to allocate

resources for mitigation. Federal programs

designed to assist communities must recognize what has been done to date and face the

issue of the allocation of responsibility for

these decisions.

Determining a Maximum Growth Rate

How rapidly can the communities expand?

How much growth can be accommodated before a community breaks down? The social

and economic impacts of oil shale develop-
Ch. 10–Socioeconomic Aspects ● 463

ment will depend on the total number of newcomers, the rapidity with which they come

into the area, the size of the industry’s expansion, its location within the oil shale region,

and the ability of the communities to prepare.

The maximum amount of growth the different

areas can accommodate without incurring

boomtown consequences is a critical question.

Attempts to determine a maximum rat e

have discovered that generalizations are difficult to derive and that the capability to adjust to rapid growth turns out to be highly site

specific. Whether communities will suffer

from rapid growth or take it in stride depends

on a unique set of factors within each individual community, for example, the threshold

when negative impacts outweigh positive

ones. Since the positive and negative impacts

may vary from one town to the next, establishing this threshold is highly dependent on

local conditions. In the past decade, identifying and measuring the social changes that accompany rural energy development have received increasing attention. The results have

been an expansion of the factual base describing these changes, and a more systematic framework for seeking to explain them.

To date, however, there are neither sufficient

facts nor theories to understand fully why

one town becomes vulnerable to boomtown

impacts but a similar one does not.

No systematic study of the factors determining a maximum growth rate is being carried out for the oil shale communities. The

groups presently involved in growth management and planning would benefit from a determination of thresholds of growth for their

individual communities and policy makers

could use this information when considering

the rate of future development. The population of the Colorado oil shale region was

about 10,000 in 1977 and is projected to be

about 14,000 by the end of 1980. OTA estimates that the communities could accommodate up to 35,000 total residents during the

period from 1985 to 1990. This assumes that

construction of the new town of Battlement

Mesa in Garfield County is started in the near

growth.

The Mitigation of Impacts

Solving the problems

volves local, regional, State, and Federal

agencies. Questions about the role of the

Federal Government fall into two categories:

● the extent to which the Federal Government should be involved, and

● the form the involvement might take.

The first category raises the fundamental

question of whether the Federal Government

should be involved at all. The extent and

nature of Federal involvement in impact mitigation are controversial. On the one hand it is

argued that social and economic impacts are

State and local problems which should be

viewed as the inevitable consequences of industrial development. On the other hand is

the position that national requirements are

the root causes of the local impacts, therefore

an expanded Federal role is appropriate. Several Western States have taken the stance

that expanded domestic energy production is

a national goal and thus, for reasons of equity, the Federal Government should assume a

more direct role in the alleviation of negative

impacts from this development.

The second category deals with the nature

of Federal involvement. One position states

that present programs are sufficient but that

the amount of money they provide needs to be

increased. Another is that Federal regulation

could be used to mitigate impacts by, for example, pacing industry’s growth rate through

leasing policies. A third position is that the

Government should be directly involved in

mitigation programs that use Federal funds.

The question of the effectiveness of mitigation programs arises as well. Some observers

contend that the success of oil shale mitigation processes to date is proof of their effec-
464 ● An Assessment of Oil Shale Technologies

tiveness. Others maintain that the processes

have never been adequately tested because

rapid, large-scale development has not yet occurred, and that existing programs could

break down under such circumstances. Most

questions about the effectiveness of the processes relate to intrastate issues. For example,

it can be questioned whether the legislative

approach to disbursement of the Oil Shale

Trust Fund deals adequately with the desires

of the oil shale counties. The Federal Government could respond to such questions by, for

example, providing funds directly to the communities. The desirability of such an action is

a topic of current debate, however.

Increased Federal assistance probably will

be required if the region experiences sustained rapid growth. This could come about

from accelerated oil shale development, but

is more likely to be the consequence of combined growth from several industries. Aside

from the planning efforts of CWACOG, which

are limited to northwestern Colorado, no systematic evaluation of the full range of effects

from an increase in all types of industrial

growth on the entire region is being undertaken. Thus, it is difficult to determine which

types of Federal assistance might be the most

productive.

Policy Approaches

Confronting the social and economic effects of an expanding domestic energy industry involves policies for all parts of the Nation. Concern for the consequences of oil

shale development, however, for the time

being centers only on northwestern Colorado,

east-central Utah, and southwestern Wyoming. In addition, although the impacts themselves are basically similar regardless of the

geographic region, the responses of particular communities can differ significantly depending on the State and location involved.

Flexible policies are best, given this situation.

The following discussion is concerned with

policies that bear most directly on the effects

of a larger oil shale industry.

Background

The initial action responsible for consideration, in public policy decisions, of the socioeconomic effects of Federal projects was

the National Environmental Policy Act of

1969 (NEPA).77 It requires Federal agencies to

consider environmental factors in decisions

involving “major Federal actions significantly

affecting the quality of the human environment. “

78 The broad wording of the Act has led

to a considerable amount of litigation. In

these court cases, 79 NEPA has been interpreted as granting authority for the imposition of conditions to mitigate adverse social

as well as environmental impacts. As a result

of the litigation, and subsequent regulations

issued under NEPA, socioeconomic considerations have of late received greater emphasis in the preparation of EISs.

The Coastal Zone Management Ac t

Amendments of 197680 set up a program of

assistance for communities experiencing impacts from Outer Continental Shelf (OCS)

energy development. Loans, loan guarantees,

and grants are available to States and communities where an energy facility planning

process has been established under the

Coastal Zone Management Act of 19728 1

(CZMA). Site plans must include the identification and mitigation of anticipated adverse

impacts from OCS-related development. The

program is tied closely to land use planning

mechanisms that State and local governments

are required to develop if they participate in

the coastal zone management program. The

impact assistance portion depends upon the

initiative of the States in meeting the CZMA

requirements; Federal involvement is therefore indirect, in the sense that the policy

makes Federal funding contingent upon the

establishment of State and local land use

planning processes.

In March 1978, DOE published for the Energy Impact Assistance Steering Group a Report to the President—Energy Impact Assistance.

82 The Steering Group, composed of representatives from Federal, State, local, and
Ch. 10–Socioeconomic Aspects ● 465

Indian Tribal governments, was established

following a meeting of several Governors with

the president in mid-1977. At that time the

Governors expressed concern for potential

adverse results from the 1977 National Energy Plan. Four policy options were presented

representing “different points along a continuum ranging from minimal new efforts to

undertaking major program reform and investment of substantial new Federal funds, ]

(See table 104.)

In an effort to pull together the various

Federal programs that can assist communities, the Region VIII FRC has created an

Energy Impact Office. Its establishment was

a direct response to recommendations of the

National Governors Conference and of the

General Accounting Office (GAO) .8’ A GAO

report, published in 1977, concluded that at

that time the need for additional Federal assistance to impacted communities had not

been demonstrated, Among its conclusions,

the report stated:

Rocky Mountain State and local governments should be primarily responsible for

providing facilities and services prior to or

concurrent with population increases , . .

It is not industry’s responsibility to provide the facilities and services needed because of energy resource development. But

industry does have a strong and continuing

responsibility to communicate its plans to

State and local governments, as soon as possible, and to establish and maintain a continuing liaison with these governments,

The Federal Government should continue

to provide some assistance ., . (but) the need

for additional Federal assistance at this time

has not been demonstrated.

GAO believes there should be some assurances that impacted communities will receive funds available to mitigate the socioeconomic impacts of energy resource development.85

A theme running through each of these

Federal policy documents is that the Federal

role regarding the social and economic effects of energy development should be primarily indirect assistance. Examples are providing funds to the States and improving the

delivery of existing Federal programs (e.g.,

the establishment of a “one-stop shopping

center” where local officials can go to determine whether their towns are eligible for the

many Federal programs already available).

A recent departure from this theme is

found in the Energy Impacted Area Development Assistance Program that was enacted

in the Powerplant and Industrial Fuel Use Act

of 1978 (sec. 601).86 This program, administered by FmHA, is designed “to help areas

impacted by coal or uranium development activities by providing assistance for the development of growth management and housing

plans and in developing and acquiring sites

for housing and public facilities and services. ” The probability of greater Federal involvement in the direct amelioration of impacts is reflected in the amendments to the

Powerplant and Industrial Fuel Use Act considered during the fall of 1979. A review of

the problems, legislative issues, and proposals being considered by the 96th Congress is

available in a Congressional Research Service (CRS) study titled Energy Impact Assistance: A Background Report prepared for the

Senate Committee on Energy and Natural Resources.

87

In general, the Western States have

adopted policies that supplement and fill gaps

in Federal programs. Colorado provides

funds, from Federal revenues and a State severence tax, and technical assistance to counties and towns with growth problems. The

State’s position is that local initiative must be

central in the mitigation process. As a result,

sentiments are strong among leaders in Colorado’s oil shale communities that local government should play a significant part in the

control and management of growth. 88 For a

number of years, because of the delays in oil

shale development, these leaders were skeptical about its eventual occurrence; now they

are fearful that a national crash program

might ignore the plans that they have so carefully laid and cause a population surge that

the communities could not absorb. Utah has
466 ● An Assessment of Oil Shale Technologies

Table 104.–Selected Policy Options, 1978 Report to the President

Option A Option B Option C Option O

Modification and expansion of

Expansion of industry role and Enhancement of State, local, and existing programs to assure

modification/reprioritization of Tribal capabilities through new greater Federal share of New Federal grant program

Need areas existing programs initiatives and programs long-term costs to pay long-term costs

Information

Participation in

decision making

Planning and

management

Coordination of

assistance programs

Financing

implementation or national energy

information systems by DOE

with State/local/Tribal access

to certain NEIS data

Encourage States to require in-mindustry release of employment,

population, and siting data for

proposed projects as precondition for receipt of certain State/

local permits (water, construction, etc )

Opation A, plus nave appropriate

Federal agencies give prior notification to State/localities, and

Tribes of BLM, OCS Ieasing

plans, decisions and other data

related to industry projects proposed to Federal agencies, improve conformance with NEPA

and A-95 review processes

. . , . , ,. A . , , . -

Option B, plus establishment Option C

by DOE of a new information

system to gather and disseminate impact assistance

related data from energy developers ($1 5 million).

Continued ad hoc efforts by

State/ local governments and

Tribes to impact Federal decision processes on energy resource development and project

siting.

Conduct joint Federal/State/local/Tribal impact assessments

Provide Federal technical assistance and information to commu -

mties which are now, or expected to experience energy development

Increase funding under selected

existing planning program by

$20 million and target to energy

impact areas

Expand the role of the Federal

Regional Councils in coordinating and packaging assistance

funds to energy-impacted areas,

make greater use of joint funding authority.

Modify requirements of selected

existing programs to provide for

eligibility and priority for funds

to impact areas (within existing

statutory Iimits)

Increase funding of selected programs by $30 million to offset

reduction in funds for other pri -

ority needs (e g , urban poverty)

Give priority to States, etc ,

securing industry cost-sharing

Possible amendment to Federal

tax code to encourage prepayment of taxes by Industry

Issue Presidential Executive order

requiring Federal agencies to

provide for State/local/Tribal involvement m all energy development decisions affecting their

jurisdictions, and to provide for

consideration of the findings of

the impact assessment teams

prior to final decisions.

Option A, except Incorporate new

planning monies into proposed

comprehensive State energy

planning and management bill,

and specifically target new

funds to support State/local/

Tribal participation on assessment teams and ongoing impact-related capabilities. A setaside of funds for Tribes would

be provided. Also, bonus funds

for States with energy facility -

siting mechanisms.

Option A, plus designate DOE as

lead agency to oversee and support coordination of programs at

the regional level through an ininteragency board

Establish Federal loan and loanguarantee programs in EDA with

forgiveness provisions and competitive interest rates to be used

by States, communities, and lndian Tribes ($75 million)

Fund sec. 306 of the proposed

Coal Conversion Act ($60 million)

Give priority to States, etc , with

energy facility-siting mechanisms

Annual $50 million $160 million

authorization

SOURCE Department of Energy DOE /lR-0009, UC 13.

Option B, plus establishment

of due process mechanism to

review appeals of Governors/Tribal officials.

Option B, plus require all

Federal energy decisions to

be compatible with approved

State impact mitigation

strategies

Option B, plus issue ExecuWe order mandating appropriate Federal agencies to

support FRC efforts and to

give priority consideration to

funding requests channeled

through this mechanism

Option B, plus increase EDA

funds by additional $50 million and authorize grants as

well as loan/guarantees.

($125 million plus$60 million for 306). Priority to

States, etc , with Increased

commitment of State/local/

Tribal revenues and facility

siting procedures.

Suboption

Consolidate Coastal Energy

Impact Program and sec.

306 program into EDA to

create single, flexible program to relet Infrastructure

needs m all States

Option C

Option B

● Establish Federal/State

assessment teams as

specified.

● Federal assistance to

State to develop facility -

siting mechanisms and to

provide intial and second-round planning

grants ($1 5 million).

Ž Federal compatibility requirement

The Federal agency designated as the lead assessment agency would be responsible for coordinating

all relevant Federal programs,

Establish a new program to

provide grants to the

States for.

–State revolving funds

($200 million)

–Highways construction

and railroad grade separations.

–Mismatches ($10 million)

(Interstate and State/

Tribal)

–Loan guarantees ($15

million).

Fund housing support in

sec. 306 but expand and

augment to cover energy

facility construction and 011

shale development ($60

million).

$212 million $300 million
Ch. 10–Socioeconomic Aspects . 467

been faced with rapid growth from coal and

uranium development, and has not planned

extensively for oil shale activities. The State

created a Community Impact Account in 1977

to provide loans and grants to areas impacted

by mineral resource development. Because it

is the only funding source in the State designed to respond to problems associated

with energy development, requests for help

have far outstripped the available monies.

Wyoming does not anticipate consequences

from shale development in the near future,

The State has an array of mitigation programs dealing with other energy industry impacts that could be adapted to growth problems from accelerated oil shale activities.

Evaluation of Existing Policies

The diverse nature of present policies, Federal and State, makes their overall evaluation

difficult. State policies vary: Colorado places

emphasis on local initiative and advocacy,

whereas Utah and Wyoming emphasize more

centralized State determination of needs and

allocation of funds. At the present time, there

is no single Federal policy with respect to the

social and economic effects of energy production. Some programs are operating that address certain aspects of these effects but, at

present, none speaks directly to the general

impacts that may come with synthetic fuel development nor to the specific effects of accelerated shale oil production. A limited amount

of assistance is available through avenues

not specifically designed to deal with energy

development impacts, but these Federal programs each have different emphases and

modes of providing help. While they may be

adequately fulfilling their policy mandates,

the specific nature of the mandates means

that the entire range of problems is not being

addressed. Additionally, even though steps

have been taken to consolidate the fragmented nature of Federal programs, effective

implementation of a more uniform set of practices has yet to reach the oil shale communities.

An increasing recognition of the problems

caused by national energy decisions has led

to several reviews of existing policies and to

suggestions of ways to achieve a more unified

policy. Congress has had before it proposals

for a comprehensive inland energy impact assistance program, but to date none has been

enacted. Up to the present, return to the

States of portions of the lease, rental, and

bonus payments for development on Federal

lands has been the major Federal contribution to mitigation efforts.

Colorado has an ambitious set of policies

and programs to assist with impact mitigation. Overall, these efforts have been successful in helping the oil shale counties and

municipalities to get ready for shale development. The ability of existing policies to deal

with a large or sudden population influx,

such as might occur with the rapid expansion

of the oil shale industry, is as yet untested.

The uncertainties about the specific growth

of the industry make it difficult to evaluate

whether any policies—Federal or State—will

be adequate to deal with the effects of rapid

expansion of the industry.

Approaches to Impact Mitigation

There are three approaches available to

Congress when considering the social and

economic effects of oil shale development.

The impacts can be viewed:

● as part of the consequences of all kinds

of energy development;

Ž as an aspect of specific energy initiatives; or

• as the result only of shale development.

From the perspective of the first approach,

oil shale impacts would be included along

with the problems accompanying all domestic

energy efforts. As noted above, Congress has

recently considered bills providing comprehensive assistance for these problems, and

programs for oil shale could be in such legislation. The second approach would place

shale impacts along with those from other

major national efforts. Proposed amendments

to the Powerplant and Industrial Fuel Use Act

of 1978 are illustrative. These amendments

are directed to the adverse effects of major
468 ● An Assessment of Oil Shale Technologies

energy developments, which could include oil

shale. They authorize grants, loans, loa n

guarantees, and payments of interest o n

loans, and propose an expediting process for

present Federal programs as well as an interagency council to coordinate Federal assistance. The third approach sees the effects a s

the result of oil shale development alone. In

this case, specific language dealing with socioeconomic impacts could be included in

bills providing for the development of o i l

shale resources.

Regardless of the approach adopted for oil

shale, there are three options that Congress

can consider to address social and economic

impacts.

CONTINUATION OF PRESENT PROGRAMS

Under this option, Federal assistance

would continue to emphasize revenue sharing

and technical assistance. Funding through

existing channels, such as the Mineral Leasing Act, as amended, would be the majo r

mechanism. Certain other existing Federal

programs, not now designed to deal specifically with socioeconomic impact mitigation,

could be redirected. For instance, EPA water

and sewer grants could be accelerated, with

additional appropriations made available

and limited to impacted communities. Restrictions on existing programs could be modified.

An example is Federal housing programs,

now restricted to projects for low- a n d

moderate-income families, that could be provided to rural communities undergoing rapid

growth regardless of local income levels.

The advantages of this option are that it

would require only minor adjustments to existing laws. Mechanisms for delivery a r e

already in place. Flexibility would be maintained since the focus would be on already

established programs designed to meet a variety of needs. The disadvantages include the

possibility that the amount of aid might not be

adequate to meet the demands of severely impacted communities. In this case, appropriations would have to be increased for some

programs now being held at particular funding levels. The fragmentation of programs,

now viewed by some States and localities as a

barrier to efficient delivery of Federal aid,

probably would not be reduced.

INCREASED FEDERAL INVOLVEMENT IN

GROWTH MANAGEMENT

This option would emphasize regulation.

Present Federal revenue sharing would continue. Several possibilities exist for increased

growth management participation. consideration of social and economic effects on adjacent communities could be made a part of

executive agency criteria when selecting

Federal lands for energy mineral leasing. In

this case, given natural resource deposits of

approximately equal value, leases would be

made available only in areas where the socioeconomic impacts could be minimized. Also,

the number and timing of leases could be adjusted to take into account the ability of nearby communities to absorb growth. Finally, the

lease provisions could include mandatory

participation of lessees in mitigation efforts.

