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THERMOPHYSICAL PROPERTY DATA ON

SOLID FEEDSTOCKS

II. Oil Shale

Jane E. Callanan

National Bureau of Standards

U.S. Department of Commerce

Boulder, Colorado 80303-3328

April 1987

QC

100

. U56

87-3064

1987

NBSIR 87-3064

Research Information Center

National Bureau of Standards

Gaithersburg, Maryland 20399

REVIEW OF NEEDS FOR

THERMOPHYSICAL PROPERTY DATA ON

SOLID FEEDSTOCKS

II. Oil Shale

Jane E. Callanan

Chemical Engineering Science Division

Center for Chemical Engineering

National Engineering Laboratory

National Bureau of Standards

Boulder, Colorado 80303-3328

April 1987

U.S. DEPARTMENT OF COMMERCE, Malcolm Baldrige, Secretary

NATIONAL BUREAU OF STANDARDS, Ernest Ambler, Director
i gftf
CONTENTS

LIST OF TABLES v

LIST OF FIGURES v

ABSTRACT vii

1. INTRODUCTION 1

2. NATURE AND EXTENT OF THE RESOURCE 1

2 . 1 Nature of Oil Shale 1 2.2 Extent of the Shale Resource 3 2.3 Eastern and Western Shales 4

3. CHARACTERIZATION AND ANALYSIS 5 3.1 Characterization 5 3.2 Analysis 5 3.2.1 Mineral 5 3.2.2 Oil yield 6

3.2.3 Organic 8 3.2.4 Thermal analysis 8 3.2.5 Electromagnetic 9

4. THERMAL PROPERTIES 9 4.1 General Considerations 9 4.2 Thermal Analysis 11

4.3 Status of Individual Thermal Properties 11

4.3.1 Heat (energy) of combustion 11

4.3.2 Heat of retorting 14

4.3.3 Specific heat 15

4.3.4 Thermal conductivity 16

4.3.5 Thermal expansion 17

4.3.6 Heat of immersion 17

4.4 Postscript 18

5. PROCESSING AND BENEFICIATION 18

5.1 History of Commercial Production 18

5.2 Oil Shale Processing 18

5.2.1 Above ground 19

5.2.2 In situ 19

5.2.3 Modified in situ 21

5.2.4 Developing processes 21

5.3 Beneficiation 22

iii
6. KINETICS AND MODELING 25

6.1 General Considerations 25

6.2 Kinetics 25

6.3 Modeling 27

7. RECOMMENDATIONS 28

7.1 General Recommendations 28

7.2 Specific Recommendations 30

8. REFERENCES 32

IV
LIST OF TABLES

Table

1. Summary of consultations: oil shale 46

2. Estimate of world-wide shale resources 47

3. Oil shale resources of the United States 48

4. Estimate of abundance of eastern shales by hydroassay ... 49

5. Organic and mineral constituents of eastern shale and

western shales 50

LIST OF FIGURES

Figure

1. Van Krevelen diagram for oil shale kerogens 51

2. Known world reserves of recoverable oil shale 52

3. Major shale-bearing areas of the United States 53

4. Green River shale deposits 54

v

Review of Needs for Thermophysical Property Data on Solid Feedstocks. II. Oil Shale

Jane E. Callanan

Thermophysical Properties Division

National Bureau of Standards

Boulder, Colorado

This report, a comprehensive survey concerning oil shale, is the

second in a series dealing with needs, particularly for

thermophysical properties, for solid fuels/feedstocks. This survey

shows the need for experimental work on heat of combustion, heat of

retorting, heat capac i ty/enthalpy , thermal conductivity, thermal

expansion and heat of immersion for raw, spent and burnt shale,

for kerogen and for the mineral matter found in shale. These studies

should be preceded by agreement on the properties necessary for good

characterization of the shale and on the methods of measuring these

properties; the thermal properties measurements should be made on well-characterized samples. Standardized measurement techniques do

not exist for thermal properties, with the possible exception of heat

of combustion, and must be developed. Existing data must be

evaluated and reliable data generated. Theoretical studies that will

allow for modeling of thermal properties should proceed along with

the experimental investigations to improve the ability to predict

shale properties for process design. Recommendations for work

appropriate to the National Bureau of Standards are included.

Key words:

immersion

;

f eedstocks;

enthalpy; heat capacity; heat of combustion; heat of

heat of retorting; oil shale; review; solid fuels

thermal conductivity; thermal expansion.

vi i

1 . INTRODUCTION

This is the second of a series of reports on the needs for thermophysical

property data for solid fuels/feedstocks. This report on oil shale, like the

first on coal [1], is based on an extensive survey of existing literature and

discussions with scientists and engineers working with shale. Table 1 lists

those we have visited or contacted by telephone. This report is written

against a backdrop of several years of experience with thermophysical

property measurements on solid fuels/feedstocks, both coal and gas hydrates.

This report differs from the coal report in the amount of material included

that is seemingly unrelated to thermophysical properties or the modeling of

these properties. To some extent the inclusion of this material reflects the

author's own learning process. To properly evaluate needs, it is necessary

to be thoroughly familiar with the material under study. Second, shale is a less well-known material in general than coal; some material is included for

the convenience of the reader.

Considerable detail is included in the section on characterization and

analysis because one of the obstacles to the development of models is the

lack of a coherent body of data on which to base predictions. Data on oil

shale exist, but the lack of characterization information limits its

usefulness. Material on analytical procedures is included to assist in

judgments regarding suitable characterization information. Information on processing is included because of its bearing on measurement needs. However,

neither of these two sections is meant to be an exhaustive treatment;

references are representative.

In contrast, the section on thermal properties is exhaustive. Every

reference available to us has been examined and evaluated. References

available related to modeling have been reviewed carefully. None deal with

properties modeling. References to kinetic and process models are selective.

The report outlines the nature of oil shale and the extent of the resource. After consideration of characterization, the status of thermal property

information is detailed. A survey of processing methods used with oil shale,

the status of beneficiation , oil shale modeling, and kinetic studies are discussed. Finally, recommendations are made both for potential studies for

shale in general and, more specifically, for studies appropriate to the

charter of the National Bureau of Standards (NBS)

.

2. NATURE AND EXTENT OF THE RESOURCE

2.1 Nature of Oil Shale

Oil shale can best be defined as any rock that yields commercial quantities

°f °il on destructive distillation. The oil occurs within the rock as a resinous solid, not in liquid form. The rock in which the oil occurs is not

geologically a shale but rather a marlstone. The relative amounts of organ i <•

1
and mineral species in shale are variable, with mineral predominating.

Rarely is the organic content greater than 20 percent. The more usual

proportions for United States shales are 14-16 percent organic to 86-84

percent mineral. It is the high proportion of mineral matter that presents

difficulties in processing. If the oil shale is heated without first

reducing the mineral content, a great deal of energy is expended in heating a material that will not produce oil or gas.

The organic matter in oil shale is classified either as bitumen or kerogen.

Bitumen is a general name for solid and semi -solid hydrocarbons that are fusible and soluble in organic solvents like carbon disulfide, asphalts, and

natural mineral waxes. In many United States shales, about 10 percent of the

organic matter is bitumen; the balance is kerogen. Kerogen has long been

considered to be a heteroatomic polymer with a molar mass greater than 3000

[2]. Cross-linking by oxygen and sulfur leads to a three-dimensional

molecular structure throughout. It is a rubbery organic material that is

insoluble in most organic solvents. The organic material, like that found in

petroleum source rocks, has a high hydrogen content compared to coal [3]. It

is fine-grained, much of it from algal sources, and embedded in the mineral

matrix. Both kerogen and bitumen are thermally unstable and begin to

decompose at about 525 K. Oil shale does not show the very short-range

heterogeneity that coal does, especially within horizontal layers, because it

has deposited from sediments or silt in a body of water. Regions of

latitudinal character that are more or less set off from surrounding regions

by some distinctive characteristic are referred to as zones.

The characterization of kerogen as a polymer has been challenged in recent

years. McKay [4] describes kerogen as merely a complex hydrocarbon, of

average molecular mass 600-800, that breaks down on heating.

Three types of kerogen are recognized [5-7]. Distinctions among the classes

are based on the environment from which the deposition took place, the origin

of the kerogen, the H/C and 0/C ratios, the extent of maturation, and certain

structural features. In type I kerogen, the organic material has deposited

from a marine or a lacustrine environment, is principally of algal origin,

has high H/C to 0/C ratios, and has a highly amorphous structure. Type II

kerogen has both terrestrial and marine material with marine tending to

predominate. The H/C ratio is lower than that found in type I, the 0/C ratio

higher. Aromatics and naphthene are dominant hydrocarbons; exinous

,

vitrinous, and fusinous materials are more common than in amorphous kerogens

.

Type III kerogen is mainly of terrestrial origin, has lower H/C and higher

0/C ratios than the other types, has more vitrinite and fusinite than exinite

or amorphous material, and has increased proportions of polycyclic aromatics

and heteroatoms. Oil shales with type III kerogen are often referred to as coaly since their origins are similar to that of coal. Oil shales in which

types I and II kerogen predominate produce oil; long chain aliphatics are abundant. Shales with type III kerogen produce significant quantities of gas

in addition to oil. Amorphous material and algal kerogen are usually

associated with high oil yields. Figure 1 shows a van Krevelen diagram (H/C

vs. 0/C) for shale kerogens. Kerogens are also classified as to maturity. A

mature deposit is found at greater depth, has undergone thermal evolution,

and produces more oil per mass percent of organic material.

2
Shales of marine origin have high concentrations of silicaceous minerals and

less clay- like material. In lacustrine shales, carbonates and clays

predominate. The specific mineral content will vary with geographic region

and with the geologic era in which deposition occurred. In some instances, a particular mineral depositional layer is so distinctive that it serves as a marker throughout the entire deposit. The well-known Mahogany marker, which

locates the Mahogany zone in the Green River formation, is in fact a deposit

of buff- colored carbonaceous mineral which extends very uniformly through the

entire zone [8]. The mineral matter in shale is finely divided and dispersed

in an organic matrix. In turn, the organic material is considered to be

embedded in the mineral matrix. Whichever way it is expressed, the two

species are intimately mixed, partially because of the fineness of the

deposit, and very hard to separate completely, particularly by the physical

means used in beneficiation processes. Jeong and Kobylinski report that

little mineral matter is encapsulated by kerogen, but that over 27 percent of

the bitumen is trapped by fine-grained carbonate and silicate minerals [9],

Espitalie has compared kerogen with rock containing organic matter and

concludes that the heavy hydrocarbons are retained on the mineral surface

[ 10 ].

