E NVIRONMENTAL BENEFITS

of A DVANCED OI L and G A S E XPLORATION

and P RODUCTION TECHNOLOGY

U. S. D EPARTMENT of E NERGY

O FFICE of F OSSIL E NERGY
I NTRODUCTION

EXPLORATION DRILLING AND COMPLETION PRODUCTION

OPERATIONS IN SENSITIVE E NVIRONMENTS

F OSSIL RESOURCES

C ONTENTS

THROUGHOUT THE OIL AND GAS LIFE CYCLE, THE INDUSTRY HAS APPLIED AN ARRAY OF

ADVANCED TECHNOLOGIES TO IMPROVE EFFICIENCY, PRODUCTIVITY, AND ENVIRONMENTAL PERFORMANCE. THIS REPORT FOCUSES SPECIFICALLY ON

ADVANCES IN EXPLORATION AND PRODUCTION (E&P) OPERATIONS

(SHOWN IN COLOR BELOW).

10

6

FOREWORD

1 A Word from the Office 

of Natural Gas and 

Petroleum Technology 

2 Executive Summary

4 Making a Difference 

to the Environment

OUR QUALITY OF

LIFE RELIES ON

OIL AND GAS

8 Demand for Natural Gas

and Oil Continues to Grow

A HISTORY OF

INNOVATION

12 E&P Trends: Smarter,

Farther, Deeper, Cleaner

14 Meeting the Challenges of 

a Mature Resource Base

18 More Efficient, More

Effective, More Protective

of the Environment

ENVIRONMENTAL

BENEFITS OF

ADVANCED E&P

TECHNOLOGY

26 Exploration

32 Drilling and 

Completion 

42 Production

50 Site Restoration 

56 Operations in Sensitive

Environments

• Arctic

• Wetlands and Coastal

• Offshore

• Urban

• Public Lands

THE FUTURE CHALLENGES

TECHNOLOGY

FACT SHEETS

In-depth technical discussions

and case studies of 36 advanced

E&P technologies and their

associated economic and

environmental benefits.

APPENDICES

• Sources of Additional

Information

• DOE Oil and Gas Programs

• References

66

76

24

From fossil resources to

products, the entire oil 

and gas life cycle typically

spans 7 to 10 years.

Development of more

challenging resource areas,

however, such as the 

Outer Continental Shelf,

can take up to 20 years.

Oil and gas resources 

are organic, formed by 

the effects of heat and

pressure on sediments

trapped beneath the

earth’s surface over 

millions of years. While

ancient societies made

some use of these

resources, the modern

petroleum age began 

less than a century and 

a half ago. Advances in

technology have steadily

improved our ability to

find and extract oil and

gas, and to convert them

to efficient fuels and 

useful consumer products.
O IL AND G A S T ECHNOLOGY 1

IN THE PAST THREE DECADES , the petroleum

business has transformed itself into a high-technology

industry. Dramatic advances in technology for exploration, drilling and completion, production, and

site restoration have enabled the industry to keep up

with the ever-increasing demand for reliable supplies

of oil and natural gas at reasonable prices. The productivity gains and cost reductions attributable to

these advances have been widely

described and broadly recognized.

But public awareness of the significant and impressive environmental benefits from new exploration

and production (E&P) technology

advances remains limited. • T H E

U.S. DEPARTMENT OF ENERGY

is responsible for achieving national

objectives in the fields of energy 

and the environment. We believe it

is important to tell this remarkable

story of environmental progress in

E&P technology. Greater awareness

of the industry’s achievements in

environmental protection will provide the context for effective policy,

and for informed decision making

by both the private and public

sectors. • LOOKING FORWARD, the domestic oil

and gas industry will be challenged to continue

extending the frontiers of technology. Ongoing

advances in E&P productivity are essential if producers are to keep pace with steadily growing

demand for oil and gas, both in the United States

and worldwide. Continuing innovation will also be

needed to sustain the industry’s leadership in the

intensely competitive international arena, and to

retain high-paying oil and gas industry jobs at

home. Progressively cleaner, less

intrusive, and more efficient technology will be instrumental in

enhancing environmental protection in the future. • OUR NATION

has come to expect the benefits of

fossil-based fuels and products 

and a clean environment. The oil

and gas industry has consistently

responded to provide both. The

Department of Energy looks forward to increased dialogue with 

the oil and gas industry and other 

stakeholders. With commitment 

to a shared vision, with collaboration, and with continued private

and public investments, the oil 

and gas industry can continue to

deliver essential energy resources

and protect the environment, for ourselves and for

the generations to come.

A WORD FROM THE OFFICE

O F NATURAL GAS AND

P ETROLEUM TECHNOLOGY

F OREWORD

SITE RESTORATION T RANSPORTATION REFINING AND PRODUCTION PRODUCTS

POWER GENERATION

The U.S. oil and gas industry 

employs 1.4 million people 

and generates about 4 percent 

of U.S. economic activity. 

It is larger than the domestic 

auto industry and larger than

education and social services, 

the computer industry, and the

steel industry combined. 

The exploration and production

sector alone employed nearly

326,000 people in 1998.

Photo: © SPE, 1993
Oil and Natural Gas Are Critical

to the U.S. Economy

OIL AND NATURAL GAS ACCOUNT

for virtually all transportation fuel in the

United States and a majority of our total

energy use, and provide the raw materials for

countless products used in our daily lives.

Americans have come to take these resources

and products largely for granted and expect

them to be available and affordable. 

For over a century, the oil and 

gas industry has successfully met

rising demand for these valuable

resources. 

Continuous innovation has characterized the

oil and gas industry throughout its history.

In recent decades, new technologies have been

key to finding and extracting recoverable oil

and gas resources—located in deeper and

more remote locations, in more challenging

geologic formations, in difficult terrain, in

smaller pockets, under sensitive wetlands and

tundra, and far out at sea. As the world’s

most mature oil and gas province—and

home of some of the world’s most rigorous

environmental standards—the United States

has been the site of much of the industry’s

innovation in exploration and production

(E&P) technology. 

American ingenuity, know-how, 

and entrepreneurial spirit have

created the necessary technology 

to maintain reliable oil and gas

supplies in a volatile marketplace.

Technology innovation has enabled the

domestic industry to remain viable in an

energy business where highly competitive

global markets determine prices. The industry has developed more efficient E&P technology to enable continued exploration,

development, and production through the

boom and bust cycles that are characteristic

of world oil markets.

Nowhere have the dual requirements

of producing more challenging

resources and protecting the

environment been as pressing as 

in the United States.

Hand-in-hand with overcoming tough

geologic and geographic conditions, the

industry has also developed new technology

and management techniques for enhanced

protection of our environment.

While increasing productivity,

technology innovation has also

yielded environmental benefits.

Today’s exploration technology, for example,

is boosting industry success rates in pinpointing new resources. The results: fewer

dry holes, reduced waste volumes, and less

environmental disruption. Across the E&P

spectrum, new technology is delivering:

• More efficient recovery of oil and gas

resources. Continuing improvements in

recovery efficiency per well translate into

fewer wells (and less impact from drilling

operations) to achieve the same level 

of reserves. 

• Smaller footprints. Smaller, lighter rigs and

advances in directional and extended-reach

drilling shrink the footprint of oil and gas

operations and reduce surface disturbance. 

• Cleaner, safer operations. Advanced, more

energy-efficient drilling and production

methods cut emissions of air pollutants

and greenhouse gases, practically eliminate

spills from offshore platforms, and translate

into enhanced worker safety, lower risk of

blowouts, and better protection of groundwater resources. 

2 E NVIRONMENTAL B ENEFITS

F OREWORD

E XECUTIVE S UMMARY
O IL AND G A S T ECHNOLOGY 3

F OREWORD

Environmental Protection is

Good Business

THE U. S . OIL AND GAS INDUSTRY

has integrated an environmental ethic into its

business culture and operations. The industry

has come to recognize that high environmental standards and responsible development

are good business, and it is demonstrating its

commitment to protecting the environment

in research and technology investments,

policies and practices, and participation in a

host of voluntary environmental protection

programs. Industry’s use of smarter, more

efficient technology complements these trends.

Advanced E&P technology provides

environmental benefits beyond the

oil and gas industry. 

Innovations pioneered by the oil and gas

industry are now being used in a wide range

of applications. Geologic and geophysical

technology are providing information on the

fundamental characteristics of the earth’s

crust, enabling better prediction and evaluation of earthquakes and other geologic hazards.

Reservoir simulation and performancemonitoring technology are being used to

predict groundwater flow patterns. And the

same principles used to increase the recovery

of oil—such as thermal and microbial

processes—are now applied to clean up

chemical spills.

Continued technology progress 

will be essential in meeting the

challenges of the 21st century. 

Further increases in productivity will be

essential to sustain the viability of the U.S.

petroleum industry in the face of a sometimes volatile world oil market. Industry 

and government leadership and American

ingenuity will be necessary to preserve our

Nation’s oil and gas production capacity

and energy security. In the longer term,

technology innovation will be critical to

ensure optimal recovery of America’s oil

and gas resources, while respecting the

environment and other public values.

Technology innovation will be key to overcoming the constraints of an increasingly

challenging resource base, domestically and

around the world.

Industry and government both 

have roles in advancing E&P 

technology progress and

environmental performance.

Environmental quality will be a continuing

issue for the oil and gas industry. America’s

oil and gas industry must find the means,

including new technology, to address future

environmental challenges, such as global

climate change. Industry must continue to

demonstrate its commitment to responsible

development. Government must provide a

rational regulatory framework and reasonable

access to resources. Open communication 

is also critical to meeting these objectives.

Continued investment, both private and

public, will be required to advance E&P

science and technology.

America’s legacy of technology

progress and improved environmental management in E&P

provides a solid foundation for

meeting the challenges of the future.
4 E NVIRONMENTAL B ENEFITS

I NNOVATION IN OIL AND GA S E&P TECHNOLOGY:

MAKING A DIFFERENCE

TO THE E NVIRONMENT

Right Where We Live and 

Around the Globe

FROM COAST TO COAST, INNOVAtive E&P approaches are making a difference to the environment. With advanced

technologies, the oil and gas industry 

can pinpoint resources more accurately,

extract them more efficiently and with less

surface disturbance, minimize associated

wastes, and, ultimately, restore sites to

original or better condition. Most of these

advances have been pioneered in the

United States, but many are now also

providing benefits around the globe. 

Increasingly, in our own backyards and 

in all corners of the earth, innovation 

is the key to producing oil and gas while

protecting neighborhoods and natural

habitats. Here are just a few examples 

of the contributions being made by 

new technology.

WEST COAST

California

• ARCO Long Beach, Inc.’s production operations

in Long Beach Harbor represent a model

approach to operating in sensitive urban environments. To shield the harbor’s operations

from the public, drilling rigs are disguised as

high-rise buildings, and other above-ground

facilities have been masked with palm trees,

concrete sculptures, waterfalls, and colorful

night-lighting. Advanced horizontal drilling and

hydraulic fracturing technology, combined with

the largest waterflood in California’s history,

have increased production by approximately 

30 percent in recent years.

• In the southern California town of La Habra, the

area’s rolling hills, once the site of oil production

from the West Coyote field, are now covered

with premium homes, thanks to painstaking

site restoration upon the field’s closure. 

• Thermal enhanced oil recovery technology is

increasing production rates and ultimate

recovery from the mature, “heavy” oil fields of

Kern County, California, and surrounding areas.

For example, decades-old steam floods are

facilitating production at some of the Nation’s

largest, most mature fields, including MidwaySunset, South Belridge, and Kern River. 

NORTHERN PLAINS 

Montana, North Dakota, South Dakota

• Advanced horizontal drilling and measurementwhile-drilling technology are enabling recovery

of previously untapped resources in the Williston

Basin’s Red River B Formation, spread across

Montana and the Dakotas. In 1994, horizontal

drilling technology facilitated the discovery 

of the Cedar Hills play, the Nation’s largest

onshore discovery in the last 25 years. 

GULF OF MEXICO AND 

GULF COAST

Texas, Louisiana, Mississippi, Alabama, Florida

• New subsalt imaging technologies, aided by

today’s super-powered computers and advanced

mathematical modeling concepts, are enabling

operators to get a clearer picture of the Gulf’s

hydrocarbon-rich subsalt play, facilitating exploration success and greater resource recovery.

F OREWORD

1

8

1 2

3

3

5 4

6

7 2

■ Major areas of oil and gas potential
O IL AND G A S T ECHNOLOGY 5

MID-CONTINENT 

Nebraska, Kansas, Oklahoma

• Visitors to Oklahoma City’s Will Rogers World

Airport are greeted with the sight of pumpjacks

and other production equipment and facilities —

the airport is located in the heart of an active 

oil field.

• Funded exclusively through voluntary contributions by Oklahoma’s oil and gas producers

and royalty owners, the Oklahoma Energy

Resources Board (OERB) restores orphaned and

abandoned well sites around the State. By

removing abandoned oilfield tanks and other

equipment and remediating saltwater erosion

and oil-stained soil, OERB is returning land to

productive use, at no cost to landowners.

TEXAS

• Advances in horizontal and multilateral drilling

have been critical to increasing production in

the mature, highly fractured Austin Chalk play

in southeast Texas. In the Clay NE field, for

example, horizontal drilling has increased gas

production fourfold since 1991. The Chalk has

been the site of 90 percent of U.S. horizontal

land rigs since the late 1980s.

• Since the early 1970s, the Permian Basin region

of west Texas and southeast New Mexico has

been home to innovative miscible CO2-injection

enhanced oil recovery projects. The largest and

oldest of these projects, the SACROC Unit in

Scurry, Texas, is a fieldwide project over nearly

50,000 acres that began over 25 years ago. 

ALASKA

• Ice roads and ice pads have significantly

reduced the impacts of exploratory drilling

operations on the North Slope, protecting 

the area’s fragile tundra and ecosystem.

• Extended-reach, horizontal, multilateral, and

“designer” directional drilling technology has

enabled North Slope operators to tap more

resources, while minimizing drilling footprints

and avoiding sensitive habitats.

• In the past 30 years, production footprints have

shrunk dramatically. Production pads have been

reduced by up to 80 percent, and wellhead

surface spacing has been reduced by over 

75 percent. If built today, the Prudhoe Bay oilfield’s footprint would be 64 percent smaller.

• Advanced offshore platforms—tension leg

platforms; mini-TLPs; spars; and floating production, storage, and offloading systems—and

subsea completions are equipping offshore

operators to explore and produce in deeper,

more remote, and harsher environments. These

advances enable increased access to deepwater

resources, while minimizing disruptions to

ocean ecosystems. 

• State-operated artificial reef programs turn

decommissioned offshore platforms into 

permanent reef structures, creating complex

and vibrant subsea “living communities” and

also enhancing commercial and recreational

fishing opportunities.

• Synthetic drilling fluids are fast becoming the

drilling fluid of choice for many complex deepwater drilling operations. Combining the

advanced operational properties of oil-based

muds with the environmental benefits of waterbased drilling fluids, synthetic fluids enable

operators to drill faster and cheaper, with less

overall environmental impacts.

ROCKY MOUNTAINS 

Wyoming, Colorado, New Mexico

• In the gas-rich San Juan Basin, advanced

coalbed methane production and completion

technologies—such as nitrogen injection and

CO2 flooding—are unlocking clean-burning

methane from coal seams, substantially

increasing our domestic gas supply.

• Smarter operations in the Rockies enable

successful exploration and production while

protecting an environment marked by rugged

mountains, sensitive Federal lands, and fragile

habitats. For example, in Wyoming’s BridgerTeton National Forest, drilling operations were

conducted using a helicopter to transport 

the drilling rig and other heavy equipment,

minimizing environmental impacts. 

APPALACHIA

Pennsylvania and Kentucky

• Field trials in central Pennsylvania and the

Devonian Shales of Kentucky indicate that

innovative CO2-sand fracturing technology can

significantly increase gas production in certain

types of wells and reservoirs, while reducing

waste volumes and formation damage.

• In Pennsylvania, “roadspreading” brine

produced from oil and gas wells has proven 

to be an effective dust suppressor and road

stabilizer on unpaved secondary roads. This

beneficial use of an oilfield waste reduces the

volume of wastes that would otherwise need 

to be disposed of by oil and gas operators.

F OREWORD

4

5

6

7

8
6 E NVIRONMENTAL B ENEFITS

O IL AND G A S I NDUSTRY

T HE LIFESTYLE U.S. CITIZENS ENJOY, THE ENVY OF MUCH OF THEworld, was built in large measure on reliable, affordable oil and natural gas

supplies. Over the past century, these valuable resources have been instrumental in

transforming America’s economy from agrarian to industrial to high-technology,

steadily improving our standard of living. • Energy remains the lifeblood of our economy, powering our factories and communities, heating and cooling our homes, and

moving people and goods. We rely on oil and gas to supply two-thirds of our energy

needs. Fuels derived from oil and gas provide virtually 100 percent of our transportation demand, and an ever-increasing proportion of our electricity.

OUR QUALITY OF

RELIES

E XPLORATION

S ITE R ESTORATION

P RODUCTION

D RILLING AND

C OMPLETION

O PERATIONS IN

S ENSITIVE

E NVIRONMENTS

■ Oil ■ Gas ■ Electricity ■ Hydro/ Renewables ■ Coal ■ Nuclear 

*Electricity share is prorated. 

Source: Energy Information Administration

TRANSPORTATION RESIDENTIAL BUSINESS

THE U . S . RUNS ON OIL AND GAS

100% Oil and Gas 64% Oil and Gas* 60% Oil and Gas*
O IL AND G A S T ECHNOLOGY 7

E XPLORATION AND P RODUCTION

LIFE

ON OIL AND GA S

In thousands of products —

as diverse as food preservatives, clothing, toys, sports

equipment, antiseptics, and

computers—we rely on

petroleum-based materials.

FUELS , PLASTICS , POWER

... AND MUCH MORE

AMERICANS DEPEND ON THE

benefits of oil and gas without always being

aware of the vital role these resources play in

their daily lives. The use of petroleum-based

products extends far beyond fuels and power

for our homes, cars, and factories. The

strength, durability, and flexibility of petroleum-based plastics, resins, and foams 

make them an inexpensive, resilient, and

lightweight alternative to non-petroleum

materials such as wood, iron, and steel.

Petroleum products touch our lives 

hundreds of times in a typical day. When 

we wake to a digital clock, brush our teeth,

take a vitamin, see our kids off for school 

in their vinyl raincoats, and commute to

work...When we work on computers, use

our credit cards, play golf, and fertilize the

garden...When we cook dinner, touch up

paint on the shutters, and tuck the kids into

bed in their flame-retardant pajamas. In 

all of these activities, we rely on products

derived from petroleum.

INDUSTRY ELECTRICITY

72% Oil and Gas* 13% Oil and Gas

Photo: Walt Seng
8 E NVIRONMENTAL B ENEFITS

O U R Q UALITY of L IFE

R ELIES ON O IL AND G A S

DEMAND FOR NATURAL GAS AND

OI L C ONTINUES TO GROW

Providing Abundant Supplies 

at Reasonable Prices

EVEN AS INDUSTRY, GOVERNMENT,

and academia conduct research and development on alternative sources of energy,

reliance on oil and natural gas for fuels,

electric power, and other products will continue into the foreseeable future. With the

potential of technology to affordably meet

almost any need, American consumers

demand the convenience and benefits of 

gas- and petroleum-based fuels in abundant

quantities, at reasonable prices, and with

minimal environmental impact.

The U.S. Energy Information Administration

(EIA) projects that U.S. demand for refined

petroleum products will grow by over 35 percent in the next two decades, increasing from 

18.0 million barrels per day in 1996 to 24.6

million barrels per day by 2020. Natural 

gas demand is expected to rise even faster, 

by at least 45 percent, from 22 trillion cubic

feet (Tcf) per year in 1996 to between 32 and

37 Tcf in 2020. Actual rates of growth will

depend on the effects of ongoing electric

utility restructuring, more stringent air emission controls, advances in transportation

technology and infrastructure, and efforts to

minimize the potential impacts of global

climate change.

Natural Gas... 

the Cleaner Choice

AS CONCERNS ABOUT GREENHOUSE

gas emissions and global climate change have

intensified, cleaner-burning natural gas has

become the fuel of choice. Though coal and

oil will remain the dominant fossil fuels for

decades to come, natural gas will certainly

play an increasing role in the Nation’s energy

future. Whether discovered and produced in

isolation or in association with crude oil

production, natural gas has always been an

economical and popular fuel for heating,

lighting, and cooking. 

Unlike oil and refined liquids, however,

natural gas must be transported by pipeline.

Until recently, where pipelines were not

technically or economically feasible, 

wells where only gas was discovered were

frequently plugged and abandoned.

Fortunately, in recognition of its environmental desirability, natural gas use has grown.

Major advances in natural gas technology

and supply have occurred over the past 

25 years. New technology for finding, producing, transporting, storing, and using

natural gas has been developed. Increasingly

higher estimates of economically producible

natural gas resources have improved the

market’s confidence in the reliability of 

long-term supplies.

Source: Energy Information Administration, 1998

Projections of U.S. Natural Gas

Consumption, 1970 – 2020

(Quadrillion Btu)

Projections of U.S. Petroleum 

Consumption, 1970 – 2020

(Quadrillion Btu)

1970

2020

2000

40

30

20

10

0 1970

2020

2000

40

30

20

10

0

■ History

■ Projection
O IL AND G A S T ECHNOLOGY 9

1970

1971

1972

1973

1974

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

19961997

Average U.S. City Retail Price —Per Gallon Including Taxes

.30

.55

.80

1.05

1.30

1.55

1.80

2.05

2.30

Consumer Price Index-Urban(1982-84=100)

165

155

145

135

125

115

105

95

85

75

65

55

45

35

Motor Gasoline Prices vs. 

General Consumer Prices: 1970-1997

Consumer Prices

Gasoline (Nominal)

Fueling a Mobile Society

A quarter of a century after the 1973 Arab Oil Embargo,

when Americans waited in lines for gasoline, crude oil and

refined products (in real terms) are relatively inexpensive. In

fact, gasoline prices declined by 6 percent in real terms

between 1970 and 1997.

An “unscientific comparison pricing” survey released in

April 1998 demonstrates just how great a bargain petroleumbased fuels are compared to other widely used consumer

products. The survey—by Connecticut-based research firm

John S. Herold Inc.—found that a barrel of crude oil ($15.25)

or gasoline ($45.36) is significantly cheaper than Coca Cola®

($78.38), milk ($126.00), Evian® water ($189.80), or orange

juice ($251.16). Visine® topped the list at $238,133 per barrel.

Source: Oil and Gas Investor, June 1998

Source: American Petroleum Institute and Bureau of Labor Statistics
10 E NVIRONMENTAL B ENEFITS

O IL AND G A S I NDUSTRY

T HROUGHOUT ITS HISTORY , THE OILand gas industry has been shaped by the vision

and initiative of technologists. Today’s innovators

and entrepreneurs can be found in service companies,

engineering and consulting firms, small independent

producers, multinational integrated oil and gas

companies, government, and academia. They are

responding to current challenges with the same

driving focus on opportunity that characterized the

industry’s earliest days.

A HISTORY OF

A New Generation of Pioneers 

for a New Millennium

FROM THE MOMENT THAT THE FIRST U.S. OIL

well was drilled in 1859, the progress of the oil and gas

industry has been a chronicle of technological advancement.

In the early “oil boom” decades, explorers joined forces with

entrepreneurs, engineers, and skilled craft workers to invent a

dynamic industry. Through experimentation, hard work, and

simple necessity, these pioneers rapidly developed the fundamental tools and systems for finding, extracting, transporting,

and processing oil. As the industry matured, its scientists and

technologists led the way in improving our understanding of

earth sciences, geology, geophysics, and chemistry.

Now, another wave of technological innovation is transforming the oil and gas industry. The focus this time is on finding

economically viable ways to continue discovering and producing oil and gas from an increasingly challenging and more 

remote U.S. resource base. Without new solutions to extend

their productive life, more U.S. oil and gas fields will have to

be abandoned. Complex environmental protection standards 

add to the costs and challenges. The industry seeks ways 

to cost-effectively meet Federal and State requirements, and 

to produce from sensitive environments in wetlands, in coastal

and offshore waters, or under the frozen tundra of Alaska. 

More resource-efficient and less intrusive E&P approaches 

are key to meeting these challenges. This report highlights 

the dramatic progress of the past two decades in enhancing

the power, productivity, safety, and environmental performance of oil and gas technology. It is a record of achievement

that would have seemed a fantasy to the wildcatters in the

industry’s early days.

The petroleum industry has 

progressed from Colonel Drake’s

shallow 1859 well to satellite 

and computer-guided technology

operating miles above and below

the earth’s surface.

Photo: Pennsylvania Historical & Museum

Commission, Drake Well Museum Collection,

Titusville, Pennsylvania
O IL AND G A S T ECHNOLOGY 11

E XPLORATION AND P RODUCTION

Milestones

1859 Drake well dug by hand

’70 First cable tool rig

’90 Rotary drilling developed

1933 First whipstock for directional drilling

’35 First tri-cone bit

’39 First horizontal well drilled (Havener Run field 

in Morgan County, OH)

’47 First offshore directional wells drilled (Gulf of Mexico)

’53 First truly multilateral well drilled

’54 First hydraulic rotary rig

First directional drilling assembly

’55 Craig-Geffen-Morse waterflooding model developed

’61 First use of dynamic positioning

’66 Computerized well data monitoring

’69 First coiled tubing rig job

’71 Polycrystalline diamond compact bit introduced

2-D seismic prevalent, computers convert drill velocity 

data into geological information

’72 Landsat satellite becomes available for remote sensing

’74 3-D seismic data acquisition tested in Gulf of Mexico

’75 First floating production system begins operation

First commercial 3-D seismic survey recorded

’78 First measurement-while-drilling (MWD) system

’80 Cost of 3-D post time depth migration (PTDM) estimated 

at $8 million for 50 square miles

’81 First offshore horizontal well (Rospo Mare field, 

offshore Italy)

’83 Horizontal wells drilled from vertical shaft (Kern River, CA)

’84 First steerable drilling system

New resistivity measurement devices

’85 3-D vertical seismic profiling developed

’86 Metal sealed-bearing roller cone bits

Neutron porosity measurement capability added to MWD

’87 First logging while drilling (LWD) tool

’88 Extended-reach drilling exceeds 60-degree radius

First horizontal well drilled from semisubmersible drill rig

’89 Only 5% of Gulf of Mexico wells based on 3-D seismic data

’90 Horizontal well achieves 14,585 linear feet

’91 15,000-foot horizontal well drilled with directionally 

controlled coiled tubing

’92 Slimhole horizontal well (3 3⁄8”) drilled 801 feet

’93 3-D surveys worldwide cost $1 million for 50 square miles

MWD tools advance —smaller, broader temperature

range, pressure detection, geosteering

’94 Digital image processing of 3-D

’95 3-D seismic used for 75% of U.S. onshore surveys

4-D seismic emerges

’96 80% of Gulf of Mexico wells based on 3-D seismic data

4-D seismic characterization methodology applied to

previously recorded seismic surveys

’97 Extended-reach drilling achieves 26,450 feet horizontal

displacement in South China Sea

Magnetic resonance imaging begins on MWD

3-D PTDM cost reduced to $90,000 for 50 square miles 

by the year 2000

Photo: Larry Lee

INNOVATION
A H ISTORY of I NNOVATION

Today’s optical and radar satellites

cost-effectively pinpoint promising

geological formations.

E&P TRENDS : S MARTER , 

FARTHER , DEEPER , CLEANER

Exploring Frontiers and 

Embracing Change

ON THE THRESHOLD OF THE NEW

millennium, the oil and gas industry has

transformed every phase of exploration and

production operations, from initial prospect

identification to final project closure and 

site restoration. Today’s advanced exploration and production operations are models

of high technology and resource efficiency.

They incorporate high-speed computing,

remote sensing and imaging, geologic interpretation, and visualization technology. 

They use global positioning systems, the

latest geographical information systems, and

3-D seismic and 4-D imaging capabilities. Higher Success Rates, Enhanced

Productivity, Reduced Impacts

THANKS TO PRODUCTIVITY GAINS

from advanced E&P technology, the oil and

gas industry has dramatically increased the

ultimate recovery of resources from existing

fields and become progressively more

successful in pinpointing promising new

reservoirs. In turn, higher productivity means 

less impact on the environment and better

protection of our precious resources. 

Technology Leadership for 

a Strong U.S. Economy

THE UNITED STATES HAS BEEN THE

proving ground for developments on all

these fronts, as market-based drivers have

fostered flexibility and innovation. In striving

to reduce costs and remain competitive, the

E&P industry has embraced new technology

at a rapid pace. Simultaneously, a sizeable

number of smaller companies have come 

on the scene, carving out profitable niches

based on specialized technological capabilities. Recent trends toward more alliances 

and mergers in the oil and gas industry—

created largely to fill gaps in technological

strengths—may further accelerate the rate 

of future innovation. The domestic industry’s aggressive application of new technology positions U.S. companies to remain

world leaders in E&P technology. 

“The oil industry still produces oil, but it

has been infused by so many new technologies that it should be thought of as

one of the new manmade, brain-power

industries like biotechnology.”

LESTER T HUROW

Economist

Source: Price Waterhouse World Energy Conference,

November 1997

12 E N V IRONMENTAL B ENEFITS

Photos: Corbis Images
O IL AND G A S T ECHNOLOGY 13

OIL AND GA S OPERATIONS

E XPLORATION

Techniques have progressed from surface observation and divining

rods to the use of satellites, microprocessors, remote sensing, and

super computers to generate three-dimensional and four-dimensional

time-lapse imaging of subsurface reservoirs. Sharply increased drilling

success rates have cut the number of both wells drilled and dry holes. 

D RILLING AND C OMPLETION

Technology has advanced from gravity-driven cable tools in vertical

wells to top-drive rotary rigs, coiled tubing units, advanced drilling

fluids, and systems that monitor wellbore conditions during drilling

operations. Current technology allows directional and horizontal

drilling to reach previously inaccessible resources as well as to drill

in deeper offshore waters. Durable forged alloys and polycrystalline

diamond have replaced brittle cast iron bits, boosting drilling

productivity and efficiency. Enhanced worker safety, habitat

protection, lower and less-toxic waste volumes, and increased 

well productivity are the results.

P RODUCTION

Techniques have evolved from collecting crude oil in wooden barrels

from open gushers, which recovered less than 10 percent of the oilin-place, to gas, thermal, and chemical injection techniques that 

can recover, in some cases, up to 50 percent or more of the original

oil-in-place without spilling a drop. Today’s techniques for reducing

emissions of methane (natural gas) have allowed operators to recover 

an ever-increasing proportion of this valuable resource. These recovery 

techniques, which are enhanced with 4-D time-lapse imaging, are

directly transferable to other industries, such as groundwater resource

management and industrial pollution remediation.

S ITE R ESTORATION

Despite the continued advance of technology, mature oil fields

eventually cease being economic, must be shut down, and the

production site restored to near-original conditions or conditions

appropriate for alternative uses. Once capped at the surface and

abandoned, wells are now plugged below ground and restored,

leaving little or no visible evidence they ever existed. Rigs toppled

offshore in “rigs-to-reefs” programs actually improve the habitat for

marine life, yielding benefits to oil and gas producers, commercial

and recreational fishing industries, and the marine environment.

O PERATIONS IN S ENSITIVE E NVIRONMENTS

Resources underlying arctic regions, coastal and deep offshore waters,

sensitive wetlands and wildlife habitats, public lands, and even cities

and airports can now be contacted and produced without disrupting

surface features above them. Wildlife preserves and conservation

easements are created and managed jointly by industry, environmental, and government stakeholders. In Alaska, such new

approaches as ice pads and roads, multilateral completions, and

annular injection of drilling wastes minimize environmental

impacts while also reducing costs.
14 E NVIRONMENTAL B ENEFITS

A H ISTORY of I NNOVATION

MEETING THE C HALLENGES

OF A MATURE RESOURCE B ASE

Mature Resource Base: 

Perception vs. Reality

T H E UNITED STATES IS THE MOST

mature petroleum-producing province in 

the world—much of our easy-to-find

resource base has been depleted. So should

we be concerned that the United States will

soon stop producing oil and gas? Not if the

past two decades are any indication. 

With our easily recoverable resources largely

depleted, it would be logical to expect

resource development opportunities in the

United States, relative to the rest of the

world, to continue to diminish. Conventional

wisdom would predict a relentless drop in

U.S. reserve additions and well productivity

and a continued increase in finding costs. 

In fact, quite the opposite has been the case.

E&P Successes Defy 

Conventional Wisdom

DESPITE THE FACT THAT THE

United States is the most mature hydrocarbon region of the world, 11 percent of all the

petroleum reserves ever added in the United

States (since 1859) have been added in just

the last eight years. Over these eight years,

the United States has replaced 100 percent 

of the gas it has produced, 104 percent of the

natural gas liquids, and 79 percent of the

crude oil. The overall replacement rate for

hydrocarbons in the United States over the

last eight years is 92 percent, despite high

rates of production. And in the past three

years, total hydrocarbon reserve additions

have exceeded production by 8 percent. 

Advanced technologies have been behind 

the logic-defying trends in E&P, allowing

economic access to domestic resources that

are concentrated in deeper formations,

tighter zones, deeper water, more sensitive

environments, and increasingly more 

unconventional settings. 

“This industry...can, at $15 or $16 a barrel,

do things that it thought it couldn’t do at

$30 a barrel a decade ago. It’s an industry

that’s being transformed by technology

and computers. It’s an industry that can

do much better at lower prices. It’s an

industry that’s surprised itself.”

DANIEL YERGIN

Chairman

Cambridge Energy Research Associates

Source: New York Times, August 16, 1998

Source: U.S. Geological Survey, modified by ICF Resources Incorporated

■ States producing oil and gas

■ Major areas of oil and gas potential
O IL AND G A S T ECHNOLOGY 15
1 1 1

11

12

14

14 14

14

14

13

13

17

18

1 1 1

15

13

1 1 1

1 1

8

9

2

19

2

2

2 1

3

4

4

6

6

7

7

10

5

5

16

16

16

16 E NVIRONMENTAL B ENEFITS

A H ISTORY of I NNOVATION

Tapping Resources Once 

Thought Unreachable

CONTINUAL INNOVATION OVER THE

last three decades has enabled the E&P

industry to drill ever deeper, with fewer dry

holes, and to recover more reserves per well

drilled. When onshore production in the

lower-48 States began to decline in the 1970s,

for example, waterflooding and gas pressure

maintenance practices helped to increase U.S.

crude oil production. Enhanced oil recovery

technologies were used as early as 1967 and

gained serious attention when the price and

import supply shocks of 1973, the Iranian

revolution, and the Iran/Iraq war stimulated

significant research and development investments by industry and the U.S. Department

of Energy. More recently, sophisticated

imaging technologies, including 3-D seismic

and 4-D time-lapse systems, have provided

oil and gas professionals with detailed pictures

of reservoirs and formations, enabling more

accurate and productive exploration and

development efforts.

E&P Capabilities 

Spell Opportunity

THESE AND MANY OTHER ADVANCED

E&P technologies have literally redefined

reserves. Oil and gas at depths recently

considered unreachable can now be tapped. 

Smaller accumulations once thought to be

uneconomic can now be produced profitably. Fields under wetlands or cities can be

accessed without disruption of the surface.

Particularly impressive is the industry’s track

record in effectively extracting additional

resources from previously discovered, older

fields. Since 1990, the vast majority of reserve

additions in the United States—89 percent

of oil reserve additions and 92 percent of gas

reserve additions—have come from finding

new reserves in old fields. Recent studies

found that about half of these additions are

from development-dominated growth

(growth from more intensive development

within the limits of known reservoirs), with

the other half coming from more explorationAnnual Reserve

Additions of Crude Oil

(Millions of barrels)

3,000

2,000

1,000

0

Source: Energy Information Administration, 1998

Annual Reserve

Additions of Natural Gas

(Billions of cubic feet of dry natural gas)

21,000

14,000

7,000

0

1990

1997

1997

1990

Estimated Recoverable 

Gas Resources (Tcf)

Range of government and private 

estimates on recoverable gas resources

(several estimates are for the lower- 48

States only). All estimates are adjusted

for production since date of estimate.

Source: William L. Fisher, 1994, modified by 

ICF Resources Incorporated

■ Reserve additions in known fields

■ New field discoveries

dominated growth (growth from finding 

new reservoirs in old fields and in extending

the boundaries of oil fields). 

As E&P capabilities continue to grow, so

does the consensus of estimates of recoverable U.S. oil and gas resources. For example,

in the 1970s, the consensus of estimates of

ultimately recoverable gas resources was 

on the order of 400 trillion cubic feet (Tcf).

Today, adjusting for what has already been

produced, estimates range from 1,200 to 

over 2,000 Tcf. 

1. PGC

2. USGS

3. Mobil

4. Hubbert

5. NRC

6. Exxon

7. Shell

8. Hefner

9. Nehring

10. Sohio

11. DOI

12. DOE

13. Enron

14. GRI

15. AAPG

16. EIA

17. NPC

18. Smith & Lidsky

19. USGS/MMS

2,400

1,600

800

0

1970

1975

1980

1985

1990

1995
O IL AND G A S T ECHNOLOGY 17

A H ISTORY of I NNOVATION

Gas Hydrates

Devonian Shales

Tight Gas

Coalbeds

Low

Quality

High

Quality

High Stakes in 

Unconventional Settings

TODAY, THE E&P INDUSTRY IS

confronting formidable new technology

challenges. Both the stakes and the potential

rewards are great. Among the opportunities?

Finding cost-effective ways to tap plentiful,

less conventional resources that could potentially extend the world’s oil and gas supplies

for hundreds of years. Less conventional oil

resources are found in heavy oil deposits, 

oil shales, and tar sands. Gas is now found 

in coal seams, large shale deposits, and gas

hydrates. All told, the world’s unconventional

resources contain energy deposits many times

larger than the world’s remaining conventional

resources. In fact, a fundamental characteristic

of the world’s hydrocarbon resources is that

the more challenging and technically difficult

the resource is to exploit, the more of that

resource there is to pursue. 

If these resources can be successfully extracted

and refined, we may well need to change 

the definition of a “mature” resource base.

When unconventional resources are factored

into the U.S. resource base, our Nation

does not seem to be such a mature province

after all. With more than a century of oil

production behind us, more than two-thirds

of the over 600 billion barrels of the Nation’s

known oil resources remain untapped.

Source: U.S. Department of Energy, 1998

*Technically recoverable domestic resource base

**Mean estimate of U.S. hydrate resource base

Source: U.S. Department of Energy and U.S. Geological Survey

Targets for Advanced Exploration

and Production Technology

(In billions of barrels)

Of the approximately 603 billion barrels of the United States’ known oil resources,

over two-thirds remain untapped. Advanced exploration and recovery technologies

are key to reaching these undiscovered or currently unrecoverable resources.

Targets for advanced

exploration technologies

Target for advanced and

improved oil recovery

technologies

Natural Gas Resource Base

■ Cumulative production

■ Proved reserves

■ Discovered, unrecoverable by current technology (45% already abandoned)

■ Undiscovered, recoverable by current technology

■ Undiscovered, unrecoverable by current technology

Conventional 616 Tcf*

Unconventional 519 Tcf*

320,000 Tcf**
18 E NVIRONMENTAL B ENEFITS

A H ISTORY of I NNOVATION

Environmental Awareness, 

Commitment, and Results

AS SCIENCE AND TECHNOLOGY HAVE

evolved, so too has our awareness of the

impacts of human activity on the environment. In the past 30 years we have begun to

more fully understand the effects of human

activities on soils and vegetation, air and

water quality, wildlife, and health. A

heightened respect for the environment 

has become pervasive in our society—in

education, industry, and government.

In the petroleum sector, oil and natural gas

must be discovered, produced, processed,

and consumed in a manner that respects and

protects the environment. This has become

the standard to which both government 

and the industry are committed.

Government Has Responded 

to Environmental Concerns

PROTECTION OF THE ENVIRONMENT

began in the early years of the industry.

While many early regulations were designed

to conserve oil and gas resources, these mandates served the environment at the same

time. Later, as understanding grew of the

potential risks associated with E&P operations, regulations to protect public health

and the environment were implemented. 

Before World War I, States began implementing requirements to case and cement

wellbores to prevent possible contamination

of freshwater aquifers. Based on new technology and operational techniques developed

by the industry, States continued to advance

new standards of protection or restricted the

use of less protective alternative practices.

Since 1970, State and Federal governments

have passed legislation and promulgated

regulations to ensure higher levels of environmental protection. Federal legislation 

cuts across the spectrum of environmental

concerns. Among others, these statutes

include the Clean Air Act, Safe Drinking

Water Act, Clean Water Act, Coastal Zone

Management Act, Resource Conservation

and Recovery Act, Endangered Species Act,

and Occupational Safety and Health Act.

Many of these statutes are implemented

primarily by State agencies, which have

developed programs that apply to unique

and diverse environmental settings. These

programs must meet or exceed the Federal

requirements. 

The Environmental Protection Agency 

has acknowledged a need for individually

tailored regulations for waste management 

at the State and local levels that take into

account differences in environmental conditions, geology, and production economics.

Most States base the protective measures 

they require on site-specific conditions. This

approach allows the State the flexibility to

require additional protection where needed

without unnecessarily adding requirements

and costs on operations by imposing a uniform statewide standard. Although Federal

regulations sometimes restrict this State

flexibility, site-specific regulations appear to

be an appropriate tool to assist the States in

balancing the dual goals of environmental

protection and oil and gas production.

A Fundamental of Effective

Business Management

INDUSTRY POLICIES AND FIELD

practices have changed dramatically in recent

decades, often leading or defining new regulatory requirements. The oil and gas industry’s environmental orientation has become

part and parcel of its business operations,

domestic and worldwide. Companies have

recognized that sound environmental practices are a prerequisite for society’s consent 

to conduct their operations. 

Operators are becoming increasingly involved

in the regulatory development process at both

State and Federal levels to assist in finding a

balance between oil and gas production and

environmental protection. Many operators

have developed innovative approaches to

increase environmental protection, and may

employ practices that exceed the requirements

set forth under State and Federal regulations. 

MORE EFFICIENT, MORE

EFFECTIVE , MORE P ROTECTIVE

OF THE E NVIRONMENT

Industry and government are 

working to protect the environment 

for future generations.
Photo: Corbis Images
20 E NVIRONMENTAL B ENEFITS

A H ISTORY of I NNOVATION

Most companies have integrated environmental issues and activities into their operational planning and management, policies,

and education and training. Most conduct

extensive internal audits of their impacts on

the environment, and many have adopted

internal standards for monitoring and

continuously improving their environmental

performance. In many cases, companies 

have adopted international environmental

performance protocols such as ISO 14000* 

as standard business practice for their operations around the world. Meeting or exceeding

regulatory requirements and maintaining 

a high level of environmental performance 

are recognized as cornerstones of the oil 

and gas industry.

The industry—both in the United States

and worldwide—commits enormous financial resources to specific measures for caring

for the environment. In total, the industry 

spent over $8 billion on the environment 

in the United States in 1996—more than

the U.S. Environmental Protection Agency’s

entire budget and more money than the

industry spends annually on exploration for

oil and gas in the United States.

*The ISO 14000 series, a project of the International

Organization for Standardization, is a collection of

voluntary consensus standards that have been developed 

to assist organizations to achieve environmental and

economic gains through the implementation of effective

environmental management systems.

Source: Department of Energy and Interstate Oil & Gas Compact Commission, June 1993

Source: American Petroleum Institute, 1998

1966

1970

1975

1980

1990

1991

1993

1995

1992

1994

1996

1979

1983

1987

1991

80

70

60

50

40

30

20

10

0

11

9

7

5

3

1

0

■ Government spending ($millions)

■ Wells drilled/ permitted (thousands)

State Spending on Oil and Gas Regulatory Activities

State spending on oil and gas regulatory activities nearly tripled during the 1980s in 

the largest oil- and gas-producing States. Spending rose fastest between 1979 and 1985,

a period of high industry activity. 

Industry Spending on Environmental Protection, 1966 –1996

(Billions of nominal dollars)

From 1966 to 1993, the U.S. petroleum industry’s spending on environmental protection

rose steadily, peaking at $10.6 billion. The decline since 1994 is primarily attributable to

the completion of major capital projects in the refining sector.
O IL AND G A S T ECHNOLOGY 21

A H ISTORY of I NNOVATION

OSHA Voluntary 

Protection Programs

Participants are a select group of facilities

across all industries with outstanding 

health and worker safety programs that go

beyond compliance with Occupational

Safety and Health Act (OSHA) regulations.

E&P industry participants include BP

Exploration’s Endicott Island, Alaska site 

and Texaco Exploration’s operations in

Maysville, Oklahoma. The programs establish

a cooperative relationship among management, labor, and OSHA to ensure a safe and

healthful workplace. Once OSHA verifies

that the program meets established criteria,

the site is removed from routine scheduled

inspection lists. OSHA reassesses periodically

to confirm that the site continues to meet

the criteria.

Safety and Environmental

Management Program (SEMP) 

SEMP is a voluntary, nonregulatory strategy

for identifying and reducing risks of accidents, injuries, and oil spills associated with

developing oil and natural gas on the

Nation’s Outer Continental Shelf (OCS).

Operators representing over 99 percent of

production from the OCS have a SEMP in

place or are developing one. The program

was developed by the Minerals Management

Service (MMS) in partnership with industry.

Proper implementation of the program can

help operators comply with MMS operating

regulations, decrease operational risks, and

enhance worker safety. 

The Minerals Management Service Safety Award for Excellence, the SAFE award, first

given in 1983, recognizes and commends Outer Continental Shelf operators that conduct

operations in a safe and pollution-free manner. In referring to 1997 SAFE recipients

Newfield Exploration Company and Kerr-McGee Corporation, MMS Director Cynthia

Quarterman noted: “This prestigious award recognizes these two companies’ exemplary

performance, as well as their corporate commitment to safety and environmental

protection while conducting operations on the Nation’s Outer Continental Shelf.”

Recognizing Excellence in Safe Operations

Voluntary Industry Programs 

for Environmental Protection

I N 1996, THE PETROLEUM INDUSTRY

spent an estimated $187 million on company

environmental departments and voluntary

programs to improve environmental quality

and to support community and environmental groups.

Programs include:

API Step

The American Petroleum Institute’s 

STEP Program (“Strategies for Today’s

Environmental Partnerships”) encourages

companies to reflect environmental commitments in their principles and policies,

and to develop programs that prevent

pollution, promote safe operating practices,

and conserve resources in partnership with

government, the public, and other key

stakeholders.

EPA Natural Gas STAR

Nearly 70 exploration, production, transmission, and distribution companies are

members of the Environmental Protection

Agency’s Natural Gas STAR program.

Natural Gas STAR seeks to reduce methane

emissions by identifying best management

practices that reduce emissions and disseminating these advanced technologies to other

companies to use when it makes economic

sense to do so.

Photo: Corbis Images
Steps Toward Reductions in

Greenhouse Gas Emissions

Oil and gas companies all over the world are

voluntarily reducing emissions of carbon

dioxide and other greenhouse gases. Industry

giants BP Amoco and Royal Dutch/Shell

Group have taken the lead in this area,

publicly committing to reduce future greenhouse gas emissions to levels below those set

forth in the Kyoto Protocol. In recent years,

individual companies have implemented

hundreds of emissions reduction initiatives

and projects—from the reduction of natural

gas flaring and venting, to innovative gasto-liquids and gas liquefaction technology, 

to the development of creative, market-based

emissions trading programs.

Wetlands Restoration

In States where a substantial amount of oil

and gas operations occur in sensitive wetlands,

the oil and gas industry is actively restoring

and protecting the fragile ecosystems in which

it operates. Louisiana Land and Exploration

22 E NVIRONMENTAL B ENEFITS

A H ISTORY of I NNOVATION

Myth: The oil and gas industry is frequently characterized as Big Oil.

Reality: The Big Oil image is misleading. Independent oil and gas producers—small

businesses typically employing 10 full-time and 3 part-time employees—drill 85 percent

of the Nation’s wells and produce 65 percent of the natural gas and nearly 40 percent

of the oil consumed by Americans. Across America, the owners and employees of

these businesses may be your neighbors, serving as a cornerstone of economic activity

in smaller rural communities. Accordingly, the Department of Energy has technology

transfer programs targeted specifically to small independent producers.

Myth: Many Americans believe that the spills from oil and gas E&P are the leading

cause of oil pollution in the oceans and in the Nation’s rivers and streams.

Reality: To the contrary, the National Academy of Sciences found that offshore oil 

and gas E&P accounts for only 2 percent of the oil in the marine environment; marine

transportation accounts for 45 percent; industrial and municipal discharges, including

urban runoff, 36 percent; atmospheric pollution, 9 percent; and natural sources such 

as oil seeps, 8 percent.

Myths about the Oil and Gas Industry

“While fiercely supportive of efforts to

preserve and protect the environment,

most Americans are using yesterday’s 

news while making critical decisions about

behavior and policy on key environmental

issues. This dependence on mythology

threatens to block progress on important

environmental initiatives...it is vital that

we debunk these myths so that the public

can most effectively address the environmental needs of today.”

KEVIN J. COYLE

President

National Environmental Education & 

Training Foundation

International Protocols 

On an international basis, the E&P industry

is sharing “best environmental practices” 

and setting voluntary operating guidelines 

to improve environmental performance. 

Key associations include the European-based

E&P Forum; the Western Hemisphere Oil

and Gas Environmental Forum, a cooperative effort among over 30 private and Stateowned oil and gas companies in the United

States and Latin America; the International

Association of Geophysical Contractors; 

and the International Petroleum Industry

Environmental Conservation Association. 
O IL AND G A S T ECHNOLOGY 23

A H ISTORY of I NNOVATION

With the help of Shell Oil Company Foundation and Exxon Corporation, the National

Fish and Wildlife Foundation (NFWF), a nonprofit organization dedicated to promoting

conservation and sustainable use of our natural resources, has been able to significantly

enhance its habitat and wildlife protection programs. Multi-million-dollar, multi-year

grants from these companies have enabled NFWF to establish two important grant

programs: the Shell Marine Habitant Program—dedicated to protecting and enhancing

the Gulf of Mexico ecosystem—and the Save the Tiger Fund, an international effort

launched with Exxon to assist in the long-term survival of Asia’s remaining population

of wild tigers.

Wildlife Protection Programs

Company (which merged with Burlington

Resources in 1997), for example, began studying wetlands restoration methods as early as

the 1950s and later implemented an awardwinning wetlands conservation program.

Today, in LaTerre, Louisiana, Fina has

undertaken an extensive program to halt

erosion on over 7,000 acres of marsh by

planting cordgrass and constructing a series

of weirs and dams, helping to restore the

marsh and its declining alligator population.

Coastal and Marine Habitat Protection

The industry actively collaborates with private

conservation groups to protect sensitive

coastal and marine habitats and wildlife. For

example, Shell Oil Company Foundation

recently provided a 5-year, $500,000 grant 

to The Nature Conservancy of Texas for

conservation research and field-based environmental educational programs at the 

Mad Island Marsh Preserve along the Texas

Gulf Coast. On Shamrock Island in Corpus

Christi Bay, The Nature Conservancy of

Texas and Bristol Resources are collaborating

to restore and protect habitats impacted by

past oil and gas operations. On Galveston

Bay, Mobil Oil recently donated over 2,200

acres of wetlands and grasslands for use as a

preserve for the area’s wild prairie chicken, one

of North America’s most endangered species.

Federal Lands Stewardship

Whether tailoring operations to protect

Federal lands or assisting the government 

in enacting sound resource development

policies, the domestic petroleum industry

plays a vital stewardship role on our

Nation’s Federal lands. For example, a recent

exchange of over 18,000 acres of land in

North Dakota’s Badlands enabled the Bureau

of Land Management to consolidate ownership of prime bighorn sheep habitat, and

provided Burlington Resources with access 

to Federal mineral rights on lands away 

from these critical habitats. 

Equally crucial is the industry’s commitment

to environmental excellence when exploring

or producing on Federal lands—Unocal

Alaska’s award-winning operations in Alaska’s

Kenai National Wildlife Refuge and Conoco’s

management of its operations in the Aransas

National Wildlife Refuge on Texas’ Gulf

Coast typify this commitment.
24 E NVIRONMENTAL B ENEFITS

O IL AND G A S I NDUSTRY

T HANKS TO ADVANCES IN EXPLORATION AND PRODUCTION TECH -nology, today’s industry is better equipped than ever to find and produce valuable

oil and gas — even as these resources become concentrated in deeper, more remote,

and more technically challenging areas. Many of the same advances also support our

Nation’s goals for environmental protection. With each step up in performance and efficiency, the industry can recover more resources with fewer wells drilled, resulting in

ENVIRONMENTAL

ADVANCED E&P

1998

expected

(without technology)

1985

1998

actual

Drilling waste generated per 

100 BOE of reserve additions

8

6

4

2

1976-82

7.5

1983-88

6.5

1989-95

3.4

Barrels of water produced to

surface per barrel of production

Without 

downhole separation

With 

downhole separation

E XPLORATION

S ITE R ESTORATION

P RODUCTION

D RILLING AND

C OMPLETION

O PERATIONS IN

S ENSITIVE

E NVIRONMENTS

FEWER WELLS TO

ADD SAME LEVEL

OF RESERVES

If technology had not

advanced since 1985, four

domestic wells would have

to be drilled today to 

maintain the production

levels achieved by two 

wells in 1985. But, in fact,

technology advances have

boosted productivity so

successfully that 1985-level

production can be achieved

today with only one well.

LOWER DRILLING

WASTE VOLUMES

Volumes of drilling muds

and drill cuttings per barrel

of new oil reserves have

steadily declined thanks to

improvements in drilling

efficiency. 