Greater involvement of Federal agencies in

monitoring socioeconomic impacts and in providing assistance to mitigation efforts is

another alternative. For example, the regulatory activities of the Area Oil Shale Supervisor’s Office could be expanded to include

monitoring social and economic indices in offtract communities. Attention could be given

to difficulties not now being systematically

faced, such as interstate jurisdictional problems between Utah and Colorado. The Region

VIII Energy Impact Office could have a field

representative permanently stationed in oil

shale country to provide the services of FRC

locally. This representative could provide

technical assistance to area planners and

could address problems they are too busy to

consider now, such as anticipating the postboom period. Increased technical assistance

could also address the problems of defining

and identifying boomtown conditions. A determination of the maximum growth communities could sustain without experiencing

severe disruption would be valuable for policymakers at all levels.
Ch. 10–Socioeconomic Aspects • 469

Identifying and evaluating social and economic impacts, determining a maximum

growth rate for specific sites, and coordinating Federal programs are needed in all

parts of the country experiencing energy -

related growth, Thus, actions to deal with

these problems would be of nationwide value,

For this reason, R&D could be undertaken by

any of several agencies on a national basis,

and would not necessarily have to be limited

to the oil shale region.

Among the advantages of this option is that

it would supplement existing mitigation programs already established by local and regional entities. It would provide a link between Federal decisionmaking bodies and

State and local agencies responsible for

growth management. Access to Federal programs would be enhanced. Among the disadvantages are the increased bureaucrac y

needed to implement the option, and the possibility that local individuals would perceive

the Federal efforts as increased infringement

on their lives. Energy development companies

would most likely object to additional lease

restrictions and to required participation in

mitigation programs. Executive agencie s

might find implementation burdensome.

EXPANSION OF FEDERAL PROGRAMS FOR

IMPACT MITIGATION

Under this option, programs alread y

enacted would be expanded or new one s

adopted. The Powerplant and Industrial Fuel

Use Act of 1978, section 601 program, is the

obvious candidate for extension. Under this

Act,

89 Federal assistance was provided for

areas experiencing rapid growth from coal or

uranium production. The assistance is aimed

at improved planning for growth management, and for land acquisition for housing

and public facilities development. Expansion

of the program would include areas affected

by growth from industries other than coal

and uranium producers, and could encompass a wider range of problems than growth

management planning and land acquisition.

A bill to expand the section 601 programs is

currently under consideration. *

The advantages of this option are that it

expands an already existing program. The

mechanisms for implementation are in place

and have already been operating under the

present law, Disadvantages include the need

for increased appropriations to fund the various elements of the program and expansion of

the Federal bureaucracy to carry out the

Act’s provisions. Some flexibility may be lost

as uniform standards are applied to all States

wishing to participate in the expanded program.

*S. 1699.
—- —.

470 ● An Assessment of Oil Shale Technologies

Chapter 10 References

1

For a discussion of current controversies

about the early inhabitation of the North American continent, see Graham Chedd, “On the Trail

of the First Americans, ” Science 80, vol. 1, No. 3,

March/April 1980, pp. 44-51. For general information, see Handbook of North American Indians

(Washington, D. C.: The Smithsonian Institution,

1979).

2Angelico Chavez (tr.), Ted J. Warner (cd.), The

Dominguez-Escalante Journal: Their Expedition

Through Colorado, Utah, Arizona and New Mexico

in 1776 (Provo, Utah: Brigham Young University

Press, 1976).

This was Powell’s second expedition to the

Rockies. It followed a trail pioneered by Berthoud

in 1861; Jim Bridger served as guide. Powell’s

wife accompanied the group and was the only

woman to spend the winter. Powell made a trip in

November, which he nearly didn’t complete, to get

supplies at Green River City, Wyo, Powell’s Park,

a few miles west of Meeker, Colo., was the site of

the “Meeker Massacre” in 1879, Here, a group of

Ute Indians shot and killed Nathan Meeker and

several other workers at the Indian Agency. See

Robert Emmitt, The Last War Trail: The Utes and

the Settlement of Colorado (Norman, Okla.: Univ.

of Oklahoma Press, 1954) and Marshall Sprague,

Massacre: The Tragedy at White River (Boston,

Mass.: Little, Brown & Co., 1957).

4

The Ute Indians signed four treaties with the

United States: in 1840, 1863, 1868, and 1880, See

Gerald T. Hart, Leroy R. Hafen, Anne M. Smith,

and the Indian Claims Commission, Ute Indians II

(New York, N. Y.: Garland Publishing, Inc., 1974)

and George E. Fay, Land Cessions in Utah and Colorado by the Ute Indians, 1861-1899 (Greeley,

Colo.: Univ. of Northern Colorado, Museum of Anthropology, Misc. Series No. 13, 1970). See also

Emmitt, Supra No. 3.

5Range wars erupted in the latter part of the

19th and early decades of the 20th centuries

when sheep and cattle raisers fought over the use

of the rangelands. See James H. Baker and LeRoy

R. Ha fen (eds.), History of Colorado (Denver, Colo.:

Linderman Press, 1927).

6

In 1901, Roosevelt spent 5 weeks hunting

mountain lion near Meeker; the party killed 14, of

which the largest weighed over 220 lb and was

over 8 ft long. In 1905, he returned for a bear hunt

in the area south of New Castle.

7Bureau of the Census, County and City Data

Book, 1977 (Washington, D, C.: Government Printing Office, 1978). See also Colorado Department

of Agriculture, Agricultural Land Conversion in

Colorado (Denver, Colo.: Resource Analysis Section, 1979).

‘Bureau of the Census, Congressional District

Data Book, 93d Cong. (Washington, D. C.: Government Printing Office, 1973).

‘

) Frank G. Cooley, “The Growing Awareness of

Oil Shale’s Impact on Communities in Western

Colorado, ” Rocky Mountain Association of Geologists—1974 Guidebook to the Energy Resources of

the Piceance Creek Basin, Colorado, 171-3.

‘[’Altogether, more than 20 studies were published between 1970 and 1977 dealing with one or

another aspects of oil shale development. See,

e.g., Oil Shale Regional Planning Commission and

the Colorado West Area Council of Governments,

Profile of Development of an Oil Shale Industry in

Colorado (Rifle, Colo.: CWACOG, 1973), and Colorado West Area Council of Governments, Oil

Shale and the Future of a Region: A Summary Report (Rifle, Colo.: CWACOG, 1974).

11Alys Novak, “Oil Shale—1976/1977, ” Shale

Country, vol. 2, No. 12, December 1976, pp. 2-6.

12Rio Blanco Oil Shale Project, Social and Economic Impact Statement—Tract C-a (Gulf Oil

Corp. - Standard Oil Co. (Indiana), March 1976);

an Addendum was published in May 1977.

‘

] C-b Oil Shale Project, Oil Shale Tract C-b

Socio-Economic Assessment, 2 vols. (Ashland Oil,

Inc. - Shell Oil Co,: March 1976).

14Colony Development Operation, An Environmental Impact Analysis for a Shale Oil Complex at

Parachute Creek, Colorado (Denver, Colo.: 1974).

15Jonijane Paxton, “Whither Now, Battlement

Mesa?” Shale Country, vol. 2, No. 6, June 1976,

p.15,

1 6Western Environmental Associates, Inc.,

Baseline Description of Socio-Economic Conditions

in the Uinta Basin and Socio-Economic Impact

Study of Oil Shale Development in the Uinta Basin

(Denver, Colo.: White River Oil Shale Corp., 1975).

17The five studies are:

a.

b.

Department of the Interior, Final Environmental Statement for the Prototype Oil

Shale Leasing Program, 6 vols. (Washington, D. C.: Government Printing Office,

1973),

Rio Blanco Oil Shale Project, Social and

Economic Impact Statement—Tract C-a

(Gulf Oil Corp. - Standard Oil Co. (Indiana),

March 1976), including 1977 Addendum,
Ch. 10–Socioeconomic Aspects ● 471

c.

d.

e.

C-b Oil Shale Project, Oil Shale Tract C-b

Socio-Economic Assessment, 2 vols. (Ashland Oil, Inc. - Shell Oil Co., March 1976).

Department of the Interior, Final Environmental Impact Statement: Proposed Development of Oil Shale Resources by the Colony

Development Operation in Colorado, 2 vols,

(Washington, D. C.: Government Printing Office, 1975).

Western Environmental Associates, Inc.,

Baseline Description of Socio-Economic Conditions in the Uinta Basin and Socio-Economic Impact Study of Oil Shale Development in

the Uinta Basin (Denver, Colo.: White River

Oil Shale Corp., 1975).

18Rio Blanco County Ordinances, sec. 1003;

1974.

19See Steve H. Murdock and F. Harry Leistritz,

Energy Development in the Western United

States—Impact on Rural Areas (New York, N. Y.:

Praeger Publishers, 1979).

20It is difficult to place a dollar value on the contributions of industry, In Wyoming, the Missouri

Basin Power Cooperative (a consortium of REA

electric cooperatives) estimates that it spent $21

million in mitigation efforts in conjunction with

the construction of the 1,500-MW Laramie River

Station in Platte County. This included in-kind

services; direct grants and revenue guarantees to

towns, counties, and agencies; bond guarantees;

and similar assistance. The cooperative believes

it saved approximately $50 million in costs by reducing employee turnover and by allowing the

plant to be constructed on schedule. Furthermore,

they anticipate recovering all but about $3 million

of the $21 million outlay as the bonds are paid and

other revenues become available. Eventually the

amount spent for mitigation probably will fall between one-half and 1 percent of the total cost of

the plant. (Personal communication from Dr.

James Thompson to OTA, Nov. 5, 1979.)

21CO1. Gen’1 Ass’y, H.B. 1200 (1974, 2d sess.).

2241 Stat. 437 (1920), as amended and supplemented, 30 U. S. C., sec. 181 et seq. (1976),

23C.R.S. 1973,34-63-104.

24C.R.S. 1973, 34-63-104 (l).

25C.R.S. 1973.34-63-104 (2).

26C.R.S. 1973, 34-63-101 and 102, as amended.

27C.R.S. 1973, 34-63-102 and 39-29-110.

28C.R.S. 1973, 39-29-101 through 114 (Supp.

1977).

29Personal communication, Stan L. Albrecht to

OTA, Oct. 16, 1979.

30U.C.A. 1953, 63-51-1 through 4.

31U.C.A. 1953, 53-7-1 and 2; 65-1-64 and 65; and

65-1-115.

32U.C.A. 1953, 73-10-8 and 73-10-23.

33W.S. 35-12-101 through 121,

34W.S. 9-1-129 through 136.

35W.S. 39-6-412.

36Personal communication, Dr. James Thompson

to OTA, Oct. 16, 1979. An example of an imaginative program is the Wyoming Human Services

Project (WHSP). The WHSP program trained human service personnel at the University of Wyoming campus and then placed the students in

Wyoming boomtowns for field experience. After

completing the program, many students found

jobs in the communities and stayed to continue

their service. See Judith A, Davenport and Joseph

Davenport, III, Boom Towns and Human Services

(Laramie, Wyo.: Univ. of Wyoming, 1979).

37Personal communication, Dr. James Thompson

to OTA, Oct. 16, 1979. See also Stan L. Albrecht,

“Socio-Cultural Factors, “ in Mohan K. Wali (cd.),

Mining Ecology.

“Department of Energy, Report to the President—Energy Impact Assistance (Washington,

D. C.: DOE/IR-0009, UC-13; March 1978).

39Supra No. 19. Under Public Law 95-238, D OE

has awarded grants to Colorado and Utah for socioeconomic planning. Also, grants have been

given to Rio Blanco and Garfield Counties and the

the Northern Ute Indian Tribe.

40Supra No, 22.

4190 Stat. 1083

201 et seq. (1976).

4290 Stat. 2743

(1976).

43Supra No. 41.

1976), amending 30 U.S.C. sec.

(1976), 43 U.S.C. § 1701-1782

44For a number of reasons, the loan program authorized by FLPMA has yet to be implemented.

4592 Stat. 3323 (1978).

46Ibid.

‘department of Energy, Regional Profile—Energy Impacted Communities—Region VIII (Denver,

Colo.: TIC-1OOO1, UC-13; 1979).

48Federal Energy Administration, A Report—

Regional Profile—Energy Impacted Communities

(Denver, Colo.: Region VIII Socioeconomic Program Data Collection Office, July 1977) pp. 5-6.

49For a complete discussion of alternatives, see

Economic Impact of the Oil Shale Industry in

Western Colorado, hearing before the Subcommittee on Public Lands of the Committee on Interior and Insular Affairs, U.S. Senate, 93d Cong., 2d

sess., Jan. 19, 1974; Inland Energy Development

Impact Assistance Act of 1977 (S. 1493), hearings
472 Ž An Assessment of Oil Shale Technologies

before the Subcommittee on Regional and Community Development of the Committee on Environment and Public Works, U.S. Senate, 95th Cong.,

1st sess., August 1977 (ser, No. 95-H28); and Energy Impact Assistance Act of 1978 (S. 1493), hearing before the Subcommittee on Energy, Nuclear

Proliferation, and Federal Services of the Committee on Governmental Affairs, U.S. Senate, 95th

Cong., 2d sess., Aug. 18, 1978.

50C.R.S. 1973, 29-1-301 and 302.

51For an introduction to the boomtown literature, see Charles F. and Jane Archer Cortese,

“The Social Effects of Energy Boomtowns in the

West: A Partially Annotated Bibliography, ” Council of Planning Librarians Exchange Bibliography

No. 1557 (Monticello, Ill. ) June 1978; and P. B.

Allison, “A Bibliography of Bibliographies Connecting Energy and the Social Sciences, ” Social

Science Energy Review, vol. 1, No. 2 (New Haven,

Corm.: Yale University Institution for Social and

Policy Studies), spring 1978,61-70.

52John S. Gilmore and Mary K. Duff, Boom Town

Growth Management: A Case Study of Rock

Springs—Green River, Wyoming (Boulder, Colo.:

Westview Press, 1975).

53Ibid., passim.

54Adapted from Ross M. Bolt, Dan Luna, and

Lynda A. Watkins, “Boom Town Financing

Study, ” in Financial Impacts of Energy Development in Colorado—Analysis and Recommendations (Denver, Colo.: DLA, 1977), pp. 11-12.

55Study of these changes necessitates the combination of theory and data from several disciplines: sociology, psychology, anthropology, economics, and political science. Such a combination

is difficult to accomplish given the differences between the disciplines. In addition, applied science

of this kind is often viewed with a measure of disdain by some professionals within each field.

‘

()’’ The Social Impacts of Energy Development in

the West: A Symposium, ” The Social Science Journal, vol. 16, No. 2, April 1979.

“Charles F. Cortese and Bernie Jones, “The Sociological Analysis of Boom Towns, ” Western Sociological Review, vol. 8, No. 1, 1977, pp. 76-90.

58Ronald L. Little, “Some Social Consequences

of Boom Towns, ” North Dakota Law Review, vol.

53, No, 3, 1977, pp. 401-425.

59William R. Freudenburg, People in the Impact

Zone: The Human and Social Consequences of Energy Boomtown Growth in Four Western Colorado

Communities (unpubl. doctoral dissertation, Yale

Univ., 1979).

60CWACOG, Oil Shale Trust Fund Request (Rifle, Colo.: Nov. 1978), p. 6.

‘

)] The complete list of developments includes:

C-a Rio Blanco Oil Shale project (Gulf and

Standard)

C-b Cathedral Bluffs Shale Oil Co. (Occidental

and Tenneco)

Paraho (oil shale)

Snowmass/Anschutz (coal)

Mid-Continent Garfield I/Mid-Cont. Mesa II

(coal)

Superior (oil shale and minerals)

Colowyo (coal)

Utah International (coal)

Colorado Ute (powerplant)

Empire (coal)

Moon Lake (coal)

GEX CMC (coal)

Sheridan (coal)

Energy fuels (coal)

Union Oil (oil shale)

Storm King (coal)

Colony/Atlantic Richfield and Tosco (oil shale)

Northern Minerals (coal)

62The complete list of documents consulted includes:

1980 Oil Shale Trust Fund Request

1979 Oil Shale Trust Fund Request

Housing Plan for Meeker, Colorado, 1979

Northwest Supplemental Report—A Supplement to the Northwest Colorado Coal Regional Environmental Statement, Colorado

Development Guide for Meeker, Colorado—A

Working Draft

Development Guide for Rifle, Colorado—A

Working Draft

CWACOG New Housing Unit Needs, 1979

Rifle Needs Assessment

Meeker Five Year Capital Improvements Needs

Grand Valley School District No. 16—Estimated Needs 1980-1985

Meeker School District RE-1 Projected Needs

Meeker Regional Library Projected Needs

Pioneer Hospital, Rio Blanco County, Projected

Needs

Five Year Capital Improvements Projection—

Rio Blanco Criminal Justice

Rangely District Hospital Projected Needs

Colorado Northwestern Community College

Long Range Plan

Grand River Hospital District

Rifle—Water Facility Needs (1980 - 1984)

Garfield County School District (Projected

Needs)

Silt Projected Needs

Roaring Fork School District RE-1—Five Year

Needs Assessment/Capital Improvements Plan
Ch. 10–Socieconomic Aspects Ž 473

Valley View Hospital Needs Assessment

63Personal communication, Dan Deppe (city

manager) to Dr. Donald Scrimgeour and Miss

Ellen Hutt, July 1979.

64Donald P. Scrimgeour and Marilyn Cross, Development Patterns and Social Impacts: A Focus

on the Oil Shale Region (Denver, Colo,: Quality Development Associates, July 1979).

65Discussion with Mr. Floyd McDaniel, Chairman, Planning Commission, Grand Valley, August

1979.

66Personal communication, Peter Kernkamp

(town planner) to Dr. Donald Scrimgeour and Miss

Ellen Hutt, July 1979.

67Personal communication, Bob Young (town

manager) to Dr. Donald Scrimgeour and Miss

Ellen Hutt, July 1979.

68Department of the Interior, Draft Environmental Statement: Proposed Superior Oil Company

Land Exchange and Oil Shale Resource Development (Denver, Colo.: BLM, August 1979) pp. 77-90.

69Supra No. 50.

70Supra No. 67.

71Supra No. 64.

