University of Texas at Austin

FAQ

FAQ for Bureau Shale Gas Study
Who were the team members who conducted the studies? 
Between January 2011 and August 2014, a large number of researchers contributed to the analysis of four shale gas plays: Barnett, Fayetteville, Haynesville and Marcellus.

  • Principal Investigator: Scott Tinker, Director, Bureau of Economic Geology, and acting Associate Dean and Professor, Jackson School of Geosciences, The University of Texas at Austin
  • Co-Principal Investigator: Svetlana Ikonnikova, Energy Economist, Bureau of Economic Geology, The University of Texas at Austin
  • John Browning, Petroleum Engineer, Bureau of Economic Geology, The University of Texas at Austin
  • Qilong Fu, Geologist, Bureau of Economic Geology, The University of Texas at Austin (Barnett, Fayetteville)
  • Carl Grote, Graduate Research Assistant, Jackson School of Geosciences (Haynesville, Marcellus)
  • Gürcan Gülen, Energy Economist, Bureau of Economic Geology, The University of Texas at Austin
  • Ursula Hammes, Research Scientist, Bureau of Economic Geology, The University of Texas at Austin (Haynesville, Marcellus)
  • Susan Horvath, GIS Specialist, Bureau of Economic Geology, The University of Texas at Austin (Barnett, Fayetteville, Haynesville)
  • Frank Male, Graduate Research Assistant, Department of Petroleum and Geosystems Engineering, The University of Texas at Austin
  • Ken Medlock III, Energy Economist, James A. Baker Institute for Public Policy, Rice University (Barnett)
  • Tad Patzek, Chair, Department of Petroleum and Geosystems Engineering, The University of Texas at Austin
  • Eric Potter, Associate Director – Energy Division, Bureau of Economic Geology, The University of Texas at Austin
  • Forrest Roberts, Graduate Research Assistant, Jackson School of Geosciences, The University of Texas at Austin (Barnett, Fayetteville)
  • Jake Schultz, Graduate Research Assistant, Bureau of Economic Geology, The University of Texas at Austin
  • Likeleli Seitlheko, Graduate Fellow, James A. Baker Institute for Public Policy, Rice University (Barnett)
  • Katie Smye, Research Associate, Bureau of Economic Geology, The University of Texas at Austin (Fayetteville, Haynesville, Marcellus)
  • Xinya Zhang, Postdoctoral Fellow, Bureau of Economic Geology, The University of Texas at Austin (Marcellus)

The team members acknowledge the following people and organizations who contributed valuable suggestions, comments, and editorial help: William L. Fisher, Leonidas T. Barrow Centennial Chair in Mineral Resources, Jackson School of Geosciences, The University of Texas at Austin; Ian Duncan, program director, Vanessa Nunez, research associate, Caroline Breton, research scientist associate, all at the Bureau of Economic Geology, The University of Texas at Austin; Robert Bryce, author, senior fellow, Manhattan Institute; and oil and gas information providers Drilling Info, Inc. and IHS.

Who funded the study? 
The Alfred P. Sloan Foundation. The Sloan Foundation is a philanthropic, not-for-profit grantmaking institution based in New York City. Established in 1934 by Alfred Pritchard Sloan Jr., then-President and Chief Executive Officer of the General Motors Corporation, the foundation makes grants in support of original research and education in science, technology, engineering, mathematics and economic performance. For more information, see About the Sloan Foundation.

What is the Bureau of Economic Geology? 
The Bureau of Economic Geology, established in 1909, is the oldest and second largest research unit at The University of Texas at Austin. Part of the Jackson School of Geosciences at The University of Texas at Austin, the Bureau also functions as the State Geological Survey.
The Bureau conducts basic and applied research related to energy resources including oil, natural gas, and coal; mineral resources; coastal processes; Earth and environmental systems; hydrogeology; carbon sequestration; nanotechnology; energy economics; and geologic mapping. The Bureau disseminates scientific knowledge by (1) publishing research results in scientific journals, in Bureau reports, and on the Internet; (2) conducting technology transfer workshops and schools; (3) participating in professional meetings; (4) training undergraduate and graduate students and postdocs by providing hands-on research experience with modern datasets; and (5) promoting K-12 and public outreach.

The Bureau not only curates the largest volume of subsurface core and cuttings in the United States at three world-class centers located in Houston, Austin, and Midland, but also runs a major Texas well log library, with nearly one million well records on file. The Bureau serves as the managing organization for the Advanced Energy Consortium, a major subsurface nanotechnology research organization. Centers include the Gulf Coast Carbon Center and Center for Energy Economics. Bureau reports, maps, and other publications are available online.

What are the previous major studies and assessments of natural gas in shale plays? 
The U.S. Energy Information Agency (EIA) included an estimate of technically recoverable resources in their 2011 “Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays.” The EIA has been providing updated estimates on its web site.
Other recent studies, mainly consensus views and literature surveys have been conducted by the National Petroleum Council and the Potential Gas Committee. A recent analysis was published by the Post Carbon Institute. Wood Mackenzie, IHS, Navigant, Rystad, ICF all conducted resource assessments but their analyses are not publicly available.
In 2003, the U.S. Geological Survey published an assessment (updating an earlier assessment from the late 1990s), but this was done before the advent of horizontal drilling had transformed shale gas exploration, and the reserves number has long since been recognized as well below the now estimated ultimate recovery (EUR) for the formation.

