Scott H. Stevens, Jason A. Kuuskraa
Advanced Resources International Inc.
Arlington, Va.Richard A. Schraufnagel
Gas Research Institute
Chicago
Since the late 1980s, more than $2 billion in capital investments and continued technological advances have harnessed an entirely new source of natural gascoalbed methane (CBM). From its roots as an experimental coal mine degasification method, the CBM industry today has grown into a significant component of U.S. natural gas supply.
Independent E&P companies that invested heavily in CBM development, such as Meridian Oil Inc. and Devon Energy Corp., saw their gas production, reserve holdings, and market capitalization rise sharply. Majors such as Amoco have relied on CBM to help stabilize their domestic reserve base while searching aggressively abroad for new international CBM opportunities.
This report, the second of a four part series assessing unconventional gas development in the U.S., examines the state of the CBM industry following the 1992 expiration of the Sec. 29 Nonconventional Fuels Tax Credit. Parts of the industry believed that CBM was largely a tax credit play that would die out once supports were removed. Now that several years have passed, however, it is becoming clear that the CBM industry has legs sturdy enough to carry it into the 21st century without special tax breaks.
This article presents the post 1992 drilling and production data, coupled with detailed assessments of specific CBM projects, which together paint a portrait of a CBM industry that overall continues to thrive without tax credits, thanks to improving E&P technology and continued identification of favorable reservoir settings.
Industry status
As of yearend 1994, CBM accounted for 5% of U.S. natural gas production and 6% of proved reserves. The principal producing areas remain the mature San Juan and Warrior basins, while new gas production is on line in the Central Appalachian, Uinta, Raton, Cherokee, Arkoma, Forest City, Powder River, and Piceance basins (Fig. 1).
A cumulative total of 13 tcf of CBM reserve additions has been booked in the U.S., mostly during the past 5 years. To place this number in context for natural gas, it equates to the building of a company larger than Amoco, the No. 1 domestic gas reserve holder at 11.7 tcf.
The most successful CBM operator, Meridian Oil (Burlington Resources), has vaulted into a virtual third place tie among domestic natural gas reserve holders (from ninth in 1989)pulling even with Shell and Chev- ronlargely due to CBM reserve additions (Table 1). CBM accounted for 227 bcf of Meridians total 384 bcf of natural gas production in 1994.
By mid-1995, the San Juan and Warrior basinsstill the dominant regions for CBM reserves and productionhave developed into mature gas provinces. Emerging areas, such as the Central Appalachian, Uinta, and Raton basins, are onstream and contributing increasing volumes of production. Small operators in the Cherokee, Forest City, Arkoma, and Powder River basins remain active in these low productivity, low cost plays.
Frontier CBM areas, including the Piceance and Greater Green River basins, offer large resource potential, but exploration and production technology for these more challenging settings remains inadequate.
Meanwhile, the success of the U.S. CBM industry has encouraged Amoco, Enron, and others to initiate aggressive exploration programs overseas in coal rich countries such as Australia and China in pursuit of large, low risk reserves.
In short, the potent combination of new technology and initial tax incentives unleashed a billion dollar per year CBM industry, one that competes on an even footing with other natural gas resources without tax supports.
Growth since 1992
Analysis of industry performance since 1992 indicates thatwhile the Sec. 29 tax credit undoubtedly accelerated investment in CBMthe better plays remain profitable without tax incentives.
Production, new well completions, and reserve additions all continued to grow after the tax credit expired. And, as technology and understanding of coal reservoirs continue to im- prove, new basins are being developed without a tax incentive. This shows that CBM no longer deserves the moniker of unconventional gas resource.
Consider the CBM industrys vital statistics (Tables 2-5, Figs. 2-4). Since tax credit expiration at yearend 1992, most important measures of the CBM industryincluding production, producing well counts, and reserveshave stayed strong or increased. U.S. 1994 CBM production totaled 858 bcf, up more than 50% from 562 bcf in 1992 (Table 2, Fig. 2).
New well completions slowed somewhat following the torrid pace of 1992-93, when many operators accelerated drilling to qualify for tax credits (Table 3). Announced plans for CBM development within new basins indicate a drilling rebound the next 5 years. Producing CBM wells during this period climbed to 6,301, an increase of nearly 1,000 wells since 1992 (Table 4; Fig. 3).
CBM reserves at yearend 1994 were 9.7 tcf, virtually unchanged since 1992 de- spite increased production (Table 5).