72Supra No. 67.

73Personal communication, Mr. William Brennan to OTA, January 1980.

74Ibid,

75Supra No. 68.

76Supra Nos. 47 and 48.

7783 Stat. 852 (1970), as amended by 89 Stat.

424 (1975), 42 U.S.C. 4321-4347.

78Ibid.

79See, for example, Calvert Cliffs Coordinating

Committee, Inc. v. U.S. Atomic Energy Commission,

449 F.2d 1109 (D.C. Cir. 1971), cert. denied, 404

U.S. 942.

8090 Stat. 1013 (1976), 16 U.S.C. 1451-1464.

8186 Stat. 1280 (1972), 16 U.S.C. 1451-1464.

82Supra No. 38.

83Ibid., pp. 59-81.

84Rocky Mountain Energy Resource Development: Status, Potential, and Socioeconomic Issues

(Washington, D, C.: GAO, July 1977), EMD-77-23.

85Ibid., pp. 5-7.

86Supra No. 45.

87Energy Impact Assistance: A Background Report, printed at the request of the Committee on

Energy and Natural Resources, U.S. Senate, 96th

Cong., 1st sess., October 1979 (publ. No. 96-34)

(committee print).

88For a spirited elucidation of this position, see

Raymond L. Gold, “On Local Control of Western

Energy Development, ” The Social Science Journal,

vol. 16, No. 2, April 1979, pp. 121-127.

89Supra No. 45.
Appendixes
APPENDIX A

Description and Evaluation of the Simulation Model

To evaluate quantitatively the alternative incentives, a computerized model was used, developed by Tyner and Kalter1 that captures the probabilistic attributes of the oil shale development

process through Monte Carlo simulation techniques. The core of the model is a discounted cash

flow algorithm computing the after tax profit.

In computing aftertax profit, the model uses a

conventional discounted cash flow algorithm in

which the net cash flow for each year (i. e., revenues less costs and taxes) is discounted to the beginning of the project. These discounted cash

flows are then summed to arrive at the aftertax

net profit.

With the model, the user can input probability

distributions of prices and costs instead of single

value estimates. The model then constructs a

probability distribution for aftertax profits using

the Monte Carlo method. With this method, the

model makes repeated runs in which profit is calculated. In each run the model randomly selects

values from the input distributions. The resulting

profit calculations are then cumulated into probability y distributions characterized by an expected

value and standard deviation, The expected value

gives the average profit for all the Monte Carlo

runs and the standard deviation provides a measure of dispersion or variation about this average

value. The model also totals the number of Monte

Carlo runs that results in positive profits and

plots a histogram of the frequency distribution of

the profit outcomes, From this output the user can

compute the probability that a loss will be incurred.

Although the model was designed to test the effects of alternative mineral leasing systems on

profits and Government revenues, it incorporates

several financial incentives, including construction grants, price supports, purchase agreements,

investment tax credits, depletion allowances, and

variable depreciation schedules. Indeed, its authors used an earlier version to evaluate the effects of some of these incentives on the profitability and risk of oil shale development. ’

However, because the model was not designed

specifically to test incentives, it has several limitations. First, it does not provide for inflation indexing of the floor price under a price support

program. Thus, if the user inputs nominal (i.e.,

gross of inflation) values into the model, the real

(i.e., net of inflation) floor price will decline over

time. Alternatively, the user can input all real values (as OTA did) which implicitly indexes the

floor price. However, this solution causes some

distortion in the tax calculations. With inflation,

income increases in nominal value, but the

amount of depreciation deducted for tax purposes

remains constant. Thus, in real terms, the value of

depreciation decreases with inflation. However,

since the model does not account for this real decrease when the user inputs all real values, the

model underestimates the amount of tax payments. This distortion was not considered serious,

given the short depreciation period and the higher

fraction of depreciation claimed in early periods.

Second, the model has a limited capability with

respect to purchase agreements. To model a purchase agreement for the entire production, the

user can input the purchase price in place of the

market price for oil. However, the model cannot

directly handle purchase agreements for only a

portion of the output in a given year. To evaluate

a partial purchase agreement, the user must perform offline calculations to obtain an average of

the market and purchase agreement prices,

weighted by the proportion of output sold for each

price, A similar calculation must then be performed for the standard deviation of the price

distribution.

Third, the model has no capability to simulate

the effects of production tax credits. It does allow

for a price subsidy, but this subsidy is not a tax

credit. Unlike a tax credit, the subsidy increases

taxable income and hence income tax payments.

Because of this limitation, the model was not used

to perform the necessary calculations for the

$3/bbl tax credit. To estimate the increase in expected profit, the per barrel tax credit was multiplied by each year’s production. The total annual

credits were than discounted to the present and

summed. The same procedure was used to calculate the expected cost to the Government, except

that the Government discount rate was used in

the calculation. To evaluate the effect on risk, it

was assumed that the standard deviation would

not change as a result of the tax credit. This

assumption follows because the tax credit does

not alter costs or prices; these alterations determine the standard deviation. Because the standard deviation is the same for the tax credit as it is

with no incentive, it was possible to transform the

histogram computed for the no-incentive case into

477
478 ● An Assessment of Oil Shale Technologies

a histogram for the production tax credit case.

With this new histogram an estimate could be

made of the percentage of cases falling below the

zero profit level. Finally, the breakeven price was

calculated by subtracting the production tax

credit from the breakeven price with no incentive.

Fourth, the model is not able to simulate the effect of low-interest loans. Although the user could

adjust the discount rate downward to account for

the low-interest loan, this method has several limitations because it fails to account for all the terms

of the loan. In particular, this method is not sensitive to the time when the loan is received and

the time when it must be repaid. Moreover, the

approach is based on very restrictive and unrealistic assumptions about the structure of debt financing for the project.3

Accordingly, the model was not used to perform

the calculations for the low-interest loan. The

steps for the low-interest loan computations are

referenced in table A-1, The actual cash flows

(both loan payments and repayments) to the firm

were set up based on the Government’s lending

rate and the structure of the loan. These cash

flows were then discounted using the borrowing

rate for the firm on the open market (assumed to

be 3-percentage points higher than the Government lending rate), A similar calculation was performed to estimate the expected cost to the Government. As with the production tax credit, it was

assumed that the standard deviation of the distribution of profits would not change, since the loan

does not alter any of the costs or prices in the

model. With the estimated mean for the profit

distribution and the standard deviation, the histogram of profit distribution from the no-incentive

run was subsequently used to estimate the probability of a loss. The price increment was then

computed, which, when multiplied by the production for each year, yielded a discounted value

equal to the estimated increase in expected profits. The price increment was then subtracted from

the breakeven price with no incentive to yield the

breakeven price under the low-interest loan program.

Finally, the model does not directly calculate

the net cost to the Government. However, if the

Government and the firm use the same discount

rate, the cost to the Government exactly equals

the gain in expected profit to the firm calculated

Table A-1 .–Calculating Change in Expected Profit and Cost to

the Government for a Low-Interest Loan

Assumptions

● The average total construction cost is $1.7 billion

• 70 percent of one-fifth of the total construction cost, $238 million, is

loaned at the end of each of the 5 years of construction

Ž Interest IS calculated on the principal from the moment the first loan is

made

● The loan principal plus interest is amortized over 20 years

● The interest rate is 3 percent in real terms

● The firm market borrowing rate is 6 percent in real terms

● The Government’s discount rate is 10 percent in real terms

Calculations

Result

Step ($ million)

1.

2

3.

4.

5.

6.

7.

8.

9.

10,

11.

Calculate annual loan amounts (1 ,700x .7x 2), ., ‘ 238/yr ‘

Calculate the future value in year 5 of five payments of

$238.00 (3-percent Interest) . .

Calculate the annual principal and Interest payment to the

Government (years 6-25) based on the future value in

step 2 (3-percent Interest)

Calculate the present value to the firm year 5 of the

payment from step 3 (6-percent Interest)

Calculate the present value to the firm in year O of the

value from step 4 (6-percent Interest) ,

Calculate the present value to the firm in year O of the

annual loan amount from step 1 (6-percent Interest).

Calculate the change in profit for the firm (1 ,003-726)

Calculate the present value to the Government in year 5 of

the payment from step 3 (l O-percent interest) .,

Calculate the present value to the Government in year O of

the value from step 8 (l O-percent Interest)

Calculate the present value to the Government in” year O of

the annual loan amounts from step 1 ( 10-percent

interest )

Calculate the net cost the Government (901-448)

1,264

85/yr

974

726

1,003

277

723

448

401

453

SOURCE :Office of Technology Assessment

by the model. This is so because, except for small

tax payments to State governments, all the monetary exchanges occur between the Federal Government and the firm. If the discount rates are the

same, the present value of the exchanges to both

entities is the same, Therefore, since a lo-percent

Government discount rate has been assumed, the

net cost to the Government of each incentive is

equal to the net gain in profitability to the firm

calculated at a lo-percent discount rate. The only

exception occurs with the Government loan. Because it has been assumed that the real interest

rate on debt financing for firms is less than 10

percent, the present value to the firm of the lowinterest loan is less than its cost to the Government.
Appendix A–Description and Evaluation of the Simulation Model Ž 479

Appendix A References

1Wallace E. Tyner and Robert J. Kalter, “A Simula- Foundation, April 1975.

tion Model for Resource Policy Evaluation, ” Cornell Ag- 3tewart C. Meyers, “Interactions of Corporate Firicultural Economic Stuff Paper, September 1977. nancing and Investment Decisions—Implications for

2Wallace E. Tyner and Robert J. Kalter, An Analysis Capital Budgeting, ” in Modern Developments in Finanof Federal Leasing Policy for Oil Shale Lands, prepared cial Management, Hinsdale, Ill.: Dryden Press, 1976.

for the Office of Energy R&D Policy, National Science
APPENDIX B

Assumptions and Data for Computer Analyses

Most of the assumptions used in the computer simulation analyses are embodied in

the input data displayed in table B-1. All cost and price data in the exhibit are in constant

1979 dollars.

Table B-1 .–Data Used for Quantitative Analysisa

Data item Value used Explanation

costs

Capital cost distribution

Maximum capital cost,

Most probable capital cost:

Minimum capital cos t

Operating and maintenance

(O&M) cost distribution.

Maximum O&M cost .

Most probable O&M cost :

Minimum O&M cos t

Operating cost Increase

Construction perio d

Fraction of costs occurring each

year during construction

Year 1 .,

Year 2

Year 3 ., : : : : :

Year 4 .,

Year 5

Year 6 .,

Prices

Initial oil price (1979) ., .,

Mean annual 011 price increase

Standard deviation of annual oil

price change distribution

Taxes and transfers

Federal corporate tax, .,

State corporate ta x

State severance tax .,

Investment tax credit,

Depletion allowanc e

Royalty .,

Depreciation Iifetim e

Annual rent .,

Depreciation metho d

$2.0 billion

$1.7 billion

$1.4 billion

$17/bbl

$12/bbl

$ 9/bbl

4 percent/year

6 years

10

25

30

25

00

10

$35/bbl

3 percent

3 percent

46 percent

3 percent

4 percent

10 percent

15 percent

1 percent

12 years

$2,600

Sum-of -years

The capital cost data apply to all the capital equipment needed to mine and retort shale and hydrotreat the raw shale oil product, the costs do not Include land acquisition or interest charges, Data

were based on recent industry cost estimates,

Operating costs include hydrotreating costs. Data were based on recent industry cost estimates

Operating costs were assumed to increase 4 percent per year in real terms (I e., net of inflation)

to account for probable Increases in labor costs due to expansion of shale Industries in sparsely

populated areas Assumption was based on expectations expressed to OTA by industry sources

A 6-year construction period (i. e , a l-year delay between the fourth and fifth years) decreased

expected profits by $117 million for the no-incentive, 12-percent discount rate case.

Based on the price of imported oil, which at the time of the analysis ranged from $33 to $37/bbl.

The assumed 3-percent real increase in oil prices accounts for increasing scarcity as cheap domestic supplies are exhausted, and is midway in the range (2-4 percent) used by DOE planners

Based on historical trends from the American Petroleum Institute, Basic Petroleum Data Book,

1976.

Current Federal corporate income tax rate,

Colorado corporate income tax rate.

Colorado severance tax on 011 shale reserves,

Investment tax credit of 10 percent applies to all investments, an existing additional 10-percent

credit for energy-related Investments was ignored because it is to expire in 1982,

Depletion allowance computed on 011 shale revenues and deducted from taxable income.

Current royalty is 12.5 cents per ton of mined shale; this is equivalent to a royalty on 011 revenues

of less than 1 percent.

Based on discussions with industry sources.

Based on a 50-cent-per-acre rent on Federal shale leases of 5,200 acres,

Provides the most rapid tax writeoff,

digits with switchover to straight

Iine

Production

Maximum output of facility ., 50,000 bbl/d Size of typical commercial facility,

Production lifetime ., ., ., 22 years Based on production lifetime of 20 to 30 years in industry cost estimates.

Annual output

Year 1 15,000 bbl/d 2-year buildup accounts for probable startup difficulties.

Year 2 ..., : ..........35,000 bbl/d

Years 3 to 22, ., ., ., 50,000 bbl/d

a

All monetary values in constant 1979 dollars

SOURCE :Office of Technology Assessment

480
APPENDIX C

Oil Shale Water Pollutants

Introduction

The types and amounts of water contaminants that are likely to be produced by major kinds of oil shale facilities are discussed here,

Water Pollutants Produced by Major Oil Shale Processes

Types and Origins of Pollutants

The following summarizes the major sources of

each class of waterborne contaminants found in

oil shale facilities.

●

●

●

Suspended solids will occur primarily in

water from the dust-control systems used in

shale mining and crushing operations. Mine

drainage water will also contain suspended

solids, as will a retort condensate stream

that picks up fine shale particles as it

trickles down through the broken shale. In

aboveground retorts, some fine shale may be

entrained in the retort gas and captured in

the gas condensate, but levels should be low,

thus should not be a problem to treat, Cooling

water will pick up dust from the atmosphere,

particularly if the cooling tower is near a

shale crushing or disposal site. Precipitated

salts and biological matter may also be present in the cooling tower blowdown.

Oil and grease will be present in the retort

condensate water that is removed from the

in situ retort together with the product oil.

Some oil remains in the water after product

recovery and must be removed prior to further treatment. Part of the oil forms an emulsion in the water and its removal may be difficult. 1 Volatile hydrocarbons leave with the

retort offgas and condense in the gas condensate water. Tests indicate that the oil in the

gas condensate occurs in well-defined droplets that can be separated without difficulty.2

Oils in the coker and hydrotreater condensates are expected to be similar to those in

the gas condensate.

Dissolved gases include all of the NH3 a n d

some of the CO2 and H2S formed in the retorting process. These gases dissolve in the retort and gas condensates. Any NH3 and H2S

that are formed during upgrading will appear in the hydrotreater condensates.

●

●

●

Dissolved inorganic will be found in mine

drainage water and retort condensates because these streams leach sodium, potassium, sulfate, bicarbonate, chloride, calcium,

and magnesium ions from the shale that they

contact. 3 In addition, some inorganic volatilize and may be captured from the gas

phase in the retort, Of the heavy metals present in raw oil shale, cadmium and mercury

(probably as their respective sulfides) are expected to be present in the gas condensate in

low concentrations.’ An analysis of TOSCO II

gas condensate water showed the presence

of cyanide, sodium, calcium, magnesium, silica, and iron ions, with only trace amounts of

some of the heavy metal elements.5

Dissolved organics arise largely from the organic compounds in the raw oil shale, which

may be altered during pyrolysis and end up

in the retort, gas, or hydrotreater condensates. The types of organics in each condensate will probably depend on the volatility

and volubility of the organics and the temperature at which the wastewater is condensed. No data are available on this subject

but it is known that a wide range of compounds, particularly carboxylic acids and

neutral compounds, can be expected.6 Many

of the individual compounds should be biodegradable, but studies have shown that less

than 50 percent of the organic matter can be

removed by conventional biological oxidation. This poor performance is attributed to

the effect of toxic compounds on waste-treatment bacteria. Both inorganic and organic

toxic substances may be responsible. The

specific types of toxic pollutants will differ

with the retorting process and with raw

shale composition. 789

Trace elements and metals are not expected

to occur in large concentrations in the major

waste streams except those streams dis481
482 ● An Assessment of Oil Shale Technologies

cussed under dissolved inorganics.

10 11

Chromium was used for corrosion control in

older cooling-water systems but other agents

are now available and should be used to

avoid the problem of chromium contamination of blowdown streams. If trace element

and metal removal is required, chemical

treatment, specific ion exchange, and membrane processes are available.

Trace organics are toxic or hazardous organic compounds present in low concentrations. They may occur in the retort and gas

condensate streams and in the wastewater

stream from the upgrading section. These

constituents can generally be removed together with other dissolved organics by ultrafiltration with carbon adsorption for final ●

cleaning (“polishing”).

Toxics, including carcinogens, mutagens,

priority pollutants, and other hazardous-subTable C-1 indicates

process streams and

stances, have been reported for various

types of oil shale processing wastes. Any toxic substances present in the wastewater

streams will be removed along with the trace

organics or inorganic substances. It is not expected that thermal oxidation, which is often

employed to destroy hazardous organic compounds, will be required for the wastewater

streams, although it may be considered for

concentrates or sludges. However, the presence of toxic substances may interfere with

biological oxidation processes used for bulk

organic removal. If this is a problem, the

substances could be removed in any of several conventional pretreatment steps.

Sanitary wastes in “domestic” and service

waste streams can be kept separate and

treated in commercially available package

biological treatment units.

The Amounts of Pollutants Produced

he principal contaminated MIS process. It is similar to the design proposed

their flow rates for four by Occidental and Tenneco for tract C-b. The

commercial-scale [50,000 bbl/d)* oil shale facil- “MIS/aboveground” plant combines Occidental’s

ities. These facilities correspond to the plants for

which water requirements are estimated in chapter 9. The “aboveground direct” plant uses directly heated aboveground retorts like the Paraho

direct or gas combustion. The “aboveground indirect” uses indirectly heated retorts like TOSCO

II. It is similar to the design proposed by Colony

Development. The “MIS” plant uses Occidental’s

MIS process-with Lurgi-Ruhrgas indirectly heated

aboveground retorts. It is similar to Rio Blanco’s

design for tract C-a.