The mineral matter in shale can be considered detrimental because it cannot

generate hydrocarbons and it intensifies problems associated with leaching

and subsequent pollution of ground waters. However, some mineral species

actually exert a beneficial catalytic effect in processing. In addition, the

mineral species often give rise to valuable inorganics which are commercially

profitable and thus contribute to the economic feasibility of the resource.

2.2 Extent of the Shale Resource

Oil shale is found on all continents, but, as with other fossil fuels, is more abundant in some locations than others . The global data are incomplete

because many countries, particularly those in South America, Africa, and

Asia, have done little in the way of exploration or characterization of the

extent and quality of the resource. In addition, there is a lack of

worldwide uniformity in reporting shale grades. Figure 2 dramatically

illustrates oil shale abundance throughout the world [11].

Table 2 (which has been adapted from the data of Duncan and Swanson [12])

shows a 1965 estimate of shale resources in the world. Because of the limits

these authors have placed on the shale grade in their estimates, resources

with oil yields lower or higher than the limits given are not included. In a 1980 update of estimates of United States resources, Smith [13] notes that an estimate of the extent of the resource based on grade assumes that the

technology will remain as it is now. He presents his data for U.S. shales in

terms of the total resource, without reference to grade. There is no convenient estimate of world resources that includes the total resource.

Because of the uncertainty about the technology of utilization of the shale

resource and because of uncertainties in world estimates, no attempt is made

to estimate recoverable resources. The amount of oil that can be recovered

will depend on factors like the location of the reserve, its richness,

3
geographic features associated with the resource, and the kind of processing

required. The economic feasibility of a recovery scheme is influenced by the

availability of other fuel resources in a particular country, the extent of

its need for fuel, and the economy of the country. Resources that the United

States judges as not economically viable either because of the leanness of

the resource or the extent of the operation are commercially exploited in

China and Estonia [14]. Chinese shales are lean (e.g., 21-42 L/tonne > ^ 5-10

gal/ton); the Estonian shales are rich (166.89 L/tonne , 40 gal/ton) but the

operation is limited in extent.

Table 3 shows the figures for United States shale reserves as updated from

Duncan and Swanson's data by Smith. In Figure 3, the major shale -bearing

areas of the United States are depicted [13]. These are generally designated

as eastern and western shales. The designation western usually refers to the

abundant Green River shales of Colorado, Utah, and Wyoming. Smaller deposits

exist in Montana, Idaho, Nevada, Oregon, North and South Dakota, Nebraska,

Texas, and Alaska. The eastern shales are found principally in Ohio,

Michigan, Indiana, Kentucky, Tennessee, and Alabama with smaller deposits in

New York, Pennsylvania, and North Carolina. Table 4 shows estimates of the

eastern reserve when a recovery process specifically developed for eastern

shales is used [15].

Scotland, China, and Estonia (USSR) have produced oil from shale

commercially. China and Estonia still do today. Several other countries

produced small quantities of transportation fuel from shale during World War

II, when other supplies were severely limited.

2.3 Eastern and Western Shales

Eastern and western United States shales are distinctly different in nature

and in their response to processing and analytical variables. They differ in

geological age, kerogen structure, and oil and mineral content. The

differences which exist within each region are less striking than those

between east and west. The analytical procedures by which oil yield is

evaluated and the processing schemes which give best results differ for these

two groups of shales. These differences are discussed in the appropriate

sections of this report.

Figure 4 shows the locations of the four basins included in the Green River

(western) formation: Green River, Washakie, Piceance Creek, and Uinta [13].

These lacustrine shales are believed to have deposited from ancient Lake

Uinta some 60 million years ago during the Eocene age. This lake expanded

and contracted during its lifetime and sometimes was saline in nature and

sometimes not. Thus the deposits vary according to the nature of the lake at

the time of deposition, particularly in their mineral composition [3], The

Mahogany zone is unusual in its very uniform mineral composition. In western

shales aliphatic hydrocarbons predominate; nitrogen-bearing heteroatomic

compounds are more abundant than in eastern shales.

1 A tonne is a metric ton.

4
The eastern shales deposited from marine sources some 200 million years ago.

Some are Devonian, some Permian, and some Mississippian. Their organic

content is lower than that of western shales; aromatic species and pyrite are more abundant. An estimate of the extent of each of the shale deposits in

each area is given in Table 4 [16]. The location of the DevonianMississippian deposites is shown in Figure 3.

Table 5 lists the organic and mineral species which commonly occur in eastern

and western shales [13,16].

3. CHARACTERIZATION AND ANALYSIS

3.1 Characterization

For many years the sole characterization information given for shale was its

oil yield as determined by the Fisher Assay (FA) . Today individual research

reports sometimes include additional information: percent organic carbon,

percent aliphatic and aromatic carbon, elemental analysis, proximate

analysis, calorific value. However, there is no consensus, nor common

practice, about what information should be supplied to ensure maximum

usefulness of the data that are generated. Specification of the exact

location of the shale source and information about inorganic (mineral)

species are other serious omissions.

The only test procedure that is specified and universally used is the FA

analysis. The American Society for Testing and Materials has published a test method for the FA [17], but the method does not specify a particular

heating rate. The use of different heating rates during the assay introduces

considerable variability into the results [18]

.

In contrast, the coal

science community has long used extensive characterizations. Because of this

wealth of information about coals studied, valuable correlations have been

developed. Also, rigidly specified procedures exist for the determination of

characterization properties [19]. In addition, the coal science community

has agreed on the characterization information that ideally should be

provided to permit improved process design and maximum development of

correlations [20].

Characterization efforts for shale are in utter chaos by comparison with

coal. Some agreement among shale scientists as to what kind of information

will be useful for the understanding of shale reactions, process design, and

the development of correlations is an immediate need. Then, as properties

and process research proceeds, we will begin to amass the information needed

to understand the processes, to modify them, and to develop correlations

useful for modeling both processes and properties.

3.2 Analysis

Analysis procedures appropriate for shales include those used to determine

the potential oil content and/or the nature of the organic component as well

as others suitable for identifying the mineral species present.

5
3.2.1

Mineral

Mineral species are commonly identified by optical methods or by x-ray

diffraction techniques. X-ray techniques are not sufficiently sensitive to

give good quantitative estimates, nor will they identify minerals present in

small amounts. Optical techniques are particularly difficult to use for most

shales because of the small grain size of the mineral particles.

Quantitative estimates of a few minerals (nahcolite, dawsonite

,

nordstrandite) cannot be obtained satisfactorily by these techniques. These

minerals can be solubilized and then analyzed successfully by standard

instrumental methods [21,22]. In some instances all inorganic species

present are determined by atomic absorption spectroscopy [23].

3.2.2 Oil yield

Most analytical efforts have been directed toward determining the oil yield

and the nature of the organic phase. The estimate of oil yield for a particular shale customarily has been obtained from the Fischer Assay. The

original FA procedure, based on a retorting method for coal that used a retort design suggested by Fischer and Schrader [24], predicted the yield of

oil shale from retorting; the assay required about six hours [25,26].

Pyrolysis of the shale released the kerogen as hydrocarbon vapor. When

cooled, some of these vapors condensed to a shale oil; the light hydrocarbons

remained in the vapor phase.

Modifications to this procedure (mesh size, heating profile, aluminum

spacers) improved the oil yield estimates and reduced the assay time to about

two hours (modified Fischer assay [27]). Further modifications of the FA

procedures allowed more precise determination of individual hydrocarbons,

carbon monoxide, and acid gases; a complete material balance closure could be

obtained. With the addition of elemental analysis, the organic carbon,

nitrogen, and sulfur balances can be calculated. In this way both product

balances and material balances are obtained (material balance assay [28-30]).

All assay procedures for oil shale are evaluated by comparison with FA

results. This comparison in turn strongly influences the evaluation of shale resources. This is somewhat unfortunate as the FA is intended to assay

geologic deposits, not retorting parameters, and it is the retorting

parameters that determine the actual oil production.

The ASTM procedure stipulates that agreement between replicates should be + 4.2 L/tonne (+ 1 gal/ton); agreement among laboratories should be + 8.3

L/tonne (+ 2 gal/ton) [17]. The error and scatter in FA procedures and

results have rarely been considered. The failure to include such statistical

information introduces considerable uncertainty into oil yield determinations

and into judgments of these newer analytical procedures, many of which

represent considerable savings in time.

In particular, FA procedures have been found to give false estimates of oil

yield for eastern shale. This has caused these shales to be considered

unsuitable for commercial development, despite the many potential advantages

of an eastern shale industry. The process yield from Eastern shales should

6
be comparable to that from western shales with the same carbon content.

Assay procedures suitable for eastern shales have been developed. These

include hydroassaying procedures, rapid-heat-up (RHU) procedures, and the

Rock Eval assay. The Eastern shales are now considered to be sufficiently

rich for exploitation; however, they do have a greater aromatic and lesser

aliphatic content than western shales. Development of western shale is

favored because its high aliphatic content is more suited for the production

of liquid transportation fuel. Also, the high aromatic content of eastern

shale intensifies potential pollution problems.

A hydroretorting assay procedure [31] has been found suitable for prediction

of oil yield from the HYTORT^ process, which has been developed by the

Institute of Gas Technology. For eastern shales, the richness estimated

using this procedure is significantly greater than the FA yield for the same

shale. For the hydroretorting assay, a small oil shale specimen is retorted

with hydrogen at about 5 MPa pressure. The yield obtained with the FA for a New Albany shale from Kentucky was 52.2 L/tonne (12.5 gal/ton); the yield

predicted for the same shale by hydroretorting was 117.7 L/tonne (28.2

gal/ton) . The FA yield suggests that the deposit is uneconomical to work;

the HYTORT results predict the potential for an economically feasible

process. In developing the hydroretorting assay, care was taken to ensure

that the results were identical with those for FA results when a western

shale was being studied.

A rapid-heat-up (RHU) assay [32] for Eastern shales is an alternative

procedure in which the heating rate is about 55 K/min versus 12 K/min, as for

the FA. The RHU assay uses a fluidized sand bed, collects condensables at a slightly lower temperature than the FA, and measures noncondensables with a wet test meter. No temperature gradient exists in the shale because a very

narrow bed is used; all the shale is essentially at the same temperature.

For the same shale, the gas yield in this process is 15-50 percent greater

than that from the FA; the oil yield is from 85-100 percent greater. Rubel

et al. [33] and Margolis et al . [34] describe an analytical pyrolysis assay

which is successful in predicting yields from fluidized bed retorting

techniques, which are extreme RHU processes. They report yields that are 130-145 percent of FA. Rubel and Audeh provide the first comparison of a variety of RHU procedures in different laboratories [35],

The Rock Eval process was developed by Espitalie as a source rock analysis

tool [36]. It is widely used in Europe and Canada, and by U.S. industry.

