EXPLORATION How unconventional gas prospers without tax incentives

Vello A. Kuuskraa
Scott H. Stevens
Advanced Resources International Inc.
Arlington, Va.

It was widely believedand sometimes too loudly statedthat the development of unconventional natural gas (coalbed methane, gas shales, and tight gas) would die once U.S. Sec. 29 credits stopped. Quieter voices countered, and hoped, that technology advances would keep these large but difficult to produce gas resources alive and maybe even healthy.

Sec. 29 tax credits for new unconventional gas development stopped at the end of 1992. Now, nearly three years later, who was right and what has happened? Was the past activity in unconventional gas merely artificial and transitory, maintained by a price subsidy disguised in the cloak of a tax credit, or is the development of these new gas sources founded on a more permanent rock of technology and resource understanding?

Why are early answers to these questions important?

• Potential new entrants to the U.S. unconventional gas play are holding back, worried that continued commercial development would not be possible once Sec. 29 tax credits ended in 1992. Are these worries well founded?

• Many overseas firms, looking to develop their own coalbed methane or tight sands gas, continue to make other investment choices believing that unconventional gas sources are not economically viable without price subsidies or tax credits. Are they making the best investment choices?

• Research investment in coalbed methane, gas shales, and tight gas has been curtailed by industry and its supporting R&D institutions because it was judged that the resulting technology would not be used once tax credits ended. Was this the right call?

This first of a four part series of articles concludes that, just as inaccurate forecasts of high future natural gas prices have hurt the competitive position of this fuel, so too a lack of understanding of the technology and economics of unconventional gas may have contributed to incorrect investment and R&D decisions on this resource. It is the aim that at the end of this series, the reader will have a more fact-based perspective on the status, economic potential, and outlook for coalbed methane, gas shales, and tight sands.

Perspective

There is no doubt that Sec. 29 tax credits stimulated the development of coalbed methane, gas shales, and tight gas. Tax credits attracted new sources of capital that helped fund this gas play, including the innovative coalbed methane royalty trusts floated by Wall Street.

Tax credits helped to reduce risks and raise financial returns, enabling new projects to pass high, risk-weighted economic hurdles common to these resources.

What is less known is that the tax credits helped spawn and push into use an entire new set of exploration, completion, and production technologies founded on improved understanding of unconventional gas reservoirs. As set forth below, while the incentives inherent in Sec. 29 provided the spark, it has been the base of science and technology that has maintained the vitality of these gas sources.

Current status

For the past five years, coalbed methane, gas shales, and tight sands have been a major part of U.S. gas drilling and development, accounting for three out of four gas wells drilled in 1992. For the past two years, 1993 and 1994, this ratio has dropped, but these three gas resources still account for three out of five U.S. gas wells drilled (Table 1)(13903 bytes).

Overall, development of unconventional gas has declined since the end of tax credits in 1992. However, the decline from 1992 has been modest and may be reversing:

• Unconventional gas well completions were down by less than 300 wells in 1993 and by about 800 wells (or 12%) in 1994 from the 6,293 wells completed in 1992.

• While the data are still being collected, the preliminary results for 1995 show a rebound in unconventional gas well drilling in the first six months, led by strong Antrim gas shale and Rocky Mountain tight gas development.

The historic data also show that the Sec. 29 tax credits helped maintain unconventional gas drilling, and even accelerated gas shale development in the Michigan and other basins as operators rushed to put qualifying wells in the ground in the face of an industrywide slump in overall gas drilling in 1992.

Unconventional gas represents the major focus of U.S. gas drilling, when measured by wells. However, unconventional gas represents a much smaller portion of E&P investment, production, and reserves. This is because a large portion of the coalbed methane, gas shale, and Appalachian tight gas wells are shallower, lower in cost, and lower in gas production and per well reserves. Still, the U.S. has seen a steady growth in unconventional gas production (Table 2)(16055 bytes).

The growth in production of natural gas from coalbed methane,1 gas shales, and tight sands has not been interrupted by the end of Sec. 29 tax credits in 1992:

• Annual production of unconventional gas reached 3.6 tcf in 1994, equal to 20% of overall U.S. natural gas production and nearly 30% of U.S. Lower 48 onshore gas production.

• Unconventional gas has accounted for essentially all of the growth in U.S. natural gas production since 1990. (The gas supply forecasts of Gas Research Institute and the U.S. Department of Energy project that unconventional gas will need to continue its role as the main source for meeting increasing U.S. gas consumption.)

