Implications of Variable Gas Saturation in Coalbed Methane Reservoirs of the Black Warrior Basin
Published:December 01, 2009
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Pashin Jack, 2009. "Implications of Variable Gas Saturation in Coalbed Methane Reservoirs of the Black Warrior Basin", Unconventional Energy Resources: Making the Unconventional Conventional, Tim Carr, Tony D’Agostino, William Ambrose, Jack Pashin, Norman C. Rosen
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Variable gas saturation in coal of the Black Warrior basin has significant consequences for production performance, and the relationship of gas saturation to isotherm geometry is a critical consideration for development. Although gas content generally increases with depth, saturation typically vari‘es greatly among individual coal seams. Reservoir conditions in the Black Warrior basin are the product of a complex mix of stratig 22raphic, structural, hydrogeologic, and petrologic factors, and these factors have a strong influence on the mobility and recoverability of coalbed methane. In deep, highly pressured seams that are substantially above Langmuir pressure, the low slope of the isotherm indicates that even minor undersaturation can necessitate prolonged dewatering before the reservoir reaches critical desorption pressure. Where reservoir pressure is relatively low and the slope of the isotherm is relatively steep, by contrast, reservoirs that are significantly undersaturated with gas can be close to the critical desorption pressure. Consequently, low reservoir pressure in the northern part of the Black Warrior coalbed methane play favors high gas recovery from all coal seams, whereas recovery from deep, highly pressured coal in the southwestern part of the play is favored by a combination of high initial gas content and high Langmuir pressure.
The Black Warrior basin of Alabama (Fig. 1) has served as a laboratory for the development and implementation of coalbed methane technology since the mid 1970s, when the U.S. Bureau of Mines conducted a historic program that was directed at improving mine safety through the production of gas from coal (Elder and Deul, 1974).There are now more than 4800 wells currently on line since commercial production of coalbed methane was established in 1980. Coalbed gas resources in the Black Warrior basin of Alabama have been estimated to be between 10 and 20 Tcf (Hewitt, 1984; McFall et al., 1986), although technically recoverable resources were estimated to be 2.4 to 2.6 Tcf during the 1990s (Rice, 1995; Lyons, 1997). Indeed, the most recent assessment of the basin indicates that an additional 4.6 to 6.9 Tcf of gas may remain undiscovered (Hatch and Pawlewicz, 2007). As of 2007, the Energy Information Administration (2009) estimated proved coalbed methane reserves at 2.1 Tcf, and the proved reserve base has grown annually by more than 100 Bcf/yr since 1996, indicating that, despite the maturity of exploration and development, the Black Warrior remains a vital and highly active coalbed methane basin. Cumulative gas production now exceeds 2.1 Tcf, and annual gas production is typically between 110 and 120 Bcf and has yet to begin a systematic decline.
Experience from all of the major coalbed methane plays indicates that geological heterogeneity from molecular scale to basin scale influences the distribution and producibility of coalbed methane (e.g., Levine, 1993; Kaiser et al., 1994; Pashin, 1998; Ayers, 2002; Scott, 2002). Resource distribution in the Black Warrior basin is influenced by a spectrum of stratigraphic, structural, hydrogeologic, and petrologic variables (e.g., Pashin et al., 1991, 2004; Pashin and Hinkle, 1997; Pashin, 2007). Desorption tests demonstrate that the gas content of coal in the Black Warrior basin exhibits significant lateral and vertical variability, and gas content and gas saturation can differ markedly among closely spaced coal seams (e.g., Diamond et al., 1976; Malone et al., 1987; Levine and Telle, 1989) (Fig. 2). This paper provides a brief overview of the geology of the Black Warrior coalbed methane play and considers the implications of variable gas saturation for reservoir performance. This review is intended to demonstrate that gas production does not necessarily correlate with the original resource base and that careful consideration of the relationship of basic Langmuir adsorption parameters to a broad range of geologic factors is helpful for identifying where and how gas can be recovered economically.
