We show that, even without consideration of their special storage and flow properties, Devonian shales are special cases of dual porosity. We also show that, while neglecting these properties in the short term is appropriate, such neglect in the long term will result in an underestimation of production.

This report was prepared as an account of work sponsored by an agency of the United States Government.

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Summary Gas-production characteristics of naturally fractured Devonian shale have been quantified through a three well interference field test by use of an established producing well and two offsets placed on the primary and secondary regional fracture trends relative to the producer. Three individual shale zones were evaluated simultaneously by buildup, drawdown, and pulse tests to investigate reservoir gas flow characteristics, natural fracture properties, and gas storage and release mechanisms. Test results show severe permeability anisotropy, indicating elliptical drainage pattern with an 8:1 axis ratio. Essentially all gas is stored in a sorbed state in the shale matrix and is transported toward the wells through the native fracture system. Introduction The Devonian shales of the Appalachian basin underlie approximately 68,000 sq miles [175 000 km] from New York to Tennessee. These massive shales range in thickness from a few feet at the basin margin outcrops to thousands of feet at the basin center, and are made up of both organically lean ("gray") and rich ("brown") intervals. The shales contain natural gas in considerable quantity, primarily held in solution in solid organic constituents (kerogen) of the shale matrix, which makes the gas resource truly "unconventional." Recent resource estimates for the Appalachian basin shales range from 585 to 2,500 Tcf [16.5 × 10(12) to 70.8 × 10(12) m3] of natural gas in place, but because of the extremely low matrix permeability of the shale, gas is often not economically recover-able by conventional industry practice. The approximately 12,000 wells drilled to date historically have recovered only about 3 Tcf [0.08 × 10(12) m3] over the last 50 years. The Appalachian basin shales are considered blanket formations because discrete members are correlative over wide geographic areas. However, even though stratigraphically continuous and gas-containing across their extent, the Devonian shales do not produce uniformly when drilled. Current commercial production is a function of connecting the well with the primarily vertical natural fracture systems present in the shale, which form gathering and transportation networks to move gas from the matrix to the wellbore. Historical production has been limited to discrete areas where natural fracture density was high enough to support development. The Eastern Gas Shales Project (EGSP) is a long-term R and D effort by the U.S. DOE to improve overall gas recovery from the shale and to stimulate development of the resource by the private sector. An important part of the R and D thrust has been the development of a technical data base on shale characteristics and production behavior. The offset well test (OWT) described in this paper is a field experiment conducted to improve understanding of the basic gas-production mechanism of this unconventional reservoir. The test project was designed to investigate both qualitatively and quantitatively the gas-production characteristics of the shale in an area of natural fracturing and commercial development, and used a series of reservoir interference tests to achieve the test objectives. Specifically, the experiment addressed the following objectives. 1. Investigate the tow mechanics of gas in shale matrix and fractures. 2. Determine fracture orientation and distribution. 3. Determine how gas is stored in and released from the shale. 4. Verify the existence of directional drainage patterns and their impact on production practice. A three-well pattern was developed. consisting of an existing gas well with a 22-year production history and two newly drilled holes offsetting the producer by 120 and 90 ft [36.6 and 27.4 m], respectively, on the major and secondary directional fracture trends predicted for the test area. The interference series was conducted by perturbing the shale reservoir in the base well and monitoring the effects in the offsets. Fig. 1 shows a schematic of the OWT layout and instrumentation used during the interference testing. Earlougher provides a thorough description of interference testing, as well as many references on the subject. Site Selection The established producer (control well) used in the OWT formed an important part of the experiment and was carefully selected. During the test planning phase, design criteria were developed to define well parameters required for the planned interference tests. Table 1 lists these requirements. JPT P. 291^

A study was conducted which demonstrated the use of geostatistical techniques for identifying correlations between geologic parameters and gas production for 38 coalbed methane wells completed in the Blue Creek coal seam of the Oak Grove (U.S. Steel) field in Alabama. Data used in the study consisted of production information for these wells along with geologic information for the area of interest. Results indicated that four geologic parameters showed statistical correlations with gas production: the well elevation (a proxy variable for permeabilty), the number of lineament intersections within 250 feet (76 meters), the thickness of the Blue Creek coal seam, and the length of the nearest lineament. The study suggested that the results obtained for wells in the primary degasi-fication grid could be extrapolated to wells in an adjacent area having lineament orientations similar to the primary grid. A method by which each well could be characterized based upon its production profile (i.e., production versus time relationships) rather than a simple one-number summary, such as 4-year cumulative production, was also identified.