CBM well productivity varies widely by basin, due to variations in coal thickness, gas content, permeability, and other key reservoir parameters, and reflecting alternative completion and operation approaches (Fig. 4).
The San Juan basin is the most prolific, with average production exceeding 800 Mcfd/well and many individual wells averaging over 3 MMcfd within the fairway. In contrast, Warrior basin wells average 120 Mcfd, reflecting lower permeability and thinner coal seams, although with best practices, lower well costs, and higher wellhead gas prices the better wells are still economically viable. Results in emerging basinssuch as the Uinta and Ratonare preliminary but initial well productivity has been highly encouraging, as discussed below.
Mature CBM basins
San Juan basin
The San Juan basin dominates the industry, accounting for 82% of total CBM production in 1994. Production continued to rise by 15% in 1994 to 706 bcf, but new well completions dropped to one third of 1992 levels as the basin matured with just over 2,500 producing wells.
Many of the most favorable sweet spots have been drilled. Still, the bulk of these new wells are highly productive open hole dynamic cavity completions that average 2-3 MMcfd/well. Operators are sidetracking or redrilling previously cased and fractured wells and recompleting using cavitation, thereby upgrading the productivity of producing properties within the San Juan fairway. New technologies such as nitrogen- and CO2-based enhanced CBM recovery, currently undergoing testing by Amoco and Meridian, show potential for significantly increasing San Juan basin CBM reserves.
Expansion in gas gathering systems and debottlenecking are enabling this basins CBM wells to produce closer to full potential. New drilling is concentrated in the northwestern part of the basin with promise of a second fairway as this area dewaters. The high costs of water disposal and lack of low cost water treatment technology are barriers to expanded development.
Warrior basin
Development in the Warrior basin slowed markedly following the end of the tax credits, with just 79 new CBM wells added during 1994.
Time and experience have shown that major parts of the Warrior basin were viable only under higher than current gas prices or with the tax credits due to modest per well productivity and the need for costly multiple stimulations to complete the thin Mary Lee, Blue Creek, and Black Creek coal seams.
Warrior basin gas production held steady during 1994 at 108 bcf. Productivity of the 2,706 CBM wells on line averaged a modest 117 Mcfd/ well in December and has steadily improved with de- watering of the coal reservoirs and well remediation (Fig. 4).
However, significant writedowns in reserves took place in Alabama, including 526 bcf in 1993 and an additional 190 bcf in 1994, due to inappropriate well siting, sub-optimal completion and stimulation practices during the pre-1992 CBM boom, and problems with gas recovery from the thin, numerous Black Creek coal seams. Although Warrior basin CBM wells can achieve rates in excess of 300 Mcfd under optimal completion and stimulation practices, with the best areas already developed significant new grassroots CBM activity is unlikely.
The one encouraging recent development has been the remediation of inadequately completed wells.1 Research sponsored by Gas Research Institute at the Rock Creek production test site showed that initial well completion techniques often led to below optimum gas rates and highly damaged well conditions. A steady program of using less damaging fracture fluids, such as foam or just formation water, and more rigorous quality control on perforation and zone by zone stimulations have enabled new wells to show improved gas production rates and reserves. Many unexplained production problems remain, such as why properly completed wells in evidently favorable areas of the basin fail to respond.
New CBM basins
As technology and understanding of coal seam reservoirs improve, new basins are expected to account for an increasing share of CBM production. Three highly promising emerging CBM areas are the Central Ap- palachian basin in Virginia and West Virginia, the Uinta basin in Utah, and the Raton basin in Colorado and New Mexico (Fig. 1).
Together, these three basins accounted for only 6% of total CBM production in mid-1995, but production is positioned to expand rapidly the next 5 years.
Central basin
With a CBM resource estimated at 5 tcf, the Central Appalachian basin is the smallest of the new generation of CBM plays.2
Commercial development was sparked due to early success with coal mine degasification wells and favorable prices. Much of the current CBM development takes place in conjunction with coal mining: production from conventional hydraulically stimulated CBM wells predominates, but recovery and sale of production from unstimulated ventilation boreholes and gob wells associated with longwall coal mining operations are significant.
Passage of a Gas and Oil Act in 1991, codifying CBM ownership and regulation, has promoted production in Virginia, while recently enacted laws in West Virginia are expected to foster development.
Principal reservoirs are the Pennsylvanian Pocahontas and Lee coal seams at depths of 500-3,000 ft. Completed coal thickness averages a relatively thin 8-12 ft, but gas content of the medium to low volatile bituminous rank coal is high at 400-600 cf/ton. Well tests at a USBM/Island Creek project measured in situ permeability of 5-8 md, a figure that has been validated by subsequent well production.
