Beginning about 1976, groundbreaking research directed by the Department of Energy
catalyzed several innovative industry "firsts" that later became commercial technologies,
and also resulted in the acquisition, analysis and wide dissemination of an enormous
quantity of "ground truth" data on a topic that at the time generated little interest:
unconventional sources of natural gas. At the time, less than 7 percent of the natural gas
produced from gas wells came from unconventional sources.
Today, more than 40 percent of the natural gas produced from gas wells in the United
States--7.5 trillion cubic feet (Tcf) per year--comes from unconventional sources:
fractured gas shales, tight gas sands and coal seams. Without the contribution from these
reservoirs, the volume of natural gas the nation must import would be much higher than
its current level, which has reached about 15 percent of consumption.
The growth in unconventional gas production over the past thirty years has been driven
by several factors, but the rapid growth in new technologies for finding and producing
unconventional gas have played an important role. Tax credits that began in 1980, and
higher natural gas prices driven by rapidly growing demand have played a part in
supporting economics, but the tools for tapping into these resources when economics
began to make sense would not have been there, or would not have been adapted as
quickly, if the groundwork had not been laid by research carried out through the DOE's
Unconventional Gas Research (UGR) Programs.
For example, the first use of nitrogen foam to effectively stimulate production of gas
from shale wells, the discovery of how natural gas is stored in coal seams and fractured
shales, recognition of the importance of interconnected natural fractures in the production
of gas from such reservoirs, the first use of directional drilling in shale reservoirs to
improve productivity by intersecting fractures, the creation of advanced tools and
methods for measuring the properties of unconventional reservoir rocks, and the early
development of micro-seismic monitoring techniques for mapping hydraulically-created
fractures; are just a few of the advances initiated by DOE-funded research. The pay-offs
from these early investments are reflected in the commercial technologies that are making
the current expansion of unconventional gas production possible.
Today, for example, micro-seismic fracture mapping is playing a key role in optimizing
the way gas wells are hydraulically stimulated in the Barnett Shale Play in North-Central
Texas. The play has been proven to contain at least 2.1 Tcf of natural gas, and some
industry experts believe it to be the largest onshore natural gas field in the United States.
But the first systematic application of microseismic fracture mapping was a project
funded by DOE and carried out by Los Alamos National Labs in the 1970s. Subsequent
research performed at the DOE's Multiwell Experiment (MWX) site in Colorado during
the 1980s helped refine the process. Although it took two decades to make this
technology workable for normal oil and gas activities, DOE's long-term support was
critical in the development of commercial tools for microseismic monitoring of fracturing
As well, many wells in the Barnett play are drilled horizontally to intersect fractures and
maximize the flow rate of gas. DOE-industry collaborative efforts in the 1970s resulted
in the first directionally-drilled wells designed to intersect fractures in the Appalachian
Basin's Devonian shale play. These cost-shared demonstrations and the lessons learned
from them set the stage for the technological advancements leading to what is today a
widely applied practice in fractured shale plays like the Barnett and other reservoirs.
The largest portion of the unconventional gas produced today comes from the low
permeability (tight) sandstone reservoirs of the Rocky Mountains. In the Rulison Field of
the southern Piceance Basin of Colorado, carefully chosen well locations and technically
advanced well completion designs are dramatically increasing the volumes of gas that can
be extracted from these tight sands. However, the knowledge base and fundamental
science behind these advanced practices are rooted in work carried out by DOE at its
MWX Site in the Rulison Field during the 1980s. This research provided key insights
that convinced industry new technologies could be economical. Many of the same
lessons are now being applied in the tight sand reservoirs of Wyoming as well.
An estimate of the benefits resulting from DOE's unconventional gas research programs
was prepared and reported on in the National Research Council report titled "Energy
Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy Research 1978
to 2000" published in 2001. The Council reported benefits of several billions of dollars
in incremental state and federal tax revenues, trillions of cubic feet of incremental gas
supply, and billions in consumer savings due to lower natural gas prices accompanying
the supply increase.
Because of the substantial base of knowledge developed by DOE and the technologies
catalyzed by this early research, the Energy Information Administration (EIA) is now
able to make predictions of a strong future for unconventional gas production.
Production from tight sands, gas shales and coal seams is expected to reach 10.2 Tcf by
2030, nearly nine times the volume being produced when DOE's research program was
Three major resource areas (Eastern Gas Shales, Western Gas Sands, and Coal Seams)
and three less immediately accessible resources areas (Gas Hydrates, Deep Source Gas
and Secondary Gas Recovery), were the targets of R&D programs that extended from
about 1976 through 1992.