• The biggest gains in gas production have been from coalbed methane and gas shales, with tight gas (while still the largest overall contributor) showing only modest growth since 1990.

Development healthy

In light of the evidence showing continued strong drilling for coalbed methane, gas shales, and tight sands, the question is: Why has development of these gas sources remained healthy? There were several economics-based reasons to have expected otherwise:

• The price incentives embedded in Sec. 29 tax credits were strong, equal to about $1/Mcf for coalbed methane and gas shales and about 50/Mcf for tight gas. Obviously these incentives had the potential to make a major difference in the bottom line.

• Wellhead gas prices that averaged $1.74/Mcf in 1992 did improve in 1993. But gas prices fell back in 1994, and now in 1995 gas prices have dropped below 1992 levels.

• Well drilling and completion costs for gas wells overall were higher in 1993 and 1994 than in 1992.

All of these argue that coalbed methane, gas shales, and tight gas development should have taken at least a major hit after 1992 when tax credits ended.

The simple answer to the quandary of why unconventional gas did not wither is that, driven by improving technology, finding rates, and well productivities (measured in terms of bcf per well) improved and kept these resources economic. Because well productivities (finding rates) are volatile on a year-to-year basis, reflecting the sporadic timing of reserve bookings, a three year running average has been used to smooth the annual data (Table 3)(12313 bytes).

The steady improvements in the reserves added per well, most notable for coalbed methane, but important also for tight gas and gas shales, give support to the hypothesis that improving technology and resource understanding have enabled unconventional gas to survive the end of Sec. 29 tax credits.

Technology

The term new technology has been used broadly in this and other articles on gas supply. What are these new technologies and how have they enabled producers to increase their reserves per well?2 The list is long and includes a mixture of small changes and radical breakthroughs in extraction technology plus, and maybe most importantly, an improved characterization of these new gas resources and how to best match technology to their recovery. A sampling follows:

• A significant improvement in the quality of these low-permeability wells is from improved well sitingthe placing of the bulk of the new wells into areas that are more intensely naturally fractured, the sweet spots. Advances in remote sensing, using satellite imagery and high resolution aeromagnetics, improved 3D and shear wave seismic, and modeling of basement tectonics and basin evolution are the new tools for finding sweet spots.3 4

• The second set of advances involve improved linkage of the wellbore with the naturally fractured gas reservoir. These include (1) using open hole cavity wells in the San Juan coalbed methane fairway to im- prove gas production rates by sixfold over hydraulic stimulations, and (2) applying improved hydraulic frac technologies to remediate old gas shale wells in the Michigan basin and to develop new tight sand wells in the Piceance basin; and (3) using horizontal wells to produce high rates of gas from tight Mesaverde sands in the Rocky Mountains where hydraulic stimulation had been ineffective.5-7

The third, and arguably the most important, technology advances have been in building a scientific understanding of the controlling production mechanisms, correctly characterizing the reservoirs, and then properly matching technology to the resource. Improved reservoir models have emerged that capture the key gas storage and flow mechanisms, such as the COMET2 model for coalbed methane and gas shales. Also, improved rock mechanics models such as FRACPRO for hydraulic fracturing the Cavity-PC for well cavitation and providing insights on how better to link the well to the reservoir.8 9 10

While aggregate data on unconventional gas activity provide an important overall perspective, additional insights can be gained by looking (in more depth) at each of the three gas sources, as provided in the rest of this article.

Coalbed methane

1. Annual production. Production of coalbed methane has continued to climb, reaching 858 bcf (2.35 bcfd) in 1994, up 53% from 562 bcf (1.54 bcf) in 1992 (Fig. 1)(24879 bytes). The prolific San Juan basin accounts for over 80% of 1994 coalbed methane production, with the Appalachian and Uinta basins showing recent growth.

2. Proved reserves and reserve additions. Proved coalbed methane reserves slumped for the first time, to 9.7 tcf in 1994 from 10.3 tcf in 1993 and 9.8 tcf at the end of 1992 (Fig. 2)(25139 bytes). Even though substantial new reserves were being added by drilling, low gas prices prompted significant reserve write-downs and well shut-ins in both the Warrior and San Juan basins in 1994. In line with increasing gas production, significant new coalbed methane reserve additions were recorded in the Central Appalachia and Uinta basins.