The Black Warrior basin is a late Paleozoic foreland basin that formed at the juncture of the Appalachian and Ouachita orogenic belts (Thomas, 1985, 1988). Coalbed methane development is restricted to the eastern part of the basin along the frontal structures of the Appalachian orogenic belt (Fig. 1). Coal and coalbed methane reserves are distributed among multiple coal seams in the upper part of the Pottsville Formation, which is of Early Pennsylvanian age (Fig. 3). The Pottsville is a siliciclastic succession that contains a distinctive series of flooding-surface-bounded depositional units, or parasequences, in which deltaic deposits are overlain by heterogeneous coal zones containing a spectrum of marginal marine and terrestrial facies (e.g., Pashin et al., 1991; Gastaldo et al., 1993; Greb et al., 2008).
Seam thickness is generally between 0.1 and 12 ft, and the geometric mean of seam thickness is about 1 ft. Net coal thickness increases southeastward from less than 10 ft in Robinson’s Bend Field to more than 70 ft in Moundville Field (Fig. 4). This increase in net coal thickness corresponds with thickening of the Pottsville Formation into the Moundville-Cedar Cove depocenter, which was a persistent area of subsidence throughout Pottsville sedimentation (Pashin, 1994, 2004; Pashin and Raymond, 2004). A major proliferation of coal seams corresponds with thickening of the Pottsville into the depocenter. Seams as thin as 1 ft are commonly completed for production. In most vertical wells, gas is produced from 5 to 8 coal seams at depths between 500 and 2,500 ft, and nearly all wells produce from the Black Creek, Mary Lee, and Pratt coal zones (Fig. 3). Many wells in the Moundville-Cedar Cove depocenter are completed in 20 or more coal seams, and productive strata include all upper Pottsville coal zones between 500 and 4,500 ft.
Structurally, the eastern Black Warrior basin is a southwest-dipping homocline having superimposed folds and faults (e.g., Thomas, 1988; Pashin and Groshong, 1998; Pashin et al., 2004) (Fig. 1). Folds of the Appalachian thrust belt have deformed the southeast margin of the basin. Here, closely spaced structural contours define an upturned basin margin in which the major reservoir coal beds dip steeply and are exposed at the surface. The regional homocline is broken by numerous normal faults that strike northwest at a high angle to the upturned basin margin. The faults dip steeper than 50° and form a regionally extensive horst-and-graben system. Vertical separation of the faults is typically less than 250 ft but locally exceeds 700 ft in the southwestern coalbed methane fields.
Pottsville strata are exposed in the northeastern part of the basin and are overlain with angular unconformity by as much as 1,100 feet of poorly consolidated Cretaceous strata in the southwestern part (Fig. 1). This unconformity is a simple homoclinal surface that dips southwest at less than 1° (Kidd, 1976). All folds and faults in the Paleozoic section terminate at or below the unconformity surface (Thomas, 1988).
The basic geologic framework is a fundamental determinant of the hydrogeology of the Black Warrior basin (Pashin et al., 1991; Pashin and Hinkle, 1997; Pashin, 2007). Upper Pottsville shale and sandstone in the coalbed methane fields are effectively impermeable, and so coal is the only rock type possessing significant hydraulic conductivity. Closely spaced cleats, which are fracture networks resembling joint systems, are the primary source of this conductivity and provide the transmissivity required to support commercial flow rates. Coal is a stress-sensitive rock type and well testing confirms that permeability tends to decrease exponentially with depth (McKee et al., 1988). Accordingly, permeability in coal seams shallower than 500 ft can be on the order of 100 to 1,000 mD, whereas in seams deeper than 2,000 ft it can be less than 1 mD.
Exposure of reservoir coal seams along the upturned basin margin has been interpreted to have a strong influence on water chemistry and reservoir pressure in the upper Pottsville (Pashin et al., 1991; Pashin and McIntyre, 2003; Pashin, 2007). The upturned basin margin is an important zone of meteoric recharge, and fresh-water plumes having TDS content lower than 3,000 mg/L extend northwestward into the interior of the basin (Fig. 1). Because the normal faults strike at a high angle to the basin margin, they do not block recharge and in some places may have helped transport water deep into the basin. Poorly consolidated Cretaceous strata contain major sandstone aquifers that intercept meteoric recharge, and so coal seams in the southwestern coalbed methane fields can contain saline water having more than 30,000 mg/L TDS (Ellard et al., 1992; Ortiz et al., 1993).