The total amount of money spent on these programs--about
$220 million, or less than $15 million per year--were a small fraction of the billions
spent by DOE over that time period.
Yet these investments provided a foundation for
technology development that led to the technology products and E&P methodologies
An estimate of the benefits resulting from the DOE's unconventional gas research
programs of the 1980s was prepared and reported on in the National Research Council
report titled "Energy Research at DOE: Was It Worth It? Energy Efficiency and Fossil
Energy Research 1978 to 2000" published in 2001.
- Foam Fracture Technology -- The Eastern Gas Shales Program (EGSP) was
responsible for the first use of nitrogen foam fracture technology. Prior to this time,
shale wells had been explosively stimulated in open-hole well bores. Foam fracture
stimulation technology allowed sand to be transported by the fracture fluid while
simultaneously reducing the volume of water used. By 1979, foam fracturing was the
preferred commercial method of stimulation for Devonian shale gas wells and
commercial services were widely available to operators in the eastern United States.
- Oriented Coring and Fractographic Analysis -- In 1977 the EGSP carried out the first
oriented coring and fractographic analysis of Devonian shale to detect natural
fractures. The use of oriented core was an innovation which allowed not only the
detection and location of natural shale fractures, but also allowed for the
determination of both fracture azimuth and dip - key parameters in determining
geologic structural trends, gas production mechanisms, reservoir modeling parameters
and reservoir anisotropy. The core analysis techniques developed for identifying
natural and core-induced fractures have since been used throughout the US to
evaluate low-permeability gas reservoirs.
- Gas Shales Logging Suite -- As part of the EGSP, DOE worked with the well logging
service industry to jointly develop an electric downhole well logging suite for airdrilled
bore holes. Most previous logging had required water or mud-filled wellbores,
liquids which damaged the permeability of the fluid-sensitive shales. By 1985, a
commercially available well logging suite was being used by industry within the
- Role of Adsorption in Devonian Shale Production Mechanism -- Gas desorption data
from 35 cored EGSP wells were used to establish the role of adsorbed gas and the
mechanism for gas flow through a network of interconnected natural fractures. This
permitted the development of more accurate production models that incorporated dual
porosity/dual permeability fluid flow in the reservoir, that in turn resulted in better
tools for reserve estimates and economic decision-making by industry. These
reservoir models also paved the way for later, similar models for coal seams.
- Downhole Video -- The EGSP carried out the first use of a downhole video camera in
the history of U.S. oilfield operations. By 1981, downhole video camera services had
been commercialized in the eastern U.S. with multiple companies operating in Ohio,
Kentucky and West Virginia.
- Large-scale Massive Hydraulic Fracturing -- The EGSP introduced large-scale
Massive Hydraulic Fracturing (MHF) to the Eastern gas shale marketplace. By 1990,
commercialization of MHF stimulation allowed industry to recognize the benefits of
such large scale stimulations in targeted shale areas.
- Directional Drilling to Improve Productivity -- DOE-industry collaborative efforts
resulted in the first Appalachian Basin high-angle gas shale directional well in 1975,
with additional wells drilled between 1978 and 1990. The EGSP was responsible for
the first air-drilled horizontal shale well, the first recovery of core from a horizontal,
air-drilled shale well, the first successful use of external casing packers in a horizontal
well, and the first horizontal well completed with seven individual hydraulically
fractured intervals. These cost-shared demonstration wells were the first to identify
the technology enhancements needed for wider application of underbalanced
horizontal drilling in the United States, a practice that is now widely used to enhance
production from other fractured shale reservoirs (e.g., Barnett shale of the Fort Worth
- Electromagnetic Measurement-While-Drilling -- Wells drilled as part of the EGSP
saw the first use of electromagnetic measurement while drilling (EM/MWD), where it
was introduced as a method for steering downhole motors. More than 13 field tests
were conducted during and after the EGSP program, leading to successful
commercial application in the US and western Canada.
- Carbon Dioxide Fracture Treatment -- The EGSP introduced the use of CO2/Sand
stimulation for Devonian shale wells, a technology not previously used in the US.
CO2/Sand stimulation subsequently became one of the stimulation options used in the
San Juan Basin on a commercial basis.
- Characterization of Eastern Shale Resources -- Basic knowledge gained from the
collection of 38,000 feet of oriented core from more than 35 wells and the
geochemical, fracture characterization, and detailed lithological analyses carried out
on the core, was used to characterize the Eastern gas shale resource across the
Appalachian Basin, including stratigraphy, structure, and geochemistry. Estimates of
recoverable gas in specific states were determined and published for use by operators.