As of June 1995, a total of 612 CBM wells and 117 gob/ventilation boreholes were on line in Dickenson, Buchanan, Wise, and Russell counties of western Virginia. Gas production in the basin totaled 121 MMcfd, for per well averages of 175 Mcfd for CBM wells and 125 Mcfd for gob wells.
Major operators are Consolidation Coal Co. (Consol), which acquired the Island Creek and Pocahontas Gas Partnership properties in 1993, and Equitable Re- sources (EREX). These and other operators produced a total of 28 bcf from 515 wells during 1994; 1995 production is expected to exceed 35 bcf.
Consols Oakwood field in Buchanan County, Va., is the largest field in the Central Appalachian basin. Consol operates 209 fractured wells producing an average 160 Mcfd/well during August 1995, although some of the better wells average nearly 400 Mcfd (Fig. 4).
A variety of completion techniques, both open hole and cased hole, has been used in this field the past few years. Generally, wells were cased through the Pocahontas No. 3 seam and hydraulically stimulated with three to four treatments per well, using a mixture of 30,000-50,000 lb. of 12/20 and 20/40 mesh sand with 1,500-3,000 bbl of fresh water, linear gel, or N2-gel foam. Accelerating development since 1992 indicates that the Central Appalachian basinwith its low well costs and attractive wellhead gas pricesis economic without tax supports.
Uinta basin
A major new CBM discovery within the Uinta basin is the best candidate yet to match the prolific San Juan basin. The significance of this discovery is that it demonstrates for the first time that San Juan type reservoir conditions are not necessarily unique, intensifying the search for highly productive coal basins in the U.S. and abroad.
River Gas Corp. and Texaco jointly drilled 73 production wells at the Drunkards Wash Unit near Price, Utah, and expected to have 92 wells on line by yearend 1995. Following early successes, the operators with new partner Dominion Resources have submitted plans to the U.S. Bureau of Land Management outlining a 1,000 well development program involving the drilling of up to 100 CBM wells/year through 2005.
The Drunkards Wash wells target Cretaceous Ferron coal seams of high volatile B bituminous rank at about 2,000 ft. Net coal thickness averages about 30 ft, with gas contents of approximately 400 cf/ton, unusually high for this rank and depth. Reservoir conditions are overpressured, and free gas is commonly present within the coal cleats and fractures. A secondary target is the lenticular sandstone intercalated with the Ferron coal seams that may provide enhanced storage and deliverability.
Most of the Drunkards Wash wells were air drilled to minimize coal reservoir damage and then cased through the coal.3 Hydraulic stimulations typically em- ploy three individual treatments totaling 200,000 lb. of sand proppant carried by 120,000 gal of crosslinked gel. Drilling and completing a well takes about one week. Block contracts with service companies have helped minimize well drilling, completion, and hydraulic stimulation costs to an average $274,000/well. With gas reserves estimated at over 2 bcf/well,4 this play has a highly attractive finding/ development cost estimated at under 15/Mcf.
Although on line for only 2 years, gas production at the Drunkards Wash unit is high and continues to improve as the reservoir is dewatered. Current production from the initial 33 well program averages more than 600 Mcfd/ well, with production from five wells exceeding 1 MMcfd (Fig. 4). Assuming uniform reservoir conditions, the planned 1,000 well Uinta basin expansion would add over 2 tcf of new CBM reserves. The Utah Geological Survey further estimates that, assuming favorable reservoir conditions extend over the wider fairway, 3,400 CBM wells could ultimately be developed in the Uinta basin.
Raton basin
Located east of the San Juan basin in southeastern Colorado and northeastern New Mexico, the Raton basin has a CBM resource estimated at 10.8 tcf.5
Cretaceous age Raton and Vermejo formation coal seam reservoirs resemble in many respects those of the correlative Fruitland coals of the San Juan, although their thinner and less continuous nature and the presence of igneous intrusives present challenges for completion technology. During the past 5 years, industrys understanding of the Raton basin coal reservoirs has advanced and, with new pipeline construction, the basin is now poised for accelerated CBM development.
Nearly 150 CBM production test wells have been drilled to date in the Raton basin, most during the exploratory period 1985-91. Early results were mixed, reflecting sub-optimal well siting and completion techniques, while a lack of pipeline infrastructure precluded commercial development.6
Recently, however, operators have identified a potential high rank, high gas fairway within the central Raton basin along the Purgatoire River, away from the high recharge western margin where water production was excessive. In addition, moderate sized and better contained hydraulic stimulations have been developed to avoid completing water prone igneous intrusives and sandstones.