What is distinct about this study? 
The BEG assessment is an integrated study of the four shale formations, bringing together the best related research in engineering (reservoir engineering, production engineering), geoscience, and economics. Most previous publicly available assessments of these shale plays have taken a top-down approach, using averages to estimate the size of the recoverable resource. In contrast, the BEG assessment takes a bottom-up approach, starting with actual production data from each individual well in the formation.
Unique features of the BEG shale gas study:

  • Multi-disciplinary collaboration by geologists, engineers and economists creating a cohesive model of the plays linking geologic mapping, production analysis, well economics and development forecasting.
  • Development led by the Department of Petroleum Geosystems and Engineering of a physics-based decline curve that closely describes well declines and explains impacts due to interfracture interference late in well life (after several years typically).
  • Well-by-well analysis of production and calculation of individual well estimated ultimate recovery (EUR) for thousands of wells in each play, making use of decline approach.
  • Mile-by-mile analysis of several thousand square miles gross area divided into currently drilled and undrilled acreage.
  • The fields are subdivided into 6 to 10 productivity tiers, depending on the range of production, providing much improved granularity to reserves and economics.
  • Geologic mapping of porosity and net pay zone thickness across the entire play. Porosity-thickness (PhiH) was determined to be a key driver of well productivity in all four plays.
  • Calculation of volumetric original gas in place (OGIPfree) and technically recoverable resources for each square mile and for the full field.
  • Quantification of well “drainage areas” and recovery factors that were validated against observed well interference between closely spaced wells.
  • Detailed well economics of average wells in each productivity tier, including the impacts of gas plant liquids on well economics.
  • Quantification of historic attrition effects by productivity tier is incorporated into production models to account for the future volumes lost due to well failure.
  • Detailed modeling of future drilling through 2030 or 2045, depending on the maturity of the play and remaining resource potential, honoring production histories, well economics, pace of development and sensitivity to many other drivers of well performance.

The production outlook considers key variables of:

  • The parameters of future wells (RF & length, attrition, lifetime, interfracture interference), resulting in an inventory of future wells
  • Natural gas price
  • The economic limit of each well
  • Technology and well cost improvements
  • OGIPfree
  • Decline rate is the function of permeability, porosity and well depth and is proportional to one over the square root of time
  • Percentage of developed (drilled) & developable (undrilled) acreage
  • Dry gas (Low Btu) vs. higher liquids (higher Btu) gas areas and oil production per well
  • Achievable pace of development
  • Ability of the production areas to expand and collapse with well economics (minimum & maximum incremental wells)
  • Economic incentives to drill (which trigger increase in internal rate of return)

Where did the production data on the wells come from? Can others obtain it? 
IHS and Drillinginfo.com provided datasets on production. Both companies sell their proprietary data, which BEG cannot lawfully share.

How many years of supply of natural gas can be expected from these four shale plays? 
While it is common for analysts to report that a formation or county has a certain number of years of natural gas reserves based on current rates of consumption, presenting information in this manner can be misleading because of shifts in national energy use. In 2004, for example, the U.S. produced half of its electricity from coal and only about 20 percent from natural gas, whereas in 2012, the resources each accounted for about 35 percent of U.S. electricity generation. For this reason it can be more useful to simply state the production forecasts in trillion cubic feet (TCF).

In 2013, the U.S. consumed about 26 TCF of natural gas, according to the U.S. Energy Information Administration. The production from these four shale plays supplied about 31% of that consumption.

Why are there more reserves if the price of gas goes up, and fewer if the price goes down? 
The word “reserves” refers to the amount of a mineral resource that is technically and economically recoverable within a certain area. In an oil or gas formation, the resource base is almost always considerably larger than the recoverable reserves, because in some parts of the formation, it is simply too expensive or technically difficult to extract the resource. When resource prices are high, operators can afford to spend more and take greater technological risks seeking the harder-to-extract parts of the resource base. When prices are low, it does not pay to pursue expensive parts of the formation, and this fact lowers the overall reserves estimate.

Technology also plays a significant role in understanding reserves. Before the advent of hydraulic fracturing, for example, the U.S. was known to have a large resource base of shale gas, but the country did not have economically recoverable reserves. Today, hydraulic fracturing has substantially reduced the cost of obtaining shale gas resources, contributing to much higher natural gas reserves estimates for the U.S. and world. The resource (shale gas) did not change, but the drilling and extraction technology and our understanding of the geology did.

Has this study been peer-reviewed? 
Numerous research papers based on research from the assessment are either published or in review in peer reviewed journals. Two overview articles are published in the Oil & Gas Journal on Barnett and Fayetteville. 

Before submitting the papers, the BEG team submitted their research to several other forms of peer review, as part of the research process. The BEG team invited an independent review panel with members from government, industry and academia to critique their research. At an open day for academic, government, NGO representatives and industry scientists, 100 attendees were invited to offer additional feedback on the Barnett analysis, first in the series. Scientists from two of the largest producers in the Barnett, Devon Energy and ExxonMobil, offered feedback on the methodology during two in-house corporate review days. Finally, the BEG hired a consulting company to critique the draft manuscripts and offer suggestions for their improvement of the study. For other plays, we pursued a similar strategy of seeking feedback, especially on the geology of different plays. Finally, work in progress has been presented in many conferences, providing another avenue for peer review.