The flow rate estimates were derived from

tables 71, 74, and 75. (See ch. 9.) Estimates have

been added for the internally recycled gas washing and hydrotreater wash streams that were not

considered in chapter 9. (The water availability

*Barrels per stream day.

Table C-1 .–Flow Rates of Contaminated Streams in Oil Shale Facilities

Producing 50,000 bbl/d of Shale Oil Syncrude (acre-ft/yr)

Aboveground Aboveground

direct redirect MIS MIS/aboveground

Cooling tower blowdow n 1,550-1,820 1,320-2,070 1,040-1,280 910-1,130

Boiler blowdown .. . 325 370-405

Boiler feedwater treatment wastes

370 350

165 190-210 185 180

Gas washing condensate ., 1,070-1,190 (a) 3,320-3,640 2,270-2,500

Gas condensate (net). . 490-540 730-800 2,160-2,370 1,480-1,630

Retort condensate, . . . . (a) (a) 1,240-1,370 850-940

Coker condensate. . , 60 60 60 60

Hydrotreater wash condensate 875 875 875 875

Net hydrotreater condensate 40 40

Excess mine drainag e (a) (a) 0-10,000 0-10,00 0

a)@glecfed for processes designs or sites considered

SOURCE R F Probstem H Gold and R E Hicks, Wafer Reqwernenfs Po//ufIorI Mecfs and Cos/s of Waler Supply arrd Treafrnerd for (he 0(/ Sfra/e /ndus(ry. prepared for OTA by Water Purlflcahon Associates October 1979
Appendix C–Oil Shale Water Pollutants ● 483

analysis presented there deals only with streams

that cross the project boundaries.) These additional streams are of significance for water quality analysis because they contain all of the NH3

,

most of the CO2

, and some of the H2S that is removed from gas streams in the plants. Flow rate

ranges are shown in some cases to account for the

expected variations in shale grades and plant designs, as discussed in chapter 9. The following

points should be noted with respect to the flow

rate estimates.

●

●

●

●

●

Cooling tower blowdown varies substantially

among the plants, largely because of different modes of power generation.

Boiler blowdowns are fairly uniform because

it is assumed that boilers will generate steam

for use in the upgrading units, which are

identical for all four plants.

For the same reason, all four plants have the

same flow rates for coker condensate, hydrotreater wash condensate, and net hydrotreater condensate.

Excess mine drainage is indicated for the

MIS and MIS/aboveground plants because it

was assumed that they would be located in

the ground water areas of the Piceance basin. The other two plants were assumed to be

located in drier areas (e.g., in the Uinta basin

or along the edge of the Piceance basin),

No retort condensate is shown for the AGR

plants because it was assumed that condensation in the retort would be avoided by adjusting the operating temperature. A large

●

value is shown for the MIS retort condensate

because of unavoidable condensation in the

lower portions of the MIS retorts. The value

for MIS/aboveground is a weighted average

of Lurgi-Ruhrgas (no condensate) and MIS

(large quantities of condensate).

Large values are also shown for gas condensate and gas washing condensate in all systems except the aboveground indirect. In the

aboveground direct and the two MIS operations, large quantities of moist retort gas

must be treated, resulting in large volumes of

condensate. Much of the moisture is a combustion product. In contrast, the above-

-ground indirect has no combustion within the

retort and produces less gas that must be

cooled and cleaned.

In table C-2, estimates are presented of the concentrations of contaminants in the condensate

streams. It is important to note that extensive

data on contaminant concentrations are not available for the process condensate streams and that

published measurements show considerable variation. Only the estimate for the aboveground indirect gas condensate is based on extensive field

measurements.

13 The other values are consistent

with material balance calculations and information from the literature but they are at best approximate. Moreover, only concentrations of major contaminants are shown. Trace contaminants,

including most toxic elements, are not indicated

because information on their occurrence is even

more limited, Although toxic elements are not exTable C-2.–Contaminant Concentrations in Oil Shale Process Condensate Streams (mg/1)a

Gas condensate Retort condensate Hydrotreater condensate

Contaminant Aboveground direct Aboveground redirect MIS or MIS/aboveground MIS or MIS/aboveground All plants

N H 3 17,990C 5,150 21 ,330C

720 41 ,000c

H 2 S 206c

810 118C — 18,000 C

C O2

b

32,400 C

6,150 41 ,800C9,940 None

Calcium : Lowd

6 Low 20 Low

Magnesium . Low 2 Low 17 Low

Potassiu m Low 0 4 Low 100 Low

Sodiu m Low 5 Low 3,600 Low

Chlorid e Low 5 Low 280 Low

Fluorid e Low 0.3 Low 39 Low

Boron , Low Low Low 25 Low

Sulfat e Low Low Low 1,200 Low

Organic carbo n — 6,100 — — —

BOD e ., 10,000 10,000 2,200 2,220 10,000

alrace elements and organlcs for which data are unavailable are flOl shown

bBlcarbonafe and carbonate concentrations reporled as CO, e(lulvalenf

cln Internal acid wash before gas separation and wash recYcle

dBa5ed on avadable dala or estlmales

eBlochemlcal oxygen demand estimated al one half of the fheorellcal oXY9en demand

SOURCE R F Probstem H Gold and R E Hicks Wafer l?equ~rerneflfs, Po//ufIorI Ef/ecK and Cos/s of Waler Supp/y and Treafrnefll for rhe 0// Shale /ndustry prepared tor OTA by Waler Punflcaf!on

Associates October 1979
484 ● An Assessment of Oil Shale Technologies

pected to be present to any significant extent in

the gas condensates, some could be present in the

MIS retort condensate. ”

The hydrotreater condensate concentrations

were developed for Colony’s upgrading unit, but

they should be typical of values for any facility

(MIS or aboveground) that processes Green River

shale oil. A retort condensate is shown only for

the MIS and MIS/aboveground facilities, for reasons mentioned previously. Significant differences are indicated for the three gas condensate

streams with respect to NH3

, H2S, and CO2 concentrations. The aboveground indirect stream is

much lower in CO2 and NH3 because of the lack of

combustion (which produces soluble CO2 and NOx

gases) in the retort. H2S concentration is higher in

the aboveground indirect stream because there is

little oxygen available in the retort to oxidize the

H2S to SO2 A lack of data prevents evaluation of

process-related effects on concentrations of other

contaminants.

In table C-3, the likely rates of pollutant production are shown for the gas condensate streams.

Table C-3.–Production Rates for Principal Pollutants

in Gas Condensate Streams (ton/d)a

Type of facility

Aboveground Aboveground MIS/

Contaminant direct Indirect MIS aboveground

N H , 75.6 147 276 189

H 2 S

b

0.87 2.3 1 5 1.1

c o , 136 17,5 541 371

BOD C ., : : 19.2 28.5 185 127

aTons per stream day for production of 50000 bbl/d shale oll syncrude

bAddltlonal SUIIIJr IS recovered dlreclly from the retofl 9as

cBlochemlcal oxygen demand

SOURCE R F Probsteln H Gold and R E Hicks Waler I?equlrenrerrfs, Po//utIon Ef/ec/s and

COSIS of Waler Supp/y and Trea/nrenl for Ihe 0// Stra/e /rrdustry prepared for OTA Dy

Waler Purlflcatton Assoclales October 1979

The values shown were obtained by multiplying

the flow rates in table C-1 by the pollutant concentrations in table C-Z. Only a single value is shown

for each contaminant in table C-3 and in the other

pollutant production-rate tables that follow. The

rates shown were calculated for average stream

flows wherever a range is shown in table C-1. This

approximation is justified because the uncertainty in pollutant concentrations is larger than the

relatively narrow range shown for the flow rates.

These uncertainties result from a paucity of published data, and also because large differences

can occur in some plants with different feed

waters and process designs.

Table C-4 indicates the pollutant production

rates for the retort condensate streams produced

Table C-4.–Production Rates for Principal Pollutants

From MIS Retort Condensates (ton/d)a

Type of facility

Contaminant MIS MIS/aboveground

N H3 . , 3 4 9 2.40

H 2 S — —

co, : : 48,2 33.1

Calciu m 0.10 0.07

Magnesium. . 0 0 8 0.06

Potassium. . 0.49 0.33

Sodiu m 17.5 12.0

Chlorid e 1,36 0.93

Fluorid e 0.19 0 1 3

Boron. : . 0.12 0.08

Sulfate . 5,82 3.99

Biochemical oxygen demand ., 10.07 7.32

aTOn~ per stream day for production of 50000 bbl/d shale o!! syncrude

SOURCE R F Probstem H Gold, and R E Hicks Wafe/ Requ(rernerrts Po//ul(on E//ec(s and

Cosls o/ Waler Supp/y arrd Trealmen/ for /tre 0// Sha/e /rrdus/ry prepared for OTA by

Water Purlflcahon Assoclales October 1979

in MIS retorting. It is assumed that retort condensates are produced only with MIS processing.

These condensates leach inorganic salts from

shale in the retort, as indicated by the contaminant production rates shown.

Table C-5 shows the production rates for the

principal contaminants in the process waste

waters generated in the upgrading portion of the

Colony design. This is the only plant for which an

upgrading section has been described in the literature. Since shale oils produced by different

retorts are not markedly different in their nitrogen and sulfur contents, it is reasonable to apply

the pollutant production estimates for the TOSCO

H upgrading section to all of the facilities considered.

In table C-6, the pollutant production rates for

all of the process condensate streams are combined. It can be seen that the biochemical oxygen

demand (BOD) does not have a wide range between facilities. This is in large measure a result

Table C-5.–Production Rates for Principal Pollutants

in Upgrading Condensates (ton/d)a

Waste stream

Contaminant Hydrotreater condensate Coker condensate

NH 3 ., . . ., 133 1.15

H 2 S

b 

., . . . . 58.6 0,18

c o2 o 1.37

Biochemical oxygen demand 1.49 2.23

a

Tons per stream day for production of 50,000 bbl/d shale 011 syncrude Based on a TOSCO II

process design Similar values anticipated for the other process models

bAddltlonal sulfur IS recovered dwecfly from fhe refofl 9as

SOURCE R F Probsfeln, H Gold, and R E Hicks Wale{ Requwemerrfs Po//u(ion Effects, and

Costs of Waler Supp/y and Treaonen( for (he 0// Sha/e /rrduslry, prepared for OTA by

Water PurlficatlonAssoclales, October 1979
Append/x C–Oil Shale Water Pollutants ● 485

Table C-6. –Sum of the Production Rates for Principal Pollutants

in Retorting and Upgrading Condensates (ton/d)a

Type of facility — —

Above-ground Aboveground MIS/

Contaminant direct indirect MIS aboveground

NH, 210 149 414 -

326

H @ 5 9 7 61 1 6 0 3 5 9 9

Co, c 137 189 591 405

BODd2 2 9 3 2 2 3 2 9 2 3 7

alons per stream day for procfucl Ion of 50 000 bDl d shalemi Syncrude

bAddiflond. sulfur IS recoverec dlrecf y frOm the retofl 9as

Clhls does not represen[ iota I CO, p-oducflon CO, IS also generated In combustion and Iosl up

flue gds stacks as n TOSCOII tnd~recl process dnd In steam and power production

dBloc~emlcal oxyqen demand

SOURCE R F Probslelr H Gold and R E Hicks Wafer Requremeols PoIlufIon Ef(ech and

Cosls of Wafer 5WPIJ am Tredlme[)( for !ne 011 .SOde Iodu.slrp prepared ‘or OTA t)y

Waler Purll[cahon Assocla!es Oc!ober 1979

of the BOD concentrations assumed. The H2S production, which represents about a third of the

total sulfur recovered in the plant, varies little

among the different facilities. This is reasonable,

since the amount of sulfur removed per unit of

shale oil produced should be similar for the different processes. However, this H2S includes only

that amount that dissolves in the condensate

streams; it does not include the gas that goes

directly to the sulfur recovery units.

The most striking estimate in table C-6 is the extremely high CO2 production rate for the MIS facility. The rate for the aboveground indirect facility is lowest because decomposition of carbonate

minerals to CO2 is much less at the lower retorting

temperatures (about 90 0

0 F or 50 00 C) than in the

higher temperature (about 1,50 0

0 F or 800° C)

MIS or aboveground direct processes. The rate is

highest for MIS because the shale remains at high

temperatures for a long time, thus allowing nearly

complete decomposition of the carbonates. The

combined MIS and AGR facility shows a correspondingly lower value—a weighted average of

MIS and Lurgi-Ruhrgas rates. It should be emphasized that CO2 is also produced by combustion in

the indirect AGR plant, which does not show up in

the condensate streams because it is lost directly

up flue gas stacks, However, even if this gas were

included, the ratio of CO2 produced in MIS or

aboveground direct to that in indirectly heated

retorting would still be large.

Differences in NH3 production rates also result

from combustion in MIS and directly heated

aboveground retorts. The aboveground indirect

process produces the least NH3 because it is

essentially one of pyrolysis in which the nitrogen

is mostly obtained from the organic matter in the

shale. In fact, almost all of the NH3 that will be

produced in the indirectly heated AGR will be

manufactured in the upgrading section when nitrogen is removed from the crude shale oil by hydrotreating. Differences in BOD yields are not statistically significant, given the lack of precision in

the data base.

In order to calculate pollutant concentrations

in cooling tower blowdown and waste streams

from boiler feedwater treatment, it is necessary

to know the raw water composition to the plant.

Table C-7 shows the raw water compositions

assumed for this assessment. The surface water

quality is that of the Colorado River near Cameo,

Colo., and the mine drainage water is a composite

of the expected quality of water to be drawn from

the bedrock aquifers of the Piceance Basin. 15* The

raw water compositions are only approximate.

Table C-8 presents the estimated composition

of the cooling tower blowdown of four facilities

Table C-7.–Composite Water Quality Data for Colorado River

Water and Mine Drainage Water in the Piceance Basin (mg/l)

Source of process water

Contaminant Surface water Mine drainage water

NH3

— 1.2 

‘Bicarbonat e 168 750

Boron — 3

Calcium 72 50

Carbonate — 50

Chlorid e 205 20

Fluoride — 15

Magnesium 19 60

Pheno l — 25 x 10 -3

Silica 7 15

Sodium 153 300

Sulfate 158 350

Total dissolved solids 734 1,350

SOURCE R F ProDstem H Gold and R E HICKS Water Requ/rewmff Po IIUW? t ‘fecf~ ,MO

Cosls O( Warer SJpLW and Trealmenf (or /he 011 Shd e Iflctisfr)preparecl for OTA OY

Water Punflca:(on Assoctales October 1979

Table C-8.–Estimated Concentrations of Principal

Contaminants in Cooling Tower Blowdown (mg/l)

Type of facility

AGR with MIS retorting with mine

Contaminant surface water supply drainage water supply

Calcium, 215 200

Chloride 615 80

Fluorid e — 60

Magnesium 60 240

Sodium 460 1,200

Sulfate 840 1,400

SOURCE R F Probstein, H. Gold and R E Hicks Waler Reqwrernenrs Po//uflon E(/ecrs and

Cosls O( Wa[ef Supp)y and TreaVneflf for rhe 01/ Sha/e /ndus(fy prepared for OTA by

Wafer Purlhcahon Assoclales Ocfober 1979
486 ● An Assessment of Oil Shale Technologies

considered, based on an average of three cycles

of concentration for AGR (surface water supply)

and four cycles of concentration for MIS retorting

(mine drainage water supply). The relatively low

numbers assumed for concentration cycles are

based on the assumption that all of the blowdown

water is needed for solid waste disposal. Under

this assumption there is no advantage to the more

costly procedure of using a larger number of

cycles.

Table C-9 gives the estimated composition of

the waste streams from treating the raw supply

Table C-9.–Estimated Concentrations of the Principal

Contaminants in an Ion Exchange Regenerant Waste Stream

From Boiler Feedwater Treatment’ (mg/l)

Type of facility

AGR with MIS retorting with mine

Contaminant surface water supply drainage water supply

Calciu m 950 660

Chloride : 2,400 790

Magnesiu m 250 4,600

Sodium ., 990 2,200

Sulfat e 2,080 3,460

avo]ume 01 regenerant wastewater assumed to be approximately 75 Percent ot the volume of

treated water

SOURCE R F Probsteln H Gold and R E Htcks Wa/er Ileqwrernen(s Po//u/IorI E/(ec/s am-l

COSM of Waler Supply and TrealmerU for (he 0(/ S/ra/e /frdus/(y prepared Ior OTA by

Waler Purlflca[ton Associates October 1979

water by ion exchange to obtain a high-quality

water for boiler feed. The estimates assume the

removal of all the calcium, magnesium, and sulfate ions from the supply water. Most of the other

ions will also be removed but only the principal

ones are shown for the waste streams. The waste

volume is about 7.5 percent of the water treated.

This corresponds to a fairly efficient ion exchange treatment system. Boiler blowdown waste

composition is not shown because the quality of

this water is usually equivalent to that of the raw

water entering the plant. It can therefore be

mixed with the raw water and used as a makeup

source.

Table C-10 gives the estimated pollutant production rates in the cooling tower blowdown and

boiler waste treatment streams based on the compositions of tables C-8 and C-9. Also shown are the

total production rates from these two sources; the

streams would usually be combined in the plant

and used for solid waste disposal. There is not a

great deal of difference in the total quantities of

pollutants produced by the facilities considered,

In table C-1 it was assumed that oil shale mines

in ground water areas might result in production

of from O to 10,000 acre-ft/yr of excess mine

drainage water for a 50,000-bbl/d in situ facility.