During 1994, Amoco and Colorado Interstate Gas Co. constructed a 20 mile line west from Trinidad, Colo., to bring Raton coalbed gas to market for the first time. Future pipeline expansions are planned to link Evergreen Resources Inc., Meridian, and other coalbed properties within the central Raton basin fairway to the central pipeline system. The early production results from two of the major companies in the central Raton basin CBM play are as follows:
- Evergreen, of Denver, has drilled on a 100,000 acre farmout from Amoco. Evergreen brought on line nine wells in mid-1995 in the Spanish Peaks Unit in 33s-65w and 33s-66w. These wells have averaged 210 Mcfd each during their first two months of production, with the best well averaging 435 Mcfd.
- Gas production at Amocos two well Burro Canyon Unit in 28-32s-66w has increased steadily from 277 Mcfd/well after initial hookup in November 1994 to 831 Mcfd/well as of June 1995. Water production has declined by half to about 300 b/d, reflecting dewatering and depressurization of the Vermejo coal seams that is projected to boost gas production to more than 1 MMcfd/well. Amoco plan- ned two more stepouts in this unit in late 1995.
In New Mexico, the only active operator has been Pennzoil, which has drilled a total of 36 wells on its 780,000 acre Vermejo Ranch. Vermejo coals were drilled, cased, and then stimulated with water or gel and a substantial sand proppant load averaging 250,000 lb. Six month production tests were modest, ranging from 60-100 Mcfd/well, although higher productivity was noted along the fractured Vermejo Park anticline. With no firm plans for pipeline construction in the southern Raton basin, Pennzoil idled its coalbed program.
New CBM technologies
Open hole cavitation
Operators within the overpressured, highly permeable San Juan basin fairway have found that open hole cavitated wells significantly outperform conventional cased and fractured completions, generally by three to seven times (Fig. 5) for over 800 wells in the fairway. Outside the fairway, conventional fractured wells generally outproduce cavitated wells.
The use of cavity completions helped underscore the serious damage being caused to permeability by the use of heavy borate crosslinked gels during stimulation. It also showed that hydraulic fractures were contacting only a portion of the total coal package. Understanding of these conditions has led to significant changes in CBM stimulation design and operations.
The critical reservoir conditions for successful cavitation are still only partly understood. In general though, low stress settings with good permeability, adequate seam thickness, and fully gas charged coals are favorable. The use of CAVITYPC, the first publicly available rock mechanics model to simulate the process of open hole cavitation, is providing insights into this complex but highly effective well completion technology.
Dynamic open hole cavitation is achieved by repeatedly injecting water air mixtures into the coal seams at high rates and pressures, followed by rapid blowdown which promotes sloughing of coal into the wellbore, increasing its radius to several feet or more. Apart from the finite benefits of larger hole size, productivity is enhanced by the tensile and shear fractures hypothesized to be induced near the wellbore by the cavitation process, which better link the wellbore to the reservoirs natural cleat and fracture system.7 Modeling of the cavitation process shows that permeability in the near-wellbore area can increase tenfold over pre-cavitation reservoir conditions.
Well remediation
During the late 1980s boom years in the Warrior basin and in the rush to drill prior to tax credit expiration, many wells were inappropriately completed and experienced low productivity. During 1993-94, GRI sponsored a research program aimed at developing technology to remediate these poorly producing wells. The Productivity Improvement Program (PIP) study found that a number of factors contribute to poor performance in the Warrior basin, including:
- inadequate isolation of zones targeted for completion due to poor cement jobs;
- perforations plugged with mineralized scale, particularly in deep wells; and
- coal seams not receiving sand proppant during initial stimulation treatments.7
A second finding of the PIP study was the general lack of reliable, easy to use, low-cost diagnostic tools and methods. Among the few diagnostic tools found to be effective were wireline conveyed downhole camera to identify plugging and nonstimulation of coal intervals, and production logging and zone isolation packer tools to determine zonal gas flow contribution.8 These diagnostic tools showed that up to one third of the coal package was poorly (if at all) connected to the wellbore.
It is estimated that improved recompletions could add approximately 550 bcf of CBM reserves and restore the productivity of up to 1,000 poorly producing wells. Recompletion of one GRI Rock Creek R&D well, P-3, showed that proper completion methods could increase gas production five fold to 300 Mcfd, even after the well had been on line for 9 years9 (Fig. 6).