Studies were extended to include organic shales in the Illinois and Michigan Basins.
- Economic Relationship of Technology and Recovery -- The EGSP performed the first
integrated assessments, based on subsurface data and validated models, to show how
the application of enhanced fracturing and infill drilling could be used to improve the
economics of Eastern gas shale production. This approach re-defined how operators
viewed Appalachian gas shale E&P.
- Advanced Tight Gas Core Analysis Technology -- Specialized equipment and
techniques were developed by the Western Gas Sands Program (WGSP) to fully
characterize the reservoir properties of very low permeability rocks. Of particular
importance were methods that were developed to test rocks under both in situ stress
and water saturation conditions and capillary pressure measurements to aid in the
understanding of the important two-phase flow mechanisms (water and gas). These
techniques are now routinely used for low-permeability core testing and are available
- Tight Sand Reservoir Characterization Methodology -- The WGSP utilized core
samples in three closely spaced wells, along with the careful assessment of surface
outcrops, to develop methods for quantifying the size of sandstone lenses in various
depositional environments. This methodology, which is now used by numerous
companies working in tight-sand basins, provides critical information needed for
resource assessment, reserves calculations, fracture design, and well spacing in these
- Naturally Fractured Core Analysis -- Through the WGSP, DOE developed a process
for analyzing fractured core and for identification of coring induced fractures that has
been transferred to numerous companies and is routinely used by industry.
Information from stress sensitivity testing of naturally fractured cores is now used in
many reservoir and fracture models.
- Stress Testing and Applications -- The Multiwell Experiment Site (MWX) employed
by the WGSP was where a methodology for micro-fracture stress testing through
perforations using down-hole shut-in was fully developed and where anelastic strain
recovery and circumferential velocity anisotropy were validated. Micro-fracture
stress testing is a testing procedure now used routinely by companies throughout the
world and anelastic strain recovery is a commercial service available through
- Advanced Tight Gas Log Analysis -- By running multiple logging suites (including
experimental logs) and coupling the results with the results of core analysis, new
correlations were developed that more accurately predicted tight gas sand reservoir
properties. The data were made available to all of the commercial logging companies
and used to improve the quality of tight sand formation evaluation.
- Extreme Overbalanced Perforating -- While attempting to develop methods for
effectively connecting to and testing the reservoir, the first extreme overbalanced
perforation operations were conceived and performed at the MWX site. Extreme
Overbalanced Perforating is a service performed by Halliburton and used routinely.
- Deviated or Horizontal Drilling in Fractured Reservoirs -- The Slant Hole
Completion Test carried out as part of the WGSP resulted in a number of
recommendations for using deviated well bores to exploit fractured reservoirs. This
approach is now widely applied throughout the U.S.
- Micro-Seismic Monitoring and Fracture Mapping -- The first successful microseismic
monitoring tests in tight gas reservoirs were conducted at MWX and showed
that fractures grew out of zone proportional to the stress contrasts and that fracture
lengths were considerably shorter than designed. The M-Site testing that followed on
the heels of the MWX portion of the WGSP, validated the accuracy of down-hole
micro-seismic monitoring for real-time mapping of hydraulic fracture growth and
established the accuracy of the technique, the interpretation of the data, and the
technology needed to acquire and process the data. Micro-seismic monitoring is now
considered the most accurate method of imaging fracture growth and is now a
globally-available commercial service. Downhole tiltmeters were first used for
fracture monitoring during these tests and this technology is now a commercial
service (Pinnacle Technologies) available to map fracture height and length.
- Fracturing Mechanisms -- Important insights into the mechanisms of fracturing,
developed from the early work at MWX and the follow-on work at M-Site, are now
being used in fracture models. Some of these are the development of multi-stranded
fracture systems as a routine part of fracturing, the identification of additional fracture
height containment in highly layered reservoir systems, and the variability in fracture
development with different fluid systems.
- First In Situ Observation of Fracture Behavior -- WGSP experiments provided the
first observational evidence of fracture behavior in situ. These tests showed that in
situ stress contrasts were the primary feature controlling fracture height growth, that
modulus contrasts had little effect on height growth, that natural fractures caused
considerable offsetting and branching of fractures, and that stress changes across
faults and interfaces could stop fractures.
