3.1. Eastern Gas Shales Program (1976-1992)

Thick Devonian-age black shales underlie extensive areas of the eastern United States (Figure 3.1.1).

Figure 3.1.1: Extent of Eastern Gas Shales Distribution. (Click to enlarge)

Of the roughly 160,000 square miles of the Western Appalachian Basin, about 40 percent is underlain by Devonian shale deposits at depths of less than 4,000 feet and 60 percent at depths between 4,000 and 8,000 feet.

The shale deposits of the Appalachian Basin, and to a lesser degree of the Michigan and Illinois Basins, have been recognized as gas productive since the late 1800s. By the end of the 1970s the shallower deposits had produced an estimated 3 Tcf.

However, because Devonian shale wells produce at low rates (albeit for many years) this resource, along with the other unconventional natural gas resources targeted by the DOE's Unconventional Gas Resource R&D program, was historically viewed as relatively insignificant compared to conventional gas produced from highly permeable and porous sandstone and carbonate reservoirs. Very large ranges in estimates of gas-in-place (from less than 1,000 Tcf to 300 times that amount) and recoverable reserves (from less than 25 Tcf to as much as 285 Tcf) attested to the industry's relatively poor understanding of Devonian shale reservoir and production characteristics.

When domestic natural gas reserves began to decline in 1968, the U.S. Bureau of Mines (USBM) began to examine marginal gas resources to determine what methods might be employed to extract them. The USBM subsequently became part of the Energy Research and Development Administration (ERDA).

The Eastern Gas Shales Project (EGSP) was formally initiated at ERDA's Morgantown Energy Research Center (METC) in 1976, just before that organization became part of the newly formed Department of Energy (DOE). EGSP funding continued through 1992.

During that time period, several innovative and industry “firsts” were undertaken which later led to commercial technologies. In addition, the basic tools and methodologies developed for use in the Eastern U.S. led to a better appreciation for the potential of fractured shales in general. Subsequent drilling and development of the Barnett Shale of the Fort Worth Basin of Texas during the mid to late 1980s and the Lewis shale of the San Juan Basin of New Mexico, had its roots in the renewed interest in Eastern shales engendered by the EGSP.

The EGSP operated with a total budget of slightly more than $92 million over its 16 year history. Expenditures peaked in 1979, when the annual budget was $18 million. The first five years (1976-1981) of the EGSP concentrated on characterizing the geological, geochemical, geophysical, and reservoir properties of the Eastern gas shales, and on conducting cost-shared stimulation research (hydraulic fracturing, chemical explosive fracturing, and directional drilling) experiments with oil and gas operators. Close to 38,000 feet of oriented core was obtained and 300 technical publications were published related to the results of this research.

Starting in the early 1980s, research emphasis shifted to detailed reservoir performance analysis and the development of a mathematical reservoir simulator for fractured shales.

An Offset Well Test experiment was conducted in 1982/1983 in Ohio. The experiment consisted of drilling three closely spaced wells (<150 feet apart) and conducting a number of sophisticated production tests, including pressure pulse interference tests, to derive both matrix and fracture flow properties in the shale. Based upon this work (and the previously acquired characterization data), a fractured shale reservoir simulator (SUGAR-MD) was developed to quantify the inter-relationship of key parameters.

During the later stages of the EGSP, the research focused on validating the simulator through testing of ten single wells and the installation of a second, multiple well Offset Well Test Facility at one of the ten sites.

Another major initiative was the drilling of a directionally controlled horizontal well to intersect the fractures in the shale and prove the concept that a horizontal well could produce at a flow rate six to eight times greater that that of standard vertical well.

A medium radius directional well was drilled 2000 feet horizontally in December 1986. Initial flow rates were ten times the average for producing vertical wells in the vicinity.

Throughout the EGSP, a number of smaller contracts with universities and private R&D firms supported research in adsorption/desorption studies, database development, and reservoir performance predictive capabilities.

When the EGSP began in 1976, production from Devonian shales was on the order of 65 Bcf per year, almost entirely from the Appalachian Basin. By 1992, when the EGSP ended, natural gas production from this resource had climbed three fold, to 200 Bcf per year, with increased production from the Appalachian Basin and the onset of gas production from the Michigan (Antrim Shale), Fort Worth (Barnett Shale) and several other gas shale basins.

Driven by the Section 29 tax credits and the boom in Antrim shale drilling, gas well drilling climbed sharply; 10,700 shale gas wells were drilled from 1978 to 1992 with an annual peak of 1,709 gas shale wells completed in 1992.

Since 1992, production from gas shales has continued to grow. In 2004 Appalachian shale gas production totaled 137 Bcf, Antrim 149 Bcf, Barnett 379 Bcf, and the newly developed Niobrara shale of the Williston Basin and Lewis Shale of the San Juan Basin totaled 23 Bcf, for a national total of 689 Bcf, more then ten times the annual total for shale gas production when the EGSP began.

The DOE R&D program in gas shales helped unlock a major new natural gas resource and source of significant natural gas supply. It revitalized gas shales drilling and development in the Appalachian (Devonian) Basin, helped initiate development of other previously over-looked gas shale basins, and took the lead in demonstrating much more efficient and lower-cost gas shales production and recovery technology. Without DOE involvement, the practical aspects of foam fracturing as a cost effective recovery method for shale gas wells would have never been discovered.

Furthermore, the comparative analysis of various stimulation methods would not have been available to guide industry choices. The benefits of drilling horizontally through such naturally fractured formations would not have been realized as quickly without the efforts of the EGSP.

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