The assay uses a small charge (milligram quantities) and reports results in

2 Certain commercial processes are identified in this paper in order to

specify adequately the experimental procedure. Such identification does

not imply recommendation or endorsement by the National Bureau of

Standards, nor does it imply that the process identified is necessarily

the best for the purpose.

7
terms of hydrocarbon content, hydrogen and oxygen indices (related to van

Krevelen H/C and 0/C ratios) , and the temperature of the rate of maximum oil

evolution. It can be done in individual laboratories within about 20

minutes

.

3.2.3 Organic

Standard methods of analysis for organics have been applied both to the shale

and to the oil generated in the process. Miknis summarizes the standard

analytical methods that have been used to evaluate the organic component of

shales [37]. For the most part, these analyses are related to the amount of

kerogen in the shale rather than the amount of oil which can be produced.

The methods discussed by Miknis include organic elemental analyses including

sulfur and oxygen, determination of organic carbon from combustion

measurements , organic hydrogen from nuclear magnetic resonance (NMR) , laser

pyrolysis chromatography, thermal chromatography, correlation with the

specific gravity or density of the shale, ultraviolet (UV) and infrared (IR)

spectroscopy, including Fourier Transform IR (FTIR) , gas chromatography

coupled with mass spectroscopy (GC/MS) , electron paramagnetic resonance

(EPR) , fluorescence spectroscopy, various NMR techniques, and thermal

analysis. The NMR techniques, which have provided a real breakthrough in

shale analysis, are discussed at length by Miknis.

The use of various solid-state NMR techniques represents a significant

advance in analytical capability for shale. Both proton and C-13 NMR

techniques have been used to identify saturated and unsaturated aliphatics

and aromatics [38,39]. Through the use of cross polarization and magic angle

spinning (CP/MAS) , it is possible to determine the relative aliphatic and

aromatic contents of the raw shales [40]. Trewhella et al . studied the

structure of Green River oil shale kerogen with a combination of advanced NMR

techniques [41].

3.2.4 Thermal analysis

Thermal analysis techniques have been used to estimate oil yields. Oil

yields can be estimated either from weight loss determinations by

thermogravimetry (TG) or from heat of decomposition determinations by

differential thermal analysis (DTA) . These techniques are simple and rapid

but may have kittle validity for raw shale because of complicating mineral

reactions in the temperature region where oil loss occurs. In addition,

these techniques have poor quantitative accuracy and are readily

misinterpreted. A linear correlation between enthalpy of decomposition and

oil yield, reported by one investigator [42], was shown to be fortuitous by

subsequent investigations [43]. The linearity observed by the first

investigator was a result of the use of shales from the Mahogany zone, with

its remarkably uniform mineral composition. A random selection of shales

showed no correlation between enthalpy of dissociation and oil yield. In

other studies, Johnson et al . [44] used a specially built apparatus that

permitted simultaneous determination of mass loss and thermal effects. With

this equipment and their considerable background, both in shale and thermal

methods, they found variations from FA values of less than 10 percent for

Mahogany zone shales; for shales from other sources, the differences between

8
thermal analytical and FA results were from 1.6-28 percent [45]. A carbon

dioxide atmosphere shifts some of the mineral peaks so that some of the

interferences are less detrimental.

3.2.5 Electromagnetic

Judzis et al. [46] suggest microwave radiation for the measurement of the

organic content of a shale. A strong correlation exists between the

dissipation of microwave energy and the organic richness. The dielectric

behavior of Green River oil shale was studied in the microfrequency range as

a function of shale richness, its density, and the frequency of the

radiation. They found a strong correlation between shale richness as determined from FA results and either the imaginary term of the dielectric

constant or the loss tangent (ratio of real to imaginary permittivity)

.

However, as the accuracy is given as + 14.2 L/tonne (+ 3.4 gal/ton), this

procedure offers little advantage over FA techniques.

Jesch and McLaughlin [47,48] have investigated the use of a high-frequency

electron mapping (HFEM) technique that would facilitate evaluation of the

efficiency of rubblized modified in situ retorts before ignition. Their

measurements enabled them to determine the complex permittivity of disk

specimens of oil shale, cut parallel to the bedding plane, from room

temperature to 773 K. All effluents were collected. The shale began to

retort about 650 K; all emission of oil and gases had ceased by 750 K. When

the specimens were cooled to room temperature and remeasured, the properties

were almost identical to those obtained before heating. Thus, contrary to

expectations, removal of oil did not affect the electrical properties

significantly, as had been suggested. Measurements showed an uncertainty of

+ 1-2 percent in dielectric constant and of +5 percent in the imaginary

part of the permittivity at room temperature. Moisture content and density

were found to influence the permittivity.

4. THERMAL PROPERTIES

4.1 General Considerations

Because of the nature of the processing that shale undergoes, there is a need

both for kinetic and equilibrium thermal property data. Kinetically correct

heats are needed to assess energy needs for retorting (or pyrolysis). These

processes occur so rapidly in the raw shale that equilibrium conditions are not met. However, equilibrium does prevail for the spent/burnt shale which

are used as circulating hot solids in some retorting processes. For these

components of the processing cycle, equilibrium data are required.

The thermal properties of potential interest for oil shale include heat of

combustion, heat of retorting, heats of reaction of organic components and

minerals, thermal conductivity, thermal diffusivity, thermal expansion, and

specific heat. The heat of retorting includes contributions from specific

heat and from the heats of the various reactions which occur during

retorting.

9
The ability to process large volumes of shale to pyrolysis temperatures

depends on heat capacity, thermal conductivity, and the heat associated with

the various reactions which occur. The heat capacity provides information

about the total energy required to raise the temperature of the shale;

thermal conductivity, the transfer of the heat supplied through the shale.

Heat capacity and thermal conductivity are functions of temperature, shale

grade, orientation with respect to the bedding plane, and the extent of

pyrolysis. Differential thermal analysis gives a qualitative picture of

endothermic and exothermic reactions that are occurring; calorimetry gives

quantitative information about these reactions.

The published data on thermal properties of oil shale are scarce; no comprehensive or systematic studies published in the United States have come

to our attention in our survey of the literature. Reliable studies are limited in application. Thermal data on shale are rarely accompanied by

statistical information. Thermal property studies need to be expanded to assess the effects of different variables on the measurements themselves, to

refine the measurement procedures so that they will be transferable, and to

determine the statistical validity of the results. Statistical evaluation of

thermal measurements is needed to provide information about inherent

variability and would be part of the development of transferable measurement

procedures. Once a reliable measurement process is developed, studies

closely related to process variables and practical problems will be feasible.

Some general deficiencies in our knowledge of thermal properties of shale can

be identified by comparison with similar data on coal. As indicated

previously, there is no agreed upon characterization of shale specimens like

that recommended for coal. Because there is no accepted general

characterization scheme for shale, the work published is for the most part on poorly characterized shales (at least by comparison with customary

characterization of coal) . A broad range of generally accepted testing and

evaluation procedures, similar to the ASTM procedures for coal [19], do not

exist. As a result, measurements of a particular property on the same shale

in two different laboratories may differ considerably. Procedures by which

reliable data can be generated must be developed. In addition, most

published studies are for Green River shales; measurements must be extended

to a variety of well-characterized shales.

Most thermal property measurements have been made on Green River shale from

the Mahogany zone, where the variability in mineral content is slight.

Similar measurements on shale outside of the Mahogany zone, other western

shales, and eastern shales are needed. This is true especially since we now

know, as a result of recently developed procedures, that there is far more potential than formerly realized in eastern shales. These shales, too, must

be included in the data base from which correlations are developed.

Because thermal property data on well-characterized shales are scarce, no useful correlations among thermal properties or between thermal properties

and other properties of shale have been developed. For coals, good

predictions of thermal properties from analytical data have been made

[49,50], The validity of such correlations that will be developed for shale

10
in the future depends on both the extent of the data base and the reliability

of the measurements. It would be of great value to those developing

correlations to have access to as much data as possible. Proprietary thermal

property measurements, some of which can be expected to be reliable, have

been made. Since all concerned stand to benefit if valid correlations are developed, every effort should be made to find a way to release as many of

these data as possible while still protecting proprietary interests. It

would be advantageous to work out agreements that give some laboratories,

perhaps selected government laboratories, access to the data for development

purposes without releasing figures in a way that would harm proprietary

interest

.

4.2 Thermal Analysis

The suitability of differential thermal analysis (DTA) and thermogravimetric

analysis (TG) for the determination of thermal properties is questionable.

DTA is generally a qualitative technique and has marginal utility in

determining thermophysical properties of a material as complex as shale.

Though attempts have been made to declare the technique quantitative, its

accuracy is questionable. Even differential scanning calorimetry (DSC), a more accurate measurement technique, requires carefully developed operating

procedures that must be adhered to rigidly [51]. DTA does not provide a way

of separating contributions from various simultaneous or overlapping

reactions that occur as shale is heated. The practice of determining heat

effects associated with the reaction of a pure mineral and then applying a corresponding correction to a composite curve ignores the interactions which

may be occurring among various mineral species and between mineral and

organic moieties. These interactions, some of which are catalytic, are extremely complex; simple additivity cannot be assumed.

Thermogravimetric analysis provides a way of following the mass loss of a material as a function of temperature/heating rate. It does indicate the

temperature at which the shale begins to decompose. When used in conjunction

with analytical procedures, useful information about products generated can

be obtained. However, the technique does not provide direct information

about thermal properties. Its principal utility for shale is for kinetic

studies

.

4.3 Status of Individual Thermal Properties

4.3.1 Heat (energy) of combustion

A heat of combustion is the heat associated with a combustion reaction.

Thermodynamics considers it to be the heat associated with a reaction in

which the reactants and products are well-defined. For fuels, this

requirement presents difficulties. The initial and final states associated

with the reaction must be known accurately; the combustion most often takes

place in an oxygen atmosphere. The heat of combustion is usually determined

experimentally as a constant volume process (an energy of combustion) in a bomb calorimeter. Either adiabatic or isothermal shield techniques can be

used.