LOWER PRODUCED

WATER VOLUMES

Emerging downhole

separation technology has

the potential to dramatically reduce volumes of

produced water, which is

the largest waste stream

associated with oil and gas

production.
O IL AND G A S T ECHNOLOGY ECHNOLOGY 25

E XPLORATION AND P RODUCTION

Standard

Rig

Slimhole

Rig

16

12

8

4

1993 1994 1995 1996 1997

Methane saved in Bcf

CCAP reduction goal

Job related injuries and illnesses per 100 workers

12

8

4

1987 1996

Exploration and production

U.S. manufacturing

smaller volumes of cuttings, drilling muds and fluids, and produced waters. Technologies

such as slimhole, directional, and multilateral drilling reduce the footprint of drilling rigs

and minimize surface impacts. Other benefits of advanced technology include reduced

energy consumption, reduced noise from operations, decreased visibility of facilities,

reduced emissions of greenhouse gases and hazardous air pollutants, better protection of

water resources, preservation of habitats and wildlife, and enhanced worker safety.

SMALLER 

FOOTPRINTS

Using modular drilling rigs

and slimhole drilling, operators can develop the same

volume of resources with a

rig up to 75 percent smaller

and lighter than a standard

rig, reducing impacts 

on surface environments.

PROTECTION 

OF SENSITIVE 

ENVIRONMENTS

Directional drilling, 

slimhole rigs, and other

advances enable production

of valuable oil and gas

resources with less disturbance to wetlands and other

sensitive environments.

REDUCED

GREENHOUSE GAS

EMISSIONS

Through the EPA’s voluntary

Natural Gas STAR program,

the gas industry’s use of

innovative best management

practices has reduced methane

emissions by nearly 55 billion

cubic feet since 1991, well

exceeding the annual goals

set by the Climate Change

Action Plan. The natural gas

production sector alone has

accounted for two-thirds of

this reduction.

ENHANCED

WORKER SAFETY

Job-related injuries and 

illnesses in oil exploration

and production are well

below the rates in the U.S.

manufacturing sector.

Advanced drilling, completion, and production technologies have contributed 

to steady improvements in

worker safety, by decreasing

workers’ time on site and

enhancing wellbore control.

BENEFITS OF

TECHNOLOGY

Photo: Larry Lee
TODAY, FINDING BLACK GOLD IS A HIGH-TECHNOLOGY VENTURE. HIGHER SUCCESS

RATES MEAN FEWER DRY HOLES, FEWER WELLS DRILLED, AND LESS IMPACT ON THE

ENVIRONMENT.

E XPLORATION
© SPE, 1993
28 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Advanced technologies like seismic 

imaging have raised exploration success 

rates by 50 percent or more.

Photo: Texaco Production Operations

C UTTING -E DGE TECHNOLOGY

REVOLUTIONIZES E XPLORATION

The Gulf of Mexico’s coastal transition zone is

among the most prospective, unexplored oil

and gas regions in the country. Yet, the region’s

geological and operational complexities have

long hampered E&P activities. Now, thanks to

next-generation 3-D seismic imaging, new drilling

capabilities, and associated technologies, the

zone is coming alive with new discoveries —

including successful strikes in old fields. For

example, Spirit Energy ’76 (Unocal Corporation’s

E&P unit) recently began drilling deeper targets,

based on newly acquired 3-D seismic data,

around the 40-year-old Vermilion 14 field, located

in State waters off central coastal Louisiana.

Barry Gouger, Central Gulf asset manager,

reported in 1998 that 10 million barrels of oil

equivalent had been added to the field’s

reserves since the acquisition of 3-D seismic. 

“The 3-D seismic has allowed us to sharpshoot

for bypassed pay and new targets within the

field and new opportunities around the field,”

Gouger explained. “The effort and expense of

acquiring 3-D seismic over these older giant

fields is well worth it. We are finding significant

new reserves in and around the field, and just

as important are the wells that we do not drill

because of the 3-D coverage.” It’s a story being

replicated throughout the Gulf transition zone,

where 3-D seismic is minimizing environmental

disruption by effectively targeting new

prospects and extending the life of existing

reservoirs. 

Source: American Oil & Gas Reporter, April 1998

SEARCHING FOR HYDROCARBONStoday is about as far removed as possible

from old movie images of wildcat drillers

hoping for a gusher. It involves teams of

geologists, geophysicists, and petroleum engineers seeking to identify, characterize, and

pursue geologic prospects that may contain

commercial quantities of oil and gas. Because

these prospects lie thousands of feet below

the earth’s surface, uncertainty and trial-anderror pervade the exploration process. It is a

painstaking and hugely expensive enterprise,

with low success rates. Historically, new 

field wildcat exploration has succeeded at a

rate of one productive well for every five to 

10 wells drilled.

Over time, the more easily discovered

resources in the United States have been

found, developed, depleted, and then plugged

and abandoned when they reached their

economic limit. New fields now being

discovered in the United States are generally

smaller in size and found in deeper, more

subtle, and more challenging geologic formations. Yet, despite the increased difficulty 

of discovering remaining domestic resources,

technology developments have enabled the

oil and gas industry to maintain or, in many

cases, improve upon, historical levels of

exploration success.

Today, experts can interpret geological and

geophysical data more completely; manage,

visualize, and evaluate larger volumes of data

simultaneously; and communicate interpretations based on these data more accurately. 

Advanced techniques now allow the scientist

to virtually “see” the inside of the formation.

Three-dimensional seismic technology, first

commercially available nearly 25 years ago,

bounces acoustic or electrical vibrations off

subsurface structures, generating massive

amounts of data. Then powerful computers

manipulate the data to create fully visualized

multidimensional representations of the subsurface. Even more exciting is 4-D time-lapse

imaging—an emerging technology developed

only within the past 5 to 10 years—which

adds the dimension of time, allowing scientists to understand how the flow pattern of

hydrocarbons changes in the formation 

over time.
O IL AND G A S T ECHNOLOGY 29

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Searching for Oil and Gas

Exploration includes:

• Surveying and mapping surface and subsurface geologic features to identify 

structures where oil and gas may have accumulated.

• Determining a geologic formation’s potential for containing commercial 

quantities of economically producible oil and/or gas.

• Identifying the best location to drill an exploratory well to test the structure.

• Drilling exploration and delineation wells to determine where hydrocarbons 

are present and to measure the area and thickness of the oil- and/or 

gas-bearing reservoir.

• Logging and coring wells to measure permeability, porosity, and other properties 

of the geologic formation(s) encountered.

• Completing wells deemed capable of producing commercial quantities of 

hydrocarbons.

E XPLORATION

Fewer Dry Holes, More

Production and Reserve

Additions per Well

IMPROVEMENTS IN 3-D SEISMIC AND

4-D time-lapse visualization, remote sensing,

and other exploration technology allow

explorationists to target higher-quality

prospects and to improve success rates by as

much as 50 percent or more. The result:

fewer wells need to be drilled to find a given

target, and production per well is increased,

in some cases by 100 percent. 

Today, fewer than half as many wells are

required to achieve the same reserve additions as two decades ago. Annual reserve

additions for new exploratory drilling have

quadrupled, from a per-well average of 

about 10,000 barrels of oil equivalent (BOE)*

in the 1970s and 1980s to over 40,000 BOE

in the 1990s. 

Thanks to today’s technology, whole new

categories of resources, considered inaccessible just 20 years ago, are now counted as

part of the domestic resource base. Advances

in exploration drilling technology have been

particularly dramatic in deepwater areas,

where significant expansion of the known

resource base has resulted.

In aggregate, technology improvements have

slashed the average cost of finding oil and gas

reserves in the United States from roughly

$12 to $16 per BOE of reserves added in the

1970s and 1980s to $4 to $8 today. 

*Natural gas is converted to “barrels of oil equivalent” 

on the basis of 0.178 barrels of oil per thousand cubic 

feet of gas.

Fundamentals of Exploration

1970s

1971

1980s

1990s

Exploration Success Rates

Despite a dwindling resource base, U.S. exploration

success rates continue to improve.

■ All exploration

■ New field wildcats only

Source: American Petroleum Institute

14%

23%

16%

26%

21%

29%

BOE New Reservoir and New Field Reserve

Additions per Exploratory Well

(Million barrels of oil equivalent per well)

The volume of reserves added per exploratory 

well has increased dramatically since the 1970s 

and early 1980s.

Source: U.S. Department of Energy

0.45

0.30

0.15

0

1976

1981

1986

1991

1996
30 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Exploration Applies High Technology

Advances in widely varied technical disciplines have boosted exploration 

efficiency over the past 20 years:

• Advances in computer power, speed, and accuracy

• Remote sensing and image-processing technology

• Satellite-derived gravity and bathymetry data that enable remote sensing for 

offshore deepwater exploration

• Developments in global positioning systems (GPS)

• Advances in geographical information systems (GIS)

• Three-dimensional (3-D) and 4-D time-lapse imaging technology that permit better

characterization of geologic structures and reservoir fluids below the surface

• Improved logging tools that enhance industry’s geoscientific understanding of

specific basins, plays, and reservoirs

• Advances in drilling that allow explorationists to more cost-effectively tap

undepleted zones in maturing fields, test deeper zones in existing fields, and 

explore new regions

The sharply increased success rates and well

productivity improvements attributable to

advanced exploration technology yield substantial environmental benefits. Fewer wells

drilled means reduced volumes of wastes to

be managed, such as cuttings and drilling

fluids (which lubricate the drill bit, circulate

cuttings, and stabilize wellbore pressures). 

New Resources in Old Fields

IMPROVEMENTS IN EXPLORATION

and production technology enable operators

today to better tap resources that remain in

existing fields. Advances in 3-D and interwell

seismic technology allow operators to take

another look at older producing areas, such

as the fields in Appalachia, California, and

West Texas, and see untapped zones of

hydrocarbons that were bypassed or could

not be seen in the past. 

Improved computer-processing technology

and interpretation software allow older seismic data to be reprocessed and reevaluated. drillships, jackup rigs, semisubmersible

drilling rigs, and modular rigs. When commercial quantities of resources are discovered,

discovery wells are capped until permanent

production platforms can be set in place.

Where dry holes are found, wells are plugged

and the rigs are redeployed swiftly. As offshore technology extends exploratory reach,

the industry continuously pushes to advance

development and production technology to

operate cost-effectively in ever deeper waters.

On the Cutting Edge

Photo: Sundowner Offshore Services

Once untapped zones are identified, new

techniques for sidetrack drilling (drilling a

lateral extension from an existing wellbore)

and deeper drilling from existing wells can

allow some of these resources to be developed without drilling new wells or disturbing

previously undisturbed areas.

Exploring New Frontiers

NEW DEEPWATER DRILLING TECH -

nology enables exploratory drilling in ever

deeper offshore waters, making promising

new resources accessible for the first time.

Advances include high-technology floating
O IL AND G A S T ECHNOLOGY 31

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

T H E 4-D DIFFERENCE

At BP Amoco/Shell’s Foenhaven field,

estimated recovery rates of oil-in-place

are expected to reach 65 to 70 percent

with 4-D seismic, compared to 25 to 

30 percent with 2-D technology and 

40 to 50 percent with 3-D technology.

BEYOND THE OI L PATCH

• Advances in 3-D and 4-D seismic

technology and earth-imaging systems

have helped in the understanding 

of subsurface fluid flow, not just for 

oil and gas, but for groundwater

monitoring and pollutant transport.

• Advances in geological and geophysical technologies have assisted in

improving our overall understanding

of “earth systems,” or the major

processes influencing activity in the

earth’s crust.

• Improved logging and interpretation

technologies have helped us learn 

more about the characteristics of the

earth’s crust.

E XPLORATION

More Advances in 

Exploration Technology

BEYOND ADVANCED IMAGING,

other new exploration approaches are being

applied throughout the country to reduce

environmental impacts, particularly in sensitive environmental areas. Redesign of drill

rigs has minimized surface loading. Seismic

techniques also have been redesigned to

reduce impacts resulting from explosive

shocks—for instance, through more flexible

positioning of shotholes and geophones,

redesign of shothole loading procedures, 

and use of ramming instead of drilling 

to set charges in hydrophones. These new

acoustical and vibration devices replace

explosives for generating seismic signals

onshore and offshore, reducing noise, and

protecting human, marine, and animal life.

These advances are enabling exploratory

drilling in water depths of a mile or more,

extending drilling seasons in the Arctic 

without disturbing the tundra or wildlife

migratory patterns, and opening commercial

development prospects in complex geological basins.

Exploration Drilling Techniques 

from Land to Deepwater

Source: Minerals Management Service

0

Exploration Drilling Technology

Evolution in Offshore

0

1,000

2,000

3,000

4,000

5,000

Land Rig

Submersible

Jackup

Semisubmersible

Multilateral 

Wells

1978 

1,025 ft

1988 

1,350 ft

1989

1,760 ft

1994 

2,860 ft

1996 

2,930 ft

1997 

5,400 ft

Drillship

© SPE, 1993

Outfitted with state-of-the-art 

electronics and computers, 

seismic survey vessels collect and

process invaluable subsurface 

geological data to aid 

offshore exploration.
SUCCESSFUL DRILLING OFTEN MEANS GOING FASTER AND DEEPER, THROUGH

HARDER ROCK, AND IN MULTIPLE DIRECTIONS FROM A SINGLE WELLBORE. THE

RESULT? MORE RESOURCES ARE CONTACTED WITH FEWER WELLS, LESS DRILLING

WASTE, AND LESS SURFACE DISTURBANCE.

D RILLING AND C OMPLETION
© SPE, 1993
34 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Advanced drill bits reduce

time on site and associated 

environmental impacts.

Photo: RBI-Gearhart

GREATER DRILLING EFFICIENCY,

L ESS E NVIRONMENTAL I MPACT

“High technology has migrated to almost 

all phases of exploration and production,

and that includes stepping right up to 

the drilling rig floor. That’s right, the 

rig floor—the domain of the roughneck 

and the pipe wrench, where the real 

‘nitty gritty’ gets done—is becoming more

technology-oriented by the day....

Technology is markedly improving drilling

performance and enhancing safety even 

as it helps trim cost.”

MAGGIE LE E

Source: The American Oil & Gas Reporter, April 1998

With horizontal drilling, today’s oil and gas

industry has an extraordinary capability: the

power to navigate three-dimensionally through

the earth, contacting and economically producing resources while minimizing surface

disruption. A case in point is the Red River B

Formation in the Williston Basin (North Dakota,

South Dakota, and Montana), where Burlington

Resources Inc. and Continental Resources are

using horizontal technology to drain a narrow

but oil-rich, low-permeability dolomite zone.

Historically, vertical wells completed in the Red

River B produced an uneconomic 20 or 30 barrels

a day. New wells penetrate the zone laterally,

extending a mile or more within a porosity window of only 2 feet. Initial daily production from

the longest of the 123 horizontal wells drilled

and completed to date was 575 barrels of oil. 

Horizontal drilling was instrumental in Burlington

Resources’ discovery of an estimated 150 million

barrels of recoverable oil in the Cedar Hills 

play in the Williston Basin, the largest onshore

discovery in the last 25 years. The technique

complements waterflood recovery efforts 

there. “With two horizontal wells per section,

Burlington is replacing traditional line-drive

techniques in the area where operators have

typically drilled eight to 10 wells per section,”

said drilling manager Doug Harris. “In fact, the

horizontal wells will result in a more efficient

flood than the vertical-drilled line-drive patterns,

with only one-fourth the number of wells.”

Source: American Oil & Gas Reporter, September 1998

DRILLING IS THE MOMENT OFtruth for oil and gas producers. After 

all of the analyses and preparation, have

explorationists pinpointed the reservoir? 

Will it be productive? Are development 

wells being drilled in the right pattern for

efficient extraction?

Substantial investments ride on the answers.

Drilling activities for a given field or reservoir may require the investment of hundreds

of millions of dollars or more. Justifying 

such investments in developing domestic

resources is increasingly difficult, since much

of our Nation’s remaining oil and gas is

locked away in geologically complex and

challenging structures that necessitate deeper

drilling or enhanced completion and production technologies. 

Despite these challenges, drilling is now

safer, faster, more efficient, and less costly

than in the past. High-resolution 3-D

seismic and improved reservoir imaging and

characterization are combined with improvements in drilling technology to increase

drilling success rates, reduce drilling costs,

and reduce the environmental impacts of

both exploratory and development drilling.

Onshore, typical drilling and completion

costs have dropped by about 20 percent,

from an average of about $500,000 per well

in the 1980s, to about $400,000 per well

today, adjusting for inflation, depth, type of

well, and locations of wells drilled. Similarly,

offshore drilling and completion costs of

about $5.5 million per well in the 1980s have

dropped to an average of $4.3 million today. 

In addition to expanding the deepwater oil

and gas resource base, technology advances

in drilling and completion have added new

gas reserves from sources once considered

uneconomic—including Devonian shales,

deep gas formations, coalbeds, and lowpermeability “tight” gas sands.
Photo: CANRIG

D RILLING AND C OMPLETION
36 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Contacting a targeted formation involves:

• Using rotary equipment and hardened drill bits, weighted and lubricated by drilling

fluids, to penetrate the earth’s surface.

• Inserting casing and tubing into each well to protect the subsurface and control 

the flow of fluids (oil, gas, and water) from the reservoir.

• Perforating the well casing at the depth of the producing formation to allow flow 

of fluids from the formation into the wellbore.

• Installing a wellhead at the surface to regulate and monitor fluid flow and prevent

potentially dangerous blowouts.

Fundamentals of 

Drilling and Completion

Fewer Wells Mean Less Waste

ENVIRONMENTAL BENEFITS FROM

drilling and completion advances are

significant. For example, new exploration

and drilling technology has, on average,

doubled the amount of oil or gas supplies

developed per well since 1985. Thanks to 

this productivity increase, today’s level of

reserve additions is achieved with 22,000

fewer wells annually than would have 

been required with 1985-era technology.

Reducing the number of wells decreases

wastes generated from drilling operations.

Assuming an average well depth of 5,600 feet

and 1.2 barrels of waste per foot drilled, with

22,000 fewer wells, the average annual volume

of drilling waste is reduced by approximately

148 million barrels. Avoiding this waste—

enough to cover about 1,440 football fields 

to a depth of 10 feet—reduces waste management and disposal requirements.

Other environmental benefits of advanced

drilling and completion technology include:

• Smaller footprints

• Reduced noise and visual impacts

• Less frequent well maintenance and

workovers, with less associated waste 

• Reduced fuel use and associated emissions

• Enhanced well control, for greater worker

safety and protection of groundwater

• Less time on site, with fewer associated

environmental impacts

• Lower toxicity of discharges

• Better protection of sensitive 

environments

Some technology advances key to improved

drilling and completion efficiency are

described below:

Horizontal and directional drilling

Oil and gas wells traditionally have been

drilled vertically, at depths ranging from a

few thousand feet to as deep as 5 miles.

Depending on subsurface geology, technology advances now allow wells to deviate

from the strictly vertical orientation by

anywhere from a few degrees to completely

horizontal, or even inverted toward the

surface. About 90 percent of all horizontal

wells have been drilled into carbonate

formations, which account for about 

30 percent of all U.S. reserves.

Directional and horizontal drilling enable

producers to reach reservoirs that are not

located directly beneath the drilling rig, a

capability that is particularly useful in avoiding sensitive surface and subsurface environmental features. New methods and technology

allow industry to produce resources far

beneath sensitive environments and scenic

Average Onshore and Offshore Drilling Costs

(Dollars per well, in thousands)

Both onshore and offshore drilling costs have 

declined by over 20% since the 1980s.

Onshore 

Offshore 

Costs adjusted for 1996 activity (i.e., depth, 

type, and general location of wells drilled).

Source: American Petroleum Institute

$415

$496

$5,445

$4,287

$6,000

5,000

4,000

3,000

2,000

1,000

0

$500

400

300

200

100

0

1980s

1990s

1980s

1990s
O IL AND G A S T ECHNOLOGY 37

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Measures of Success for Horizontal Drilling

According to a 1995 DOE study, horizontal drilling has improved:

• Reserve additions: Reserves are potentially increased by an estimated 10 billion 

barrels of oil, nearly 2 percent of original oil-in-place in the United States.

• Speed of delivery: Carbonate production is nearly 400 percent greater in horizontal

projects than with vertical wells, yet costs are only 80 percent more.

• Average production ratio: The ratio is 3.2 to 1 for horizontal compared to vertical

drilling, offsetting a higher average cost ratio of 2 to 1. Average increase in reserves

derived from horizontal well applications is approximately 9 percent.

D RILLING AND

C OMPLETION

vistas in Louisiana wetlands, California

wildlife habitats and beaches, Rocky

Mountain pine forests, and recreational 

areas on the Texas Gulf Coast. Even some

offshore resources, including many off the 

coast of California, can be produced from

onshore wells.

Horizontal drilling may also allow a producer

to contact more of the reservoir, so that more

resources can be recovered from a single well.

In Mississippi’s Black Warrior Basin, for

example, horizontal wells provide six times 

as much natural gas deliverability as conventional vertical wells do at the Goodwin natural gas storage field. In growing numbers of

operations, the benefits from this increased

production far outweigh the added cost for

these wells. This was the case in the remote

South China Sea, where Phillips China Inc.

recently used advanced horizontal drilling

and completion technologies to successfully

complete a 5-mile-long extended-reach well.

Advances in directional drilling also facilitate multilateral drilling and completion,

enabling multiple offshoots from a single

wellbore to radiate in different directions or

contact resources at different depths. Recent

and very rapid development of such radial

drilling technology has spurred a boom in

horizontal drilling. Since the mid-1980s, the

drilling of horizontal wells has grown from 

a few to more than 2,700 wells per year

worldwide. In the United States, horizontal

drilling now accounts for 5 to 8 percent of

the land well count at any given time.

Environmental benefits of horizontal and 

directional drilling include:

• Fewer wells

• Lower waste volumes

• Protection of sensitive environments

METRICS

Advanced Drilling Techniques

Worldwide Horizontal Wells

(Number of horizontal wells)

Source: Oil & Gas Journal, November 23, 1998

3,000

2,250

1,500

750

0

Pre-1988

1989

1990

1988

1991

1992

1994

1995

1993

1995

Multilateral Horizontal Directional
38 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Use of coiled 

tubing redefines

equipment 

footprints.

Slimhole drilling and coiled tubing

Slimhole drilling—a technique gaining

widespread use for tapping into reserves in

mature fields—significantly decreases waste

volumes. For example, a slimhole drilled 

to 14,760 feet and ending with a 41⁄

8-inch

bottomhole produces one-third less volume

of cuttings than a standard well at the same

depth. Operational footprints are also reduced,

since equipment for slimhole drilling is

smaller than that used in conventional operations. The area cleared for drilling locations

and site access can be as little as 9,000 square

feet with mud holding pits, as much as 

75 percent less than that required for conventional operations. In contrast, if technology

development had stopped in 1985, today’s

drill pads would cover an additional 17,000

acres of land in the United States, an area

roughly the size of 12,900 football fields.

Coiled tubing technology—a cost-effective

solution for drilling in reentry, underbalanced,

and highly deviated wells—has similarly

impressive benefits, reducing drilling wastes

and minimizing equipment footprints. A

typical coiled tubing layout requires a working space about half that of a conventional

light workover hoist. The drilling site is easier

to restore when operations are completed,

and the impact of equipment mobilization

on the environment is reduced.

In addition, coiled tubing and slimhole

drilling enable less disruptive, quieter drilling

operations, minimizing the noise impact on

wildlife or humans near the well site. Since

coiled tubing is a continuous pipe, most

noises associated with conventional drilling

pipes are avoided. Efficient insulation and

the equipment’s smaller size further reduce

noise levels. For example, the noise level of 

a conventional rig at a 1,300-foot radius is 

55 decibels, while a coiled tubing unit’s noise

level at the same distance is 40 decibels, or

27 percent less. The smaller size of coiled

tubing drilling also cuts fuel use and reduces

emission of gaseous air pollutants, compared

with traditional rotary drilling.

Environmental benefits of slimhole drilling 

and coiled tubing include:

• Lower waste volumes

• Smaller footprints

• Reduced noise and visual impacts

• Reduced fuel use and emissions

• Protection of sensitive environments

Mud Disposal Reduction in Slimhole Coiled Tubing

Operations vs. Conventional Drilling Operations

Maximum fluid volume (m3)

© SPE 27156, 1994

180

120

60

0

Conventional

Reservoir

Intermediate

Tophole

Conductor

Slimhole

Completion

Photo: Haliburton Energy Serivces
O IL AND G A S T ECHNOLOGY 39

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Impressive Performance from Modern Diamond Bits

Polycrystalline diamond compact (PDC) drill bits have become 

increasingly effective:

• Between 1988 and 1994, technology advances increased the average footage drilled 

per PDC bit by over 260 percent (from approximately 1,600 to 4,200 feet per bit).

• Total footage drilled worldwide by diamond bits has climbed steadily, from

approximately 1 percent in 1978, to 10 percent in 1985, and to 25 percent in 1997.

• Latest-generation PDC bits drill 150 to 200 percent faster than similar bits just a 

few years ago.

Decreased Drilling Time

Modern drill bits enable operators to contact 

targeted formations in ever more difficult 

geologic environments, and to 

drill significantly faster.

(Days to drill)

D RILLING AND

C OMPLETION

Light modular drilling rigs

Now in production, new light modular

drilling rigs can be deployed more easily 

in remote areas than conventional rigs.

Fabricated from lighter and stronger materials, these rigs are built in pieces that can 

be transported individually and assembled 

on site. The lower weight of components

and the rig reduces surface impacts during

transport and use. The modular design also

allows the rigs to be quickly disassembled

and removed when drilling operations 

are completed. 

Environmental benefits of light modular

drilling rigs are:

• Smaller footprints

• Reduced fuel use and emissions

• Protection of sensitive environments

(decreased surface impacts of transportation)

Measurement-while-drilling (MWD)

MWD systems measure downhole and

formation parameters to allow more efficient

and accurate drilling. By providing precise,

real-time drilling data on bottomhole

conditions, these systems reduce costs and

improve the safety of drilling operations. 

Combined with advanced interpretive software, MWD tools allow drilling engineers 

to more accurately determine formation pore

pressures and fracture pressures as the well 

is being drilled. Such accurate geopressure

analysis can help reduce the risk of lifethreatening blowouts and fires. In the event

of the loss of well control, MWD tools help

engineers to quickly steer a relief well and

regain control.

Environmental benefits of MWD 

systems include:

• Fewer wells

• Enhanced well control

• Less time on site 

Improved drill bits

Advances in materials technology and bit

hydraulics, spurred by competition between

roller cone and polycrystalline diamond compact bits, have yielded tremendous improvement in drilling performance. Extensive field

data indicate that, on average, a 15,000-foot

well in Roger Mills County, Oklahoma, takes

about 39 days to drill today, while that same

well would have taken over 80 days in the

1970s. By reducing the time for the rig to be

on site, advanced drill bits reduce potential

impacts on soils, groundwater, wildlife, and

air quality.

Environmental benefits of improved 

drill bits are:

• Lower waste volumes

• Reduced maintenance and workovers

• Reduced fuel use and emissions

• Enhanced well control,

• Less time on site

METRICS

100

80

40

0 6,000 ft

0 ft

12,000 ft

18,000 ft

Source: Hart’s Oil & Gas World, November 1996

1970 –79

1984 –86

1994 –96
40 E NVIRONMENTAL B ENEFITS

METRICS

Synthetic Drilling Fluids (Muds) Cut Costs

An operator in the Gulf of Mexico found that synthetics significantly outperformed

water-based fluids in a recent drilling operation. Of eight wells drilled under

comparable conditions to the same depth:

• The three wells drilled using synthetic fluids were completed in an average of 53 days 

at an average cost of $5.5 million.

• The five wells drilled using water-based fluids were completed in an average of 195 days

at an average cost of $12.4 million.

Advanced synthetic drilling fluids

Today’s drilling fluids (muds) must perform

effectively in extreme temperature and pressure environments, support industry’s use of

increasingly sophisticated drilling and completion technology, and be compatible with

current environmental disposal standards. 

To meet these challenges in deepwater formations, synthetic drilling fluids combine

the higher drilling performance of oil-based

fluids with the lower toxicity and environmental impacts of water-based fluids. Because

synthetic fluids can be recycled, they generate

less waste than water-based fluids. Also,

unlike oil-based fluids, these synthetics

produce wastes that are thought to be environmentally benign, thus minimizing impact 

on marine life. Moreover, by eliminating the

use of diesel as a mud base, synthetic fluids

have low-toxicity and low-irritant properties

that significantly enhance worker health 

and safety.

Environmental benefits of synthetic 

drilling fluids vs. water-based fluids are:

• Lower waste volumes

• Enhanced well control

• Lower toxicity of discharges

• Less time on site

• Protection of sensitive environments

Air percussion drilling

Air percussion or pneumatic drilling—

used for natural gas wells in regions such 

as Appalachia—can eliminate the need for

drilling liquids during drilling operations. 

As a result, only drill cuttings are generated,

significantly reducing requirements for waste

management and disposal. Although this

technology has limited application, it can 

be an effective underbalanced drilling tool 

in mature fields, in formations with low

downhole pressures, and in fluid-sensitive

formations.

Environmental benefits of air percussion

drilling include: 

• Lower waste volumes

• Protection of sensitive environments

Annular injection of cuttings

In certain settings—such as deep onshore

wells, remote offshore operations, and

Alaska’s North Slope—drilling cuttings can

be disposed of by reinjecting them into the

annulus around the drill pipe. Reinjecting

wastes down the annulus eliminates several

needs on the surface: waste management

facilities, drilling waste reserve pits, and offsite transport. Returning the wastes to geologic formations far below the earth’s surface

minimizes the impacts of drilling operations

on sensitive environments, and in many cases

reduces the costs of drilling operations in

these environments.

Environmental benefits of annular 

injection of cuttings include:

• Smaller footprints

• Lower toxicity of discharges

• Protection of sensitive environments

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Downhole Cuttings Injection

Annular injection wellbore configuration

© SPE 25964, 1993

Prepared

cuttings

slurry Wellhead

Confining layer

Surface casing

Injected slurry

Injection zone

Intermediate casing

Production hole
O IL AND G A S T ECHNOLOGY 41

BEYOND THE OI L PATCH

• Advances in horizontal drilling and

technologies supporting its application, such as measurement-whiledrilling (MWD) and coiled tubing, have

expanded the technology’s application

to such areas as groundwater remediation and pipeline construction.

• Advances in drilling technologies for

E&P, such as slimhole drilling, have

been adapted for mining, geothermal,

and water supply applications, as well

as for application to research geology.

Productivity Gains from CO2-Sand Fracturing

CO2-sand fracturing may greatly improve productivity in certain wells. After 

37 months of DOE-supported field trials at 15 Devonian Shale test wells, wells

fractured with CO2-sand technology produced:

• Four times as much gas per well as wells fractured with nitrogen foam and proppant.

• Twice as much gas per well as wells fractured with nitrogen gas.

A Major Contribution

In addition to being critical to natural

gas production, hydraulic fracturing has

enabled recovery of 8 billion barrels of

additional oil reserves in North America.

Corrosion-resistant alloys

New alloys and composites for drill bits, 

drill pipe, and coiled tubing—particularly

for equipment designed to operate in deep,

hot, and sour (high concentrations of H2S)

wells—reduce well failure rates and the

frequency of workovers and increase

equipment life.

Environmental benefits of corrosion-resistant

alloys are: 

• Fewer wells

• Reduced maintenance and workovers

• Enhanced wellbore control

• Protection of sensitive environments

Improved completion and 

stimulation technology

Advanced completion and stimulation

technology includes CO2-sand fracturing,

which yields clean fractures to increase 

well deliverability while avoiding the waste

management and well maintenance costs

associated with more traditional fracturing

operations. In addition, advances in hydraulic

fracturing technology—such as state-ofthe-art fracture simulators and improved

microseismic fracture mapping—have

improved well placement and design, and

increased ultimate recovery. In the overpressured, highly permeable San Juan Basin

fairway, operators are using advanced open

hole cavitation techniques to produce more

coalbed methane. Operators have found 

that dynamic open hole cavitation boosts

production when compared with conventional cased and fractured completions,

generally by three to seven times as much.

Environmental benefits of improved completion and stimulation technology include:

• Increased recovery

• Lower waste volumes

• Fewer wells drilled

• Protection of groundwater resources

Improved offshore drilling and 

completion technology

Today’s offshore operations include more

stable rigs and platforms, can drill in far

greater water depths, and apply new controls

to prevent spills. Subsea completion technology, for example, allows multiple wells 

to be drilled through steel templates on the

seafloor. A small number of lines (or risers)

then carry produced fluids from the templates to production facilities on the surface

or to a platform collection system. This 

technology reduces the risks of spills and

allows safe production from multiple wells 

as the industry approaches water depths 

of 10,000 feet.

New offshore platforms and wells feature

extensive blowout prevention, well control,

oil-spill contingency, and safety systems. All

offshore wells have storm chokes that detect

damage to surface valves and shut in the well

to prevent spills. Blowout preventers are

located at the seafloor instead of at the platform level, protecting sea beds and sea life,

and sensors continuously monitor subsurface

and subsea-bed conditions.

Environmental benefits of improved offshore

drilling and completion technology include:

• Fewer wells

• Lower waste volumes

• Reduced maintenance and workovers

• Enhanced well control

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

METRICS METRICS

D RILLING AND

C OMPLETION
WITH ADVANCED RESERVOIR MANAGEMENT AND OTHER PRODUCTION TECHNOLOGIES, 

PRODUCERS RECOVER MORE RESOURCES FROM OIL AND GAS OPERATIONS, WHILE

MINIMIZING PRODUCED WATER AND OTHER WASTES.

P RODUCTION
© SPE,1993
44 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

HIGHER YIELDS P LUS

A CLEANER E NVIRONMENT

Since the beginning of the commercial oil

industry in 1859, just a handful of U.S. oil fields

have topped the 1-billion-barrel mark for production. California’s South Belridge field

recently joined their ranks, thanks in large part

to enhanced oil recovery technology. 

The discovery at South Belridge in Kern County

was described in 1911 by a San Francisco newspaper as “a small quantity of oil, not sufficient 

it is believed to be a commercial success.”

Production levels remained modest throughout

the field’s early years. A new era began for 

the field in the 1960s with the advent of steam

injection to increase oil recovery. From an

average production of 11,370 barrels per day at

the end of the 1950s, the field by the end of

December 1979 was producing 49,500 barrels

per day. With a major development program by

Shell, production peaked in 1987 at an average

of 174,800 barrels per day. Though decline 

had set in, the field remained the Nation’s fifth

most productive oil field in 1994, with production averaging 120,000 barrels per day. By

extending the productive life of fields such as

South Belridge, enhanced oil recovery technology reduces the need for new exploration

and drilling operations—and eliminates their

associated environmental impacts.

Source: Oil & Gas Journal, October 16, 1995

ONCE A FIELD IS BROUGHT ONproduction, good reservoir management is required to ensure that as much 

oil and gas as possible is produced as costeffectively as possible, with minimal waste

and environmental impact. Early producers,

relying on natural pressure and primitive

pumps, recovered only about 10 percent 

of the oil in a given field. They sometimes

vented or flared natural gas produced in

association with the oil. In contrast, today’s

producers use an arsenal of advanced recovery techniques to keep oil and gas resources

flowing, enabling them to produce as much

as 50 percent or more of the oil resources

and 75 percent or more of the natural gas 

in a typical reservoir.

Progress has been particularly impressive 

in the last decade. In response to declining

crude oil prices and relatively flat natural 

gas prices in the 1990s, operators throughout

North America have initiated major programs

to reduce production expenditures, resulting

in further technological advances and more

streamlined operations. Technology improvements have brought a dramatic decrease 

in the average cost of producing oil and gas,

from a range of $9 to $15 per BOE in the

1980s to today’s average of roughly $5 to 

$9 per BOE.
O IL AND G A S T ECHNOLOGY 45

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

P RODUCTION

Production from oil and gas operations generally flows around the clock.

A constant stream of performance

data allows a producer to reevaluate 

operations and make appropriate 

decisions over time.

Surface facilities gather the produced

oil, gas, sands, and water into distinct streams. These streams are then

processed to remove impurities from

oil and gas products, capture gas 

and water for reinjection if enhanced

recovery techniques are in use, and

treat and properly use or dispose of

any water or solid wastes. Finally, 

the product is transported to market.

Producing Energy and

Environmental Benefits

IMPROVED PRODUCTION TECH -

nology has greatly reduced environmental

impacts as well as costs. For example, better

reservoir management has decreased volumes

of produced water, which, at about 15 billion

barrels per year, is the largest waste stream

generated in U.S. oil and gas exploration 

and production. On average, the industry

produces about 6 barrels of water for every

barrel of oil. Since management of produced

water is expensive—ranging from about

$0.10 to more than $4.00 per barrel—

technology to minimize produced water

volumes can yield significant cost efficiencies.

Many other advances—such as improved

treatment of produced water, better control

of hazardous air pollutants, more energyefficient production operations, and reduction of greenhouse gas emissions from E&P

operations—have also made oil and gas

production progressively less waste-intensive

and more productive. 
46 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Oil and Gas Recovery Processes

Field development can occur in three distinct phases:

Primary Recovery

Primary recovery produces oil, gas,

and/or water using the natural

pressure in the reservoir. Wells can 

be stimulated through injection of

acids or other fluids, which fracture 

the hydrocarbon-bearing formation 

to improve the flow of oil and gas 

from the reservoir to the wellbore.

Other techniques, including artificial

lift, pumping, and gas lift, help

production when the reservoir’s 

natural pressure dissipates.

Secondary Recovery

Secondary recovery uses other

mechanisms — such as gas reinjection and water flooding — to 

energize the reservoir and displace 

fluids not produced in the primary 

recovery phase.

Enhanced Oil Recovery

Enhanced oil recovery involves 

the injection of other liquids or 

gases (such as surfactants, polymers,

or carbon dioxide) or sources of 

heat (such as steam or hot water) 

to stimulate oil and gas flow 

and mobilize reservoir fluids that 

were bypassed in the primary 

and secondary recovery phases.

Advances in production technology that

contribute significant environmental 

benefits include:

Improved recovery processes

Rapidly evolving oil recovery technology

allows today’s operators to extract more

residual oil from existing reservoirs, after

primary and secondary recovery. Residual 

oil may be either too viscous to be produced,

trapped by interfacial tension, or lying in

zones that have not been swept by injected

fluids. The application of improved recovery

technology has expanded to all producing

areas of the country, allowing for production

of some of the approximately 350 billion

barrels of discovered but unproduced crude

oil in the United States. Without improved

recovery technologies, such as polymeraugmented waterflooding, the thermal

processes of steam or hot water injection,

and the injection of gases such as CO2, flue

gas, or nitrogen, these resources would be

prematurely abandoned.

Fundamentals of Production

Enhanced Oil Recovery in the United States

Crude production from enhanced oil recovery 

(Thousand barrels per day)

800

600

400

200

0

Source: Oil & Gas Journal, April 20, 1998

1984

1986

1988

1990

1992

1994

1996

1998

■ Chemical, microbial

■ Gas

■ Thermal

Natural flow

Primary recovery

Secondary

recovery

Waterflood

Thermal

Combustion

Steam soak/

cyclic/

huff and puff

Steam drive/

flood

Hot water drive

Electromagnetic

Gas miscible /

immiscible

Hydrocarbon

CO2

Nitrogen

Flue gas

Chemical

Alkaline

Polymer

Microbial/

polymer

Foam

Other

Microbial

Tertiary 

recovery

Pressure maintenance

Water Dry hydrocarbon

gas injection

Artificial lift

Pump, gas lift, etc.

Conventional oil recovery

Enhanced oil recovery

Source: Oil & Gas Journal, April 20, 1998
O IL AND G A S T ECHNOLOGY 47

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Improved produced water 

treatment technology

In locations where surface discharge of

produced water is still permitted (such as 

offshore and low-rate stripper wells in

Appalachia), a variety of methods are being

pursued to treat and reuse the water or

discharge it to the surface without environmental impact. Approaches include hydrocyclones, gas flotation, membrane separation,

granular activated carbon fluidized-bed

reactors, and biotreatment technology.

One particularly promising technology for

low-rate well application in some climates

and operational settings is the freeze-thaw/

Better reservoir management 

to reduce water production

Improved understanding of the flow

mechanics of reservoirs—resulting from

crosswell tomography, crosswell seismology,

better logging tools, and other reservoir

characterization advances—allows operators

to reduce produced water volumes through

more selective well placement and selective

shutting in of some wells. Developments in

completion technology, especially as applied

in horizontal wells, are also helping to delay

water breakthrough and maintain the ratio

of produced oil to produced water as high

and as long as possible. 

evaporation (FTE) process. Using a freeze

crystallization process in winter and natural

evaporation in summer, produced waters 

are separated into fresh water, concentrated

brine, and solids. The resulting fresh water

can be used for horticulture, livestock, and

other beneficial uses. The remaining volume

of wastes (solids and semisolids) requiring

disposal is significantly reduced. This process

requires large amounts of land and high

volumes of produced water retention and 

is limited to climates with cold winters and

dry summers, such as the Rocky Mountain

region, the Northern Great Plains, and

virtually all of Canada.

Downhole separation technology

In certain settings, downhole separation

represents a potential solution to a significant

environmental and cost issue for oil and gas

operators: the management and disposal of

produced water. In today’s operations, water

is generally pumped to the surface along with

oil, then separated from the oil. Since volumes

of produced water can exceed oil production

by 10 times or more, companies incur sizeable costs to lift the unwanted water, manage

it on the surface, and dispose of it (usually

by reinjection into the earth’s subsurface). The

approach also has the disadvantage of bringing contaminants up through the well piping.

In downhole separation, mechanical or

natural methods are used in the wellbore to

separate the formation’s oil and water. The

oil is then brought to the surface, while the

water is directly pumped into a subsurface

injection zone. In its current state of development, downhole separation is thought to be

applicable only to light oil wells with relatively

high flow rates and meeting minimum casing

diameter and water-to-oil ratio standards. 

P RODUCTION

Currently being tested in pilot-scale projects throughout the world, downhole separation

may someday deliver significant cost savings and environmental benefits in settings

where the technology is applicable. In one recent demonstration (illustrated here), downhole separation decreased surface water production by 95 percent and increased oil

production by 50 percent, resulting in a 4-month payback period.

Actual Example of Reduction in Produced Water 

Using Downhole Separation

METRICS

■ Surface water production

■ Oil production

(Production in barrels per day)

© SPE, 1997 January

Begin workover

Install test electrical submersible pump

Install downhole separator

F

M

A M

J

J A

S

O

N December

10,000

1,000

100
48 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Field tests are demonstrating that this technology, effectively deployed, has the potential

to significantly reduce the produced water

brought to the surface in applicable wells,

directly reducing fluid lifting and disposal

costs, as well as any associated environmental

concerns. Downhole separation can also

increase oil production in proportion to the

decrease in water production.

In many parts of the country, the high cost

of produced water management is the main

reason for well abandonment. By controlling

the increasing costs normally incurred as

water volumes increase, downhole separation

can potentially increase U.S. oil production

and recoverable reserves. 

In some cases, downhole separation may also

enable increased oil production and recovery

of original oil in place through improved or

altered water flow distribution in the reservoir. In addition, dynamic control of the 

oil-water contact can be achieved through

dual completion and reinjection. 

Depending on how widely downhole separation is applied in the future, as much as 

5 billion barrels per year of produced water

that otherwise would have been brought 

to the surface will remain in the ground.

Better leak detection, measurement,

and control systems for hazardous

air pollutants

Technology advances on several fronts are

reducing emissions of hazardous air pollutants in E&P operations. In the last decade,

for example, many approaches have been

developed to detect, measure, and control air

pollutants from a variety of oil and gas field

equipment. State-of-the-art leak detection

and measurement systems pinpoint fugitive

gas leaks, conserving valuable natural gas 

and identifying potentially life-threatening

hazards to workers and the community.

Vapor recovery units—economical for large

operations with relatively high reservoir

pressures and vapor releases—are being

employed to reduce emissions of volatile

organic compounds from storage tanks by 

as much as 95 percent. Improved management approaches for glycol dehydrators 

are also helping to reduce emissions substantially. In addition, new technology for

removal and recovery of acid gas (hydrogen

sulfide, mercaptans, and carbon dioxide)

shows cost savings of 40 percent compared

to current technology.

More energy-efficient 

production operations

Operators increasingly are focusing on ways

to reduce energy use in their operations. 

For example, new stripper well beam pumps

have reduced electricity consumption substantially. Improvements in energy efficiency

result in corresponding reductions in emissions of air pollutants associated with energy

use in production operations.

Better facility-wide waste 

management planning

The E&P industry, working with States, 

is aggressively employing technology and

practices to reduce or eliminate waste by

preventing it at the source. Techniques

include better planning, materials management, materials reclamation, and recycling;

major changes to E&P processes; improved

auditing and maintenance procedures;

changes in day-to-day operations to control

waste generation; and more targeted

employee training.

Increased focus on reducing 

greenhouse gas emissions

A wide variety of approaches are currently

being pursued to reduce emissions of

methane, a potent greenhouse gas thought 

to contribute to global climate change.

Methane losses from oil and gas industry

operations are considerable, and emission

reduction techniques reduce both global

emissions of greenhouse gases and the losses

of a valuable product. Technology being

pursued includes glycol dehydration using 

a separator-condenser (which can result in 

emissions recovery of over 95 percent), and

replacing high-bleed pneumatic controllers 

(a particularly large source of methane emissions) with low-bleed pneumatic devices.

Nature’s technology provides water for agricultural and other beneficial uses. 

In suitable environments and under certain operating conditions, initial field tests

indicate the freeze-thaw/evaporation process may reduce the volume of produced

water requiring disposal by 80 percent.

METRICS
O IL AND G A S T ECHNOLOGY 49

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

P RODUCTION

BEYOND THE OI L PATCH

• Developments in reservoir engineering

and reservoir simulation technologies

and processes have advanced our ability to predict groundwater flows, 

pollutant fate, and transport in groundwater, and to simulate the diffusion 

of air pollutants in the atmosphere.

• Adaptations of microbial enhanced 

oil recovery technology, originally 

developed for enhancing crude oil 

recovery, has proven to be quite 

effective in the remediation of

hydrocarbon-contaminated sites.

Recent advances in coalbed reservoir engineering and completion practices have also

turned coalbed methane—historically considered a safety hazard for mines and vented

to the atmosphere—into a reliable energy

resource. This resource now accounts for

over 5 percent of U.S. gas production and 

6 percent of proved gas reserves. Recovery

rates are being further enhanced by the

injection of carbon dioxide or nitrogen.

Gas-to-liquids technology is still on the

cutting edge, but promises to make vast

quantities of previously untapped natural gas

transportable and marketable. The process

chemically alters natural gas to form a stable

synthetic liquid that performs more efficiently and with fewer greenhouse emissions

than conventional fuels. The North Slope of

Alaska alone is estimated to have 25 trillion

cubic feet of natural gas that is currently

undeveloped because transporting it to markets would be uneconomical. Gas-to-liquids

technology may soon enable natural gas, 

the fuel of choice for environmental performance, to be transported around the world.

In the 33 oil- and gas-producing States, approximately 574,000 oil wells and 300,000 gas

wells currently yield approximately 6.5 million barrels of oil and 54 billion cubic feet of

gas per day. Most of these wells—approximately 435,000 oil wells and 170,000 gas 

wells—are classified as “stripper wells” because they produce less than 10 barrels of 

oil or 60,000 cubic feet of gas per day. 

About 26 percent of U.S. oil production and 29 percent of gas production comes from 

offshore operations, predominantly in the Gulf of Mexico. Currently, there are over 5,000

producing structures in Federal offshore waters.

U . S . OIL PRODUCTION

U . S . GAS PRODUCTION

Source: American Petroleum Institute; U.S. Department of Energy; Independent Petroleum Association of America;

and Interstate Oil and Gas Compact Commission

Producing oil wells Crude oil production

Producing gas wells Natural gas production

■ Offshore

■ Onshore– Stripper

■ Onshore– Other
ON LAND AND OFFSHORE, OIL AND GAS PRODUCERS HAVE DEVELOPED INNOVATIVE

WAYS TO RESTORE SITES TO ORIGINAL — AND SOMETIMES BETTER-THAN ORIGINAL —

CONDITION, FOR DIVERSE USES RANGING FROM HOUSING TO AGRICULTURE TO

WILDLIFE HABITATS.

S ITE R ESTORATION
Photo: Corbis Images
52 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Farming and oil and gas 

production have coexisted beneficially 

for decades in rural America.

L EAVING A P OSITIVE

E NVIRONMENTAL L EGACY

Diamond Y Spring in West Texas, a rare desert

spring habitat, has been the site of an actively

producing oil and gas field for decades. It also

has been the focus of preservationists since 

the 1960s, with the discovery there of the Leon

Springs pupfish, a species thought to be extinct.

Pecos County cattle rancher M. R. Gonzales,

who bought the property in 1969, was instrumental in bringing the spring’s ecological

significance to the attention of oil companies

operating in the area. After a series of oil spills

around the property, a diversion dike was 

build in 1974 to protect the headspring from 

any future spills.

The Nature Conservancy turned to the oil

companies active in the area to provide funds

for the purchase of Diamond Y Spring in 1990.

Donations were made by Enron Corporation,

Exxon, and the Mobil Foundation, and an innovative partnership was forged with these and

other oil companies to establish protection and

reclamation projects in the area of the springs.

Old flow lines were replaced, pipelines near 

the spring system were encased in steel, many

well sites were diked and bermed, abandoned

wells were plugged, road construction was

minimized, and areas were revegetated with

native grasses and marshland flora. Today, 

the Leon Springs pupfish—together with rare

snails, a unique salt-tolerant sunflower, the

endangered Pecos gambusia fish, javelinas,

foxes, and other species—continue to flourish

on this unique desert spring property.

Source: The Nature Conservancy

AFTER 15 T O 30 YEARS OFproduction, most oil or natural gas 

wells reach their economic limit. It is time 

to pack up and move on. Wellheads, pumpjacks, tanks, pipes, facilities, equipment...

everything has to be removed from the site. 

The wells are then permanently plugged

with cement to prevent future flow of

subterranean fluids into the wellbore. 

The vast majority of abandoned or ophaned

wells in the United States today are a legacy

of the industry’s earliest environmental

practices, when operators took only rudimentary steps to inhibit the fluids left in the

formation or the wellbore from flowing to

the surface, to restore the land, or to remove

used equipment. These practices often created

animosity with landowners, prompting State

governments to address issues associated with

past closures. Today’s industry is responding

to the environmental challenges of past

closures and is treating site restoration as a

critical operational activity. Specialized teams

now handle site restorations, using new

technology and approaches that often result 

in reduced liability as well as enhanced

environmental conditions.

At land-based sites, the wellbore is plugged

to confine the producing formation and 

to protect valuable groundwater resources.

Waste-handling pits and other facilities are

closed, and the location is then restored to

near-original condition or prepared for its

intended future use, whether as agricultural

land, as a wildlife habitat, or as an industrial,

residential, or commercial development site.

Current strategies include maximizing reuse

of equipment and materials still appropriate

for other applications. 

Closure of offshore facilities has begun only

recently, so the legacy of past practices is 

not at issue here as it is with land-based sites.

Decommissioning and removing offshore

installations is a complex process, both legally

and technically. It is essential to meet the

wide variety of regulatory requirements and

to ensure that the marine environment 

is not compromised. Alternative approaches

are total or partial removal of the installation, or toppling on site. All require planning

and preparation years in advance. 

Advanced site restoration 

techniques enhance 

marine habitats.
S ITE R ESTORATION
54 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Restoring, and 

Even Improving, Habitats

TODAY’ S SITE RESTORATION

strategies are significantly more environmentally protective than past approaches. 

In some instances, these strategies actually

enhance the environment and create

economic benefits.

“Rigs-to-reefs”...presenting 

homes for marine life

Decommissioning operations, especially in the

Gulf of Mexico, have been largely dependent

on the use of explosives. But shock waves

from the blasts can damage sea life, other

nearby installations, and surface vessels. And

when an obsolete rig structure is towed to

shore, cut up, and sold for scrap metal, the

platform’s artificial reef habitat is eliminated

and the area’s ecosystem is upset.

In the “rigs-to-reefs” approach, massive offshore platforms are toppled and sent to the

bottom of the ocean, providing several acres

of living and feeding habitat for thousands 

of underwater species. The first planned rigsto-reefs conversion took place in Florida in

1979. In 1983, the Minerals Management

Service—the agency that manages leasing,

exploration, and development of Federal 

offshore lands—announced its support for

rigs-to-reefs programs. These programs are

beneficial from many perspectives. Marine

life is enhanced. Oil companies realize considerable savings from avoided removal costs.

And States receive a share of the savings as

the companies donate operating platforms 

or obsolete rigs, construct reefs, and donate

funds from their savings to support and

enhance the State’s marine ecosystems.

In 1984, the Federal government passed the

National Fishing Enhancement Act, which

further strengthened the program. Louisiana

and Texas followed suit in 1986 and 1990,

respectively, forming their own programs.

Today all five States bordering the Gulf of

Mexico have artificial reef programs, and

such reefs also are found in other locations

around the world.

Rigs make ideal artificial reefs. Constructed

of corrosion-resistant steel that withstands

displacement or breakup, rigs have a large,

open structure that allows easy circulation

for fish and provides havens for barnacles,

corals, sponges, clams, bryozoans, and

hybroids. Within six months to a year after 

a rig is initially placed on the sea floor, it 

will be a thriving reef ecosystem completely

covered with marine life. When it is toppled,

the newly created reef attracts additional

mobile invertebrates and other fish species and

an even more complex food chain develops.

The rigs-to-reefs approach saves the industry

millions of dollars a year and also yields

economic benefits for States:

• Generally 50 percent of the industry

savings is donated to a host State’s artificial

reef program.

• Commercial and recreational fishing and

recreational scuba diving prosper from the 

conversion, in turn increasing local tourism.

• Commercial divers are used for nearly all

phases of the conversion.

Oilfield pits and pads...

changing eyesores to assets 

Caliche, the crust of calcium carbonate that

forms on the stony soil of arid regions, is

common in drilling pads and pits in many oil

fields in Texas. A program recently initiated

by the University of Texas converts these 

pits and pads into no-maintenance wildlife

habitats. In the program, the pads and pits

are recontoured to a depth of 18 inches, shrubs,

grass, and forbs are planted, and a functional

hydrologic cycle is reestablished. Natural

recovery processes following drilling and

production are accelerated and can quickly

transform sites into desirable habitats.