Original hydrostatic pressure gradients in most of the coalbed methane fields tend to be slightly under-pressured to normally pressured (0.30-0.43 psi/ft) (Pashin et al., 1991; Pashin and McIntyre, 2003) (Fig. 5). However, some prominent areas of underpressure that pre-date the coalbed methane industry exist in the northeastern part of the basin. Recharge along the upturned basin margin appears to support near-normal hydrostatic pressure gradients up to 13 miles into the interior of the basin. Within this area, however, are two prominent areas of underpressure in Oak Grove and Brookwood Fields that correspond with the longwall coal mines that were developed prior to the coalbed methane industry. Farther northwest is a large area of underpressure that is not associated with mine development and thus appears to be natural. Pashin and McIntyre (2003) interpreted this natural underpressure to be caused partly by free gas in cleat systems.
Coal Rank and Gas Storage
Coal in the Pottsville Formation of the Black Warrior basin is bright-banded, rich in vitrinite, and of bituminous rank (Fig. 6). In the coalbed methane fields, rank ranges from high volatile B bituminous to low volatile bituminous. Virtually all coalbed production todate is from where coal in the Mary Lee zone is of high volatile A bituminous or higher rank and is thus within the thermogenic gas window. Medium and low volatile bituminous coal of metallurgical quality is concentrated in an elliptical area centered in Oak Grove and Brook-wood Fields and has been the primary focus of longwall mining operations in the Mary Lee coal zone.
It has long been known that rank patterns in the eastern Black Warrior basin do not correspond with structural or depositional patterns (Semmes, 1929), and indeed isovols in many areas cut directly across bedding and structure (Winston, 1990a, b; Pashin et al., 1999). The regional rank pattern is thought to reflect variation of the paleogeothermal gradient near the time of maximum burial (Telle et al., 1987), and explanations for elevated gradient in the high-rank area include orogenic fluid expulsion and increased burial depth associated with emplacement of a now-eroded thrust sheet (Winston, 1990a, b; Thomas et al., 2008).
Kim (1977) determined that the adsorption capacity of coal in the Black Warrior basin is influenced primarily by coal rank. Indeed, Langmuir volume, which is the ultimate adsorption capacity of coal at a given temperature (Fig. 7), correlates significantly with volatile matter content (Fig. 8). Correlation with other compositional parameters, such as mineral matter and maceral content, is strongly subordinate to coal rank (Carroll and Pashin, 2003; Pashin et al., 2009). Langmuir pressure, which is the pressure at which the gas content of coal reaches 50% of Langmuir volume (Fig. 7), is an important indicator of the geometry of an adsorption isotherm. Where Langmuir pressure is low, the slope of the isotherm is very steep at low pressure and flattens at high pressure. Where Langmuir pressure is high, the isotherm slopes less steeply at low pressure but maintains slope at higher pressure. Langmuir pressure ranges greatly from less than 200 psi to nearly 900 psi in coal of the Black Warrior basin and does not correlate significantly with rank or other known compositional parameters.
Nearly all coalbed methane production in the Black Warrior basin comes from where coal is of sufficient rank to have generated thermogenic gas. However, methane from the highest rank coal can be the most depleted in 13C, which has led some workers to suggest that there has been mixing with late-stage biogenic gas in areas influenced by fresh-water recharge (e.g., Rice, 1993; Pitman et al., 2003; Pashin, 2007). Coalbed gas produced from the Black Warrior basin is sweet, dry gas containing a small percentage of nitrogen and only traces of carbon dioxide (Scott, 1993). The low carbon dioxide content is atypical of most thermogenic and biogenic gases (Hunt, 1979; Scott, 1993) and may indicate geochemical alteration. Isotopic analysis of calcite cement in cleats suggests an origin associated with bacterial CO2 reduction (Pitman et al., 2003), and so some of this calcite may be a by-product of alteration of the gases. Regardless, coalbed gas in the Black Warrior basin has been generated and preserved in a complex thermal and hydrodynamic system, which may help explain variable gas saturation.