11
There is a serious flaw in the way energies of combustion are determined for

materials with fossil origins, which usually contain sulfur or nitrogen. The

first law of thermodynamics requires that the initial and final states of the

system being measured be known accurately. When sulfur compounds undergo

combustion, oxides are formed. Some of these are in the form of dioxides;

some are trioxides. When this situation prevails, the final state of the

system is not known accurately. For determination of the energy of

combustion of sulfur-bearing materials, the bomb should be charged with

oxygen along with small amounts of nitrogen and water. When sulfur oxides

are formed on combustion, the nitrogen catalyzes the conversion of the

dioxide to trioxide; thus all the oxide of sulfur exists as trioxide. The

bomb is rotated during the combustion so that a homogeneous solution of

sulfuric acid is formed in the bomb. The sulfur content can then be

determined correctly and corrections to the energy of combustion made [52].

The error associated with the sulfur compounds is frequently between 10-20

percent; it can be as high as 100 percent. The same principles apply to the

complex mixture of nitrogen acids that may be generated, but the nitrogen

error has been shown to be not as serious as that from sulfur.

A further problem can be introduced by the mineral species present in fossil

materials. Their oxidation contributes to the measured energy and also can

cause different end products to be present. These products must be

identified in order to know the final state of the system. Measurement of

the thermal properties of organic concentrates, which largely eliminate the

mineral species, helps to avoid problems introduced by minerals. However, it

does not solve the problems encountered in processing shale that are due to

its mineral content.

No measurements of energies of combustion of any fossil materials in a rotating bomb system have been published in the open literature. Thus, all

reported measurements are expected to have some error. Some proprietary

measurements have been made on coal , but as no measurements were made on the same samples by classical bomb calorimetric procedures normally used for coal

[53,54], a comparison of results by the two methods is not possible. An

estimate of the correction for sulfur and nitrogen in these measurements was about + 5 percent. This error may not seem overly serious, but if

translated to energy, it amounts to about 2208 kJ/kg. For a process

involving tons of coal, a tremendous amount of energy is involved in that

miscalculation. For good design, an accuracy of 0.2 percent is desirable

[55],

The facilities and expertise needed for accurate measurement of the heat of

combustion are scarce and expensive. Thus routine determination of

combustion heats by rotating-bomb calorimetry is not economically feasible.

Because of these limitations, a static oxygen bomb will continue to be used

for routine measurements. The shale industry needs to obtain comparisons,

for some representative shales, between results obtained by truly appropriate

procedures (rotating bomb) and the static bomb procedures customarily used

for heat of combustion. The development of an adequate data base would help

in error evaluation. As more information about the chemical constitution of

shale becomes available, group additivity relations should be investigated.

12
As shale technology advances, heats of formation of the shale and of all its

products will be required for model development. This information is

obtained from heat of combustion data as a small difference between large

numbers. The inaccuracies in the large numbers (heats of combustion) are multiplied by a factor of 10 when obtaining heats of formation from them.

The resulting heats of formation are seriously in error. The uncertainty

about the heat of formation of coal has been a serious problem in modeling

for some time [56].

Muehlbauer and Burnham estimated the heat of combustion of raw shale [57] and

Burnham et al . that of retorted and spent shale [58] by thermochemical

estimates and linear regression of experimental data. These data were needed

for modeling the modified in situ process under study at Lawrence Livermore

National Laboratory (LLNL) . For the experimental measurements on which this

work was based, the shale was ground and compressed into pellets before use. These results were flawed by the presence of unburned material, frequently

found on opening the bomb. In addition, since the bomb used could not be

rotated, the sulfur and nitrogen corrections have not been made as effectively as they could be [59].

Measurements of the heats of combustion of retorted and burnt shale by

Burnham et al . [58], by much the same technique, aided them in identifying

and quantifying reactions. These exothermic and endothermic reactions occur when retorted shale is burned above 800 K. Corrections appropriate for the

composition differences of burnt, retorted, and acid- leached specimens were

applied. An equation that was developed for determining the heat of

combustion from the composition of the shale assumed that the heat of

combustion included contributions from the char, the iron sulfides, carbonate

decompositions and the formation of a glass. The equations proposed by

Burnham et al . are realistic in light of their discussion of mineral

contributions and the corrections applied. They report considerable

complication introduced in this work by mineral reactions and point to a need

for study of the chemistry of combustion in order to improve estimates of

combustion heats. From the analyses of 66 retorted shales, they determined

the empirical formula to be CH(0 . 4)N(0 . 07)

.

Values for the contributions of

the organic carbon, nitrogen, and hydrogen are suggested; a measured heat of

combustion for demineralized shale is reported as well as that for the raw

shale

.

Corino and Turnbull devised a method of measuring the heat of combustion of

spent shales in a differential scanning calorimeter (DSC) in an oxygen

atmosphere and report good agreement with bomb calorimetric results when

these latter are extrapolated to DSC conditions [60,61].

Mraw et al . have adapted techniques originally developed for the heat of

retorting of shale to measure the heat of combustion of shale. These

techniques are described in the next section of this report. By working in a moist oxygen atmosphere at optimum oxygen- flow rates, their results for

well-known materials agreed with literature values within a few percent

[62,63].

Ringen et al . [64] have calculated heating values (calorific values) from th*

13
elemental composition of fossil fuels (oils, crude oil residua, and coals) by means of the Boie equation [65]. The calculation of the heat of combustion

in this manner is desirable because of the ease and rapidity with which

accurate values for elemental composition can be determined. The very high

mineral matter content of shale complicates the application of this technique

to shales. Smith and Young [66] applied the Boie equation to the elemental

composition of organic concentrates of raw New Albany shales, which they had

determined. Ringen et al . have used the literature data for an organic

concentrate of Green River shales [67] to apply the Boie equation. They

state that the contributions from S, N, and 0 combined are less than 1 percent; results calculated from the complete analysis (C, H, N, 0, S) differ

from those calculated from only the C, H terms by about 1 percent for both

the New Albany and the Green River shale. These statements are misleading.

When the whole shale is being used, the inorganic components contribute

significantly to heteroatom concentration. Thus Ringen' s estimate is not

valid for raw shales, which will be used in processing.

4.3.2 Heat of retorting

The heat of retorting is the total enthalpy required to heat a shale from

ambient temperature to the decomposition temperature and convert it into gas,

oil, and spent shale. It includes the enthalpy involved in the increase in

temperature (sensible heat) and that associated with any reactions, organic

or mineral, that occur in the decomposition process.

The earliest reliable enthalpy measurements on shale were made by Shaw in

1947 [68]. He determined the mean heat capacity of a number of shales

varying in grade from 4.2-372 L/tonne (1-89.2 gal/ton) over the temperature

range 340 to 505 K. Water was the medium for raw shale and kerosene for the

spent shale. His data were converted to enthalpies and published as such.

Sohns et al. [69] designed a retort that was capable of holding about 20

kilograms of raw shale. They equated the heat of retorting to the difference

in heat content of an inert gas as it entered and left the retort. By use of an adiabatic shield, they reduced heat losses to a level that could be

calculated accurately.

Wise et al. [70] improved on the measurements of Sohns et al . for raw shale

by correcting for the enthalpies of products leaving the retort. They

extended the measurements that had been made on spent shale and also reported

results for burnt shale. Wise et al . worked with a smaller version of the

adiabatic calorimeter that had been used previously. They calibrated their

system carefully for heat losses and report results obtained with a calibrant

in addition to shale results.

Corino and Turnbull [60,61] used a commercial calorimeter which is based on

the Tian-Calvet principle [71] to measure heats of pyrolysis of Rundle oil

shale. They report satisfactory agreement with previous workers. They have

also measured the heat effects associated with the mineral species present in

the shale they studied.

Mraw and Keweshan have developed a new technique [72], which they call

14
ballistic calorimetry, that uses a specially constructed Tian-Calvet

calorimeter [73]. It is essentially a drop calorimetric method which can separate the instantaneous heats, related to the organic content of the

shale, and longer term (1.5-2 hours) effects, related to mineral reactions.

They established the validity of the method for pure substances [72] and for

mixtures and substances of industrial importance [74]. Through the use of

this technique, they are able to separate the effects of kerogen

decomposition from the mineral reactions [75], Their results are consistent

with those of Sohns [69] and Wise [70].

Carley has examined existing data for heat of retorting and presented a critical analysis [76]

.

Camp has reviewed this analysis and extended it to

specific heat [77]. These authors conclude that extant data for these

quantities are often contradictory and sometimes seriously in error.

4.3.3 Specific heat

A serious problem may be encountered in attempting to measure the specific

heat of oil shale. Heat capacity and specific heat are thermodynamic

properties. As such they refer to a system in a particular state. If the

system under study changes during the measurement, it is not appropriate to

call the result a heat capacity or a specific heat.

The mineral content of raw shale may complicate the determination of specific

heat in just this way -- because of competing mineral reactions. Many of the

minerals found in shale will react in the same temperature region in which

the shale decomposes or is retorted. Nahcolite, dawsonite , nordstrandite

,

and hydrated clays are particularly troublesome. Thus what one hopes to

measure as specific heat often is complicated by the enthalpy of the mineral

reactions and of the reactions of the organic components of oil shale. The

first heating of the material includes both contributions. Subsequent

heating should give values that resemble true specific heats. However, the

salient question here is: the specific heat of what? When the material has

reacted, it is different from the starting material. The best one can do is

consider it to be the specific heat of a spent or partially spent shale,

prepared at a particular temperature. This is much like the boxing technique

used by Singer and Tye [78]. The difference between the initial and repeat

curves can be evaluated to give the enthalpy of the mineral reactions that

are actually occurring. However, it is difficult to determine the exact

nature of the mineral reaction in a material as complex as an oil shale.

Gavin and Sharp [79] report early specific heat measurements of an unidentified shale. Shaw [68] measured mean specific heat but reported his

results as enthalpies. This work has been discussed previously.

In measurements of the specific heat of Green River shales by DSC, Taylor and

Groot [80] noted the existence of an endotherm on the first heating; second

and later heat capacity scans were uneventful heat capacity scans with a gently rising slope. Corino and Turnbull [60,61] report the specific heats

of raw, spent, and burnt Rundle shale. Gilliam and Morgan, in DSC

measurements of the heat capacity of eastern oil shales from ambient

temperature to 473 K, noted interferences from water present in their systcn

15
[81]. No comparative evaluation of these above results can be made at this

time because the studies involved different shales under different

experimental conditions. If equilibrium conditions were not met, the

comparison will be difficult. Other specific heat measurements can be found

in the literature or have been communicated to our laboratory, many of which

have been made by DSC or DTA. These are not discussed here because problems

associated with these data have not been solved.

4.3.4 Thermal conductivity

Thermal conductivity measurements of solids, especially solids which may

contain defects or undergo reaction, are difficult to do properly at best.

The extension of these measurements significantly above room temperature

indeed presents a challenge. Problems anticipated include integrity of the

specimen, contact problems between sensor and specimen, and contributions

from radiative heat transfer. At high temperatures radiation will contribute

significantly to heat transfer.