Drill cuttings to create 

or restore wetlands

With assistance from DOE’s National

Petroleum Technology Office, Southeastern Louisiana University is exploring

whether drill cuttings can be safely used to

restore and create wetlands. Using unique

temperature-controlled mesocosm greenhouse
O IL AND G A S T ECHNOLOGY 55

From Oil Fields to Housing

Here are two illustrations of how effectively exploration and production sites

and their wastes can be adapted for reuse:

California (United States)

When the West Coyote oil field was discovered in 1909 near La Habra, California, it 

was 10 miles from the nearest town. By 1980, the field was nearly depleted and was

surrounded by housing developments. Since then, Chevron’s real estate management

group has converted the field from a potential liability into a prime real estate asset

through careful abandonments of tank farms, oil wells, and multiple surface facilities,

and subsequent site restoration—all in line with very strict environmental regulations

and constraints. The rolling hills are now the site of premium homes.

Colombia (South America)

In looking at options for disposing of drill cuttings from its Colombian operations, BP

Amoco staff came up with a new answer: using the cuttings as a raw material for bricks.

The deceptively simple idea has met a vital need in the local community, where building

materials had been scarce and expensive. The approach has also eliminated the environmental impacts of traditional disposal methods, which involved placing lime-fixated

cuttings in lined pits. Today, the bricks are manufactured by local companies, using a

combination of cement and water-based drill cuttings. Cuttings produced from drilling

just one well can make up to 700,000 new bricks.

BEYOND

THE OI L PATCH

Developments resulting from the

restoration of oil and gas E&P sites 

have been adapted and applied to 

the restoration of a wide variety of 

industrial facilities.

S ITE

R ESTORATION

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

facilities to simulate a wetland’s full range 

of tidal fluctuations, researchers found that

processed drill cuttings generally exhibited

low levels of toxicity and appeared capable 

of supporting healthy wetlands vegetation. 

In some cases, the elemental composition of

restored drill cuttings was found to be very

similar to dredge spoil currently in use as a

wetlands creation substrate.

New approaches to 

reclaiming and remediating 

abandoned well sites

The Oklahoma Energy Resources Board

(OERB), with support from the U.S.

Department of Energy, has been evaluating

and restoring abandoned and orphaned

drilling and production sites with no current

owner or operator. Since 1995, OERB 

has restored more than 1,000 sites across 

52 counties, and restoration is in process at 

an additional 500 sites. Under the OERB

program, oil and gas producers and royalty

owners in Oklahoma voluntarily finance the

site clean-up—the landowner pays nothing,

and OERB is not reimbursed from any other

source. The OERB effort was the Nation’s

first industry-funded environmental cleanup

and education program. Today, similar

programs have been adopted in several 

other States.

Road mix from 

nonhazardous oilfield waste

In road building, native soils are typically

excavated to prepare a road base and then

used as aggregate (course binding material) 

in the on-site mixing process. For roads in

oil and gas operations, a recently developed

approach uses recycled crude oil tank residuals

and other nontoxic wastes as an aggregate.

Although this practice has limited application, it has proven effective in reducing

particulate matter from unpaved roads and

other road dust emissions. Roads of these

materials provide all-weather access to

remote exploration and production sites,

improve driving conditions, and decrease

dust generation in production areas.

Case Study
FROM THE TUNDRA OF ALASKA TO THE WETLANDS OF LOUISIANA, A HOST OF

ADVANCED TECHNOLOGIES ENABLE THE OIL AND GAS INDUSTRY TO PRODUCE

RESOURCES FAR BENEATH SENSITIVE ENVIRONMENTS.

O PERATIONS IN

S ENSITIVE E NVIRONMENTS
O IL AND G A S T ECHNOLOGY 57

Smaller Footprints, Less Waste,

Lower Impact

A GROWING PROPORTION OF THENation’s remaining untapped resources

exist in sensitive environments—which are

as varied as the mountains and tundra of

Alaska, offshore California, the deepwater

Gulf of Mexico, and the wetlands of coastal

Texas and Louisiana—and even in the

midst of bustling urban centers. Moreover,

many of these fragile areas reside on our 

Nation’s public lands, requiring industry 

and government to work collaboratively as

stewards of these treasures. Industry simply

cannot afford failures in these fragile settings.

Over the last four decades, the industry has

developed increasingly innovative technology

and approaches for conducting operations 

in sensitive areas, improving not only environmental performance, but economic

performance and resource recovery as well.

Technology that enables safe and efficient

exploration and production beneath sensitive

environmental areas includes new 3-D seismic

and 4-D time-lapse imaging, satellite imaging,

aeromagnetic sensing, and ground-penetrating

radar. New acoustical and vibration devices

have also replaced explosives for generating

seismic signals onshore and offshore, reducing

noise and protecting marine and animal life.

And new directional drilling, extended-reach

drilling, and multilateral drilling technology,

coupled with measurement-while-drilling

systems, allow industry to safely produce

resources far beneath sensitive environments

with less surface disturbance.
58 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Established by President Theodore Roosevelt,

southern Alaska’s Kenai National Wildlife

Refuge is home to moose, Dall sheep, mountain

goat, caribou, coyote, wolf, grizzly bear, black

bear, lynx, wolverine, beaver, small mammals,

birds, and salmon. It is also home to the

Swanson River oil field. Unocal, operator of the

field since 1992, received the “National Health

of the Land” award in 1997 from the U.S.

Department of the Interior for environmental

excellence at Swanson River. 

To ensure that its oil and gas operations within

the refuge are conducted in an environmentally

responsible manner, Unocal has implemented

state-of-the-art practices. Plastic pipeliners have

been installed on 28,000 linear feet of metal

gathering lines and flow lines to avoid the

potential for leaks. Specially trained dogs are

used for the early detection of underground

pipeline leaks. A water filtration and treatment

system collects and processes runoff to prevent

problems that may arise from the leakage of

hydrocarbon compounds from old petroleum

storage facilities. And groundwater-monitoring

wells ensure that if contamination of groundwater occurs, it is quickly detected. Together,

these measures protect a habitat that will be a

refuge to wildlife and an inspiration to visitors

for many generations to come.

Source: Unocal Corporation, 1996 – 97 Health, 

Environmental, and Safety Report

LOGISTICAL BARRIERS—POSEDby extremely low temperatures, freezing

and thawing of the tundra, and remote locations—once limited drilling in arctic environments. Today’s operators not only cope

successfully with these challenges, but also

institute protective measures appropriate to

sensitive environments. Improvements over

the past 40 years have dramatically reduced

industry’s footprint on the fragile tundra,

minimized waste produced, and protected

the land for resident and migratory wildlife.

Environmental advances have also dramatically reduced costs of conducting oil and 

gas activities. Industry innovations include:

Ice pads and roads

As ice construction technology and equipment have improved in recent years, bittercold temperatures have been turned to good

use. Ice-based roads, bridges, drilling pads,

and airstrips have become the standard for

North Slope exploration projects. Not only

is ice-based fabrication cheaper than gravel, 

it leaves virtually no footprint on the tundra;

ice structures simply thaw and melt in the

spring. In recent years, this approach has

been further improved: BP Exploration

(Alaska) Inc. (BPXA) has successfully built

insulated ice pads for drill rigs, permitting

the company to extend its exploratory

drilling season significantly and to reduce

both seasonal mobilization of equipment and

drilling footprints, as well as operating costs.

Low-impact exploration approaches

When exploratory wells are too far from

existing infrastructure to build ice roads costeffectively, alternate means of transportation

are now used almost exclusively. Large 

all-terrain vehicles with huge, low-pressure,

balloon-like tires carry substantial equipment

loads across the tundra, leaving practically 

no tracks. To protect the North Slope’s fragile tundra, exploratory operations are now

conducted exclusively during the winter. 

Advanced drilling technology

Advances in drilling technology have played

a major role in increasing North Slope productivity and in benefiting the environment.

Horizontal drilling, introduced in 1990, now

accounts for 90 percent of the wells drilled in

Prudhoe Bay. Whereas early horizontal wells

in Prudhoe penetrated only 500 to 800 feet

of reservoir laterally, technology advances

From Alaska’s North Slope to Kenai ...Greater Protective Measures

Photo: The Stock Market
O IL AND G A S T ECHNOLOGY 59

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

S ENSITIVE E NVIRONMENTS

recently enabled a North Slope operator to

penetrate 8,000 feet of reservoir horizontally,

greatly increasing contact with oil-bearing

sands. If the bay were developed today using

horizontal drilling, only 11 drill sites would

be needed, compared to the 42 required in

the 1970s. The area’s first multilateral well

was drilled less than two years ago; today

there are 10 multilateral wells in the area,

two of which used coiled tubing rigs. 

A technology recently introduced jointly by

ARCO-Alaska and BPXA is truly revolutionary. Called through-tubing rotary drilling,

it allows an operator to drill a new well

through the existing production tubing of 

an older well, saving both time and money.

Another recent North Slope breakthrough 

is “designer wells” technology, an advanced

form of directional drilling, where wells

curve around and behind geological barriers

to reach small pay zones. Extended-reach

drilling is also greatly improving resource

recovery and environmental protection in

the area. Using extended-reach drilling,

North Slope operators expect to develop the

area’s newest giant field, the 1-billion-barrel

Alpine field, with 100 wells from only two

drill sites, minimizing the drilling footprint.

At Niakuk, operators have used extendedreach drilling to tap many offshore locations

from a single drill pad on Heald Point. 

By increasing resource recovery and reducing

drilling costs, all these advances have benefited

the economics of North Slope operators. 

By minimizing the number of wells drilled,

drilling footprints, and waste volumes, they

have benefited the environment as well.

Reduced footprint

Significant reductions in the size of

production-related facilities have shrunk the

footprint of North Slope operations. ARCOAlaska’s Kuparuk field, for example, uses a

55-acre facility as an operations base for

contractor support, compared with a similar

1,000-acre facility in the original Prudhoe

Bay field. If the entire Prudhoe Bay oil field

were built with today’s technology, its footprint would be 64 percent smaller than its

current size—the area impacted by drilling

pads would be 74 percent smaller, roads

would cover 58 percent less surface area, and

oil and gas separating facilities would take up

50 percent less space. Today, new production

pads are up to 70 percent smaller than the

original Prudhoe pads, and spacing between

wellheads has been reduced dramatically. 

In addition, facilities are now built more

quickly than previous ones, further reducing

construction costs and disturbances to 

the environment.

Improved methods for site 

restoration and enhancement

In the fragile North Slope ecosystem, site

restoration and habitat enhancement are a

vital part of post-production. As North Slope

operators continue their search for advanced

environmental solutions, new technology

and practices have been developed to restore

areas affected by E&P activities. For example,

at a number of abandoned gravel mining

sites in floodplains, BPXA and ARCOAlaska flooded the sites to create large pools

and lakes that serve as overwintering habitats

for fish and predator-free nesting sites for

waterfowl, a practice encouraged by the

Alaska Department of Fish and Game.

Revegetation of areas affected by gravel

construction and drilling is also an important

restoration technique. Between 1985 and 1989,

BPXA and the U.S. Department of Fish and

Wildlife worked jointly to restore the habitat

along the 10-mile-long Endicott road.

Researchers found that transplanting arctic

pendant grass successfully revegetated disturbed aquatic sites. In 1988, BPXA began

restoring its BP Pad, an exploratory drilling

site first used nearly 20 years earlier. After

equipment and debris were removed, the

well was plugged and construction gravel 

was excavated from the site. BPXA seeded

the wellsite and surrounding tundra with

three types of native grasses and fertilized 

the area. A snow fence was erected to create

snowdrifts that would increase moisture

levels at the site. Within three years, the

area’s native vegetation had been restored.
60 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

Wetlands and Coastal Operations...Ecosystems Preserved

GROWING NATIONAL AWARENESSof the environmental significance 

of wetlands and coastal areas has inhibited 

E&P operations in certain areas. Where

operations are conducted, the industry takes

extreme care to minimize all associated risks.

Technology such as directional drilling is

critical in minimizing surface disturbance 

in wetlands and coastal areas. Advanced 

site restoration methods for these sites are

also a vital industry pursuit.

Today, operators employ a variety of

advanced drilling and production technologies to operate safely in sensitive wetlands

and coastal areas. In the wetlands of south

Louisiana, for example, ARCO Oil and 

Gas Co. employed innovative drilling

technology to conduct operations that were

both environmentally safe and cost-effective.

By utilizing an efficient closed loop solids

control system, ARCO reduced both its

drilling footprint and its waste volumes.

A recent drilling operation on Padre Island

National Seashore on the Gulf Coast of

Texas, the longest remaining undeveloped

barrier island in the world and one of our

Nation’s most treasured Federal lands, also

demonstrates this commitment to environmentally responsible operations. In drilling

an exploratory well near the seashore’s

Malaquite Beach, Bright & Co. undertook

extensive cooperative planning and regulatory compliance efforts with Federal and

State agencies, while utilizing state-of-theart drilling and site restoration technology

to minimize impacts. For example, drilling

operations were conducted with a dieselelectric rig, which operated at extremely low

noise levels. Most of the rig’s components

were wheel-mounted, reducing the number

of equipment loads moved across the beach.

The drilling system’s mud pumps and draw

works were powered by electric motors—

using electric motors not only reduced air

emissions from the site, it minimized the

possibility of harmful oil leaks. 

Since the targeted pay zone was located

under a large wetlands area, directional

drilling was employed to drill beneath the

sensitive area, greatly reducing environmental impacts. During its operations,

Bright & Co. utilized an advanced polycrystalline diamond compact bit in order 

to maintain the well’s angle and direction.

Finding no productive zones in the well,

Bright & Co. plugged and abandoned 

the well, restored the site to its original

contours, and reseeded with native grass. 

These are but two examples that represent

the oil and gas industry’s commitment to

operate responsibly in sensitive wetland and

coastal areas. This commitment is recognized outside the industry as well. Robert J.

Potts, State Director of The Nature

Conservancy’s Texas office, recently noted,

“The Nature Conservancy of Texas has a

long history of cooperative partnerships

with the oil and gas industry. Several of our

preserves are home to ongoing oil and gas

operations while at the same time providing

excellent habitat for wildlife.”
O IL AND G A S T ECHNOLOGY 61

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A DVANCED E&P T ECHNOLOGY

S ENSITIVE E NVIRONMENTS

Offshore Operations...Operating Safer, Smarter, and Deeper

FROM THE GULF OF MEXICO’ Ssubsalt plays, to the hostile North Sea,

to offshore West Africa and Brazil, as the

offshore oil and gas industry moves into

deeper and more remote settings in search

of new resources, operators are utilizing a

variety of advanced technologies to protect

the environment, enhance worker safety,

and increase recovery. Offshore operations,

which occur in the midst of complex underwater ecosystems consisting of hundreds 

of aquatic species and flora types, require

extreme care and planning. Today, advanced

technology is meeting these challenges.

Advanced 3-D seismic and 4-D time-lapse

data processing and imaging technologies,

coupled with satellite-derived bathymetry

and gravity data, enable offshore operators

to locate oil and gas resources far more

accurately than only one decade ago, resulting in fewer dry holes, less drilling, and

greater resource recovery. For example, the

Gulf of Mexico’s subsalt play, completely

undeveloped 10 years ago, is now one of the

world’s hottest offshore settings, thanks to

state-of-art subsalt imaging technology such

as Full Tensor Gradient (FTG) imaging

and marine magnetotelluric surveys.

Not only is the industry finding and developing resources in more remote and challenging settings, it is significantly enhancing

worker safety and pollution control in the

process. Today, nearly all Outer Continental

Shelf operators are collaborating with the 

Minerals Management Service and other

Federal agencies to implement Safety and

Environmental Management Programs

(SEMP), voluntary, nonregulatory strategies

designed to identify and reduce risks and

occurrences of offshore accidents, injuries,

and spills. As a result, this commitment to

safer and smarter operating practices has

enabled the offshore industry to practically

eliminate oil spills from offshore platforms.

Today’s advanced subsea drilling and completion technology also enables the industry

to operate effectively and safely as it moves

into deeper and more hostile areas. For

example, advanced subsea blowout preventers (BOPs) maintain well control in deepwater environments. Current deepwater

BOPs, located on the sea floor instead of at

the platform level, continuously monitor

subsurface and subseabed conditions.

In the event of a well control emergency,

advanced “intelligent” subsea trees allow live

wells to be shut in quickly under a variety 

of well conditions and operational circumstances. Moreover, current measurementwhile-drilling technology enables drillers to

accurately steer a deepwater relief well to

regain well control if necessary.

Other recent advances in subsea technology

are permitting operators to access more

remote deepwater resources with minimal

disturbance to the surface and subsea environments. Subsea production systems, aided

by new-generation remotely operated

vehicles, all-electric subsea monitoring and 

control systems, and minimally sized

umbilicals, are now able to connect remote

subsea satellite wells to host production

facilities tens of miles away. For example,

Shell Exploration and Production’s Mensa

subsea production system, located in over

5,000 feet of water in the Gulf of Mexico,

produces natural gas from three subsea wells

connected to a subsea manifold sitting on

the sea floor, which is then tied back to an

existing shallow water production platform

(West Delta 143) over 60 miles away via a

12-inch carbon steel flowline. At West Delta

143, a computer-based system monitors the

operational status of the wells and other

subsea equipment, with the capability to

open and close the wells if necessary.

On the whole, these technologies are 

allowing the offshore industry to venture

into deeper waters than ever before, while

protecting marine life and subsea habitats. 

As a result of these advances, operators are

able to locate and produce more offshore

resources, with less drilling, fewer dry holes,

less waste, and minimal impact.
62 E NVIRONMENTAL B ENEFITS

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

DIVERSE IMAGES COME TO MINDwhen one envisions oil and gas exploration and production sites: scorching hot

deserts; windblown, tumbleweed-strewn

prairies; vast frozen tundra; 20-foot-high

waves and churning whitecaps; and distant

mountain ranges. But few people realize

that the petroleum industry also explores

for and produces oil and gas in the midst of

our Nation’s largest cities. In recent decades,

the industry has successfully met the unique

challenges posed by these urban environments, where operations are frequently

visible for all to see. Advanced technology

has been a key to meeting the challenges.

Urban operations are as varied as the cities

in which they are located. For example,

visitors to Oklahoma City are greeted with

the sight of pumpjacks and other production equipment and facilities—Oklahoma

City’s Will Rogers World Airport is located

in the heart of an active oil field. The Los

Angeles Downtown oil field, located in the

shadow of the Santa Monica Freeway and

near the Los Angeles Civic Center, has

produced nearly 14 million barrels of oil and

21 billion cubic feet of natural gas over the

past 30 years. State-of-the-art fire prevention and gas leak detectors ensure the safety

of the surrounding community. In the

Southern California beach community of

Huntington Beach, oil and gas development

occurs both onshore and in State offshore

waters. Onshore, production equipment

located on the beach operates as runners

and bicyclists enjoy a nearby boardwalk.

Offshore, extended-reach drilling technology

has permitted operators to tap nearshore

reserves from onshore deviated wells.

Perhaps the most remarkable story of urban

operations today is ARCO Long Beach,

Inc.’s 43,000-barrel-per-day operation at 

the East Wilmington unit, located in the

City of Long Beach’s scenic harbor. The 

East Wilmington unit is part of the giant

Wilmington field, one of the Nation’s

largest. Production at East Wilmington

occurs from four manmade islands—built

on 640,000 tons of boulders and 3.2 million

cubic yards of sand dredged from the harbor, and concealed by palm trees, flowers,

concrete sculptures, waterfalls, and colorful

Urban Oil and Gas Sites...Producing on the Avenue

“Hundreds of visitors from all 

around the world visit our islands every 

year, many of whom come here 

specifically to learn about this model of 

oilfield development in a sensitive, urban

environment. I haven’t met a person yet 

who doesn’t come away impressed.”

JAMES M. DAVIS

President of ARCO Long Beach, Inc.
O IL AND G A S T ECHNOLOGY 63

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

S ENSITIVE E NVIRONMENTS

Oilfield development 

in Long Beach harbor is a 

model urban operation.

nighttime lighting. These islands represent

the centerpiece of a collaborative solution

between the industry and the City of Long

Beach to tap the harbor’s resources without

harming its natural beauty.

Daily operations at East Wilmington are 

a testament to advanced technology and 

its success in protecting the environment.

Rather than using relatively noisy and

polluting diesel engines for drilling and

pumping, operations make use of quiet and

clean electric power. To shelter operations

from public view, drilling rigs are covered

by structures built to resemble high-rise

buildings, and wellheads and other support

facilities are located below ground.

In recent years, advanced technology has

played a critical role in expanding the field’s

production and maintaining a high level 

of environmental performance. In 1996,

ARCO implemented the largest waterflood

in California’s history at the field. This oil

recovery technique, combined with advanced

hydraulic fracturing and horizontal drilling

technology, has increased daily oil production by approximately 30 percent. Moreover,

ARCO is expecting a recently conducted 3-D

seismic survey to further boost production.

ARCO is now using chemical treatment for

final separation of produced water and oil

rather than gas-fired heated vessels, reducing

air emissions by 60 percent. The thousands

of tons of sand and shale removed during

operations are now reinjected into a dedicated well on one of the production islands,

rather than hauled to a landfill. Moreover,

ARCO is currently testing the viability of

using treated sewage effluent in its waterflood operations in order to reduce the

amount of fresh water currently needed.

Advanced technology has enabled the

petroleum industry to increase recovery of

oil and gas resources wherever they may

occur—including urban environments. As

a result, oil and gas development operations

are able to coexist, even thrive, in urban

surroundings, as operators successfully

minimize noise pollution, air emissions, 

and surface and visual disturbances. 
64 E NVIRONMENTAL B ENEFITS

Stewardship of public lands 

requires close collaboration of 

industry and government.

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

MANY OF OUR NATION’ S OILand gas resources are located on public

lands, over which the Federal government

has management and resource protection

responsibilities. These public lands range

from wildlife refuges to national parks and

seashores to the Outer Continental Shelf.

Operating in these national treasures entails

complex logistical, organizational, and operational challenges. The industry, in collaboration with the Department of the Interior

and other Federal and State agencies, has

employed a variety of advanced technologies

and creative solutions to operate effectively

in these areas, thus providing the environmental stewardship necessary.

In the Aransas National Wildlife Refuge on

Texas’ Gulf Coast, for example, Conoco has

worked collaboratively with the U.S. Fish

and Wildlife Service, the National Marine

Fisheries Service, and the Texas Parks and

Wildlife Park for 60 years to ensure that

ongoing operations do not harm the refuge’s

whooping crane population. Once one of

the rarest species in North America, the

refuge’s whooping crane population has

increased in number from 15 to approximately 200 over the last half century. Today,

Conoco performs seismic and drilling

operations only when the cranes are summering in Canada, avoids the marshlands

inhabited by cranes, and protects the

wolfberry plants on which they feed. 

In Alaska’s Kenai National Wildlife Refuge,

Unocal Alaska won the Department of

Interior’s “National Health of the Land”

award in 1997 for environmental excellence

in its Swanson River field operations.

Employing advanced pipeline maintenance,

leak detection, and water filtration/

treatment technologies, Unocal continues 

to operate successfully in this beautiful, 

yet fragile, environment.

Chevron USA Production Company’s

recent exploratory drilling operation at the

Hunter Creek site in Lincoln County,

Wyoming, further demonstrates advanced 

Joint Stewardship Protects Our Public Treasures
O IL AND G A S T ECHNOLOGY 65

E NVIRONMENTAL B ENEFITS of 

A DVANCED E&P T ECHNOLOGY

S ENSITIVE E NVIRONMENTS

technology’s positive impact on industry

performance in sensitive public lands. The

Hunter Creek site is located in the BridgerTeton National Forest—approximately 

20 miles from Grand Teton National 

Park and within the Greater Yellowstone

Ecosystem—and is home to a wide variety

of sensitive wildlife species, from black 

bears to bighorn sheep to peregrine falcons.

Chevron worked closely with the U.S. Forest

Service, the Department of the Interior, 

the Wyoming Fish and Game Department,

and other Federal and State agencies to

design and conduct operations with minimal impact on the surrounding habitat 

and wildlife. Although the site’s exploratory

well was not a commercial success, Chevron’s

goal of reducing environmental impacts 

was achieved.

To minimize surface impacts of equipment

mobilization on the area’s main access road,

the Hunter Creek operation became only 

the second well in the lower-48 States to be

drilled utilizing a helicopter to transport 

the drilling rig and other heavy equipment 

to and from the site. The drilling pad was

designed to blend in with the surrounding

meadows and clearings by carefully locating

the site, contouring the area cleared of trees,

and leaving some of the site’s trees intact.

To enhance site restoration activities,

Chevron stockpiled snags, boulders, and

stumps so that the site could eventually 

be returned to its natural state.

To manage drilling wastes, a semi-closedloop solids removal system was employed,

minimizing mud volumes and thus enabling

smaller reserve pits. To reduce sedimentation

impacts from runoff contact with exposed

soil near the pad, the drilling location was

enclosed by drain canals, drainage ditches,

berms, and containment pit, and capped

with four inches of gravel. To further

manage operations, Chevron implemented

surface and groundwater quality protection

plans to ensure protection of surrounding

creeks and underground water supplies.

These operations demonstrate the petroleum industry’s commitment to environmentally responsible operations on our

Nation’s public lands. By collaborating with

the numerous Federal and State agencies

with stewardship responsibilities over these

valued areas, the oil and gas industry is

today fulfilling its role as protectors of the

environment—and advanced 

technology is playing a 

large part in this success.

BEYOND THE

OI L PATCH

Research and demonstrations of the

restoration of sensitive environments

have advanced the state of knowledge

and understanding of a wide variety 

of sensitive ecosystems.
66 E NVIRONMENTAL B ENEFITS

O IL AND G A S I NDUSTRY

U NTIL NOW, IN EVERY ASPECT OF THE OIL AND GAS BUSINESS —

from satellite sighting of under-earth resources, to production, to refining, to

product formulation — technological progress has transformed the ability of the oil and

gas industry to meet the imperatives of both the environment and the marketplace. 

• Now the bar is being raised. The new century brings an array of environmental,

economic, and political challenges that will inevitably stretch the resources and test the

will of the industry. Strategic issues currently facing the industry include remaining

successful in an evolving and volatile marketplace; sustaining science and technology

TH E FUTURE

E XPLORATION

S ITE R ESTORATION

P RODUCTION

D RILLING AND

C OMPLETION

O PERATIONS IN

S ENSITIVE

E NVIRONMENTS

REMAINING SUCCESSFUL 

IN AN EVOLVING AND

VOLATILE MARKETPLACE

As this report goes to press, oil prices at

wellhead in the United States have increased

approximately 80 percent since December

1998, when prices were at their lowest

levels since the Great Depression. Although

low prices enabled energy consumers 

and the United States economy to reap

tremendous savings, low prices also threatened the economic viability of the domestic

oil and gas industry and our Nation’s

longer-term oil and gas production capacity

and energy security.

SUSTAINING SCIENCE AND

TECHNOLOGY PROGRESS

On the domestic E&P front, oil and gas

resources will become increasingly difficult

to find and produce. Although significant

new resources remain to be discovered in

previously unreachable areas, low oil prices

will constrain E&P investments. If these

domestic resources are to be developed,

industry will be challenged to develop and

apply E&P technologies that are even more

productive and innovative than today’s best.

Ongoing R&D will be vitally important.

Photo: The Stock Market

Photo: Corbis Images
O IL AND G A S T ECHNOLOGY 67

E XPLORATION AND P RODUCTION

progress; minimizing and controlling greenhouse gases; and ensuring responsible development. • In the longer term, worldwide demand for oil and gas is projected to increase

significantly, possibly raising competitive tensions, particularly between the developed

and developing nations. Increased productivity in E&P will be essential if the industry

is to keep pace with demand. • If the past is prologue, further advances in science and

technology can enable these challenges to be met. Technology innovations, stimulated

by shared societal objectives for a sustainable future and enabled by a flexible, responsive government regulatory and policy framework, can ensure a brighter tomorrow. 

MINIMIZING AND

CONTROLLING 

GREENHOUSE GASES

Concerns about global climate change are

expected to drive reductions in greenhouse

gas emissions associated with the production

and use of fossil energy. Scientists cite such

phenomena as the melting of the polar 

ice caps and increases in weather volatility 

as evidence that climate change is already

under way, and consensus is growing among

both political and industry leaders that

actions must be taken to reduce greenhouse

gas emissions to prevent far-reaching consequences. The oil and gas industry will be

challenged to minimize and control these

emissions on many fronts, including in E&P.

ENSURING RESPONSIBLE

DEVELOPMENT

Environmental challenges for the

exploration and production of oil and gas

will intensify. Industry will face increased

concerns and pressures related to land, air,

and water quality issues, environmental

justice, preservation of indigenous plants,

animals, and people throughout the world,

and protection of the earth’s ozone layer.

Continued improvements in efficiency,

waste minimization, ecology-sensitive

solutions, and societal interactions in E&P

will be required.

CHALLENGES
68 E NVIRONMENTAL B ENEFITS

T H E F UTURE C HALLENGES

DAUNTING C HALLENGES

DEMAND NE W S OLUTIONS

Increased productivity 

in E&P is vital to meeting 

future demand growth.

U.S. Consumption of Petroleum

Products, 1970–2020

(Million barrels per day)

■ History

■ Projections

25

20

15

10 1970

2000

2020

Source: Energy Information Administration, 1998

Remaining Successful 

in an Evolving and Volatile

Marketplace

MOST INDUSTRY EXPERTS PROJECT

that worldwide demand for oil and gas will

grow considerably over the longer term. As a

result, the international petroleum industry

will face intensified pressure to provide

increased volumes of crude oil and natural 

gas at reasonable prices. Industry success will

depend on continued improvements to

productivity and efficiency.

The global oil and gas industry is struggling

to survive in the increasingly competitive 

and volatile marketplace. Mergers and acquisitions, such as the BP-Amoco and ExxonMobil mergers, are unprecedented in both

scale and pace. Moreover, the industry is

going through a fundamental transformation

—many countries with traditionally

government-operated national petroleum

companies are divesting assets and opening 

their borders to international investment 

and development. 

The petroleum industry has in the past and

must continue in the future to be able to

withstand change in the marketplace. The

industry has a long record of success in

assessing and managing risk, and in handling

the cyclic oil prices that have been a hallmark of the petroleum business. By most

accounts the year 1998 was considered one of

the worst the industry has ever experienced.

Adjusting for inflation, world oil prices

premature abandonment. In 1997, approximately 436,000 oil wells in the United States

produced fewer than 10 barrels per day.

With 353 million barrels produced, these

wells accounted for almost 15 percent of

domestic oil production. 

In 1998, company budgets for exploration

and development expenditures were dramatically reduced from previous years. Finding

capital for new projects and preserving the

existing infrastructure—including leases,

wells, drilling and service equipment, transmission pipelines, and a skilled workforce—

became increasingly difficult. Although

industry is breathing easier these days, the

pain of low oil prices has not faded. Despite

months of recovering prices, rig activity

remains near historic lows. Some analysts

predict that domestic E&P spending will

decrease 20 percent in 1999.

reached the lowest level in 25 years.

Throughout 1999, however, world oil prices

have rebounded considerably, increasing

nearly 50 percent in the first six months of

the year. 

Low oil prices: What’s at stake?

While low oil prices, such as those in 1998,

enable energy consumers to reap significant

savings, they also threaten the viability of the

domestic petroleum industry. The number

of rigs drilling in the United States in 1998

was 60 percent lower than the year earlier.

Upstream employment dropped to levels not

seen in decades, to an annual average of

almost 326,000, the lowest level in 25 years

—nearly 55 percent lower than the record

employment levels of the early 1980s. And

U.S. imports of crude oil reached an all-time

high of 8.6 million barrels per day.

Low prices make marginally producing 

wells (especially those producing fewer than

10 barrels per day) particularly susceptible to
O IL AND G A S T ECHNOLOGY 69

T H E F UTURE C HALLENGES

Low oil prices pose a particular threat to

smaller domestic companies, those of

insufficient size, diversification, or worldwide

presence to “weather the storm.” In the

United States, the vast majority of oil and

gas companies are smaller independent firms

with fewer than 20 employees. These independents drill 85 percent of all new oil 

and gas wells in the country and produce 

40 percent of the crude oil and 65 percent 

of the natural gas.

Americans enjoying the low prices at the

gasoline pump may ask, “So what?” The

answer: this short-term windfall may well

come at the expense of longer-term economic

and national security. If American wells are

prematurely plugged and abandoned and

American producers go out of business, we

lose jobs, tax revenues, royalty income to

land and mineral owners, access to domestic

resources, in some cases never to return, 

and increase our dependence on foreign oil

and gas. Such changes could also hurt our

environment—reducing the capability 

of industry to meet projected natural gas

demand in the United States, increasing

tanker traffic and the possibility of spills 

in the marine environment, and reducing

industry’s capacity to develop and deploy

new technologies for improving productivity and environmental performance. 

A formidable task for industry 

and government

At this challenging time in the industry’s

history, government and industry must work

together to preserve America’s longer-term oil

and gas production capacity and energy security. An array of actions by States as well as

the Federal government may periodically be

necessary to assist the industry, especially

small businesses, in surviving low oil prices,

and to enable them to provide a foundation

for the future. Industry itself plays the greatest role in its future survival. Companies

must reassess their corporate strategies and be

prepared to articulate to others outside the

industry why oil and gas E&P is a prudent

longer-term economic and energy investment.

Sustaining Science and

Technology Progress

RESEARCH AND DEVELOPMENT

(R&D) is America’s investment in its future,

providing a science and technology base for

international competitiveness and leadership.

In the oil and gas industry, however, both

public and private investment in R&D have

been declining over the past decade. The 

24 largest E&P companies report that they

spent less than $500 million in 1995 on

research and development, only about 

45 percent (in real dollars) of its 1985 peak. 

A decline in basic research is particularly

apparent. Two-thirds or more of the investments made supported field service activities

rather than the advance of the basic science

that generates dramatic new technology.

U.S. Crude Oil Prices, 1970 –2020

(1997 dollars per barrel)

■ History

Projections

■ High Oil Price

■ Reference

■ Low Oil Price

$60

50

40

30

20

10

0

1970

2000

2020

$2,000

1,600

1,200

800

400

0 ■ Oil and Gas Recovery

■ Other Petroleum

■ Total

1977

1980

1985

1990

1991

1992

1993

1994

1995

1996

1997

Source: Energy Information Administration, Form EIA-28

(Financial Reporting System)

Petroleum Industry R&D

Expenditures, 1977 –1997

(Millions, $1997)

Source: Energy Information Administration, 1998

United States dependence on imported oil

has increased to record levels during the

last 25 years. Net imports provide almost

50 percent of U.S. oil consumption. Oil

imports could grow to as much as 71 percent

in 2020 depending on world oil prices, as

the gap between domestic oil production

and consumption widens.

Photo: Corbis Images
70 E NVIRONMENTAL B ENEFITS

T H E F UTURE C HALLENGES

Additional causes for concern are trends in

corporate downsizing and restructuring, as

well as a phase-out of consumer subsidized

financing by 2005 at the Gas Research Institute, the Nation’s largest natural gas research

and technology development organization.

Some experts believe these trends foreshadow

a shrinking population of scientists and

engineers and reduced opportunities for 

new generations of technologists.

Other factors provide reason for hope. From

the vantage point of three decades, both the

E&P industry and government have climbed

a steep learning curve. Industry and government relationships over the environment

have progressed markedly, from confrontation toward dialogue, from conflict to far

more collaborative, win-win problem solving. Technology partnerships have become

more widespread. To meet cost pressures and

leverage resources, companies increasingly

are working with each other, with academic

groups, and with government in new and

creative technology research, development,

and deployment efforts. More efforts of this

kind will be required in the future, to enable

essential technological advances.

Continued need for leadership 

Energy experts from industry, academia, and

the research community have recommended

that the Federal government continue to

provide leadership, focus, and substantial

financial support for energy research and

development. This Federal role can ensure

the achievement of national goals of U.S.

energy security, economic strength, environmental quality, and leadership in science

and technology. 

To lower carbon dioxide emissions and

decrease oil imports, the Department of

Energy has been called on to increase collaborative government and industry R&D

on natural gas as the transition fuel in 

the 21st century. For example, investments

would be made to conduct R&D in natural

gas production and processing technologies,

including a science-based program to understand the potential of methane hydrates

worldwide. Collaborative investments also

would be continued for technology transfer

and cost-effective technology demonstrations,

to maintain production from mature and

marginal domestic oil and gas regions. 

Organizations fostering oil and gas technology transfer range from universities,

to States, to professional societies, to advocacy groups. These groups are also

instrumental in articulating geoscience principles, and standards for more efficient oil and gas operations, environmental protection, and professional conduct.

A representative—but not comprehensive—list of these organizations includes:

American Association of 

Petroleum Geologists

American Association of

Professional Landmen

American Geological Institute 

American Institute of 

Professional Geologists

American Petroleum Institute

Association of American 

State Geologists

Completion Engineering

Association

Drilling Engineering Association

E&P Forum

Federal agencies 

Gas Research Institute 

Geological Society of America 

Ground Water Protection Council

Independent Petroleum 

Association of America

International Association of 

Drilling Contractors

International Petroleum Institute

Environmental Conservation

Association

International Marine Contractors

Association

Interstate Oil and Gas Compact

Commission 

National Ocean Industries

Association

National Association for Black

Geologists and Geophysicists 

Offshore Operators Committee

(Gulf of Mexico)

Oil and gas service companies 

(e.g. drilling and equipment 

service suppliers)

Petroleum Technology Transfer

Council (addressing the needs 

of independent producers)

Society of Exploration

Geophysicists

Society of Independent

Petroleum Earth Scientists

Society of Petroleum Engineers

Society of Petroleum Evaluation

Engineers

Society of Professional Well 

Log Analysts

State and national environmental

professionals associations 

State and private universities,

including Historic Black Colleges 

and Universities

State and regional industry 

trade associations

State geological surveys 

and societies

State regulatory agencies

U.S. Oil and Gas Association

“The United States’ research and development enterprise is in transition, shaped 

by the end of the Cold War, increasing

competitive pressures in the private sector,

realignments at research universities, and

shifting priorities in Federal spending....

The headlights are being lowered in the

private sector, where ‘long term’ is now

only five years—and sometimes three.”

Secretary of Energy Advisory Board Task Force on

Strategic Energy Research and Development, 1995

Building Awareness of 

Smarter Technology
O IL AND G A S T ECHNOLOGY 71

T H E F UTURE C HALLENGES

Fostering technology transfer

Demonstrations of advanced technology

concepts and information exchange are critical to accelerating the deployment of smarter

technologies. As new technologies are developed to improve economics or productivity, 

their introduction into the marketplace can

vary significantly due to such factors as 

cost, performance, applicability, adherence 

to government regulations or policies, and

regional availability. The advanced technologies described in this report range from technologies commonplace today, such as 3-D

seismic, to those gaining wider use domestically and internationally, such as horizontal

drilling, to very promising technologies yet to

be fully demonstrated, such as separating oil

and water downhole within the reservoir. 

Minimizing and Controlling

Greenhouse Gases 

T HE RISE IN GREENHOUSE GAS

emissions from fossil fuel combustion and

industrial and agricultural activities has

aroused international concern about the

impacts of these emissions on climate.

Greenhouse gases—mostly carbon dioxide,

but also some methane, nitrous oxide, and

other trace gases—are emitted to the atmosphere, enhancing an effect in which heat

reflected from the earth’s surface is kept from

escaping into space, as in a greenhouse.

Concerned scientists believe that the earth’s

surface temperature may rise enough to cause

global climate change. They cite such phenomena as the melting of the polar ice caps

and increases in weather volatility as evidence

that climate change is already under way.

And while scientific uncertainty remains on

the extent of the potential climate change,

nonetheless, consensus is growing among

both political and industry leaders that

actions must be taken to reduce greenhouse

gas emissions to prevent potentially farreaching consequences. 

On a per capita basis, the United States is

the world’s largest source of greenhouse gas

emissions. With 4 percent of the world’s

population, our Nation emits 23 percent of

the world’s greenhouse gases. 

Approximately 90 percent of United States

greenhouse gas emissions from human

activities come from energy production and

use, most emissions a by-product of the

combustion of fossil fuels. Concerns about

global climate change are expected to drive

reductions in greenhouse gas emissions

related to the production and use of fossil

energy. The oil and gas industry will be

challenged to minimize and control these

emissions on many fronts, including in E&P.

The Kyoto Protocol, negotiated by more than

160 nations in December 1997, is intended to

reduce net emissions of certain greenhouse

gases significantly by the 5-year period

between 2008 and 2012. Each participating

developed country has established emission

reduction or limitation targets under the

negotiated treaty. The ground rules for how

these reductions can be achieved, reported,

and verified continue to be negotiated.

Uncertainties and constraints

Many believe that significant economic

burdens could result from implementing 

the requirements agreed to under the Kyoto

protocol. The extent of these burdens is

highly uncertain, however, and is the source

of significant disagreement. Some factors

contributing to this uncertainty include:

• The availability and cost of new and

improved technologies, and the pace at

which existing capital stock can be replaced.

• Consumer acceptance of more advanced 

or efficient technologies, as well as the

increased use of nuclear and renewable

electric generation technologies.

• The identification and implementation of

successful, cost-effective fiscal and monetary

policies to moderate economic impacts,

and a diverse range of cost-effective mechanisms to encourage actions to reduce

greenhouse gas emissions.

• The adjustment of the electricity, natural

gas, and renewable energy industries to

new requirements and the possible changes

in industrial and energy sector composition

that would likely result.

• The timing and phase-in of the necessary

transitions.

“Technological progress plays a critical 

role in the modern economy.”

Presidents Council on Advanced Science and 

Technology, 1998
72 E NVIRONMENTAL B ENEFITS

T H E F UTURE C HALLENGES

The opportunity: the critical role 

of natural gas

Because of the higher relative carbon content

of coal and petroleum products, any strategy

to reduce greenhouse gas emissions would

encourage the decreased use of these fuels

and the increased use of lower-carbon fuels.

This implies more reliance on renewable

energy, perhaps on nuclear energy, and,

especially in the nearer term, on natural gas.

Most projections envision a dramatic rise 

in natural gas consumption to meet the 

needs of a greenhouse gas constrained world, 

which in turn will require substantial

increases in natural gas development and

production to meet growing market demands.

To minimize potential negative economic

impacts of climate change constraints, the

domestic industry must be able to continue

to hold costs down while delivering increasing volumes of natural gas. To accomplish

this, technological advances must continue,

and a supportive policy and regulatory

environment must encourage increased

natural gas development and production.

The response: policy and 

technology dimensions

To meet the challenges posed by climate

change, industry and government must work

collaboratively. Government must provide 

a policy and regulatory environment for 

the industry that encourages action, without

posing unnecessary economic burdens or

penalizing in the future those that act today.

Governments must identify and evaluate the

full range of options available to encourage

greenhouse gas emission reductions, allowing

the maximum amount of flexibility possible

to capture the innovation and entrepreneurial

creativity that has always characterized 

the petroleum industry. All possible policy

instruments—including, but not limited 

to, economic incentives, emissions trading,

technology controls, energy efficiency

initiatives, and product changes—should 

be debated, evaluated, and, where appropriate, implemented.

“For the oil and gas industry the dominant

issue of public policy is climate change.. ..

Our goal [at BP Amoco] is to reduce our

emissions of greenhouse gases by 10 percent from a 1990 baseline over the period

to 2010.... That target will now sit alongside our financial targets.... [It] has 

been developed... in close cooperation

with the Environmental Defense Fund, whose

help and support has been tremendously

valuable. I want to pay a tribute to them.”

SI R JOHN BROWNE, GROUP C HIEF

Executive, BP Amoco p.l.c., 1998

• In 1988, the World Meteorological Organization and the United Nations Environment

Programme established the Intergovernmental Panel on Climate Change (IPCC) to

assess the available scientific, technical, and socioeconomic information regarding

climate change.

• The United Nations Framework Convention on Climate Change (UNFCCC) was

adopted in 1992, in which Parties agreed in a nonbinding pledge to voluntarily

reduce greenhouse gas emissions to 1990 levels by 2000. The United States was 

one of the first countries to ratify this treaty.

• In 1995 and 1996, the first and second Conference of the Parties agreed to address

greenhouse gas emissions for the period beyond 2000, and began negotiating 

a protocol establishing legally binding emissions limitations and reductions for

developed countries.

• At the third Conference of the Parties—held in December 1997 in Kyoto, Japan—

the Kyoto Protocol was finalized, committing participating developed nations to

specific, binding emissions targets.

• The fourth Conference of the Parties, which was held in Buenos Aires, Argentina, 

in November 1998, agreed to a 2-year plan for implementing the Kyoto Protocol. 

The United States signed the Kyoto Protocol on November 12, 1998. Although signing

affirms the United States’ commitment to work with other nations to meet the

treaty’s goals, it does not impose an obligation on the United States to implement

the Protocol. (The treaty cannot become binding without approval of the United

States Senate.)

The Birth of the Kyoto Protocol
O IL AND G A S T ECHNOLOGY 73

Industry must be proactive in addressing

demands upon it to reduce greenhouse gas

emissions. It must participate in multistakeholder forums to constructively develop

effective mechanisms to address climate

change issues and ensure that industry’s

concerns and recommendations are represented. Industry must carefully examine its

own operations, policies, and procedures,

and identify all possible options for costeffectively and voluntarily reducing emissions

of greenhouse gases and improving efficiency

of operations. In many instances, considerable

cost reductions and economic advantages can

be achieved in conjunction with emissions

reductions. And responding to concerns

about climate change can provide marketplace opportunities for those in industry

willing to act decisively.

The oil and gas industry currently possesses

many of the tools and basic understandings

needed to mitigate carbon emissions.

Technologies now available, and under

development, may be used to separate and

capture carbon dioxide emissions from 

fossil-fueled power plants, oil and natural 

gas processing facilities, and other industrial

processes for injection into geologic formations. Three principal formations—inactive

and uneconomical gas reservoirs, aqueous

formations, and deep and unmineable coal

reservoirs—are widespread and have the

potential for sequestering large amounts 

of carbon dioxide. In the case of carbon

dioxide injection for enhanced oil recovery

or enhanced coalbed methane recovery, 

the benefits of oil and gas extraction may

partially or totally offset the cost of carbon

dioxide separation and capture.

For the industry and the Nation to address

climate change, continued improvements in

technology are critical. Technology opportunities in the 21st century to reduce United

States greenhouse gas emissions are possible

only with sustained government and industry

R&D efforts. Future technologies for

deployment in the oil and gas industry to

reduce greenhouse gas emissions may include: 

• Increasing energy efficiency in crude 

oil refining.

• Converting natural gas to liquid fuels.

• Increasing natural gas production to help fuel

industry and generation of electric power.

• Pumping carbon dioxide captured from

industrial and electric power generation

into oil reservoirs to enhance oil recovery,

into coal seams to recover methane efficiently, and into natural gas storage fields

to maintain subsurface pressures necessary

for gas deliverability (carbon sequestration).

• Minimizing fugitive gas emissions from

pipelines and other oil and gas equipment. 

While holding significant promise, the

development and deployment of such

technologies is not certain, given the decline

in R&D investment. 

Ensuring Responsible

Development

ENVIRONMENTAL QUALITY WILL BE

a continuing issue for the oil and gas industry.

America’s oil and gas industry must find the

means, including new technology, to meet

its future challenges, both in lowering costs

to maintain competitiveness and in protecting the environment. A rational regulatory

framework, reasonable access to resources 

in the United States and abroad, and

communication are also critical to meeting

these objectives.

Reinventing government

A more flexible and responsive policy and

regulatory framework is critical to the U.S. oil

and gas industry’s ability to provide reliable

and affordable energy supplies in a manner

reflecting shared societal concerns for environment, health, and safety. Government

must continue to improve its approach to

regulation—emphasizing sound science 

and cost-benefit and goal-oriented mechanisms—and to improve coordination of

policies affecting the industry. States and

Federal agencies, including the United 

States Environmental Protection Agency, 

the Department of the Interior, and the

Department of Transportation, have increasingly come to understand effective roles of

government in enabling industry to improve

its environmental performance. These roles

include providing educational assistance 

and fostering, not stifling, technology

innovation and voluntary efforts to protect

the environment.

“Natural gas has the potential to make 

a significantly larger contribution to both

this Nation’s energy supply and its environmental goals. Achieving that potential 

will take a commitment of innovation,

leadership, and resources by the industry

to overcome challenges that arise.”

National Petroleum Council, The Potential for 

Natural Gas, 1992

T H E F UTURE C HALLENGES
74 E NVIRONMENTAL B ENEFITS

Moving beyond conflict to 

consensus

Access to oil and gas resources domestically

and abroad will increasingly depend on

industry’s ability to demonstrate its commitment to responsible development. Industry

has a responsibility to improve its credibility

and an opportunity to lead in the resolution

of contentious issues. Oil companies, in particular, have been viewed by many as lacking

a concern for the environment and the commitment to protecting it. For this perspective

to change, industry must improve and

expand communication with stakeholders

outside the industry. Such communication

will be crucial for resolving the economic

and environmental issues the oil and gas

industry will face. Enhanced communication

must be championed by industry leaders to

show the commitment to real change in

relationships with stakeholders. Effective dialogue can enable consideration of the positions of all stakeholders, resulting in a more

realistic basis of action. Great strides have

been made, but more opportunities remain. 

Innovation in E&P technology continues well into the 21st century, providing

further environmental benefits. Successive generations of technology 

pioneers ensure that E&P trends are progressively smarter, more protective 

of the environment. 

In the fields of the future:

• Advanced earth imaging pinpoints the location of valuable oil and gas resources.

• Downhole sensors ensure peak drilling efficiency.

• Multiple completion wells and reduced surface footprints are the norm.

• Improved reservoir management and recovery processes ensure maximum oil 

and gas recovery.

• Subsurface waters remain in situ or are separated downhole, and produced waters

are minimized.

• Air emissions approach zero as particulates are effectively captured, gases are 

reinjected, and leak detection and control strategies become more effective.

• Production wastes are minimized and/or recycled.

• Impacts of drilling and resource recovery on sensitive environments, including

wildlife habitat, are minimal.

• Exploration and production sites are restored to original conditions or 

beneficially improved.

In the Nation:

• Maximum recovery of the Nation’s valuable domestic oil and gas resources is

achieved, respecting the environmental and other societal objectives.

• Natural gas serves as a transition fuel to lower carbon-based greenhouse gas

emissions and to decrease oil imports.

• Affordable and abundant supplies of energy enhance our national security.

• The United States sustains its E&P technology leadership worldwide.

• International cooperation expands to address global economic, security, and

environmental concerns.

T H E F UTURE C HALLENGES

A Vision for the Future

“A better dialogue between the oil industry

and the environmental movement is imperative. There is a lot of misunderstanding,

and an opportunity for constructive 

action exists.”

Participant in the National Petroleum Council’s 1995

Report on Future Issues: A View of U.S. Oil and 

Natural Gas in 2020
O IL AND G A S T ECHNOLOGY 75

Better communication between industry and

the public will improve public understanding

of the industry and its value to the country.

Education in the principles of science and

economics is key to comprehending energy

and environmental issues facing the industry.

Though industry has a strong history of

supporting educational programs, it must

focus its efforts to better understand public

and customer concerns, and to encourage

science, economic, and energy education.

Stewardship of public lands

In the United States, vast quantities of oil

and gas resources underlie Federal lands,

including forests, deserts, rangelands, wetlands

and marine environments, to be managed for

public benefit. Today, onshore Federal lands

annually yield approximately 5 percent of our

Nation’s crude oil production and nearly 

10 percent of its natural gas. Offshore, Federal

lands account for approximately 19 percent

of annual crude production and 25 percent

of annual natural gas production. About 

50 percent of the remaining untapped technically and economically recoverable crude

oil and gas reserves are on Federal lands,

excluding wilderness areas. More than 

80 percent of these properties are offshore.

Public opinion on access to Federal lands 

for resource exploration and production

remains divided. Advanced oil and gas technology will play a critical role in the continued debate regarding access to Federal lands,

both onshore and in the Outer Continental

Shelf. Public dialogue on the need for energy

and the need for protection of the environment, particularly our most fragile ecosystems, will contribute to improved resolution

of the issues.

Looking to the Future

AS WE APPROACH THE 21ST CENTURY,

oil and gas scientists and engineers, through

professional organizations such as the

American Association of Petroleum Geologists,

the American Geologic Institute, and the

Society of Petroleum Engineers, are looking

to the future. Key organizations have

strengthened their commitment to fostering

ethical behavior and professional conduct, 

to applying scientific principles and data for

addressing basic environmental issues, and 

to working actively to encourage responsible

exploration and production of the world’s 

oil and gas resources. 

These organizations have long stimulated

professional development in the oil and gas

industry, as the hub of information exchange

on geologic, engineering, and biological

sciences, and as the source of career and

corporate mentoring. Increasingly, these

organizations are also looking outward. 

They are stepping up outreach efforts to

communicate the technology and practices

used today to minimize environmental

impact. They are partnering across scientific

disciplines. They are partnering with land

management agencies to understand the

impact of oil and gas operations on sensitive

ecosystems, and to develop industry guidelines and policy for future operations in these

areas. And they are encouraging members 

to become more involved in public policy

and promoting a scientific approach in

solving environmental problems.

The development of new oil and gas technologies—and the environmental benefits that

come from them—will be constrained only

by the limits of our Nation’s drive and imagination. With sustained vision, leadership,

and the commitment of both the public and

private sectors, new technologies will be

developed, American oil and gas resources can

be utilized, and the environment will be served.

T H E F UTURE C HALLENGES

ENABLING NEW GENERATIONS OF 

TECHNOLOGY PIONEERS

“Folks were impressed with the pluck and

enterprise of the two guys and decided to

give them a hand.... The story of Wilcox 

Oil Company [the dream of two young

geologists fresh out of college] is one of

generosity, mentoring, giving the lessons

of a lifetime, and furthering the best of

human character.”

