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US Shale Gas & Oil Plays

Only in the past five years has shale gas been recognized as a "game changer" for the US natural gas market. 


By The Energy Information Administration
US Department of Energy
Washington, DC 

 The use of horizontal drilling in conjunction with hydraulic fracturing has greatly expanded the ability of producers to profitably recover natural gas and oil from low-permeability geologic plays—particularly, shale plays.

Application of fracturing techniques to stimulate oil and gas production began to grow rapidly in the 1950s, although experimentation dates back to the 19th century. Starting in the mid-1970s, a partnership of private operators, the US Department of Energy (DOE) and predecessor agencies, and the Gas Research Institute (GRI) endeavored to develop technologies for the commercial production of natural gas from the relatively shallow Devonian (Huron) shale in the eastern United States.
The shale plays and basins in the United States’ Lower 48.
This partnership helped foster technologies that eventually became crucial to the production of natural gas from shale rock, including horizontal wells, multistage fracturing, and slick-water fracturing. Practical application of horizontal drilling to oil production began in the early 1980s, by which time the advent of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies (particularly, downhole telemetry equipment) had brought some applications within the realm of commercial viability.

The advent of large-scale shale gas production did not occur until Mitchell Energy and Development Corp. experimented during the 1980s and 1990s to make deep shale gas production a commercial reality in the Barnett Shale in North-Central Texas. As the success of Mitchell Energy and Development became apparent, other companies aggressively entered the play, so that by 2005, the Barnett Shale alone was producing nearly 0.5 trillion ft³ (14 billion m³)of natural gas per year. As producers gained confidence in the ability to produce natural gas profitably in the Barnett Shale, with confirmation provided by results from the Fayetteville Shale in Arkansas, they began pursuing other shale plays, including Haynesville, Marcellus, Woodford, Eagle Ford, and others.

Although the US Energy Information Administration's (EIA) National Energy Modeling System (NEMS) and energy projections began representing shale gas resource development and production in the mid-1990s, only in the past five years has shale gas been recognized as a “game changer” for the US natural gas market. The proliferation of activity into new shale plays has increased dry shale gas production in the United States from 1.0 trillion ft³ (28 billion m³) in 2006 to 4.8 trillion ft³ (134 billion m³), or 23% of total US dry natural gas production, in 2010. Wet shale gas reserves increased to about 60.64 trillion ft³ (1.698 trillion m³) by year-end 2009, when they comprised about 21% of overall US natural gas reserves, now at the highest level since 1971. Oil production from shale plays, notably the Bakken Shale in North Dakota and Montana, has also grown rapidly in recent years.

To gain a better understanding of the potential US domestic shale gas and shale oil resources, EIA commissioned INTEK Inc. to develop an assessment of onshore Lower 48 States technically recoverable shale gas and shale oil resources. This paper briefly describes the scope, methodology, and key results of the report and discusses the key assumptions that underlie the results. The full report prepared by INTEK may be found at The shale gas and shale oil resource assessment contained in the INTEK report and summarized here was incorporated into the Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) within the Oil and Gas Supply Module (OGSM) of NEMS to project oil and natural gas production for the Annual Energy Outlook 2011 (AEO2011). EIA also anticipates using the assessment to inform other analyses and projections and to provide a starting point for future work.

Scope and results
The INTEK shale resources report estimates shale gas and shale oil resources for the undeveloped portions of 20 shale plays that have been discovered. Eight of those shale plays are subdivided into two or three areas, resulting in a total of 29 separate resource assessments. The total of 750 trillion ft³ (21 trillion m³) excludes three additional components of resources: proven reserves, inferred reserves in actively developed areas and undiscovered resources as estimated by the US Geological Survey (USGS). The accompanying map shows the location of the shale plays in the Lower 48 States.
Diagram of fracking operation with recommendations to protect groundwater from contamination.
Eighty-six percent of the total 750 trillion ft³ of technically recoverable shale gas resources are located in the Northeast, Gulf Coast, and Southwest regions, which account for 63%, 13%, and 10% of the total, respectively. In the three regions, the largest shale gas plays are the Marcellus (410.3 trillion ft³ [11.5 trillion m³], 55% of the total), Haynesville (74.7 trillion ft³ [2.1 trillion m³] 10% of the total), and Barnett (43.4 trillion ft³ [1.2 trillion m³], 6% of the total).