At this time, it is not known whether the water

will be treated for discharge to surface streams,

Table C-10.–Production Rates for Principal Pollutants in Cooling Tower Blowdown and Boiler Treatment Wastes (ton/d)

Contaminant Aboveground direct Aboveground indirect MIS MIS/aboveground

Cooling tower blowdown

Calcium . 1 35 1,36 0.86 0 7 6

Chlorid e 3 8 5 3.88 0 3 5 0.30

Fluoride . . . — — 0.26 0 2 3

Magnesiu m 0 3 8 0.38 1.04 0,91

Sodium . 2.88 2 9 0 5.18 4,55

Sulfat e 5.26 5 2 9 6 0 4 5.31

Boiler treatment wastes

Calcium . 0,58 0.71 0.45 0.44

Chlorid e 1,47 1 79 0.54 0,53

Magnesiu m 0 1 5 0.19 3.16 3.08

Sodium . 061 0.74 1,51 1.47

Sulfat e 1 28 1.55 2.38 2,32

Total

Calcium . 193 2.06 1.32 1.20

Chlorid e 5 3 3 5,66 0 8 9 0 8 3

Fluorid e — — 0.26 0.23

Magnesiu m 0,53 0 5 6 4.20 3.99

Sodium : 3 4 9 3.64 6.69 6.02

Sulfat e 6 5 4 6.84 8.42 7,63

Total . 17.82 1876 21.78 19,90

SOURCE R F Probstein H Gold and R E Hicks, Waler r7e9u/remerr/s Po//u/lon Effec/s and Cos/s of Waler Supp/y and Trea/merrl /or (he Od Sha/e /ndusVy prepared for OTA by Water Purlflcatlon

Associates Oclober 1979
Append/x C–Oil Shale Water Pollutants ● 487

or reinfected into the aquifer from which it was

drawn. The question has economic as well as environmental implications. If it is to be discharged,

then it must be treated, and wastewater streams

will be produced that will require management

and disposal. The level of treatment is not known

at present. In DRI's analysis of the costs of environmental protection, “less strict” and “more

strict” pollutant discharge criteria were assumed.’” In table C-1 I their estimates are given

for the total quantities of pollutants produced by

treatment for surface discharge of 10,000 acreft/yr of excess mine drainage water of the quality

shown in table C-7 for the less strict and more

strict regulations. These quantities could be appropriately scaled down or up for different rates

of drainage-water production. The effect of the

different standards on the total quantity of pollutants produced is not large. However, the costs of

achieving the “more strict” criteria would be

much higher.

Table C-1 1.–Rates of Pollutant Production From Treatment

of 10,000 acre-ft/yr of Excess Mine Drainage Water

for Surface Discharge

Regulatory scenario

‘‘Less strict’ ‘ ‘More strict ‘

Contaminant 0

/0 Removal Ton/ d O/O Removal Ton/d —.

N H

3

85 0 0 4 91 7 0 0 4

Bicarbonat e 77 21 47 9 4 3 2630

Boro n 70 0 0 8 9 8 2 011

Calciu m 99 184 9 9 9 1 86

Carbonat e 90 1 67 9 5 8 1 78

Chloride 94 0 7 0 9 9 6 0 7 4

Fluorid e 90 0 5 0 99.0 0 5 5

Magnesium 99 221 9 9 9 2 2 3

Silci a 83 0 4 6 9 6 7 0 5 4

Sodium 94 10.49 9 9 7 11 12

Sulfate 97 1262 9 9 9 1300

Tota l 5208 5827

SOURCE Adap!ed from T D Nevens et al ~ DRI Wafer PunfIcaIIon ASSOCldlE+S and Slone dnd

Websler Englneerlng ) Predcled Cosfs of ErIti/?OflrWh!dl Conffos for a Comr~lerc)d 011

Shale /ndustry Vohme / An Engfneerfng Analys/s Depa:tmenl of Energy July 1979

Appendix C References

1D, S. Farrier, Division of Environmental Sciences,

Laramie Energy Technology Center, Department of Energy, Laramie, Wyo., personal communication, July

1978.

‘R. F. Probstein, H. Gold, and R. E. Hicks, Water I?equirements, Pollution Effects, and Costs o.f Water Supply and Treatment for the Oii ShaJe Industry, prepared

for OTA by Water Purification Associates, October

1979, p. 81.

‘Environmental Protection Agency, A Preliminary Assessment of the Environmental Impacts From Oil Shale

Development, prepared by TRW and DRI under contract No. 68-02-1881 (EPA-600/7-77-069), July 1977.

‘J. P. Fox, K. K. Mason, and J. J. Duvall, “Partitioning

of Major, Minor, and Trace Elements During Simulated

In Situ Oil Shale Retorting in a Controlled-State Retort, ” Proceedings of the Twelfth Oil Shaie Symposium

(J. H. Gary, cd.), Colorado School of Mines Press,

Golden, Colo., 1979, pp. 58-71.

‘F. C. Haas, “Analysis of TOSCO II Oil Shale Retort

Water, ” paper presented at ASTM Symposium D199.33 on Analysis of Wastes Associated With Alternative Fuel Production, Pittsburgh, Pa., June 4-5, 1979.

‘Ibid.

‘E. W. Cook, “Organic Acids in Process Water From

Green River Oil Shale,” Chemistry & Industry, May 1,

1971, p. 485.

“G. W. Dawson and B. W. Mercer, “Analysis, Screening and Evaluation of Control Technology for Wastewater Generated in Shale Oil Development, ” Quarterly

Reports, Battelle Pacific Northwest Laboratory, Richmond, Wash,, January 1977-March 1979.

‘

]Water Purification Associates, A Study of Aerobic

Oxidation and Allied Treatments for Upgrading In Situ

Retort Waters, contract No. EW-78-C-20-0018 with Laramie Energy Technology Center, Department of Energy,

Quarterly Status Report, August 1979.

‘“E. F. Bates and T. L. Thoem (editors), Pol)ution Control Guidance for Oil Shale Development, Revised Draft

Report, Environmental Protection Agency, Cincinnati,

Ohio, July 1979.

‘

l Supra No. 4,

1

2 Supra No. 5.

1‘Ibid.

‘%upra No. 4.

“Denver Research Institute, Predicted Costs of Environmental Controls for A oil ShaJe Industry; Vo]ume l—

An Engineering Analysis, prepared for the Department

of Energy under contract No, IZP-78-S-O2-51O7, Jul y

1979.

“Ibid,
APPENDIX D

Technologies for Managing

Point Sources of Wastewater

Introduction

This appendix describes the wastewater streams that will be produced in oil shale

facilities, including leachates from solid waste disposal. The physical, chemical, and biological treatment devices and systems are then described, Finally, developer plans are reviewed to show how water supply, wastewater treatment units and systems, and methods

of disposition might be combined into comprehensive

commercial-scale oil shale facilities.

Oil Shale Waste Streams That Will

water management schemes for

Require Treatment

The major point source streams that will require treatment are:

●

●

●

●

●

The

excess mine drainage water—principally for

plants near the center of the Piceance basin;

retort condensates —especially and perhaps

exclusively for in situ operations;

gas condensates—for all systems;

coker and hydrotreater condensates from all

plants that have onsite upgrading or refining

operations; and

streams from service operations—including

boiler feedwater treatment wastes and cooling tower blowdown.

other streams are either relatively small or

relatively clean and consequently require little

treatment. They include boiler blowdown, rain

and service water runoff, and sanitary wastes.

Sanitary wastes will certainly need treatment,

but they should be similar to typical domestic

●

Individual Methods for Point

Physical Methods

Gravity separators are used to treat nearly all

oily wastewaters. They are especially common

in refineries and chemical plants. The simplest

are impingement-type devices such as API

separators, corrugated plate interceptor separators and parallel plate interceptor separators. These devices are very inexpensive and

reliable but they can be used only for firststage oil removal. Additional treatment is usuwastes and can easily be handled in commercially.

available biological u-nits.

Leachate from spent or raw shale piles on the

surface is not considered as a separate stream requiring treatment during the operating life of the

plant. With proper compaction and irrigation,

water will be either retained in the pile or lost by

evaporation. There should therefore be little accumulation of leachates. 1 There will be storm and

snowmelt runoff, but this will be in limited quantities and will have a low salt content.2 The small

quantity of water that may percolate through the

pile after intentional leaching can be expected to

be low in both organic and inorganic substances, ]

This water can be used for dust control in raw

shale crushing operations and will thus find its

way back to the retort, Leachate from spent in

situ retorts poses a potential problem of unknown

magnitude, Design concepts for its control are discussed in chapter 8.

Source Wastewater Treatment

●

ally needed before the wastewater can be sent

to sensitive treatment systems like biological

oxidizers.

Coalescing cartridge separators (figure D-1)

are more effective devices that can reduce oil

concentrations to as low as 1 mg/l. In this type

of separator, oily wastewater is pumped

through a coarse filter medium within the cartridges, causing oil droplets and some mechanically emulsified oil to coagulate into large

globules which float to the top of the separator

488
Appendix D– Technologies for Managing Point Sources of Wastewater ● 489

Figure D-1 .—Cartridge-Type Coalescing Oil-Water

Separator

OIL Y

M IXTU R E

E R

SOURCE. Assessment of Oil Shale Retort Wastewater Treatment and Control

Technology, Hamilton Standard Division of United Technologies,

July 1978, p 5-3.

●

●

and are removed. These devices have high removal efficiencies but tend to clog if the water

contains suspended particles. They can also be

fouled by growth of micro-organisms on the

filter medium.

Air flotation is even more effective but is relatively complex. One device—the dissolved air

flotation cell—is shown in figure D-2. In this

separator, air is injected into the oily wastewater as fine bubbles, The oil droplets adhere

to the air bubbles and rise to the surface as a

froth, which is skimmed off by a motor-driven

rake, Some small suspended particulate contaminants can also be removed in the froth and

others will settle to the bottom of the cell and

can be removed as a sludge. Coagulant can

also be added to aid removal efficiency. If lime

is added, for example, it will precipitate some

heavy metals and certain anions such as carbonates.

Clarification [also called coagulation/sedimentation or precipitation/sedimentation) may be

used to settle out oil, to remove suspended

solids, or to precipitate toxic metals, carbonate, and other anions. A slant-tube clarifier is

shown in figure D-3. Accumulation of oil droplets and particulate on the tubes greatly enhances separation of the materials compared

with the performance of simpler gravity devices, Chemicals can also be added in an upFigure D-2.— Dissolved Air Flotation

OILY WATER

IN FLUENT WATER

DISCHARGE

OVER FLOW

DRIVEN SHUTOFF

RAK E

SOURCE: A

BACK PRESS . . —.

*a *a m I I I

o \

EXCESS

AIR OUT

LEVEL

CONTROLLER

ssessmentssessrnent ofOil Shale Retort Waste water Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-3.

63-898 0 - 80 - 32
490 ● An Assessment Oil Shale Technologies

Figure D-3.—Clarification and Precipitation

RAPID SEDIMENTATIO N

AND CONTINUOU S

GRAVITY DRAINAG E

.

.

CLARIFICATIO N

I

IN LET

MIX TANK

/

/ \

CLARIFIE R SIPHO N

SLUDGE COLLECTO R

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton

Standard Division of United Technologies, July 1978, p. 5-3

stream mixing tank to aid precipitation (such as

sodium hydroxide) or coagulation (such as alum

or a polyelectrolyte).

● Filters can be used to remove particles and in

some cases oil. Some of the more common filtering devices are shown in figure D-4. Pressure

filters are generally automatic devices in which

the contaminated water is sucked inwards

through a series of leaves on which a filter cake

forms. The filter may be used to remove particles from dilute wastewaters as the first stage

in a treatment system, or it can be used to dewater the sludge products from other separators. The filter cake is generally very low in

moisture, which eases disposal problems.

Vacuum filtration can also be used to remove

suspended particles from wastewater but is

more suitable for dewatering concentrated

streams and sludges. Two vacuum devices are

shown in figure D-4, In the rotary vacuum filter,

a rotating drum dips into a trough filled with

wastewater, and suction is applied to the inside

of the drum. Water is drawn through the perforated surface of the drum and solids are deposited on the outside as a filter cake. As the

drum rotates, the dewatered sludge is scraped

off and falls into a receiving trough. A filter

press is functionally similar except that the

wastewater is sucked or pumped through a

series of plate-and-frame assemblies. The de-

●

watered sludge is periodically removed from

the filter medium by mechanical cleaning. Ultrafiltration, in which the wastewater is forced

through a membrane, is often used for separation of oil and water. It is generally limited to

separation of chemically stabilized emulsions

and is not suitable for mechanical emulsions.

In multimedia filters, granular materials

such as sand forma filtering bed through which

the wastewater is pumped. The water passes

through a series of layers with granules of increasingly fine size, The collected solids are

subsequently removed by backflushing with

clean water. This filter produces a sludge,

rather than a dry cake, which requires additional dewatering before disposal. The multimedia filter is generally more economical than

pressure filters for high flow rates and dilute

slurries.

Stripping with steam (figure D-5) or with air or

flue gases is used to remove NH3 and sulfide

gases from wastewater. The operation is carried out in a packed column or a plate column,

and two-stage processing is sometimes employed to provide independent recovery of NH3

and sulfuric acid, If the stripper is part of a

treatment system that includes biological treatment, some NH3 is usually left in the stripper

product to act as a nutrient for the micro-organisms.
Appendix D–Technologies for Managing Point Sources of Wastewater . 491

Figure D-4.— Filters for Wastewater Treatment

I

A. Pressure filter

I

1’ -

I CYCL E

D. Filter press

B. Rotary vacuum filter

,“.. . “. .“ . . . .

OIL Y

“ . . . -. . , . : . . . . “. . ‘ . ,.

. . .

. . , . . .

. . . .~: ..,::,:::’ : ,

. . . . . . ~,~. . .

. , . . ,.

. .

Fmcc . . . : , ‘. . . “ “ , . wATCm “ “ . . . .-

: 

‘ : “

C. Ultrafiltration

I )

- - -

. . ~

cOA L

.,

A N

O I L

CO NCm NIRATa

E. Multimedia filtration

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, PP 5-4, 5-6,

5-11, and 5-12

“ .

Adsorption is used to remove dissolved metals, .

organic compounds, and many toxic substances. Adsorption with regenerated carbon

slurries and with resin particles is shown in

figure D-6. Other systems use activated carbon

particles that are contained in a fixed bed, either without regeneration or with regeneration

within the column. In all cases, the separation

involves physical adsorption of the contami- ●

nants on the surfaces of the particulat e

medium.

Distillation (figure D-7) is a simple process in

which wastewater is purified by boiling. The

products are a very clean steam, which can be

condensed with cooling water or in air-cooled

condensers, and a highly contaminated concentrate. Very pure water can be obtained, but the

process has large energy requirements. Cooling

water is also needed in most applications.

Reverse osmosis can also recover very pure

water from concentrated salt solutions. Some

dissolved organic materials can also be re-
492 ● An Assessment of Oil Shale Technologies

Figure D-5.—Steam Stripping

HEA T

INTER -

w ASTE W ATE R

V A PO R S

I

WATE R

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control

Technology, Hamilton Standard Division of United Technologies,

July 1978, p, 5-4

moved. A typical reverse osmosis system is

shown in figure D-8. Each element in the separation system contains a membrane that separates the clean product (permeate) from the

concentrated waste or residual. The membrane

is pressurized on one side, which forces the

pure water through the membrane and leaves

the salt and organic contaminants on the other

side. The process is very effective, but problems arise if the wastewater stream contains

very fine suspended solids (colloids) that can

clog the membranes and reduce their performance.

● Electrodialysis cells consist of an anode and a

cathode separated by two membranes—one

near the cathode through which cations (positively charged ions) can pass and one near the

anode that is permeable to anions (negatively

charged ions). A system consisting of several

such cells is shown in figure D-9. The wastewater is pumped between the membranes.

Upon application of an electric current, the anions migrate through one membrane towards

the anode and the cations migrate through the

other to the cathode. The concentration of ionic

species in the central chamber is thereby reduced. The concentrated streams beyond the

membranes are the waste products. Electrodialysis is very effective in removing dissolved

salts but it is very expensive because each

system must be specifically designed and manufactured for the particular application.

. Thickeners (figure D-1 O) are used between a

sludge-generating step (such as clarification)

and a sludge-dewatering step (such as vacuum filtration). These concentrate the sludge

●

●

●

through gentle agitation and thereby reduce

the amount of water that must be removed in

subsequent processes.

Evaporation (figure D-1 1) is a final step for concentrating solid residues. It is generally accomplished in evaporation basins, which are

simply lined ponds into which the sludge is

pumped and allowed to stand while the moisture evaporates, or in sludge drying beds,

which contain a layer of coarse sand over a

layer of fine sand over clay or perforated

plastic drainage tiles. Both systems require

large areas of land compared to other more

compact devices such as vacuum filtration but

they are inexpensive and require little maintenance. Sludge drying beds are faster but more

expensive. Both systems require mechanical

removal of the dried sludge, usually with a

backhoe or front-loader.

Chemical Methods

Ion exchange is a process in which ions held by

electrostatic charges on the surface of resins

are exchanged for ions with similar charges in

the wastewater. An example is a home water

softening system in which sodium ions (from

rock salt) are exchanged for calcium ions in the

water supply, thereby reducing the hardness of

the water. The process is classified as adsorption because the ion exchange occurs on the

surface of the resin particles and the ions to be

removed must undergo a change of phase: from

the liquid phase of the wastewater to the solid

phase of the resin. By this technique, harmful

ions in the wastewater can be exchanged for

the harmless ions of the resin. Ion exchange

can be used only for removing ions (such as

those from dissolved salts) from solution; it cannot be used for non-ionic contaminants such as

organic compounds and suspended solids. A regenerating ion exchange system is shown in

figure D-12. Such a system is suitable for recovery of valuable ions from dilute streams. It has

a limited capacity, thus would not be useful for

first- or second-stage salt removal but would

more likely be reserved for “polishing” a

treated effluent from another treatment technology.

Wet air oxidation was developed for destruction of organic contaminants. In this process

(see figure D-13), wastewater is exposed to air

under elevated temperature and pressure, thus

causing organic compounds to oxidize com-
Appendix D–Technologies for Managing Point Sources of Wastewater • 493

Figure D-6.—Adsorption Systems for Wastewater Treatment

ADSORPTIO N

IN FLUENT

W A STEW AT E R

REGENERATED CAR BON SLUR RY

I

TR E ATE D

EFFLUEN T

FIN ES

‘

REM OVA L

SCREEN

i

DEW ATE R I N G

SCREEN

REGENERATIO N

STORAG E F U RN ACE

REGENERATE D

CAR BON

SLURRY TANK S

FINES TO -

WASTE

A. Carbon adsorption with external regeneration

I

I TAN K

B. A two-tank adsorption system

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of

United Technologies, July 1978, pp. 5-4 and 5-6
494 ● An Assessment of Oil Shale Technologies

Figure D.7.– Distillation Figure D-8.– Reverse Osmosi s

CON DENsER WASTE WATER . . ●

FEE D

PREPROCESSIN G

FEE D WATER T O

DISCHARG E

OR REUS E

DRAIN TO WAST E

TAN K

PRODUCT WATE R

( PERMEAT E)

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies,

July 1978, p 5-7. Technology, Hamilton Standard Division of United Technologies,

July 1978, p. 5-7

Figure D-9.—Electrodialysis

OUTLET OF CONCENTRATION STREA M

OIL.

