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Abstract

Shale gas is produced from the Woodford, Caney, and Fayetteville shales (Devonian and/or Mississippian), and coal-bed gas is produced from the Hartshorne and McAlester coal beds in the Arkoma basin of Oklahoma and Arkansas. The U.S. Geological Survey is currently assessing the technically recoverable hydrocarbon resources of the Arkoma basin and for assessment purposes has divided the continuous shale gas (unconventional) resources into three total petroleum systems together with their associated assessment units (AUs). Each of the gas shale AUs contains 2.5 % or more total organic carbon, is thermally mature with respect to gas generation over much of its area within the basin, and may be accessed by the drill at depths less than 14,000 feet. In addition, the Woodford, Caney, and Fayetteville Shale Gas AUs underlie relatively large areas that have not been tested adequately by the drill. Coal-bed gas is currently being produced from the Hartshorne and McAlester coal beds in the Arkoma basin, and for assessment purposes they have been grouped together into one total petroleum system and one AU. Much of the area where the coal beds are relatively shallow in the northern part of the AU has been drilled. However, the area underlain by coal in the southern part of the basin, which is deeper and more structurally deformed, remains largely unexplored for coalbed methane.

Introduction

The U.S. Geological Survey (USGS) is currently conducting an assessment of the technically recoverable undiscovered hydrocarbon resources of the Arkoma basin, Oklahoma and Arkansas (incomplete as of November, 2009). The Arkoma basin is a foreland basin that lies between the Ozark Plateaus and Cherokee Platform on the north and the Ouachita Mountains to the south (Fig. 1) (Houseknecht et al., 1984; Andrews, 1998).

Figure 1.

Major geologic provinces of Oklahoma and Arkansas (adapted from Oklahoma Geological Survey; Arkansas Geological Commission).

Figure 1.

Major geologic provinces of Oklahoma and Arkansas (adapted from Oklahoma Geological Survey; Arkansas Geological Commission).

In general, the major structural elements within the Arkansas Valley coal fields consist of southward dipping Paleozoic strata that are broken by relatively closely spaced normal (extensional) faults and broad open folds (Haley, 1968; Haley and Hendricks, 1968, 1971; Merewether and Haley, 1969; Hadaway and Cemen, 2005). Although displacement on the normal faults generally ranges from several tens to hundreds of feet, in some places structural relief may be up to ten thousand feet or more. In Arkansas, the south-dipping (down-to-the-basin) faults are considered to be the master faults, and the north-dipping antithetic extensional faults terminate against them at depth. In general, the dips of both master and antithetic extensional faults range generally from about 30° to 60° (Haley, 1968; Haley and Hendricks, 1968, 1971; Merewether and Haley, 1969).

Major anticlinal structures are commonly fault propagation folds that are associated with north-verging low-angle thrust faults. As a result, the anticlines tend to be asymmetrical, with their steeper limbs to the north. Anticlinal closures apparently diminish with depth as the faults flatten and become parallel to bedding at depth (Haley and Hendricks, 1968).

For assessment purposes the USGS divides hydrocarbon accumulations into two major categories: conventional resources and continuous (unconventional) resources. Conventional resources, by definition, are those that are segregated in reservoirs into layers of gas, oil, and water, whereas continuous hydrocarbon resources are not separated by gravity into their component gases and liquids. USGS assessments of hydrocarbons are based on the total petroleum system (TPS) and AU concepts (Magoon and Smoker, 2000; http://energy.cr.usgs.gov/oilgas/noga/methodology.html). In general, petroleum systems and AUs are characterized by their hydrocarbon source rocks and reservoirs. Coal-bed gas and shale gas reservoirs are predominantly self-sourced (autogenic) so that source rocks and reservoirs are within the same geological formation.

The purpose of this paper is to serve as a brief introduction for the USGS assessment of the continuous shale gas and coal-bed gas resources in the Arkoma basin, Oklahoma and Arkansas. Much of the geological information herein was compiled from the geological literature and especially from the online data and interpretative reports of the Oklahoma and Arkansas geological surveys.