Reservoir work
Improved characterization of CBM reservoirs has helped operators understand the crucial production mechanisms and properly match technology to the resource. Advanced reservoir simulators, such as the COMET2 model, which captures the key gas storage and flow mechanisms for CBM, have enabled CBM reserves to be reliably booked and evaluated. COMET2 is the first triple porosity/dual permeability model for CBM and is capable of simulating enhanced recovery using nitrogen or CO2 flooding.10
Advances in establishing gas contents and multicomponent isotherms have helped operators pinpoint and avoid high water production, undersaturated coal conditions. Zone by zone coal characterization has provided insights as to gas and water charged coal intervals, enabling more selective coal completions and more appropriate stimulation fluids to be used. Improvements in two phase well testing and analysis have provided a clearer picture of coal permeability and its capacity to produce gas.
N2/CO2 flooding
New enhanced CBM (ECBM) recovery technology developed by Amoco, Meridian, and other companies has the potential to dramatically boost gas recovery much as EOR can improve oil recovery.11
Two ECBM methods are being tested in the San Juan basin: displacement desorption using CO2 or other strongly sorbing gases; and inert gas stripping employing nitrogen to lower the partial pressure of methane. Initial field testing by Amoco indicates that nitrogen ECBM offers commercial promise. Meridians four well CO2 flood project at the Allison Unit is under way, but no results have been released.
Injection of nitrogen into coal reservoirs reduces the partial pressure of adsorbed methane, accelerating desorption and production of methane while maintaining overall reservoir pressure. Laboratory tests and computer simulations conducted by Amoco, which holds a patent for application of this method, indicate that up to 90% of OGIP may be recovered from relatively homogeneous coal reservoirs, significantly higher than the 30-70% generally recoverable with conventional reservoir depressurization.
Field tests of nitrogen ECBM in the San Juan basin have demonstrated that this new technology may have significant commercial potential (Table 6).
During 1993, Amoco successfully conducted the first nitrogen flood test within a CBM reservoir. Amocos test pattern consisted of four exterior injection wells and the central Simon 15U-2 production well in the northwestern San Juan basin. The Simon test was successful over a 1 year interval, as Amoco reported methane production increasing five fold to over 1 MMcfd in the central production well.
Encouraged by the Simon test results, Amoco, Conoco, and Meridian are jointly implementing a nitrogen flood at their 28-7 Unit in the central San Juan basin. This is a 12 well (seven producers, five injectors) project on 320 acre spacing that will be the first commercial scale demonstration of ECBM technology. Nitrogen for injection will be sourced from air using a skid mounted membrane separation system, compressed to 2,000 psi, and then injected at a total rate of 4.5 MMcfd into the Fruitland coal reservoirs.
The operators anticipate a fivefold increase in production from current relatively low rates to a total 3.5 MMcfd. Nitrogen injection will take place for 2-4 years, with ECBM recovery expected to last 5-10 years. The nitrogen cut of the produced gas is expected to increase gradually from 5% initially, possibly to as high as 50% of total gas production by the end of the project. Thus, nitrogen separation from produced methane is expected to be the largest operating cost in the late stage of ECBM projects.
Amoco plans a more extensive ECBM pilot within its Tiffany area in the north central San Juan, where the Fruitland coal reservoirs are more permeable than at the 28-7 Unit. Scheduled to commence operations during 1996, Amoco will operate a total of 13 injection wells that will pump 25-30 MMcfd of nitrogen into the reservoir. Amoco anticipates incremental recovery of up to 50 bcf from the 30 production wells. Amoco predicts that ECBM application at Tiffany will boost production at the pilot field fivefold to a total of 25-30 MMcfd. Capital costs are estimated at $20-30 million, while operating costsprimarily for nitrogen separationare expected to be $4-6 million/year.
Apart from the San Juan basin, Amoco also plans to extend application of ECBM technology to other coal basins. During 1995, Amoco initiated a nine well nitrogen injection program in the central Raton basin in southern Colorado that targets Raton and Vermejo formation coalbeds at depths of about 2,500 ft.
During the late 1980s, Amoco had drilled and successfully tested 11 Raton/ Vermejo wells in this area, but with no pipelines nearby the wells were shut-in. Amocos ECBM test pattern in the Raton basin will comprise two nitrogen injection wells and seven producing wells within this existing project. Nitrogen injection rates are planned at 2.25 MMcfd per injector at a maximum bottomhole pressure of 700 psi, just under the natural fracture gradient for the deeper zone. Once ECBM operations begin, Amoco anticipates incremental methane production of 5.9 MMcfd from the seven production wells, up from 1.4 MMcfd of base production. Both nitrogen and CO2 ECBM require relatively homogeneous reservoirs with few lateral discontinuities, which is characteristic of the San Juan and several other coal basins in the western U.S.