- 1 - -

CATHOD E

COMPARTMEN T

ANOD E

COMPARTMEN T

STREA M STREA M

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-7.
Appendix D-Technologies for Managing Point Sources Wastewater ● 495

FigureD10.- M echanical Sludge Thickening

BLAD E

CON D U I T COUNTER F LOW

TO MOTOR

DRIVE UNIT

\ \

!

N FLUE

CON D

OVER

ALA R

t

PLA N

BASE

HAN D R A I L

SOURCE: Assessment of Oil Shale Retort Waste Water Treatment anrd Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-9
496 ● An Assessment of Oil Shale Technologies

Figure D-11 .—Evaporation Systems for Sludge Drying

A. Evaporation pond

(

A

v

1

- -

I

- _&_ - .

- y~ -

PLA N WAL K

/

3-1 N COARSE-SAND

F

A

“OR

B. Sludge drying bed

United Technologies, July 1978, pp. 5-10 and 4-11.
Figure D-12. —A Regenerable Ion Exchange System

UNI T

EJECTO R

I

O U T L E-,

TO WAST E

S U PPORTING BED TAN K

SOURCE Assessment of 011 Shale Retort Wastewater Treatment and Control Technology, Hamilton

Standard Divlsion of United Technologies. July 1978, p 5-14

Figure D-1 3.— Wet Air Oxidation

R EACTO R

SEPARATOR I

AIR

HOLD I N G FEED HIG H

7A N K

A I R EXPANSIO N

COMPRESSOR ENGIN E

E X HAU ST

PUM P

SOURCE. Assessment of 0il Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p 5-14
498 ● An Assessment of Oil Shale Technologies

pletely or at least decomposing them into forms

that are more easily treated. In particular, the

process can be used to increase the biodegradable properties of compounds that are normally

refractory (resistant) to biological oxidation.

The method is very effective but is costly because the highly corrosive environment within

the equipment requires expensive materials

and construction methods.

Photolytic oxidation processes (figure D-14) use

light to oxidize organic contaminants. They can

be used in conjunction with chemical oxidizers.

One technique that works well in many industrial situations is the combination of ultraviolet

light and ozone gas. The process has the disadvantage of requiring relatively long residence

times.

Electrolytic oxidation is similar to electrodialysis except that it can be used to oxidize or

reduce dissolved contaminants to their gaseous

forms. A typical system is shown in figure D-15.

The method is costly to operate, and is generally reserved for removing very valuable or very

hazardous substances, It has been used with industrial wastewaters to remove, for example,

chromic acid and cyanide. In oil shale plants, it

could be employed for removing hazardous

organics.

Chemical oxidation relies on contacting wastewater with oxidizing chemicals. As mentioned

previously, chemical oxidation can be combined with other oxidizing systems. The example of ozone combined with ultraviolet light was

mentioned above. The chemical combination of

ozone and hydrogen peroxide has been found to

work well with refinery wastes, which are similar to the expected wastes from oil shale processing. Potassium permanganate has been

tested with oil shale streams.

Biological Methods

Anaerobic and aerobic digestion.-The principal anaerobic system is the anaerobic digester,

which is a closed, heated vessel in which the

microbial population is maintained under an atmosphere of its own waste gases. Such systems

have a long history of application in treatment

of municipal wastes. A typical digester is

Figure D-14.— Photolytic Oxidation

MIXE R

f

FIRS T

STAG E

SECON D

STAG E

G A S

TEMPERATUR E

CONTRO L

TEMPERATUR E

CONTROL
Appendix D–Technologies for Managing Point Sources of Wastewater Ž 499

Figure D-15.— Electrolytic Oxidation

CATHODE WATER

1

1

s

c

CATHOD E IN F I-U EN T

W ASTEWATE R

SETTLIN G

R

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies. July

1978, p 5-15

shown in figure D-16. The illustration shows a

flare stack for disposal of the digester gas. It is

also possible to use the gas for many industrial 2.

purposes. In municipal systems, the gas is used

as fuel for the compressors that maintain the

atmosphere within the unit. Some of the common aerobic biological systems, in which digestion takes place in an oxygen-rich atmosphere,

are described below,

1. Activated sludge processes treat waste

streams that contain 1 percent or less of suspended solids. In this process, flocculated

biological growths are continuously circulated in contact with organic wastewater in

the presence of oxygen. Organic compounds

that can be decomposed include polysaccharides, proteins, fats, alcohols, aldehydes, fatty acids, alkanes, alkenes, cycloalkanes, and

aromatics. The process is widely used for in- 3,

dustrial wastes and is even more common in

municipal treatment plants, It is relatively

inexpensive to fabricate and operate, and is

usually cost effective for a variety of organic

contaminants. Its major disadvantages are

complex control procedures and high maintenance and power requirements. A typical

activated sludge system is shown in figure

D-1 7,

Trickling filters are also commonly used for

municipal wastewater treatment. One system is shown in figure D-18. In this process,

the microbial population lives on the fixed

elements of the filtering medium, and the

wastewater trickles past them. Stones were

a common medium in the past; plastic is

more common today. Extra nutrients are

often added to the entering waste stream to

accelerate the biodegradation process. The

process requires relatively little land area

and can achieve high throughputs with the

proper adjustments of acidity, nutrients, and

trace chemicals. It does not work well if the

waste is chemically unstable or if it contains

suspended solids.

Aerated lagoons are similar to activated

sludge processes except that the micro-organisms are not circulated. The lagoons are

essentially stabilization ponds that are

equipped with mechanical agitators and

aerators to provide the microbial population

with uniform conditions and with the oxygen

that they need to grow. About 60 to 90 per-
500 ● An Assessment of Oil Shale Technologies

Figure D-16. —An Anaerobic Digestor

FLAR E

I

I

IN FLUENT SLUDG E

HEA T

EXCHANGE R

“1

MIXER S

SUPERNATAN T

SLUDGE EFFLUENT

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, pp. 2-12 to 2-24.

Figure D-1 7.—The Activated Sludge Process

IN F

I RECYCLED SLUDG E

the air. Biodegradation occurs very rapidly.

A unique advantage of RBCs is that different

strains of micro-organisms can be established on each of the disks, One strain could

be established on an upstream disk to remove the organic compounds that might be

harmful to another strain on a downstream

disk. This could not be done in other biological systems in which all micro-organisms are

exposed to essentially the same environment.
Appendix D–Technologies for Managing Point Sources of Wastewater ● 501

Figure D-18.—Trickling. Filter Waste Treatment

CHEM IC A L PH ADJUSTMEN T N I T ROG EN

& PHOSPHORU S

RAW WAST E

TRICK L 1 N G

FI LTE R

PR IM AR Y

CLARIFIE R

TR E A T E D

A I R W A S T EW A T ER

SEC ON D A R Y

SLU DG E CLARIFIE R

SOURCE Assessment of Oil Shale Retort Waste water Treatment and Contro/ Technology, Hamilton Standard Division of United Technologies,

July 1978 p 5-17

Figure D-19.—Aerated-Lagoon Waste Treatment

NUTRIENT FEE D

MECHANICAL AERATOR S

I N FLUEN T LIQUI D

\

EARTH CONSTRUCTION )

C LA F? 1 F I E R

EXCESS SLUDG E

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology. Hamilton Standard Division of United Technologies, July 1978 p

5-17

Figure D-20.— Rotating Biological Contractor

SE CON DAR Y SETTLING

I J

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies. July 1978, P

518
502 ● An Assessment of Oil Shale Technologies

Status of Point Source Water Pollution Control Methods

The removal efficiencies, reliabilities, adaptabilities, and cost features of some point source

control technologies are summarized in table D-1.

Removal Efficiency

All of the systems could perform adequately for

first-stage oil and grease removal, and meeting

discharge standards should be possible if a biological oxidation unit is used for final cleaning. If

not, single-stage cleaning in a coalescing filter

would be sufficient. For dissolved gases, any of

the stripping techniques should be adequate

alone, and a biological oxidation unit could be

used for final removal of any residual NH3

. For removal of organic compounds, carbon adsorption

would be suitable if used in conjunction with pretreatment and post-treatment systems. Photolytic

methods should also work, but they are not well

demonstrated. Any filtration method would reduce suspended solids to acceptable levels. For

dissolved inorganic, clarification would generally have low removal efficiency but could be suitable for removing metals. Distillation would be

very effective for salt removal. Ion exchange or

reverse osmosis would also work well, but their

limited capacities might restrict their use to final

removal of low-level contaminants. For sludges,

sludge drying beds and evaporation basins would

be very effective in the semiarid oil shale region.

The alternate processes would be much less effective.

Table D-1 .–Relative Ranking of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost

Oil and grease Dissolved air flotation 90 Very high Very high Medium

Coalescing filter 99 High High Medium

Clarification 80 Very high Very high High

Dissolved gases Air stripping 80 High -

High Medium

Steam stripping 95 Very high High Medium

Flue gas stripping High Medium Medium

Biological oxidation High Medium Medium Low

Dissolved organics Activated sludge

Trickling filter

Aerated lagoon

Rotating contactor

Anaerobic digestion

Wet air oxidation

Photolytic oxidation

Carbon adsorption

Chemical oxidation

Electrolytic oxidation

95 BOD/40 COD

85 BOD

80 BOD

90 BOD/20-50 COD

60-95 BOD

64 BOD/74 COD

99 BOD

99 BOD

90 BOD/90 COD

95 BOD/61 COD

High

High

Medium

High

High

Medium

Medium

Medium

Very high

Medium

Medium

Medium

Medium

Medium

Medium

High

Very high

High

Very high

Low

Low

Low

Low

Medium

Very high

Very high

Medium

High

High

Suspended solids Clarification 50 High High Medium

Pressure filtration 95 High High Medium

Multimedia filtration 95 Very high High Low

Dissolved solids Clarification Low except for metals High Medium Medium

Distillation 99 Medium Low Very high

Reverse osmosis 60-95 Medium Medium Medium

Ion exchange High High Low High

Electrodialysis 10-40 Medium Medium Very high

Sludges Thickening Product 6-8% solids Very high High Medium

Anaerobic digestion Low High Medium Medium

Vacuum filtration Product 20-35% solids High High High

Sludge drying beds Product 90% solids Medium Low Medium

Evaporation basins Product 95% solids Very high Low Low

Filter press Product 35% solids Very high High High

Aerobic digestion Low Low Low High

BOD = biological oxygen demand COD = chemical oxygen demand

Adapted from: Assessment of Oil Shale Retort Wastewater Treatment Control Technology, Hamilton Standard Division of United Technologies, July 1978, pp 2-12 to 2-24
—. —

Appendix D–Technologies for Managing Point Sources of Wastewater • 503

Reliability

For oil and grease removal, the coalescing filter

has the only potentially severe reliability problem

because it tends to clog. For dissolved gases, all of

the stripping techniques should be sufficiently reliable, Biological oxidation is considered less reliable because of the need for carefully controlled

inlet conditions. For organics removal, chemical

oxidation should be the most reliable; the biological systems (activated sludge, trickling filters, rotating contractors, and anaerobic digestion) should

also be satisfactory. All systems for removal of

suspended solids should be highly reliable, For

dissolved solids, clarification and ion exchange

are highly reliable. Distillation is downgraded

because of its potential for corrosion; reverse

osmosis because of potential fouling problems;

and electrodialysis because it has a relatively

short history of successful applications. For handling sludge, thickening, anaerobic digestion, and

all of the filtration techniques should be highly

reliable,

Adaptability

Few treatment techniques have been extensively tested with oil shale waste streams, and most

will be adapted directly from other industries.

Physical and chemical conditions in which a device will be expected to operate may differ significantly from those for which it was originally developed and in which it is normally operated. For

example, a method suitable for petroleum refineries may not work well in the oil shale industry

where it will be exposed to shale fines, organometallic complexes, or other contaminants peculiar to oil shale wastewaters. Although a system

cannot be fully evaluated until it has been tested

under commercial operating conditions, indications of the expected performance can be obtained by examining how easily the technique has

been adapted to other new industries significantly different from the one for which it was developed.

As shown in table D-1, all of the systems for oil

and grease removal are highly adaptable. For dissolved gases, air stripping and steam stripping

are highly adaptable; flue gas stripping is downgraded because suitable gases may not be available. Biological systems are downgraded because

they may have problems with the high NH3 concentrations in some oil shale wastewaters. They

could probably be used only with some pretreatment system. For dissolved organics, the oxidation systems and carbon adsorption are very

adaptable, the biological systems less so because

of potentially toxic substances and because they

are sensitive to inlet conditions. All methods for

removing suspended solids are highly adaptable.

However, problems may be encountered with the

removal of dissolved solids because of possible interference from high salt loadings or membrane

clogging. The only significant problem with distillation is its need for cooling water, which may not

be readily available at oil shale sites. For sludge

handling, thickeners and filters are highly adaptable. Sludge drying beds and evaporation ponds

should have no technical adaptability problems,

but they are downgraded because evaporation

would mean a loss of the contained moisture,

which could be recovered with filtration systems.

Aerobic digestion is downgraded because some of

the components of oil shale sludges may resist biological degradation.

cost

Costs in table D-1 are based on experience with

similar systems in other industries. As indicated,

systems with moderate capital and operating

costs are available for all of the major contaminants, and many of the lower cost options also

have reasonable removal efficiencies, reliability,

and adaptability. The only potentially serious

problem is in removal of dissolved solids, where

the medium-cost systems (reverse osmosis and

clarification) have questionable removal efficiencies.
504 Ž An Assessment of Oil Shale Technologies

Integrated Wastewater Treatment Systems

Generally, no one device is able to remove all

the contaminants from a process stream, Furthermore, certain process streams may be combined

before treatment or at different stages of treatment to take advantage of scale economies.

Treatment systems that have been proposed for

oil shale wastewater streams are shown in figure

D-21 for mine drainage water, figure D-22 for gas

condensate, and figure D-23 for retort condensate. These systems and their component units

are discussed below.

Excess Mine Drainage Water

This water can be used without treatment as a

slurry medium for backfilling burnt out in situ

retorts,’ but sufficient ground water may not be

available over the lifetime of the plant for this

control option. Additional water might have to be

imported from other sites. Another disposal option is reinfection, but for this purpose the water

should be free of suspended solids and contain no

constituents that would react adversely with the

water in the receiving strata. 5 6 7 While min e

drainage water could easily be treated to meet

these requirements, reinfection is a costly disposal option, because deep wells would be required to avoid contamination of aquifers that

discharge to the surface, and an extensive piping

network would be needed. It has been suggested

that the reinfection option be used only for very

objectionable and relatively untreatable wastes

and that underground disposal of the relatively

clean mine drainage water would be wasteful in a

region where water is scarce. 17 18

For the option of discharge to a river, dissolved

solids would have to be reduced to less than 500

mg/l, which can easily be achieved by a membrane process such as reverse osmosis, as shown

in figure D-21. Treatment is not expected to be difficult, but conclusive test data are not yet available. 19 Discharge permits will probably also specify a phenol concentration of no more than 0.001

mg/1 and a boron concentration of less than 0.75

mg/1. Specific ion absorbents are available for

these substances and can be used, as suggested in

option A of figure D-21. Alternatively, a secondstage reverse osmosis step may prove more economical, as suggested in option C of figure D-21. A

single-stage, high-pH reverse osmosis step may

also prove adequate, particularly if some of the

Figure D-21 .—Possible Treatment Options for Excess Mine Drainage

Option A

(Reference 8)

Option B

(Reference 9)

Spent Shale

Mine Backfill to burned

water out MIS retorts

-r

Mine Pretreatment Reverse

*

Phenol Boron Aerated

holding pond Discharge

osmosis adsorption adsorption

Option C

(Reference 9)

Sodium hydroxide

1

Mine Pre- 9

Stage 1 reverse Stage 2 Aerated

m

pH Discharge

m reverse osmosis adjustment holding

osmosis pond stream

Option D Mine

●

Weak acid

*

Steam pH

m

Reverse ●

Aerated Discharge

ion exchange stripping Adjustment osmosis holding pond

(1-wk retention) stream

SOURCE R F Probstein, H. Gold, and R. E Hicks, Wafer Requirernents, Pollution Effects and Costs of Water Sq@y and Treafrnerrt for the Oi/ Sha/e /rrdustry, prepared

for OTA by Water Purificatlon Associates, October 1979
Appendix D–Technologies for Managing Point Sources of Wastewater Ž 505

Figure D-22.— Possible Treatment Options for Gas Condensates

Option A

(Reference 10)

Steam

Gas Oil-water stripping Biological Organic Cooling

condensate separation & NH3

oxidation polishing

(if required) Tower

recovery

Option B ●

(Reference 11)

●

● .

Filter Stream

Gas stripping Chemical Biological & oil-water Filter

condensate & NH3

treatment separation oxidation

recovery

.

Desalinization Carbon

sorption

SOURCE R F Probstetn H Gold and R E Hicks, Wafer RequirementsReaufrernenfs, Po//utIorI Effects and Cosfs of Wafer Supp/y and Treatrnenf for the 0// Shale Industry, prepared

for OTA by Water Purification Associates, October ’1979

dissolved salts are first removed by chemical pretreatment in a weak acid ion exchange degasifier

as shown in option D of figure D-21,

An aerated holding pond would be used in any

of the options to dissipate any NH3 and phenol

that are not removed in the treatment units. The

pond would also serve as an equalization basin

for blending in waters that can bypass the treatment train. The size of the bypass stream will

vary with the quality of the drainage water, the

effectiveness of the aeration pond, and the criteria of the discharge permit.

Gas Condensate

This stream requires treatment for removal of

dissolved gases and organics. Dissolved NH3 will

largely be combined with CO2 in the form of ammonium bicarbonate. Both gases can easily be removed by steam stripping. Stripping has been

tested in the laboratory with both a synthetic ammonium bicarbonate solution and an actual gas

condensate. 20 21 It was found that the small

amount of oil present in the condensate was rapidly removed in the stripping operation, but even

if an oil-water separator is required before the

stripper (as suggested in figure D-22) separation

difficulties due to emulsification are not expected.

Organic control by biological oxidation has not

yet been demonstrated on an actual gas condensate stream, The organic mix is different from

that of retort condensates and may prove to be

more or less amenable to biodegradation. Other

processes such as resin adsorption, carbon adsorption, and wet air oxidation are available for

organics control and may prove adequate in combination. Preliminary laboratory investigations on

retort condensates suggest that no single process

(except possibly wet air oxidation) will be capable

of controlling all the organics present.