Arkoma Basin shale gas resources

Shale gas petroleum systems and AUs

For the purposes of this assessment the USGS defined two shale-gas total petroleum systems (the Woodford-Chattanooga TPS and the Fayetteville-Caney TPS) and one coal-bed gas TPS (the Arkoma coal-bed gas TPS). The Woodford-Chattanooga TPS is divided into the Woodford Shale Gas and Chattanooga

Woodford shale gas AU

Historical production

The Woodford Shale (Devonian and Mississippian) is a major gas-producing formation within the Arkoma basin of Oklahoma (Oklahoma Geological Survey, 2009b, Brown, 2008). Although the Woodford Shale first produced hydrocarbons in 1939, it was not until 2004 that its full potential was recognized (Valkó, 2008). At present (2009) most of the wells that are drilled into the Woodford are horizontal and have lateral legs that range from about 1000 to 5,000 feet long. For most Woodford wells, vertical drilling depths range from about 3,000 feet to 12,000 feet.

Stratigraphy

In the Arkoma basin, The Woodford ranges in thickness from about 50 feet in northern and central Shale Gas AUs (Fig. 2). Similarly, the Fayetteville-Caney TPS is divided into the Fayetteville Shale Gas and Caney Shale-Gas AUs (Fig. 3). Of the four shale gas-producing formations recognized in the Arkoma basin, the Woodford and the Fayetteville have proven to be the most productive.

Figure 2.

Woodford-Chattanooga shale gas total petroleum system and AU.

Figure 2.

Woodford-Chattanooga shale gas total petroleum system and AU.

Figure 3.

Caney-Fayetteville shale gas total petroleum system and AU.

Figure 3.

Caney-Fayetteville shale gas total petroleum system and AU.

Oklahoma and in adjacent Arkansas to about 300 feet in south-central Oklahoma. The most productive area of the Woodford in the Arkoma basin is in Hughes and Coal counties, where the Woodford is 150 feet thick or more (Wickstrom, 2008). It unconformably overlies formations of the Hunton Group (Silurian and Devonian) and is overlain by the Sycamore Limestone (Mississippian) (Fig. 4). In general, it may be divided into three or more members based upon its log signature, geochemistry, and palynomorphs (Cardott, 2008a). Strata that contain the greatest content of organic material are readily identified on gamma and density logs, and these zones are commonly perforated by the drillers. In outcrop, the formation is commonly silty, black fissile shale, which in places may contain interbeds of chert (Comer, 2007). Nodules of phosphate are common.

Figure 4.

Paleozoic stratigraphic nomenclature of south-central Oklahoma and western Arkansas.

Figure 4.

Paleozoic stratigraphic nomenclature of south-central Oklahoma and western Arkansas.

Chattanooga shale gas AU

Stratigraphy

The Devonian Chattanooga Shale of Arkansas is the approximate lateral equivalent of the Woodward Shale in Oklahoma (Arkansas Geological Survey, 2009b). As in Tennessee, the Chattanooga contains a basal sandstone member in Arkansas, the Sylamore Sandstone. The thickness of the Chattanooga Shale (including the Sylamore Sandstone) ranges up to about 85 feet or more, but normally averages about 30 feet (Arkansas Geological Survey, 2009b).

The Chattanooga Shale is several tens of feet thick in west-central Arkansas, where depths to the formation range from about 6,400 feet on the north to over 14,000 feet on the south (Peng and Ratchford, 2008). In western and northwestern Arkansas, in Sebastian, Franklin, and Crawford counties, the Chattanooga of Haley and Hendricks (1968, 1971) overlies the Penters Chert or Clifty Limestone and is overlain by the Boone Formation (Fig. 4). There, it consists of 9 to 121 feet (commonly 20 to 80 feet) of dark-gray to grayish black, pyrite-bearing shale, locally with very thin interbeds of siltstone. The thickness of the Chattanooga increases generally from the northwest to the southeast (Haley and Hendricks, 1968, 1971).

Caney shale gas AU

Historical production

The Caney Shale in Oklahoma is of Meramecian (Late Mississippian) age (Fig. 4) and is in the approximate stratigraphic position of the Chesterian Fayetteville Shale in the Arkoma basin of Arkansas (Fig. 5). The first Caney Shale gas well in the Arkoma basin was drilled in 1982, and only 8 more were completed in the Caney until 2004, when 24 additional wells were drilled. Most of the wells were vertical completions until early 2005, when the first horizontal wells were drilled. As of April 2008, almost 60 Caney wells had been drilled in and near the Arkoma basin (Oklahoma Geological Survey, 2009a). In the Arkoma basin, the main producing trend of the Caney extends from Coal County, Oklahoma, on the south, northeastward through Hughes, Pittsburg, and McIntosh counties to Muskogee County (Andrews, 2007). Its comparatively low productivity is apparently related to its clay content, which is relatively higher than in the Barnett (Mississippian; Texas) and Fayetteville shales. As a result, the Caney is not as readily fractured as the Barnett or Fayetteville shales (Cardott in Brown 2006a).

