Advances, needs highlighted for deep U.S. gas drilling

Nov. 30, 1998
Economics of U.S. deep gas exploration and production have improved significantly the past 3 years, one speaker told Gas Research Institute's Second Deep Gas Forum in Denver in mid-October. Purpose of the 2 day meeting was to discuss the latest practices and technologies for improving deep gas exploration and lowering development costs. Depths considered are generally 15,000 ft and deeper, although the principles apply to many reservoirs several thousand feet shallower.

Economics of U.S. deep gas exploration and production have improved significantly the past 3 years, one speaker told Gas Research Institute's Second Deep Gas Forum in Denver in mid-October.

Purpose of the 2 day meeting was to discuss the latest practices and technologies for improving deep gas exploration and lowering development costs. Depths considered are generally 15,000 ft and deeper, although the principles apply to many reservoirs several thousand feet shallower.

Of particular interest were presentations on deep gas resources; the integrated application of exploration technologies; case studies of deep gas exploration in the Anadarko, Permian, and Rocky Mountain basins; and performance reviews of high priority deep gas plays.

The 50 invited attendees unanimously recommended that GRI continue the Deep Gas Forum Series and expand the invitation list to other producers in high priority deep gas basins. Those attending represented oil and gas and service companies and research organizations.

Advanced Resources International Inc. (ARI), Arlington, Va., and the U.S. Geological Survey organized the meeting.

Improving economics

With recent reductions in well costs and improvements in dry hole rates, deep gas economics are improving (Table 1 [20,696 bytes]), said Vello Kuuskraa, president of ARI and a forum moderator.

Kuuskraa also reviewed the historical and recent performance of selected deep gas plays in Rocky Mountain basins.

For example, based on historical exploration and production results (Table 2 [52,049 bytes]), the Cody shale (Shannon and Sussex sands) gas play in the Wind River basin may be an attractive target, with 16 bcf wells and full cycle finding costs of 47¢/Mcf.

The Mesaverde sand play in this basin suffers from high dry hole and marginal well rates of over 50% that severely hurt its economics. The Madison carbonate play in the Madden Deep Unit is thought to be a 1 tcf accumulation. Its economics are strongly influenced by the costs of processing the sour gas that contains 11% H2S and 19% CO2.

Ted Dyman, a USGS research geologist and a forum moderator, reviewed the latest USGS resource assessments for 162 conventional and 11 basin-centered (unconventional) deep gas plays. These plays contain a 114 tcf resource base. Dyman said an upcoming USGS update of deep gas resources will include several new plays, such as the exciting Upper Cretaceous-age Cave Gulch deep gas play in the Wind River basin, where Barrett Resources has drilled prolific deep gas wells.

Need to integrate technology

Another session focused on the need for integrated exploration technologies, such as basement mapping with high resolution aeromagnetics, deep seismic imaging, geophysical logging, and outcrop to core characterization of deep, naturally fractured reservoirs.

Integrated use of these technologies is essential in exploring for deep, basin centered naturally fractured reservoirs (Fig. 1 [95,375 bytes]), said David Campagna, project manager and consulting structural geologist with ARI.

Cited were the application of these technologies to mapping the higher productive areas for the lenticular Mesaverde tight gas in Rulison field, Piceance basin, and for delineating a Frontier formation "sweet spot" to be developed with a horizontal well in Table Rock field of the Washakie area, Green River basin.

Deep gas case studies

Another session involved case studies of deep gas exploration and development in the Permian and Anadarko basins.

Bruce Cain, Altura Energy geologist, discussed the importance of understanding structure, paleokarsts, and natural fractures in unraveling the performance of the Ellenburger dolomite gas trend in West Texas. The trend has already produced 13 tcf of gas.

Improved 3D seismic, 2,000+ ft long horizontal wells, and targeted well workovers are being successfully applied to the gas fields in this trend, raising gas production from 4 MMcfd to 20 MMcfd for one company.

Tom Maher, Apache Corp. E&D manager, discussed the results of a deep Springer gas play (17,000-19,000 ft) in Verden field of the Anadarko basin, Oklahoma. Apache has drilled 44 successful producers out of 47 wells (94% success), averaging about 6 bcf/well of expected reserves.

Of particular value has been the innovative use of photoelectric measurements provided by wireline density tools in making well completion decisions by identifying permeable zones in otherwise tight formations, Maher said.

Moving R&D forward

Three presentations examined the technology status, development activities, and R&D needs for deep gas.

Goals for GRI's R&D are to reduce deep gas drilling costs, improve the deep gas exploration success rate, and improve deep gas well productivity, said David Hill, principal product development manager for deep gas/drilling and completion at GRI.

Achieving these goals would help make deep gas economically more attractive with competing sources (Table 3 [37,107 bytes]).

The Deep Drilling and Coring Consortium (DOSECC) is developing technology for preventing formation damage in underpressured reservoirs, and its advanced reservoir visualization project is helping identify fluvial channels in sandstone reservoirs and karsted zones in dolomites, said Ray Levey, Energy and Geosciences Institute, University of Utah.

GRI has proposed to form a high temperature electronics consortium for improving logging and measurement while drilling in deep, hot, high pressure gas reservoirs, said Mike Weiss, principal project manager, drilling and completion at GRI, and Kurt Minnich of Spears and Associates, Tulsa, Okla. Further information on this consortium proposal will be available in January 1999.

Industry wish list

Forum participants shared experiences with deep gas development as well as technology needs, including:
  • Improved practices and materials have reduced deep drilling costs by 25% for some companies. Continued reductions in these costs will be important and will allow development of the currently economically marginal deep gas plays. The development of new exploration technologies that reduce dry holes and help find higher quality areas will be essential for enabling deep gas to compete with other gas resources on an even basis.
  • Deep gas resources are often in unconventional, basin-centered reservoirs that are not dependent on an exploration strategy based on "traditional traps" but rather on finding "sweet spots" with superior reservoir characteristics. New exploration concepts and technologies for identifying naturally fractured areas and "sweet spots" could be valuable.
  • Advances in deep gas reservoir characterization should also focus on understanding reservoir compartments for infill drilling, developing deeper pools in known fields, and laterally expanding producing pools.
Finally, the participants stated that building a base of performance history for high priority deep gas plays will be an important issue for stimulating additional development of deep gas. Future deep gas forums would benefit from more case studies and documentations of exploration and production results.

R&D priorities

Of particular interest and value in shaping the nature of GRI's R&D in deep gas was the completion of a survey identifying:
  1. The highest priority technology E&P needs.
  2. The promising technology solutions; and
  3. The priority basins for deep gas R&D.
The respondents ranked natural fracture identification/prediction, geologic/structural characterization, and deep drilling technology as the top three technology needs (Table 4 [81,133 bytes]).

Detailed deep gas case studies, improved natural fracture mapping/detection technology, and improved reservoir characterization and reserve prediction received the highest recommendations for technology solutions. The Anadarko, Green River, and Wind River basins and the Austin Chalk Trend were ranked as the top priority basins for deep gas studies and field demonstrations.

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