The INTEK shale report also assesses the technically recoverable shale oil resources, which amount to 23.9 billion barrels in the onshore Lower 48 States. The largest shale oil formation is the Monterey/Santos play in southern California, which is estimated to hold 15.4 billion barrels or 64% of the total shale oil resources. The Monterey shale play is the primary source rock for the conventional oil reservoirs found in the Santa Maria and San Joaquin Basins in southern California. The next largest shale oil plays are the Bakken and Eagle Ford, which are assessed to hold approximately 3.6 billion barrels and 3.4 billion barrels of oil, respectively.

The 750 trillion ft³ of shale gas resources in the INTEK shale report is a subset of the AEO2011 onshore Lower 48 States natural gas shale technically recoverable resource estimate of 862 trillion ft³ (24.1 trillion m³). The AEO2011 includes 35 trillion ft³ (0.98 trillion m³) of proved reserves reported to the Securities and Exchange Commission (SEC) and the EIA, 20 trillion ft³ (0.56 trillion m³) of inferred reserves not included in the INTEK shale report, and 56 trillion ft³ (1.48 trillion m³) of undiscovered resources estimated by the USGS.

The resource estimates developed by INTEK come from publicly available company data and commercial databases for wells and acreage currently in production. The estimates of technically recoverable resources are based on the area, well spacing, and average expected ultimate recovery (EUR) for each shale play or subportion of the play. An effective recovery factor has been applied which reflects: (a) a probability factor that takes into account the results from current shale gas activity as an indicator of how much is known or unknown about the shale play; (b) a recovery factor that takes into account prior experience in how production occurs, on average, given a range of factors (including mineralogy and geologic complexity) that affect the response of the geologic play to the application of best-practice shale gas recovery technology; and (c) resources in the play that have already been produced or added into proved reserves.

Estimates of technically recoverable shale gas resources are certain to change over time as new wells go into production and new technologies are developed. For example, the gas resource estimates in the INTEK shale report are predicated on the assumption that natural gas production rates for current wells covering only a limited portion of a play are representative of an entire play or play sub-area; however, across a single play or play sub-area there can be significant variations in depth, thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content. As a result, individual well production rates and recovery rates can vary by as much as a factor of 10.

There is considerable uncertainty regarding the ultimate size of technically recoverable shale gas and shale oil resources, including but not limited to the following:
Because most shale gas and shale oil wells are only a few years old, their long-term productivity is untested. Consequently, the long-term production profiles of shale wells and their estimated ultimate recovery of oil and natural gas are uncertain.

In emerging shale plays, production has been confined largely to those areas known as "sweet spots" that have the highest known production rates for the play. If the production rates for the sweet spots are used to infer the productive potential of entire plays, their productive potential probably will be overstated. The INTEK shale report mitigates this problem by differentiating the productivity of a play's sweet spot from the productivity for rest of that play.

Many shale plays are so large (e.g., the Marcellus shale) that only portions have been extensively production tested.

Technical advancements could lead to more productive and less costly well drilling and completion.

Currently untested shale plays, such as thin-seam plays or untested portions of existing plays, could prove to be highly productive.

Estimating the technically recoverable oil and natural gas resource base in the United States is an evolving process. For shale gas and oil, the evolution of resource estimates is likely to continue for some time. The size of the technically recoverable oil and natural gas resource base in the United States becomes evident only as producers drill into geologic deposits with oil and gas potential and attempt to produce from them on a commercial basis. As producers find plays to be more or less bountiful than expected, resource estimates are adjusted to reflect that information. As time passes and our knowledge of the resource base and future technologies and management practices improves, estimates of the technically recoverable resource base will be refined. Consequently, the resource estimates in the current report will be modified over time as more wells are drilled and completed, technologies evolve, and the long-term performance of shale wells becomes better established.

The estimates of shale oil and shale gas resources provided here represent a reasonable estimate of the resource potential for those shale plays for which public information is currently available. ME

This article is derived from Review of Emerging Resources: US Shale Gas and Shale Oil Plays published by the US Energy Information Administration (EIA), the statistical and analytical agency within the US Department of Energy. By law, EIA's data, analysis and forecasts are independent of approval by any other officer or employee of the United States government. The views expressed herein and in the larger study from which it is derived should, therefore, not be construed as representing those of the Department of Energy or other federal agencies.

This article was originally published in Manufacturing Engineering's 2012 Energy Manufacturing yearbook. A PDF of the article can be downloaded here.

Published Date : 2/1/2013

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