Figure 5.

Mississippian stratigraphic nomenclature of northern Arkansas (from Ogren, 1968).

Figure 5.

Mississippian stratigraphic nomenclature of northern Arkansas (from Ogren, 1968).

Stratigraphy

Much of the following discussion is condensed from the work of Andrews (2007). The Caney overlies the Sycamore Limestone over much of the area (Fig. 4). Where the Sycamore is absent, the Caney overlies the Woodford or Hunton directly. In outcrop, the Caney is a gray to dark gray fissile shale, in part interbedded with siltstone, and in places may contain calcareous beds and phosphate nodules. In the Arkoma basin, it is about 200 to 250 feet thick and may be divided into two informal units. The upper unit consists of shale interbedded with siltstone and limestone, and the lower unit consists of fissile shale. The formation thins to the east to less than 50 feet thick in eastern Oklahoma, near the border with Arkansas.

The upper part of the Caney is considered the better reservoir for dry gas primarily because of intergranular porosity within the siltstone beds and the potential for these more brittle beds to be fractured more easily. In contrast with the Woodford, however, the Caney Shale lacks the abundant natural fractures that are necessary for production of large volumes of gas, and the associated clay shales lack the relatively large amounts of silica (chert) that make the Woodford more brittle (Brown, 2008).

Fayetteville shale gas AU

Historical production

The Fayetteville Shale was first developed in 2004, and at present (2009) 2,552 wells have been drilled into the formation. Cumulative production is about 106 Bcf (Arkansas Geological Survey, 2009a). The main part of the explored area lies in the easternmost part of the Arkoma basin, adjacent to the Mississippi embayment.

Stratigraphy

The Fayetteville Shale (Fig. 5) is Chesterian in age and is a black, fissile clay shale that in places contains interbeds of limestone and siliceous, cherty material. The Fayetteville Shale overlies formations of the Mayes Group in Arkansas, the Batesville Sandstone in northeastern Arkansas, and the Hindsville Formation in northwestern Arkansas (Ogren, 1968). In outcrop, the Fayetteville is overlain by the Pitkin Limestone (Mississippian). In general, the Fayetteville may be divided into two members, an upper gray or black shale that may be interbedded with limestone, and a lower, more radioactive black shale (Ratchford et al., 2006, his Figure 2). In places, the upper part of the Fayetteville contains a quartzose sandstone member in northwestern Arkansas, the Wedington Sandstone Member. The contact of the Fayetteville with the overlying Pitkin Limestone is conformable in eastern Arkansas. To the west the contact is apparently unconformable, so that in places depending on erosion, the Pitkin overlies the Wedington Sandstone Member, the upper shale member, or the lower shale member of the Fayetteville (Ogren, 1968).

Assessment data for shale gas AUs

In general, the Woodford is a good naturally fractured gas source rock that is readily fractured hydraulically. Organic matter is primarily type II kerogen and total organic carbon (TOC) values range from 3 to 10%. Vitrinite reflectance is 1.1-3% or more. Geochemical parameters of the Woodford, Caney, and Fayetteville are shown in Table 1. The Woodford contains abundant natural fractures and its quartz content ranges generally from 30 to 87%, which enhances its capability to be fractured during well completion (Cardott, 2009).

Table 1.

Summary of geochemistry of shale gas formations.

Chattanooga vitrinite reflectance values in west-central Arkansas range from about 1.5% at a depth of 7,705 feet to 5.05% at 14,695 feet, and the mean TOC value is 2.88% (Table 1). Kerogen types are mixed marine and terrestrial (Peng and Ratchford, 2008). Thus far, the Chattanooga has not been extensively explored for shale gas in Arkansas, and its resource potential is speculative.

