EXECUTIVE SUMMARY

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 procedures.

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 initiated.

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 highlighted below.

• 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 Appalachian Basin.
  
  
• 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 Basin).
  
  
• 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 commercially.
  
  
• 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 fields.
  
  
• 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 Halliburton.
  
  
• 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 stimulating coalbeds.
  
  
• 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 flow.
  
  
• 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 settings.

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 energy.

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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