- PDC Bit Technology Development -- Drilling technology was advanced by
breakthroughs in polycrystalline diamond compact (PDC) bits through work done at
Sandia National Labs and funded by DOE. The WGSP proved the effectiveness of
the Stratapax core bit. PDC bits accounted for 60 percent of the footage drilled
worldwide in 2005, and revenue from PDC bit sales reached $600 million in 2003.
- Comprehensive Tight Gas Resource Assessments -- The WGSP provided the first
comprehensive scientific quantification and characterization of a vast new resource,
removing any question that pursuing the difficult technical challenges of enabling
large-scale tight gas production was clearly worthwhile. The program highlighted the
concept and importance of basin-center gas formations, providing a rationale for the
unique off-structure exploration and development techniques that would enable
production from overpressured, low-permeability reservoirs. As a result of this work,
industry began not only to appreciate the volumes of gas present, but to see a way in
which it could be produced. As a result, tight gas began to be widely recognized as a
key part of the nation's resource base.
- Comprehensive Coal Seam Gas Resource Assessments -- The Methane from Coal
Seams Program (MCSP) established that a large, 400 Tcf natural gas resource was
contained in coal seams across 16 priority basins. Basin reports were completed and
published and gas-in-place estimates determined for eleven basins.
- Mining-Related Insights -- The MCSP helped to characterize the shape of the gob area
above longwall mining, assessed the effective placement of gob wells to maximize
recovery of gas and assessed the overall potential for gas production associated with
longwall mining in the Appalachian Basin. MCSP experiments verified that
hydraulic fracturing for recovery of coal seam gas in advance of mining does not
damage a mine roof and that predrainage of methane by drilling long, horizontal holes
from within a mine is compatible with longwall mining operations.
- Understanding Fracture Mechanisms in Coal Seams -- Significant research was
conducted to better understand the mechanisms controlling fracture initiation and
propagation, leading to the confirmation that: in the absence of confining stresses,
fractures will propagate along bedding planes, and that natural shale layers (stringers)
within the coal have a definite influence on fracture toughness.
- Coal Seam Gas Production Technology Development -- MCSP efforts included the
design, application and/or evaluation of 40 fracture treatments in six basins. These
tests helped to demonstrate: that coal seam gas could be efficiently produced using
vertical wells rather than in-mine horizontal drain holes, the technical feasibility of
completing a well in multiple coal seams from a single wellbore, that economic
production could be achieved from a multiple completion in spite of low methane
content of individual seams, and that nitrogen-generated foam is suitable for
- Fundamental Nature of Methane Storage and Flow in Coal -- DOE's initial coal seam
methane R&D program provided a significant portion of the scientific knowledge
base for this gas resource, and established the essential coal-bed methane storage and
flow mechanisms, including adsorption, desorption, diffusion, and fracture-dominated
- Enhanced Production from Existing Gas Reservoirs -- The Secondary Gas Recovery
Project identified 288 Tcf of natural gas in the nation's older fields that remained
unrecovered due to geologic complexity. The program, a joint venture among
government, industry and academia, applied 3-D seismic and vertical seismic
profiling to developing these reserves and transferred the tools to industry.
- Basic Gas Hydrates Knowledge -- DOE's Gas Hydrates R&D program developed the
first framework of basic knowledge about the distribution and physical/chemical
nature of naturally occurring methane hydrates, including comprehensive studies of
15 offshore basins and preliminary estimates of gas-in-place for hydrate deposits.
This collaborative gas hydrates research effort among industry, national labs,
academic institutions and multiple Federal agencies continues to the present day and
is currently the leading force in international gas hydrate research.
- Identified North Slope Hydrates -- The Gas Hydrates program established the
existence of hydrates in the Kuparuk Field of the North Slope of Alaska. The current
interagency gas hydrate R&D program is funding a joint venture stratigraphic test
well in that same area with BP Exploration Alaska (BPXA) to test the program's
seismic-based hydrate exploration methodology.