About half of the 24 wells drilled in the Caney in 2004 had initial production rates (IP) of 100 MCFD or more, and one well achieved a rate of 1,125 MCFD. Of these, eleven horizontal wells had IP rates of 200 MCFD, or more. In comparison, for the 882 Woodford wells for which there are IP data, 711 had IP rates of 200 MCFD or more, and 528 exceeded 1,000 MCFD. Almost all of the wells with IPs greater than 200 MCFD are horizontal wells (Source, Oklahoma Geological Survey 2009a).

Most of the wells currently being drilled in the Fayetteville Shale have horizontal legs that may be as much as 4,000 feet long. Horizontal wells with laterals greater than 3,000 feet commonly have estimated ultimate recoveries (EUR) that range from 2.0 to 2.5 Bcf per well (Arkansas Geological Survey, 2009a). Improved well performance is related to improved completion technology, such as the use of slickwater fracs and cross-linked gel stimulation (Brown 2006b).

In Arkansas, eight wells in the Wedington Sandstone Member of the Fayetteville Shale had IPs that ranged from 246 to 3,358 MCFD. Initial production rates for 71 wells in the Fayetteville Shale ranged from 82 MCFD to 3703 MCFD. Of these, seven wells had IPs less than 200 MCFD (IHS Inc., 2008).

Arkoma Basin Coal-Bed Gas Resources

Coal-bed gas petroleum systems and AUs

The Arkoma coal-bed gas total petroleum system lies within the coal fields of south central Arkansas and adjacent Oklahoma. It consists of one AU, the Arkoma coal-bed gas AU (Fig. 6). In general, the coal beds of this total petroleum system, which are both the source rock and reservoir, were deposited in Middle Pennsylvanian (Desmoinesian) time. The Arkoma coal-bed gas AU includes the Hartshorne, lower Hartshorne, upper Hartshorne, and McAlester coal beds, which occur within the Hartshorne and McAlester formations (Fig. 7).

Figure 6.

Arkoma coal-bed gas TPS and AU.

Figure 6.

Arkoma coal-bed gas TPS and AU.

Figure 7.

Stratigraphic nomenclature for Pennsylvanian strata in the coal-bed methane-producing areas of the Arkoma basin, Oklahoma and Arkansas.

Figure 7.

Stratigraphic nomenclature for Pennsylvanian strata in the coal-bed methane-producing areas of the Arkoma basin, Oklahoma and Arkansas.

Arkoma coal-bed gas AU

Historical production

As in other regions, the high content of methane in the Hartshorne coal beds was first recognized as a major hazard to underground mining operations (Iannacchione and Puglio, 1979). Commercial production of coal-bed methane began in the Arkoma basin in 1988, when a vertical well intersected the Hartshorne coal bed at depths of about 600 feet (Brady et al., 2004). The first horizontal coal-bed methane (CBM, coal-bed gas) well in Oklahoma was drilled in 1998, and by the end of December 2001, 83 horizontal CBM wells had been completed in the Hartshorne (PTTC, 2002). As of December 8, 2008, 2,615 CBM wells had been completed in the Hartshorne coal bed in Oklahoma. Of these about 1,500 wells were horizontal (Cardott, 2008b). By 2006, cumulative production of coal-bed methane from the Arkoma basin in Oklahoma was about 154 Bcf, of which 96 Bcf had been produced from horizontal wells (Cardott, 2006).

The first CBM well drilled in the Arkoma basin of Arkansas was in Franklin County in 1986 (IHS Inc., 2008). Since then, approximately 12 Bcf of CBM have been produced in Arkansas, mostly from Sebastian County. In 2007, about 3 Bcf of coal-bed gas were produced from Sebastian County. CDX Gas, LLC, is currently the only producer of CBM in Arkansas and has drilled approximately 37 Z-pinnate horizontal wells and 15 vertical wells into the lower Hartshorne coal bed in Sebastian County. About 564,238 feet of horizontal pinnate laterals have been drilled to-date in Arkansas. On average, approximately 15,000 feet of horizontal laterals were drilled for each of CDX’s Z-pinnate wells (Arkansas Geological Survey, 2009c). The Z-pinnate well pattern consisted of a main horizontal well lateral, from which multiple horizontal side laterals were drilled in a pattern that resembled the veins of a maple leaf.