RICHARD S. BISHOP

President

American Association of Petroleum Geologists, 1998
Better 

Wellbore 

Control

Protection of 

Habitats, 

Wildlife, and

Cultural 

Resources

O IL AND G A S I NDUSTRY

TECHNOLOGY

Smaller

Footprint

Fewer Wells 

or 

Dry Holes

E XPLORATION

1 3-D Seismic

2 4-D Visualization

3 Remote Sensing

4 Subsalt Imaging

D RILLING AND C OMPLETION

5 CO2-Sand Fracturing

6 Coiled Tubing

7 Horizontal Drilling

8 Hydraulic Fracturing

9 Measurement-While-Drilling

bl Modern Drilling Bits

bm Multilateral Drilling

bn Offshore Drilling

bo Pneumatic Drilling

bp Slimhole Drilling

bq Synthetic Drilling Muds

P RODUCTION

br Acid Gas Removal and Recovery

bs Artificial Lift Optimization

bt Coalbed Methane Recovery

bu Freeze-Thaw /Evaporation

cl Gas-to-Liquids Conversion

cm Glycol Dehydration

cn Advanced Data Management

co Improved Recovery Processes

cp Leak Detection and Measurement Systems

cq Low-Bleed Pneumatic Devices

cr Offshore Platforms

cs Downhole Oil / Water Separation

ct Safety & Environmental Management Programs

cu Vapor Recovery Units

S ITE R ESTORATION

dl Advanced Approaches to Site Restoration

dm Rigs to Reefs

dn Road Mix and Roadspreading

S ENSITIVE E NVIRONMENTS

do DOE-BLM Partnership

dp Coastal and Nearshore Operations

dq Insulated Ice Pads

dr North Slope Operations

76 E NVIRONMENTAL B ENEFITS
E XPLORATION AND P RODUCTION

FACT SHEETS

Optimized

Recovery of

Valuable Oil and

Gas Resources

Enhanced 

Worker 

Safety

Reduced

Greenhouse 

Gas Emissions

(e.g., methane)

Reduced Air

Emissions

(e.g., HAPs, 

NOx, PM)

Reduced 

Power 

or Fuel

Consumption

Protection 

of Water 

Resources

Reduced 

Waste 

Volumes

The technologies described in these Fact Sheets are merely representative of the numerous advances in exploration and 

production technology over the last three decades and, as such, are not intended as an exhaustive inventory of these advances.

O IL AND G A S T ECHNOLOGY 77
Fact Sheets 1 to 4

E XPLORATION

Fact Sheets 5 to bq

D RILLING AND C OMPLETION

Fact Sheets br to cu

P RODUCTION

Fact Sheets dl to dn

S ITE R ESTORATION

Fact Sheets do to dr

S ENSITIVE E NVIRONMENTS

C ONTENTS

T ECHNOLOGY F ACT S HEETS
Two decades of successively better geologic interpretation

demonstrate tangible results and environmental benefits

E XPLORATION

1

E XPLORATION

Advances in 3-dimensional

(3-D) seismic technology

over the past 25 years

have enabled oil and gas

producers to evaluate

prospects more effectively,

drill fewer exploratory

wells, and develop fields

more efficiently. The result

is decreased environmental impact and increased 

profit. To establish a visual

orientation of the subsurface without drilling,

energy waves directed

downward through the

earth’s strata are reflected

off the rock layers and

sent back to the surface.

The resulting data undergo complex processing

and interpretation and

provide explorationists

with a 3-D visual characterization of the subsurface’s geological features.

This allows detailed

assessment of the opportunities and risks of developing a reservoir, an

increasingly important

capability as the search for

resources pushes into new

exploration frontiers, such

as deepwater and subsalt

formations.

From 2-D to

3-D technology

U NTIL THE ,

developers had to rely

on inaccurate, low-resolution

analog data in planning their

exploration investments. In

the s, improved -D seismic techniques enabled

explorers to characterize subsurface opportunities with

greater effectiveness. Now,

with -D seismic, they can

establish more accurate -D

characterization of geologic

structures. Reservoir characterization is key across all

stages of a hydrocarbon field’s

life. Seismic information, 

critical during the exploration

and appraisal phase, is now

used for development until

the field is abandoned. In the

last  years, the discovery

cost has decreased from 

per barrel with -D seismic to

just under  per barrel with

-D seismic. Better geologic

representations, coupled with

advanced drilling and production technologies, also

lead to increased recovery

efficiencies.

Several major improvements

in -D surveying occurred

during the , in seismic

data acquisition, processing,

computer hardware, and

interpretation and display.

Particularly remarkable have

been the hardware improvements. Within the last five

years, recording systems have

increased capacity from  to

, channels, as many as 

seismic data lines can be

recorded in a single pass, and

satellite navigation systems

have evolved to pinpoint

accurate positioning of

sources and receivers. At the

same time, technological

improvements have reduced

computing time and lowered

costs. -D stack-time migration can now be performed in

a few hours on massively parallel processors, and between

 and , costs dropped

from  million to  million

for a -square-mile survey

using -D post-time depth

migration. By , costs for

an equivalent survey are

expected to be near ,.

3-D Seismic

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

More accurate exploratory well-siting reduces

the number of dry holes and improves overall

productivity per well drilled

Less drilling waste is generated

Better understanding of flow mechanics

produces less water relative to oil and gas

Overall impacts of exploration and production

are reduced because fewer wells are required

to develop the same amount of reserves

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Helps explorers to better identify oil and

gas prospects

More effective well placement improves

development of resources

Fewer dry holes ultimately reduces drilling and

exploration costs

Can substantially improve project economics

by reducing overall drilling costs

Exploration time relative to successful

production is cut
E XPLORATION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Edith C. Allison

(202) 586-1023

edith.allison@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Aylor, W. The Business Impact

and Value of 3-D Seismic. OTC

7960, 1996.

Aylor, W. Role of 3-D Seismic in

Exploration Turnaround. Oil &

Gas Journal, 3/1/98.

Barr, F. New Seismic Technique

Is Improving Hydrocarbon

Recovery. Journal of Petroleum

Technology, 7/96.

Locke, S. Advances Reduce Total

Drilling Costs. The American Oil

& Gas Reporter, 7/98.

Hansen, W. Reducing the Impact

of 3-D Seismic. SPE 35812, 1996.

Nesser, D., and J. Pohlman.

Offshore Seismology Today:

More, Better, Faster, Cheaper.

Offshore, 3/98.

SOURCES AND ADDITIONAL READING

CASE STUDIES

METRICS

Exploration success in 

the United States

Advances in 3-D seismic and drilling and completion 

technology dramatically increased drilling successes.

Exploratory Wells

0% 100%

1970

1997

1980 30%

48%

17%

-D seismic has now gained

widespread acceptance.

Whereas by  only 

-D seismic surveys had been

done, by the mid- an

estimated – -D seismic surveys were being conducted annually. Offshore

growth has been tremendous: in , only  percent

of the wells drilled in the

Gulf of Mexico were based

on -D seismic data; by

, nearly  percent used

-D seismic. Onshore, 

percent of all surveys were

conducted with -D seismic

by .

Answering environmental

and safety challenges

Today, producers are working to assess and minimize

the impact of -D seismic

equipment and crews on

sensitive environments.

Explosives used to generate

sound waves recorded by a

seismograph can now be

replaced where necessary by

vibrating technology that

sends an acoustic signal.

Offshore seismic surveying

now relies on the use of

compressed air guns to

ensure protection of marine

life. Depending on the kind

of information needed, the

geology expected, the

nature of the field, and the

costs, -D seismic exploration can be customized to

protect the specific terrain.

For example, in mountainous terrains, standard seismic techniques (-D)

required densely gridded

surveys for accurate geologic

descriptions. -D acquisition

techniques allow for more

widely spaced, less invasive

surveys while providing better quality data. 

Advancements in -D data

processing also allow for

survey acquisition in areas

congested with urban or

industrial noise sources.

3-D seismic highly effective for portfolio 

management at Amoco

Amoco Corporation established an exploration drilling success

rate of  percent for its -D seismic exploration activities

between  and . By contrast, its exploration success rate

for wells drilled without the benefit of -D seismic was only

 percent. To evaluate the effectiveness of using -D, data were

collected on  seismic surveys and a control group of  other

prospects. -D proved extremely valuable at defining geometries,

particularly in the North Sea and Gulf of Mexico. Where conventional surveying turned up eight prospects, -D narrowed

these down to two. In addition, while all eight had been given

an economic success probability of between  and  percent, 

-D seismic correctly predicted that the two selected had a potential success rate of  percent.

Success in the Field

Source: Energy Information Administration, 1998
Evolving seismic technologies improve accuracy and

interpretation, allowing operations to be tailored to

protect the environment

E XPLORATION

2

E XPLORATION

Three-dimensional (3-D)

seismic technology has

revolutionized oil and gas

exploration and served as

a springboard to visualization technology. Now

emerging visualization

and 4-D time-lapse monitoring technologies are

improving interpretation

of the data 3-D seismic

imaging provides.

Invaluable in locating

bypassed reserves in existing formations and discovering new resources, seismic reservoir characterization can now incorporate

perceptual cues such as

projection, lighting and

shading, depth, motion,

and transparency. This

technology enables a

more consistent, detailed 

picture of a complex formation. 4-D monitoring

goes one step further, 

providing a dynamic 

picture of hydrocarbon

flows and other reservoir

changes over time, 

information valuable for

both exploration and 

reservoir management of

existing resources.

Adding a fourth

dimension—time

P ETROLEUM ENGIneers, geologists, and

planners have a far better

understanding of the geologic

structures of potential hydrocarbon-bearing formations

now that reservoir images are

projected in three dimensions. Four are better still,

largely due to DOE-supported

research. A reservoir’s fluid

viscosity, saturation changes,

temperature, and fluid movements can be analyzed by

time-lapse monitoring in

three dimensions. The timelapse picture is built out of

data re-recorded at intervals,

compared and plotted by

computer onto a -D model.

Engineers can view changes

occurring over time and link

these to static and dynamic

reservoir properties and production techniques. They can

then follow the consequences

of their reservoir management

programs and make predictions as to the results of

future activities. -D monitoring is an offshoot of the computer processing techniques

developed for -D seismic

interpretation.

With improved visualization

techniques, petroleum engineers, geologists, and geophysicists are integrating

many types and ages of data

(well logs and production

information, reservoir temperatures and pressures, fluid

saturations, -D and -D

seismic data) into time-lapse

imagery and reservoir performance modeling. As this

time-dependent tool is c

orrelated with physical data

acquisition, more accurate

characterization of subsurface

reservoirs will be possible,

pushing maximum recovery

efficiencies.

Geologists and planners are

better able to understand the

structure of promising formations. As computing science

advances, further gains will be

made. Already, audio technology is being added, both for

controlling images and presenting complex geological

data so that scientists can

share data in real time from

remote locations.

4-D Visualization

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced drilling due to more successful siting

of wells, with greater recovery from existing wells

Less drilling waste through improved reservoir

management

Lower produced water volumes through better

well placement relative to the oil/water interface

in the formation

Increased ability to tailor operations to protect

sensitive environments

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Improved recovery due to precise placement of

injector wells and infill drilling

More efficient operations due to better

identification of drainage patterns

Lowered operating costs because of improved

program timing and fewer dry holes

Increased identification and ultimate recovery of

as yet untapped resources
E XPLORATION

CONTACT

Gras, Cox, and Sagert. 3-D

Visualization, Automation Speed

Interpretation Workflow. World

Oil, 9/98.

He, Wei, et al. 4-D Seismic Helps

Track Drainage, Pressure

Compartmentalization. Oil &

Gas Journal, 3/27/95.

He, Wei, et al. 4-D Seismic

Monitoring Grows as Production

Tool. Oil & Gas Journal, 5/20/96.

Locke, S. Advances Reduce

Drilling Costs. The American Oil

& Gas Reporter, 7/98.

Ramshorn, C., and R. Sagert.

Interacting with Data in Virtual

World Leads to Better RealWorld Decisions. The American

Oil & Gas Reporter, 7/98.

Texaco E&P Center Allows

Visual Probe of 3-D Data

Volumes. Oil & Gas Journal,

7/1/98.

Tippee, B. Immersive

Visualization Provides an

Insider’s View of Subsurface. Oil

& Gas Journal, 6/1/98.

Track Production with 4-D

Technology. The E&P

Connection.

Williams, P. Time-Lapse Seismic.

Oil and Gas Investor, 5/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

4-D seismic in Indonesia

The Duri field in central Sumatra was the first -D project of its

kind. Today over  time-lapse projects follow its lead. Producing

, barrels of oil per day, the PT Caltex Pacific Indonesia

project is the largest steamflood in the world. In , Caltex

began -D recording in a series of eight surveys to determine

whether time-lapse could successfully monitor a steamflood. The

goal: to improve oil recovery and cut energy use. The data generated helped direct the injection process and identify both swept

and unswept zones. Due to the project’s success, Caltex started

baseline surveys in six new areas, and other companies are also

initiating use of time-lapse monitoring.

Immersed in 3-D visualization at ARCO

The ultimate formation viewing experience is to be immersed in

a walk-in virtual reality cube that replicates geophysical features.

In ARCO’s Immersive Visualization Environment, images from

projectors and mirrors outside the cube are projected onto three

-foot walls of seamless screens. An electromagnetic tracking system orients the viewer’s perspective, and stereoscopic goggles use

alternate left- and right-eye images and infrared timing devices to

create -D effects.

ARCO’s exploration teams have used the facility to study data

from the North Sea, Alaska’s North Slope, and a project near the

Philippines, using its superior visualization capabilities to produce

solutions to drilling problems. In the North Sea’s Pickerill field,

for example, drilling plans for a multilateral hole were complicated by pressure changes among the reservoir’s different compartments and drilling hazards above the reservoir. Adjustments to

the original drilling plan were dictated by judgments made in the

Visualization Environment, avoiding potential problems.

METRICS

Technology Percent Recovery

Estimated recovery for oil-in-place

at BP Amoco/Shell’s Foenhaven field

in offshore U.K.

0% 100%

2-D

3-D

4-D

40–50%

65–70%

25–30%

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Edith C. Allison

(202) 586-1023

edith.allison@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

Source: Hart’s Petroleum Engineer International, January 1996

Indonesia

Java Sea

South China

Sea Brunei

Borneo

Malaysia
Remote exploration helps pinpoint hydrocarbon resources, 

pollution sources, and sensitive environments

E XPLORATION

3

E XPLORATION

Used in conjunction with

other exploratory techniques, such as 3-D seismic imaging, remote sensing systems detect and

map concentrations of

hydrocarbons with greater

accuracy than other technologies alone, and with

less environmental

impact. Technologies such

as satellite imagery, aeromagnetic surveys, and

gravimetry are now being

applied by the largest

exploration companies to

attempt to detect the vertical or near-vertical

migration of oil and gas to

the earth’s surface and

help identify promising

geologic structures. These

systems measure gases,

solids, and liquids, using

their physical properties to

attenuate or reflect beams

of electromagnetic energy.

Resulting geophysical data

are processed into easily

understood images and

maps, and form an integral part of current

onshore and offshore

programs throughout

the world.

Enhanced satellite

imaging systems

OPTICAL SATELLITEimagery has been the

predominant source of data

for identifying and mapping

onshore geology since the

early , when the first

Landsat Earth Observation

satellite was launched. Today,

satellite imagery, onshore and

offshore, is also provided by

radar satellites very sensitive

to the earth’s surface contours. For example, various

types of satellites can see

through  feet of clear water

and up to  feet beneath the

surface. Early optical satellites

depended on visible or nearinfrared light to collect energy

reflected from the earth’s 

surface. By contrast, radar

satellites emit energy at

microwave frequencies,

enabling them to acquire

imagery under nearly any

atmospheric condition.

Sophisticated digital image

processing systems can now

convert and sort raw satellite

data into thematic maps that

point to the location of productive formations, even

detecting oil and gas seepages

that indicate migration pathways from undrilled traps.

Similarly, remote sensing

techniques can also identify

hydrocarbon spills and leaks

in remote areas, such as along

pipelines. 

Current multispectral satellites such as the Landsat

Thematic Mapper create

images by gathering up to

seven bands of light spectra in

prism-like fashion. In ,

when the U.S. Navy plans to

launch its Navy EarthMap

Observer satellite, an exciting

new satellite technology

called hyperspectral analysis,

accessing upwards of 

bands of light, will further

increase imaging accuracy.

Improved aeromagnetic

surveys

Initially developed for military applications, aeromagnetic surveying has evolved

into a productive exploration

technology that can recognize

the magnetic signature of

potential hydrocarbon-bearing

basins from altitudes over

, feet. Using a 

Remote Sensing

Locations: Worldwide (especially deepwater)

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Accurate identification of fragile ecosystems,

enabling care when drilling 

Increased ability to address environmental needs

Fewer dry holes and nonproductive exploratory

wells are drilled

Improved characterization of earth’s natural

systems

Identification of spills and leaks in remote areas

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased exploratory success rates

Dramatically reduced exploratory costs

Access to geological data otherwise 

unobtainable

Increased recovery of resources from frontier

basins

Identification of hydrocarbon “seeps” as

distinguished from oil spills or pollution
E XPLORATION

CONTACT

Corbley, K. Landsat Images

Assist in Mapping Caspian

Bathymetry. Oil & Gas Journal

Offshore, 7/1/97.

Detecting the Sleeping Giants of

the Caspian—from Space.

Offshore Magazine, 7/1/98.

Koger, D., and R. Dodge. Geosat

Starts Up R&D on Exploration

Sector. Oil & Gas Journal,

10/5/98.

Petzet, G. Explorers Look

Toward Better Remote Sensing

Data. Oil & Gas Journal, 3/9/98.

Remote Sensing Terminology.

Journal of the Air and Waste

Management Assoc., 11/91.

Wagner, M. Radar Imaging

Matched with Gravity and

Bathymetry. Oil & Gas Journal

Offshore, 5/1/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

magnetometer mounted on

a magnetically cleaned aircraft, explorers are successfully mapping sedimentary

anomalies critical to oil and

gas exploration, detecting

salt/sediment contact, mineralized shear zones, and

intrasedimentary markers. 

Recent improvements in

magnetometer design, digital signal processing techniques, and electronic navigation technologies, in

combination with faster

sampling of the magnetic

field and the use of more

detailed survey grids, allow

mapping of subtle magnetic

signatures. These advances

improve the interpretation

and visualization of

geological data.

Measuring gravity to gauge

resources

Gravimetry measurement is

now derived from both

satellite and airborne observations. Gravity anomalies

can be measured and

mapped to give geoscientists

an idea of the size and

depth of the geological

structures that caused them.

Satellite gravity imaging

uses radar to measure undulations in the sea surface

that reflect density variations in the earth’s upper

crust. This technology

enables mapping of areas of

mass deficit, where sedimentary deposition is likely

to have occurred. Identification of such areas gives

explorers a better idea of

where hydrocarbons may be

located.

Putting it all together 

Exploration companies like

BP Exploration, Exxon,

Mobil, Texaco, Unocal, and

RTX are tailoring their

remote sensing programs to

combine technologies as

needed. Recent advances 

in radar imaging and

sophisticated image-processing packages, combined

with satellite-derived gravity

and bathymetry data, for

example, present new

opportunities to use remote

sensing for deepwater

exploration. Remote sensing

is now considered critical to

such operations. It is also

extraordinarily cost-effective.

Satellites help explore in the Caspian Sea

After water-level changes along the shallow coast of the Republic

of Kazakhstan made their bathymetric maps obsolete, Oryx

Energy and its exploration partner, Exxon, turned to remote 

sensing to gauge depths. Water depth fluctuations caused by 

wind can make movement of seismic and drilling equipment 

challenging. With satellite image processing technology, the team

created new bathymetric maps (e.g., the , square km

Mertvyi Kultuk block, some  km south of the giant Tengiz field)

and used these maps to position a successful new drilling program

in one of the world’s most productive oil exploration areas.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Edith C. Allison

(202) 586-1023

edith.allison@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

Russia

Azerbaijan

Iran

Turkmenistan

Kazakhstan

Caspian

Sea
Interpretation of formations hidden under layers of salt

allows more accurate siting of new reserves

E XPLORATION

4

E XPLORATION

Now that most easily

accessible domestic

resources have been discovered, oil and gas

explorers are investigating

the promising but more

inaccessible resources

beneath saltsheet formations in the Gulf of

Mexico. Large, irregular

saltsheets may cover 60

percent of the slope

beneath the Outer

Continental Shelf in the

Gulf and are found

throughout the world.

Advances in 3-D imaging

technologies are crucial to

providing reliable images

of what lies below the

thick layers. A 3-D

prestack depth migration

method of seismic data

processing and an advanced

marine magnetotellurics

technique are now making

it possible to image the

structure and thickness of

subsalt sediments.

Together, these technologies provide sufficient

information to help locate

new oil or gas deposits,

estimated at 15 billion barrels of oil equivalent in the

Gulf of Mexico alone.

Getting under the salt

DEVELOPING IMAGESof subsalt structures

poses a critical challenge to

exploration. Seismic imaging

is based on the transmission

of sound waves and analysis

of the energy that is bounced

back. But large amounts of

energy are lost when sound

waves pass through salt; thus,

an extremely strong seismic

source is required. Often seismic data are incomplete, preventing explorers from

obtaining accurate readings of

a structure’s shape and thickness. Traditional imaging

methods cannot deliver accurate readings when seismic

sources are blocked by salt

squeezed into sheets between

sediment layers from an

underlying salt base. The oil

and gas sandwiched between

the salt layers can only be

imaged by a combination of

advanced seismic source technology, complex mathematical modeling simulations, and

improved data processing and

imaging techniques. DOE’s

public/private Natural Gas and

Oil Technology Partnership

has helped develop several

such technologies, among

them improvements to the

speed and reliability of -D

prestack depth migration,

which creates a coherent image

by processing as many as 

million records.

Using electromagnetic 

resistance

As a part of this DOE partnership, the National

Laboratories and industry are

currently investigating the

feasibility of marine magnetotellurics, which is ideal for

subsalt exploration since it is

based on electrical resistance.

Because salt’s resistivity is 

 times greater than that of

surrounding sediments, the

contrast between salt and sediment resistance to low-frequency electromagnetic radiation from the earth’s ionosphere makes it easier to map

the extent and thickness of

salt structures.

Stealth imaging breakthrough

The latest technology used 

to enhance seismic data is

-D full tensor gradient (FTG)

imaging, originally developed

by the U.S. Navy during the

Cold War for stealth submarines. A -D gradiometer

survey takes real-time measurements of very small

changes in the earth’s gravity

field, each relaying information directly related to mass

and geometry of subsurface

Subsalt Imaging

Locations: Gulf of Mexico, West Africa, and other salt formations

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Increased resource recovery due to better

reservoir characterization

Better, more careful siting of new drilling

operations

Reduced drilling wastes as fewer wells are

drilled

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

More efficient exploration to pinpoint new oil

and gas, reducing the financial risks

Cost-effective exploration: an average 30-image

seismic survey costs $500,000, while an MT survey covering the same area costs about $50,000
E XPLORATION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Edith C. Allison

(202) 586-1023

edith.allison@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Camp, W., and D. McGuire.

Mahogany Field, A Subsalt

Legend: A Tale of Technology,

Timing, and Tenacity. Houston

Geological Society Bulletin,

10/97.

Coburn, G. 3D Full Tensor

Gradient Method Improves

Subsalt Interpretation. Oil & Gas

Journal, 9/14/98.

Cold War Stealth Technology

Can Aid Seismic Interpretation.

Journal of Petroleum

Technology, 1/98.

Earth View Associates. Subsalt

Exploration Methods

Information Brochure.

Hoverston, G., et al.

Magnetotellurics for Petroleum

Exploration. Case for Sea MT.

Minerals Management Service.

Gulf of Mexico OCS Region,

Subsalt Exploration.

Petzet, G. Anadarko Find,

Technology Gains Renew

Subsalt Hopes. Oil & Gas

Journal, 8/17/98.

Prutzman, J., and G. Coburn.

Technology Pinpoints Base of

Salt. The American Oil & Gas

Reporter, 7/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Beneath the Mahogany field salt

Drilling beneath the salt formations of the Gulf of Mexico, an

exploration play spanning , square miles south of the

Louisiana coast, began in the . A decade of unsuccessful

exploration followed, and it took advanced subsalt technologies to

break through the visual block. Nine subsalt discoveries were

drilled in the play from  to , representing a phenomenal

success rate of  percent. The centrally located Mahogany field

(the Gulf’s first commercial subsalt play) was discovered in ,

and four wells were completed by , now flowing at a daily rate

of , barrels of oil and  million cubic feet of gas. Mahogany

field’s total reserves are estimated at  million barrels of oilequivalent, and total recovery from this and the Gulf’s other subsalt discoveries is estimated to be  million energy equivalent

barrels, resources that would have remained inaccessible without

advanced subsalt imaging technology. A new discovery, the

Tanzanite field, is estimated to hold reserves of  million barrels

of oil-equivalent. Due to the size of this discovery, subsalt exploration in the Gulf is likely to remain active. Future subsalt technology advances may be the key to discovering other large untapped

fields. As technology progresses, so will resource recovery.

geological bodies. FTG provides the depth and shape

of almost any geological

structure, independent of

seismic velocities, allowing

geoscientists to develop

more complete images of

complex salt formations.

Two field tests have 

demonstrated a significantly

improved view of the Gulf’s

subsalt geology, and FTG

promises to be an affordable

tool with which to enhance

existing -D seismic imaging

technology in salt formations around the world.

© SPE, 1993

United States

Gulf of

Mexico
In widespread use in Canada, a stimulation technique

now successfully demonstrated in the U.S. has outstanding

results without formation damage

D RILLING AND

C OMPLETION

5

D RILLING AND C OMPLETION

Fracturing has been widely

used since the 1970s to

increase production from formations with low permeability

or wellbore damage. Unlike

conventional hydraulic and

acid fracturing techniques,

CO2-sand fracturing stimulates the flow of hydrocarbons without the risk of formation damage and without

producing wastes for disposal. A mixture of sand proppants and liquid CO2 is forced

downhole, where it creates

and enlarges fractures. Then

the CO2 vaporizes, leaving

only the sand to hold the

fracture open—no liquids,

gels, or chemicals are used

that could create waste or

damage the reservoir. Any

reservoir that is watersensitive or susceptible to

damage from invading fluids,

gels, or surfactants is a candidate. The process has had

widespread commercial

success in Canada, and

recent DOE-sponsored field

tests have demonstrated

commercial feasibility in the

United States.

Using CO2 to fracture

oil and gas reservoirs

RECOMPLETING ANDfracturing an existing oil

or gas well to stimulate production that has declined over time

is significantly less costly than

drilling a new well. First used in

the mid-, fracturing treatments inject fluids under high

pressure into the formation,

creating new fractures and

enlarging existing ones.

“Proppants” (usually largegrained sand or glass pellets) are

added to the fluid to support

the open fractures, enabling

hydrocarbons to flow more

freely to the wellbore.

Fracturing is widely used to

stimulate production in

declining wells and to initiate

production in certain 

unconventional settings.

More than one million fracturing treatments were performed by , and about 

to  percent of existing wells

are hydraulically fractured at

least once in their lifetime.

More than eight billion barrels of additional oil reserves

have been recovered through

this process in North America

alone. Yet conventional fracturing technology has drawbacks. The water- or oil-based

fluids, foams, and acids used

in traditional fracturing

approaches can damage the

formation—for instance, by

causing clay in the shale to

swell—eventually plugging

the formation and restricting

the flow of hydrocarbons.

Conventional fracturing also

produces wastes requiring 

disposal.

An advanced CO2-sand fracturing technology overcomes

these problems, and is proving a cost-effective process for

stimulating oil and gas production. First used in  by

a Canadian firm, the process

blends proppants with 

percent liquid CO2 in a

closed-system-pressurized vessel at a temperature of °F

and a pressure of  psi.

Nitrogen gas is used to force

the resulting mixture through

the blender to the suction

area of the hydraulic fracture

pumping units and then

downhole, where it creates

and enlarges fractures. The

CO2 used in the process

CO2-Sand Fracturing

Locations: Canada (commercial) and United States (demonstration only)

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Using liquid CO2 creates long, propped fractures without formation damage

No wastes requiring disposal are created

Conventional fracturing gels and chemicals,

which may damage the flow path between

wellbore and formation, are not used

Groundwater resources are protected

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Eliminates hauling, disposal, and maintenance

costs of water-based systems

Can significantly increase well productivity and

ultimate recovery

CO2 vaporization leads to fast cleanup, whereas

water-based fluids sometimes clean up slowly,

reducing cash flow

Recovery of valuable oil and gas is optimized
D RILLING AND C OMPLETION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Arnold, D. Dry Frac Damage

Control. PTTC Network News,

2nd Quarter 1997.

Arnold, D. Liquid CO2 and Sand:

An Alternative to Water-Based

Stimulation Fluids. Hart’s

Petroleum Engineer

International, 1/98.

DOE, Office of Fossil Energy.

Fracturing Gas/Oil Formations

with “Reservoir Friendly”

Carbon Dioxide and Sand.

Investments in Fossil Energy

Technology.

Petroleum Technology Transfer

Council. Needed: Demonstration

Sites for New Stimulation

Process. PTTC Network News,

2nd Quarter 1997.

Raymond, Johnson, et al. CO2

Energized and Remedial 100%

CO2 Treatments Improve

Productivity in Wolfcamp

Intervals. Val Verde Basin, 

West Texas, SPE 39778, 1998.

Yost II, Mazza, and Remington II.

Analysis of Production Response

to CO2/Sand Fracturing: A Case

Study. SPE 29191, 1994.

1995 National Assessment of

United States Oil and Gas

Resources. USGS Circular 1118,

U.S. Government Printing Office.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Increased Gas Production per Well

Results of fracturing technique tests

in Devonian Shales wells after 

37 months

0% 600%

CO2-Sand vs.

Nitrogen Gas

(no proppant)

CO2-Sand vs.

Nitrogen Foam

(with proppant)

400 %

200%

vaporizes, leaving behind a

dry, damage-free proppant

pack. The technology has

gained widespread commercial acceptance in Canada,

where it has been used some

, times. In the United

States, use has been limited

to demonstrations—many

sponsored and cofunded by

DOE—taking place over

the last two years in about

 wells in Kentucky, Ohio,

Pennsylvania, Tennessee,

Texas, New York, Colorado,

and New Mexico.

CO2-sand fracturing treatments average from ,

to ,, depending on

well depth and rock stresses.

While often higher-cost

than conventional methods,

these costs are offset by savings realized through eliminating both swab rigs and

the hauling, disposal, and

maintenance costs associated with water-based systems. As in conventional

fracturing, CO2-sand treatments can significantly

increase a formation’s production and profitability.

METRICS

Source: Arnold, Hart’s Petroleum Engineer International, January 1998

Successful DOE-sponsored field tests

The U.S. Geological Survey estimates that  to  trillion

cubic feet of natural gas resources exists in unconventional settings in the United States. Developing cost-effective advanced

fracturing techniques is crucial in our quest to recover these

resources. A number of field-test fracturing projects sponsored by

DOE recently evaluated and proved CO2-sand technology’s effectiveness in gas recovery. In the Devonian Shales in Kentucky, four

of  gas wells were stimulated with CO2-sand mixture, seven

with nitrogen gas and no proppant, and four with nitrogen foam

and proppant. After  producing months, wells stimulated with

the CO2-sand process had produced four times as much as those

treated with foam, and twice as much as those stimulated with

nitrogen gas. In central Pennsylvania, three gas wells were stimulated using CO2-sand fracturing. Immediately after fracturing,

two of the wells exhibited production increases of , percent

and  percent. Over a year and a half later, production from

the wells had increased  percent,  percent, and  percent, respectively.

■ Major areas of oil

and gas potential
Successively better coiled tubing technologies drive 

improvements in cost, productivity, and efficiency of 

drilling operations, while reducing environmental impact

D RILLING AND

C OMPLETION

6

D RILLING AND C OMPLETION

Continuous coiled tubing

can dramatically increase

the efficiency, profitability,

and productivity of drilling

for oil and gas. Whereas in

conventional drilling operations, the drilling pipe

consists of several jointed

pieces requiring multiple

reconnections, a more

flexible, longer coiled pipe

string allows uninterrupted

operations. A cost-effective alternative for drilling

in reentry, underbalanced,

and highly deviated wells,

coiled tubing technology

minimizes environmental

impacts with its small

footprint, reduced mud

requirements, and quieter

operation. Quick rig setup, extended reach in horizontal sidetracking, onetime installation, and

reduced crews cut operating costs significantly. For

multilateral and slimhole

reentry operations, coiled

tubing provides the opportunity for extremely

profitable synergies.

A strong portfolio of benefits

P ARTICULARLY VALUable in sensitive environments such as Alaska’s North

Slope, coiled tubing technology has far less impact on a

drilling site than conventional

equipment, in addition to

performing drilling operations more efficiently and

cost-effectively. Although the

first coiled tubing units were

built in the , only after

rapid technological advances

in the late  did the technology start to gain industrywide recognition. From 

operating units in , usage

has grown to some  units

in , and many drilling

companies are now revising

their rig portfolios.

In a variety of drilling applications, coiled tubing eliminates the costs of continuous

jointing, reinstallation, and

removal of drilling pipes. It is

a key technology for slimhole

drilling, where the combination can result in significantly

lower drilling costs—a typical

,-foot well drilled in

southwest Wyoming costs

about ,, but with

coiled tubing and slimhole,

the same well would cost

, less.

Reduced working space—

about half of what is required

for a conventional unit—is an

important benefit, as are

reduced fuel consumption and

emissions. A significant drop in

noise levels is also beneficial in

most locations. The noise level

at a ,-foot radius is  

decibels, while at the same

radius a conventional rig has a

-decibel level.

Coiled Tubing

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced mud volumes and drilling waste

Cleaner operations, as no connections to leak mud

Reduced operations noise

Minimized equipment footprints and easier site

restoration

Reduced fuel consumption and emissions 

Less visual impact at site and less disturbance,

due to speedy rig set-up

Reduced risk of soil contamination, due to

increased well control

Better wellbore control

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased profits, in certain cases, from 24-hour

rig set-up and faster drilling

Smaller drilling infrastructure and more

stable wells

No interruptions necessary to make connections

or to pull production tubing

Reduced waste disposal costs

Reduced fuel consumption

Increased life and performance from new rig

designs and advanced tubulars, reducing

operating costs
D RILLING AND C OMPLETION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Adams, L., and C. Overstreet.

Coiled Tubing Facilitates Deep

Underbalanced Workover. Oil &

Gas Journal, 3/31/97.

Berning, Isennock, and Coats.

Composites Extend CT’s

Applications. The American Oil

& Gas Reporter, 9/98.

Electric Coiled-Tubing Drilling.

Journal of Petroleum

Technology, 9/98.

Faure, A., and J. Simmons.

Coiled Tubing Drilling: A Means

to Minimize Environmental

Impact. SPE Paper 27156, 1994.

Furlow, W., Lake Maracaibo’s

Depleted Fields Continue to

Produce. Offshore Magazine,

9/1/98.

Kunkel, B. Benefits Fuel CT

Growth. Hart’s Petroleum

Engineer International, 7/97.

Newman, K. Coiled Tubing

Technology Continues Its Rapid

Growth. World Oil, 1/98.

Schutz, R., and H. Watkins.

Titanium Alloys Extend

Capabilities of Specialty

Tubulars Arsenal. The American

Oil & Gas Reporter, 9/98.

Strunk, C. Slim Hole, Coiled

Tubing Combine to Enhance

Well Economics. The American

Oil & Gas Reporter, 2/97.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

METRICS

Field trials in the Netherlands

demonstrate environmental benefits

Fuel Consumption and Gas Emissions:

Coiled Tubing vs. Conventional Rigs

Med Land Coiled Tubing

Workover Drilling Drilling

Rig Rig Unit

Diesel m3/month 35 160 25

Gas CO2 3,293 15,055 2,122

Emissions CO 3.7 16.8 2.5

kg/day NOx 4.6 21 2.1

HC 3.9 17.8 2.8

HC (Gas) 1.8 8.4 1.1

SO2 4.2 19.4 2.2

180

160

140

120

100

80

60

40

20

Conductor Tophole

Intermediate Reservoir

Completion

Conventional Coiled Tubing

Conventional drilling fluids volume compared with coiled tubing volumes (m3)

At Lake Maracaibo field

Advanced coiled tubing drilling is helping operators optimize

resource recovery at Venezuela’s Lake Maracaibo field. Baker

Hughes INTEQ’s first-of-its kind Galileo II hybrid drilling barge,

containing ⁄

-inch coiled tubing and slimhole drilling measurement-while-drilling tools, drilled its first well at the end of .

It was the first time an underbalanced well had been drilled on

Lake Maracaibo, and it promises good results. Galileo II’s unique

design is also expected to significantly increase the life of its coiled

tubing, ultimately reducing operating costs. Operating in a fragile

lake ecosystem presents unique waste management challenges,

and all drill cuttings and waste mud are transported back to shore

for disposal.

Technology advances 

in the ’90s

Dramatic advances have

recently brought new coiled

tubing technology to market. For example, new

designs from leading

drilling service companies

have eliminated coiled 

tubing rigs’ guide arches; in

these new designs, eliminating the bending in the tubing at the guide arch has

significantly increased its

life. The newest advance is

an electric bottomhole

assembly offering immediate data feedback on bottomhole conditions,

reduced coiled tubing

fatigue, maintenance of bit

speed independent of flow

rate, and improved reliability. New materials like

advanced titanium alloys

and advanced metal-free

composites have improved

the reliability, performance,

corrosion-resistance, weight,

and cost-effectiveness of

coiled tubing assemblies. In

certain cases, titanium tubing offers an estimated reeling cycle life  to  times

greater than steel. ©SPE 27156, 1994

Photo: WZI, Inc.
Without any increase in environmental impact, horizontal

drilling allows developers to reach reserves beyond the

limits of conventional techniques

D RILLING AND

C OMPLETION

7

D RILLING AND C OMPLETION

Horizontal drilling targets

oil or gas in thin, tight

reservoirs, reservoirs inaccessible by vertical drilling,

and reservoirs where horizontal wellbores significantly increase flow rates

and recovery. Horizontal

wells maximize utilization

of drilling sites and infrastructure. While vertical

wells drain oil from a single hole and have limited

contact with oil-bearing

rock, horizontal wells penetrate a greater crosssection of the formation,

allowing substantially

more oil to drain. A horizontal well is drilled laterally from a vertical wellbore at an angle between

70° and 110°. It can tap the

hydrocarbon supplies of a

formation without further

environmental disturbance, of particular value

in sensitive areas.

Breaking geologic barriers

T HE CURRENT BOOMin horizontal drilling is

due to rapid developments in

technology over the past two

decades. Although several

horizontal wells were successfully drilled between the 

and , these were limited

to expensive - to -foot

forays. Interest waned in such

onshore applications after the

development of hydraulic

fracturing technology made

vertical wells more productive.

The offshore industry continued to pursue horizontal

drilling, but the limitations of

the available equipment often

resulted in ineffective, expensive, and time-consuming

drilling operations. 

In the mid-, several significant technology advances

started breaking down these

barriers. Steerable downhole

motor assemblies, measurement-while-drilling (MWD)

tools, and improvements in

radial drilling technologies

were the breakthroughs needed to make horizontal drilling

feasible. Short-radius technology had been developed in the

, the earliest curvature

technique used to drill laterals;

in the , long-radius technology allowed lateral displacement away from the rig

to penetrate the reservoir.

Then, in the , mediumradius techniques permitted

re-drilling horizontal intervals

from existing wellbores, and

with this advance producers

could build rapidly to a 

° angle. Today, horizontal

wells are being drilled longer

and deeper, in more hostile

environments than ever before.

Horizontal drilling is now

conventional in some areas

and an important component

of enhanced recovery projects. At any given time, horizontal drilling accounts for 

to  percent of the U.S. land

well count. The Austin Chalk

field has been the site of over

 percent of the onshore

horizontal rig count since the

late , and still accounts

for the majority of horizontal

permits and rig activity in the

U.S. today. Thirty percent of

all U.S. reserves are in carbonate formations, and it is

here that  percent of horizontal wells are drilled.

Horizontal Drilling

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Less impact in environmentally sensitive areas

Fewer wells needed to achieve desired level of

reserve additions

More effective drilling means less produced water 

Less drilling waste

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased recoverable hydrocarbons from a

formation, often permitting revitalization of

previously marginal or mature fields

More cost-effective drilling operations

Less produced water requiring disposal and less

waste requiring disposal

Increased well productivity and ultimate recovery
D RILLING AND C OMPLETION

CONTACT

Cooper, S., and R. Cuthbertson.

Horizontal, Underbalanced Wells

Yield High Rates in Colombia.

World Oil, 9/98.

Department of Energy. Using

Horizontal Drilling to Give a

Michigan Oilfield New Life.

Deskin, W. et al. Survey Shows

Successes, Failures of Horizontal

Wells. Oil & Gas Journal, 6/19/95.

Gas Research Institute.

Measuring the Impact of

Technology Advances in the

Gulf of Mexico. 

Horizontal Well Successfully

Drilled in Black Warrior Basin.

Oil & Gas Journal, 7/22/96.

Knoll, R. Buzzwords Can Lead to

Poor Results. The American Oil

& Gas Reporter, 9/98.

Mason, R. Horizontal Drilling

Broadening Mindset, Opening

New Possibilities. The American

Oil & Gas Reporter, 9/98.

Natural Petroleum Council. The

Potential for Natural Gas in the

United States, 12/92.

Philips, C., and D. Clarke. 3D

Modeling/Visualization Guides

Horizontal Well Program in

Wilmington Field. Journal of

Canadian Petroleum

Technology, 10/98.

Potter, N. 3D, Horizontal Drilling

Changing Clair Development

Economics. Offshore Magazine,

5/1/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

of , barrels. Success has spawned the drilling of nine other

horizontal wells here, and nearly  others in geologically similar

fields in the basin. If successful in other depleted Dundee fields,

horizontal wells could produce an additional  to  million

barrels of oil, worth about  million in tax revenues alone.

In the United States, according to a recent

DOE study, horizontal drilling has improved:

Potential reserve additions—by an estimated 10 billion barrels of oil equivalent,

nearly 2% of original oil-in-place

The average production ratio—now 3.2:1 for horizontal compared to vertical

drilling based on field data, even though the average cost ratio is 2:1

Carbonate numbers are even better—production is nearly 400% greater than vertical wells, yet costs are only 80% more

Worldwide Horizontal Wells

3,000

2,500

2,250

2,000

1,750

2,750

1,500

1,250

Pre19881988 1990 1991 1989 1992 1993 1994 1995 1996

1,000

500

250

750

0

Number of Horizontal Wells

Success in the Black Warrior Basin

In , after six years of production, the Goodwin gas field in the

Black Warrior Basin was converted to gas storage by the Mississippi

Valley Gas Co. Only conventional vertical wells had been drilled

in the thin ( feet), tight, abrasive formation. The operator 

successfully drilled and completed the first horizontal well in only

 days, utilizing MWD and gamma ray tools, a short radius

motor, and a polycrystalline diamond bit. Overall costs approached

twice that of a conventional well in the field, but the deliverability

of the horizontal well was six times that of a vertical well. Since one

horizontal well is producing the equivalent of six vertical wells,

maintenance and operating costs are lower, and fewer meter runs,

flowlines, and other facilities are required. 

New reserves in the Dundee Formation

Only  percent of the known oil located in the Michigan Basin’s

Dundee Formation had been produced when a DOE co-sponsored

horizontal drilling project brought new life to the formation’s

exhausted Crystal field. The new horizontal well now produces

nearly  times more than the best conventional well in its field—

 barrels of oil a day—and boasts estimated recoverable reserves

METRICS

Source: U.S. Department of Energy and Maurer Engineering, Inc., 1995

Source: Oil & Gas Journal, November 23, 1998

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

■ Major areas of oil

and gas potential
Assisting operators to bring new life to mature fields

and make unconventional fields commercially viable

D RILLING AND

C OMPLETION

8

D RILLING AND C OMPLETION

Routinely applied to over

half of U.S. gas wells and

a third of oil wells,

hydraulic fracturing has

been proven to enhance

well performance, minimize drilling, and recover

otherwise inaccessible

resources. It makes the

development of some lowpermeability, tight formations and unconventional

resources economically

feasible. When the flow of

hydrocarbons is restricted

by formation characteristics, injecting pressurized

fluids and solid additives

can stimulate wells to

increase production. Fluids

are pumped into the formation at pressure great

enough to fracture the

surrounding rock. A proppant slurry follows, biodegrading to sand proppant

that holds the fractures

open, allowing free passage of fluids to the wellhead. So successful has

this technology been that

the industry currently

spends a billion dollars

annually on hydraulic

fracturing.

Stimulating wells

to deliver more

FIRST INTRODUCED IN, hydraulic fracturing

quickly became the most

commonly used technique to

stimulate oil and gas wells,

ultimately enabling production of an additional eight

billion barrels of North

American oil reserves that

would otherwise have been

unrecovered. By , fracturing

had already been applied

nearly a million times. Each

year, approximately ,

gas and oil wells are hydraulically fractured. 

Fracturing is generally used to

regain productivity after the

first flow of resources diminishes. It is also applied to initiate the production process

in unconventional formations, such as coalbed

methane, tight gas sands, and

shale deposits. Improvements

in fracturing design and quality control have enabled operators to successfully apply

fracturing techniques in more

complex reservoirs, hostile

environments, and other

unique production settings.

New advances

The DOE-led Natural 

Gas and Oil Technology

Partnership has promoted

many of this decade’s fracturing advances. These include

the use of air, underbalanced

drilling, and new fracturing

fluids to reduce formation

damage and speed well cleanup. Improved log interpretation has improved identification of productive pay zones.

Improved borehole tools help

map microseismic events and

predict the direction and

shape of fractures. New -D

fracture simulators with

revised designs and real-time

feedback capabilities improve

prediction of results. 

Advanced breakers and

enzymes that minimize the

risk of formation plugging

from large-volume hydraulic

stimulations are the latest

advances to protect the environment and increase ultimate

recovery. In addition, emerging technologies developed by

DOE and the Gas Research

Institute, such as microseismic

fracture mapping and downhole tiltmeter fracture mapping, offer the promise of

more effective fracture diagnostics and greater ultimate

resource recovery.

Hydraulic Fracturing

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Optimized recovery of valuable oil and

gas resources

Protection of groundwater resources

Fewer wells drilled, resulting in less waste 

requiring disposal

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased well productivity and ultimate recovery

Significant additions to recoverable reserves

Greatly facilitated production from marginal

and mature fields
D RILLING AND C OMPLETION

CONTACT

The CER Corporation. Using the

Rifle, CO, Test Site to Improve

Fracturing Technology,

apollo.osti.gov/html/fe/cer.html

Diffusion of Advanced

Stimulation Technology in the

Petroleum Industry: A Case

History. Journal of Petroleum

Technology, 3/98.

Dual-Hydraulic-Fracturing

Technique Minimizes Proppant

Convection and Increases

Hydrocarbon Production. Journal

of Petroleum Technology, 3/97.

Ellis, R. An Overview of Frac

Packs: A Technical Revolution

(Evolution) Process. Journal of

Petroleum Technology, 1/98.

Jennings, A., Jr. Fracturing

Fluids—Then and Now. Journal

of Petroleum Technology, 7/96.

Longitudinally Fractured

Horizontal Wells Add Value in

Alaska. Journal of Petroleum

Technology, 3/97.

Stewart, Stewart, and Gaona.

Fracturing Alliance Improves

Profitability of Lost Hills Field.

Oil & Gas Journal, 11/21/94.

Swift, T., and P. Mladenka.

Technology Tackles LowPermeability Sand in South

Texas. Oil & Gas Journal,

9/29/97.

Wolhart, S. New Initiatives in

Hydraulic Fracture Diagnostics.

GasTIPS, Fall 1998.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Increased profits from the once

declining Lost Hills field

Refined fracturing methods and improved quality control have

brought increased productivity and profitability to a field that once

resisted development. The Lost Hills field in California contains an

estimated two billion barrels of oil-in-place, but since its discovery

in  it has produced only a fraction of its potential. The field

has very low permeability and it lacks a strong natural fracture network, which restricts the flow of resources. This makes the field difficult to produce at acceptable rates without fracture stimulation.

Although hydraulic fracturing began in Lost Hills during the

’ and ’, completion results were poor because of small proppant volumes and inefficient fracture fluids. Between  and

, Chevron initiated massive hydraulic fracture stimulation.

Although productivity increased significantly, costs were high and

the work was not as profitable as anticipated.

In , Chevron and Schlumberger Dowell formed a partnership aimed at improving fracturing efficiency, reducing costs,

and increasing productivity. One result is that multiple wells are

now stimulated from fixed equipment locations. Since its 

implementation in late , this central site strategy has been

used to fracture more than  wells, using some  million

pounds of proppant. The strategy has lowered costs by reducing

personnel, well completion time, and equipment mobilization,

while improving environmental management and safety 

controls. Along with fracture design changes, this has reduced 

overall fracturing costs by  percent since . These efforts

played a large part in the field’s  percent production increase

between  and —from , barrels to more than

, barrels of oil per day. 

©SPE, 1993

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

■ Major areas of oil

and gas potential
High-tech tools that deliver real-time bottomhole data

prevent excessive formation damage and make drilling

significantly more precise and cost-effective

D RILLING AND

C OMPLETION

9

D RILLING AND C OMPLETION

Measurement-while-drilling

(MWD) systems measure

downhole and formation

parameters to allow more

efficient, safer, and more

accurate drilling. These

measurements can otherwise be obtained only by

extrapolation from surface

measurements. MWD systems calculate and transmit

real-time data from the drill

bit to the surface, avoiding

the time-lag between

occurrence and surface

assessment and significantly

improving drilling safety

and efficiency. Without this

analysis of bottomhole conditions, it is sometimes

necessary to abandon a

hole for a new start. MWD

reduces both costs and

environmental impacts

because measurements and

formation evaluation occur

before formation damage,

alteration, or fluid displacement have occurred. Of particular use in navigating

hostile drilling environments, MWD is most frequently used in expensive

exploratory wells, and in

offshore, horizontal, and

highly deviated wells.

More information for

better drilling

M WD TECHNOLOGYis critical as operators

seek to reach deeper and farther for new hydrocarbon

resources. A real-time bit navigation and formation evaluation aid, MWD uses tools

such as triaxial magnetometers, accelerometers, and pressure sensors to provide vital

downhole data concerning

directional measurements,

pore pressures, porosity, and

vibration. This provides for

more effective geosteering

and trajectory control, and

safer rig operations. Novel

equipment transmits bottomhole information to the surface by encoding data as a

series of pressure pulses in the

wellbore’s mud column or by

electromagnetic telemetry.

Surface sensors and computer

systems then decode the

transmitted information and

present it as real-time data.

In normal drilling environments, MWD is used to keep

the drill bit on course. MWD

is also valuable in more challenging drilling environments,

including underbalanced,

extended-reach, deviated, and

high-pressure, high-temperature drilling. In underbalanced directional drilling,

MWD monitors the use of

gas injected to maintain safe

operating pressure. In deviated and horizontal wells,

MWD can be used to geologically steer the well for maximum exposure in the reservoir’s most productive zones. 

Evaluating the formation

Prior to the spread of MWD

systems in the late ’, bottomhole conditions were

monitored by time-consuming analysis of cuttings and

gas intrusion, and by afterthe-fact wireline steering measurement that necessitated frequent interruptions for pipe

removal. Today, the continuous flow of MWD information improves formation 

evaluation efforts as well as

drilling progress. Over successive periods, MWD data can

reveal dynamic invasion

effects, yielding information

on hydrocarbon mobility, gasoil-water contact points, and

formation porosity. Future

advances in MWD technology,

such as MWD acousticalipers

with digital signal processing

Measurement-While-Drilling

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Less formation damage

Reduced possibility of well blowouts and

improved overall rig safety

Reduced volume of drilling waste as fewer

wells drilled overall

Better wellbore control

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Improved drilling efficiency and accuracy

Timely formation evaluation

Reduced operating costs and financial risks

Improved rig safety
D RILLING AND C OMPLETION

CONTACT

Duey, R. Maximizing While

Drilling. Hart’s Oil and Gas

World, 7/98.

Greenberg, J. Managing Loss-ofControl in Deepwater Drilling.

Oil & Gas Journal, 4/1/98.

Hall, G. Growth in the

Measurement-While-Drilling

Sector Continues. Oil & Gas

Journal, 9/16/91.

Joseph, R. Special Techniques

and Equipment Reduce

Problems. Oil & Gas Journal,

3/27/95.

Kennedy, J. Fundamentals of

Drilling, Technology and

Economics. PennWell Publishing

Co., Tulsa, OK, 1991.

Maranuk, C. Acoustic MWD

Caliper Improves Accuracy with

Digital-Signal Technology. Oil &

Gas Journal, 3/2/98.

Meehan, R., et al. Case Histories

Show Real-Time Information

Reduces Uncertainty. Oil & Gas

Journal, 5/18/98.

Pressure-While-Drilling Data

Improve Drilling Performance.

Journal of Petroleum

Technology, 2/97.

Talkington, K. Remote South

China Sea Reservoir Prompts

Extended Reach Record. Oil &

Gas Journal, 11/10/97.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Extended reach in the South China Sea

In the South China Sea, MWD technology was critical in helping

operators drill a -mile extended-reach well to a then world-record

horizontal displacement of nearly , feet, at a true vertical

depth of approximately , feet. It effectively “steered” the

well to access the most productive zones at a final hole angle of

°. In combination with other advanced drilling and completion

technologies, MWD technology permitted operators to access this

otherwise uneconomical, remote offshore field, completing the

project in approximately  days at a cost of  million. As of

June , this once-bypassed field was producing , barrels 

of oil per day.

and DOE-sponsored

research into ultra-deepwater MWD technologies,

promise to enhance operations even further.

Contributing dramatically to

operational safety

Operators seeking to control drilling operations and

enhance rig safety in difficult environments such as

deepwater drilling find

MWD a valuable tool. In

combination with advanced

interpretive software applications, MWD is helping

deepwater operators better

forecast and measure a formation’s pore and fracture

pressures. More accurate

geopressure estimates can

prevent dangerous well

blowouts and fires. In the

unlikely event of a deepwater blowout, MWD

equipment is a crucial tool

in assisting operators to drill

and steer a relief well to

regain control of the well.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

China

Vietnam

Philippines

Taiwan

South China Sea

©SPE, 1993
Evolving bit technology allows operators to drill wellbores

more quickly and with less environmental impact

D RILLING AND

C OMPLETION

bl

D RILLING AND C OMPLETION

Dramatic advances in drill

bit technology have

improved drilling performance significantly while

cutting wastes and environmental impacts.