Resource Base and Production
On the basis of the available gas content and coal thickness data, original gas-in-place (OGIP) in the Black Creek through Cobb coal zones can exceed 9 Bcf/mi (McFall et al, 1986). Figure 9 is a highly generalized map showing the relative distribution of OGIP in the Black Warrior coalbed methane fields that incorporates new data on gas content and coal thickness (e.g., Bodden and Ehrlich, 1998). Comparison of Figures 4 and 9 indicates that coal thickness is the primary determinant of OGIP. Coal rank is a secondary control, and the increased adsorption capacity of medium- and low-volatile bituminous coal (Fig. 8) appears to have elevated OGIP values relative to coal thickness where mining activity is concentrated on the Oak Grove-Brookwood area (Figs. 6, 9). In addition to vertical variation of gas saturation (Fig. 2), some natural anomalies of exceptionally low gas content have been identified in the northern part of the coalbed methane development area (Malone et al., 1987). The origin of these anomalies remains enigmatic, and Malone et al. (1987) proposed a hydrodynamic hypothesis related to paleovalley incision and lowering of water levels during arid episodes in the geologic past. Indeed, the occurrence of these anomalies along the northwest edge of the region with near-normal reservoir pressure (Figs. 5, 9) supports some type of hydrodynamic cause.
The volumes of water and gas produced from coalbed methane wells in the Black Warrior basin vary greatly (Figs. 10, 11) and are log-normally distributed (Pashin and Hinkle, 1997; Zuber and Boyer, 2001; Pashin, 2007). Peak production rate correlates strongly with cumulative production and is thus a valuable short-term predictor of cumulative gas and water production (Pashin and Hinkle, 1997). Peak production maps have been published and interpreted recently by Pashin (2007), and so cumulative production trends are emphasized herein. Eighty percent of the wells reporting more than four years of production have produced 0.01 to 0.81 MMbbl of water and 0.02 to 0.71 Bcf of gas, and exceptional wells have produced more than 2.00 MMbbl of water or 1.20 Bcf of gas.
Mapping cumulative water and gas production indicates that actual reservoir performance patterns correspond poorly with regional trends of reservoir thickness (Figs. 4, 10, 11). Indeed, no significant correlation has been identified between productivity and net completed coal thickness at a regional scale (Pashin et al., 1991). Moreover, no universal correlation between water and gas production values exists (Pashin and Hinkle, 1997), and indeed, regional patterns of cumulative water and gas production differ markedly (Figs. 10, 11).
The map of cumulative water production bears some similarity to the map of hydrostatic pressure gradient (Figs. 5, 10). Cumulative water production tends to be less than 0.1 MMbbl in the mine-related and natural areas of underpressure in the northern part of the coalbed methane play. Water production values tend to be significantly higher but are extremely variable in normally pressured to weakly underpressured areas, including the southwestern fields below Cretaceous cover. A prominent exception is in Moundville Field, where few wells have significant production history and perforations commonly do not correspond with the positions of coal seams.
Mapping cumulative gas production indicates that coalbed methane operations have met with little success near the southwestern limit of coalbed methane development, where Pottsville strata are concealed below thick Cretaceous cover (Fig. 11). Production values tend to increase northeastward and are in places greater than 0.3 Bcf as far as 10 to 15 mi southwest of the edge of Cretaceous cover in Robinson’s Bend and Cedar Cove fields. Well performance is quite variable where Cretaceous cover is thin or absent.
Production performance is most consistent along an arcuate trend that cuts across the central part of the coalbed methane play from Cedar Cove Field to White Oak Creek Field. Numerous wells have produced more than 0.9 Bcf in the southern part of this trend, which overlaps the northeastern part of the Moundville-Cedar Cove depocenter (Figs. 4, 11). Farther north along this trend in Deerlick Creek, Blue Creek, and White Oak Creek fields, cumulative production values are commonly between 0.3 and 0.9 Bcf, even though this is the youngest part of the Black Warrior coalbed methane play and reservoir thickness is limited. Importantly, this part of the trend corresponds with natural underpressure and low water production (Figs. 5, 10, 11).
The eastern boundary of the arcuate trend is distinct and is marked by an array of wells having less than 0.1 Bcf of cumulative production that stretches from northwestern Brookwood Field to southeastern Deerlick Creek Field. This trend corresponds at least partly with the low gas content anomaly identified by Malone et al. (1987) and further corresponds with the edge of the region of near-normal reservoir pressure that is supported by recharge along the upturned basin margin. Low gas production values in much of western Oak Grove Field, however, may also reflect ineffective resource recovery related to broad and irregular well spacing. Some prominent anomalies, which have produced below 0.1 Bcf, exist along the southeastern basin margin of the basin from the northeastern corner of Cedar Cove Field into Oak Grove Field. The northeastern anomaly corresponds largely with an en echelon fault swarm (Fig. 1) and may thus be influenced by limited reservoir continuity. The origin of the other anomalies along the basin margin is also unclear, and factors that may have played a role include ineffective dewatering of coal near the recharge area and resource depletion caused by hydrodynamic sweep of gas into the interior of the basin. Between the low-production anomalies, the gas production pattern in Oak Grove and Brookwood fields is highly irregular and appears to be influenced by a complex mix of hydrogeology, underground coal mining, and coal degasification.