Stratigraphy

The Desmoinesian Series contains the Krebs Group, which in turn consists of (in ascending order), of the Hartshorne, McAlester, Savanna, and Boggy formations (Fig. 7). The upper and lower Hartshorne coal beds within the Hartshorne Formation in Oklahoma and the McAlester coal bed within the McAlester Formation comprise the source rocks and the principal reservoirs of the Arkoma coal-bed gas total petroleum system, Arkoma coal-bed gas AU (Fig. 6). In Arkansas, the Hartshorne coal beds are classified as lying within the lower part of the McAlester Formation (Arkansas Geological Survey, 2009d). The lower Hartshorne is the most extensive and productive coal bed in the Arkansas part of the Arkoma basin.

In Oklahoma, the Hartshorne Formation may be divided into two areas by a “coal-split-line” (Fig. 6). Southeast of the coal-split line, McDaniel (1961) divided the Hartshorne Formation into upper and lower members, each with its own coal bed in the upper part of the member. North and west of the line, the coal beds merge into one bed and the Hartshorne Formation is dominated by fluvial-deltaic deposits in its lower part that are overlain by the Hartshorne coal bed (Houseknecht et al., 1984).

During the Middle Pennsylvanian, Hartshorne siliciclastic sediments entered the basin generally from the north and east and were transported westward along the basin within a fluvial-deltaic system. In Arkansas, Hartshorne deposition is dominated by relatively widespread fluvial sandstones. To the west in Oklahoma, the major sandstone trends bifurcate into delta distributaries, which in turn gave way westward into marine and marginal marine deposits (Houseknecht et al., 1984; Andrews, 1998). The major sedimentary facies within the Hartshorne were described by (Houseknecht et al., 1984) from the most distal to most proximal and include: (1) prodelta, (2) delta-front, (3) distributary-channel, (4) interdistributary bay, (5) marsh-swamp, (6) crevasse-splay, and (7) fluvial facies.

The Hartshorne Formation overlies prodelta shales, siltstones and sandstones within the upper part of the Atoka Formation (Houseknecht et al., 1984). The contact of the Hartshorne with the underlying Atoka is generally conformable, except where Hartshorne channel-fill deposits cut deeply into the underlying strata (Suneson, 1998). The Hartshorne ranges in thickness from a few tens of feet to about 400 feet thick (Knechtel, 1949; Merewether, 1971) and locally may be as much as 1,000 feet thick (Suneson, 1998). Houseknecht and Iannacchione (1982) conclude that the westward progradation of the Hartshorne depositional system results in the formation of prodelta and delta front deposits that are overlain by distributary-channel sandstones and laterally equivalent interdistributary bay deposits. These, in places, grade upward and laterally into marsh and swamp deposits together with their associated peat (coal) deposits.

Houseknecht et al. (1984), Gossling (1994), and Andrews (1998) mapped a significant area of sandstone-filled distributary channels within both the Lower and Upper members of the Hartshorne Formation, from the Arkansas state line westward across northern Le Flore and Latimer Counties into northeastern Pittsburg County; from there the Hartshorne Formation channels turn generally to the southwest and cross southwestern Pittsburg, northwestern Atoka, and northeastern Coal County. Coal beds are relatively thin or absent in the areas dominated by sandstone-filled distributaries. In adjacent areas, which are dominated by interdistributary bay deposits that are overlain by marsh-swamp deposits, the coal beds are thicker and may be productive of hydrocarbons (Houseknecht and Innacchione, 1982; Innacchione et al., 1983; Houseknecht et al., 1984; Gossling, 1994).

The McAlester Formation ranges from a few hundred feet thick to 2,800 feet thick and consists mostly of gray to grayish-black shale with interbeds of siltstone and very-fine-grained sandstone beds that are commonly irregular in thickness. The McAlester Formation contains two minable coal beds near the middle of the formation, the McAlester (Stigler) and upper McAlester coal beds (Fig. 6). The McAlester (Stigler) coal bed is the thicker of the two, and it has been included as a potential source rock and reservoir for coal-bed methane within this petroleum system. Merewether (1971) interprets the depositional environments of the McAlester to range from continental to near-shore settings. The upper McAlester coal bed is not considered because of its limited distribution and shallow depth of burial. Figure 8 shows the depths to the top of the Hartshorne coal bed and the general distribution of deep synclinal areas, shown in light blue, in the southern part of the basin.

Figure 8.

Depth to the top of the Hartshorne coal bed based on well control data from IHS Inc. (2008).

Figure 8.

Depth to the top of the Hartshorne coal bed based on well control data from IHS Inc. (2008).