Although the choice of bit

represents only 3 percent

of the cost of well construction, bit performance

indirectly affects up to 75

percent of total well cost.

Faster rates of penetration

and greatly extended bit

life, the result of advances

in materials technology,

hydraulic efficiency, cutter

design, and bit stability,

now allow wells to be

drilled more quickly, more

profitably, and with less

environmental impact. The

improvement to an operator’s cost-efficiency from

these advances is striking.

Today, selection of the

appropriate bit has

become critical both in

establishing the overall

economics of field development and in minimizing

the environmental impacts

of drilling.

The diamond success story

F ROM USE IN ONEpercent of total worldwide drilling in , to an

estimated  percent in ,

diamond drill bits, which use

cutters consisting of a thick

layer of tungsten carbide permeated with bonded diamond particles, have been

one of the success stories of

the last  years. Natural diamonds, synthetic diamonds,

and diamond composites are

now routinely used within

insert-bit cutting structures,

and, although originally

developed for hard formations, polycrystalline diamond compact (PDC) bits

have proved their value in

soft- and medium-hard formations too. Today, PDC bits

are most applicable in areas

with relatively soft formations

or where drilling is expensive,

such as offshore locations and

remote wells. In parallel with

PDC development, roller

cone bits have also been

improved. The

National Petroleum

Council estimates

that improvements

in drilling efficiency

from advances such

as those in bit technology have reduced

underlying drilling

costs by about 

3 percent annually

over the last  years. As

materials technology,

hydraulics, and bit stability

continue to improve, so will

drilling performance and environmental protection.

Matching the bit to the

formation

By helping operators choose

the best bit for the job, 

computerized drill bit optimization systems have

improved the way bits are

being selected and used.

These systems match an individual formation to the most

effective milled-tooth, tungsten carbide insert and PDC

bit to complete the job for the

least cost per foot. They also

prescribe other design parameters such as hole gauge and

hydraulic requirements to

help determine optimal 

cutting structure.

Modern Drilling Bits

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced power use and resultant emissions 

Less drilling waste 

Reduced equipment mobilization and fewer rigs

Less noise pollution

Better wellbore control and less formation

damage

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased rates of penetration

Fewer drilling trips due to greater bit life

Reduced power consumption 

Improved drilling efficiency and hence viability

of marginal resources

Carbide substrate

Carbide

substrate

PDC layer

PDC layer

Carbide cylinder

Carbide stub

PDC wafer

Braze joint

PDC Cutter Components

Source: Petroleum Engineer International, 1993
D RILLING AND C OMPLETION

CONTACT

Bit Design Key to Improved

Performance. Journal of

Petroleum Technology, 12/96.

Diamond Enhanced Inserts

Improve Roller-Cone Bits.

Journal of Petroleum

Technology, 2/97.

Drill-Bit Solutions for

Operational Constraints. Journal

of Petroleum Technology, 12/97.

Lee, M. New Bits Drill Faster,

Cheaper, Better. The American

Oil & Gas Reporter, 4/98.

Locke, S. Advances Reduce Total

Drilling Costs. The American Oil

& Gas Reporter, 7/98.

Mensa-Wilmot, G. New PDC

Cutters Improve Drilling

Efficiency. Oil & Gas Journal,

10/27/97.

New Polycrystalline-DiamondCompact-Bit Technology Proves

Cost-Effective. Journal of

Petroleum Technology, 12/97.

Rappold, K. Industry Pushes Use

of PDC Bits to Speed Drilling,

Cut Costs. Oil & Gas Journal,

8/14/95.

The Role of Bit Performance in

Drilling Efficiency. Supplement

to Petroleum Engineer

International.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Switching to new drill bits saves time and money

Using a specialized bit optimization system, Anadarko Petroleum

has demonstrated significant efficiency improvements. For example, drilling time was reduced by  to  days in Algeria, with savings of , to ,; and a Mississippi project saved 

days and ,. Ultimately, impacts on the environment were

appreciably lessened.

Petroleum Development Oman found that rates of penetration

dropped from  feet per hour to under  feet per hour when drills

using tungsten carbide inserts hit the hard Khuff Formation.

Switching to a new generation PDC bit with carbide-supported edge

cutters resulted in a new rate of . feet per hour in the Khuff. The

entire section was drilled in one run, at half the cost of the same section in a similar well. Another well drilled in the comparable

Zauliayah field resulted in a rate of  feet per hour at a cost of 

per foot, nearly half the cost of drilling a comparable well in the area

with an earlier-generation bit.

When Chevron switched to new generation polycrystalline bits at its

Arrowhead Greyburg field in New Mexico, the rate of penetration

increased more than  percent. Chevron had been experiencing

problems using -cone bits and thermally stabilized diamond bits.

Switching to PDC bits with curved cutters significantly increased

drilling efficiency, while reducing environmental impacts.

Increases in diamond bit drilling

In 1978, approximately 1 percent of the total footage drilled worldwide was drilled

with diamond bits; in 1985, it was approximately 10 percent; by 1997, that figure

was an estimated 25 percent. Also, between 1988 and 1994, advances in PDC

technology increased the average footage drilled by over 260 percent, from

approximately 1,600 feet to 4,200 feet per PDC bit.

0% 100%

1978

1985

1997

1%

10%

25%

METRICS

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

Source: Rappold, Oil & Gas Journal, 8/14/95

Indian Ocean

Arabian Sea

Somalia

Gulf of Aden

Yemen

Iran Pakistan

India

U.A.E.

Persian

Gulf Gulf of

Oman

Oman

Saudi

Arabia
New lateral drilling developments provide dramatic returns

for operators, with less waste, smaller footprints, and

increased site protection

D RILLING AND

C OMPLETION

bm

D RILLING AND C OMPLETION

Multilateral drilling 

creates an interconnected

network of separate, pressure-isolated, and reentryaccessible horizontal or

high-angle wellbores surrounding a single major

wellbore, enabling

drainage of multiple target

zones. In many cases, this

approach can be more

effective than simple horizontal drilling in increasing productivity and

enlarging recoverable

reserves. Often multilateral drilling can restore 

economic life to an aging

field. It also reduces

drilling and waste disposal

costs. Today, in a wide

variety of drilling environments, both onshore and

offshore, from the Middle

East to the North Sea 

and from the North Slope

to the Austin Chalk, multilateral completions are 

providing dramatic returns

for operators.

Multilateral Drilling 

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Fewer drilling sites and footprints

Less drilling fluids and cuttings

Protection of sensitive habitats and wildlife

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Improved production per platform

Increased productivity per well and greater ultimate recovery efficiency

New life for marginally economic fields in

danger of abandonment

Reduced drilling and waste disposal costs

Reduced field development costs

Improved reservoir drainage and management

More efficient use of platform, facility, and crew

From horizontal to

multilateral branching

wellbores

HORIZONTAL DRILLing provoked a surge

of interest in the  as a

way to contact more oil

reserves, penetrating a greater

cross-section of the oil-bearing rock with a single wellbore and intersecting repeatedly the fractures that carry

oil to a producing well.

Today, declining production,

flat prices, and heightened

environmental awareness

have led the exploration and

production industry to develop advanced drilling and

completion technologies that 

permit wells to branch out

multilaterally, in certain cases

saving both time and money

compared to horizontal

drilling. In many cases, such

as deep reservoir production,

it is more efficient to create a

connected network than to

drill multiple individual horizontal wellbores.

Multilateral drilling is of

greatest value in reservoirs

that:

• Have small or isolated

accumulations in

multiple zones

• Accumulate oil above the

highest existing perforations

• Have pay zones that are

arranged in lens-shaped

pockets

• Are strongly directional

• Contain distinct sets of

natural fractures

• Are vertically segregated,

with low transmissibility
“[With advanced re-entry

multilateral technology] we

are seeing the potential to

reduce by half the costs

associated with subsea

developments. In some

cases, this will make what

were previously marginal or

non-economic discoveries

economical.”

AL I DANESHY

Vice President, Halliburton

D RILLING AND C OMPLETION

CONTACT

Boone, L., F. Clausen, T.

Birmingham, and N. Schappert.

Horizontal Branches Reach Out

to Drain Reserves: Slim Hole

Laterals Put New Twist on Field

Development. The American Oil

& Gas Reporter, 7/98.

DeLuca, M. Multilateral

Completions on the Verge of

Mainstream. Offshore Magazine,

1/97.

Halliburton Energy Services.

First Subsea Multilateral with

Re-Entry Access. Press Release,

7/21/97.

Halliburton Energy Services.

Multilateral Technology (MLT)

Overview.

Taylor, R.W., and R. Russell.

Multilateral Technologies

Increase Operational Efficiencies

in Middle East. Oil & Gas

Journal, 3/16/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Norsk demonstrates the future

of offshore drilling

A highly successful offshore project in Norway is showcasing the

reduced environmental impacts and increased economic benefits of

multilateral completions. In March , Norsk Hydro a.s. and

Halliburton Energy Services drilled the world’s first subsea multilateral with reentry access in Norsk’s Troll field. The companies estimate that the economic benefits will be  percent greater than

those from fixed platforms. By reducing the systems required to

access the subsea reservoir, the project cuts both costs and impact

on the environment and leads the way for subsequent offshore

drilling operations.

New life for old wells:

pentalateral drilling in the Middle East 

Mounting evidence demonstrates that multilaterial drilling can

bring new life to old wells. In the Arabian Gulf recently, a significant reduction in production that may have spelled well closure in

the past was instead the stimulus to drill five lateral branches into

new pay zones. The lateral wells were drilled in only  days,

reaching some , feet of new producing formations. Since the

new zones consisted of relatively soft limestone layers separated

from each other by dolomites, drilling presented few problems.

Dramatically increased production rates covered costs in just six

days. In all, production increased . times as a result of the multilateral completions.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

North

Sea

United

Kingdom

Netherlands

Germany

Norway

Denmark

Indian Ocean

Arabian Sea

Somalia

Gulf of Aden

Yemen

Iran Pakistan

India

U.A.E.

Persian

Gulf Gulf of

Oman

Oman

Saudi

Arabia
Technology advances in dynamic positioning expand

opportunities for deepwater drilling with reduced

environmental impact

D RILLING AND

C OMPLETION

bn

D RILLING AND C OMPLETION

Recent exploration successes in deepwater plays in the

Gulf of Mexico are of crucial

importance in providing a

vital new domestic

resource. Technological

advances are increasing

operators’ ability to take

advantage of these finds,

while reducing the dangers

and uncertainty inherent in

deepwater operations.

Without such progress,

much of the Gulf’s

resources may remain

undeveloped. A major concern for operators is the

safety of deepwater

exploratory operations,

especially as the industry

moves toward depths of

10,000 feet. To ensure 

stability and efficiency at

such depths, advanced

dynamic positioning 

technology is now being

used. This includes thruster

units and sophisticated

computer and navigation

systems to hold a new 

generation of drillships,

floating production, storage, and offloading systems, and survey vessels on

location without anchors or

mooring lines.

Deepwater opportunities

T HE GULF OF MEXICO’Sdeepwater reservoirs

have become America’s new

frontier for oil and gas exploration. Production potential

from proved and unproved

reserves in deepwater areas is

estimated to be roughly .

billion barrels of oil and .

trillion cubic feet of natural

gas. Consequently, drilling in

the Gulf’s Outer Continental

Shelf has increased greatly

over the last 10 years. Today,

deepwater drilling from permanent structures and wildcat wells is at an all-time

high. In October , a

record  temporary and 

permanent deepwater rigs

were drilling in water depths

greater than , feet, as

compared to only nine in

. 

Production from deepwater

wells is increasing too. In

, for example, less than 

percent of the Gulf’s total oil

production was from deepwater

wells. By , over  percent

of the Gulf’s oil production

came from deepwater wells.

Natural gas production from

deepwater areas in the Gulf

has also increased—from less

than  percent of total production in —to nearly 

percent in .

Improving station keeping

Dynamic positioning systems

compensate for the effects of

wind, waves, and current,

enabling mobile offshore

drilling units to hold position

over the borehole, maintaining within operational limits

lateral loads on the drill stem

and marine riser. Improved

dynamic positioning systems,

in combination with

improved onboard motion

compensation systems, are

expanding the range of water

depths and environmental

conditions within which

drilling operations can be

safely conducted.

Azimuthing thruster units,

often retractable so as to enable

shallow water maneuvers, are

the backbone of the dynamic

positioning system. Ship-based

computers and satellite-linked

navigation units control the

vessel’s rudder, propellers, and

thrusters using input from 

various monitoring systems,

such as gyrocompass wind 

sensors, real-time differential

global positioning systems,

micro-wave positioning 

systems, underwater sonar 

Offshore Drilling

Locations: Deepwater—Gulf of Mexico, West Africa, North Sea, Brazil, others

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Less disruption to seafloor ecosystem

Reduced environmental impacts due to

increased operational stability

Enhanced deepwater operational safety 

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Minimized positioning and transit times for

deepwater exploration 

Reduced operating costs in deepwater exploration operations

Improved access to deepwater and ultra-deepwater resources that might otherwise have

remained undeveloped
D RILLING AND C OMPLETION

CONTACT

Deepwater Drilling Driving

Progress of Azimuthing

Thrusters. Offshore Magazine,

4/98.

Deepwater Surge Galvanizes DP

Power Sector. Offshore

Magazine, 1/97.

DeLuca, M. Dynamic Positioning

Versus Mooring: Debate

Continues as Technology

Evolves. Offshore Magazine,

10/98.

DiSouza, Delepine, and Cordy.

An Approach to the Design and

Selection of a Cost-Effective

Floating Production Storage and

Offloading System. Offshore

Technology Conference (OTC)

7443, 1994.

Duhen, de Bonnafos, and

Rietveldt. A New Generation DP

Drillship for 10,000 ft Water

Depths. Drilling Contractor, 9/98.

Dynamic Positioning, Compact

Power System Create New Life

for Semisubmersible. Oil & Gas

Journal, 10/5/98.

Harding, B. The Deepwater

Drilling Rig Explosion - 1996-

1998: New Designs and

Equipment for Water Depths

Over 3,500 ft. Offshore

Magazine, 7/1/98.

Herold, A. Fourth Generation DP

System Set Up on Pipelay UnitAccuracy of Deepwater Pipeline

Touchdown Product of

Sophisticated Routing

Trajectories. Offshore Magazine,

3/95.

Portable Dynamic Positioning

Systems Fill Special Need.

Offshore Magazine, 7/97.

SOURCES AND ADDITIONAL READING

Steady drilling from dynamic positioning

Today’s advanced dynamic positioning technology enables drillships to maintain station with maximum excursion levels below 1%

of total water depth. At a water depth of 5,000 feet, for example,

these advanced systems are able to keep a 200-yard-long, 30-storyhigh drillship within 50 feet of station.

METRICS

The forces of wind, waves, and ocean currents cause exploration

and drilling support vessels to sway, yaw, and move off course.

To counter this, dynamic positioning technology stabilizes deepwater site equipment, allowing exploratory operations in waters

too deep for conventional mooring systems.

beacons, and hydro-acoustic

beacons. If the wind or tide

swell moves the ship from its

desired station, guided

thrusters can automatically

hold the vessel’s orientation

and position. They can also

move it to a new position in

the event of extreme weather. 

A new equipment market

The trend toward longterm, ultra-deepwater

exploratory operations has

substantially increased

demand for dynamically

positioned vessels. The

harsher environments of

deeper offshore plays has

accelerated demand for

dynamically positioned

drillships, semisubmersible

rigs, seismic survey vessels,

floating production, storage,

and offloading systems,

pipelayers, shuttle tankers,

and standby support vessels.

The benefits of dynamic

positioning include: 

Cost-effectiveness

When permanent or

disconnectable moorings

become excessively difficult

or expensive, or when lowcost fuel is available,

dynamically positioned 

systems may be highly costeffective. Given today’s

technology, it would be

practically impossible to

conduct ultra-deepwater

exploratory operations

without dynamic positioning technology.

Operational flexibility

These systems allow vessels

to move readily from one

location to another during

exploratory operations,

eliminating the cost and

time of setting and removing mooring lines. Such

flexibility, vital during hurricane season, may ultimately

reduce operating costs.

Safety

The precise positioning

afforded by these systems

contributes significantly to

both environmental protection and worker safety during offshore operations. The

safety of operations involving diving support vessels,

deepwater drillships, or

shuttle tankers, for instance,

is often enhanced by the

degree of operational 

precision provided by

dynamic positioning systems.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

©SPE, 1993
Unlike conventional mud-based drilling, air drilling

significantly reduces or eliminates drilling fluid additives 

and prevents formation damage

D RILLING AND

C OMPLETION

bo

D RILLING AND C OMPLETION

Pneumatic drilling is an

underbalanced drilling

technique in which boreholes are drilled using air

or other gases as the circulating agent. In certain

cases this air drilling technique offers the promise

of mudless drilling. By

using nitrogen, air, or

natural gas in place of

oil- or water-based muds,

producers can both eliminate drilling fluids that

need disposal and ensure

that drill cuttings are not

tainted by chemicals or

oil. Although it is suitable

only for certain formation

types and lithologies and

can create potentially

explosive downhole conditions—and is not therefore

likely to become widespread—this technique is

a very attractive environmental prospect, offering

significant operational

benefits.

Protecting low-pressure

formations and maximizing

production

U NDERBALANCEDdrilling offers significant advantages over conventional systems in low-pressure or pressure-depleted formations. Pressure overbalances in conventional

drilling can cause significant

fluid filtrate invasion, and

lost circulation in the formation. Expensive completions,

decreased productivity, and

high mud and mud-removal

costs can then plague drilling

operations, but these can be

avoided by using underbalanced conditions. By lowering downhole pressure using

a noncondensable gas in the

circulating fluid system,

underbalanced pneumatic

drilling can prevent difficulties commonly encountered

when reservoir pressures are

lower than the hydrostatic

pressure exerted by traditional water-based drilling fluids.

Depending on the environment, gas may be used alone

or with water and additives.

When drilling fluid is needed for well control, gas is

mixed with lightweight

drilling fluids. 

In general, pneumatic

drilling is used in mature

fields and formations with

low downhole pressures, in

open-hole completions, and

in fluid-sensitive formations.

It is an important tool in

drilling horizontal wells,

which must expose a large

amount of reservoir face to

be productive, and have

minimum damage from fluids invasion. As horizontal

drilling increases in popularity, underbalanced pneumatic drilling will become more

widespread, because it can

penetrate the reservoir without damaging the formation

or its productive capacity.

Air drilling techniques to suit 

Air dust drilling is a dry

technique that relies on the

annular velocity of air to

Pneumatic Drilling

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Greatly reduced drilling fluids and chemicaltainted cuttings

Decreased power consumption and emissions

Better wellbore control and less damage to

formations

Fewer workover and stimulation operations

needed 

Potential for smaller drilling footprints and less

impact on habitats, wildlife, and cultural

resources

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Substantially less fluid and waste requiring

disposal

Increased rates of penetration and longer 

drill bit life

Indication and evaluation of productive zones

and more effective geosteering of the well by

monitoring flow of produced fluids

Potential elimination of waste pits gives access

to restricted areas
D RILLING AND C OMPLETION

CONTACT

Baker, L. Underbalanced Drilling

with Air Offers Many Pluses. Oil

& Gas Journal, 6/26/95.

Bennion, D. Underbalanced

Operations Offer Pluses and

Minuses. Oil & Gas Journal,

1/1/96.

Carden, R. Air Drilling Has Some

Pluses for Horizontal Wells. Oil

& Gas Journal, 4/8/91.

A Closed Circulating System for

Air Drilling. Journal of

Petroleum Technology, 2/98.

Downey, R. On-Site Generated

Nitrogen Cuts Costs of

Underbalanced Drilling. Oil &

Gas Journal, 2/24/97.

Elrod, J. Horizontal Air Drilling

Increases Gas Recovery in

Depleted Zone. Oil & Gas

Journal, 6/30/97.

LeBlanc, L. Underbalanced

Drilling Solution for Wells with

Long Exposure. Offshore

Magazine, 8/1/95.

Rusnak, J. Apparatus Eliminates

Earthen Pits in Air-Drilling

Operations. Oil & Gas Journal,

8/17/98.

Teichrob, R. Low-Pressure

Reservoir Drilled with Air/N2 in

a Closed System. Oil & Gas

Journal, 3/21/94.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Accessing new supplies in the Carthage field

Selected as the most viable technique to prevent damage to an

extremely low-pressure reservoir, pneumatic drilling made history

as the first air-drilled horizontal well in the Carthage field in

Texas. Air drilling successfully increased gas recovery from 

depleted zones without wellbore skin damage, which would have

restricted the reservoir’s productive flow. Drilled in December

, the Pirkle  well had by the end of April  produced 

 million cubic feet of gas at a rate of . million cubic feet per

day. The well was drilled with compressed nitrogen into the

Cretaceous Frost “A” zone at , feet true vertical depth; it

produces through a ,-foot lateral well with bottomhole 

pressure of  psi. The operation successfully met the economic 

criteria of producer OXY USA Inc., which had determined that

the well’s production rate would have to at least double that of a

standard vertical well to be economically viable.

transport cuttings. It is 

typically employed in

drilling dry formations, or

when any water influx is

low enough to be adsorbed

by the air stream. If excessive water influx precludes

its use, air-mist drilling is

employed instead, using an

air-injected mud that

returns to the surface as

mist. Sometimes foamdrilling is required, using a

stable mixture of water and

compressed air with detergent and chemicals. When

the water influx is too great

to be removed through

mist or foam, aerated mud

drilling, a technique in

which air is injected into

viscosified fluid or mud in

order to reduce the weight

of the fluid column on the

formation, combines the

best properties of conventional and air drilling to

provide an effective solution. 

A new waste management

technology enables operators to eliminate the earthen waste pits used to catch

effluent created while

drilling with an air- or airmist system. Liquids and

solids in the effluent are

separated and treated, and

gases are exhausted. By

eliminating the environmental risks associated with

pits, drillers can operate in

otherwise restricted areas,

such as State parks and

within city limits. Initial

field tests indicate that this

technology can handle continuous liquid volumes of

 barrels per hour and

solid volumes of  barrels

per hour.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

■ Major areas of oil

and gas potential
SUMMARY

Technology advances in less invasive slimhole drilling 

increasingly valuable in exploration and production

D RILLING AND

C OMPLETION

bp

D RILLING AND C OMPLETION

Improved slimhole drilling

technology brings the twin

advantages of environmental protection and economical results to oil and

gas exploration and production. (For example, a

conventional well drilled

with a 12.25-inch bit and a

5-inch drill pipe becomes a

slimhole when using a 

4-inch bit and a 3.7-inch

drill pipe.) Slimhole rigs

are defined as wells in

which at least 90 percent

of the hole has been

drilled with a bit six inches

or less in diameter.

Slimhole rigs not only

boast a far smaller footprint and less waste generation than conventional

operations, they can also

reduce operating costs by

up to 50 percent. The technique is proving a lowcost, efficient tool with

which to explore new

regions, tap undepleted

zones in maturing fields,

and test deeper zones in

existing fields.

Narrow boreholes prove 

highly effective

P OTENTIALLY APPLICABLEto more than  percent

of all wells drilled, slimhole

drilling holds promise for

improving the efficiency and

costs of both exploration and

production. Although the

technique was first used in

the oil and gas industry in the

, its acceptance has been

hampered until recently by

concerns that smaller boreholes would limit stimulation

opportunities, production

rates, and multiple completions.

Advances in technology, 

coupled with a growing

record of success, have 

dispelled these concerns,

making slimhole an increasingly attractive option for

reservoir development. Today,

slimhole drilling is employed

throughout the lower-

States and the Gulf of

Mexico, especially in the

Austin Chalk fields of South

Texas. Globally, slimhole

drilling has been used in a

wide range of onshore and

offshore settings.

As an exploration tool, slimhole drilling for stratigraphic

testing provides geologists

with a clearer picture of the

local geography, refining seismic interpretation. Such 

testing, combined with other

technologies such as continuous coring, yields valuable

information for increasing

success rates in exploration. 

In the production arena,

improved slimhole drilling

offers a viable means of recovering additional reserves from

existing reservoirs, including

economically marginal fields.

Resources in pay zones

bypassed in the original field

development can be costeffectively accessed through

the existing wellbores, thereby

extending the productive life

of the field.

Slimhole Drilling

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

A slimhole rig occupies far less space than a

conventional rig—the entire footprint including

site access can be up to 75 percent smaller

The rig requires far less drilling fluid and produces far fewer cuttings for disposal

Reduced volume and weight of equipment

favors use in sensitive environments, such as

rainforests and wetlands, particularly in 

helicopter-supported campaigns

Better wellbore control

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Smaller drilling crews and less drilling time

mean up to a 50 percent reduction in costs

Slimhole drilling is critical for adding millions of

barrels of oil to the Nation’s reserves

Slimhole is feasible in a wide range of operations and capable of reducing exploration and

development costs around the United States
SOURCES AND ADDITIONAL READING CONTACT

Boone, Clausen, Birmingham,

and Schappert. Horizontal

Branches Reach Out to Drain

Reserves: Slim Hole Laterals

Put New Twist on Field

Development. The American Oil

& Gas Reporter, 7/98.

Dachary, J. and R. Vighetto. Slim

Hole Drilling Proven in Remote

Exploration Project. Oil & Gas

Journal, 6/22/92.

Deliac, Messines, and Thierree.

Mining Technique Finds

Application in Oil Exploration.

Oil & Gas Journal, 6/5/91.

Department of Energy. An

Assessment of the Oil Resource

Base of the United States, 1992.

Gordon, T. The Skinny on

Slimholes. Oil and Gas Investor,

1/93.

Millheim, Prohaska, and

Thompson. Slim Hole Drilling—

Past, Present, Future. SPE 30151,

1995.

SOURCES AND ADDITIONAL READING

D RILLING AND C OMPLETION

Success in the Field

In Wattenberg field

An eight-well field test conducted by HS Resources Inc. in 

 in the Denver-Julesburg Basin’s Wattenberg field successfully

demonstrated that slimhole lateral wells could be drilled from

inside an existing .-inch cased producing vertical well. These

lateral wells with .- and .-inch liners are considered the

first lateral cementing operations of this size liner in the Rocky

Mountain region and the first reported lateral drilling in

Colorado using coiled tubing. The project’s success led HS

Resources to begin additional

slimhole drilling in  and 

is significant for several reasons.

First, this approach allows production of additional reserves

with minimal impact on an

active agricultural area. Second,

it reduces operating costs by

commingling production from

both vertical and lateral 

wellbores.

CASE STUDIES

Standard

Rig

Slimhole

Rig

At the Austin Chalk fields 

More than  horizontal slimhole well reentries have been drilled

by Slim Dril International, demonstrating a successful way to discover and tap otherwise inaccessible reserves of domestic oil. The

company also used slimhole to deepen a conventional well to a

depth of , feet, using mud motors to test a producing field.

This advancing technology is extending the life of wells both at

Austin Chalk in south Texas and in the Gulf of Mexico, and could

potentially add millions of barrels of oil to our Nation’s reserves.

METRICS

Fuel consumption 75% less

• Installed power 1,350 vs. 4,000 kilowatts

• Mud-pump power 330 vs. 3,200 horsepower

Drillsite area 75% smaller

Mud cost 80% less

• Active mud volumes 50 vs. 1,500 barrels

Rig weight 412,000 vs. 3,400,000 pounds

150 vs. 500 helicopter lifts 

12 vs. 65 Hercules loads 

18 vs. 55 truckloads 

Drillstring weight: 37 vs. 150 tons

Drilling crew size Staff of 3 or 4 vs. 6

Camp size Staff of 30 vs. 80

Bottom Line:

Potential well cost-savings of 50%

Source: Nabors Industries .

A Head-to-Head Comparison

At a drilling depth of 14,000 feet, here is how a slimhole rig with a 4-inch diameter performs versus a conventional drilling operation with an 8.5-inch diameter:

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

■ Major areas of oil

and gas potential
New synthetic drilling muds combine the performance 

of oil-based muds with the easier, safer disposal of 

water-based muds

D RILLING AND

C OMPLETION

bq

D RILLING AND C OMPLETION

Drilling fluids are essential

to carry cuttings to the

surface, maintain pressure

balance and stability in the

borehole, lubricate and

clear the drillstring and bit,

and prevent the influx of

other fluids. Today’s

advanced offshore drilling

practices include the use of

synthetic-based muds

(SBMs), which combine the

higher performance of oilbased muds (OBMs) and

the lower toxicity of waterbased muds (WBMs). SBMs

are a high-performance,

environmentally friendly

choice for complex offshore

drilling environments.

Management of fluids and

cutting wastes is a significant responsibility for the

industry, and in remote

offshore areas can entail

significant expense.

Compared with OBMs, drill

cuttings from SBMs can be

safely discharged in many

offshore areas, significantly

reducing disposal costs and

environmental impacts.

Conventional versus

new muds

NEARLY ALL WELLSless than , feet

and  percent of deeper wells

are drilled with water-based

muds (WBMs), making them

the most commonly used

muds both onshore and offshore. With a  percent

water base, WBMs and associated cuttings can typically

be discharged on-site.

However, they are often not

technically feasible or costeffective in complex drilling

situations. As such, oil-based

muds (OBMs) are often the

drilling fluids of choice in

deep, extended-reach, highangle, high-temperature, and

other special drilling environments, greatly outperforming

WBMs. But their diesel or

mineral oil base means that

although they effectively minimize drilling problems,

OBMs cannot be discharged

on-site. At remote offshore

sites, operators must incur the

expense, logistical problems,

and environmental risks of

shipping OBM wastes back

to shore for disposal.

The development of synthetic-based muds (SBMs)

was driven by industry’s need

for a drilling fluid with lower 

Synthetic Drilling Muds

Locations: Worldwide, deepwater

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Lower concentration of inherent contaminants,

such as complex hydrocarbons (versus OBMs)

Safe discharge of drill cuttings (versus OBMs)

Less waste than WBMs, as SBMs are reusable

Faster drilling, so reduced power use and air

emissions (versus WBMs)

Smaller footprint, as SBMs facilitate extendedreach and horizontal wells (versus WBMs)

Increased worker health and safety—volume

and toxicity of irritating vapors lower than OBMs

Reduced air pollution because SBMs are not

transported to shore for disposal (versus

OBMs)

Reduced landfill usage

Increased wellbore control (versus WBMs)

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Improved drilling speeds, lower operating costs,

and shorter completion times (versus WBMs)

Reduced downtime from common drilling

problems (versus WBMs)

Minimal to no waste hauling and disposal costs

(versus OBMs)

Reduced drilling costs as SBMs can be

reconditioned and revised (versus WBMs)

Increased access to resources by high-angle,

extended-reach, and horizontal wells (versus

WBMs)
D RILLING AND C OMPLETION

Proof in the Gulf

A set of Gulf of Mexico wells with similar characteristics were the

scene for a comparative study of the relative merits of SBMs and

WBMs. Marathon Oil drilled five wells with WBMs and three

with SBMs, and found that SBM performs with greater overall

efficiency. For example, the SBM wells averaged  feet per day

and  days per well, compared to  feet per day and  days

per WBM well. Despite higher per-barrel costs, SBM resulted in

lower total drilling mud costs and downtime costs. Overall, total

drilling and completion costs for the SBM wells were in the range

of . to . million per well, compared with . to .

million for WBM wells. Combined with significant increases in

productivity and decreased environmental impacts, these results

proved that SBM was the better performer for these wells.

CONTACT

Argonne National Laboratory.

Removing Regulatory Barriers to

Allow Wider Use of Innovative

Drilling Fluids, 1/97.

Burke, C., and J. Veil. SyntheticBased Mud Can Improve Drilling

Efficiency Without Polluting. Oil

& Gas Journal, 3/4/96.

Candler, Rushing, and

Leuterman. SyntheticBased Mud Systems Offer

Environmental Benefits Over

Traditional Mud Systems. SPE

25993, 1993.

Furlow, W. Despite Limits,

Synthetic Fluids Still Best Bet for

Deepwater. Offshore Magazine,

1/98.

Furlow, W., New Cuttings

Treatment Taking on Recovery,

Environment Challenges—

Recovering Costly Synthetic

Fluids. Offshore Magazine, 7/98.

Legendre Zevallos, M., et al.

Synthetic-Based Fluids Enhance

Environmental and Drilling

Performance in Deepwater

Locations. SPE 35329, 1996.

Veil, J., C. Burke, and D. Moses.

Synthetic-Based Drilling Fluids

Have Many Environmental

Pluses. Oil & Gas Journal,

11/27/95.

Wood, T., and B. Billon.

Synthetics Reduce Trouble Time

in Ultra-Deepwater Borehole.

Offshore Magazine, 3/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

disposal costs than OBMs

and higher levels of performance than WBMs. In general, SBM performance is

comparable to that of

OBMs, and in some cases

superior. They are manufactured by chemical synthesis

from basic building blocks

of relatively pure materials,

forming highly uniform

products. By varying the

components and manufacturing conditions, different

SBMs can be created that

exhibit varying rheological

properties and environmental

performance parameters.

Current synthetic fluids fall

into several groups: polyalphaolefins (PAOs), linear

alpha olefins (LAOs), internal olefins (IOs), fatty acid

esters, and others.

Comparing costs

Although more expensive

on a per-barrel basis, SBMs

can reduce overall drilling

expenses. When measured

against WBMs, SBMs can

shorten drilling time. Compared with OBMs, SBMs offer

lower disposal costs.

Advantages of synthetic muds as demonstrated

by Marathon Oil in the Gulf of Mexico

METRICS

Mud Cost Total Well

Footage Footage Cost in $ per Cost in Total

Drilled per Day $ Millions Foot $ Millions Days

WBM Wells

17,981 138 1.3 74 11.6 163

16,928 63 2.5 150 18.3 326

17,540 82 – – 9.6 214

17,142 101 1.6 90.4 12.7 197

17,381 215 – – 10.1 77

SBM Wells

16,842 301 0.8 48 5.0 50

18,122 275 1.7 94 7.8 75

17,250 431 0.8 45 3.7 33

©SPE 29737, 1995

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Elena S. Melchert

(202) 586-5095

elena.melchert@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

United States

Mexico

Cuba

Gulf of

Mexico
Improved technology and practices “sweeten” sour gas for

pipeline use and achieve nearly 100 percent sulfur recovery,

greatly reducing air emissions

P RODUCTION

br

P RODUCTION

Before natural gas can be

transported safely and

economically, hydrogen

sulfide (H2S), a highly poisonous acid gas, and other

acid compounds such as

carbon dioxide (CO2) must

be removed from the raw

gas stream in order to

meet pipeline sales contract specifications. Sulfur

recovery plants are used

in tandem with acid gas

removal (sweetening)

operations to avoid emitting unacceptable quantities of sulfur compounds

to the atmosphere.

Improvements in gas

sweetening, in conjunction with advanced sulfur

recovery technologies,

make it possible to practically eliminate noxious

emissions and recover

nearly all the acid gas

stream’s elemental sulfur

for later sale or disposal.

Sweetening natural gas

A RECENT GAS RESEARCHInstitute survey concluded

that approximately  percent

of the raw natural gas produced

in the lower- States contains

unacceptable quantities of

H2S, CO2, or both. To sweeten the high acid content

“sour” gas, it is first prescrubbed to remove entrained

brine, hydrocarbons, and

other substances. The still

sour gas then enters an

absorber, where lean amine

solution chemically absorbs

the acid gas components, as

well as a small portion of

hydrocarbons, rendering the

gas ready for processing and

sale. An outlet scrubber

removes any residual amine,

which is regenerated for recycling. Hydrocarbon contaminants entrained in the amine

can be separated in a flash

tank and used as fuel gas or

sold. Process efficiency can be

optimized by mixing different

types of amine to increase

absorption capacity, by

increasing the amine concentration, or by varying the

temperature of the lean

amine absorption process.

Recovering sulfur

Once acid components have

been removed from the gas

stream, sulfur recovery plants

can minimize sulfur emissions and maximize recovery

of elemental sulfur—environmental regulations commonly

require sulfur recovery levels

well over  percent. The

Claus sulfur recovery process,

first developed over  years

ago, is still the most widely

used process today. Between

 and  percent of the total

sulfur recovered worldwide

uses a variation of this

process. Typically, the acid gas

feed is partially oxidized to

produce SO2, which is then

catalyzed with the remaining

H2S to produce elemental

sulfur, of which approximately

 to  percent is recovered

for sale. Most Claus plants

contain two or three catalytic

stages to enhance recovery. To

reach higher recovery levels, a

sub-dewpoint Claus process is

employed, which operates at

a lower temperature, causing

sulfur condensation and

higher recovery. A tailgas

cleanup unit is required to

obtain sulfur recovery levels

as high as . percent. This

converts the sulfur compounds in the tailgas back to

H2S, then transfers it to a

low-pressure amine sweetening unit, which recycles the

H2S with some CO2 to the

Acid Gas Removal

and Recovery

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Improved air quality through increased sulfur

recovery

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased access to sour natural gas resources

Sale of recovered sulfur as a commodity
P RODUCTION

The Scott field experience

Scott field,  miles northeast of Aberdeen, Scotland, is the

United Kingdom’s largest offshore project this decade.

Recoverable reserves are estimated at  million barrels of oil and

 billion cubic feet of associated gas. In addition to subsea facilities, the development has twin connecting steel platforms,

including a process/drilling platform, drilling and gas treatment

modules, and a flaring unit. 

Developer Amerada Hess Ltd. realized that offshore production

could begin several months before availability of permanent

onshore gas processing facilities at Mobil North Sea Ltd.’s 

St. Fergus terminal, which was scheduled to come on-line on

April 1, . To permit early production, temporary gas sweetening equipment was installed in April  to attain pipeline specifications. A single, fixed-bed reactor sweetening unit enabled H2S

content to be reduced by nearly  percent. By the middle of

October, the Scott field development was producing, treating,

and exporting gas, approximately five months ahead of schedule. 

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Kopperson, D., et al. Injecting

Acid Gas with Water Creates

New Disposal Option. Oil & Gas

Journal, 8/3/98.

Kopperson, D., et al. Two Cases

Illustrate Acid Gas/Water

Injection Scheme. Oil & Gas

Journal, 8/10/98.

Lunsford, K., and J. Bullin.

Optimization of Amine

Sweetening Units. Proceedings

of the 1996 American Institute of

Chemical Engineers Spring

National Meeting, 1996.

McIntyre, G., and L. Lyddon.

Claus Sulphur Recovery

Options. Petroleum Technology

Quarterly, Spring 1997.

Skinner, D., et al. Amine-Based

Gas Sweetening/Claus Sulfur

Recovery Process Chemistry and

Waste Stream Survey. Gas

Research Institute, 1995.

Spears, M., et al. Converting to

DEA/MDEA Mix Ups Sweetening

Capacity. Oil & Gas Journal,

8/12/96.

Temporary Sweetening Unit

Aids Early Oil, Gas Production.

Oil & Gas Journal, 93:7, 2/13/95.

Towler, G., et al. Improved

Absorber-Stripper Technology

for Gas Sweetening to Ultra-Low

H2S Concentrations,

Proceedings of the SeventySixth Gas Processors Association

Annual Convention, 1997.

Wichert, E., and T. Royan. Acid

Gas Injection Eliminates Sulfur

Recovery Expense. Oil & Gas

Journal, 4/28/97.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Claus unit for reprocessing.

In most sulfur recovery

processes, a tailgas thermal

oxidizer incinerates nearly

all remaining sulfur compounds and other contaminants before venting it to

the atmosphere. 

Alternative acid gas

disposal methods

In cases in which it is not

economically feasible to

recover elemental sulfur for

sale, industry is developing

advanced acid gas disposal

techniques. In Canada, for

example, where operators

have typically flared recovered acid gases if unable to

recover sulfur economically,

acid gas is now being dissolved in oil field produced

water at the surface and

injected into subsurface formations. This practice,

although still being demonstrated, potentially offers

producers a low-cost, environmentally sound acid gas

disposal technique when sulfur recovery is not economic.

Scotland

North Sea

Atlantic Ocean

Ireland

England

©SPE, 1993

Aerial view of pipeline transporting recovered sulfur to market
Reduced emissions during production and increased 

productivity result from increasing the efficiency of the 

systems that raise oil to the surface

P RODUCTION

bs

P RODUCTION

As reservoir pressure

declines, natural processes

no longer push the oil to

the surface. Artificial lift

technology, which includes

sucker-rod pumps, electrical submersible pumps,

hydraulic jet pumps,

plunger lifts, progressing

cavity pumps, and gas lift

systems, is now used to

produce some 65 percent

of all oil. Performance of

artificial lift systems has

been optimized through

recent innovations in 

artificial lift equipment,

improved operational

design and parameters,

and real-time data collection, automation, and control technologies. System

optimization not only

maximizes production 

efficiency, but can also

decrease on-site power

use and extend equipment

life. Results include

improved profitability,

reduced workover wastes,

and lower air emissions. 

Practical measures with

attractive environmental and

productivity paybacks

S UCKER - ROD PUMPS ,

the most prevalent form

of artificial lift, use arm-like

devices to provide up-anddown motion to a downhole

pump. Such rod pumping,

most effective in relatively

shallow and low-volume

wells, can be optimized to

increase lifting efficiency and

minimize energy consumption. Surface and downhole

energy losses can be reduced

by adjusting key design parameters like pumping mode

selection, counterbalancing

(to balance loads on the gear

box during the pumping

cycle), and rod string design. 

A number of other advanced

artificial lift technologies 

and practices have improved

efficiency in recent years.

Real-time data collection,

automation, and control

techniques now allow operators to monitor pumping 

performance and downhole

conditions continuously, and

to control operations accordingly. Variable-speed motors

tailor pumping operations to

changing conditions. New

low-profile rod pumps are

attractive options in sensitive

urban, residential, and agricultural areas, as well as on

crowded offshore platforms. 

Gas lift, another common

form of artificial lift, pumps

natural gas down the well’s

annulus and injects the gas

into the production tubing

near the bottom of the well.

The gas expands within the

production tubing stream,

allowing liquid hydrocarbons

to be carried to the surface.

Gas lift is commonly used

when natural gas is readily

available, and is especially

prevalent offshore. Each gas

lift well has an optimum

injection rate and pressure.

Since the injected gas raises

the back pressure in the flow

line leading to the field’s separation and processing facilities, back pressure in one well

affects all wells sharing common flow lines. Using

advanced modeling techniques to develop models of

multiflow characteristics and

to optimize parameters, operators today can design complex gas lift systems that maximize production from all

wells in a network, given the

system’s constraints.

Artificial Lift Optimization

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Increased equipment life and fewer failures

result in less workover and recompletion operations, reducing the volume of workover fluids

and other wastes

Reduced air emissions due to lower power

consumption

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Enhanced efficient production from 

existing wells

Lower equipment maintenance costs

Lower on-site power consumption and costs
P RODUCTION

Optimizing artificial lift in Oman

For Petroleum Development Oman (PDO),

real-time automation and optimization software

was the key to increasing production by some

five percent, while saving  million annually.

Power consumption was reduced and the mean

time between pump failures was increased by

 percent. 

PDO used the Shell Oil Foundation System

(SOFS) to monitor, control, and optimize over

, wells and production facilities, including

both beam-pump and gas lift operations. It collected load, position, and operational data from

 individual beam pumps and then modeled

downhole conditions. The system enabled

pumps to be remotely started, stopped, and

adjusted, providing an on-line tool to evaluate

and optimize pump designs and predict pump

performance.

PDO also applied the SOFS to gas lift wells in

the Yibal field, creating gas lift performance models for each of  wells, matching them to actual

field measurements, and using the resulting performance curves to calculate optimal production

rates for given lift-gas availability. In a pilot

demonstration,  wells in the Yibal field were

also fitted with electronic instruments to measure

lift-gas injection pressure and flow, and tubinghead and casinghead pressures. Ten months of

data were used to adjust lift rates, valve settings,

and completion strings as necessary. As a result,

PDO optimized wells in real-time, achieving a

five percent increase in oil production and a 

percent reduction in the volume of lift gas used. So

successful was the pilot effort that PDO decided

to extend the program to the entire field.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

George Stosur

(202) 586-8379

george.stosur@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Almeida, A., and I. Slobodcicov.

Continuous Gas Lift Performance Analysis. World Oil, 9/98.

Copelin, K. New Techniques Lift

Revenues. Hart’s Oil & Gas

World, 8/98.

Cramer, R., et al. Real-Time

Automation Optimizes

Production Economies in Oman.

Oil & Gas Journal, 11/24/97.

Dutta-Roy, K. Simulation

Approach Improves Gas Lift.

The American Oil & Gas

Reporter, 6/97.

Lea, J., and H. Winkle. What’s

New in Artificial Lift Parts I and

II. World Oil, 3/98 and 4/98.

Lekic, O., and G. Watt. ”System

Approach” Optimizes Gas Lift.

The American Oil & Gas

Reporter, 6/98.

Podio, A. Total Well

Management. Hart’s Oil & 

Gas World, 8/98

Schaible, B. New Artificial Lift

Technologies Enhance

Production Economics. The

American Oil & Gas Reporter,

6/98.

Takacs, G. Improved Designs

Reduce Sucker-Rod Pumping

Costs. Oil & Gas Journal,

10/7/96.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Iran Pakistan

India

Persian

Gulf Gulf of

Oman

Indian Ocean

Somalia

Gulf of Aden

Yemen

U.A.E.

Oman

Saudi

Arabia Arabian Sea

Optimization of sucker-rod

pumping can increase production

efficiency and minimize

energy consumption.

©SPE, 1993
Technology has reduced greenhouse gas emissions by

transforming coalbed methane into an energy resource

P RODUCTION

bt

P RODUCTION

Only 30 years ago, coalbed

methane was viewed primarily as a hazard by the

mining industry. To ensure

mine safety, ventilation and

degasification systems

emitted this gas to the

atmosphere. Methane is

now considered a potent

greenhouse gas thought to

contribute to global warming. It is also a valuable and

significant resource with

potential recoverable

domestic quantities estimated at 40 to 60 trillion

cubic feet. Since the 1970s,

Federal tax credits, intensive government and industry R&D efforts, and rapid

technology growth have

motivated improvements in

coalbed reservoir characterization, reservoir engineering, and completion technology. These advances

have spurred coalbed

methane production and

reserve growth, making this

unconventional resource a

significant component of

our domestic natural 

gas supply.

Producing coalbed methane

L ARGE AMOUNTS OFmethane are stored within coal’s internal structure.

Most coalbeds are aquifers, in

which water pressure holds

the gas in an adsorbed state.

To produce the methane,

water must be pumped from

the coal seams to decrease

reservoir pressure and release

the gas. After desorption from

the coal matrix, the gas diffuses through the coal bed’s

cleats and fractures toward the

wellbore. 

Some coal seams are too deep

to be profitably mined, but

methane production may be

feasible. In these cases, operators drill into the coal seam,

insert production piping, and

then perforate opposite the

target zone. Typically, the

reservoir is then hydraulically

fractured to enhance natural

fractures or create new ones.

Such “stand-alone” coalbed

methane sites often require

substantial initial dewatering

to reduce reservoir pressure,

although produced water

tapers off as methane 

production increases.

Produced water disposal

presents major economic and

environmental challenges for

operators—these costs alone

can determine the feasibility

of coalbed methane projects.

In areas such as Alabama’s

Black Warrior Basin, produced water can be used for

irrigation or treated and discharged into surface waters.

In regions where these waters

are more saline, they are

reinjected into subsurface

geological formations, or in

some cases recycled in fracturing applications. In the

future, emerging technologies

using evaporation, reverse

osmosis, ion exchange, and

wetlands construction

promise more cost-effective

water management. 

Capturing coal mine emissions 

Reduction in reservoir pressure during underground

mining operations releases

coalbed methane into the

mine. To ensure mine safety,

this methane is typically vented into the atmosphere in significant volumes—an EPA

profile of  underground

mines in  indicated that

they emitted an estimated 

billion cubic feet of methane.

But technological advances,

along with utility industry

restructuring, utility offset

projects, and “green” pricing,

are motivating operators to

add methane recovery units

to their ventilation and

drainage systems. Also, the

U.S. Environmental

Protection Agency’s voluntary

Coalbed Methane Outreach

Program is assisting coal mine

operators to identify and

exploit ways to recover and

use or sell methane. As a

result, coal mine methane

Coalbed Methane Recovery

Locations: Worldwide onshore 

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Significantly reduced methane emissions 

Optimized recovery of valuable natural 

gas resource

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Lower operating costs and increased profitability

if recovered gas can be used to fuel on- or off-site

facilities or to generate electricity for site use or

sale

Depending on quality, recovered gas can be 

marketed through pipeline sales
Enhanced recovery in the

San Juan Basin

Several advanced technologies are in use in the

San Juan Basin of northwest New Mexico and

southwest Colorado. In the overpressured, highly

permeable San Juan Basin fairway, open hole cavitation completions are outperforming conventionally cased and fractured completions by factors of three to seven. In this technique, repeated

high-rate, high-pressure injections of air-water 

mixtures into the coal seam are followed by rapid

blowdown. This promotes sloughing of coal into

the wellbore, which increases its radius and

induces tensile and shear fractures. 

San Juan operators are also field testing two new

enhanced coalbed methane (ECBM) recovery

technologies—displacement desorption with

injected carbon dioxide (CO2) and partial pressure reduction with injected nitrogen. Amoco

successfully conducted the first nitrogen flooding

field test in  at its Simon U- well, increasing production fivefold in one year. At Amoco’s

Tiffany Project,  million cubic feet of nitrogen

is injected daily into  injection wells—the

largest commercial demonstration of this technology to date. Since full-scale injection began

January , , total gas production from  production wells has increased from  million cubic

feet to  million cubic feet per day. Furthermore,

Burlington Resources is testing CO2 flood technology at a four-well project at its Allison Unit,

with encouraging preliminary results. 

In a recent study outlining promising technologies for reducing greenhouse gas emissions, U.S.

National Laboratory directors concluded that

coalbed sequestration technology is critical. For

example, future technology could inject CO2

from a powerplant stack into coal seams to

enhance coalbed methane production, then cycle

the methane back to fuel or co-fire the plant,

thereby eliminating significant CO2 emissions.

P RODUCTION

Coalbed Methane—An Untapped

Energy Resource and an Environmental Concern. U.S. Geological

Survey, Fact Sheet FS-019-97, 1997. 

CO2 Utilization Technology Eyed

for Development. Oil & Gas

Journal, 3/2/98.

Environmental Protection Agency.

Identifying Opportunities for

Methane Recovery at U.S. Coal

Mines: Draft Profiles of Selected

Gassy Underground Coal Mines,

1997.

Kuuskraa, V. Outlook Bright for

U.S. Natural Gas Resources. Oil &

Gas Journal, 4/13/98.

Saulsberry, J., R. Schraufnagel,

and P. Schafer, eds. A Guide to

Coalbed Methane Reservoir

Engineering. Gas Research

Institute, 1996.

Shirley, K. Producers in Rocky

Mountains Target Production

Increases. The American Oil & Gas

Reporter, 7/98.

Stevens, S., J. Kuuskraa, and 

R. Schraufnagel. Technology Spurs

the Growth of U.S. Coalbed

Methane. Oil & Gas Journal, 1/1/96.

United States Department of

Energy (National Laboratory

Directors). Technology

Opportunities to Reduce U.S.

Greenhouse Gas Emissions, 1997.

Williams, P. Throughout the

Continental U.S., Emerging Coalbed

Methane Plays Are Commanding

Industry-Wide Respect. Oil and Gas

Investor, 11/98.

SOURCES AND ADDITIONAL READING

CASE STUDIES

METRICS

Coalbed methane production

growth in the United States

1983 1997 2010 2020

Billions cubic feet (Bcf)

6 Bcf

1,090

Bcf

1,400

Bcf*

2,000

Bcf*

* Estimates assume high 

technology progress.

Source: Energy Information Administration;

Kuuskraa; Gas Research Institute

recovery has risen more than

 percent since . 

As technology improves, coal

mine methane recovery is

likely to increase. Several prototype technologies for using

low and variable quality coal

mine methane are under

demonstration. In the UK, an

operator is recovering

methane from poorly sealed

vent holes in abandoned

mines. In the United States,

DOE-sponsored field trials in

recent years have focused on

recovering gob gas.

Success in the Field

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

■ Coalbed methane areas
New approach promises substantial reductions in

produced water volume and associated environmental risks

P RODUCTION

bu

P RODUCTION

A new freeze-thaw/evaporation process purifies produced waters from oil and

gas production operations

by separating out dissolved

solids, metals, and chemicals. These typically brackish waters can be made

suitable for beneficial use,

significantly lowering

environmental risks and

furthering resource management. Initial field tests

indicate that, under specific climatic and operational parameters, the

freeze-thaw/evaporation

process is highly effective.

In these cases, the volume

of produced water can be

reduced by 80 percent if it

is frozen until its solidsladen brine separates, and

the resulting purified water

thawed and drained off for

use or discharge. The isolated pollutants, which

can include heavy metals

and naturally occurring

radioactive materials, are

then disposed of separately.

For volumes greater than

500 barrels per day, disposal costs and environmental risks can be cut

dramatically.

From wastewater to

beneficial by-product

P RODUCING WELLSgenerate an average of six

or seven barrels of produced

water per barrel of oil. This

ratio generally increases as the

field matures, and it may rise

as high as : for marginally

productive wells. Due to its

sheer volume, the near  billion barrels of wastewater generated by exploration and production activities annually is a

matter of potential environmental concern. 

Produced water handling,

treatment, and disposal are

expensive. Class II wells for

enhanced oil recovery or subsurface disposal wells cost

from , to $1 million

each. Water handling costs

usually increase as a field

matures, eroding profit margins. Most oil fields lose economic viability when the

ratio is between : to :,

even if they still hold producible resources. Waterhandling costs are often the

main factor leading to well

abandonment and may make

development of unconventional resources, such as

coalbed methane, economically unfeasible.

Although not considered hazardous waste under existing

Federal legislation, produced

waters are governed by

Resource Conservation and

Recovery Act nonhazardous

waste provisions as well as by

the Clean Water Act and the

Safe Drinking Water Act.

Through cost-effective freeze

crystallization and evaporation

processes, they can be separated into fresh water,

concentrated brine, and solids.