The use of a cooling tower as part of the treatment systems (as shown in option A of figure D-22)

would have two advantages. First, experience

with similar wastewaters has shown that some

degradation of organics occurs in a properly

operated cooling tower circuit. 22 Second, the volume of blowdown water leaving the cooling tower

is one-half to one-tenth that of the makeup water,

depending on the number of concentration cycles

used. Final organic polishing, if necessary, can

therefore be done on a smaller, more concentrated stream. Because the wastewater stream

will previously have been subjected to high-temperature steam stripping, air pollution by volatilization of organics in the cooling tower is not expected to be a problem. This assumes that any organics created in the biological oxidation step will

be either nonvolatile or nontoxic.

Although salts are not a major contaminant in

the gas condensate stream, desalination by reverse osmosis could be used to remove inorganic

and organics. In option B of figure D-22, a desalination step is included to provide a very clean discharge stream. An effluent stream could also be
Figure D-23.— Possible Treatment Options for Retort Condensates

Option A

(Reference 12)

Option B

(Reference 13)

Retort

condensate*

Filter & Lime treatment Activate

oil-water & ammonia *

carbon

separation removal sorption

Retort Thermal

condensat e

>

treatment sludge

1

Boiler makeup

Sludge

r

Option C Retort

Discharge or re-use

(References 14, 15) condensate >

treatment

●

I

Concentrate Evaporation pond

Option D

(Reference 16)

● ✎ ☛ ✌

Retort API Chemical Dissolved Steam air Multimedia Biological Ultra

separator treatment flotation stripping filtration treatment filtration

● ●

Carbon Ultraviolet

filter sterilizer I

SOURCE: R. F. Probstein, H. Gold, and R. E. Hicks, water Requirement, Pollution Effects and Costs of Water Supply and Treatment for the Oil Shale Industry, prepared for OTA by Water Purification Associates,

October 1979.
Appendix D–Technologies for Managing Point Sources of Wastewater • 507

taken from any intermediate stage of the treatment system to provide water for various reuse

options.

Retort Condensate

The retort condensate stream presents the

most formidable treatment challenge. As discussed in chapter 8, this stream is created when

water and oil vapors condense within in situ

retorts, and some aboveground retorts if they are

operated at a low top temperature. The condensate will be contaminated with oil, dissolved

gases, inorganic salts, and organic substances, all

of which will have to be removed.

In the conventional treatment scheme of option

A in figure D-23, oil and suspended solids are first

separated from the water. Oil-water separation

by API units may not be adequate because of

emulsions, and some emulsion-breaking technique

will probably be required. The techniques that

would be appropriate for oil shale wastewaters

have not yet been determined.

The addition of lime will facilitate NH3 removal

and will also remove calcium, magnesium, and

carbonate ions. NH3 is easily removed by steam

stripping, but unlike the gas condensate, the retort condensate contains strong acid anions that

will “fix” the NH3 as ammonium ions, which cannot be directly stripped. Lime addition will elevate the pH and convert ammonium to NH3

.

23 T h e

pH elevation is also needed to prevent scaling and

fouling of the steam stripping column by carbonate precipitates.

Removal of organic substances from retort condensates has not been adequately demonstrated.

Activated carbon adsorption (option A in figure

D-23) would remove only about half of the organics and would be expensive, given the high organic concentrations found in retort condensates. 24 2 5

Biological treatment (option D) has been suggested for control of organics, but complete removal by biological processing may not be achievable. The two major problems with biological

treatment are the presence of resistant (biorefractory) and toxic materials. It is expected that

as much as half of the organic matter in retort

water will be biorefractory and that adequate removal may not be possible even with novel process modifications such as the addition of powdered activated carbon to the biological unit. Laboratory tests have shown that the addition of powdered activated carbon to the aeration basin in an

air-activated sludge biological system improves

organics removal by only about 10 percent, indicating that much of the biorefractory organic

matter is not adsorbed on carbon. Polymeric resins have been shown to facilitate removal of organics from retort condensates,

26 but it is not

known whether the ones removed are those that

are resistant to biological and activated carbon

treatment.

The inhibition of biological action by toxic substances is also expected to be a problem, The toxics may be either organic or inorganic, and can be

expected to be different in the condensates from

different retorts. Their characteristics and concentrations may even change with time if retorting conditions are not constant—a normal situation in MIS processes. Even with all of its potential disadvantages, biological oxidation could

prove more economical and more effective than

other processes (such as wet air oxidation) when

combined with appropriate pretreatment and polishing steps.

Wet air oxidation removes a much wider variety of organics but it is also more expensive. In this

process, organic material in water is oxidized by

air at about 500° F (260° C). The water is pressurized to prevent boiling. The reaction takes about

30 minutes and a pressure vessel is required that

is large enough to contain the water for this

length of time. The cost of wet oxidation is not

strongly dependent on the concentration of the

waste, and unlike biological treatment it can be

cost effective for very concentrated wastes. Wet

air oxidation also has several technical advantages, Because it relies on chemical oxidation, the

organic material that is to be destroyed does not

have to be biodegradable. In fact, biorefractory

materials are often converted to biodegradable

substances, and a biological process could be effectively used as a polishing step. No data have

been published on the performance of a wet air

oxidation process with oil shale retort condensates, but an investigation has been initiated. 27

Reverse osmosis membranes (option C in figure

D-23) are also available for organics control,28 but

recent tests have shown that considerable pretreatment will be required to provide a feed that

will not plug or foul the membranes, 29 In fact, a

pretreatment system similar to the treatment

train of option A in figure D-23 may be required

for very dirty condensates. If this is done, then it

is not clear that a final reverse osmosis step will

be required to provide an effluent suitable for

some of the low-quality reuse options. Nevertheless, reverse osmosis is of interest because it also

provides a means for control for some of the inor-
508 ● An Assessment Oil Shale Technologies

ganic contaminants for which lime softening is not

adequate. Ion exchange demineralization after

organics removal is an alternative to reverse

osmosis, but its costs escalate rapidly with increasing salt concentrations in the feed.

It is apparent that even if the retort condensate

is to be treated to only the low-quality levels required by some re-use options, an elaborate treatment system similar to that shown as option D in

figure D-23 will be required. Even here additional

treatment steps may be required. API separators

may not be adequate, and an ultrafiltration step

upstream of the steam stripper may be needed to

remove emulsified oil and large organic molecules. As discussed above, biological oxidation

and carbon adsorption will not adequately control

the remaining organics, and resin adsorption or

wet air oxidation steps may be required. An additional processing step to remove inorganic may

also be required for some re-use options.

In view of the difficulty in treating the retort

condensate (option B in figure D-23) in which the

treated water is used to raise steam for retorting

is the most attractive. Volatilized organics will be

incinerated in the retort, and other substances

can be removed in a concentrated sludge for disposition at a hazardous-waste disposal site. A

stripping pretreatment step may be needed to

avoid accumulating NH3 and CO2 in the thermal

sludge device. No information has been published

on the feasibility of a thermal-sludge steam raising process fed with retort condensates. Scaling

and fouling may be problems unless appropriate

pretreatment steps are used.

Other Wastewater Streams

The two other major streams are the coker and

hydrotreater condensates from the shale oil upgrading section. Compositions of these streams

are not known, but they should be somewhat similar to the gas condensate. The exception is the

concentration of dissolved gas because, in the

absence of CO2

, the NH3 will probably react with

H2S to form ammonium hydrogen sulfide. Different steam stripping conditions will be required in

that more stages or more steam will be needed to

remove H2S. Modifications should not be extreme

because, unlike in the retort condensate, there

should be no NH3

-fixing inorganic anions present.

The treatment systems can be expected to be similar to any of the options shown in figure D-22.

Blowdown streams, regenerant streams, concentrates, and sludge products from water treatment processes must also be handled. If a thermal

sludge process is included in any water treatment

train, it could be used to reduce the reverse

osmosis concentrates and ion exchange regenerant streams to a disposable sludge. If not, vapor

compression evaporators may be used. These

have been successfully demonstrated on a commercial-scale at, for example, electric power generating stations. Because cooling towers will

probably be operated with few cycles of concentration, blowdown streams should not have high

salt concentrations, and should be suitable for

dust control and shale disposal operations.

Water Management Plans for Oil Shale Facilities

Complete water management plans must consider supply, treatment, waste recovery and removal, and ultimate disposition. Figures D-24

through D-26 are flow sheets that show how water would be used, treated, and disposed of in

three typical oil shale facilities. The flows into,

within, and out of the plants are indicated in gallons per minute.

Figure D-24 is a water management plan for an

aboveground direct facility that uses Paraho retorts. The major sources of water are the Colorado River, contaminated runoff from the facility

site and its associated disposal area, and gas condensates from the retorting section. No upgrading

facilities are included, so there are no upgrading

condensates. The total water inflow is 2,357 gal/

rein, of which about 40 percent is lost to the atmosphere through evaporation within the facility.

The rest is eventually used for dust control and in

the solid waste disposal area for spent shale

moistening, compaction, and revegetation. The

principal components of this water are treated

river water, sanitary wastes, blowdowns, runoff,

service water, and condensates.

Figure 1)-25 is a plan for an aboveground indirect plant that uses TOSCO II retorts. Because

the retorts are indirectly heated, and because upgrading facilities are included, water requirements are substantially higher than for the Paraho plant. The total inflow is 7,386 gal/rein from

the Colorado River, from surface runoff, and from

gas condensates and upgrading condensates.
Appendix D–Technologies for Managing Point Sources of Wastewater ● 509

Figure D-24.— Major Streams in a 50-000-bbl/d Aboveground Direct (Paraho) Oil Shale Plant (gal/rein)

Colorado River water

1883

(7)

Domestic

water

system / ●

@

16

Biological

treatment

663 686 Clarification

I

BFW ~ CW

treatment -

treatment

I

17

(2)

Steam

system

BD

Cooling

tower

B D

BFW = Boiler Feed Water

CW = Cooling Water

( ) = Losses

s = Sludge

TW = Treater Waste

BD = Blowdown

GC = Gas Condensate

Revegetation Dust Shale

control disposal

(25) 221 791

Equalization

43

water

system &

Oil/water 156

separation

b

Runoff and 138

Ieachates

(29)

Retorting 336 307

gas treatment GC Treatment

— \

SOURCE R F Probsteln, H Gold, and R E Hicks, Water Requlrerrrents, Po//ufIon

Eflects and Costs of Water SUPP/y and Treatrrrent for the 0// Shale /fldustry, prepared for OTA by Water Purl flcatlon Associates, October 1979

About 40 percent of the water is lost through

evaporation. The rest is eventually used for dust

control, or finds its way to the spent shale pile.

Figure D-26 is a plan for an MIS facility that is

located in a ground water area, Excess mine

drainage water is produced, and over 70 percent

of it is reinfected. The rest is used in the plant,

together with retort condensates, gas condensates, and surface runoff, The plant uses a thermal sludge system to process the retort condensate and to generate steam for injection into the in

situ retorts. The system produces no liquid effluent. The total net inflow is about 5,059 gal/rein, of

which 34 percent is lost through evaporation and

34 percent is converted to steam for the retorts.

The rest is used to control dust and for disposal of

the mined raw shale.

In summary, the aboveground direct plant will

dispose of about 604 gal/min of treated wastewater and treated condensates in the spent shale

disposal pile. An additional 22 I gal/rein of treated

wastewater will be used for dust control. The
510 Ž An Assessment of 0il Shale Technoiogies

Figure D-25.—Major Streams in a 50,000-bbl/d Aboveground Indirect (TOSCO II) Oil Shale Plant (gal/rein)

Colorado River water

2177 2198 3937

Clarification

water

system

Biological

treatment

1

BFW ~

treatment

(1191)

Steam

system

2400

Cw

treatment

(1630)

Cooling

tower

BD

Revegetation Dust Shale

control disposal

w

Retorting

gas treatment

upgrading

GC

1072 ~ (53)

Stripping and

N H3 recovery (6)

503 Organics 497

(20) removal.

/

631

17

water .

3 7 system Oil/water 134

r separation

\

Runoff and 117

Ieachates

/ v

BFW = Boiler Feed Water

CW = Cooling Water

( ) = Losses

S = Sludge

TW = Treater Waste

BD = Blowdown

GC = Gas Condensate

RC = Retort Condensate

SOURCE: R. F. Probstein, H. Gold, and R. E. Hicks, Water Requ/refnenrs, PollutlorrEflecfs afl~ COS@ of water SUPPIY and Treatment for the 0// Shale hrdustry, prepared

for OTA by Water Purification Associates, October 1979.
Appendix D–Technologies for Managing Point Sources of Wastewater Ž 511

To reinfection

Figure D-26.— Major Streams in a 50,000-bbl/d MIS Oil Shale Plant (gal/rein)

Mine drainage water

7656

treatment

924

14

Biological

treatment

14

380

(13)

m

6539 ‘ ‘ 737

Y

A A Clarification

(5)

treatment treatment

Cooling

tower

Steam

system

882

w L

Revegtation Dust Shale

control disposal

(26) Equalization

-

42

water

system \

Oil/water 141

separation

\

Runoff and 125

4

(68)

\

( ) = Losses

s = Sludge

SOURCE: R.F. Probstein, H Gold, and R E Hicks, Water Requirements, Pollution Effects and Costs of Water Supply and Treatment for the Oil Shale Industry, prepared

for OTA by Water Purification Associates, October 1979
512 Ž An Assessment of Oil Shale Technologies

aboveground indirect plant will add about 1,827

gal/rein of treated wastewater and concentrates

to the disposal pile. The MIS plant will use about

686 gal/rein of treated wastewater for raw shale

disposal and 210 gal/rein for dust control An

additional 5,554 gal/rein of treated mine drainage

water will be reinfected into the source aquifer.

Thus, the methods for wastewater management

and disposal are recycling after treatment, followed by disposal through evaporation, in dust

control, and in solid waste disposal areas. Excess

treated mine drainage water will be reinfected.

Appendix D References

1H, P. Harbart and W. A. Berg, Vegetative Stabilization of Spent Oil Shales, EPA-600/7-78-021, Industrial

Environmental Research Laboratory, Environmental

Protection Agency, Cincinnati, Ohio, February 1978.

21bid.

‘T. R. Garland and R. E. Wildung, “Influence of Irrigation and Weathering Reactions on the Composition of

Percolates from Retorted Oil Shale in Field Lysimeters, ” Proceeding of the Twei~th Oil Shale Symposium

(J, H. Gary, cd.), Colorado School of Mines, Golden,

Colo., August 1979.

4Rio Blanco Oil Shale Project, Revised Detailed DeveL

opment Plan; Tract C-a, submitted to Area Oil Shale Supervisor, U.S. Geological Survey, Department of the Interior, May 1977.

‘E. F. Bates and T, L. Thoem (eds.), PoJJution Control

Guidance for Oil Shale Development, revised draft report, Environmental Protection Agency, Cincinnati,

Ohio, July 1979.

‘B. W. Mercer, et al., “Assessment of Control Technology for Shale Oil Wastewaters, ” paper presented at

Environmental Control Technology Symposium, Department of Energy, November 1978.

7N. de Nevers, et al., Analysis of the Environmental

Control Technology for Oil Shale Development, Department of Energy, report No. COO/4043-1, February 1978.

‘Supra No. 4.

‘Denver Research Institute, Predicted Costs of Environmental Controls for A Oil Shale Industry: VoJume 1—

An Engineering Analysis, prepared for the Department

of Energy under contract No. EP-78-S-O2-51O7, July

1979,

‘

OIbid.

“G. W. Dawson and B. W, Mercer, “Analysis,

Screening and Evaluation of Control Technology for

Wastewater Generated in Shale Oil Development, ”

Quarterly Reports, Battelle Pacific Northwest Laboratory, Richmond, Wash,, January 1977-March 1979.

12A. B. Hubbard, “Method for Reclaiming Wastewater From Oil Shale Processing, ” American Chemical

Society, Division of Fuel Chemistry Reprints, vol. 15, No.

1, March-April 1971, pp. 21-25.

1

3 Supra No. 9.

14A. E. Fry andR. S. Martin, Assessment Of pOllLItiOIl

Control Costs for Emerging Energy Supply Technologies

—Subtask 11—Modified In Situ Oil Shale Retorting, Department of Energy, final report, contract No. EE-77-

C-02-4534, NOV. 20, 1978.

15A. Brown, et al., Water Management in Oil Shale

Mining: Volume 1, NTIS report No. PB-276085, Golder

Associates, Inc., Seattle, Wash., September 1977.

“Supra No. 5.

‘

7 Supra No, 6.

“R. E. Hicks and R. F. Probstein, “Water Management in Surface and In Situ Oil Shale Processing, ”

paper presented at AIChE 87th National Meeting,

Boston, Mass,, Aug. 19-22, 1979.

‘

gWater Purification Associates, A Study of Reverse

Osmosis for Treating Oil Shale Process Condensates

and Excess Mine Drainage Water, quarterly progress

report, prepared for Laramie Energy Technology

Center, Department of Energy, contract No. DE-AC20-

79LC1OO89, September 1979,

ZOA, L. Hines, The Role of Spent Shale in Oi] SMe

Processing and the Management of Environmental Residues, Department of Energy, report No. TID-28586,

ERDA-Laramie Energy Research Center, Laramie,

Wyo., Apr. 1, 1978.

‘lSupra No, 19.

“D. J. Goldstein, 1, W. Wei, and R. E. Hicks, “Reuse of

Municipal Wastewater as Makeup to Circulating Cooling Systems, ” presented at Water Reuse Symposium,

American Water Works Association, Research Foundation, Washington, D. C., Mar. 25-30, 1979, pp.

371-397. Also: Industrial Water Engineering, vol. 16,

No. 4, July 1979, pp. 20-29.

23Water Purification Associates, A Study of Aerobic

Oxidation and AJlied Treatments for Upgrading In Situ

Retort Waters, contract No, EW-78-C-20-0018 with

Laramie Energy Technology Center, Department of

Energy, quarterly status report, August 1979.

24 Supra No. 19.

25B. Harding, et al., “Study Evaluates Treatments for

Oil-Shale Retort Water, ” Industrial Wastes, September/October 1978, pp. 28-33.

2bIbid.

Z7D. Vernados, I&earch and Development Department, Amoco Oil Co., Naperville, Ill., personal communication, August 1979.