Assessment data

Gas-in-place data

Table 2 illustrates the publically available canister desorption data for the Hartshorne, lower Hartshorne, and upper Hartshorne coal beds in Oklahoma (Diamond et al., 1986). The data are from Le Flore and Pittsburg counties and in general range from 70 cubic feet per ton (CF/ton) to 547.2 CF/ton. Of the 32 values, 18 are greater than 300 CF/ton, which suggests that the Hartshorne should contain a large volume of gas over much of its area of deposition. Cardott (1998) summarizes the regional distribution of gas content for coal beds in the Oklahoma part of the Arkoma basin and notes that Forgotson and Friedman (1993) concludes that gas content of the coal beds generally increases from west to east, from about 300 CF/ton to 600 CF/ton at depths of 800 to 2000 feet.

Table 2.

Direct-method gas content measurements of Hartshorne coal bed, Oklahoma. See Figure 6 for county locations.

Thermal maturity

In general, thermal maturity increases from west toward the east across the Arkoma basin, from a little less than 1.0 % Ro in western Pittsburg County to 2.4 % Ro in Le Flore County. The coal ranges from high volatile bituminous through medium volatile bituminous in Pittsburg, Latimer, and Haskell Counties, to low volatile bituminous and semi-anthracite in a small area in LeFlore County (Cardott, 2006). In Arkansas, the rank of the Hartshorne coal bed ranges from low-volatile bituminous over much of the western part of the Arkansas Valley coalfield to semi-anthracite in Johnson County (Fig. 6) in the eastern part of the coalfield, where vitrinite reflectance values exceed 2.0 % Ro in Johnson and Pope counties (Arkansas Geological Survey, 2009d, Houseknecht et al., 1992). In general, the capability of coal to generate methane is related to the rank of the coal. Although the generation of methane peaks within low volatile bituminous coals, gas storage capacity generally decreases with increasing rank (Cardott, 1998). Cardott (1998) concludes that the most favorable CBM reservoirs are within high volatile to low volatile bituminous coals because of increased generation capacity and fracture porosity. Previous estimates of coal-bed gas resources in the Arkoma basin are shown in Table 3.

Table 3.

Estimates of CBM resources (Data from Cardott, 1998; Rice and Finn, 1996a, b). H is Hartshorne coal bed; LH is lower Hartshorne coal bed.

Seals

The primary seal for coal-bed gas is water, and in most cases the water has to be removed by pumping to initiate the flow of gas to the well bore. The largest amount of water produced from 2,021 Hartshorne wells in the Oklahoma part of the Arkoma basin is 1,861 barrels of water per day (BWPD). This maximum water production is from an old well that was worked over in Coal County (Fig. 6). The median value for all of the 2,021 wells for which there are data is about 24 BWPD. For the most part, the Hartshorne coal beds are relatively dry when compared to coals in other parts of the nation, which accounts in part for the relatively high productivity of the Hartshorne (Mutalik and Magness, 2006).

Conclusion

The Arkoma basin is a super mature basin that has produced about 18 Tcf of gas from both continuous and conventional reservoirs (Boyd, 2005; Arkansas Geological Survey, 2009e). Although all of the continuous reservoirs have been penetrated by the drill, there still are large areas that have not been adequately tested. For shale gas, these relatively untested areas include almost all of the Chattanooga Shale Gas AU in Arkansas, the central and western parts of the Woodford Shale Gas AU in Oklahoma and adjacent Arkansas, the western and southern part of the Fayetteville Shale Gas AU in Arkansas, and the eastern part of the Caney Shale Gas AU in Oklahoma. Although the Arkoma coal-bed gas AU has been substantially drilled to the north of the coal split line, the more deeply buried areas to the south of the line have not been explored to any large extent and may contain undiscovered gas resources.

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31
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Valkó
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P.P.
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: http://www.pe.tamu.edu/valko/public_html/course_material/2008oct14sem/semsupp/wf/FirstArkoma.docx
Wickstrom
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.

Figures & Tables

Table 1.

Summary of geochemistry of shale gas formations.

Table 2.

Direct-method gas content measurements of Hartshorne coal bed, Oklahoma. See Figure 6 for county locations.

Table 3.

Estimates of CBM resources (Data from Cardott, 1998; Rice and Finn, 1996a, b). H is Hartshorne coal bed; LH is lower Hartshorne coal bed.

Contents

GeoRef

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