Freeze-Thaw/Evaporation

Locations: Rocky Mountains, Northern Great Plains, and Canada

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Produced water volume requiring disposal

reduced by 80% in preliminary field tests

Creation of fresh water to enhance agricultural

development in the arid western United States

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

A low-cost, energy-efficient method of purifying

produced water volumes greater than 500 bbl/day

Reduction of water treatment and disposal costs.

DOE-supported field tests in the San Juan Basin

estimate treatment costs of 25¢ to 60¢/barrel,

compared to current disposal costs of about

$1/barrel in New Mexico

Extended life for mature fields in certain regions

Improved economic feasibility of developing

marginal or unconventional resources

Start-up of freezing operations

Photo: Hart Publications, Inc., and Gas

Research Institute
P RODUCTION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

H. William Hochheiser

(202) 586-5614

william.hochheiser@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Boysen, J., et al. Field

Demonstration of the FreezeThaw/Evaporation Process for

the Treatment of Produced

Waters in the San Juan Basin in

New Mexico. SPE 37904, 1997.

Boysen, J., et al. Treating

Produced Waters in the San

Juan Basin with the FreezeThaw/Evaporation Process. 

Gas TIPS, Fall 1997.

Department of Energy. Cold

Weather Helps Researchers

Transform Salt Water into

Freshwater. Fossil Energy

Techline, 4/17/97.

Department of Energy and

Interstate Oil and Gas Compact

Commission. Oil and Gas

Exploration and Production

Waste Management: A 17-State

Study, 1993.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Successful DOE-sponsored tests in New Mexico

In , a joint DOE-, Amoco-, and Gas Research Institutesponsored project reported that the freeze-thaw/evaporation

process could economically cut produced water disposal volumes

by more than  percent and produce purified water suitable for

beneficial use or surface discharge. Total dissolved solids concentrations at Amoco’s Cahn/Schneider evaporation facility in the

San Juan Basin, for example, were between  and , mg/l

for the waters resulting from the process, compared with 

, mg/l in untreated waters. In addition to this near 

percent reduction, organic and metal constituents were also significantly reduced in the processed water. In the winter of

‒, a more extensive evaluation conducted in more typical

weather conditions resulted in almost identical outcomes. These

field tests demonstrate the technology’s commercial viability for

high retention operations in areas with subfreezing winters and

warm, dry summers, such as the Rocky Mountains and Northern

Great Plains and much of Canada.

Treated

Water

Conductivity-Activated Controller

Beneficial

Use

Control

Valve

Pump

Temperature 

Switch

Freezing Pad

Produced Water

Holding Pond

High Salinity

Brine Disposal

HOW THE TECHNOLOGY WORKS

Source: Hart Publications, Inc., and Gas Research Institute

■ Major areas of oil

and gas potential

• Produced water is placed in a holding pond.

• When ambient temperature drops below 32°F, water is sprayed on

a freezing pad.

• Due to its higher density, brine with elevated concentrations of total

dissolved solids separates from the ice.

• When ambient temperature rises above 32°F, ice on the pad melts

and purified water drains.

• Brine is disposed of; purified water is discharged or stored for later

beneficial use.

• In summer, natural evaporation from the holding pond is

substituted for freezing cycles.
Gas-to-liquids conversion taps remote sources of gas to produce

cleaner transportation fuels and promote energy security

P RODUCTION

cl

P RODUCTION

Evolving gas-to-liquids

(GTL) technology offers

the promise of accessing

our vast but remote and

uneconomic natural gas

resources in Alaska’s North

Slope and the deepwater

Gulf of Mexico, significantly

increasing our Nation’s

energy and economic

security. GTL technology,

on the brink of widespread

commercial viability,

chemically alters natural

gas into stable synthetic

liquid hydrocarbons that

are far more environmentally friendly and efficient

than conventional petroleum-based liquid fuels.

Globally, the technology

could bring some of the

estimated 2,500 trillion

cubic feet of known but

currently untapped gas

to market, accessing an

abundant fuel source to

produce liquid transportation fuels fully compatible

with our existing transportation infrastructure.

Developing and transporting

remote gas resources

R OUGHLY HALF THEworld’s natural gas is

unused because remote locations makes it too expensive

to transport to market via

conventional gas pipelines or

as cryogenically generated 

liquefied natural gas, due to

distance, climate, environmental concerns, political

uncertainty, and the large

capital investments required.

On Alaska’s North Slope

alone, for example, approximately  trillion cubic feet of

producible gas-in-place could

be accessed with a costeffective approach such as

GTL technology, with the

converted liquid transported

through existing pipelines

and tankers. 

The promise of gas-to-liquids

In , German scientists

Franz Fischer and Hans

Tropsch introduced the first

GTL conversion process.

The technology can produce

a variety of chemicals and

fuels—of particular interest

is its ability to yield large volumes of sulfur-free diesel fuel.

The process involves reforming natural gas into synthesis

gas (“syngas”) by combining

the gas with steam, air, or

oxygen, then converting the

synthesis gas to liquid hydrocarbons through catalytic

reaction, typically with an

iron- or cobalt-based catalyst.

The liquid products are

hydrocracked and stabilized

to create transportation fuels

and chemicals. Until recently,

this process has not been

competitive in the petroleum

marketplace, although it had

been used for political reasons

in noncompetitive economies

such as Nazi-era Germany

and apartheid-era South

Africa. Dramatic recent

advances in GTL technology

focus on improved processes

and catalysts, which are reducing costs enough to be more

competitive with petroleumbased fuels, depending on gas

costs and oil prices.

GTL’s potential to fundamentally alter oil and gas markets

worldwide has generated

significant private sector

research and development

efforts, and sparked numerous small-scale and pilot

studies. The Department of

Energy is committed to a

Gas-to-Liquids

Conversion

Locations: Stranded natural gas resources worldwide

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced emissions of greenhouse gases

and other air pollutants compared with

conventional petroleum-based fuels

Optimized recovery of valuable gas resources

Reduced flaring of associated gas in remote

fields

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Access to remote uneconomic natural gas

resources

Prolonged access to Alaskan crude oil as a

result of sufficient Trans-Alaska Pipeline System

(TAPS) utilization

Creation of a gas-to-liquids industry resulting in

thousands of new domestic jobs and potentially

billions of dollars in new investments
P RODUCTION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Corke, M. Economics Favor GTL

Projects with Condensate

Production. Oil & Gas Journal,

9/28/98.

Corke, M. GTL Technologies

Focus on Lowering Costs. Oil &

Gas Journal, 9/21/98.

DOE Funds GTL Study for TAPS.

Oil & Gas Journal, 10/21/98.

Gas-to-Liquids Processing Hits

Its Stride. Oil & Gas Journal,

6/15/98.

National Laboratory Directors.

Technology Opportunities to

Reduce U.S. Greenhouse Gas

Emissions, 10/97.

Rhodes, A. Downstream,

Catalyst Companies Ally with

Gas-to-Liquids Process

Developer. Oil & Gas Journal,

12/30/96.

Saunders, B. Coming Next:

Natural Gas Refineries? Oil and

Gas Investor, 8/98.

Singleton, A. Advances Make

Gas-to-Liquids Process More

Competitive for Remote

Locations. Oil & Gas Journal,

8/4/97.

Von Flatern, R. Gas-to-Liquids

Technology: An Answer to

Stranded Gas. Offshore

Magazine, 5/1/97.

SOURCES AND ADDITIONAL READING

goal of , barrels per

day of GTL production by

 (assuming Alaskan

North Slope gas is no longer

required for reservoir repressurization), and it plays an

active role in technology

advances through support of

a variety of research and

assessment projects. It

recently concluded an eightyear,  million costsharing agreement with a

consortium of research and

private sector parties. The

consortium, led by Air

Products and Chemicals,

Inc., is working on a revolutionary ceramic membrane

technology that promises to

cut GTL production costs

substantially.

Far-reaching impacts of commercial GTL application

GTL technology mounted

on barges or offshore platforms could bring to market liquid transportation

fuels from deepwater Gulf

of Mexico sites without gas

pipeline access. In Alaska,

converted gas from the

North Slope could be

transported through the

existing Trans-Alaska

Pipeline System (TAPS),

from Prudhoe Bay to

Valdez, where tankers

would deliver these liquids

to market. This would have

major ramifications for

Alaska’s oil and gas industry

and the state’s overall economy. Due to the approximate annual  percent

decline in Prudhoe Bay oil

production rates, pipeline

flow may fall below the

minimum volume required

for cost-effective operations

within the next two

decades, eventually requiring that the pipeline be

shut in. GTL technology

could extend TAPS’ life by

more than  years and prevent shut-in of as many as

, barrels per day of

the last remaining North

Slope crude, protecting

valuable jobs and revenue.

The GTL revolution

“GTL will revolutionize the gas industry the way the first LNG plant

did...[w]e expect to see a 1-2 million barrels per day GTL industry

evolving over the next 15-20 years to the tune of 25-50 billion

dollars of investment.”

- ARTHUR D. LITTLE, IN C.

“We’re looking to open the door to a vast resource of natural gas

that is today beyond our economic reach. This research...could

pioneer a way to tap that resource and convert it into valuable

liquid fuels that America will need in the 21st century.”

- FORMER SECRETARY OF ENERGY FEDERICO PEÑA

“The cost-effective conversion of natural gas to clean liquid transportation fuels...offers a significant potential for greenhouse gas

emissions reduction while allowing greater use of domestic natural

gas supplies.”

- NATIONAL LABORATORY DIRECTORS , DEPARTMENT OF ENERGY

Zero sulfur, zero

aromatics, high cetane

diesel fuel made by

Rentech, Inc., a small

fuel development company based in Denver,

Colorado.

Photo: Rentech, Inc.

ENERGY EXPERTS
Effective management of dehydration systems reduces

greenhouse gas emissions, improves air quality, and 

recovers substantial saleable natural gas

P RODUCTION

cm

P RODUCTION

The U.S. natural gas production sector operates

some 37,000 glycol dehydration systems, which are

designed to remove water

from unprocessed gas production streams to produce

pipeline quality gas. But

during dehydration, these

systems typically vent

methane and other volatile

organic compounds

(VOCs), and hazardous air

pollutants (HAPs) into the

atmosphere. Methane, a

potent greenhouse gas, is

thought to contribute to

global warming, and reducing these emissions is of

critical environmental

importance. Better dehydration systems management, including optimization of glycol circulation

rates and installation of

flash tank separatorcondensers, enables producers to capture up to 90

percent of methane and

other emissions. These

processes reduce greenhouse gas emissions,

improve air quality, and

recover substantial gas for

on-site use or pipeline sale.

Improved practices and

technologies

AFTER REMOVINGwater from a stream of

wet natural gas, a typical

dehydration system circulates

triethylene glycol (TEG)

through a reboiler unit to

boil off the water and gaseous

compounds so that the “wet”

TEG can be recycled. At the

reboiler, however, methane,

and in some cases other

VOCs, and HAPs such as

benzene, toluene, ethyl benzene, and xylene (BTEX), are

vented to the atmosphere.

The amount of methane and

other compounds vented is

directly proportional to the

rate at which the glycol circulates through the dehydration

system. If the circulation rate

is higher than needed to

achieve pipeline quality gas,

more methane and other

compounds are emitted, with

no real improvement in the

quality of the gas stream.

Consequently, producers are

reducing air emissions and

recovering valuable methane

by combining two advanced

practices: first, by installing

flash tank separators and condenser units at the reboiler to

capture methane, VOCs, and

HAPs before they are vented

to the atmosphere; and 

second, by adjusting glycol

circulation rates to optimal

levels. Using a simple mathematical model, engineers can

determine an optimal circulation rate, based on the characteristics of the particular gas

stream, the pipeline’s water

content requirements, and

the operator’s production

needs. These two processes,

used in combination, yield

significant environmental

benefits for the producer in

addition to attractive economic benefits, since the

recovered methane can be

used as on-site fuel or compressed and reinjected into

the sales pipeline.

Glycol Dehydration

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced greenhouse gas emissions

Improved local air quality due to reduction in

BTEX and VOC emissions

Enhanced regulatory compliance for upcoming

Federal E&P Maximum Achievable Control

Technology (MACT) requirements

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Reduced energy consumption for circulation

pumps and reboiler

Lower operating costs if captured methane is

used to fuel on-site equipment

Increased saleable gas

Potential for increased recovery of natural gas

liquids
P RODUCTION

Lower emissions plus lower costs in Louisiana

In the early , Texaco retrofitted  of  field-based glycol

dehydration systems with flash tank separator-condenser units to

reduce emissions of VOCs and BTEX in response to the State of

Louisiana’s emission control program. In addition to greatly

reducing these emissions, it soon became clear that the units also

recovered substantial amounts of methane. To determine exactly

how much, Texaco staff conducted empirical measurements and

used a computer-based dehydrator emissions model developed by

the Gas Research Institute. Additional tests analyzed the extent

to which flash methane and condenser BTEX recoveries were

affected by variances in separator temperature and pressure, and

circulation rates. 

Results showed methane capture of some  thousand cubic feet

per day, nearly  million cubic feet per year. In total, methane

emissions from these units were reduced by  percent, from 

tons to less than  tons per year. Under a wide range of tested

separator pressures and temperatures, flash methane recoveries

ranged from  to  percent, and condenser BTEX recoveries

ranged from  to  percent. Texaco also found that reducing

higher than necessary circulation rates resulted in concomitant

emission reductions, even without separator-condenser installation. As an added benefit, Texaco routed the captured gas into a

low-pressure gathering system for recompression and subsequent

use in its field operations, thus lowering total operating costs.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Gearhart, L. New Glycol-Unit

Design Achieves VOC, BTEX

Reductions. Oil & Gas Journal,

7/13/98.

Schievelbein, V. Reducing

Methane Emissions from Glycol

Dehydrators. SPE 37929, 1997.

United States Environmental

Protection Agency. Lessons

Learned from Natural Gas STAR

Partners: Installation of Flash

Tank Separators. 10/97.

United States Environmental

Protection Agency. Lessons

Learned from Natural Gas STAR

Partners: Reducing the Glycol

Circulation Rates in

Dehydrators. 5/97.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

HOW THE TECHNOLOGY WORKS

In a dehydration process with a flash tank separator, “lean” TEG is

sent to the contactor, where it strips water, methane, BTEX, and other

compounds from the gas stream before entering the separator. Here

pressure is stepped down to fuel gas system or compressor suction

levels, allowing most of the methane and lighter VOCs to vaporize

(flash). The flashed methane can be captured and used as fuel gas or

compressed and reinjected into the sales line. The TEG flows to the

reboiler, where water and remaining gases are boiled off, and it is

recycled back to the contactor. To prevent discharge of HAPs and

VOCs not recovered through the flash process, dehydration systems

can also be fitted with air- or water-cooled condensers, which capture

additional compounds as they move through the reboiler stack.

Sales

Gas

Lean TEG

Rich TEG

TEG Pump

Driver

To Atmosphere

Fuel Gas/Instrument Gas

Compressor Suction

Flare

Rich TEG

Glycol FTS 

Contactor

Inlet

Wet Gas

Glycol Reboiler/

Regenerator

Electric or Energy

Exchange Pump

Flash Tanks produce a drop in pressure that causes the methane to vaporize

(“flash”) from the glycol stream.

■ Major areas of oil

and gas potential
Data management tools improve information access,

increasing resource recovery efficiencies and informing

regulatory and policy decisions 

P RODUCTION

cn

P RODUCTION

The exploration and production (E&P) industry is

among the most data

intensive in the world;

various data—from

geological to technical to

regulatory—must be

managed by both industry

and government.

Advanced data management systems are key to

increasing the efficiency

of oil and gas recovery

and making effective 

regulatory and policy decisions. With participation

by industry, State regulators, and DOE, numerous

efforts are under way,

such as standardized data

collection of State oil and

gas statistics, risk-based

decision making, detailed

online digital atlases of

oil and gas plays, and

validation methodology

for Area of Review (AOR)

variances. Initiatives such

as these reflect advanced

computer technology

capabilities, handling

massive amounts of data

more quickly and cheaply

than ever. 

E&P data management

E&P DATA GENERALLYfall into five major categories: environmental, geologic, exploration and production, regulatory, and technology. Advanced data management techniques enable:

(1) better regulatory, enforcement and compliance decisions; (2) more informed government program and policy

decisions; and (3) more efficient oil and gas recovery.

“Data management” has different meanings for different

technologists. For example,

geophysicists may want to

interpret 3-D seismic data to

locate oil and gas resources,

and petroleum engineers may

want to interpret production

data to enhance recovery;

whereas State regulators might

use online permitting and

compliance data to improve

decision-making processes;

versus environmentalists, who

need habitat surveys and emission reports to inform policy

debates. Both government

and industry seek to improve

their data management systems to support these goals. 

Comprehensive State

data facilitate decisions 

States and DOE are collaborating to enhance State-level

oil and gas data collection

and management efforts. For

example, with DOE support,

the Interstate Oil and Gas

Compact Commission

(IOGCC) is cataloging State

data collection efforts and

management capabilities and

devising uniform standards

for State permitting, production, and well statistics.

IOGCC and DOE are also

bringing key E&P data

online to facilitate decision

making by industry and

States. These efforts include

DOE’s Environmental

Compliance Assistance System,

which provides information

regarding Federal E&P environmental regulations, and

IOGCC’s framework for helping States develop permitting

and regulatory compliance

assistance programs. 

Enabling cost-effective

regulation

Developed by the Ground

Water Protection Council

with funding from DOE, the

Risk-Based Data Management

System (RBDMS) was originally designed to manage data

for underground injection

control programs, enabling

Advanced Data

Management

Locations: United States

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Better regulatory and policy decision-making

processes, leading to enhanced environmental

protection

Risk-based regulatory structures focus industry

and government activities on areas of greatest

potential risk

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Better data access facilitates more effective business and investment decisions

Risk-based regulatory decisions lower environmental costs and increase operational efficiency

More efficient recovery of oil and gas resources,

through improved prospect identification and

targeting 
P RODUCTION

CONTACT

CH2M Hill. RBDMS Web Site.

www.ch2m.com/ch2mhill/

projects/rbdms

Department of Energy. Office of

Fossil Energy. Oil and Gas R&D

Programs, 3/97.

Department of Energy.

Richardson Launches Effort to

Bring All-Digital Permit Process

to Oil Industry (Draft Release),

2/19/99.

Emmons, L. Practical

Approaches to Environmental

Protection in the Exploration

and Production Industry. SPE

28735, 1994.

E&P Forum/UNEP.

Environmental Management in

Oil and Gas Exploration and

Production: An Overview of

Issues and Management

Approaches.

Interstate Oil and Gas Compact

Commission. Guidelines for

States: Exploration and

Production Data Management,

11/96.

Kansas Geological Survey.

Digital Petroleum Atlas.

www.kgs.ukans.edu

Simmons, J., and S. Jones. Multi

State Area of Review Variance

Program. SPE 37920, 1997.

Stilwell, C. Area Waste

Management Plan for Drilling

and Production Operations. SPE

65th Annual Technical

Conference and Exhibition,

1990.

SOURCES AND ADDITIONAL READING

more effective regulatory and

operational decision making.

The system has been so well

received that it is being

modified by individual

States to include production, geological, and waste

management data, as well as

enforcement and permitting

data. Initial RBDMS success has prompted more

than 20 States to form a

users’ group to help each

other implement the system.

Improving AOR verification

Under the Safe Drinking

Water Act, operators are

required to conduct quarter-mile AOR analyses of

disposal and injection wells,

but AOR variances may be

granted in specific cases.

With DOE and American

Petroleum Institute support,

the University of MissouriRolla has developed a scientific methodology for validating AOR variance

requests that is expected to

provide industry cost savings

exceeding $300 million.

DOE has also supported

development of data management tools and

Geographic Information

Systems (GIS) to help regulators conduct AOR and

variance analyses statewide. 

Enhancing oil

and gas recovery 

Partnering with States and

the Gas Research Institute,

DOE is supporting both

print and digital atlases of

producing regions in the

United States. For example,

a DOE-supported consortium is using GIS technology to develop a digital

atlas of oil and gas plays

and fields specific to

Kansas, Nebraska, the

Dakotas, and parts of

Montana and Colorado.

In these mature regions,

advanced technology and

data management are seen

as the best approaches to

extend production and prevent premature well abandonment. To help operators

recover more original oil-inplace, the atlas, which currently covers only Kansas,

will provide extensive production, petrophysical, and

geological data, sophisticated digital maps and imagery,

as well as field-specific information on recovery technologies and engineering

methods for identifying new

or unswept zones.

Electronic permitting

in Texas

Through a new DOEsponsored pilot program,

the Texas Railroad

Commission is developing

a paperless, digital on-line

permitting system, which

will save the State’s operators and regulators millions

of dollars and countless

labor hours. This fully digital approach will soon

enable operators to submit

an electronic permit application via an Internetlinked computer, complete

with supporting graphical

or text attachments. The

operator’s identity will then

be authenticated, and permit fees paid through a

secure on-line transaction.

Within hours—perhaps the

same day, rather than the

days or weeks now

required—the producer will

be notified electronically

whether the application has

been approved. Although

the expected savings per

permit application may be

relatively small, overall cost

savings are expected to be

significant; annual savings

from drilling permits alone

are estimated at between

$3 million and $6 million.

Advanced computing

leads the way

The Oil and Gas

Infrastructure Project—

part of DOE’s Advanced

Computational Technology

Initiative—has explored

implementing inexpensive

mechanisms for online

access to well-level oil and

gas data from Texas, California, and other States.

Such mechanisms enhance

producers’ access to production and geological data,

ultimately enabling more

efficient resource recovery.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov
Thirty years of continuous improvement in enhanced

recovery technology has led to significant reserve 

additions and less drilling 

P RODUCTION

co

P RODUCTION

The goal of evolving oil

recovery technologies is

increased reserves with less

drilling. Despite significant

technology advances in primary and secondary production, much of a reservoir’s original oil-in-place

remains untapped after

these phases of the production cycle. Coupled with

advanced field management

practices, new enhanced oil

recovery (EOR) technologies—such as thermal, gas,

and chemical techniques—

can significantly increase

production in some maturing fields. The United States

leads the world in sophisticated EOR technology,

which currently accounts

for about 12 percent of

domestic daily crude oil production, a 140 percent

increase from daily EOR

rates only 15 years ago. In

addition to preventing premature abandonment of

significant domestic oil

resources, these technologies

could potentially recover half

of the Nation’s 350 billion

barrels of “discovered, but

unrecoverable” original

oil-in-place.

Getting more oil from

existing fields

PRODUCTION AT MOSToil reservoirs includes

three distinct phases: primary,

secondary, and enhanced

recovery. During primary

recovery, which uses natural

pressure or artificial lift techniques to drive oil into the

wellbore, only about  percent of the oil-in-place is generally produced. Shortly after

World War II, producers

began to conduct secondary

recovery techniques to extend

the productive life of oil fields,

increasing ultimate recovery to

more than  percent. Gas

injection, for example, can

maintain reservoir pressure

and keep fluids moving;

waterfloods are used to displace oil and drive it to the

wellbore. In recent decades,

the development and continued innovation of EOR techniques has increased ultimate

recovery to  to  percent

of a reservoir’s original oil-inplace. In the United States,

three major categories of EOR

technology—thermal, gas, and

chemical—dominate EOR

production.

Even though improved EOR

technology can significantly

extend reservoir life and has

been successfully used since

the , historically high

costs have limited widespread

application. In the last decade,

however, dramatic improvements in analytic and assessment tools have led to a

greater understanding of reservoir geology and the physical

and chemical processes governing flows in porous media.

Today, unconventional

approaches such as fieldwide

development using strategically

placed horizontal wells, or

microbial injection to improve

recovery may lead to new

classes of EOR technology.

Innovations in thermal recovery include radio frequency

heating, and enhanced gravity

drainage with steam in vertically parallel horizontal wells.

Thermal recovery

Thermal recovery techniques

account for some  percent

of daily U.S. EOR production. Used in individual wells

or fieldwide, steam injection

and flooding provide effective

recovery of heavy, viscous

crudes, which must be

“thinned” to enable oil to flow

freely to the wellbore. The

most common domestic EOR

Improved Recovery

Processes

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Fewer new wells drilled due to increased

reserves from existing fields

Less environmental impact due to reduced

abandonment of marginal wells and offshore

platforms

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Worldwide production of approximately 2.3 million barrels per day (760,000 barrels per day in

the United States) that would otherwise remain

untapped

Potential recovery of up to half of the 350 billion

barrels of discovered, currently unrecoverable,

domestic oil

Increased production from marginal resources
P RODUCTION

Steamflooding increases reserves

fivefold at Kern River field

Discovered in  by hand digging a -foot well, the giant Kern

River field near Bakersfield, California, had nearly  wells by

. At its peak, primary production was , barrels/day, but

had declined to , by . Installing bottomhole thermal

heaters in the s succeeded in making oil less viscous so that it

flowed more easily. Surface steam injection followed in the s,

and ultimately fieldwide steamflooding brought production to a

peak , barrels/day in . Production from the field was

still over , barrels/day in . Overall, thermal EOR has

increased recovery from  percent of oil-in-place to over  percent, with ultimate recovery of  percent from this . billionbarrel field. Production is nearly five times greater than possible

with primary recovery technology alone. Field life has been doubled, and on its th birthday in , Kern River field will still

have , producing wells.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

George Stosur

(202) 586-8379

george.stosur@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

California Department of

Conservation, Division of Oil

and Gas. 1997 Annual Report.

Kane, A. Performance of a

Large-Scale CO2-WAG Project:

SACROC Unit—Kelly-Snyder

Field. Journal of Petroleum

Technology, 2/79.

Moritis, G. EOR Oil Production

Up Slightly. Oil & Gas Journal,

4/20/98.

Stalkap, F. Miscible

Displacement Monograph,

Vol. 8. SPE, 1984.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

practice, this process has

contributed directly to

improved burning efficiencies of both gas and oil, and

spawned the cogeneration

industry, which uses cleanburning natural gas to create

both steam and electricity at

attractive prices for oil field

operators and utilities. In

California alone, for example,

existing cogeneration plants

generate enough electricity to

supply . million homes. 

A second type of thermal

recovery, in-situ combustion,

injects air or oxygen into the

formation and uses a controlled underground fire to

burn a portion of the inplace crude. Heat and gases

move oil toward production

wells. This process is highly

complex, involving multiphase flow of flue gases,

volatile hydrocarbons, steam,

hot water, and oil, and its

performance in general has

been insufficient to make it

economically attractive to

producers. 

Gas-immiscible and

-miscible recovery

Accounting for  percent

of daily EOR production,

gas injection is the second

most prevalent technology

currently in domestic use.

Two basic forms exist:

immiscible, in which gas

does not mix with oil; and

miscible, in which injection

pressures cause gas to dissolve in oil. Immiscible injection, which can use natural

gas, flue gas, or nitrogen, creates an expanding force in

the reservoir, pushing additional oil to the wellbore.

Miscible gas injection dissolves

propane, methane or other

gases in the oil to lower its

viscosity and increase its flow

rate. In place of the costly

hydrocarbon gases used in

some EOR projects, miscible

gas drives also frequently use

carbon dioxide (CO2) and

nitrogen. CO2 flooding has

proven to be one of the most

efficient EOR methods, as it

takes advantage of a plentiful, naturally occurring gas

and can be implemented at

lower pressures. 

Chemical recovery

Chemical recovery techniques account for less than

one percent of daily U.S.

EOR production. In an

enhanced waterflooding

method known as polymer

flooding, high molecular

weight, water-soluble polymers are added to the injection water to increase its 

viscosity relative to that of 

the oil it is displacing, raising

yields since oil is no longer

bypassed. In another chemical recovery technique, 

surfactant flooding (also

known as micellar-polymer

flooding), a small slug of 

surfactant solution is injected

into the reservoir, followed by

polymer-thickened water and

then brine. Despite its very

high displacement efficiency,

this technology is hampered

by the high cost of chemicals

and their environmental

impact.
New devices to detect and measure gas leaks aim

to eliminate greenhouse gas emissions

P RODUCTION

cp

P RODUCTION

Leak detection and measurement systems play an

essential part in controlling emissions of

methane—a potent greenhouse gas and valuable

energy product—from the

Nation’s massive oil and

gas infrastructure.

Significant amounts of

methane are emitted to

the atmosphere during

production, transmission,

processing, storage, and

distribution. New technology facilitates accurate,

efficient leak detection and

measurement by ensuring

equipment and pipeline

integrity and timely maintenance and repair. These

controls capture saleable

natural gas, create safer

work places, and protect

our environment.

Overcoming the limitations of

conventional systems

MANAGING LEAKS INthe U.S. oil and gas

infrastructure is a formidable

task. This complex infrastructure involves nearly ,

producing oil and gas wells

and related equipment,

, miles of natural gas

transmission pipeline, and

about . million miles of distribution pipeline. New technologies overcome drawbacks

in standard industry

approaches, such as “leak 

concentration measurement”

techniques. These use handheld instruments, such as

organic vapor analyzers

(OVAs) equipped with flame

ionization detectors, to sample methane concentrations

around leaking components.

The leak flow rate can be

estimated by the predicted

relationship between concentration and leak rate. Such

devices are easy to use, but

accuracy rates are low.

Distortions up to three orders

of magnitude can occur due

to wind conditions, leak

velocity, the shape of the

component, and the surface

distribution of the leak. 

Another conventional practice, “bagging,” measures

leaks by enclosing a component in a nonpermeable bag,

adding air (or nitrogen), and

then measuring an exhaust

stream with an OVA. While

highly accurate, bagging is

costly, labor-intensive, timeconsuming, and impractical

when large numbers of components must be tested and

measured.

High-flow samplers

Advanced technologies equip

the industry to detect leaks

with better accuracy and efficiency. The High-Flow

Sampler, developed by the

Gas Research Institute (GRI)

and Indaco Air Quality

Services, Inc., samples the air

surrounding leaking components using a pneumatic air

mover, thus eliminating the

need for bagging. Although

more expensive than conventional tools, this technology

offers the accuracy of bagging

and the ease and speed of

leak concentration measurements. It can also measure

much larger leaks than standard instruments, which 

typically malfunction above

leak detection ranges of

, parts per million. 

Backscatter absorption

gas imaging

Another new technology,

backscatter absorption gas

imaging (BAGI), is a state-ofthe-art, remote video-imaging

tool developed by Sandia

National Laboratories, with

Leak Detection and

Measurement Systems

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced emissions of methane, a potent

greenhouse gas

Enhanced worker safety due to more effective

and efficient leak detection

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

More accurate information on leak characteristics

and emissions, leading to successful, costeffective leak reduction strategies

Increased recovery and usage of valuable 

natural gas
P RODUCTION

High-tech sampling and imaging matched by 

effective low-tech approach

In June , a Unocal Spill Prevention Task Group used

Labradors and Golden Retrievers to detect underground pipeline

leaks in the -year-old Swanson River Field in Alaska’s Kenai

National Wildlife Refuge. The dogs, originally used in law

enforcement, were retrained to recognize a nontoxic odorant

(Tekscent) injected in the pipelines. In widely ranging temperatures, the dogs successfully detected two faulty valve box seals

and leaks in pipelines down to  feet underground or under 

feet of snow. The team inspected about  miles of pipelines in

two weeks. Unocal’s use of this and other innovative environmental technologies earned them an U.S. Department of the

Interior “National Health of the Land” environmental excellence

award in May .

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Christopher J. Freitas

(202) 586-1657

christopher.freitas@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Alaska’s E&P Outlook-3. Oil &

Gas Journal, 7/1/96.

Kulp, T., et al. The Development

of Active Imaging Techniques

for the Remote Detection of

Natural Gas Leaks. Sandia

Combustion Research Technical

Review. Sandia National

Laboratories, 1997.

Resch, R., and S. Newton.

Natural Gas STAR Program

Options for Reducing Methane

Emissions. GasTIPS. Gas

Research Institute, Winter

1996/97.

Sandia National Laboratories.

Long-Range Imaging of Gas

Plumes Demonstrated in Field

Trials. Combustion Research

Facility News, January/February

1996.

U.S. Environmental Protection

Agency. Inventory of U.S.

Greenhouse Gas Emissions and

Sinks, 1990-1996. 3/98.

U.S. Environmental Protection

Agency, Natural Gas STAR

Program. Measuring Methane

Emissions. 1997.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

support from GRI and

DOE. Whereas other surveys are performed with

manually scanned point sensors, BAGI technology uses

infrared laser-illuminating

imaging. If a gas plume is

present and resonating within the illumination wavelength, the plume attenuates

a portion of the laser

backscatter and appears as a

dark cloud in the real-time

video picture. The equipment can be tuned to the

absorption resonances of a

wide variety of gases.

Remote video imaging, with

the superior efficiency of

covering an entire area at

one time, could greatly simplify leak detection. The latest field trials indicate an

impressive detection range,

with flow rates as low as .

standard cubic feet per hour

at distances from up to 

meters, and leaks as low as

. standard cubic feet per

hour at closer distances.

Estimates are that BAGI

will increase area leak search

rates by a factor of  versus existing technology.

Photo: Hart Publications, Inc., and 

Gas Research Institute

Field trials of the new

High-Flow Sampler

promise more effective

leak detection and

measurement.

Alaska
Energy-efficient “low-bleed” pneumatic devices can 

dramatically reduce methane emissions and recover

lost gas resources

P RODUCTION

cq

P RODUCTION

Throughout all sectors of

the natural gas industry,

pneumatic valves, regulators, and sensors use pressurized gases to control 

or monitor critical equipment. As part of normal

operations, pneumatic

devices release natural

gas, primarily methane, 

to the atmosphere. Within

the industry, pneumatic

devices are the single

largest source of methane

emissions, venting nearly

50 billion cubic feet annually. Older designs leak, or

”bleed,“ an average of 140

thousand cubic feet per

year per device, a volume

equivalent to an average

household‘s annual use,

whereas newer, low-bleed

designs emit an annual

average of only 8 to 12

thousand cubic feet.

Replacing or retrofitting

devices, or improving

maintenance, can reduce

gas emissions substantially,

reducing greenhouse gas

emissions and potentially

saving the industry millions

of dollars in lost methane. 

Protecting the ozone layer 

and saving valuable gas

T HE NATURAL GASproduction sector uses

pneumatic devices to control

and monitor gas and liquid

flows and levels in dehydrators

and separators, temperature

in dehydrator regenerators,

and pressure in flash tanks.

Approximately ,

pneumatic devices are used in

the production sector alone,

venting an estimated  billion cubic feet of methane

annually,  percent of total

methane emissions. Specific

bleed rates are a function of

the design, condition, and

specific operating conditions

of the device. By definition, a

high-bleed device leaks more

than six standard cubic feet

per hour, although industry

operators estimate that most

devices typically bleed about

three times that rate.

Aggressive replacement,

retrofitting, inspection, and

maintenance

New, technically advanced

low-bleed devices and retrofit

kits offer comparable performance characteristics to highbleed models, yet reduce

methane emissions considerably—on average, they vent

 percent less methane.

Although low-bleed devices

typically cost more than their

high-bleed equivalents, costbenefit analyses show that

replacement or retrofit project

costs are typically recouped

within months. While it may

be impractical to replace all

an operation’s high-bleed

devices at once, operators are

finding successful alternatives,

such as combining replacements and retrofits, or

installing a low-bleed device

when an existing device fails

or is no longer efficient. 

Others have implemented

aggressive inspection and

maintenance programs. By

cleaning and repairing leaking

gaskets, fittings, and seals,

operators are able to reduce

methane emissions substantially. Other effective practices

include tuning the device to

operate in the low or high

end of its proportional band,

minimizing regulated gas 

supply, and eliminating

unnecessary valve position

indicators.

Low-Bleed 

Pneumatic Devices

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced greenhouse gas emissions

Conservation of valuable gas resources

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Increased operational efficiency, as retrofit or

replacement can provide better system-wide

performance, reliability, and monitoring of 

key parameters

Increased saleable product volume, as leaks 

are minimized
P RODUCTION

Chevron retrofits reduce emissions by 90 percent 

Chevron installed a low-bleed retrofit valve kit on liquid level and

pressure controllers on two platforms in the Vermilion field’s blocks

 and , roughly 60 nautical miles south of the Louisiana coast

in the Gulf of Mexico. During this pilot test in January , 

devices were tested on one platform and  devices on another. The

retrofits yielded average reductions in bleed rates of more than 90

percent. A cost-benefit analysis showed that the retrofitting costs

would be recovered in less than two years, with specific payback

periods based on the characteristics of the device retrofitted and an

assumed natural gas wellhead price of . per thousand cubic feet.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

George Stosur

(202) 586-8379

george.stosur@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Scalfano, D. Case History:

Reducing Methane Emissions

from High Bleed Pneumatic

Controllers Offshore. SPE 37927,

1997.

United States Environmental

Protection Agency. Lessons

Learned: Options for Reducing

Methane Emissions from

Pneumatic Devices in the

Natural Gas Industry. 5/98.

Weust, J. Case History of an

Onshore High Bleed Pneumatic

Pilot Evaluation Project. SPE

37928, 1997.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

METRICS

Since 1991, EPA Natural Gas STAR Producer members, who account

for approximately 35 percent of the Nation’s natural gas production,

have reduced methane emissions from pneumatic devices by nearly

11.5 billion cubic feet, worth an estimated $23 million. 

Advanced technology, combined with improved maintenance 

practices, can reduce methane losses from pneumatic devices by

approximately 90 percent.

Marathon survey drives inspection, repair, 

and replacement program

As an EPA Natural Gas STAR Program partner, Marathon Oil

Company recently surveyed more than  pneumatic devices at

 U.S. production facilities. Results indicated that Marathon

devices were bleeding . million cubic feet of methane per year,

on par with the annual gas consumption of  residential consumers. Consequently, Marathon has now implemented a comprehensive program to inspect, repair, and replace its high-bleed

pneumatic devices, saving gas and reducing emissions. In fact,

Marathon determined that purchasing expensive leak detection

equipment was not even needed to conduct such surveys; only listening was required, because “control devices with higher emissions [could] be identified qualitatively by sound.”

Before After 

Retrofit Retrofit Savings

Location Unit Service (scf/day) (scf/day) (scf/day)

V245 “F” Fisher 2900 Oil Dump 438 43 395

V245 “F” Fisher 2900 Suction Scubber 211 0 211

V245 “F” Fisher 2900 Gas Filter 397 1 396

V246 “D” Fisher 2900 Oil Dump 328 81 245

V246 “D” Fisher 2900 Water Dump 567 0 567

Average 388 25 363

V246 “D” Fisher 2900 Water Skimmer 508 177 331

V245 “F” Fisher 4150 Fuel Gas Reg. 145 0 145

V245 “F” Fisher 4160 Sales Gas Reg. 108 0 108

V245 “F” Fisher 4160 Makeup Gas Reg. 534 12 522

Average 262 4 258

V246 “D” Fisher 2900 Oil Dump 950 4 946

Gas Saved by Retrofitting Controllers at Chevron

United States

Gulf of

Mexico

©SPE 37927, 1997
Advanced offshore platform technology reduces project 

duration, costs, and impacts on marine environments 

P RODUCTION

cr

P RODUCTION

Finding economically

viable methods to tap 

vast deepwater resources

is driving innovations in

offshore technology.

Potential payoffs are

immense. An estimated 90

percent of undiscovered

global reserves are under

3,000 feet or more of

water. Between 1996 and

1998, nearly 75 percent of

the 66 oil discoveries

greater than 100 million

barrels were offshore.

Effective new technology

includes advanced tension

leg platforms (TLPs) and

mini-TLPs, which are

lower-cost, small-footprint

platforms suited to marginal fields. Other offshore

platforms include spars,

now designed to operate

in depths of up to 8,000

feet, semisubmersible

floating production systems

(FPS), and new-generation

floating production, storage, and offloading systems

(FPSOs). Ongoing technology refinement continues

to optimize recovery,

reduce costs, and minimize environmental risks

and impacts.

Enhanced recovery with 

fewer risks

P LATFORM DESIGNis key to cost-effective

deepwater field development.

Variables include field

remoteness, size, and characteristics, water depth and

condition, and weather patterns. Today, eight floating

TLPs, moored to the ocean

floor with high-strength tendons that provide vertical and

lateral stability, operate in

large, multi-well fields worldwide. TLPs offer the advantages of fixed platforms—

space for crew quarters,

drilling rigs, and production

facilities—with lower investment costs. Maturation of

TLP technology has enabled

more aggressive production

schedules and less exposure to 

economic risks. Platform 

construction time has been

cut in half. Today’s TLP can

withstand hurricane-force

winds and waves, and its

deepwater limits are being

extended, perhaps to ,

feet. High-performance composites, stepped tendons,

cables, and other options can

increase tendon stiffness and

reduce vertical motion in

harsh ocean settings. The

conceptual raft TLP, a submerged hull tensioned to the

sea floor, would also minimize motion at reduced cost. 

TLP innovations have

spawned mini-TLPs with

small footprints and permanent tension leg moorings

that allow installation close to

other platforms. The required

investment in conventional

TLPs can make their use for

smaller discoveries unprofitable. Less costly mini-TLPs

can be constructed and

deployed swiftly in marginal

deepwater fields. 

Spar drilling and production

platforms—large, cylindrical

platforms supported by buoyancy chambers and fastened

with catenary mooring systems—have been used for

research, communication,

storage, and offloading for

more than  years. The first

spar production platform,

installed in , feet at the

Gulf’s Neptune Field in ,

was designed for maximum

production of , barrels

of oil per day and features a

-by--foot hull enclosing

buoyant risers and surface

wellheads. Advances have led

to units designed to operate

in more than , feet of

water. Inherent design versatility and optional hulls

Offshore Platforms

Locations: Deepwater areas of Australia, Brazil, Gulf of Mexico,

North Sea, Southeast Asia, West Africa, and elsewhere

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Optimized recovery of valuable deepwater oil

and gas resources

Shorter construction and production schedules

ultimately reducing operational footprints, and

protecting marine habitats and ocean

resources 

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Recovery of significant deepwater oil and gas

reserves that may otherwise remain undeveloped; enhanced recovery of marginal resources

Combined with advanced subsea completion

technology, shorter construction and development schedules, leading to reduced costs

FPSO and FPS deployment facilitates low-cost

field abandonment
P RODUCTION

Ram-Powell TLP

Production began in September  at the  billion Ram-Powell

Unit, a ,-ton, ,-foot high TLP in the Gulf of Mexico

about  miles south of Mobile, Alabama. A development joint

venture between Shell, Exxon, and Amoco, Ram-Powell employs

a permanent crew of  and has peak gross production capacity

of , barrels of oil and  million cubic feet of gas per day.

Twelve -inch diameter tendons, each about , feet long, 

support the unit in more than , feet of water, a new depth

record for a permanent production platform. Ram-Powell can

drill down to , feet below the sea floor, and has complete

oil and gas processing separation, dehydration, and treatment

facilities. Estimated recovery from this project is approximately

 million barrels of oil equivalent.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

George Stosur

(202) 586-8379

george.stosur@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Beims, T. Industry Sees More

Subsea Technology on Gulf’s

Deep Horizon. The American Oil

& Gas Reporter, 6/97.

Bourgeois, T., et al. Race on for

Deepwater Acreage, 3,500-meter

Depth Capability. Offshore

Magazine, 10/98. 

Chianis, J., and P. Poll.

Production Systems: Studies

Clear Cost, Depth Limit

Misconceptions. Offshore

Magazine, 7/97.

Crager, B. and C. McCabe.

MOPS Cut Offshore

Development Risk. The

American Oil & Gas Reporter,

4/97. 

Design of FPSO Systems for

Re-use, Decommissioning.

Offshore Magazine, 4/1/98.

Kibbee, S. TLP Technology:

SeaStar Minimal Platform for

Small Deepwater Reserves.

Offshore Magazine, 6/1/96.

McCaul, J., and E. Smith.

International Report: Technology

Changing Needs for Deepwater

Vessels. Offshore Magazine,

5/1/98.

Miller, T. Deepwater E&P:

Drilling, Production Spar Dictates

Difference in Mooring Setup.

Offshore Magazine, 6/1/98.

Skaug, L. New Designs Advance

Spar Technology into Deeper

Water. Oil & Gas Journal,

11/2/98.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

(“classic” and “truss”) allow

flexibility of use, from storage

to any combination of

drilling, production, and

workover, decreasing financial

risk. Spars, easily relocated

and reused, are also attractive

for marginal fields.

Marginal fields, mild climates,

and shallow depths were the

criteria for using the first

FPSO and FPS  years ago,

but today an estimated 

units operate worldwide in

varied climates and depths.

Enhanced FPSOs have a

compression system for gas

lift, injection, and export,

desalters, water injection and

natural gas liquids recovery

systems, as well as a conventional production system.

FPSOs are selected in remote

locations lacking pipelines

and fixed infrastructure, marginal fields, and depths too

great for fixed platforms,

whereas FPSs are used where

infrastructure connections are

available. Combined with

subsea completion technologies, FPSO and FPS platforms are considered critical

to industry’s move toward

,-foot water depths,

and many believe that this

combination offers the most

viable option over , feet.

Compared with spars and

TLPs, deepwater subsea 

completions offer shorter

development schedules and

more flexibility in location

and well number.

United States

Gulf of

Mexico
Emerging technologies for downhole fluids separation can

reduce the volume of produced water brought to the surface,

while increasing oil recovery

P RODUCTION

cs

P RODUCTION

New downhole separation

technologies promise to

cut produced water volumes by as much as 97

percent in applicable

wells. Usually, both water

and oil are pumped to the

surface for separation, but

novel mechanisms

installed below the surface

can now separate the formation’s oil and water in

the wellbore. Oil is then

produced, but water is

directly pumped into a

subsurface injection zone.

This minimizes environmental risks and reduces

fluid lifting and disposal

costs. Downhole separation can also increase oil

production significantly,

and this, combined with

reduced operating costs,

could potentially extend

the life of marginal wells

or reactivate shut-in wells.

Field testing and demonstration projects are currently under way in

numerous projects

throughout the United

States and the world.

Conventional surface

separation 

I N TODAY ’ S TYPICALoil well, produced water

and oil are pumped to the

surface for separation, after

which the oil is pumped off

and the water treated, then

reinjected into the ground.

This approach brings contaminants up through the well

piping, and incurs significant

water lifting and handling

costs. Emerging downhole

separation technologies can

minimize the environmental

risks associated with produced water handling, treatment, and disposal, and

greatly reduce the costs of

lifting and disposing of the

produced water.

Three promising mechanisms

for downhole separation 

Downhole oil/water separation involves the use of

mechanical or natural separation mechanisms in the wellbore to separate the formation’s oil and water. Although

not applicable to heavier,

low-API gravity crudes, three

basic downhole separation

techniques are currently

under development. 

Gravity separation in the

reservoir enhances and maintains the gravitational

oil/water separation that

occurs naturally in reservoirs.

The normally level oil/water

contact is skewed by the production process, which causes

the water/oil interface to rise

in a phenomenon called

“coning.” When the tip of

the water cone reaches the

perforations in the well casing, the well begins to produce large amounts of water.

This technique for downhole

separation maintains a flat

oil/water zone by using dual

perforations in the well casing

to produce water from below

the zone (for downhole injection into another formation)

simultaneously with oil from

above the zone. This helps to

maintain the natural oil/water

gravity segregation and avoids

coning. 

Downhole Oil/Water

Separation

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Volume of produced water brought to surface

reduced significantly, greatly minimizing risk

from contaminants on the surface and to 

drinking water aquifers

Less drilling of new wells, due to greater 

recovery from existing wells

Reduced production footprints, as surface 

facilities may be smaller

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Significant reductions in water lifting and 

disposal costs

Enhanced oil production

Increased access to marginal or otherwise

uneconomic wells
P RODUCTION

Significant pilot results

A collaborative Mobil, BP Amoco, Texaco, and Chevron consortium (MoBPTeCh) was chartered to develop innovative solutions to

common environmental problems in the oil and gas industry.

MoBPTeCh has recently conducted extensive research on produced

water downhole separation technologies, with  test wells in operation using gravity separation in the well casing. At this time, the

project uses rod pumps only, but future tests with ESPs are expected

to greatly increase the handling capacity of liquid volumes. Initial

results indicate great potential for downhole separation technologies

to reduce produced water volumes and increase production.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Desanding System for

Downhole Oil/Water Separation:

Field Trial. Journal of Petroleum

Technology, 9/98.

Downhole Water Separation

Scaling up for Higher Volumes.

Offshore Magazine, 6/98.

Furlow, W., and V. Schmidt.

Production Systems Moving

Subsea and Downhole. Offshore

Magazine, 6/98.

Mathews, C., et al. Application

of Downhole Oil/Water

Separation Systems in the

Alliance Field. SPE 35817, 1996.

Miller, J. Tool Reduces Produced

Water Costs. The American Oil &

Gas Reporter, 1/97.

Miller, J. Tool Solves Produced

Water Problems. The American

Oil & Gas Reporter, 3/97.

Monitoring and Control of

Downhole Oil/Water Separation.

Journal of Petroleum

Technology, 10/98.

Peats, A., et al. Application of

ESP Oil Water Separation

System in the Swan Hills Unit

One Field-A Case Study. SPE

ESP Workshop, 1997.

Solanki, S., et al. Downhole

Oil/Water Separation Systems

(AQWANOT) Joint Industry

Project. SPE ESP Forum, 1996.

Veil, J., et al. Feasibility

Evaluation of Downhole Oil/Water

Separation (DOWS) Technology.

Prepared by Argonne National

Laboratory, CH2M Hill, and

Nebraska Oil and Gas

Conservation Commission, for

the U.S. Department of Energy,

Office of Fossil Energy, 1/99.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Gravity separation in the well

casing allows the produced

fluids to separate naturally

in the well casing, then uses

a dual-action pump system

(DAPS) to pump the oil up

and inject the water downhole. The DAPS has two

pump intakes that are positioned above and below the

oil/water interface. 

Hydrocyclone separation is a

promising technique that

uses centrifugal force to separate oil and water. Most

such systems rely on electrical submersible pumps

(ESPs) to push or pull water

through the hydrocyclone.

While this approach can

handle larger volumes of

fluids, the higher cost of the

hydrocyclone and pump

equipment has limited its

use to date. 

Although developed initially for onshore application,

rapid advances in downhole

separation technologies are

heightening interest in offshore use. For example, a

new generation of “intelligent,” computer-driven

subsea downhole separation

systems, currently under

development, will remotely

monitor and control fluid

flow and downhole injection. These systems promise

to be particularly useful in

multilateral environments,

by controlling downhole

water injection into a dedicated lateral strategically

placed to enhance waterflooding and pressure

maintenance. 

METRICS

Field trials in Canada and the United States

show increased oil production and decreased

water production

Source: Argonne National Laboratory, 1999

150

Wells using

Gravity Separator

Oil Production Water Production

Wells using

Hydrocyclone

100

50

0

-50

-100

-150

Talisman Energy

Tidewater Parkman

4-27

Texaco RMOTC

77 Ax20

Anderson

08-17

Talisman Energy

Creelman 3c7-12/dB

(106) (100)

(50)

(–95) (–93) (–80)

(–45)

(145)
Implementation helps offshore operators avoid costly 

injuries, platform damage, and environmental incidents

P RODUCTION

ct

P RODUCTION

Offshore operations represent over one quarter of

the Nation’s oil and natural gas production. Since

the early 1990s, Federal

regulators and industry

have successfully cooperated in the development

and implementation of

recommended practices

for voluntary safety and

environmental management programs (SEMP)

for Outer Continental

Shelf (OCS) operations.

Using the SEMP approach,

industry is responsible for

voluntarily identifying

potential hazards in the

design, construction, and

operation of offshore platforms and for implementing specific processes to

improve safety and environmental protection.

These measures are

designed to reduce the

risk and occurrence of

accidents, injuries, and

oil spills. By 1997, almost

all OCS production operators were in the process

of voluntary SEMP

implementation. 

Standards and training 

reduce human error

RESEARCH INDICATESthat nearly  percent

of offshore accidents are

caused by human error, even

when operations are fully

compliant with regulations.

In response to these risks,

Minerals Management

Service, in partnership with

the American Petroleum

Institute (API) and the

Offshore Operator’s

Committee, has delineated

voluntary standards that

address human and organizational errors and help

ensure worker safety and

environmental protection as

primary operating goals

among offshore producers.

Recommended Practice for

Development of a Safety and

Environmental Management

Plan for Outer Continental

Shelf Operations and Facilities

(RP ), first issued by API

in , provides safety and

operating guidelines for offshore operators of all sizes.

These guidelines are especially valuable to small- and

mid-sized producers, who

may lack the resources and

experience of larger companies in developing and

implementing such policies.

This cooperative relationship between industry and

government represents a

successful alternative to prescriptive regulations, with

MMS’ collaboration encouraging industry to focus on

risk identification and mitigation instead of mere compliance. Because of widespread RP  implementation, MMS has recently

announced the continuation

of its voluntary partnership

with industry and sponsorship of joint industry workshops to share best management practices. 

Safety and Environmental

Management Programs

U.S. Offshore (Gulf of Mexico, California, and Alaska)

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced risk of spills, fugitive air emissions,

blowouts, and accidents

Better protection of sensitive marine ecosystems and habitats

Enhanced worker safety, leading to fewer 

job-related injuries and illnesses

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Fewer accidents and equipment failures, thereby

reducing operating and remediation costs

Potential avoidance of fines and litigation due to

reduced risk of accidents and pollution

“We have seen strong evidence

that adoption of SEMP can

not only accomplish public

objectives in the areas of

promoting safety and environmental protection... it can

also make good business

sense by avoiding or containing accident and pollution

costs. The vast majority of

OCS operators have undertaken, in earnest, to develop

and implement SEMP plans.” 

Minerals Management Service, 62

Federal Register 43346, 8/13/97, 
P RODUCTION

DOE and its partners blaze a trail to safety

To allay small- and mid-sized producers’ concerns over the perceived

costs and burdens of RP , DOE recently supported a real-world

pilot implementation project with Louisiana-based Taylor Energy

Company. The goal was to develop a single-model SEMP that could

be shared throughout the industry, streamlining redundancies and

reducing costs, particularly for smaller, independent companies. 