The major costs for nitrogen ECBM include capital expenditures for drilling and completing nitrogen injection wells, operating costs for membrane and cryogenic separation of nitrogen from air prior to injection, and nitrogen separation from methane following production. Amoco estimates incremental capital and operating costs for nitrogen ECBM to be under $1/Mcf of new reserves in the San Juan basin. With continued technological refinement, ECBM is likely to significantly expand reserves of CBM in the U.S. and extend the production life of the San Juan and other western U.S. CBM basins.
Conclusions
Spurred by an early infusion of innovative R&D and tax incentives, coalbed methane has evolved into a stand-alone industry. Still, numerous challenges remain for expanding the CBM play to new, geologically more challenging basins in the U.S. and overseas and improving the recovery from existing wells. These dual challenges call for continued advances in technology to realize the full potential of the massive CBM resource base.
Acknowledgments
Research for this study was supported in part by funding from Gas Research Institute Contract No. 5086-213-1390. The authors thank the numerous individual operators and state oil & gas boards who generously contributed information for this study, particularly Jack E. Nolde, Virginia Department of Mines, Minerals and Energy; David Tabet, Utah Geological Survey; and Douglas Bland, New Mexico Bureau of Mines and Mineral Resources.
References
1. Young, G.B.C.,. Paul, G.W., Saulsberry, J.L., and Schraufnagel, R.A., Identification of multiseam coalbed methane wells with recompletion potential, 1994 AiChE summer national meeting, Denver, Aug. 15, 1994.
2. Kelafant, J.R., and Boyer, C.M., A geologic assessment of natural gas from coal seams in the central Appalachian basin, GRI Topical Report, GRI 88/0302, 1988.
3. Willis, C., Drilled core holes key to coalbed methane project, OGJ, Mar. 6, 1995, pp. 73-75.
4. Young, G.B.C., Paul, G., and Kuuskraa, V.A., Reservoir simulation study of U.S. coalbed methane, Technical report in support of U.S. Geological Survey 1995 National Assessment of U.S. Oil & Gas Resources, 1995.
5. Stevens, S., Coalbed methanestate of the industry, Quarterly Review of Methane from Coal Seams Technology, Vol. 11, No. 1, August 1993, pp. 33-36.
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7. Mavor, M.J., Coal gas reservoir cavity completion well performance, International Gas Research Conference, Orlando, Fla., Nov. 16-19, 1992.
8. Lambert, S., Reeves, S.R., and Saulsberry, J.L., Coalbed methane production improvement recompletion project in the Warrior basin, GRI Topical Report, GRI-95/0034, October 1995.
9. Kuuskraa, V.A., Reeves, S.R., Schraufnagel, R.A., and Spafford, S.D., Economic and technical rationale for remediating inefficiently producing eastern gas shale and coalbed methane wells, SPE 26894, Eastern Regional Conference & Exhibition, Nov. 2-4, 1993.
10. Advanced Resources International Inc., COMET2 Users Guide Version 2.0, 1995.
11. Yee, D., and Puri, R., Enhanced coalbed methane technology in the San Juan basin, presented at Pittsburgh Coalbed Methane Forum, Apr. 14, 1995.
The Authors
Scott Stevens is a project manager with Advanced Resources, where he conducts geologic and financial analyses of natural gas projects in the U.S. and overseas, particularly for coalbed methane. He formerly was an explorationist with Texaco and Getty International. He has graduate degrees from Scripps Institution of Oceanography and Harvard University.
Jason Kuuskraa is a research assistant at Advanced Resources. He specializes in the analysis of U.S. unconventional gas resources, especially in the Appalachian basin. He formerly worked as an energy analyst for Cambridge Energy Research Associates. He has degrees in mathematics and history from Boston College.
Richard A. Schraufnagel is a senior technology manager with Gas Research Institute in Chicago, where he manages research projects related to coalbed methane production. Before joining GRI he was a senior engineer for 8 years with Atlantic Richfield stationed in Plano, Tex., Tucson, and Anchorage. He is a graduate of the University of Wisconsin, Madison, in chemical engineering and received MS and PhD degrees in chemical engineering from the University of Texas at Austin.
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