Discussion and Conclusions
Analysis of regional geology, resource distribution, and production trends in coalbed methane reservoirs of the Black Warrior basin indicates that long-term production performance does not correlate directly with coal thickness or OGIP (Figs. 4, 9, 10, and 11). Understanding this poor correlation requires knowledge of the relationship of gas saturation to isotherm geometry and of the basic geologic controls on reservoir pressure and permeability. Where reservoir pressure is high enough to support gas content near Langmuir volume, for example, the low slope of the isotherm can require an extremely large reduction of hydrostatic pressure before coal can reach critical desorption pressure (Fig. 7). Hence, even a modest degree of undersaturation can result in poor gas recovery if reservoir pressure cannot be reduced substantially. This situation can be exacerbated by decreasing permeability with depth in the Black Warrior basin, which limits the ability to dewater and depressurize coal seams deeper than 2,500 ft. Conversely, where reservoir pressure is near Langmuir pressure, the steep slope of the isotherm facilitates the attainment of critical desorption pressure at a relatively small reduction of reservoir pressure. Therefore, economic gas recovery can be achieved readily from undersaturated coal seams at low pressure, provided that sufficient permeability exists and an adequate gas resource is available.
Low gas production values in the southwestern coalbed methane fields can be attributed to a number of factors. Structural dip toward the southwest (Fig. 1) places the Black Creek through Pratt coal zones at depths between 2,500 and 5,000 ft, where low permeability and high reservoir pressure can inhibit gas recovery. The high salinity of formation water in reservoirs below thick Cretaceous cover presents difficulties for environmentally safe water disposal (Ortiz et al., 1993), and few wells in this area have been pumped to their full potential. In addition, bacterial methanogenesis apparently has been less intense below Cretaceous cover, which favors undersaturated reservoir conditions (Pitman et al., 2003).
Regardless, significant opportunities for development remain below Cretaceous cover, where abundant coal and gas resources exist in the younger Pottsville coal zones. In this area, production can be optimized by selectively completing shallow, permeable coal seams with high gas saturation and by allowing enough time for a significant reservoir volume to fall below the critical desorption pressure. In addition, the slope of the isotherm at elevated reservoir pressure increases as Langmuir pressure increases, so seams having high Langmuir pressure may remain prospective at depth.
Northeast of Cretaceous cover, most target coal seams are shallower than 2,500 ft. Accordingly, reservoir pressure is lower than 1,100 psi under normal hydrostatic conditions, and many reservoir coal beds fall within the high-permeability envelope established by McKee et al. (1988). Hence, most coal is natively in or near the steep part of the adsorption isotherm (Fig. 7), and this is especially true of underpressured reservoirs (Fig. 5). Free gas in the cleats of naturally underpressured coal seams indicates that coal matrix is effectively saturated, and under these conditions, modest decreases in reservoir pressure can facilitate the production of large volumes of gas. This is especially apparent in the Deerlick Creek-White Oak Creek corridor, where large volumes of gas have been produced from an area containing a limited coal resource (Figs. 4, 9, and 11). Fresh water in coal along the southeastern basin margin facilitates low-cost, in-stream disposal of produced water in the northern coalbed methane fields, and so wells can be pumped at optimal rates. Underpressure, moreover, is associated with low volumes of produced water (Figs. 5 and 10), which substantially improves reservoir economics.
This report is based in part on research that was supported in part by the U.S. Department of Energy under Award no. DE-FC26-00NT40927. However, any opinions, findings, conclusions, or recommendations expressed herein are those of the authors and do not necessarily reflect the views of the DOE. Jim Walter Resources, Incorporated, and El Paso Exploration and Production, Incorporated, donated core samples for analysis. Isotherm analyses were performed by Marc Bustin of the University of British Columbia, and proximate analyses were provided by Alabama Power Company.