3. Producing wells and well completions. Producing coalbed methane wells reached 6,301 in 1994, up by over 1,000 wells from 1992 and by more than 4,000 wells from 1990 (Fig. 3)(25951 bytes).

New coalbed methane well completions have declined since 1992, following the rush to qualify wells prior to the deadline. New drilling in the Arkoma, Central Appalachian, and Uinta basins helped counter sharp declines in San Juan and Warrior basin coalbed methane drilling (Fig. 4)(24442 bytes). Lack of basic information on the key reservoir characteristics of coals coupled with a halt in R&D and field demonstrations have impeded industrys efforts for expanding coalbed methane development into new basins.

4. Industry activity. Meridian Oil Inc., Amoco Production Co., and Devon Energy Corp. are three of the major U.S. coalbed methane players, accounting for 460 bcf (or over one half) of total coalbed methane production in 1994:

• For Meridian, coalbed methane accounted for 227 bcf of its 384 bcf of 1994 natural gas production. CBM has enabled Meridian to become the fifth largest holder of proved domestic natural gas reserves, close on the heels of Chevron and Shell (the third and fourth largest reserve holders).

• Amoco has used coalbed methane to maintain its position as number one in domestic gas reserves and has selected coalbed methane as a strategic resource for international exploration.

• Devon (Blackwood & Nichols) has used coalbed methane (plus other sources) to triple its gas reserve base over the past five years and move into the ranks of significant independents.

Part 2 of this series will provide a review by basin of coalbed methane activity coupled with detailed assessments of specific coalbed methane projects. That article will also highlight the hot Uinta basin coalbed methane play and review the performance of enhanced nitrogen-carbon dioxide coalbed methane projects in the San Juan basin.

Gas shales

1. Annual production. Natural gas production from gas bearing shales has nearly doubled to 259 bcf in 1994 from 136 bcf in 1990. The bulk of the growth has been from the Antrim shales of Michigan, which in 1994 displaced the Appalachian basin as the largest shale gas producer.

Increasing production is also noted in the Barnett shales of the Fort Worth basin and the Niobrara shales of the Denver basin. These emerging basins (Michigan, Fort Worth, and Denver) have significantly higher reserve additions per well (or dollar) and now dominate the action in gas shales (Fig. 5)(28316 bytes). The growth in gas shales production is also shown (Fig. 6)(25362 bytes).

2. Proved reserves and reserve additions. Proved reserves of gas from shales exceeded 3 tcf in 1994, up from about 1 tcf in 1990 (Fig. 7)(25682 bytes). Significant reserve additions were noted in the Appalachian, Michigan, and Fort Worth gas shale basins.

3. Producing wells and well completions. Anchored by the large stock of older Appalachian basin Devonian age shale wells, nearly 22,000 gas shale wells were producing in 1994. However, the major growth in new well completions has been in the Michigan (Antrim) and Fort Worth (Barnett) basins. Gas shale well completions in 1993 and 1994 have dropped back to the 1991 level after the frenetic pace in 1992 (Table 4)(8165 bytes).

The pending end of Sec. 29 tax credits created a miniboom in Michigan Antrim drilling in 1992, accelerating the completion of wells that may otherwise have taken place in 1993 or 1994. Gas shale well drilling in the other basins has remained relatively steady, with the decline in the Appalachian basin countered by increases in the Fort Worth and Denver basins.

Following a 1993-94 slump, drilling in the Michigan Antrim has rebounded strongly in 1995 with 592 wells for the first nine months (the third highest in the past 10 years) and 850 wells projected for the year (Fig. 8)(26871 bytes).

4. Industry activity. The expansion of the fractured gas shales play has been led by Mitchell Energy & Development Corp. in the Barnett shale of the Fort Worth basin and by Nomeco Inc. in the Antrim shale of the Michigan basin.

• Mitchell replaced 171% of its reserves and its finding and development costs improved dramatically in fiscal 1995, falling to 65/Mcf ($3.82/BOE). The company said North Texasand particularly the Barnett shaleplayed an important role in both the gas reserves gain and finding cost improvement.

• CMS Nomeco invested $105 million in Antrim projects and added 180 bcf of gas to its reserve base at overall finding costs of 60/Mcf ($3.50/BOE).

Tight gas

1. Annual production. Production of tight gas climbed to 2,492 bcf (6.8 bcfd) in 1994, up 6% from 2,351 bcf (6.4 bcfd) in 1992 (Table 5)(8317 bytes). Essentially all of the growth in tight gas production has been from Rocky Mountain basins, with declines noted for Appalachian and Texas tight gas (Fig. 9)(27498 bytes).