A few thermal conductivity measurements for raw and spent Green River shale

are reported in the literature. These are isolated measurements on poorly

characterized shales. There have been no systematic studies, nor are estimates of accuracy and precision given.

Tihen et al. [82] measured the thermal conductivity of raw, spent, and burnt

shale as a function of grade and orientation with a transient line source

probe. They used five replicate specimens at temperature ranges that were suitable for the shale species being studied. Thermal conductivity varied

inversely as shale grade. Conductivity decreased from raw through spent to

burnt shale. These authors used the same equipment but different measurement

procedures to determine the thermal diffusivity of the same shales.

Taylor and Groot [80] used a laser- flash technique with disk specimens to

measure the thermal diffusivity and a scanning calorimeter to determine the

specific heat of a series of shales. By use of these values and the density

of the specimens, they calculated thermal conductivity; no characterization

information is reported for the shales . They observed an endotherm on the

initial heat capacity run which extended from 333-573 K. Repeat runs on preheated samples showed uneventful heat capacity curves. The thermal

conductivity values, obtained from the measured heat capacity, density, and

diffusivity, decreased with increasing temperature up to 673 K; above this

temperature, there was a sharp drop in conductivity, which was attributed to

the release of oil.

Nottenburg et al. [83] used a thermal comparator technique to measure the

thermal conductivity of two Green River shales from 298-628 K. Their

specimens varied in grade and orientation. Results are presented graphically

and are comparable to others in the literature.

Gilliam and Morgan also used a thermal comparator technique to measure the

thermal conductivity to 473 K. Again, they refer to interference from free,

adsorbed, and absorbed water [81].

16
4.3.5 Thermal expansion

Smith and Johnson [84] measured the thermal expansion of shale in a speciallyconstructed dilatometric cell, which unfortunately has not been described in

detail. The solid specimen was cut perpendicular to the bedding plane and

heated at 10 K/min. They state that the expansion of the organic moiety is

20 times that of the mineral matter. In a 146 L/tonne (35 gal/ton) shale,

the oil is about 40 volume percent. They estimate the expansion coefficient

for the organic matter to be 3.4 x 10 (-4) per K, which is similar to values

obtained for paraffin and asphalt. This estimate includes interferences from

mineral species. Two regions show rapid increases in length: 463-498 K and

673-758 K. In the first of these regions, the core increased in length about

8 percent and fissures began to develop. A major force contributing to the

development of fissures is the existence of differing oil content of

different layers of the shale bed and the consequent stress induced in the

layers. Decomposition begins in the 673-758 K temperature region; the

accumulated increase in core length by 758 K is 14 percent. By contrast from

758-1273 K, the core expands only 1.1 percent.

Duvall et al. [85] measured the free expansion of raw shale as a function of

grade, orientation, and heating rate, from 298-698 K, with a quartz push-rod

dilatometer. Shale grade was determined from a correlation between shale

grade and specific gravity [86]

.

They write of a small expansion from

350-550 K, attributed to the development of fissures, and a much greater

expansion between 650-675 K; this was accompanied by decomposition of the

shale and serious distortion of the specimen. The graphical data presented

and the very great magnitude of the error bars shown make it difficult to

support these conclusions. Variation observed as a function of heating rate was well within the error of the measurements.

Khan has used a high-pressure microdilatometer [87] to study the

expansion/contraction behavior of shales and of a kerogen concentrate as a function of several experimental variables [88]. He observed limited

expansion up to about 773 K; above that temperature, he observed contraction,

which for some shales far exceeded any expansion that had occurred.

Gilliam and Morgan measured thermal expansion with a commercial dilatomer to

473 K; they report expansion to this temperature, followed by major

deformation of their specimens above it [81],

4.3.6 Heat of immersion

While raw shale does not exhibit the extreme porosity that coal does, the

spent shale does. A relatively untouched field of investigations involves

interactions between raw, spent, or burnt shale and water, hydrocarbon

liquids, and mixtures of them. Such interactions do exist during oil shale

processing.

17
4.4 Postscript

Essential to any development of measurement procedures for thermal properties

are 1. a critical survey of existing data on materials, properties, and

methods, and 2. development and refinement of measuring procedures to be used

with well-characterized materials. This statement implies that appropriate

decisions have been made regarding suitable characterization. The first of

these tasks has been furthered by this report, though a quantitative

evaluation of thermal property data is not included here. The quantitative

evaluation and publication of thermal property data needs to be completed;

the second task remains essentially unaddressed.

Some of the pitfalls that attend measurements of thermal properties of oil

shale have been pointed out above. They serve to emphasize that thermal

property measurements on solids, particularly at elevated temperatures, are difficult to make. The complexity of shale and potential interferences from

reactions complicate these measurements. These difficulties make the two

aims enumerated above even more crucial.

5. PROCESSING AND BENEFICIATION

5.1 History of Commercial Production

Commercial exploitation of oil shale reserves has been occurring in some parts of the world and at some times since the early 1800' s. In the United

States there were working retorts in the Ohio River valley; the discovery of

oil in Pennsylvania in 1859 put an end to their operation. The same holds

true for much of Canada. Mature oil shale deposits in Scotland remained in

production as did retorts in the Eastern Provinces of Canada, particularly

Nova Scotia.

The U.S. Bureau of Mines maintained a small research program. This program

became more active with the advent of World War I. But the discovery of oil

in Texas in the late 1920 's again brought the cycle to a low point. During

World War II, intensified research was carried out in the United States and

Australia. The low price of crude oil in the late 1950' s brought most of

these efforts to a halt.

The world oil crisis precipitated by the actions of OPEC in the 1970 's again

gave birth to renewed research. Again, these efforts were largely terminated

by the drop in oil prices in the early 1980' s.

The United States has tremendous reserves of oil shale to supply a synthetic

fuels industry. The technology needed to utilize these reserves is feasible

but must be developed. This development will require a long-term commitment.

5.2 Oil Shale Processing

The older processes by which crude oil is obtained from oil shale can be

divided into three groups: above-ground, in situ, and modified in situ

retorting. The newer processes are still in laboratory development, but most

18
would be classified with above-ground retorting. The fundamentals of each of

these process groups, their advantages and disadvantages, and the present

status of each technology will be discussed in turn. All the processes

generate a crude oil which must be prerefined before any further processing

is carried out.

5.2.1 Above ground

Above-ground retorting in a wide variety of retorts and processes is the

oldest of the processing technologies. The shale is brought to the surface

by traditional mining techniques and there processed in retorts. Oil removal

from the rock is most effective in these processes because it can be

controlled better. However, tons of spent shale require disposal. The shale

expands as it is processed, so the spent shale cannot just be put back into

the mined area underground. In addition, the treatment of the retorted

(spent) shale requires large amounts of water. As the major portion of the

domestic shale slated for near term exploitation is in the west, where water

is scarce, this need for very large amounts of water is a distinct drawback.

A third serious problem arises from the porosity of the completely processed

shale, much of which will be reinserted into the mined areas. It facilitates

the leaching of deleterious species, principally inorganic, into the ground

water

.

In above-ground retorting, a hot zone is propagated through the retort by

means of countercurrent flow of hot gases or hot solids. The flow may be

from the top down, from the bottom up, or horizontal. By these means oil can

be liberated from the solid. The technical challenge is to do so at a cost

that makes the product competitive.

The majority of processes which have reached the pilot-plant stage or actual

production involve above-ground retorting. Hot gases are used in what are considered first- generation processes. The thrust to use hot solids to heat

the charge has resulted in second- generation processes; there is no certainty

at present that they can be successfully developed. Factors which have been

studied include retort volume, heat exchange, the maintenance of appropriate

temperatures in various zones, mixing in the retort, atmosphere, residence

time, power and water requirements, and waste disposal, including gases,

solids, and water.

Variants of above-ground technology being investigated actively today include

various fluidized-bed or cascading-bed techniques. These heat the shale more uniformly, thereby increasing the possibility of attaining more nearly

maximum yields. High processing rates and heat transfer result in very short

residence times. Therefore, there is less charring and coking of the oil,

which results in higher oil yields. Crucial variables include the retorting

temperature, the atmosphere, and the pressure in the bed.

5.2.2 In situ

In situ oil shale processing takes place entirely underground. The shale b< <1 must be fractured or rubblized by explosives or by hydrostatic pressure.

Then combustion of a portion of the bed is initiated and the burn is

19
propagated through the bed. The oil generated by this means is pumped to the

surface where prerefining is done. In situ processing is not useful for rich

shales because of problems generated with permeability. It is suitable,

however, for lean shales which are uneconomical to process in above-ground

retorts

.

The mining operation is eliminated as is the problem associated with disposal

of spent shale. It merely remains in the mine. Water requirements are

lower. Heat is supplied by direct combustion or steam injection. Major

problems are encountered in fracturing the bed, establishing the required

porosity, measuring temperature at a remote underground site accurately,

sustaining the burn, overcoming coking or cracking of the oil, and with

pollution associated with the spent shale. The problems associated with

contamination of ground water and aquifiers by leaching of spent shale

remains, whether the shale has been reinserted into the mine from above

ground or whether it was generated in situ. As with all in situ processes,

the burn will follow the path of least resistance. As a result, oil is not

removed from large portions of the bed. Control of the path of the burn is

not practical. Drilling costs are high; environmental contamination problems, are serious

.

In situ processes were explored widely during the 1970 's but are not

receiving much attention at present. Most of the information has been gained

from laboratory simulations since true field tests are hard to control and

evaluate. While the need to dispose of the spent shale is eliminated, the

problems of heating and sustaining the burn and of subsequent pollution are tremendous. Important process parameters include the type of heat source,

the means of propagation of the heat through the bed, the rate of kerogen

decomposition, and the removal of the oil from the retorting zone without

serious loss.

A few in situ processes deserve special mention. One is the use of radio

frequency (rf) or dielectric heating [89]. The yield is maximized because

non-uniform heating of the shale bed is eliminated. Heating is slow and the

final temperature achieved is less than 673 K, which is considerably less

than that attained in more conventional processes. The second process of

interest is one specifically developed with low front-end costs and intended

for use with very thin shale deposits [90]. This process needs improvements

in rock fragmentation and oil recovery procedures. Coveil [91] used hot

gases from underground coal gasification to heat an in situ retort. The

mineral components of the spent shale remove sulfur from the gases generated

by the coal, thus reducing environmental problems. However, a great deal of

product oil is consumed, which results in large losses in oil yield. Johnson

et al. [92] have studied the thermodynamics of combined coal -oil shale

processing; they are currently studying the kinetics of such processes.