26 Supra No, 15.

2gSupra No. 19.
APPENDIX E

Acronyms, Abbreviations, and Glossary

acre-ft

acre-ft/yr

AGR

API

AQCR

ARCO

BACT

BaP

BAT

bbl

bbl/d

BLM

BOD

BPT

Btu

cm

cm/h

co

co2

COS

CRS

CRSP

CRSS

CS2

CWACOG

CZMA

DDP

DEI

DLA

DNR

DOD

DOE

DOI

DRI

EIS

EPA

ERDA

FAPRS

Acronyms and Abbreviations

—acre-feet

—acre-feet per year

—aboveground retorting

—American Petroleum Institute ‘

—Air Quality Control Regions

—Atlantic Richfield Co,

—best available control technology

—benzo(a)pyrene

—best available technology

—barrel(s)

—barrels per day

—Bureau of Land Management,

Department of the Interior

—biochemical oxygen demand

—best practicable control

technology currently available

—British thermal unit

—centimeter

—centimeters per hour

—carbon monoxide

—carbon dioxide

—carbonyl sulfide

—Congressional Research Service

—Colorado River Storage Project

Act of 1956

—Colorado River System Simulation

Model

—carbon disulfide

—Colorado West Area Council of

Governments

—Coastal Zone Management Act

—detailed development plan

—Development Engineering, Inc.

—Department of Local Affairs

(Colorado)

—Department of Natural Resources

(Colorado)

—Department of Defense

—Department of Energy

—Department of the Interior

—Denver Research Institute

—environmental impact statement

—Environmental Protection Agency

—Energy Research and Development

Administration

—Federal Assistance Program

Retrieval Systems

FLPMA

FmHA

FMSHA

FRC

ft

ft2

ft3

FUND

FWPCA

gal

gal/rein

gal/ton

GOREDCO

HC

HEW

H2S

IFS

JBC

mg/l

mg/m3

mi2

MIS

mm

mmho/cm

MSHA

μg

μg/m3

NAAQS

NAS

NEPA

NH3

NIOSH

NOX

NOSR

—Federal Land Policy and

Management Act of 1976

—Farmers Home Administration

—Federal Mine Safety and Health

Amendments of 1977

—Federal Regional Council

—feet

—square feet

—cubic feet

—Foundation for Urban and

Neighborhood Development

—Federal Water Pollution Control

Act of 1972

—gallon

—gallons per minute

—gallons per ton

—Gulf Oil Real Estate Development

coo

—hydrocarbons

—Department of Health, Education,

and Welfare

—hydrogen sulfide

—Institute Francais du Petrol

—Joint Budget Committee of the

General Assembly (Colorado)

—milligrams per liter

—micrograms per cubic meter

—square miles

—modified in situ

—millimeters

—milliohms per centimeter

(conductivity)

—Mine Safety and Health

Administration

—megawatt

—microgram

—micrograms per cubic meter

—National Ambient Air Quality

Standards

—National Academy of Sciences

—National Environmental Policy Act

of 1969

—ammonia

—National Institute for

Occupational Safety and Health

—nitrogen oxides

—Naval Oil Shale Reserve

513
514 ● An Assessment of Oil Shale Technologies

NPC

NPDES

NSPS

O3 OCS

OMB

OSEAP

OSHA

Oxy

PADD 2

PAHs

Pb

p/m

POM

PSD

QDA

Quad

RARE II

RCRA

R&D

—National Petroleum Council

—National Pollutant Discharge

Elimination System

—New Source Performance

Standards

—Nevada, Texas, and Utah

—ozone

—Outer Continental Shelf

—Office of Management and Budget

—Oil Shale Environmental Advisory

Panel

—Occupational Safety and Health

Administration

—Occidental Petroleum

—The Petroleum Administration for

Defense District 2

—polycyclic aromatic hydrocarbons

—lead

—parts per million

—polycyclic organic matter

—prevention of significant

deterioration

—Quality Development Associates

—1 quadrillion = 1015 Btu

—Roadless Area Review and

Evaluation (Forest Service)

—Resource Conservation and

Recovery Act of 1970

—research and development

RISE

scf

SCOT

SEIO

SIP

SMCRA

SMR

so,

SOHIO

SRI

TDS

TIS

ton/d

Tosco

TSCA

UBCOG

USBM

USBR

USFWS

USGS

USPHS

WPA

WPRS

—rubble in situ extraction

—standard cubic foot

—Shell Claus Offgas Treating

process

—Governor’s Socio-Economic Impact

Office (Colorado)

—State implementation plan

—Surface Mining Control and

Reclamation Act of 1977

—standardized mortality ratio

—sulfur dioxide

—Standard Oil Co. of Ohio

—Stanford Research Institute

—total dissolved solids

—true in situ

—tons per day

—The Oil Shale Corp.

—Toxic Substances Control Act of

1976

—Uintah Basin Council of

Governments

—U.S. Bureau of Mines

—U.S. Bureau of Reclamation

—U.S. Fish and Wildlife Service

—U.S. Geological Survey

—U.S. Public Health Service

—Water Purification Associates

—Water and Power Resources

Service

Adit: A nearly horizontal opening to a mine. Calcite: The mineral calcium carbonate, found in

Aquifer: An underground formation containing

water.

Aromatic hydrocarbon: A compound of carbon

and hydrogen characterized by a ring of six

carbon atoms, e.g., benzene.

Best available control technology (BACT): The

most advanced control technology that can be

used for new sources of pollution. Required for

nonattainment regions (where air pollution presents a danger to the public health) by the

Clean Air Act as amended in 1977.

Biochemical oxygen demand: A chemical measure

of the power of an effluent to deoxygenate

water.

Bitumen: The smaller (about 10 percent) soluble,

organic component of oil shale.

Breakeven price: The constant price at which

shale oil syncrude would just earn its minimum

rate of return.

nature in the form of limestone, marble, or

chalk.

Catalytic cracking: A process of breaking down

petroleum hydrocarbons by heating them in the

presence of a catalyst. The products are hydrocarbons of lower molecular weight, having

lower boiling points, e.g., gasoline.

Coking: One of the processes used to upgrade

shale oil and improve its transportation properties. The oil is thermally decomposed at high

temperatures (900° to 980° F or 480° to 525° C)

forming coke as a solid product.

Criteria pollutants: Under the Clean Air Act, the

reduction and prevention of air pollution is regulated by measuring five criteria pollutants:

particulate, sulfur oxides, carbon monoxide,

nitrogen dioxide, and photochemical oxidants.

National Ambient Air Quality Standards were

developed for six pollutants associated with the
Appendix E–Acronyms, Abbreviations, and Glossary • 515

criteria pollutants. Sulfur oxides are measured

by sulfur dioxide and photochemical oxidants

are measured by ozone and hydrocarbons,

Crude short: The condition when a company has

limited or inadequate access to crude petroleum.

Dawsonite: The mineral, dihydroxy sodium aluminum carbonate. It is a potential source of alumina, which can be converted to aluminum.

Deposit: A natural accumulation, e.g., of coal,

iron ore, or oil shale.

Deposit dewatering: The removal of ground water

from an oil shale deposit.

Distillates: The liquid products condensed from

vapor during distillation (as of petroleum),

Light distillates contain the lowest boiling

constituents of the petroleum, from which gasoline is produced.

Middle distillates contain higher concentrations of the high boiling constituents, from

which diesel and jet fuels are produced.

Heavy distillates contain higher concentrations of the high boiling constituents, from

which lubricating and residual oils are produced.

Distillation: A separation process in which a substance is vaporized, and the vapor collected

after condensation as a liquid.

Diversion: A channel constructed to divert water

from one source or body of water to another.

Interbasis diversion-Moving water from

one major hydrologic basin to another.

Intrabasin diversion—The redistribution of

water within a major hydrologic basin.

Dolomite rock: Similar to limestone but composed

mainly of the mineral, calcium magnesium carbonate (Ca Mg (CO3

)2).

Electrostatic precipitator: A device that uses an

induced electrical charge to recover fine particles from a flowing gas stream.

Environmental impact statement (EIS): The National Policy Act of 1969 requires that an environmental impact statement be prepared for

“major Federal actions significantly affecting

the quality of the human environment.”

Fischer assay: Small samples of crushed oil shale

are heated to 932° F (500° C) under carefully

controlled conditions. The oil yield by this

method is the standard measure of oil shale

quality.

Fracturing: Breaking up a deposit by means of

chemical explosives, electricity, or injecting

high-pressure air and water to increase its permeability to fluid flow.

Fugitive dust: Particulate matter discharged to

the atmosphere in an unconfined flow stream.

Gas oil: A liquid petroleum distillate with a viscosity and boiling range between kerosene and lubricating oil (450° to 500° F or 230° to 260° C).

Ground water aquifer: Water contained underground in the interstices of soil and rock, obtainable through wells or springs.

Halite: The natural mineral form of sodium

chloride (NaCl).

High-Btu gas: Gas with a high heating value, e.g.,

pure butane has a heating value of 3,20 0

Btu/ft 3.

Hydrocarbons: Organic compounds containing

only carbon and hydrogen.

Hydrocracking: The breaking apart of relatively

heavy petroleum hydrocarbons into smaller,

lighter molecules by means of heat in the

presence of hydrogen and using specia l

catalysts.

Hydrologic basin: The entire area of land drained

by a river and its tributaries.

Hydrotreating: The hydrogenation of crude shale

oil to convert it to -synthetic crude oil (syncrude).

Kerogen: The organic oil-yielding material present in oil shales. It is not a definite compound

but a complex mixture varying from one shale

to another, and is only slightly soluble in ordinary organic solvents,

Low-Btu gas: Gas with a relatively low heating

value (about 100 Btu/ft3

), e.g., producer gas,

Locatable minerals: Minerals on public land that

can be transferred to private ownership by the

process of staking claims and filing for patents.

Marlstone: A hardened mixture of dolomite and

calcium carbonate.

Middle distillate cracking and reforming: Breaking down and converting straight chain petroleum hydrocarbons into cyclic and aromatic hydrocarbons, by means of heat, pressure, and

catalysts (usually in the presence of hydrogen).

Used to produce fuels with high octane rating

from lower grade products.

Mining:

Block caving—Sections of the area being

mined are undercut and then allowed to cave

in, thus crushing the material being mined.

Continuous—A machine cuts and loads ore

from a mine face in a continuous operation,

without the use of drills and explosives.

Long-wall—The ore seam is removed in one

operation along a working face that maybe several hundred yards long. The mine roof col-
516 • An Assessment of Oil Shale Technologies

lapses as the working face advances through

the ore body. The technique is commonly used

for coal mining, especially in Great Britain.

Open pit—The overburden is drilled and

blasted loose over a large area and removed to

expose the oil shale beds. These are then

drilled and blasted.

Room-and-pillar-Some shale is removed to

form large rooms, and some is left in place, as

pillars, to support the mine roof.

Solution—The injection of fluids into the formation to dissolve soluble salts from among the

oil shale layers, thereby creating a honeycomb

pattern of voids.

Strip—The overburden and deposit are removed with a dragline—a massive type of

scraper shovel.

Subsidence—The mine roof is allowed to collapse into the working area after the ore is

removed.

Mining bench: A shelf or ledge made in a mine

tunnel or working when an upper section is cut

back.

Modular retort: The smallest unit that would be

used in commercial practice. Its capacity

varies with the developer.

Molecular weights: The relative mass of a molecule as compared with that of an atom of

hydrogen. It is calculated by adding up the

weights of the molecule’s constituent atoms.

Mucking: Removal material broken up in the mining process.

Nahcolite: A mineral chemically identical to commercial baking soda (sodium bicarbonate).

New Source Performance Standards (NSPS): The

Clean Air Act requires that the Environmental

Protection Agency set standards of performance for major new potential sources of pollution, and that such facilities use the most advanced technology available for pollution control.

Nonattainment area: The air in the region does

not satisfy the National Ambient Air Quality

Standards as established under the requirements of the Clean Air Act.

Nondegradation area: The air in the region is

cleaner than that required by the National Ambient Air Quality Standards.

Nonmethane hydrocarbons: All the organic compounds of carbon and hydrogen that are not

straight chain, saturated (no more hydrogen

can be added) molecules in which the carbon

atoms are joined to each other by single bonds.

Nonpoint source: A site from which there is uncollected runoff, e.g., a mining operation, construction site, or agricultural area.

Olefin hydrocarbons: Unsaturated (lower ratio of

hydrogen to carbon) compounds of carbon and

hydrogen having at least one double bond.

Onstream factor: The fraction of the time that a

plant could be expected to operate at design capacity.

Organic compounds: The compounds of carbon.

These fall roughly into two classes: compounds

containing only carbon and hydrogen (hydrocarbons), and compounds in which one or more

hydrogen atoms have been replaced by other

elements or groups of elements (heteroatomic

compounds).

Overburden: The material overlying a deposit

that must be removed before surface mining.

Paraffin hydrocarbons: Saturated compounds of

carbon and hydrogen having only single bonds.

Particulate: Minute separate airborne particles,

one of the criteria pollutants under the Clean

Air Act,

Perfection of water right decree: Meeting all the

requirements under applicable law to establish

legal rights to the water—implies not only

ownership but also actual use.

pH: A means of expressing the acidity or alkalinity of a solution. At normal temperatures, pure

water has a pH of about 7 (neutral); the pH of a

strong acid is about 1 and that of a strong base

about 14.

Photochemical reactions: Chemical reactions induced in the atmosphere by ultraviolet radiation from the Sun.

Phreatophyte: A deep-rooted plant that obtains

water from the water table or the layer of soil

just above it.

Placer deposit: A deposit of alluvial material

found along and in riverbanks, streambanks,

and in beach sands.

Polycyclic organic compounds: A compound

whose molecular structure contains two or

more rings (usually fused) that are mostly constructed of carbon atoms (e.g., anthracene).

Pour point: The lowest temperature at which a

liquid will flow.

Prevention of significant deterioration (PSD): A

statutory program of the Clean Air Act aimed

at preserving the existing high air quality in

those areas having the cleanest air (nondegradation regions).

Pyrolysis: The breaking down of complex materials into simpler units by means of heat.

Radionuclide: A radioactive atom.
Appendix E–Acronyms, Abbreviations, and Glossary • 517

RARE II: The Roadless Area Review and Evaluation process being undertaken by the Forest

Service for all potential wilderness areas in the

national forest system.

Refluxing: Distillation in which the liquid is condensed with the rising vapor in a fractionating

column.

Reserve: A resource that can be extracted from

the deposit and processed to yield products

that can be marketed at a profit.

Resource: A naturally occurring substance with

properties that can be put to use.

Retort: The vessel or container in which the oil

shale is pyrolyzed to recover the shale oil.

Retort plant:

Commercial scale—A commercial-size oil

shale facility would use several modular retorts in parallel to obtain the desired production rate,

Pilot-plant scale —About one-hundredth of

the capacity of a commercial scale module.

Pioneer commercial scale—Would contain

several commercial-size modules.

Semiworks scale—About one-tenth of the capacity of commercial-size.

Retorting: The raw oil shale is heated to pyrolysis

temperatures (about 1,000° F (540° C)) to obtain

crude shale oil.

Above-ground (AGR)—In this process, the retorting vessels are essentially large, steel cylindrical or cone-shaped containers lined with refractory brick. The retorting systems, which

differ widely with respect to technical and operating characteristics, fall into four classes

based on the mode of transferring heat through

the oil shale: 1) by conduction through the retort wall, 2) by flowing gases generated from

the carbonaceous material and hot gases created in the retort, 3) by gases heated outside

the retort, and 4) by mixing hot solid particles

with the oil shale.

Modified in situ (MIS)—In this process, a portion of the shale deposit is mined out, and the

rest is fractured with explosives or by other

means to create a highly permeable zone

through which hot fluids can be circulated.

True in situ (TIS)—In this process, the shale

is left underground and is heated by injecting

hot fluids.

Rubbling: Shattering by explosives of a portion of

an oil shale deposit so that it can be retorted

underground. A modified in situ process.

Sedimentary rocks: These are derived from the

disintegration and weathering of older rocks,

and deposited in layers by water, wind, or ice

(e.g., sandstone, limestone, shale.)

Shale oil syncrude: A synthetic crude oil produced by adding hydrogen to crude shale oil,

comparable with the best grades of conventional crude.

Spent shale: The retorted residual material after

the oil and gas products are removed. Its properties vary with the type of retorting procedure

used; indirectly heated retorts product a carbonaceous spent shale, while directly heated

retorts produce a material essentially stripped

of carbon.

Spot market price: The nonposted price for a barrel of oil,

Syncrude: Synthetic crude oil, produced from any

source other than conventional petroleum.

Trona: A hydrated mixture of sodium carbonate

and sodium bicarbonate. It is a source of soda

ash for glass production.

Upgrading: The treatment of crude shale oil to improve it to a transportable refinery feedstock,

e.g., hydrotreating.

Virgin flow: The flow of a river that would occur

in the absence of human-related activities. In

this assessment most of the analysis of water

availability refers to the average flow between

1930-74, because of its common use in other

water resources analyses.

Viscosity: A measure of a liquid’s resistance to

flow.

Water rights:

Absolute—The right created when a holder

of a conditional right perfects that right by actually diverting the water and applying it to a

beneficial use.

Conditional—The right obtained by filing for

a conditional decree from the State water

courts, and then proceeding diligently towards

the actual use of the water,

Diversion—Permits the diversion of water

from a stream followed by its immediate application.

Junior—The prior appropriation doctrine for

water rights is based on the principle “first-intime, first-in-right. ” In times of shortages,

rights that are junior in terms of the initiation

date are curtailed to assure water supplies to

users with more senior rights.

Senior—The more senior (older) the water

right, the higher its priority for the use of limited resources.

Storage—Permits the impoundment of water

for later application.

o
ERRATA - AN ASSESSMENT OF OIL SHALE TECHNOLOGIES

1. The shading on Figure 2, page 7 is incorrect:

SEE INSTEAD FIGURE 13, PAGE 90.

2 . Issue 4, p. 32 : The total estimated cost o f

pollution control should be 2.4 to 6.0 cents/gal .

3. Figure 51, p. 187 :

increases from environmental costs should fall

lower on the graph (about 2 x 1971 estimate).

Site 11/line 11, under statu — —s

should read : Initial environmental, healt h

and safety tests underway .

5 . Page 136, first column, lines 6 and 7, shoul d

read : Multi Mineral has begun use of a n

8-ft-diameter shaft. . . .