2. Proved reserves and reserve additions. Tight gas proved reserves, after declining and then stabilizing at around 31 tcf, began to rebuild in 1993 and climbed back to over 32 tcf in 1994. The tight gas reserve and gas production figures include the Appalachian basin, which has often been excluded or overlooked by other studies because of the difficulty in collecting and assembling the data. Detailed data were collected from state sources for the Appalachian, San Juan, and selected other Rocky Mountain basins. Detailed data plus estimates from overall drilling and historical trends were used for the other tight gas basins.

3. Producing wells and well completions. Over 122,000 wells were producing tight gas in 1994. About 70% of these are in the Appalachian basin. The bulk of the remaining 36,000 tight gas wells are in the San Juan, Green River, and East Texas basins.

New drilling for tight gas that had plateaued at about 3,700 wells/year rebounded to more than 4,200 wells/ year in 1993-94 (Fig. 10)(25582 bytes). Tight gas well drilling in the Appalachian basin, still the most active tight gas basin, has declined by about 200 wells/year since 1992 to about 1,650 wells/year. A decline in drilling is also noted in the second largest and oldest tight gas basin, the San Juan. Countering these declines has been the strong, new tight gas activity in the lenticular sands of the Piceance and Uinta basins, the Almond and Frontier tight gas play in the Green River basin, and expanded development of East Texas Cotton Valley, South Texas Wilcox, and West Texas Canyon tight sands.

4. Industry activity. Union Pacific Resources Co. and Barrett Resources Corp., with their strong Rocky Mountain programs, and Enron Oil and Gas, with its Wilcox Lobo trend development, have been three of the most aggressive tight gas drillers the past several years.

• UPRC has successfully completed directional and slim-hole wells in the Green River basin using new hydraulic fracturing methods. Use of this technology has lowered its drilling/completion costs for tight sand wells by 24% since 1992. UPRCs drilling cost reduction program in its newly acquired West Texas Canyon sands has lowered well costs 30% to $225,000 in 1994.

• Barrett has aggressively pursued the massively stacked lenticular sands of the Mesaverde formation in the Piceance basin. Advances in well placement and completion technology have improved expected gas recoveries per well by 20% in the Grand Valley/Parachute fields and by 125% in Rulison field.

• Enrons tight gas activities include South Texas (Wilcox, Frio, Lobo producing horizons), where the company produces over 200 MMcfd, and the West Texas Canyon trend, where it has drilled a large number of infill wells.

International setting

The past three years have seen a boom in the pursuit of international coalbed meth- ane, with new projects in Australia, China, India, New Zealand, and Zimbabwe plus other areas.

Most of these projects are in the early stages of exploration or pilot testing. Still, several of them report encouraging results and are moving toward commercial development. U.S. companies such as Amoco, Enron, and Conoco Inc. as well as overseas firms such as AfPenn, Southgas, and Reliance have been active in securing leases and assessing the potential of these coalbed methane resources.

Tight gas development is noted in the Cooper basin of Australia, the Western Canada sedimentary basin, and the Sichuan basin in China. Gas shales development is still confined to the U.S., although joint completion of coal seams and organic rich shales is planned in several current overseas projects, particularly in the Gondwana-age sedimentary basins.

Acknowledgments

The authors thank the numerous state oil and gas boards and individual operators who were most helpful in contributing information for this study.

References

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2. Herasimchuk, D., Will technology make the gas bubble permanent?, Oil & Gas Investor, August 1995, pp. 51-56.

3. Herrington, M.R., and Zebrowitz, M., Coalbed methane development in the Galilee basin of central Queensland, Australia, Intergas 95, University of Alabama, May 15-19, 1995, pp. 331-340.

4. Advanced Resources International Inc. and Barlow and Haun Inc., internal GRI presentation, Future Gas Resource Evaluation, Oct. 26, 1995.

5. Palmer, I., et al., Openhole cavity completions in coalbed methane wells in the San Juan basin, SPE 24906, SPE annual technical conference and exhibition, Oct. 4-7, 1992, pp. 501-516.

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8. COMET2 users guideversion 2.0, prepared by Advanced Resources International Inc., 1995.

9. Natural gas supply product and services guide, Gas Research Institute, Fall 1995.

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The Authors