Fischer and Tyler [93] have used a programmed heating regime on cubes of

shale in a nitrogen atmosphere. They report enhanced oil yields as a result

of soaking for 24 hours at 473-573 K.

20
5.2.3 Modified in situ

Modified in situ processes combine elements of in situ and above-ground

retorting. In these a portion of the bed is mined by traditional

techniques. The remaining shale is rubblized to fill the void and

retorted in situ. The existence of the void volume facilitates the

initiation and maintenance of the burn.

Variables which influence the yield of shale oil include the particle

size heterogeneity of the rubble and fluid flow uniformity. The

production of uniformly sized rubble is the principal mining problem. In

addition, the pillars and the spent shale must be strong enough to give

the retort stability. Control of the burn, recovery of product gas and

oil, and environmental pollution remain problems, as in true in situ

processes. It is most difficult to control the direction of the

fracturing process to an extent that will result in a large proportion of

the bed being subject to extraction procedures. Problems with insertion

of spent shale into the mine are reduced because the amount that is

generated that requires disposal is orders of magnitude less than that

obtained in above-ground retorting.

5.2.4 Developing processes

For the established retorting processes, a recovery that is 65 percent of

FA is normal. Some of the processes being developed have much higher oil

yield or carbon conversion rates.

Hydroprocessing can be considered as treatment with 1) molecular

hydrogen, particularly at elevated pressure, or 2) solvent, whether

hydrogen donor or not. Processing with high-pressure hydrogen has been

shown to increase oil yield for eastern U.S. shales tremendously [31].

Baldwin found solvent hydrogenation to be useful for eastern and

Australian shales [94,95].

One of the processes which has been developed specifically for eastern

shales is the HYTORT process, which uses a hydrogen-rich atmosphere under

pressure in the retort. For Devonian shales, the yield for this process

is reported to be about 200 percent of the FA yield [96]

.

Variables

which have been examined include the effects of hydrogen partial

pressure, heating rate, maximum retort temperature, and shale mass flux.

Both vertical batch retorts and moving bed retorts have been considered.

The effects of high-pressure nitrogen or hydrogen depend on the

geographic origin of the shale used. These processes are generally most

successful with eastern U.S. shales or shales of like kerogen composition

[31,97]. Yang and Sohn report increased oil yield at lower pressures for

both Antrim and Green River shales [98],

Kahn found flash hydropyrolysis of eastern shales in a helium atmosphere

to be promising [99]. Steinberg had better results with pyrolysis with

methane in the system than with hydrogen or helium [100]

.

Carter

21
summarizes studies of the effects of various parameters on f luidized-bed

retorting of eastern oil shales [101]. Schadle and coworkers are using a xenon flash lamp reactor to study the energy required to generate

products in a variety of shales and their organic fractions [102].

Allred [103] and Wall [104] retorted oil shale in the presence of

superheated steam. Wall was able to use a low retorting temperature and

removed higher quality gas readily. He attributed the increased product

recovery to the fact that the product gas did not contain an inert

diluent

.

Supercritical extraction procedures are among the most promising of the newer processes being developed. The limited solubility of bitumen in some solvents is extended tremendously by the use of solvents in the

supercritical state. When supercritical solvents are used, the

conversion of organic carbon to oil and gas products increases. Chong et

al . [105,106] obtained conversion of organic carbon between 70-90 percent

with supercritical solvents. They looked at the effects of pressure,

reaction time, and solvent systems (both subcritical and supercritical).

Their most successful treatment was with supercritical methanol-water;

the product was extracted with toluene -methanol . They also used pyridine

on spent shale to increase the overall yield of the system. Baldwin used

supercritical toluene with and without the addition of molecular hydrogen

and under rapid heating conditions [107,108]. Guo used supercritical

toluene and tetralin and found the extraction to proceed best at 703-723

K [109] .

5.3 Beneficiation

Beneficiation is included as a subtopic to Processing because its use,

before processing, can be effective in reducing processing costs. No

entirely satisfactory beneficiation process has been developed, but

efforts are being made currently to do so. This work will be facilitated

by progress made in understanding the bonding that exists between mineral

and organic constituents of shale.

The low ratio of organic material to mineral in shales means that little

of the material actually processed has any potential for conversion to

forms useful for fuels/feedstock purposes. Therefore, beneficiation

processes which increase the organic content of the material to be

retorted will reduce the bulk of the material that must be processed.

This reduction in turn will allow 1) for smaller retorts and consequent

savings in capital equipment, 2) for reduced operating costs for heating

the smaller charge, and 3) for the use of alternative processing methods.

In addition, problems associated with the disposal of the spent shale are reduced: there is less spent shale to be disposed of and the form in

which it exists after some beneficiation processes is often less harmful

to the environment

.

Several methods of beneficiation have been attempted with mixed results.

These include selective mining, comminution of the shale, sink- float

procedures in various media, froth- flotation procedures, acid

22
dissolution, and swelling with organic solvents. The success of these

procedures is influenced by the grade of shale, the nature of the mineral

matrix, the particle size processed, and the interaction between the

mineral and organic components

.

The beneficiation procedures described in the literature have been

carried out on a laboratory scale rather than on a commercial scale.

They were applied initially to allow for improved analyses for the

richness of the shale. The need for, and benefits of, commercial scale

beneficiation are discussed by Fahlstrom [110] but no results of such

large scale beneficiation attempts have been described in the open

literature. Earlier beneficiation studies reported have been for Green

River shale [111-114]. This is probably a consequence of the common use

of these procedures to improve the oil yield in the Fisher assay; Fisher

assay procedures are applied most successfully to Green River shales.

More recently, investigators have studied beneficiation of eastern shales

[112,115-120]. Isolated studies are reported on Swedish [110], Israeli

[118], and Australian [119] shales.

Selective mining of only rich shale grades will result in upgraded

material, but mining in this way has often been considered to be too

expensive to be practical. However, selective mining of richer shales is

anticipated for utilization of eastern shales.

There is disagreement in the literature about the feasibility of

separating the organic and mineral components of shale by comminution.

This disagreement stems both from the nature of eastern and western

shales and from uncertainty about the mode of interaction between mineral

and organic species in shale [4,9,121].

The gross structure of the eastern and western shales differs . In

western shales, the organic and mineral components are layered; in

eastern shales the particles of both components are fine-grained and are more intimately mixed in a matrix [115]. Western shales are carbonaceous

and thus resistant to size-reduction on grinding as a result; the eastern

shales do not contain significant amounts of carbonates and are more

easily ground. Krishnan et al . note that eastern shales can be ground to

10-20 m in 2 hours; the carbonate -rich western shales need 8 hours

[ 112 ].

Recent work has demonstrated that the interaction between the organic and

mineral components is not well understood and that the bonding is such

that complete separation of the two by physical means is probably

impossible. For eastern shales, with their fine-grained matrix, the

fines are readily separated from the larger oil-rich particles by

comminution. The layered structure of the western shales makes such

separation of the organic component from the inorganic more difficult.

The results obtained in several beneficiation studies emphasize the

difficulty of complete separation of mineral and organic components [112-

13,116] .

Comminution is used frequently in conjunction with other separation

23
techniques, particularly sink-float and flotation. Reduction to 10-20 m

has been shown to give most efficient separations [112], though Tsai and

Lumpkin [120] report equally good separation at 150-500 m. Datta and

Salotti [111,122] report that western shales fractured easily but eastern

did not; they also report successful separation by comminution only. In

this evaluation they differ from the conclusion reached by others.

Sink- float procedures in various media use the density difference of the

mineral and organic components for separation. Variations of the usual

gravity separation include use of heavy media [113], cyclones [111], and

hydrocyclones [120]. Larson [113] notes that coarse grinding ( 3 inch

top size) followed by heavy media suspension is successful in liberating

increased amounts of high grade shale. However, grinding to a top size

of 3/4 inch or fine grinding to 45 m before suspension did not improve

the yield.

Froth flotation procedures are based on wettability differences between

the hydrophobic oil -rich material and the hydrophilic mineral matter.

Flotation procedures have long been used by the metals industry in

quantities of 23-91 ki lo tonne s/day , and thus would be expected to be good

candidates for commercial separation units. Ring [123] reports that

separations based on wettability differences are more successful for

eastern shales than those based on gravity; neither is perfect. When

gravity separation techniques are applied to eastern shales, the

interaction of the water with the clay-based shales can produce a slime,

which settles with extreme difficulty. Some Australian shales have been

reported to produce slimes that took months to separate in settling ponds

[124]. Electrostatic beneficiation methods have an efficiency equivalent

to that of gravity methods. Krishnan et al . [112] have studied the

effects of various surface modifying agents, temperature, and multiple

flotation steps . All the surface modifying agents were equally

effective. Misra et al . [125] applied froth flotation processes to

eastern shales. Increases in temperature to about 335 K improved the

separation but decreased the average shale grade; thus, operation at room temperature is favored. Yarrer and Hemphill [126] discuss an interesting

variant of froth flotation procedures, which they called gamma flotation.

In this, alcohols were used to alter the surface and interfacial tensions

and to improve the wettability of the particles.

Reisberg [114] used the tendency of some organic liquids to be imbibed

and swell the shales to induce the formation of pellets of organic phase

before separating the phases. Separation was enhanced, but if the shale

contained carbonates, these tended to remain attached to the oil-rich

pellets. Though this procedure was successful on a laboratory scale, it

is not expected to be economically feasible on a commercial scale.

McLaren [119] found that acid attack on the carbonates in Australian

shales gave no improvement whatsoever. Yurum et al . [118] studied the

chemical effects of acid dissolution on Israeli shales, but have not

attempted to apply the process to upgrade shale quality or recovery.

24
6. KINETICS AND MODELING

6.1 General Considerations

Kinetics and modeling are considered together here for two reasons.

First, a number of kinetic studies include a model, though this model is

often simply a mathematical expression describing the observed kinetics;

in other instances kinetic data have been used to obtain an expression

which incorporates process variables, according to the more general

concept of the model for a process. Second, the process models which

have been developed all draw on kinetic data.

Published kinetic studies related to oil shale, most of which were

intended to provide data for modeling, deal principally with the

pyrolysis of the shale, with char reactions, and with mineral reactions.

The need for laboratory- scale kinetic studies and subsequent modeling is

particularly evident when considering in situ processing. The only

practical way to estimate the effects of variables such as heating rate,

particle size, or mineral content is through modeling as the nature of

the in situ retort precludes true small scale experimentation. However,

kinetic studies have been carried out for virtually all existing

retorting configurations.