Taylor, assisted by subcontractor Paragon Engineering Services, Inc.,

developed and implemented an -part SEMP at seven offshore platforms in the Gulf of Mexico. First, existing site safety procedures were

updated for incorporation into the new safety program. Next, Taylor

developed company-wide documentation of its safety and environmental program management, safety procedures, and safe drilling and

workover practices, as well as a pocket-sized safety handbook summarizing these practices. In addition, Taylor performed risk-based hazard

analyses at each site and issued site-specific operating procedures for

startup, normal, and emergency response. Employee training on these

general safety guidelines and all site-specific safety practice followed.

Finally, Taylor audited the program to verify its successful implementation, using an OSHA-based audit protocol that included document

review, visual inspection, interviews, and written testing. 

While long-term outcomes are pending, Taylor’s lost-time accident

rate declined significantly at the pilot sites over the -month project

period. DOE and MMS expect similar experiences at other companies, including eventual operating cost reductions due to SEMP and

the resulting downward trend in accidents. 

Taylor is sharing its experience and offering recommendations to 

others in DOE- and MMS-sponsored workshops and publications,

including technical conferences, trade shows, and leading trade 

journals. These presentations have enabled many small- and midsized producers to learn firsthand about the program, leading to more

effective SEMP implementation at their own facilities.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Crow, P. New Slant on Safety.

Oil & Gas Journal, 7/22/96. 

Demonstration of a Safety and

Environmental Management

Program (SEMP) for Offshore Oil

and Gas Producing Operations

on the Outer Continental Shelf.

BDM-Oklahoma, Inc., 1/98.

DOE/Taylor SEMP Case Study

Technology Transfer Report.

Taylor Energy Company and

Paragon Engineering Services,

Inc., 6/96.

Moritis, G. Upstream Safety

Management Strives to Reduce

Risk to Personnel and Environment. Oil & Gas Journal,

1/16/95.

Parker, W., and S. Hanus. Safety

Procedures Plan Provides

Platform-to-Platform Uniformity.

Offshore Magazine, 2/97.

Safety and Environmental

Management Program. Minerals

Management Service.

U.S. Department of Energy. DOE

Teams with MMS to Document

Model Safety Practices for

Offshore Oil, Gas Producers.

DOE Fossil Energy Techline,

4/27/95.

Watson, L., et al. Managing

SEMP On-Line. SPE 37922, 1997.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

An effective plan addresses how to:

• Operate and maintain facility equipment

• Identify and mitigate safety and environmental hazards

• Change operating equipment, processes, and personnel

• Respond to and investigate accidents

• Purchase equipment and supplies

• Work with contractors

• Train personnel

A fully implemented SEMP covers all phases of offshore

operations, including design, construction, startup, operation,

inspection, and maintenance of new, existing, or modified

drilling and production facilities. (API RP 75)

©SPE, 1993
Vapor recovery units cut up to 95 percent of light 

hydrocarbon vapors vented from crude oil storage 

tanks, while recovering valuable gas 

P RODUCTION

cu

P RODUCTION

Vapor recovery units can

significantly reduce the

fugitive hydrocarbon

emissions vaporizing from

crude oil storage tanks,

particularly tanks associated with high-pressure

reservoirs, high vapor

releases, and larger operations. These emissions are

typically made up of 40 to

60 percent methane, a

potent greenhouse gas,

along with other volatile

organic compounds

(VOCs), and hazardous air

pollutants (HAPs). U.S.

crude oil storage tanks

emit an estimated 26.6 billion cubic feet of methane

per year, representing a

significant portion of the

oil and gas industry’s total

annual methane emissions. While vapor recovery units are only feasible

for a minority of existing

tanks, this technology can

capture over 95 percent of

these emissions and compress them for use on-site

or for sale. These units

help protect our environment from harmful air pollutants and greenhouse

gases.

Resources that vanish 

into thin air

CRUDE OIL STORAGEtanks hold oil for brief

periods of time to stabilize

flow between production

wells and pipeline or truck

transport. During storage,

light hydrocarbons dissolved

in the oil vaporize and collect below the tank roof. 

The chief component of 

this gas is typically methane,

although other gases such as

propane, butane, ethane,

nitrogen, and carbon dioxide

may be present. These

vapors also contain HAPs

such as the BTEX compounds (benzene, toluene,

ethylbenzene, and xylene).

As the oil level in the tank

fluctuates, these vapors often

escape into the air, either

through flash losses (due to 

pressure changes during

transfer of crude oil), working losses (due to the changing fluid levels and agitation

of tank contents associated

with the circulation of new

crude through the tank), or

breathing losses (due to daily

and seasonal temperature

and pressure variations). The

amount of gas lost depends

on the stored oil’s gravity,

the tank’s throughput rate,

and the operating temperature and pressure of the oil

being added.

The advantages of 

vapor recovery

Vapor recovery systems can

capture more than 

percent of these fugitive

emissions and recover 

substantial amounts of gas

for use or sale. In addition to

onshore use, they are also

employed in offshore settings such as marine crude

oil loading terminals.

Producers may opt to pipe

the recovered vapors to natural gas gathering pipelines

for sale as a high Btu-content natural gas, or to use

the gas to fuel on-site operations. Alternatively, they may

strip the vapors to separate

natural gas liquids (NGLs)

and methane. In some cases,

vapor recovery units will

reduce emissions to below

the actionable levels set out

in Title V of the  Clean

Air Act Amendments. By

installing vapor recovery 

systems, producers may be

able to avoid permitting

charges, emissions fees, and

other regulatory costs.

Vapor Recovery Units

Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Significantly reduced greenhouse gas 

emissions

Improved local air quality, due to reduced

emissions of VOCs and HAPs

Optimized recovery of a valuable 

natural resource

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Lower operating costs if captured gas is used to

fuel on-site equipment

Gas recovered for sale as a high-Btu natural gas

Gas recovered and stripped to separate NGLs and

methane, if volume and NGL prices are sufficient

Potential avoidance of regulatory permitting and

compliance costs
P RODUCTION

Vapor recovery units succeed in the

Austin Chalk field

In –, Union Pacific Resources (UPR) installed  vapor

recovery units on its crude stock tanks in the Austin Chalk.

UPR’s horizontal wells in the area are high-rate producers with

high gas-to-oil ratios. Under these conditions, gas-oil separation

is difficult, leading to high volumes of gas in the tanks. The

vapor recovery systems proved very effective in reducing high

emissions levels and generating profits. UPR recovered an average of , thousand cubic feet of gas per day, equivalent to the

annual gas consumption of  residential consumers. The recovered natural gas netted UPR an additional , in revenue

over a one-year period.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

H. William Hochheiser

(202) 586-5614

william.hochheiser@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Alyeska Pipeline Starts Up

Tanker Vapor-Control System at

Valdez Terminal. Oil & Gas

Journal, 5/11/98.

Lindsey, R., and D. Lucas. Heavy

Oil Vapor Study. SPE 37886,

1997.

Liu, D., and J. Meachen, Jr. The

Use of Vapor Recovery Units in

the Austin Chalk Field. SPE

26595, 1993.

Meehan, D. Technology Vital for

Horizontal Well Success. Oil &

Gas Journal, 12/11/95.

Nielsen, R., et al. Deepwater

Production Drives Design of

New Gulf Gas Plant. Oil & Gas

Journal, 3/16/98.

Newsom, V. Determination of

Methane Emissions from Crude

Oil Stock Tanks. SPE 37930,

1997.

United States Environmental

Protection Agency. Lessons

Learned from Natural Gas STAR

Partners: Installing Vapor

Recovery Units on Crude Oil

Storage Tanks. 9/97.

Vapor Recovery Unit Saves

53,000 Bbl During Tanker

Loading. Offshore Magazine,

8/97.

Webb, W. Vapor Jet System: An

Alternative Vapor Recovery

Method. SPE 25942, 1993.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

In a typical recovery system, hydrocarbon vapors are drawn from

the storage tank under low pressure, usually between 0.25 and

2 psi, then piped to a separator “suction scrubber,” which collects

any condensed liquids. Any recovered liquids are usually recycled

back to the storage tank. The vapors then are compressed, metered,

reused, or resold.

To prevent the creation of a vacuum in the top of the storage tank

as vapors are removed, the unit is equipped with controls that shut

down the compressor, permitting reflow of vapors into the tank as

necessary. These systems can recover practically all the hydrocarbon

vapors that would otherwise be lost to the atmosphere with negative environmental impacts. 

HOW THE TECHNOLOGY WORKS

Crude Oil

Stock Tank(s)

Condensate

Return

Liquid

Transfer

Pump

Check

Valve

Bypass Valve

Electric

Control

Panel

Gas

Gas Sales

Meter Run

Electric Driven

Rotary Compressor

Vent Line

Back Pressure

Valve

Control

Pilot

Vapor Recovery Unit

Suction

Line

Suction

Scrubber

■ Major areas of oil

and gas potential
Advanced technology and practices underscore a widespread commitment to environmental excellence

S ITE

R ESTORATION

dl

S ITE R ESTORATION

At the end of an oil or gas

well’s economic life, typically spanning 15 to 30

years, the well must be

plugged and abandoned,

all production equipment

removed, and the surrounding area restored as

closely as possible to its

original state to prevent

potential environmental or

public health risks. To

ensure the future ecological and economic viability

of closed site lands, the

industry is continually

developing and applying

innovative site restoration

practices and technologies, including Risk-Based

Corrective Action, soil

bioremediation, and 

wetlands restoration. In

addition, operators are

actively supporting

industry-led clean-up

efforts such as those

being carried out by the

Oklahoma Energy

Resources Board, a 

privatized state agency

funded solely by industry’s

voluntary contributions. 

Closing sites 

OF APPROXIMATELY. million oil and gas

wells drilled in the United

States since , more than 

. million have been plugged

and abandoned—a complex

effort involving significant

planning and expense.

Onshore, wellbores are permanently plugged with

cement to prevent any flow of

subterranean fluids into the

wellbore, thereby protecting

groundwater. Waste-handling

pits are closed, and storage

tanks, wellheads, processing

equipment, and pumpjacks

removed. Offshore, wellbores

are sealed below the sea floor

and platforms are fully or

partially removed, or toppled

in place as part of artificial

reef programs. About ,

onshore wells are plugged and

abandoned annually, and 

offshore platforms decommissioned each year.

Unplugged or orphaned wells

with no existing owner or

operator are largely a legacy

of historic operations, when

site restoration was not considered necessary. Today, a

new approach to restoration

integrates advanced technology,

increased research and development, and a spirit of voluntarism and responsibility.

An exemplary model

A highly effective industryled site restoration program is

run by the Oklahoma Energy

Resources Board (OERB),

with near-unanimous support

from Oklahoma producers

and royalty owners, whose

annual voluntary contributions solely fund this unique

initiative. Since , this privatized state agency has

restored more than ,

orphaned and abandoned

well sites across Oklahoma—

with  more sites under

way—mitigating potential

health and environmental

risks and restoring blighted

lands to the benefit of

landowners, the community,

and the environment, at no

cost to the landowner.

OERB’s success demonstrates

industry’s commitment to

preserving the lands on which

it operates.

Diverse approaches

Rather than employing a

“one-size-fits-all” approach to

site restoration, industry is

turning to flexible Risk-Based

Corrective Action (RBCA)

processes to ensure swift, 

efficient clean-ups. A joint

American Petroleum

Institute-Gas Research

Institute (GRI) project has

resulted in development of an

E&P-specific set of RBCA

tools to help operators undertake risk-based remedial planning. In this approach,

Advanced Approaches

to Site Restoration

Locations: Worldwide, onshore and offshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Mitigation of potential public health and environmental risks

Restoration of sensitive habitats and ecosystems

Organic cleaning of petroleum-stained soil

through bioremediation, maintaining and

sometimes even improving soil health

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Reduced long-term environmental clean-up

costs and lowered risk of future liability 

Increased economic value of land returned to

productive agricultural, residential, or commercial uses
S ITE R ESTORATION

Proactive, global, site restoration 

Together with other companies and the State of California,

Phillips Petroleum is leading the restoration of the abandoned

-acre Bolsa Chica oil field near Huntington Beach, California.

The project includes cleaning up old well sites and building a

tidal inlet where waterfowl can rest and feed before migrating

, miles across the Pacific Flyway. 

In Phu Khieo, Thailand, Texaco restored a nonproductive

exploratory drill site, although not legally obligated under Thai

law, by treating drilling wastes, capping the site with clean topsoil,

and building dikes to support rice paddies and sugar cane fields.

The Thai government has since proposed Texaco’s approach as a

regulatory environmental management model. 

Working with Kansas State agencies, Mobil E&P U.S., Inc. bioremediated hydrocarbon-stained soils at its Hugoton Gas Field.

Using cow manure as a soil nutrient and microbial base catalyst,

total petroleum hydrocarbon levels were reduced by more than 

percent. At the project’s conclusion, native grasses were planted to

re-vegetate the area. 

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Chamberlain, D., et al.

Vegetative Restoration at

Petroleum Exploratory Drillsites

in the Ecuadorian Amazon.

Society for Ecological

Restoration International

Conference, Seattle,

Washington, 9/95.

DeVaull, G., et al. Risk-Based

Corrective Action Tools for

Exploration and Production

Facilities. Gas Research Institute,

www.gri.org

Exxon Corporation. Environment,

Health and Safety Progress Report. 

Oklahoma Energy Resources

Board, www.oerb.com

Phillips Petroleum Company.

1997 Health, Environment, and

Safety Report.

Robb III, A., and P. Hoggatt. 

A Cost Effective Bioremediation

Strategy Using Low Technology

Resources for Reclamation of

Dry Land Hydrocarbon

Contamination: A Case Study.

SPE 29759, 1995.

Rosenfeld, A., et al. Minimizing

the Environmental Impact of Oil

and Gas Developments in the

Tropics. Hart’s Petroleum

Engineer International, 7/97.

Shaffer, G., et al. Restored Drill

Cuttings for Wetlands Creation:

Year One Results of a

Mesocosm Approach to Emulate

Field Conditions Under Varying

Hydrologic Regimes.

Southeastern Louisiana

University, 12/96.

Shaw, B., et al. Microbes Safely,

Effectively Bioremediate Oil

Field Pits. Oil & Gas Journal,

1/30/95.

Texaco, Inc. Environment, Health

and Safety Review 1996.

SOURCES AND ADDITIONAL READING

CASE STUDIES

human-health and ecological-risk analyses and decisions are integrated with the

corrective action process,

ensuring that remedial measures are appropriate given a

specific site’s characteristics

and risk levels, and that

resources are focused first on

sites presenting the greatest

potential risk. 

Emerging bioremediation

technology is a cost-effective

tool with powerful environmental advantages. During

E&P operations, soil layers

can become stained with

hydrocarbon molecules ranging from heavy crudes to

volatile organic compounds.

Bioremediation involves

stimulating existing or placing carbon-eating microorganisms in stained soils to

digest excess hydrocarbons

or break them down into

simpler, non-toxic compounds

such as carbon dioxide and

water. Bioremediation maintains the microbial populations needed to keep soil

healthy, and can also

enhance soil health.

Within the natural gas

industry, R&D efforts focus

on remediating mercurycontaminated sites, which

can entail potentially significant environmental and

public health risks. In conjunction with DOE, GRI is

examining the extent of the

contamination, developing

risk-based prioritization

models, and testing

advanced remediation technologies, including physical

separation, chemical, and

thermal techniques. 

New techniques for restoring wetlands lost to saltwater encroachment are under

development. For example,

with assistance from DOEfunded research at

Southeastern Louisiana

University (SLU) is demonstrating that drill cuttings

can be safely used to restore

and create wetlands. Using

SLU’s unique temperaturecontrolled mesocosm greenhouse facilities to simulate

wetlands’ full range of tidal

fluctuations, researchers have

found that certain processed

drill cuttings appear capable

of supporting healthy wetlands vegetation.

Success in the Field
Converting obsolete platforms into artificial reefs benefits

marine habitats, commercial fishers, divers, vacationers,

and the oil and gas industry 

S ITE

R ESTORATION

dm

S ITE R ESTORATION

Industry, regulators, and

environmentalists now recognize the advantages of

toppling decommissioned

offshore platforms and

anchoring them on the sea

floor as permanent artificial

reefs. Under existing State

programs, oil and gas companies can donate platforms to States for use as

artificial reefs, along with a

percentage of their cost

savings to be used for reef

maintenance and development. Designed for marine

environments and impervious to displacement or

breakup, these steel platforms make ideal reefs.

Thriving habitats are typically well established on

working rigs, and dismantling and moving them

threatens these habitats.

To date, more than 100

donated offshore platforms

have been placed off the

coasts of Texas, Louisiana,

and other Gulf States,

where they host complex

ecosystems that attract fish

and enhance commercial

fishing and recreational

activities. 

Removing rigs 

THE U.S. MINERALSManagement Service

(MMS) requires removal of

all platforms in Outer

Continental Shelf (OCS)

waters within one year from

production shutdown.

Currently, platform removals

from the Gulf of Mexico

OCS are averaging  platforms per year. MMS estimates that over half of about

, remaining structures

will require removal by .

For smaller structures in shallow waters, companies typically dismantle the platform

using explosives, or sometimes torches or cutters, and

then tow the deck and jacket

to shore for refurbishment or

scrapping. This option is

often elected when the platform is not located near a

“rigs to reefs” zone. 

Creating artificial reefs

When decommissioning in

deeper waters (generally

beyond  feet) at more

remote locations, operators

can reduce removal costs significantly by toppling structures (fully or partially) in

place as artificial reefs, or

towing them to a designated

site for toppling. To date,

about  percent of the Gulf’s

platform removals have been

converted to artificial reefs;

this percentage is expected to

increase as more decommissioned deepwater platforms

require removal.

The typical -story steel

jackets that support offshore

platforms provide acres of

habitat for various underwater flora and fish species—

within six months to one year

of initial placement, platforms

are covered with marine life.

The submerged hard surfaces

invite invertebrates such as

barnacles, corals, sponges,

clams, bryo-zoans and

hybroids, which in turn

attract resident reef fish such

as snapper and grouper and

transients like mackerel and

billfish. Fish are also drawn by

Rigs to Reefs

Locations: Gulf of Mexico

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Enhanced protection and nurture of complex

marine ecosystems and habitats

Creation of new marine habitats

Reduced impacts of platform demolition and

relocation

Increased recreational use of water resources

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Potential for significant reductions in platform

removal and disposal costs, particularly in

locations where partial removal is viable

Industry cost savings fund State reef maintenance and development programs

Enhancement of commercial fishing 

opportunities 

Promotion of local tourism through enhanced

recreational fishing and diving opportunities
S ITE R ESTORATION

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Susan Gregersen

(202) 586-0063

susan.gregersen@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

SOURCES AND ADDITIONAL READING CONTACT

Rig reefs boost tourism in South Texas 

Mobil Exploration and Production U.S., Inc., performed an environmentally outstanding conversion in . Over a -day period,

Mobil dismantled six platforms located in several South Padre Island

blocks, moving four jackets  miles to Port Mansfield Liberty Ship

Reef and two jackets  miles to Port Isabel. Mobil elected to cut

away the platform legs rather than blast them, despite explosives

being cheaper, faster, and more reliable. Mechanical cutting avoided

undue harm and disruption to the rich marine life inhabiting the

rigs offshore environmentally sensitive South Padre Island. 

The added time and expense of cutting and transport negated any

cost savings, but Mobil still earned tremendous payback. Jeffrey

Passmore of Mobil noted: “We were able. . .to give. . .structures with

 to  years of [marine habitat] buildup on them.” Jan Culbertson,

Texas Parks and Wildlife Department, commented, “We almost

begged Mobil to take the structures to Port Isabel. That’s where our

tourism dollars are. Mobil bent over backward to give us their structures in a natural state with no animals hurt or removed. We even

had turtles living on the structures that we had to move out of the

way. All the animals, the little blennies [fish] that were inside the

barnacles, all made it to their new reef-site home.”

Artificial Reefs: Oases for Marine

Life in the Gulf. MMS Feature

Stories, 3/18/94.

Gulf of Mexico Artificial-Reef

Programs Benefit Industry, Local

Economies, and the

Environment. Journal of

Petroleum Technology, 1/95.

Kebodeaux, T. Death of a

Platform: Artificial reef programs

provide a rebirth to decommissioned structures. Underwater

Magazine, Spring 1995.

Moritis, G. Gulf of Mexico

Platform Operators Cope with

Abandonment Issues. Oil & Gas

Journal, 5/6/96.

Moritis, G. Industry Tackles

Offshore Decommissioning. Oil

& Gas Journal, 12/8/97.

Perry III, A., et al. Amoco

Eugene Island 367 Jacket

Sectioned, Toppled in Place. Oil

& Gas Journal, 5/1/98.

Pulsipher, A., et al. Explosives

Remain Preferred Method for

Platform Abandonment. Oil &

Gas Journal, 5/6/98.

Success in the Field

CASE STUDIES

the shape, size, and openness of these structures,

which attract an estimated

 to  times more fish

than the Gulf’s naturally

flat, soft bottom.

Removing platforms after

shutdown threatens these

complex fish populations as

well as the commercial and

recreational industries that

rely on them. Through “rigs

to reefs,” industry and State

governments are collaborating to ensure the greatest

possible number of platform

conversions, thereby protecting rich marine ecosystems

and enriching the Gulf’s

commercial fishing and

recreational opportunities. 

The first planned rigs-toreefs conversion took place

in , when an Exxonowned subsea template

located offshore Louisiana

was moved to offshore

Florida. The National

Fishing Enhancement Act,

passed in , led to the

development of the

National Artificial Reef

Program and formal support from MMS. State programs followed in Louisiana

() and Texas ();

Mississippi, Alabama, and

Florida have since formed

their own programs. Today,

artificial reefs exist around

the world, with the Gulf of

Mexico boasting the most

extensive and successful

conversions.

United States

Gulf of

Mexico
Crude oil residuals and produced water can be safely and

creatively recycled for road building, stabilization, de-icing,

and dust suppression

S ITE

R ESTORATION

dn

S ITE R ESTORATION

Tank cleaning and other

common exploration and

production operations routinely generate large amounts

of non-hazardous crude oil

wastes sometimes suitable

for use as road paving (road

mix) materials. These hydrocarbon residuals act as

binders, and can be mixed onsite with native soils or

imported aggregate, then

safely paved into roads.

Similarly, another routine oilfield waste, produced water—

the brine or brackish water

extracted with oil or gas during the production process—

can be used for road de-icing

or dust control. Road mixing

and spreading technology

provides useful products,

significant disposal costsavings for producers, and

conservation of limited

landfill capacity. Minimizing

landfill use also significantly

reduces the potential for reactive hydrocarbon emissions

and soil and water contamination. While this practice

promises environmental

benefits under certain conditions, application is limited

and discrimination necessary.

Creative use of oilfield waste

AS LANDFILL ANDother traditional disposal

methods become more limited and costly, in some areas

the petroleum industry is

increasingly recycling various

oilfield wastes as road mix

material. 

Paralleling the commercial

road mixing process, the

petroleum industry mixes

crude oil residuals from tank

cleaning, sump abandonments, and production flowline leaks with imported

aggregate (coarse binding

materials) or native soils for

light duty road paving or dust

suppression.

Tank residuals are the largest

source of recycled binding

agents. These residuals, made

up of fine sediments or sands

and heavy, low-volatility

hydrocarbons that settle during storage, are periodically

cleaned out of tanks by highpressure water jets, creating a

slurry that is dewatered to

make sludge. The sludge—

with cohesive and adhesive

properties similar to commercial road mix materials—is

mixed with aggregate, graded,

and cured.

The resulting road mix can

either be stockpiled or

applied immediately with

standard paver/spreader

equipment, and compacted if

necessary. Depending on final

use, the hydrocarbon content

of the raw materials, and the

type of road mix needed,

petroleum facilities may add

commercial asphalt cements

to their road mix.

Other oilfield wastes, such as

completion and workover fluids and produced brine, are

also suitable for roadspreading to suppress dust or de-ice

unpaved roads. In northern

Road Mix and

Roadspreading

Locations: United States

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced waste volumes to landfill or reinject

into the earth’s subsurface, thus reducing

potential environmental risks and future liability

Reduced dust and particulate matter emissions

from unpaved roads 

Greatly reduced reactive organic hydrocarbon

compound emissions, compared with landfill

disposal

Demonstrated low hydrocarbon and metal

leachability 

Demonstrated nonhazardous by acute aquatic

testing

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Significant reduction in costs and potential 

liability associated with management and 

disposal of nonhazardous oilfield wastes 

More expensive alternatives such as paving

would be necessary without recycled road mix

Landfill space conserved 

Conservation of natural resources through 

product substitution
S ITE R ESTORATION

Roadspreading in Pennsylvania

A portion of the . million barrels of brine produced annually

by Pennsylvania’s oil and gas wells is spread on its unpaved

secondary roads for dust suppression and road stabilization.

To minimize environmental impacts from this practice, including the risk of contaminants leaching into surface or ground

waters, the Pennsylvania Department of Environmental

Protection (DEP) has developed mandatory roadspreading

guidelines for brine generators, transporters, applicators, and

roadway administrators. 

Funded by a Federal Clean Water Act grant, the DEP tested

water quality impacts along seven unpaved roadways in western

Pennsylvania on which brine had been spread. Between 

and , surface water samples were taken from culverts, roadside ditches, streams, and ponds at the selected road sites, while

groundwater was sampled from monitoring wells installed to

measure the impact of brine-spreading on water quality. Over

the sampling period, lysimeters were used to determine whether

brine had migrated from the roadbed. Soil and roadbed samples

were also taken to identify any leaching or accumulation of

heavy metals or other harmful pollutants. Through monitoring

and subsequent analyses, the DEP concluded that although

potential exists for harm to surface water and groundwater from

brine migration or run-off, risks could be significantly minimized by controlling the frequency and application rate of brine

and by following the roadspreading guidelines. Roadspreading

offers a cost-effective means to recycle and dispose of a portion

of Pennsylvania’s produced water waste stream, with minimal

environmental impact.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Cal/EPA Exploration and

Production Regulatory Task

Force. Beneficial Use of Road

Mix: Clarification of Issues and

Regulatory Roles. 12/96.

Cornwell, J. Road Mixing Sand

Produced From Steamdrive

Operations. SPE 25930, 1993.

Hampton, P., et al. Minimization

and Recycling of Drilling Waste

on the Alaskan North Slope. SPE

20428, 1991.

Kabrick, R., and L. Rogers.

Innovative Treatment

Alternatives for Oily Wastes

Generated During the

Exploration and Production of

Oil and Gas. SPE 24564, 1992.

Pennsylvania Department of

Environmental Protection.

Bureau of Oil and Gas

Management. Fact Sheet: NonPoint Source Report on

Roadspreading of Brine for Dust

Control and Road Stabilization.

Western States Petroleum

Association. Evaluation and

Review of the Petroleum

Industry’s Road Mix Process.

3/93.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

States, using these wastes to

de-ice roads instead of salt

can conserve this limited

natural resource. 

Today, the petroleum

industry uses most of its

recycled road mix to develop access roads to remote

exploration and production

sites and to control dust in

production areas. California

operators have been using

crude oil-impacted waste

materials as road mix for

nearly a century with no

adverse environmental

impacts. Similarly, brine

spreading to stabilize roadways and control dust has

been used effectively in certain areas for years. The primary alternatives to road

mixing and roadspreading

are landfilling the solid

wastes at an average cost of

 per ton, and subsurface

reinjection of produced

water for disposal or

enhanced oil recovery, also

very costly. 
Strategic alliances leverage DOE and BLM resources 

and expertise to protect cultural resources and 

sensitive environments

S ENSITIVE E NVIRONMENTS

do

S ENSITIVE E NVIRONMENTS

The Bureau of Land

Management (BLM) and

the Department of Energy

(DOE) have joined forces

to enhance protection of

environmental and cultural

resources on sensitive

public lands. In these joint

projects, advanced technologies and practices are

shared across BLM, DOE,

and the oil and gas industry to improve resource

management and access

to Federal lands. Currently,

teams are studying issues

such as the reversal of

subsurface damage to

freshwater aquifers at

abandoned well sites in

Oklahoma, the protection

of archaeological remains

in Nevada, and the

improvement of air quality

monitoring in remote

Wyoming locations. In

concert with Federal agencies striving to balance

competing demands for

the use of public lands,

the DOE/BLM partnership

seeks to ensure maximum

resource recovery consistent with high levels of

environmental protection

and cultural sensitivity.

The role of BLM

BLM OVERSEES 

million acres of Federal

land and  million acres of

subsurface mineral resources,

primarily in the western

United States and Alaska,

about an eighth of the land in

the United States. Federal

lands under BLM oversight

include extensive grasslands,

forests, high mountains, arctic tundra, and deserts, as

well as many fish and wildlife

habitats and archaeological

and historical sites. These

lands contain subsurface

resources amounting to eight

percent of the natural gas 

and five percent of the crude

oil produced annually, in

addition to resources like

coal, forest products, grazing

forage, and rights-of-way for

pipelines and transmission

lines. Of the total . billion

in annual revenues these

lands bring, nearly  million, or  percent, is generated by royalties, rents,

bonuses, sales, and fees from

oil and gas operations. The

total direct and indirect economic output of oil and gas

production is estimated at

nearly  billion annually.

The role of DOE

DOE and BLM have entered

into a memorandum of

understanding (MOU) to

help improve access to Federal

land for oil and gas development, consistent with effective

environmental protection.

This includes technology

transfer, data sharing, technical support, and sharing of

expertise. Cooperative efforts

under this agreement have

included DOE participation

on BLM streamlining and

environmental incentives

teams and BLM contributions

to DOE’s oil and gas databases. In addition, as part of

the MOU activities, DOE

and BLM have formed a

Federal Lands Technology

Partnership to address access

issues and provide technical

support to Federal land managers. Fiscal year  was the

first year of DOE funding

under this partnership. The

two agencies solicited projects

from BLM field offices and

worked together to prioritize

the proposals. Three resulting

projects initiated this year are

discussed here.

DOE-BLM Partnership

Locations: United States, onshore

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Greater protection of environmentally and 

culturally sensitive areas

Increased, more efficient recovery of oil and

gas on Federal lands

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Enhanced Federal revenues from increased oil

and gas production on public lands

Accelerated planning and permitting schedules,

reducing development costs and time
S ENSITIVE E NVIRONMENTS

Well decontamination in Oklahoma

BLM recently discovered brine and salt water contamination of

both soil and freshwater sources on land held in trust to the Pawnee

Indians in Payne County, Oklahoma. Today, BLM and DOE are

working together with the Oklahoma Energy Resources Board, 

an industry-funded, publicly chartered site restoration agency, to

reverse subsurface damage to a freshwater aquifer and to restore 

the area’s damaged grasses, shrubs, and trees. Knowledge gained 

in this project will apply to a wide range of water-injection and

water-disposal well problems, and technology developed for salvaging the contaminated aquifer will benefit other damaged sites 

on public lands.

Archaeological and resource development in Nevada

BLM, DOE, and state agencies in Nevada are developing a predictive geographical information system (GIS) model that will help

protect the rich archaeological remains of the northern Railroad

Valley in Nye County, Nevada. This will enhance access to the area’s

rich oil and gas resources, often restricted by concerns about archaeological remains. A potentially powerful management tool, the

model provides critical information on both subsurface resources

and cultural sites, making it easier to determine lease boundaries,

isolate sensitive areas, and accelerate resource development. For

example, by identifying the likelihood of precious cultural resources

in a specific area within the Nye Valley, the model will improve the

routing of access roads and pad orientation, and help manage

resource, range, wildlife, and recreation programs. 

Air quality monitoring in Wyoming

Since ongoing air quality data is often unavailable in many remote

areas, it is becoming increasingly difficult for land management

agencies to complete air quality impact assessments required as

part of Environmental Impact Statements (EIS). Because new oil

and gas development projects are permitted only on condition

that air quality will not significantly deteriorate, future access to

some resources may be denied where air monitoring data are

insufficient, even in areas where actual air quality impacts would

be minimal.

To address this concern, BLM and DOE, in collaboration with

other agencies, are establishing a network of low-cost, portable,

solar-powered monitoring stations in southwestern Wyoming,

which has seen a marked increase in oil and gas development

over the last five years. These stations will measure ambient air

concentrations and calculate dry deposition of nitrogen oxides

and sulfur oxides in remote areas where environmental concerns

are high and development is likely to increase. This will greatly

enhance permitting decisions and EIS preparation. Five aerometric stations currently used to measure climate and air quality parameters will be converted for operational air quality monitoring.

Three will be mobile; the other two will remain fixed to provide

long-term air quality data.

CONTACT

DOE Office of Natural Gas and

Petroleum Technologies. Oil and

Gas Technology Partnership for

Federal Lands.

Hochheiser, H. W. Achieving

Effective Environmental

Protection: An Update on DOE’s

Environmental Research and

Analysis Program. Paper presented at the 5th International

Petroleum Environmental

Conference, 10/98.

United States Department of the

Interior. Bureau of Land

Management. Working Together

for the Health of the America’s

Public Lands, 1997 Annual

Report.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

H. William Hochheiser

(202) 586-5614

william.hochheiser@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov
Cooperative planning, advanced technology, and detailed 

habitat enhancement render operations virtually invisible

S ENSITIVE E NVIRONMENTS

dp

S ENSITIVE E NVIRONMENTS

From Alabama’s Mobile

Bay to the North Irish Sea,

operators are employing

advanced exploration,

drilling, production, and

site restoration techniques

to protect sensitive coastal

wetlands and nearshore

environments. For example, through collaborative

planning with several

Federal and State agencies

and state-of-the-art drilling

and site restoration technologies, Bright & Co.

drilled an environmentally

unobtrusive exploratory

well on the Padre Island

National Seashore. In conformance with extensive

regulatory requirements,

every phase of Bright’s

operation was designed to

minimize environmental

impacts, leaving virtually no

footprint on the area.

Although no hydrocarbon

resources were found, the

undertaking demonstrated

that exploratory drilling

can be done without 

disturbing coastal 

environments. The use 

of advanced technology

helps preserve delicate

ecosystems.

Gulf coast breakthrough

AFE D E R A L LY M A N AG E Drecreational area and

wildlife and nature preserve,

Padre Island National Seashore

has , acres of beaches,

grasslands, tidal flats, dunes,

and ponds that are home to a

huge variety of plant life as well

as marine life, reptiles, sea 

turtles, coyotes, waterfowl, and

more than  species of birds,

including some threatened or

endangered species. Hiking,

camping, fishing, nature

studies, and water sports attract

some , visitors annually.

This -mile long barrier island

sits four feet above an underground freshwater aquifer,

which is the primary source of

drinking water for area wildlife

and thus critical to the island’s

ecosystem. The island is also 

situated in a high-potential oil

and gas resource zone, challenging private parties who

own subsurface oil and gas

rights to develop these resources

under the strict environmental

regulatory oversight of several

Federal and State agencies,

including the U.S. Army Corps

of Engineers, the National Park

Service, and the Texas Railroad

Commission.

Planning for all contingencies

Before Bright & Co. could

begin drilling, the National

Park Service required a comprehensive plan of operations,

including a timetable and

description of all proposed

construction, drilling, 

completion, and production

activities; spill control and

site reclamation plans; environmental impact statements;

and documentation of the

archaeological and cultural

resources potentially affected

by the operations. Bright &

Co.’s plan included site management equipment to minimize the operation’s footprint

and safely manage wastes as

well as a directional drilling

strategy that would minimize

contact with sensitive wetlands

and environmental impacts.

Upon plan approval, Bright

& Co. also posted a ,

performance bond, the estimated maximum cost of site

reclamation and clean-up should

an oil spill occur. Finally, a

U.S. Army Corps of Engineers

permit to build an access road

across reclaimed wetlands was

obtained, requiring Bright &

Co. to compensate the .

acres of nontidal wetlands

lost to road construction with

. acres of new wetlands.

Coastal and Nearshore

Operations

Locations: Worldwide

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Virtually no footprint following operation

Habitats, wildlife, and cultural resources intact

and unmolested

Fresh and marine water resources meticulously

safeguarded

Reduced air emissions and lower risk of fuel

spills through use of electric equipment

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Sensitive project execution averted potential

negative impacts on a popular tourist area 

Cost-effective, low-impact operations proven

successful
S ENSITIVE E NVIRONMENTS

Advanced technology is enhancing access to oil and gas resources

while protecting sensitive coastal and wetlands ecosystems

throughout the United States:

In Mobile Bay, Alabama—a complex marine environment with

important commercial fisheries and recreational facilities—ARCO’s

Dauphin Island production facility has successfully minimized

visual and environmental impacts while developing the area’s rich

natural gas resources. Less than three miles from Dauphin Island

residents, the ARCO platform’s unique structural design minimizes

aesthetic drawbacks. The facility also used advanced horizontal

drilling techniques to reduce the production footprint.

Covering , acres in southwest Louisiana, the Sabine

National Wildlife Refuge sustains more than  species of birds,

alligators, and marsh mammals, and is a major wintering ground

for migratory waterfowl. In , Vastar Resources selected the

refuge’s Black Bayou as an exploratory prospect. In close cooperation with the U.S. Fish & Wildlife Service and other Federal and

State agencies, Vastar used innovative drilling, waste minimization,

and site restoration techniques to drill two exploratory wells in

this fragile coastal wetlands area, with minimal impacts. 

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Susan Gregersen

(202) 586-0063

susan.gregersen@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Browning, G., et al.

Environmental Considerations

for 3D Seismic in Louisiana

Wetlands. SPE 35781, 1996.

Hunt, M. Drilling Site on a

National Seashore Required

Extra Environmental

Precautions. Oil & Gas Journal,

11/6/95.

Kerns, J., and J. Parker.

Managing Exploration Activities

in Environmentally Sensitive

Inshore Waters. SPE 26749, 1993.

Kudla, M., and B. McDole.

Managing Drilling Operations 

in a Sensitive Wetlands

Environment. SPE 35780, 1996.

Layfield, R., et al. Dauphin Island

Natural Gas Project. Journal of

Petroleum Technology, 1/94.

Longfield III, H., et al. Economic

and Environmentally Beneficial

Reuse of Drilling Waste. SPE

25929, 1993.

Longfield III, H., and T. Akers.

Economic Environmental

Management of Drilling

Operations. SPE 23916, 1992.

Macduff-Duncan, C., and 

G. Davies. Managing Seismic

Exploration in a Nearshore

Environmentally Sensitive Area.

SPE 30431, 1995.

Ritchie, C., et al. Environmental

Impact of Offshore Operation

Reduced Using Innovative

Engineering Solutions. SPE

28736, 1994. 

Rymell, M., et al. Development

and Application of Environmental Models in the

Assessment of Exploratory

Drilling in a Sensitive Coastal

Region, Isle of Man, UK. SPE

37872, 1997.

SOURCES AND ADDITIONAL READING

Beyond South Padre Island

CASE STUDIES

A “no footprint” drilling site

Using , tons of imported,

compacted caliche, Bright

& Co. built a .-mile, 

-foot wide access road to

the drill site. They constructed a -foot square

caliche pad, covered by a

polyethylene liner, on which

they mounted the drill rig,

mud tanks, and pipe racks.

The company then built a

berm around the liner and

sloped the pad to capture

any discharges in a subsurface “cellar,” draining it with

a centrifugal pump. A threefoot high levee ringed the

pad perimeter, ensuring no

groundwater contamination.

Advanced technology at work

Mesa Drilling Inc. drilled the

well with a diesel-electric, silicon controlled rectifier unit,

significantly reducing noise

impact on visitors and

wildlife. Most of the rig’s

components were wheelmounted, thus minimizing

equipment mobilization

across the beach. Electric

mud pumps and draw works

reduced air emissions and

potential oil leaks. An

advanced closed-loop mud

system collected drill cuttings

in -barrel boxes mounted

on tracks for immediate

transport and disposal off site.

Bright & Co. employed

directional drilling to hit the

targeted pay zone—the Frio

Marg A sand at approximately

,-foot true vertical

depth—located beneath a

large wetlands area. Directional

drilling allowed Bright & Co.

to avoid reclaiming additional

wetlands for the drilling pad.

An  ⁄

-inch polycrystalline

diamond compact drill bit

was selected to maintain

direction and angle, prevent

formation damage, and minimize drilling time and air

emissions. At an average rate

of  feet per hour over 

days, the well was first drilled

vertically to , feet, then

angled  degrees per  feet,

reaching an ultimate angle of

 degrees and a measured

depth of , feet. When no

productive zones were found,

Bright & Co. plugged the

well, removed the pad and

access road, restored the

ground surface to its original

contours, and reseeded with

native grasses.
Extending the drilling season with insulated ice pads can 

minimize environmental disruption and exploratory drilling

footprints, while reducing costs 

S ENSITIVE E NVIRONMENTS

dq

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New, prefabricated insulation panels can be used to

preserve ice drilling pads

from arctic summer thaw,

thereby extending the

exploratory drilling season

as much as 50 percent.

Insulated pads permit ice

pad construction prior to

the winter drilling season,

enabling drilling operations to begin some two

months earlier than if 

the pad had been built 

in December for a midJanuary drilling start—

the typical exploratory

drilling schedule. The

extended season allows

single-season well completions, which reduce

seasonal equipment 

mobilization and environmental impacts, as well 

as associated costs.

Drilling in the Arctic

CLIMATIC CONDITIONSon Alaska’s North Slope

have restricted the exploratory

drilling season in remote

Arctic environments to  to

 days. The tundra has to

be frozen solid enough to

allow equipment transport to

the drilling site as well as 

sustainable ice road and ice

pad construction and maintenance. At its longest, the 

tundra travel season extends

from November through

May, although specific conditions dictate load weight on

any given date. At the drilling 

site, ice pad construction,

often as large as an acre,

is usually begun in early

December, although November is possible under optimal

conditions. By mid-May,

equipment must be removed

to a non-tundra area. While

conventional ice pads are far

less environmentally intrusive

and less costly than gravel

drilling pads, their impermanence means an additional

round of equipment demobilization and storage at an offsite gravel pad. If, as is common, the exploratory well is

not completed, remobilization the following season is

necessary. Such operations

entail environmental disturbance and additional costs.

Innovative insulated ice pads,

however, can extend the available drilling season to a total

of  days and effective well

operations up to  days,

potentially enabling completion of one or perhaps two

exploratory wells in a single

season. Single-season completions substantially reduce

mobilization costs and related

environmental effects, and

also cut time between initial

investment and returns.

Insulated Ice Pads

Locations: Alaska’s North Slope

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Smaller footprints and less time on-site

Elimination of seasonal equipment mobilization, minimizing environmental impacts on

land and air

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Single-season exploratory well completions,

greatly reducing mobilization costs

Valuable subsurface data one year earlier 

than would otherwise be possible, enhancing

operational planning
S ENSITIVE E NVIRONMENTS

Drilling two months earlier, 

saving more than $2.3 million

When a BP Exploration (Alaska) Inc. (BPXA) engineering

feasibility study indicated that constructing an insulated ice pad

in March  at Yukon Gold # on the North Slope would

significantly extend the winter drilling season, BPXA built a

-by--foot ice pad covered with nearly 600 wind-resistant

insulating panels. Summer visits confirmed that the ice beneath

the panels remained sufficiently frozen. When the panels were

disassembled in October , they had not bonded to the resting surface, or scattered, and nearly  percent were in excellent

condition and reusable.

BPXA began drilling in mid-November, two months ahead of

conventional Arctic practice. With such an early start, Yukon

Gold # was completed in time to begin drilling immediately at

nearby Sourdough #, where the insulated panels were placed

under the rig to give BPXA the option of leaving the rig on

location over the summer and avoiding remobilization should

the well not be completed before season’s end. This was not necessary, however, as the Sourdough well was also successfully

completed during the same season. 

Overall, BPXA netted a cost savings of more than . million

from the two single-season completions. In addition, the tundra

endured significantly less impact than would have been the case

had seasonal equipment mobilization been required. Subsequent

site monitoring showed no long-term environmental impacts.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur M. Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Hazen, B. Use of Ice Roads and

Ice Pads for Alaskan Arctic Oil

Exploration Projects.

Symposium paper for Science,

Traditional Knowledge, and the

Resources of the Northeast

Planning Area of the National

Petroleum Reserve-Alaska, 4/97.

Stanley, M., and B. Hazen.

Insulated Ice Pad Technology

Enables Extending Drilling on

Alaska’s North Slope. SPE

35686, 1996.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

METRICS

Results of a BPXA study, comparing drilling season length

using conventional practices versus insulated ice pads

Time Period Conventional Insulated Ice Pad

Construction start date December 1–15 Previous Winter

Start of rig mobility December 15–31 October 7–21

Spud date for first well January 15–31 November 7–21

Tundra-travel end of season April 29–May 22 April 29–May 22

End of well operations April 15–May 8 April 15–May 8

Total Season Available 135–170 days 175–205 days

Effective Well Operations Season 75–110 days 145–160 days

©SPE 35686, 1996

Alaska
Technology advances protect the environment and 

improve recovery under hostile arctic conditions

S ENSITIVE E NVIRONMENTS

dr

S ENSITIVE E NVIRONMENTS

North Slope oil and gas

operations showcase a

number of technological 

triumphs over powerful

natural forces, enabling

successful operations in

this extreme, sensitive 

environment. Since these

resources represent nearly a

quarter of U.S. oil reserves,

the need to access them

has accelerated development of environmentally

responsible, cost-effective

practices and technologies.

For instance, the difficulties

of winter exploration have

been mitigated by innovations such as ice roads 

and ice pads that have no

lasting effects on delicate

tundra. Drilling advances—

extended reach drilling,

coiled tubing drilling, multilateral completions and

“designer” wells—are increasing resource recovery

and reducing drilling costs,

footprints, and waste volumes. Today’s exploration

and production facilities

are radically streamlined,

occupying far less surface

area than operations did 

25 years ago.

Low-impact operations

increase resource recovery,

reduce costs, and protect 

sensitive habitats

T HE LARGEST OILfield in North America,

the North Slope’s Prudhoe

Bay has estimated total recoverable reserves of  billion

barrels of oil and  trillion

cubic feet of natural gas.

Alaska is also home to

diverse, unique, and fragile

ecosystems, inspiring extensive Federal, State, and local

regulatory protection. Since

the onset of the North Slope

oil boom in the late ,

operators have been forced to

develop more cost-effective,

less environmentally intrusive

ways to develop these

resources. For example, the

exploration sector has developed innovative ice-based

transportation infrastructure

serving remote locations, even

during winters characterized

by -°F temperatures, -

foot snowdrifts, and limited

daylight. In the , road

construction by bulldozing

tundra proved disastrous.

After only one season, the

route was impassable when

the permafrost thawed.

Operators turned to gravel to

insulate the permafrost and

stabilize roadbeds, airstrips,

and drilling pads, but gravel

mining and construction are

expensive and environmentally

harmful. In the last decade,

ice-based technology has

become the new standard for

exploration. Its low-cost, lowimpact performance continues to be refined by techniques like ice pad insulation,

which can extend drilling seasons and reduce equipment

mobilization. Where ice roads

are impractical, low-pressure

balloon-tire vehicles haul

loads, leaving practically no

footprint. 

Recent advances in drilling

technology are increasing

North Slope E&P productivity and protecting the environment. Through-tubing

rotary drilling, for example,

allows new wells to be drilled

through the production tubing of older wells, saving time

North Slope Operations

Locations: Alaska’s North Slope

BLUEPRINT ON TECHNOLOGY

TECHNOLOGY

SUMMARY

Reduced surface footprints and disturbance

Protection of sensitive habitats, wildlife, and

cultural resources

Greater access to resources with fewer wells

drilled, through advanced drilling technology

Reduced waste volumes requiring disposal,

through innovative waste management and

recycling techniques

ECONOMIC BENEFITS ENVIRONMENTAL BENEFITS

Enhanced resource recovery and more efficient

operations

Lower operating costs
S ENSITIVE E NVIRONMENTS

Improving waste management

North Slope operators are using advanced technology to manage

drilling wastes more effectively. A  ARCO pilot project

demonstrated that processed drill cuttings could be safely used as

road construction materials, since the cuttings’ composition was

essentially identical to that of native gravel and surface soils.

Based on these findings, in  BPXA built a prototype grinding and injection facility that recycled recovered cuttings into

construction gravel, and ground remaining waste for subsurface

reinjection. By , refined grind-and-inject technology enabled

BPXA and other Prudhoe Bay operators to achieve “zero discharge” of drilling wastes, eliminating the need for reserve pits.

These innovative strategies yield significant environmental benefits—decreased waste volumes, less mining of surface gravel,

smaller pad sizes, and less surface disturbance.

Restoring affected areas

The fragile North Slope ecosystem makes site restoration and

habitat enhancement a vital post-production process. In recent

years, BPXA and ARCO Alaska have created artificial lakes by

flooding abandoned gravel mining sites. This practice, encouraged by the Alaska Department of Fish and Game, creates overwintering habitats for fish and predator-free nesting areas for

waterfowl. BPXA and the U.S. Department of Fish and Wildlife

collaborated to restore  miles of habitat along Endicott Road,

demonstrating that transplanting Arctic pendant grass effectively

revegetated disturbed aquatic sites. This technique was also

applied at BPXA’s BP Pad, where restoration began in .

Within three years, native vegetation was restored.

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Arthur M. Hartstein

(301) 903-2760

arthur.hartstein@hq.doe.gov

Trudy A. Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov

CONTACT

Alaska Department of Natural

Resources, Division of Oil and

Gas. Evolution of Petroleum

Development Technology on

Alaska’s North Slope—Reduced

Impacts and Enhanced

Environmental Protection. 6/95.

Alaskan North Slope Operators

Shift Focus from Stemming

Decline to Hiking Production. 

Oil & Gas Journal, 8/24/98.

Atlantic Richfield Company.

www.arco.com

Bureau of Land Management.

BLM Announces New Planning

Effort for NPR-A. Alaska

Frontiers. January/February

1997.

Brinker, T. Construction of

Grounded Ice Island for Drilling

in Beaufort Sea, Alaska. SPE

8915, 1980.

Bureau of Land Management.

NPR-A: A Briefing Book, 11/96.

North Slope Fact Sheets. BP

Exploration (Alaska) Inc., 1998.

North Slope Producers See

Alaska Renaissance as TAPS

Reaches 20. Oil & Gas Journal,

6/16/97.

North Slope’s Exploration Revival

Targeting Satellites Near Giants.

Oil & Gas Journal, 8/31/98.

Schumacher, J., et al.

Minimization and Recycling of

Drilling Waste on the Alaskan

North Slope. Journal of

Petroleum Technology, 6/91.

Stanley, M., and B. Hazen.

Insulated Ice Pad Technology

Enables Extended Season

Drilling on Alaska’s North Slope.

SPE 35686, 1996.

SOURCES AND ADDITIONAL READING

Success in the Field

CASE STUDIES

Advanced technologies have

significantly reduced the footprint

of North Slope operations

• If Prudhoe Bay were developed with today’s technology,

its footprint would be 64 percent smaller: the drilling

impact area would be 74 percent smaller, roads would

cover 58 percent less surface area, and oil and gas 

separating facilities would take 50 percent less space.

• A new 55-acre contractor base supports ARCO Alaska’s

Kuparuk field; similar facilities built over 20 years ago

occupy more than 1,000 acres.

• Surface wellhead spacing has been reduced from 145

feet to 35 feet onshore and 10 feet offshore.

• Production pads are dramatically streamlined: the 1971

Prudhoe Bay “A” Pad was built with 35 wells on 44

acres; the 1989 “P” Pad was built with 21 wells on less

than 11 acres.

Source: Alaska Department of Natural Resources and BP Exploration (Alaska) Inc.

METRICS

and, potentially, up to 

million in operating costs 

per well. New directional

drilling tools and an

advanced form of horizontal

drilling (“designer wells”) 

permit drillers to curve

around geological barriers

to tap small, difficult-toreach pay zones. Another

advanced technology is

coiled tubing, which allows

extended-reach, directional

drilling, and multilateral

completions—all major

contributors to increased

resource recovery, reduced

costs, smaller footprints,

and less waste.
THE FOLLOWING PAGES LIST SOURCES OF ADDITIONAL INFORMATION, DEPARTMENT OF ENERGY OIL AND GAS PROGRAMS AND CONTACTS, AND REFERENCES THAT

PROVIDE DOCUMENTATION FOR THIS REPORT.

A P P E N D I C E S
A - 1 . 1 E N V I RO N M E N TA L B E N E F I T S

A P P E N D I X 1

S O U RC E S O F

A D D I T I O N A L I N F O R M AT I O N

The following list, while not 

inclusive, illustrates the broad arr a y

of organizations concerned about

oil and gas E&P technology and

p rotection of the environment. 

Also, see Appendix 2, DOE Oil and

Gas Pro g r a m s .

Industry Associations

and Professional

S o c i e t i e s

American Association of

P e t roleum Geologists

More than 31,000 members in 115 countries. Established in 1917, its purpose is

to foster the spirit of scientific research

among its members and to advance the

science of geology —particularly as it

relates to petroleum, natural gas, other

subsurface fluids, and mineral resources.

The Division of Environmental

Geosciences, formed in 1992, provides

members with opportunities to increase

their knowledge about the environment 

and the petroleum industry, including

concepts for using geological, geochemical, geophysical, and hydrogeological principles and methodologies 

to resolve environmental problems. 

Tulsa, Oklahoma (918) 584-2555.

Internet: www.geobyte.com

Association of American

State Geologists

Organization of the chief executives of

the State geological surveys in 50 States

and Puerto Rico. The responsibilities 

of the various State surveys differ from

State to State, depending on the

enabling legislation and the traditions

under which the survey evolved. Almost

all function as a basic information

source for their State governments’

executive, legislative, and judicial

branches. Some have regulatory responsibilities for water, oil and gas, and land

reclamation. Web site includes an Earth

Science Education Source Book for

Teachers and Students, a compendium

of earth science education materials and

services available from the 50 State

Geological Surveys in the United States,

Puerto Rico, and the Association of

American State Geologists. Internet:

h t t p : / / w w w . k g s . u k a n s . e d u / A A S G / A A S G .

h t m l

American Gas Association

Represents natural gas utilities and pipeline

companies. Interests include all technical

and operational aspects of the gas industry.

Publishes a comprehensive statistical

record of gas industry; conducts national

standards testing for gas appliances; monitors legislation and regulations. Web site

includes extensive information on natural

gas. Washington, DC (202) 824-7000.

