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Students showcasing research posters at the 2015 GCEP Symposium

U.S. Shale Gas: From Resources and Reserves to Carbon Isotope Anomalies

January 20, 2010 - 4:15pm to 5:15pm
Building 420, Room 40
Free and Open to All

U.S. shale gas drilling dates from 1821 and accounts for 7% of annual production. The U. S. Energy Information Administration (EIA) estimated that shale gas production would overtake coalbed methane production by 2025, and grow to 2.3 Tcf annually by 2030. Some Industry analysts, apparently using Delphi-type studies, claim that shale gas will account for 50% (~11 Tcf) ) of U.S. gas production within the next 10 years. The recent EIA 2009 reserves report stated that shale gas comprises 13% (33 Tcf) of proved reserves, an indicator of significant well productivity.

In addition to measured contributions to production and proved reserves, shale gas is also an important component of future, technically recoverable resources. The upward trends in these three categories are due to improvements in exploration, completion and production technologies, aided at times by wellhead price increases. These factors have combined to transform what was previously recognized as gas-in-place to potential resource. For example, the latest Potential Gas Committee biennial assessment (June 2009), showed an overall increase of 39% (515 Tcf) for total U.S. gas resources. The bulk of this increase was for shale gas resources assessed in 12 basins. Shale gas is receiving significant attention from operators and researchers in Canada and Europe.

Shale gas also presents interpretive challenges at the molecular level. Stable carbon isotope compositions of natural gases allow for the identification of petroleum "families", detection of seals and overpressure, and provide evidence of migrated thermogenic gas accumulations. In shale gas plays, where the source rock is also the reservoir, carbon isotopes of ethane and propane are strong thermal maturity indicators and can be accurately calibrated against measured vitrinite reflectance values. Stable carbon isotopes become increasingly heavier (more positive) with increasing maturity. However, in certain shale gas plays (including the Haynesville, Barnett, Fayetteville, Woodford and Marcellus) an interesting phenomenon occurs at high maturity where the ethane and propane isotope values begin to reverse and become lighter (more negative) than methane values. A key observation is that many of these "isotopically reversed" wells appear to be the most productive.

Gas isotopic compositions are also used as a proxy for shale porosity and permeability. Large carbon isotopic shifts between mud and cuttings gases correlate with zones of increased porosity and permeability. In conjunction with traditional logs, these data can be used to guide horizontal drilling and select completion intervals.

This talk will discuss shale gas resource assessments, possible roadblocks to future shale gas production and the use of gas geochemistry for discovery and development of this potential resource.

Bio: John B. Curtis is Professor of Geology and Geological Engineering and Director, Petroleum Exploration and Production Center/Potential Gas Agency at the Colorado School of Mines. Dr. Curtis is also co-director of the CSM Unconventional Natural Gas Institute. He received a B. A. (1970) and M.Sc. (1972) in geology from Miami University and a Ph.D. (1989) in geology from The Ohio State University.  He is a licensed Professional Geologist (Wyoming).

Dr. Curtis has been at the Colorado School of Mines since July, 1990. He had 15 years prior experience in the petroleum industry with Texaco, Inc., SAIC, Columbia Gas, and Brown & Ruth Laboratories/Baker-Hughes.  He serves on and has chaired several professional society and natural gas industry committees, which previously included the Supply Panel, Research Coordination Council, and the Science and Technology Committee of the Gas Technology Institute (Gas Research Institute). He co-chaired the American Association of Petroleum Geologists (AAPG) Committee on Unconventional Petroleum Systems from 1999-2004 and is an invited member of the AAPG Committee on Resource Evaluation. He was a Counselor to the Rocky Mountain Association of Geologists from 2002-2004.

Curtis is an Associate Editor of the AAPG Bulletin and The Mountain Geologist. He has published studies and given numerous invited talks concerning hydrocarbon source rocks, exploration for unconventional reservoirs, and the size and distribution of U.S., Canadian and Mexican natural gas resources and comparisons of resource assessment methodologies.  As Director of the Potential Gas Agency, he directs a team of 145 geologists, geophysicists and petroleum engineers in their biennial assessment of remaining U.S. natural gas resources. He teaches petroleum geology, petroleum geochemistry, integrated exploration and petroleum design at the Colorado School of Mines, where he also supervises graduate student research.


Background Reading:

Dept Of Energy - Modern Shale Gas, A Primer

Paradigm Shift in Domestic Natural Gas Resources, Supplies and Costs

Fracture Shale Gas Systems

Potential Gas Committee Resource Estimates

Whiticar, M.J., 1994, Correlation of natural gases with their sources: in Magoon, L.B., and W.G.Dow, eds., 1994, The petroleum system - from source to trap: AAPG Memoir 60, p. 261-283