The modeling studies which have been reported for oil shale all deal with

processes. No attempts to model thermal properties of shale from

information about composition and heating rate have been reported. For

coal, such modeling has been successful [127-130]. At the present stage

of development of oil shale technology, kinetic studies make an important

contribution to the improvement of processes. Better thermal property

data will assist engineers in making desired improvements in process and

capital equipment design.

Correlations like those proposed by Smith et al . [131] for oil yield as a function of shale grade and heating rate do exist. These are empirical,

do not have the complexity normally associated with a model, and do not

have the same function.

6.2 Kinetics

The results of the kinetic studies often appear to be contradictory.

Some studies find that heating rate, particle size, or sweep gas

characteristics affect kinetics; others do not. In addition, much

potentially useful information is not transferable because the

characterization of the shale used is so sketchy. Two papers among the

many examined characterized the shales adequately [132,133],

Most studies appear to have addressed one problem with a specific shale,

under particular experimental conditions, once. Systematic studies of

several shales, or of a whole range of conditions for one shale, are required in order to develop basic information that can be transferred to

other samples or conditions.

25
Two experimental techniques were used in the kinetic studies: 1) weight

loss as a function of temperature or time through thermogravimetric

measurements (TG) ; 2) rate of evolution of pyrolysis products through

chromatographic measurements. In some instances, both techniques were used in a single study; the information gained from the combined studies

is far superior to that obtained from one alone. Both isothermal and

nonisothermal studies have been made; the range of heating rates for the

nonisothermal studies reflects the range of heating rates in the various

retorting processes in use. Isothermal soak periods are often used in

conjunction with nonisothermal measurements; thermal induction periods

compensate for finite heating times in isothermal studies.

Results are often reported in terms of intrinsic kinetics or of global

kinetics; these terms need some explanation. If the system being studied

is influenced only by chemical rate processes, i.e., if physical

processes, such as heat and mass transfer, are unimportant, the intrinsic

kinetics of the system are obtained. If, however, there are steep

thermal or concentration gradients in the system, the reaction rate will

be subject to heat or mass transfer limitations and the kinetics measured

are not true intrinsic kinetics [134]. Smith [135] has popularized the

term global reaction rate to describe those studies which include heat

and mass transfer effects or unusual catalytic effects as well as the

usual variables. For many of the configurations used in oil shale

processing and for a material as complex as shale, global kinetics indeed

seem more appropriate. It is not clear, however, that all authors using

the term are using it in this sense. Some authors appear to consider the

term synonymous with an overall reaction rate which replaces the

individual rates describing the proposed steps in the reaction.

A detailed summary of all existing kinetic studies is not appropriate for

this report. The reader who wishes such a summary will find the

introductory material in several articles cited here valuable [136-140],

Many other useful references are cited by the authors whose work is

considered here.

Pyrolysis studies have been carried out on large blocks of shale to aid

in simulation of in situ processes [141,142], for vertical and horizontal

retorting configurations [143,144], for moving [145] and fluidized beds

[136,146-7], for fixed beds [148], and for various atmospheric conditions

[149-151]. Heating rate, particle size, and pyrolysis temperature

dependence have also been studied widely. Results reported vary from a single first-order reaction [152] to a sequence of ten specific parallel

or consecutive reactions [141].

Mineral reactions, concurrent with pyrolysis reactions, complicate

pyrolysis in two ways. They may be endothermic or exothermic and occur

in temperature regions of concern in oil shale processing; the

overlapping energies confuse the interpretation of thermal effects during

pyrolysis. The kinetics of carbonate decomposition and the decomposition

reactions which occur under different conditions have been studied [153],

Some mineral species, most notably calcium oxide, enhance pyrolysis

through catalytic action [154].

26
The kinetics of the combustion or oxidation of char have been studied

because it is the energy from these processes that supplies the energy

needed for a retorting process. The effects of heating rate used in char

preparation [155], char pretreatment before oxidation [156], and

gasification in a steam environment have been studied for eastern [157]

and western [158,159] chars. Since the mineral matter reacts at

temperatures at which combustion occurs, results of the char oxidation

studies demonstrate vividly the sensitivity of the reactions to the

presence of various minerals.

More recent studies have concentrated on the kinetics of kerogen

decomposition [160] and of the oxidation of kerogen [161]

.

6.3 Modeling

Campbell et al . [162] used kinetic data from studies of a wellcharacterized shale [163] and applied the Anthony -Howard kinetic model

for coal devolatilization [164] to devise a mechanism for shale

pyrolysis. They suggest that a two-step process with bitumen as an intermediate occurs below 773 K. Secondary pyrolysis above 773 K reduces

the carbonaceous residue. Nuttall has applied three kinetic models to

his data for a world-wide group of shales [165], The simpler schemes,

which assume a single first-order rate equation (Chen-Nuttall and

Coates -Redfern) , were not satisfactory. The Anthony -Howard model, which

assumes multiple, parallel first-order reactions, gave the best

correlation with experimental data. Nuttall 's results demonstrate

clearly that oil shales differ significantly in their thermal

decomposition behavior; consequently, different processes may be suitable

for different shales. Studies that permit correlation of properties with

process design are indicated.

Laboratory modeling of oil shale processes includes studies that examine

the various elements of commercial processes involved in retorts, such as solids handling [96] or the effect of the variation of sweep gas

concentration or rate [151]. Processes that use large chunks of shale

are affected by heat transfer problems. Gregg et al . [141] have used ten

chemical reactions that occur during pyrolysis, kinetic data, and a heat

transfer equation to provide a model that estimates results of

large-block pyrolysis well. Pan et al . [138] made several types of

experimental measurements on the same shale. Unfortunately, they did not

report any mineral analyses and were forced to use data for heat

capacity, heat of retorting and thermal conductivity from the literature

because no data more suitable to their study were available. More

studies of this sort are needed.

Burnham and Braun [166] present a comprehensive mathematical model that

is applicable to a wide range of pyrolysis conditions. In its

formulation, it draws on a long history of measurements and model

development. However, this model does not allow for concentration or thermal gradients, both of which certainly exist unless very small shale

particles are used. Another drawback of this model is that data are

27
drawn from the literature and are not specific to the shale used; no characterization is given. The authors do include a good analysis of

things they see as weaknesses in the model and indicate that work is in

progress to address some of these problems. Braun and Lewis [145] have

applied a mathematical model for external combustion retorts that

incorporates physical and chemical parameters. This model has proved

useful for examining the effects of various retorting conditions.

The ASPEN simulator has been used widely for the simulation of a variety

of industrial processes. Fong et al . [167] have applied this model to a

fluidized-bed system for oil shale pyrolysis . They were particularly

interested in the overall process thermal balance, the solids

recirculation ratio, the effect of carbonate decomposition on heat

requirements, and the sensitivity of various operating parameters on the

performance of such a process. No kinetic data were included, though the

model permits their use. Their emphasis was principally on combustion

characteristics and the effects of these on the retorting process.

Phillips et al . applied the logic of the Aspen simulator to an eastern

oil shale in a HYTORT^ reactor [168]

.

Properties modeling, like that done for coal [127-30], would undoubtedly

be of value once a satisfactory process has been developed. No record of

attempts at such modeling appears in the open literature. The limited

recent attempts at modeling fluidized-bed retorts (Australia) [136] and

oil shale blocks for modified in situ processes (LLNL) [141] do

incorporate some of the principles involved in Merrick's approach to

properties modeling. Work is under way currently at LLNL on modeling of

the pyrolysis process.

7 . RECOMMENDATIONS

Some indication of research needs for oil shale, particularly for

thermophysical properties, are included in earlier sections of this

report

.

7 . 1 General Recommendations

The technology associated with oil shale is immature by comparison with

petroleum and coal technology. The deficiencies that exist in

fundamental knowledge are hampering those trying desperately to get

processes to work effectively.

Since adequate characterization of shales is a prime need, it would be

worthwhile to bring together a group of scientists and engineers with a variety of experience with shale to decide on what characterization

information would be most useful and to suggest how best to obtain it.

Methods of measuring these properties must be selected or developed so that the information generated will be transferable.

28
An agreement to concentrate research on the representative shales in

existing sample banks (U.S. Geologic Survey or the Department of Energy)

would extend the characterization of these shales and result in the

development of a more complete data bank on which correlations can be

based.

Once a satisfactory retorting process is developed, reliable and accurate

thermal property data will be required in order to refine the process and

scale it up for commercial production.

A survey of existing data applicable to oil shale processing and refining

should be conducted; these data must be evaluated and a systematic plan

for the generation of required data developed. (One reason for the success and efficiency of the petroleum industry is that it is based on extensive thermal and thermodynamic data that have been amassed through

the years. Systematic efforts are under way to provide similar

collections of data specific to coal and coal conversion.)

Specific needs conveyed to us by engineers and scientists with experience

in processing technology include heat of retorting values and heat

transfer coefficients both at retorting temperatures and at the

temperatures expected in the combustor. This information is required as

a function of heating rate, of ambient atmospheres, of pressure, and of

shale composition (organic and mineral and different ratios of aliphatic

and aromatic species). It is needed for raw, spent, and burnt shale, for

kerogen, and for the individual minerals found in shale. The retorted

shale should be prepared under different, but potentially realizable,

conditions to generate realistic mixtures of components.

The kerogen should be separated as completely as possible from the

mineral components of shale and the properties of kerogen determined.

Then mineral species in realistic proportions should be added one by one and the (kerogen + mineral) properties redetermined. The effects of the

minerals and mineral interactions can be evaluated only through such a systematic study.

A computer program that predicts the most probable mineral reactions

should be activated to identify the species most likely to exist.

Other needs that exist include heats of reaction of the mineral species

present in shales; heat capacities and enthalpies of raw, spent and burnt

shale; thermal conductivity; heat transfer coefficients; enthalpies of

hydration and dehydration of minerals with significant clay components.

(Heat capacity data exist for many pure minerals. At temperatures at

which there is no possibility for solid state reactions, heat capacities

and enthalpies of minerals are additive. At higher temperatures, like

those involved in the combustor, reactions occur and the additive

relationship can no longer be used. As thermal conductivity is required

29
for those same species, additivity relationships for this property must

be explored.)

A systematic comparison of heats of combustion of well-characterized

shales, including demineralized shales, by static and rotating bomb

calorimetry should be made.

Modifications of our coal model that will make it applicable to shale

should be investigated. It could provide the capability for modeling

heat capacity, thermal conductivity, thermal expansion, and heat

transfer. This modeling requires systematic studies of thermal

properties of shale as opposed to the isolated studies that have been

reported.