I n t e r n e t : w w w . a g a . o r g

American Geologic Institute

Nonprofit federation of 32 geoscientific

and professional associations that

represent more than 100,000 geologists,

geophysicists, and other earth scientists.

Founded in 1948, the Institute provides

information services to geoscientists,

serves as a voice of shared interests in

the profession, plays a major role in

strengthening geoscience education, and

strives to increase public awareness of

the vital role the geosciences play in

mankind’s use of resources and interaction with the environment. Maintains

a Clearinghouse for Earth Science

Education with an electronic database

for elementary school teachers and

secondary school science teachers.

Produces directories of geoscience

organizations and academic institutions.

Its GeoRef database provides access to

the geoscience literature of the world.

Alexandria, Virginia (703) 379-2480.

Internet: www.agiweb.org

American Geophysical Union

International scientific society of more

than 35,000 researchers, teachers, and

science administrators in more than 

115 countries, over 30 percent of whom

are outside the U.S. Dedicated to

advancing the understanding of the

earth and its environment in space and

making results available to the public.

Washington, DC (202) 462-6900.

Internet: w w w . a g u . o r g

American Petroleum Institute

Represents producers, refiners, marketers,

and transporters of oil, natural gas, and

products. Provides data and information

on industry performance, including an

annual report on E&P Environmental

Performance. Develops guidelines for E&P

environmental operations. STEP program

encourages responsible environmental

operations. Web site includes extensive

education information on topics such as

the history of oil, materials for teachers,

petroleum products at home, and

petroleum museums. Washington, DC

(202) 682-8000. Internet: w w w . a p i . o r g

Independent Petro l e u m

Association of America

Represents independent oil and gas

producers, land and royalty owners, and

others with interests in domestic exploration, development, and production of 

oil and natural gas. Advocates environmental policy being guided by good

science, economics, and reasonable goals.

Washington, DC (202) 857-4722. 

Internet: w w w . i p a a . o r g

I n t e rnational Association

of Drilling Contractors

Promotes safety, preservation of the

environment, and advances in drilling

technology. Member companies are

involved in oil and gas exploration and

production, well servicing, oil field

manufacturing, and other rig site

services. Houston, Texas (281) 578-7171.

Internet: www.iadc.org
O I L A N D G A S T E C H N O LO G Y A - 1 . 2

A P P E N D I X 1

S O U R C E S O F

A D D I T I O N A L I N F O R M AT I O N

Interstate Natural Gas

Association of America

Represents U.S. interstate and Canadian

interprovincial natural gas pipeline

companies. Promotes technologies to

reduce methane emissions through 

EPA Natural Gas STAR Program.

Washington, DC (202) 216-5900.

Internet: www.ingaa.org

Natural Gas Supply Association

Organization of major and independent

producers of domestic natural gas.

Interests include the production, consumption, marketing, and regulation 

of natural gas. Monitors legislation 

and regulations. Encourages producers

to apply cost-effective methane emission

reduction strategies. Maintains a natural

gas education site on the Internet.

Washington, DC (202) 326-9300. 

Internet: www.ngsa.org

National Ocean Industries

A s s o c i a t i o n

Sole national trade association representing all facets of the domestic offshore petroleum and related industries

—producers of crude oil and natural

gas, contractors, oil field service

companies, and others with an interest

in the process of exploring for and 

producing hydrocarbon energy resources

from the Nation’s Outer Continental

Shelf in an environmentally responsible

manner. Washington, DC 

(202) 347-6900. Internet: w w w . n o i a . o r g

Society of Exploration

G e o p h y s i c i s t s

Promotes the science and education of

exploration geophysicists. Fosters the

expert and ethical practice of geophysics

in the exploration and development of

natural resources, in characterizing the

near-surface, and in mitigating earth hazards. More than 15,000 members working in 110 countries. Tulsa, Oklahoma

(918) 497-5500. Internet: w w w . s e g . o r g

Society of Petroleum Engineers

Largest individual-membership organization serving professional engineers,

scientists, and managers in E&P

segments of the worldwide oil and gas

industry. Members include more than

50,000 professionals from oil- and gasproducing regions around the world.

Facilitates the collection, dissemination,

and exchange of technical information

concerning the development of oil and

gas resources, subsurface fluid flow, and

production of other materials through

wellbores for the public benefit.

Provides opportunities for interested

(and qualified) individuals to maintain

and upgrade their individual technical

competence in these areas. Web site

includes a Virtual Suitcase to explore

career opportunities in petroleum

engineering. Richardson, Texas 

(972) 952-9393. Internet: www.spe.org

Colleges and

U n i v e r s i t i e s

Numerous colleges and universities,

including historic black colleges and

universities, offer educational courses

and degrees in geology, petroleum engineering, and other fields related to oil

and gas and the environment. Listings

are relatively easy to find via professional organization Web sites or various

Internet search engines. Representative

of such institutions are:

Louisiana State University

Learn about petroleum engineering, the

jobs of drilling, production, and reservoir engineers, and well log analysts on

the Craft and Hawkins Department of

Petroleum Engineering Web site:

www.pete.lsu.edu

New Mexico Institute

of Mining and Te c h n o l o g y

(New Mexico Te c h )

Founded in 1889 to advance the geological sciences and mineral industries in

New Mexico. Throughout its centurylong history, Tech has maintained a

tradition of excellence in geoscience.

Earth and Environmental Science

Department, Socorro, New Mexico

(505) 835-5635. Internet:

www.ees.nmt.edu

University of Oklahoma

The School of Petroleum and Geological

Engineering, rated among the top 

three petroleum engineering programs 

in the world, has almost 4,000 alumni,

including top executives in Fortune 500

companies. Norman, Oklahoma 

(405) 325-2921 or (800) 522-0772, ext. 2921.

Internet: w w w . o u . e d u / e n g i n e e r i n g / p e t e n g

The Sarkeys Energy Center includes

seven interdisciplinary institutes and a

research program encompassing oil and

gas exploration, production, utilization,

and policy and environmental concerns,

involving faculty from the colleges of

Geosciences, Arts and Sciences, Law,

Business, and Engineering. Norman,

Oklahoma (405) 325-3821 

Internet: w w w . o u . e d u / s e c

Research and

T e c h n o l o g y

Organizations 

Gas Research Institute

Research arm of the Nation’s gas supply

and transportation industry. Its mission

is to discover, develop, and deploy

technologies and information that

measurably benefit gas customers and

the industry. Evaluates and transfers

information about gas resources and

technologies, including E&P environmental technology. Chicago, Illinois

(773) 399-8100. Internet: www.gri.org
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A P P E N D I X 1

S O U RC E S O F

A D D I T I O N A L I N F O R M AT I O N

I n t e rnational Centre for Gas

Technology Inform a t i o n

International forum on gas technology

serving senior executives and technical

and marketing professionals’ information needs. Transfers information on

gas technologies to ensure that global

gas market needs are met efficiently.

Arlington, Virginia (703) 526-7810.

Internet: http://www.gtion.org/

Institute of Gas Te c h n o l o g y

Independent, not-for-profit center for

energy and environmental research,

development, education, and information. Performs sponsored and in-house

research, development, and demonstration. Provides educational programs 

and services. Disseminates scientific 

and technical information in four 

areas: energy utilization; energy supply;

environmental protection and remediation; and natural gas transmission,

distribution, and operations. 

Des Plaines, Illinois (847) 768-0500.

Internet: www.igt.org

P e t roleum Te c h n o l o g y

Transfer Council

National clearinghouse, with 10 regional

centers, to identify and transfer E&P

technologies to enable domestic oil 

and gas producers, principally smaller

independent oil and gas producers, to

reduce costs, improve operating efficiency, increase ultimate recovery,

enhance environmental compliance, and

add new oil and gas reserves. Funded

primarily by DOE oil and natural gas

programs with additional funding provided by State governments, industry,

universities, State geological surveys,

and other sources. Washington, DC

(202) 785-2225. Internet: www.pttc.org

Education and

E n v i r o n m e n t a l

Organizations 

G round Water Protection Council

A nonprofit organization dedicated to

the protection of the Nation’s groundwater supplies. Its mission is to promote

the safest methods and most effective

regulations regarding comprehensive

groundwater protection and underground injection techniques. Meetings,

workshops, seminars, and symposia

provide forums, educational resources,

open communication, and active participation by members who include

local, State, and Federal governments,

citizen groups, industry, academia, and

other parties interested in responsible

protection and management of 

groundwater resources. Oklahoma City,

Oklahoma (405) 516-GWPC. 

Internet: http://gwpc.site.net

E n v i ronmental Defense Fund

Nonprofit organization with more than

300,000 members and five regional

offices, addressing a broad range of

regional, national and international

environmental issues. A leading advocate of economic incentives as a new

approach to solving environmental

problems. Provides environmental

information by mail and electronically;

participates in environmental education

projects; maintains a Member Action

Network to influence national environmental policy; works with grassroots

groups at the local and regional level in

the U.S. and abroad. Efforts include the

Alliance for Environmental Innovation,

a joint initiative with the Pew

Charitable Trust to work with private

companies to create environmental

change. New York, New York

(800) 684-3322. Internet: www.edf.org

National Academy of Sciences

A private, nonprofit society of distinguished scholars engaged in scientific

and engineering research, dedicated to

the furtherance of science and technology and to their use for the general

welfare. Under the charter granted to it

by Congress in 1863, the Academy has 

a mandate that requires it to advise the

Federal government on scientific and

technical matters. The National

Research Council, organized in 1916, 

is the working arm of the National

Academy of Sciences and the National

Academy of Engineering, carrying out

most of the studies done in their names.

Most requests for such studies come

from government agencies or Congress.

Washington, DC (202) 334-2000.

Internet: www.nas.edu

National Energy Education

Development (NEED) Pro j e c t

Established by a Congressional

Resolution in 1980, and founded on the

conviction that an energy-literate public

is essential to a coherent and viable

energy future. NEED is “Educating for

America’s Energy Future.” Promotes an

energy conscious and educated society

by creating effective networks of

students, educators, business, government, and community leaders to 

design and deliver objective, multisided energy education programs. 

Herndon, Virginia (703) 471-6263.

Internet: www.tipro.com/need or

www.energyconnect.com/need

National Fish and Wi l d l i f e

F o u n d a t i o n

Nonprofit organization, with five

regional offices, established by Congress

in 1984. Dedicated to promoting conservation and sustainable use of our natural resources through environmental

education, natural resource management, habitat protection, ecosystem

restoration, and public policy development. Since 1986, has awarded more

than 2,550 “challenge” grants using over

$100 million in Federal funds, which

have been matched with nonfederal dollars to bring more than $300 million to

conservation projects. Privately funded

partnerships include the Shell Marine

Habitat Program to support projects to

protect and enhance the Gulf of Mexico

ecosystem and the Save the Tiger Fund,

an international effort with Exxon to

assist in the long-term survival of Asia’s

remaining populations of wild tigers.

Washington, DC (202) 857-0166.

Internet: www.nfwf.org

N a t u re Conserv a n c y

Responsible for the protection of more

than eight million acres in 50 States and

Canada. Preserves habitats, species, 

and natural communities by buying the

lands and waters they need to survive.

Manages the resulting preserves with the

most sophisticated ecological techniques

available. With partner organizations,

has preserved millions of acres in Latin

America, the Caribbean, the Pacific,

and Asia. Owns more than 1,400

preserves—the largest private system 

of nature sanctuaries in the world.

Arlington, Virginia (703) 841-5300.

Internet: www.tnc.org
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A D D I T I O N A L I N F O R M AT I O N

National Energy Foundation

Nonprofit provider of educational

materials and programs related to

energy, natural resources, and the 

environment. Supported by businesses,

government agencies, professional 

associations, and the education 

community. Salt Lake City, Utah 

(801) 539-1406. Internet: 

www.xmission.com/~nef

Oklahoma Energ y

R e s o u rces Board

Nonprofit organization funded by

voluntary industry contributions.

Restores abandoned oilfield sites and

educates public about the Oklahoma 

oil and gas E&P industry. Encourages

efficient use of energy; promotes environmentally sound production methods

and technologies; supports research 

and educational activities. Oklahoma

City, Oklahoma (405) 942-5323 or

(800) 664-1301. Internet: www.oerb.com

Oil and Gas Museums

From the grassroots perspective, local

oil and gas museums offer excellent

opportunities to learn about the evolution of oil and gas E&P technology in

the United States. For information,

explore local Chamber of Commerce,

oil and gas industry, and professional

organization Web sites such as

www.api.org/edu/museums.htm

These museums include:

East Texas Oil Museum at

K i l g o re College

A tribute to the independent oil producers and wildcatters, the men and

women who dared to dream as they

pursued the fruits of free enterprise.

Kilgore, Texas (903) 983-8295. Internet:

h t t p : / / k i l g o r e . c c . t x . u s / a t t r / e t o m / e t o m . h t m l

Healdton Oil Museum

The opening of the Healdton oil 

field in 1913 set into motion one of

Oklahoma’s greatest oil booms, establishing southern Oklahoma as a major

petroleum-producing area. By 1937, 

this field, the largest of nine such fields

located in Carter County, had produced

over 200 million barrels of oil, making

it one of the most productive pools in

the State. Healdton, Oklahoma

(580) 229-0317. Internet:

h t t p : / / w w w . b r i g h t o k . n e t / c h i c k a s a w /

a r d m o r e / c o u n t y / h e a l d o i l . h t m l

I n t e rnational Petroleum Museum

and Exposition

Maintains “Mr. Charlie,” an authentic

offshore drilling rig, for public viewing.

A tribute to the pioneering men and

women of an industry that developed a

culture based on initiative, perseverance,

creativity, and hard work. Efforts under

way include a Web site “virtual tour.”

Morgan City, Louisiana (504) 384-3744.

Internet: www.rigmuseum.com

Kansas Oil Museum

and Hall of Fame

Founded in 1990 to preserve the history

of the oil and gas industry. El Dorado,

Kansas (316) 321-9333. For more information see: h t t p : / / w w w . g r e a t b e n d . n e t / g b c c /

t o u r i s m / o i l m u s /

O ff s h o re Energy Center

Operates a state-of-the-art refurbished

jackup facility, the Ocean Star, which 

is a museum, educational attraction, 

and working drilling rig all rolled into

one. Visitors absorb the day-to-day

excitement of offshore drilling and

production, marine transportation,

environmental protection, construction,

p i p e l i n i n g—all experienced through

three decks of videos, equipment

exhibits, and interactive displays.

Galveston, Texas (409) 766-STAR.

Internet: w w w . o c e a n s t a r o e c . c o m

Penn-Brad Oil Museum

Preserves the philosophy, the spirit, and the

accomplishments of an oil country community; takes visitors back to the early oil

boom times of The First Billion Dollar Oil

Field. Guided tours are conducted by over

100 oil country veterans who volunteer

their time to relate first-hand experiences.

Talks are illustrated with colorful display

items such as yellow dogs and barkers,

headache posts and Samson posts, hurry-up

sticks and sucker rods, all used to produce

Pennsylvania oil. Bradford, Pennsylvania.

Internet: h t t p : / / b r a d f o r d - o n l i n e . c o m

Pennsylvania Historical and

Museum Commission Drake

Well Museum

Located on the site where Edwin L. Drake

drilled the first commercially successful oil

well in 1859. Documents the birthplace of

the petroleum industry with exhibits, operating field equipment, an extensive photographic collection, and a research library.

Titusville, Pennsylvania (814) 827-2797.

Internet: w w w . u s a c h o i c e . n e t / d r a k e w e l l

Texas Energy Museum

Offers a learning experience for both

children and adults through multimedia

techniques that include rig sounds,

motion, light, cinema projection, voice,

and photo-mural backgrounds. Exhibits

deal with the geology of hydrocarbons

and the history of the petroleum

industry within a total energy picture.

Beaumont, Texas (409) 833-5100.

Spindletop Gladys City

Boomtown Museum

A reconstruction of an oil boomtown

that appeared almost overnight following

the discovery of the Spindletop oil fields

in 1901. The site includes a 58-foot

granite monument to the Lucas Gusher

and is a national historic landmark

located on the Lamar University Campus.

Beaumont, Texas (409) 835-0823.

Oil and Gas Companies

Corporations are too numerous for a

complete listing. Following are 

three with interesting Web sites: 

C h e v ro n

Check out the Exploration Zone for an

educational primer about oil production

and refining. With simple graphics and

nontechnical text, it’s great for students

and teachers. 

Internet: w w w . c a p i t a l c h e v r o n . c o m

BP Amoco

Takes a leadership position in addressing climate change and other environmental issues; offers energy educational

materials in six languages for teachers

and students worldwide as part of its

Science Across the World Web site.

Internet: www.bpamoco.com and

http://www.bp.com/saw/

Conoco, Inc.

Conoco’s Web site features short 

on-line movies about some of the

industry’s newest and most innovative

technologies. These videos provide an

excellent tool for understanding how

advanced oil and gas exploration and

production technology is impacting the

world and protecting the environment

in which we live, both in the United

States and around the world. 

Internet: www.conoco.com/about/

glance/index.html
A - 1 . 5 E N V I RO N M E N TA L B E N E F I T S

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A D D I T I O N A L I N F O R M AT I O N

Other Government

Agencies and Offices

D e p a rtment of the Interior

The mission of the Department of the

Interior is to protect and provide access

to our Nation’s natural and cultural

heritage and to honor our trust responsibilities to tribes. This mission as

related to oil and gas is implemented 

by several agencies: 

Bureau of Land Management, which

manages fluid and solid mineral leasing

on Federal lands as part of its mission to

sustain the health, diversity, and productivity of public lands for the use and

enjoyment of present and future generations. Washington, DC (202) 452-5125.

Internet: www.blm.gov

Minerals Management Service (MMS),

which manages the Federal offshore oil

and gas leasing program, including Rigs

to Reefs and Safety and Environmental

Management Plan activities in coopera -

tion with industry. These activities are

part of MMS’ mission to manage the

mineral resources on the Outer

Continental Shelf in an environmentally

sound and safe manner and to timely

collect, verify, and distribute mineral

revenues from Federal and Indian lands.

Washington, DC (202) 208-3985.

Internet: www.mms.gov, MMS Internet

KidsPage: www.mms.gov/mmskids

United States Geological Service, 

which evaluates and classifies onshore

oil, natural gas, geothermal resources,

and all solid energy and mineral

resources, including coal and uranium

on Federal lands, as part of its mission

to provide the Nation with reliable,

impartial information to describe 

and understand the earth. 

Reston, Virginia (888) 275-8747 

Internet: http://energy.usgs.gov

D e p a rtment of Labor

Occupational Safety and

Health Administration

Dedicated to saving lives, preventing

injuries, and protecting the health of

America’s workers through regulatory

and voluntary programs and partnering

with Federal and State agencies to

protect more than 100 million working

men and women and their 6.5 million

employers who are covered by the

Occupational Safety and Health Act of

1970. Voluntary Protection Programs

recognize outstanding achievements by

companies that successfully integrate a

comprehensive safety and health program

into their total management system.

Washington, DC (202) 693-2000 and

(202) 693-1999. Internet: w w w . o s h a . g o v

D e p a rtment of Tr a n s p o rt a t i o n

Coast Guard

Carries out search-and-rescue missions

in and around navigable waters and 

on the high seas. Enforces Federal laws 

on the high seas and navigable waters 

of the United States and its possessions.

Conducts marine environmental protection programs; administers boating

safety programs; inspects and regulates

construction, safety, and equipment of

marine vessels, including those for oil

and gas E&P. Establishes and maintains

a system of navigation aids; carries out

domestic icebreaking activities.

Washington, DC (202) 267-2229.

Internet: http://www.uscg.mil

D e p a rtment of Tr a n s p o rt a t i o n

O ffice of Pipeline Safety

Issues and enforces Federal regulations

for oil, natural gas, petroleum products,

and hazardous liquids pipeline safety.

Conducts a voluntary program to

advance pipeline safety. Washington

DC (202) 366-4595. 

Internet: http://ops.dot.gov/

E n e rgy Inform a t i o n

A d m i n i s t r a t i o n

Clearinghouse for statistical information

on energy data, including information

on natural gas and oil production.

Established in 1977, its mission is to

develop energy data and analyses that

enhance the understanding of energy

issues on the part of business, government, and the general public. 

A KidsPage is under development in

cooperation with the National Energy

Education Development Project.

Washington, DC (202) 586-8800.

Internet: www.eia.doe.gov

E n v i ro n m e n t a l

P rotection Agency

Implements Federal laws designed to

promote public health by protecting 

our Nation’s air, water, and soil from

harmful pollution. Aims to accomplish

its mission by integration of research,

monitoring, standard-setting, and

enforcement activities. Coordinates and

supports research and antipollution

activities of State and local governments, private and public groups, individuals, and educational institutions.

Washington, DC (202) 260-2090.

Internet: www.epa.gov

Agency programs include:

Natural Gas STAR to encourage the

natural gas industry to reduce leaks

through cost-effective best management

p r a c t i c e s.

Coalbed Methane Outreach to increase

methane recovery at coal mines.

Project XL to allow companies to test

alternative approaches that achieve

cleaner and cheaper environmental

results than would be realized under

existing requirements.

Environmental Technology Initiative,

an interagency effort supporting more

than 250 partnerships and projects

throughout the United States to promote improved public health and

environmental protection by advancing

the development and use of innovative

environmental technologies.

Interstate Oil and Gas

Compact Commission

An organization of States which promotes conservation and efficient recovery

of domestic oil and natural gas resources

while protecting health, safety and the

environment. Represents the governors

of 37 States—30 members and seven

associate States— that produce virtually

all the domestic oil and natural gas in the

United States. Established in 1935, it is

among the oldest and largest interstate

compacts in the Nation. Oklahoma City,

Oklahoma (405) 525-3556. Internet:

w w w . i o g c c . o k l a o s f . s t a t e . o k . u s

National Governors Association

A bipartisan organization comprising the

governors of the 50 States, the commonwealths of the Northern Mariana Islands

and Puerto Rico, and the territories of

American Samoa, Guam, and the Virgin

Islands. Founded in 1908 after the

Governors met with President Theodore

Roosevelt to discuss conservation issues.

Through three standing committees on

Economic Development and Commerce,

Human Resources, and Natural

Resources, the Association’s Center for

Best Practices, and other activities, the

governors identify priority issues and deal

collectively with issues of public policy

and governance at both the national and

State levels. Washington, DC 

(202) 624-5300. Internet: w w w . n g a . o r g
O I L A N D G A S T E C H N O LO G Y A - 1 . 6

A P P E N D I X 1

S O U RC E S O F

A D D I T I O N A L I N F O R M AT I O N

United States Congre s s

Numerous committees, such as those

listed below, have jurisdiction over

energy, environment, and science and

technology issues and the capability to

make national public policy decisions

affecting the advancement of oil and gas

technology. Washington. DC. More

information is available on the Internet:

www.senate.gov and www.house.gov

U.S. House of Representatives:

Committees on Appropriations,

Commerce, Resources, Science, Small

Business, Transportation and

Infrastructure, and Ways and Means.

U.S. Senate: Committees on

Appropriations, Commerce, Science

and Transportation, Energy and

Natural Resources, Environment and

Public Works, Foreign Relations, 

and Small Business.

On-Line Petroleum

Business Information

Numerous Internet sites are maintained

by private services. For example:

Oil-Link, a privately owned on-line

directory of petroleum-related Internet

sites and information, rated #1 by 

the Dow Jones Business Directory:

www.oillink.com

Offshore Technology, a London-based

Web site for the offshore oil and gas

industry that includes information on

current E&P projects and organizations,

country-by-country, worldwide:

www.offshore-technology.com

Journals and

P u b l i c a t i o n s

For more information about the oil and

gas industry and advanced oil and gas

technologies, talk to your local librarian.

The following are just some of the

numerous journals and publications on

the oil and gas industry.

The American Oil & Gas Report e r

A monthly independent trade magazine

on exploration, drilling, and production

that also serves as the official publication

for 23 oil and gas associations and two

biennial oil and gas industry trade shows.

E&P Enviro n m e n t

A biweekly newsletter reporting on

environmental issues, technological

innovations, and State and Federal

regulations affecting oil and gas E&P.

Web site links from w w w . e p e o n l i n e . c o m

include an Amazing Environmental

Organization Web Directory characterized as the Earth’s Biggest Environment

Search Engine.

H a rt ’s Petroleum Engineer

I n t e rn a t i o n a l

A monthly magazine for engineering,

management, and operating decision

makers engaged in drilling, production,

and reservoir engineering worldwide.

I m p roved Recovery We e k

A newsletter published since 1982 on

news and developments in worldwide

improved and enhanced oil and 

gas recovery.

Inside Energ y/with Federal Lands

A weekly newsletter from McGraw-Hill

Companies on Department of Energy

programs in energy, science and technology, and nuclear-weapons cleanup, and

the Department of Interior’s management

of energy and minerals on Federal lands.

J o u rnal of Petroleum Te c h n o l o g y

Official publication of the Society of

Petroleum Engineers, with peer-reviewed

oilfield management and engineering

articles focusing on practical engineering solutions to oilfield problems.

Oil & Gas Journ a l

A magazine published weekly by

PennWell Publishing Co. on technology, industry news, statistics, and

special reports and analyses for the

petroleum industry. Other publications

include Offshore Magazine and Revista

Latinoamericana Magazine, published

quarterly in Spanish about the

petroleum industry in Latin America.

E n e rgy Alert, Natural Gas We e k ,

Oil Daily, Petroleum Intelligence

We e k l y, World Gas Intelligence

Five of 12 publications from the 

Energy Intelligence Group that

disseminate market, financial, and

technology information related to 

the oil and gas industry.
A-2.1 E NVIRONMENTAL B ENEFITS

A PPENDIX 2

DEPARTMENT OF E NERGY

OIL AND G A S P ROGRAMS

A primary mission of the Department of Energy’s Office of 

Fossil Energy is to foster advanced, more efficient, and cleaner 

fossil energy technologies through research and development 

programs. Planning and implementation of our Natural Gas and

Petroleum Technology Programs reflects the collaboration of

DOE staff in the Office of Natural Gas and Petroleum Technology

in Washington, DC; at the National Petroleum Technology

Office in Tulsa, Oklahoma; and at the Federal Energy Technology

Center in Morgantown, West Virginia and Pittsburgh, Pennsylvania.

Our overall goals are to (1) reduce the vulnerability of the United

States economy to disruptions in oil supply by stabilizing domestic

oil production; (2) increase domestic energy production in an

environmentally responsible manner by increasing domestic gas

production and recovering oil with less environmental impact;

(3) ensure energy system reliability, flexibility, and emergency

response capability of oil and gas transportation and storage systems;

and (4) develop technologies that expand long-term energy options. 

For further information on the Environmental Benefits 

of Advanced Oil and Gas Exploration and Production 

Technology, contact:

NANCY L. JOHNSON

Director of Planning and Environmental Analysis

Office of Natural Gas and Petroleum Technology

(202) 586-6458; e-mail: nancy.johnson@hq.doe.gov

TRUDY TRANSTRUM

Communications Coordinator

Office of Natural Gas and Petroleum Technology

(202) 586-7253; e-mail: trudy.transtrum@hq.doe.gov

Like any organization, DOE is made up of people — people 

who care about having a healthy domestic oil and gas industry

and a healthy environment. DOE staff are committed to 

finding real solutions that allow the Nation to benefit from a

strong economy and a clean environment. Advanced oil and 

gas technologies and innovation are part of America’s heritage

and its future.

We offer our gratitude to the many individuals who made this

report possible. Special thanks are extended to Sandra L. Waisley

for her efforts on this report.
O IL AND G A S T ECHNOLOGY A-2.2

Advanced Drilling, Completion,

and Stimulation Systems

ELENA SUBIA MELCHERT

(202) 586-5095

elena.melchert@hq.doe.gov

RHONDA LINDSEY

(918) 699-2037

rlindsey@npto.doe.gov

ROY LONG

(304) 285-4236

rlong@fetc.doe.gov

Advanced Diagnostics and

Imaging Systems

EDITH ALLISON

(202) 586-1023

edith.allison@hq.doe.gov

ROBERT LEMMON

(918) 699-2035

blemmon@npto.doe.gov

JAMES AMMER

(304) 285-4383

jammer@fetc.doe.gov

Reservoir Efficiency Processes

GEORGE STOSUR

(202) 586-8379

george.stosur@hq.doe.gov

BETTY FELBER

(918) 699-2031

bfelber@npto.doe.gov

ALEX CRAWLEY

(918) 699-2055

acrawley@npto.doe.gov

Reservoir Life Extension

GEORGE STOSUR

(202) 586-8379

george.stosur@hq.doe.gov

BETTY FELBER

(918) 699-2031

bfelber@npto.doe.gov

GARY SAMES

(412) 892-4347

sames@fetc.doe.gov

JERRY CASTEEL

(918) 699-2042

jcasteel@npto.doe.gov

Gas Storage

CHRISTOPHER FREITAS

(202) 586-1657

christopher.freitas@hq.doe.gov

JAMES AMMER

(304) 285-4383

jammer@fetc.doe.gov

THOMAS MROZ

(304) 285-4071

tmroz@fetc.doe.gov

MARA DEAN

(412) 892-4520

dean@fetc.doe.gov

GARY SAMES

(412) 892-4347

sames@fetc.doe.gov

Environmental Research

and Analysis 

WILLIAM HOCHHEISER

(202) 586-5614

william.hochheiser@hq.doe.gov

NANCY JOHNSON

(202) 586-6458

nancy.johnson@hq.doe.gov

DAVID ALLEMAN

(918) 699-2057

dalleman@npto.doe.gov

SUSAN GREGERSEN

(202) 586-0063

susan.gregersen@hq.doe.gov

PETER LAGIOVANE

(202) 586-8116

peter.lagiovane@hq.doe.gov

NANCY HOLT

(918) 699-2059

nholt@npto.doe.gov

JOHN FORD

(918) 699-2061

jford@npto.doe.gov

Oil Processing

ARTHUR HARTSTEIN

(301) 903-2760

arthur.hartstein@hq.doe.gov

DEXTER SUTTERFIELD

(918) 699-2039

dsutterf@npto.doe.gov

Gas Processing

ARTHUR HARTSTEIN

(301) 903-2760

arthur.hartstein@hq.doe.gov

VENKAT VENKATARAMAN

(304) 285-4105

vvenka@fetc.doe.gov

DANIEL DRISCOLL

(304) 285-4717

ddrisc@fetc.doe.gov

ANTHONY ZAMMERILLI

(304) 285-4641

azamme@fetc.doe.gov

CHARLES BYRER

(304) 285-4547

cbyrer@fetc.doe.gov

Oil & Gas Modeling

and Analysis 

JOHN PYRDOL

(301) 903-2773

john.pyrdol@hq.doe.gov

ELENA SUBIA MELCHERT

(202) 586-5095

elena.melchert@hq.doe.gov

ANTHONY ZAMMERILLI

(304) 285-4641

azamme@fetc.doe.gov

R. MICHAEL RAY

(918) 699-2010

mray@npto.doe.gov

Natural Gas & Petroleum

Import and Export Activities 

DONALD JUCKETT

(202) 586-8830

donald.juckett@hq.doe.gov

CLIFF TOMASZEWSKI

(202) 586-9460

cliff.tomaszewski@hq.doe.gov

JOHN GLYNN

(202) 586-9454

john.glynn@hq.doe.gov

Natural Gas Market 

Access Program

PETER LAGIOVANE

(202) 586-8116

peter.lagiovane@hq.doe.gov

CHRISTOPHER FREITAS

(202) 586-1657

christopher.freitas@hq.doe.gov

HBCU Internship

DOROTHY FOWLKES

(202) 586-7421

dorothy.fowlkes@hq.doe.gov

Hispanic Internship

ELENA SUBIA MELCHERT

(202) 586-5095

elena.melchert@hq.doe.gov

Policy Development

and Planning

MICHAEL YORK

(202) 586-5669

michael.york@hq.doe.gov

NANCY JOHNSON

(202) 586-6458

nancy.johnson@hq.doe.gov

Technology Transfer

PETER LAGIOVANE

(405) 586-8116

peter.lagiovane@hq.doe.gov

HERB TIEDEMANN

(202) 699-2017

htiedema@npto.doe.gov

Communications

TRUDY TRANSTRUM

(202) 586-7253

trudy.transtrum@hq.doe.gov

BRENDA STEWART

(202) 586-8020

brenda.stewart@hq.doe.gov

DOE OIL AND GAS TECHNOLOGY PROGRAM CONTACTS

A PPENDIX 2

DEPARTMENT OF E NERGY

OIL AND G A S P ROGRAMS
A-2.3 E NVIRONMENTAL B ENEFITS

A PPENDIX 2

DEPARTMENT OF E NERGY

OIL AND G A S P ROGRAMS

DEPARTMENT OF ENERGY OUTREACH

National Washington, DC

U.S. DEPARTMENT OF ENERGY

http://www.doe.gov

DOE programs, science education, recent DOE news. Links 

to related government offices and all National Laboratories.

OFFICE OF FOSSIL ENERGY (FE) 

http://www.fe.doe.gov

Fossil-energy-related DOE activities, including news,

technology information, publications, speeches, events, issues,

international activities, and projects within FE’s coal and

power, oil and gas, or regulatory areas. 

OFFICE OF NATURAL GAS AND PETROLEUM TECHNOLOGY

http://www.fe.doe.gov/programs_oilgas.html

Details on oil and gas research and development projects, 

with links to Fossil Energy’s Strategic Petroleum Reserve 

and the Naval Oil Shale Petroleum Reserves sites. 

NATIONAL ENERGY INFORMATION ADMINISTRATION (EIA)

http://www.eia.doe.gov

Extensive archive of historical data as well as current facts and 

figures on energy resources and trends in the energy industry. 

PETROLEUM TECHNOLOGY TRANSFER COUNCIL (PTTC) 

http://www.pttc.org

National technology clearinghouse for oil and gas producers, 

offering software, workshops, and resources for industry,

especially small independent producers.

✪

Regions

■ WEST COAST

■ SOUTHWEST

■ SOUTH MIDCONTINENT

■ ROCKY MOUNTAINS

■ TEXAS

■ APPALACHIA

■ NORTH MIDCONTINENT

■ MIDWEST

■ EASTERN GULF

■ CENTRAL GULF

Field Offices

• NATURAL GAS AND OIL TECHNOLOGY PARTNERSHIP

(NGOTP) Albuquerque, NM

http://132.175.127.176/ngotp/NGOTP.htm

Describes research activities of the National Laboratories 

in partnership with industry, working to transfer new

technologies to the oil and gas industry. 

• NATIONAL PETROLEUM TECHNOLOGY OFFICE

(NPTO) Tulsa, OK 

http://www.npto.doe.gov

NPTO news, calendar of workshops, and resources for

companies, including valuable software to download. 

• FEDERAL ENERGY TECHNOLOGY CENTER (FETC)

Morgantown, WV and Pittsburgh, PA 

http://www.fetc.doe.gov

Project fact sheets, electronic business center for

procurements and on-line publications, as well 

as a “cool science” educational page for students. 
O IL AND G A S T ECHNOLOGY A-2.4

A PPENDIX 2

DEPARTMENT OF E NERGY

OIL AND G A S P ROGRAMS

DOE OUTREACH TEAM MEMBERS

Appalachia

(E-KY, NY, OH, PA, TN, VA, WV)

LOU CAPITANIO

HQ Co-Chair

(202) 586-5098

AL YOST (FETC)

Field Co-Chair

(304) 285-4479

Central Gulf

(LA)

NANCY JOHNSON

HQ Co-Chair

(202) 586-6458

BETTY FELBER (NPTO)

Field Co-Chair

(918) 699-2031

Eastern Gulf

(AL, FL, MS)

NANCY JOHNSON

HQ Co-Chair

(202) 586-6458

BETTY FELBER (NPTO)

Field Co-Chair

(918) 699-2031

Midwest

(W-KY, IL, IN, MI)

ELENA S. MELCHERT

HQ Co-Chair

(202) 586-5095

BILL GWILLIAM (FETC)

Field Co-Chair

(304) 285-4401

North Midcontinent

(KS, MO)

HERB TIEDEMANN (NPTO)

Field Chair

(918) 699-2017

Rocky Mountains

(CO, ID, MT, ND, NE, NV, SD, UT, WY)

BILL HOCHHEISER

HQ Co-Chair

(202) 586-5614

RHONDA LINDSEY (NPTO)

Field Co-Chair

(918) 699-2037

South Midcontinent

(AR, OK)

BILL LAWSON (NPTO)

Field Chair

(918) 699-2001 

Southwest

(AZ, NM)

CHRISTOPHER FREITAS

HQ Co-Chair

(202) 586-1657

ROBERT LEMMON (NPTO)

Field Co-Chair

(918) 699-2061

Texas

(TX)

EDITH ALLISON

HQ Co-Chair

(202) 586-1023

CHARLES BYRER (FETC)

Field Co-Chair

(304) 285-4547

West Coast

(AK, CA, OR, WA)

ART HARTSTEIN

HQ Co-Chair

(301) 903-2760

HUGH GUTHRIE (FETC)

Field Co-Chair

(304) 285-4632

National

GUIDO DEHORATIIS

HQ Chair

(202) 586-7296

HUGH GUTHRIE (FETC)

Field Co-Chair

(304) 285-4632

BILL LAWSON (NPTO)

Field Co-Chair

(918) 699-2001
A - 3 . 1 E N V I RO N M E N TA L B E N E F I T S

A P P E N D I X 3

RE F E R E N C E S

F o re w o rd

American Petroleum Institute. Basic

Petroleum Data Book, July 1998.

Department of Energy, Energy

Information Administration. Advance

Summary —U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves

1997 Annual Report, September 1998.

Department of Labor, Bureau of Labor

Statistics, http://stats.bls.gov

Independent Petroleum Association 

of America. The Oil & Gas Producing

Industry in Your State 1997–1998,

November 1997.

Our Quality of Life Relies

on Oil and Gas

and

A History of Innovation

American Petroleum Institute. Basic

Petroleum Data Book, July 1998.

American Petroleum Institute.

Petroleum Industry Environmental

Performance 6th Annual Report, 1998.

American Petroleum Institute.

Promoting Partnerships: Cooperation

Between the Petroleum Industry and

Environmental, Education and

Community Groups, 1996.

American Petroleum Institute. 

Strategies for Today’s Environmental

Partnership, 1997.

Chambers, Mike R. Multilateral

Technology Gains Broader Acceptance, 

Oil & Gas Journal, November 23, 1998.

Collett, Timothy S., and Vello A.

Kuuskraa. Hydrates Contain Vast Store

of World Gas Resources. Oil & Gas

Journal, May 11, 1998.

Conoco, Inc., www.conoco.com

Department of Energy, Energy

Information Administration. Advance

Summary—U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves

1997 Annual Report, September 1998.

Department of Energy, Energy

Information Administration. Annual

Energy Outlook 1998, December 1997.

Department of Energy, Energy

Information Administration. Annual

Energy Review 1997, July 1998.

Department of Energy, Energy

Information Administration. Impacts 

of the Kyoto Protocol on U.S. Energy

Markets and Economic Activity,

October 1998.

Department of Labor, Bureau of Labor

Statistics, http://stats.bls.gov

Department of Labor, Occupational

Safety & Health Administration,

www.osha.gov

El-Banbi, A.H. Modifications Improve

Waterflood Performance Model. Oil &

Gas Journal, January 1, 1996.

Fisher, William L. The U.S. Experience

in Natural Gas. Proceedings of the Global

Gas Resources Workshop, 1994.

Interstate Oil and Gas Compact

Commission and the United States

Department of Energy, Office of 

Fossil Energy. Oil and Gas Exploration

and Production Waste Management: 

A 17 - State Study, June 1993.

Milestones and Influences in U.S.

Offshore History (1946 –1997). Offshore

Magazine, May 1997.

Minerals Management Service,

www.mms.gov

The Nature Conservancy, www.tnc.org

Nehring, Richard. Innovation Overpowering Reserves Depletion in U.S.

Oil & Gas Journal, November 9, 1998.

Nehring, Richard. Knowledge,

Technology Improvements Boosting

U.S. Upstream Opportunities. Oil &

Gas Journal, November 2, 1998.

NewsWell: Americans Will Save 

$50 Billion This Year, at E&P Firms’

Expense. Oil and Gas Investor,

June 1998.

PetroFina. Health, Safety &

Environment Report 1995 –1996,

www.fina.com

Stolle, J., and L. LeBlanc. Directional

Drilling in the U.S. Gulf: The First 50

Years. Of f s h o re Ma g a z i n e, February 1998.

Talkington, Kelly. Remote South 

China Sea Reservoir Prompts Extended

Reach Record. Oil & Gas Journal,

November 10, 1997.

United States Environmental Protection

Agency, www.epa.gov/gasstar

Western Hemisphere Oil and Gas

Environmental Forum,

w w w . f e . d o e . g o v / i n t e r n a t i o n a l / w h o g e f . h t m l

E x p l o r a t i o n

American Petroleum Institute. Basic

Petroleum Data Book, July 1998.

Locke, Stephen R. Advances Reduce

Total Drilling Costs. The American 

Oil & Gas Reporter, July 1998.

Shirley, Kathy. Drilling Activity

Heating Up as 3 –D Shines New Light

on Transition Zone. The American 

Oil & Gas Reporter, April 1998.

Drilling and Completion

American Petroleum Institute. Joint

Association Su rvey on Drilling Costs, 1996.

Andersen, E.E., et al. Guidelines for

Designing Safe, Environmentally

Acceptable Downhole Injection

Operations. SPE 25964, 1993. 

Arnold, Dan. Liquid CO2and Sand:

An Alternative to Water-Based

Stimulation Fluids, Hart’s Petroleum

Engineer International, January 1998.

Butler, J., and B. Skeen. Horizontal

Well Successfully Drilled in Black

Warrior Basin. Oil & Gas Journal,

July 22, 1996.

Chambers, Mike R. Multilateral

Technology Gains Broader Acceptance.

Oil & Gas Journal, November 23, 1998.

Department of Energy. Natural Gas &

Oil Technology Partnership, June 1997.

Deskins, W.G. Survey Shows Successes,

Failures of Horizontal Wells. Oil & Gas

Journal, June 19, 1995.

Faure, A., and J. Simmons. Coiled

Tubing Drilling: A Means to Minimiz e

Environmental Impact, SPE 27156, 1994.

Greenberg, Jerry. Managing Loss-ofControl in Deepwater Drilling. Offshore

Magazine, April 1998.

Knoll, R.G. Buzzwords Can Lead to

Poor Results. The American Oil & Gas

Reporter, September 1998.

Locke, Stephen R. Advances Reduce

Total Drilling Costs. The American 

Oil & Gas Reporter, July 1998.

Lyle, Don. Drilling Technology

Accelerates. Hart’s Oil and Gas World,

November 1996.

Mason, Richard. Technology Sparks

Drilling Revolution: Horizontal

Drilling Broadening Mindset, Opening

New Possibilities. The American Oil &

Gas Reporter, September 1998.

Rappold, Keith. Industry Pushes Use of

PDC Bits to Speed Drilling, Cut Costs.

Oil & Gas Journal, August 14, 1995.

Society of Petroleum Engineers.

Monograph Volume 12: Recent Advances

in Hydraulic Fracturing.
O I L A N D G A S T E C H N O LO G Y A - 3 . 2

A P P E N D I X 3

RE F E R E N C E S

Stevens, S., et al. Technology Spurs

Growth of U.S. Coalbed Methane. 

Oil & Gas Journal, January 1, 1996.

Talkington, Kelly. Remote South China

Sea Reservoir Prompts Extended Reach

Record. Oil & Gas Journal, November

10, 1997.

Veil, J.A., et al. Synthetic-Based Muds

Can Improve Drilling Efficiency

Without Polluting. Oil & Gas Journal,

March 4, 1996.

Wolhart, Steve. New Initiatives in

Hydraulic Fracture Diagnostics.

GasTIPS, Fall 1998.

P ro d u c t i o n

American Petroleum Institute. Basic

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Boyson, J.E., et al. Field Demonstration

of the Freeze-Thaw/ Evaporation Process

for the Treatment of Produced Waters in

the San Juan Basin of New Mexico.

SPE 37904, 1997.

Department of Energy, Energy

Information Administration. Natural

Gas Annual 1996, September 1997.

Independent Petroleum Association 

of America. The Oil & Gas Producing

Industry in Your State 1997–1998,

November 1997.

Interstate Oil and Gas Compact

Commission. Marginal Oil and Gas

Report, 1998.

Moritis, Guntis. EOR Oil Production

Up Slightly. Oil & Gas Journal,

April 20, 1998.

Peats, A., et al. Application of ESP Oil

Water Separation System in the Swan

Hills Unit One Field—A Case Study,

SPE ESP Workshop, 1997.

South Belridge 15th Billion Barrel 

Field in U.S. Oil & Gas Journal,

October 16, 1995.

Site Restoration

California Environmental Protection

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Kebodeaux, T.R. Death of a Platform:

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Shaffer, Gary P., et al. Restored Drill

Cuttings for Wetlands Creation: Year 

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Operations in Sensitive

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Alaskan North Slope Operators Shift

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Hiking Production. Oil & Gas Journal,

August 24, 1998.

Alaska Department of Natural

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Evolution of Petroleum Development

Technology on Alaska’s North Slope. . .

Reduced Impacts and Enhanced

Environmental Protection, June 1995.

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BP Exploration (Alaska) Inc. 

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Cold-War Stealth Science Can Aid

Seismic Interpretation. Journal of

Petroleum Technology, January 1998.

Crow, Patrick. ANWR Leasing Issue

Destined to Heat up Again in Congress.

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Hazen, Beez. Use of Ice Roads and Ice

Pads for Alaskan Arctic Oil Exploration

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Area of the National Petroleum

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Bureau of Land Management and

Minerals Management Service, 

April 16 –18, 1997, Anchorage, Alaska.

Hunt, Mike. Drilling Site on a

National Seashore Required Extra

Environmental Precautions. 

Oil & Gas Journal, November 6, 1995.

The Nature Conservancy, www.tnc.org

Navarro, A.R. Innovative Techniques

Cut Costs in Wetlands Drilling. 

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Long Life Seen for Giant Wilmington

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Smith, R.M. The Hunter Creek Well:

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Stanley, Mark J., and Beez Hazen.

Insulated Ice Pad Technology Enables

Extended Drilling Season on Alaska’s

North Slope. SPE 35686, 1996.

Unocal Corporation. 1996–97 

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The Future Challenges

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American Petroleum Institute. Basic

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Baker, H. Personal Correspondence to

the U.S. Department of Energy, 1999.

Bishop, R. Gifts of Mentors Keep on

Giving. AAPG Explorer, December

1998.

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California Independent Petroleum

Association. The Monday Morning

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Crow, P. Associations, Government

Help U.S. Independents Grapple with

Low Oil Prices. Oil & Gas Journal,

January 11, 1999.

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Statistics, http://stats.bls.gov

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Information Administration. Annual

Energy Outlook 1999, December 1998.

Department of Energy, Energy

Information Administration. Annual

Energy Review 1997, July 1998.

Department of Energy. Comprehensive

National Energy Strategy, April 1998.
A - 3 . 3 E N V I RO N M E N TA L B E N E F I T S

A P P E N D I X 3

RE F E R E N C E S

Department of Energy, Energy

Information Administration. Impacts 

of the Kyoto Protocol on U.S. Energy

Markets and Economic Activity,

October 1998.

Department of Energy, Energy

Information Administration.

International Energy Outlook 1998,

April 1998.

Department of Energy, Energy

Information Administration. Form

EIA-28 (Financial Reporting System).

Department of Energy, Energy

Information Administration. Petroleum

Supply Monthly, December 1998.

Department of Energy, Secretary of

Energy Advisory Board. Energy R&D:

Shaping Our Nation’s Future in a

Competitive World, June 1995.

Gaddy, Dean E. Rig Activity Fails to

Bounce Back Despite $20/bbl Oil. Oil

& Gas Journal, September 20, 1999.

Gas Research Institute. Approved

1999-2003 Research and Development

Program and 1999 Research and

Development Plan, April 1998. 

Independent Petroleum Association of

America. 1996 Profile of Independent

Producers, www.ipaa.org

Interlaboratory Working Group.

Scenarios of U.S. Carbon Reductions:

Potential Impacts of Energy-Efficient and

Low-Carbon Technologies by 2010 and

Beyond. Oak Ridge National Laboratory

and Lawrence Berkeley National

Laboratory, 1997.

Interstate Oil and Gas Compact

Commission. Marginal Oil and Gas

Report, 1998.

Interstate Oil and Gas Compact

Commission. A Battle for Survival? The

Real Story Behind Low Oil Prices, 1999.

Lichtblau, J. Testimony before the

Senate Energy and Natural Resources

Committee Oversight Hearing. State of

the Petroleum Industry, January 28, 1999.

National Academy of Sciences. Oil in

the Sea: Inputs, Fates, and Effects, 1985.

National Environmental Education and

Training Foundation, www.neetf.org

National Laboratory Directors.

Technology Opportunities to Reduce 

U.S. Greenhouse Gas Emissions, 1997.

National Petroleum Council. The

Potential for Natural Gas in the United

States, 1992.

National Petroleum Council. Future

Issues—A View of U.S. Oil & Natural

Gas to 2020, 1995. 

President’s Committee of Advisors on

Science and Technology. Federal Energy

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Challenges of the Twenty-First Century,

November 1997.

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Spending. Oil & Gas Journal, April 5,

1999.

Schafer, E. Testimony before the 

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Committee Oversight Hearing. State of

the Petroleum Industry, January 28, 1999.

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www.state.gov

P h o t o g r a p h y

CANRIG—page 35

Corbis Images—pages 12, 19, 21, 51, 

66 (circuit square), 69, 78 (tractor); 

fact sheets 30 through 32 (upper left

icon: tractor)

Haliburton Energy Services —page 38

Hart Publications —fact sheets 19 

(freezing operations), 24 (men with gun)

Larry Lee Photography —cover (rig);

pages 11, 24-25

Panoramic Images —pages 58-59 

(arctic skyline), 60-61 (trees / grass), 

62-63 (city skyline), 64-65 (snowscape)

Pennsylvania Historical & Museum

Commission, Drake Well Museum

Collection, Titusville, PA —page 10

PhotoDisc—cover (polar bear /water,

clouds/ grass); inside front; pages 2

(fish, flag), 3, 6-7, 13, 18, 25 (alligator),

31 (ocean map), 44-45 (pine cones), 

48-49, 53, 54, 55 (starfish, snail), 

60 (beach), 63 (LA harbor), 64 (deer),

65 (black bear), 67 (boilers), 68 (leaf),

73; fact sheets 26 (rig), 31 (boat), 

32 (country road), 33 (mountains), 

35 (polar bears)

Picture Perfect—pages 21 (family), 

22 (boys), 23, 44-45 (pipeline /trees), 

52, 57, 78 (rig); fact sheets 33 through 36

(upper left icon: rig)

RBI-Gearhart—page 34

Rentech, Inc.—fact sheet 20 

(diesel fuel jars)

Society of Petroleum Engineers 

(SPE)—pages 1, 27, 31 (supply vessel),

33, 35, 43, 46, 76-77, 78 (rig, man, drill);

fact sheets 1 through 29 (upper left

icons: rig, man, drill); 4, (computer), 

8 (hydraulic), 9 (rig in water), 12 

(exploration operations), 16 (pipeline),

17 (pump), 28 (rig)

The Stock Market —pages 55 (housing

background), 58 (salmon), 66 (building)

Sundowner Offshore Services —page 30

Texaco Production Operations, CA —

page 28; fact sheet 1 (seismic image)

Tony Stone Images —cover (globe);

pages 2 (pump jack), 4-5, 9, 15, 61 (small

rig), 66-67 (hands with globe, field), 

68 (road)

Walt Seng Photography —page 7

(rollerblader)

WZI, Inc.—fact sheet 6 (truck /drill)

A c k n o w l e d g e m e n t s

This report was prepared by the 

U.S. Department of Energy, 

Assistant Secretary for Fossil Energy,

Office of Natural Gas and Petroleum

Technology, and supported by:

ICF Consulting

Technical and Analytical Content

Peter M. Crawford

Michael L. Godec

Richard S. Karp

and others

Brandegee, Inc./ Pittsburgh, PA

Editorial and De s i g n

Nancy A. Reese

Joe Tomko

with:

Robert C. Brandegee

Sarah H. Cornelius

Ann Kennedy

Emily A. Klein

Linda M. Ross

Karen D. Snyder

Julie E. Tabaka

Evan Wimer

WZI, Inc.

Technical Re v i e w

Theodore R. Blevins

Jesse D. Frederick

Mary Jane Wilson

Additional Contributors

Full Circle Type, Inc.

Industrial Illustrators
Comprehensive National Energy Strategy

In coming decades, our quality of life will depend significantly on scientific 

and technological advances supported by today’s energy policies:

• Improve the efficiency of the energy system. Efficient resource use is a

fundamental tenet of sustainable development, enhancing overall economic

performance while protecting the environment and advancing national security.

• Ensure against energy disruptions. Reducing the vulnerability of the United

States economy to disruptions in oil supply relies on stabilizing domestic oil

production; maintaining readiness of the Strategic Petroleum Resource, our 

Nation’s oil stockpile; diversifying import sources; and reducing consumption.

• Promote energy production and use in ways that respect health and

environmental values. Improving our health and local, regional, and global

environment quality must be integral to domestic energy production. Advanced 

oil and gas technologies are critical to achieving this goal.

• Expand future energy choices. Pursuing continued progress in science and

technology will provide future generations with a robust portfolio of clean and

reasonably priced energy sources.

• Cooperate internationally on global issues. The development of open,

competitive international energy markets and facilitating the adoption of clean, safe

and efficient energy systems are vital to addressing global economic, security, and

environmental concerns. Advanced oil and gas technologies provide opportunities

for international cooperation and demonstrating United States leadership.

Source: Comprehensive National Energy Strategy, Department of Energy, 1998

Furthering National Energy Goals
E Printed on recycled paper

October 1999

DOE-FE-0385

CONTACT

U.S. Department of Energy

Office of Fossil Energy

1000 Independence Avenue, SW

Washington, DC 20585

Nancy L. Johnson

(202) 586-6458

nancy.johnson@hq.doe.gov

Trudy Transtrum

(202) 586-7253

trudy.transtrum@hq.doe.gov