- Early Gas Hydrate Production Models -- The Gas Hydrate Program developed the
first preliminary production models for depressurization and thermal production of
gas from hydrates, setting the stage for what is today a suite of models that are being
used to model potential production scenarios in both arctic and marine hydrate
The estimated impacts resulting from the EGSP were an incremental 4.17 Tcf in gas
supply, 7.83 Tcf in proven reserves and 10,600 wells drilled over the 1978-2020 time
period. The dollar value of the benefits from state and federal tax revenue of the EGSP
was calculated at $1,040 to $2,080 million using a conservative value of $0.25 to $0.50
per Mcf for the additional gas supplies. Using the total program cost of $92 million, the
undiscounted benefit/cost ratio would be 10:1 to 20:1, based on incremental tax revenue
alone. In addition, DOE estimated over $8 billion in consumer savings due to lower gas
The same report determined that the Western Gas Sands program was successful in its
goal of increasing the supply of natural gas at lower cost. Tight gas production from the
Rocky Mountain gas basins was only 162 Bcf in 1978 at the start of the program; 10
years later it stood at 224 Bcf and in 2000 (when the NAS report was written) production
was estimated at 700 Bcf, a fourfold increase. Since the report was written, Rocky
Mountain tight sand gas production has grown even more; 2004 production from the five
targeted basins was 1433 Bcf, nearly nine times the rate at the start of the WGS Program.
The NAS report conservatively calculated a benefit to cost ratio of 8.9, and a contribution
of $591 million (1999 dollars) from royalties on federal lands and from increased state
severance taxes due to displacement of imports. Because of the substantial base of
knowledge and technologies developed under the WGS Program, the Energy Information
Administration (EIA) has been able to make predictions of strong future tight gas
production. The EIA calls for tight gas production from the Rocky Mountain basins to
reach nearly 2,300 Bcf and overall tight gas production in the U.S. to reach nearly 5,500
Bcf in 2020.
Historical and Estimated Future Unconventional Gas Production, Relative to DOE Unconventional
Gas R&D Funding 1978-1992. (Click to enlarge)
The NAS report also determined the economic benefits from DOE's Methane from Coal
Seams Program to total $499 million (1999 dollars) in increased revenues and cost
savings to producers, primarily from the Warrior and San Juan basins.
In addition, $91
million (1999 dollars) was credited from royalties on federal lands and from increased
state severance taxes due to displacement of imports. If DOE's basic research were
credited with only one-third of the benefits, recognizing the contributions of subsequent
Gas Research Institute and industry efforts, this would amount to about $200 million,
compared to a total investment of about $30 million.
The benefits attributable to the gas hydrates program are harder to quantify but still very
significant. The early DOE program initiated the first scientific inquiry into the nature
and distribution of gas hydrate to be focused on its potential use as a future source of
The level of international interest in gas hydrates has grown tremendously since
then, and the United States' position as a leader in gas hydrate research can be traced
back to this early program.
Should methane from gas hydrates someday play the same
important role in U.S. gas supply that unconventional gas does today, it will be due to the
R&D investment begun during the 1980s and extended during the current program.
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TABLE OF CONTENTS
2. GRI Research into Unconventional Gas Resources
3. Structure of the Enhanced Gas Recovery Program (EGR)
3.1. Eastern Gas Shales Program (1976-1992)
3.1.1. Key Questions and Related R&D Goals
3.1.2. Program Design and Overview of Major Projects
3.1.3. Key Eastern Gas Shales Projects
3.1.4. Highlights of Important Results
3.1.5. Subsequent Developments in DOE and Other Research Related to Eastern Gas Shales
3.2. Western Gas Sands Program (1978-1992)
3.2.1. Key Questions and Related R&D Goals
3.2.2. Program Design and Overview of Major Projects
3.2.3. Key Western Gas Sands Projects
3.2.4. Highlights of Important Results
3.2.5. Subsequent Developments in DOE Research Related to Tight Gas Sands
3.3. Methane Recovery from Coalbeds Program (1978-1982)
3.3.1. Key Questions Related to Coal Seam Methane
3.3.2. MRCP Program Design and Overview
3.3.3. Key Methane Recovery from Coalbeds Projects
3.3.4. Highlights of Important Results
3.3.5. Subsequent Research Related to Methane Recovery from Coalbeds
3.4. Deep Source Gas Project (1982-1992)
3.4.1. Key Deep Source Gas Projects
3.4.2. Highlights of Important Results
3.5. Methane Hydrates Program (1982-1992)
3.5.1. Methane Hydrates Workshop (March 1982)
3.5.2. Key Questions and Related R&D Goals
3.5.3. Program Design
3.5.4. Major Contracted Gas Hydrates Projects
3.5.5. Methane Hydrate Research Efforts of METC's In-House Organization
3.5.6. Highlights of Important Results
3.5.7. Subsequent Developments in Methane Hydrate Research
3.6. Secondary Gas Recovery (1987-1995)
3.6.1. Key Objectives and Program Design
3.6.2. Major Projects
3.6.3. Major Results
4. Elements of Spreadsheet Bibliographies (by Program)
Appendix A: Details of Major 1970-1980 Unconventional Gas Resource Assessments
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