Problems mentioned to us often, but largely outside the intended scope of

this report, include those associated with solids handling and mechanical

problems and those leading to an understanding of the interactions

between mineral and organic components of shale. The abrasive nature of

oil shale results in the production of large quantities of fines, which

seriously affect the performance of retorts, particularly with regard to

the propagation of heat and products . As rich shales tend to produce

more fines than lean shales, this problem is especially serious for the

rich shales. In addition, flow channeling in retorts can limit oil

yields severely. Abrasion and mechanical properties should be studied as functions of pertinent variables outlined above.

7.2 Specific Recommendations

1. Complete a quantitative evaluation of existing thermophysical property

data

.

2. Develop procedures for the measurement of the heat of retorting of raw

shale if a suitable calorimeter is acquired or constructed.

3. Develop reliable procedures for measuring thermal properties of raw,

retorted, and burnt shale from room temperature to 973 K.

Measurements on raw shale will be confined to temperatures below and

above the region where reactions are occurring. This temperature region

will vary according to the shale used, particularly its mineral content.

Properties of interest here include heat capacity, thermal conductivity

(thermal diffusivity) , and perhaps, thermal expansion. For these

procedures, a first step will be to evaluate the procedures already

developed for other solid fuels/feedstocks when used with shale.

4. While verifying the validity of these procedures, they should be

applied to a wide range of shales. This will help to ensure that

problems like those related to the FA of eastern shales will be

eliminated or compensated for.

5. Develop a satisfactory modeling capability for the thermal properties

of shale. A first effort here could well be adaptation of the logic

contained in the program we use for coal.

30
6. Support the experimental requirements of the modeling effort byconducting in-house research and by coordinating research in industry and

academia .

7. Attempt to develop a satisfactory measurement procedure for the heat

of immersion of spent shale in various media (water, hydrocarbon liquid).

8. Explore possible connections between various processing treatments

and the thermal properties of the materials that result.

9 . Evaluate the effects of various atmospheres on thermal properties

.

10. Survey existing thermodynamic data for model compounds for oil shale.

11. Select model compounds appropriate to shale and measure properties,

especially thermodynamic.

12. Coordinate projects with industrial and academic research centers to

provide expanded expertise and experimental facilities.

13. Activate and adapt an existing adiabatic calorimeter to an in-house

study of heat capacity of model compounds.

31
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45
Table 1. Summary of consultations: oil shale

Government

Kentucky Energy Cabinet

Lawrence Livermore National Laboratory

Morgantown Energy Technology Center

United States Geological Survey: Denver; Reston, VA.

Western Research Institute

(formerly Laramie Energy Technology Center)

Industrial

Chevron Paraho (Cathedral Bluffs,

Colony, Shell)

Exxon

Geokinetics Phillips

IGT Texaco

J&A Associates TOSCO

Marathon Union Oil

Occidental

46
Table 2. Estimate of world-wide shale resources

(10 12 L)

Grade of Shale

U.S. L/tonne

(gal/ton)

20.9 - 41 .7

(5-10)

41 .7 - 104.3

(10-25)

104.3 ~ 417.3

(25-100)

Africa 53,550 9,520 476

Asia 70,210 13,090 654

Oceania

(Incl. Australia)

1 1 ,900 2,380 119

Europe 1 6 , 660 3,094 166

North America 30,940 5,950 357

South America 24,990 4,760 238

Total 208,250 38,794 2,010

47
Table 3. Oil shale resources of the United States

(10 12 L)

Grade of Shale

U.S. L/tonne

(gal/ton)

20.9 - 41.7

(5-10)

41 .7 - 104.3

(10-25)

104.3 - 417.3

(25-100)

Green River

Formation

476 333 143

Devonian and

Mississippian

Shale (Central

and Eastern USA)

238 119

Marine Shale

(Alaska)

large 24 30

Other deposits 15,946 2648 60

Total 16,660-30,940 3,124 - 5,950 232 - 357

48
Table 4. Estimate of abundance of eastern shales by hydroassay

State Area suitable for

surface mining

(square km)

Recoverable

resources

(10 9 L)

Ohio 2537 22,258

Kentucky 6861 30,208

Tennessee 3987 6,995

Indiana 1553 6,359

Michigan 41 4 795

Alabama 777 636

Total 16,129 67,251

49
Table 5. Organic and mineral constituents of eastern and western shales

Organic

Eastern Western

Ultimate Analysis, (dry basis) wt %

Organic Carbon 13.7 13-6

Hydrogen 1 .6 2.1

Sulfur 4.7 0.5

Carbon Dioxide 0.5 15.9

Ash 78.3 66.8

Fischer Assay Analysis

Oil Yield, wt % 4.6 1 1 .4

Assay, gal/ton 10.3 29.8

Minerals

Eastern Western

Kaolinite (Cl) Dolomite (CO)

Illite (Cl

)

Calcite (CO)

Chlorite (Cl Ankerite (CO)

(clay minerals) Dawsonite (CO)

Muscovite (Si) Magnesite (CO)

Quartz (Si) Mg Siderite (CO)

Feldspar (Si) Nahcolite (CO)

Zircon (Si) Albite (Si)

Tourmaline (Si) K Feldspar (Si)

Iron Oxides Analcime (Si)

Carbonates Quartz (Si)

Pyrite (S) Orthoclase (Si)

Apatite (Ph) Pyrite (S)

Illite (Cl)

Key: Cl, clay; CO, carbonate; Si, silicate; 0, oxide; S, sulfide

Ph, phosphate •

50
The organic constituents ofthe Green River shales (+) and the Toarcian shales (a)

of the Paris Basin are typical kerogens of Types I and II, respectively. Other oil shales

belong to either Type I (+) or II (M). Key: A, Autun boghead, Permian, France: B, Moscow boghead, Permian, USSR; C, Coorongite, recent, Australia; H, Marahunite,

Tertiary, Brazil; I, Irati shales, Permian, Brazil; Kj and Kr

Kukersite, Paleozoic. USSR;

M, Messel shale, Eocene, W. Germany; R, Kerosene shale, Permian, Australia; S, Tasmanite, Permian, Australia; Tr

torbanite. Carboniferous, Scotland; and T, tor- banite, Permian, Australia. The evolution path ofhumic coals (Type III) (9)

is shown

for comparison.

Figure 1. Van Krevelen diagram for oil shale kerogens.

Reprinted by permission of the American Chemical Society from

Geochemistry and pyrolysis of oil shales by B. P. Tissot and

M. Vandenbroucke in Geochemistry and Chemistry of Oil Shales,

F. P. Miknis and J. F. McKay, eds., ACS Symposium Series 230 , 1983 . Copyright 1983 by American Chemical Society.

51
03 x:m

jO

03u

CD>oo

<13 s_o

CO0> >

SUCD

CO

CD

£-LO3C3Oc

CM

<D

l,3

bO

52

Reprinted

by

permission

of

Noyes

Data

Corporation

from

Oil

Shale

and

Tar

Sands

Technology:

Recent

Developments

by

M.

W.

Ranney,

Noyes

Data

Corporation,

Park

Ridge,

N.J.,

1979.

Copyright

1979

by

Noyes

Data

Corporation.
53

Reprinted

by

permission

of

the

Colorado

School

of

Mines

Press

from

Oil

shale

resources

of

the

United

States,

by

John

Ward

Smith,

in

Mineral

&

Energy

Resources,

vol

.

23,

no.

6,

November

1980.

Copyright

1980

by

Colorado

School

of

Mines

Press.
Atm uadarlaiamfey IS* Graaa Rlwor Fonwl lw Arm uaM/lolamby oil thalo men th*a

I* which IS* ail (halo i« unwrainl or 10 '**4 thick, which yield 29 galloa*

low grab*. or mor* oil par toa of iMIc

Figure 4. Green River shale deposits.

Reprinted by permission of the Colorado School of Mines Press from Oil

shale resources of the United States, by John Ward Smith, in Mineral & Energy Resources, vol. 23, no. 6, November 1980.

Copyright 1980 by Colorado School of Mines Press.

54
HBS-1 1 4 A IRE V. 2-8 U.S. DEPT, or COMM.

BIBLIOGRAPHIC DATA

SHEET (See instructions)

1. PUBLICATION OR

REPORT NO. NBSIR 87-3064

2. Performing Organ. Report No, 3. Publication Date

April 1987

4. TITLE AND SUBTITLE

Review of Needs for Thermophysical Property Data on Solid Feedstocks. II. Oil Shale

5. AUTHOR(S)

Jane E. Callanan

6. PERFORMING ORGANIZATION (If joint or other than N BS. see instructions)

NATIONAL BUREAU OF STANDARDS

DEPARTMENT OF COMMERCE

WASHINGTON, D.C. 20234

7. Contract/Grant No.

8. Type of Report & Period Covered

9. SPONSORING ORGANIZATION NAME AND COMPLETE ADDRESS (Street. City. State, ZIP)

10. SUPPLEMENTARY NOTES

3 Document describes a computer program; SF-185, FIPS Software Summary, is attached.

11. ABSTRACT (A 200-word or less factual summary of most significant information. If document includes a significant

bi bl iography or literature survey, mention it here) This report, a comprehensive survey concerning oil shale, is the

second in a series dealing with needs, particularly for

thermophysical properties, for solid fuels/feedstocks. This survey

shows the need for experimental work on heat of combustion, heat of

retorting, heat capacity/enthalpy, thermal conductivity, thermal

expansion and heat of immersion for raw, spent and burnt shale,

for kerogen and for the mineral matter found in shale. These studies

should be preceded by agreement on the properties necessary for good

character izat ion of the shale and on the methods of measuring these

properties; the thermal properties measurements should be made on well-characterized samples. Standardized measurement techniques do

not exist for thermal properties, with the possible exception of heat

of combustion, and must be developed. Existing data must be

evaluated and reliable data generated. Theoretical studies that will

allow for modeling of thermal properties should proceed along with

the experimental investigations to improve the ability to predict

shale properties for process design. Recommendations for work

appropriate to the National Bureau of Standards are included.

12. KEY WORDS (Six to twelve entries; alphabetical order; capitalize only proper names; and separate key words by

enthalpy; heat capacity; heat of combustion; heat of

immersion; heat of retorting; oil shale; review; solid fuels

feedstocks; thermal conductivity; thermal expansion.

13. AVAILABILITY

r~Yl Uni imited

Q3] For Official Distribution. Do Not Release to NTIS

_3 Order From Superintendent of Documents, U.S. Government Printing Office, Washington, D.C.

20402.

|y~l Order From National Technical Information Service (NTIS), Springfield, VA. 22161

14. NO. OF

PRINTED PAGE

64

15. Pric

*U.S. GOVERNMENT PRINTING OFFICE: 19 8 7-0-775-584/651 60