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CBM basin assessment

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Several different types of basins present excellent exploration targets for coalbed methane (CBM) prospecting.[1] This article discusses the geology, depositional setting, and hydrogeology of promising CBM areas, along with a discussion of data sources that can help in evaluation of prospects.

Structural geology

Foreland basins are flexural troughs that form in front of rising mountain belts. These basins, which include the Black Warrior and San Juan basins of the U.S., have provided more than 90% of the world’s coal gas production to date. Cratonic basins such as the Williston basin, which straddles the U.S./Canadian border, are simple structural depressions that favor the deposition of widespread, continuous coal seams. Intermontane basins, which are common in the Appalachian Mountains of the eastern U.S., form within mountain belts and often are structurally complex, resulting in a more heterogeneous coal distribution.

Within these basins, near-surface coal gas reservoirs of bituminous to anthracite rank were at one time buried to depths of greater than 3000 m. At these depths, hydrocarbons were generated in situ, and the cleat structure of the coal was formed. The cleats were preserved by relatively gentle uplift of the basin and erosion of the overburden. This is an important consideration for prospecting, because intense folding and faulting can shear coal seams, destroying the cleat structure and related permeability. Not all CBM reservoirs have been buried deeply before uplift. In portions of the Piceance, San Juan, and Raton basins of the western U.S., anomalously high geothermal gradients created by tertiary igneous intrusions have created high-rank coals at relatively shallow depths.[2] In the Powder River basin, biogenic gas is produced commercially from subbituminous coals that are too immature to have been deeply buried.

Within a given basin, various structures tend to be associated with enhanced gas production. In the Powder River basin, folds with up to 75 m of structural relief were created by differential compaction. These folds are superimposed on the gently dipping flank of the basin and contain free gas.[3] In the Black Warrior basin, several rollover anticlines and synclines have been linked to higher gas rates.[1] Tensional stress along the axes of these structures results in cleats that are more open and have greater permeability. Also in the Black Warrior basin, field mapping and remote sensing techniques have been used to identify well-developed fracture systems associated with high-rate gas wells.[4] In the San Juan basin, a multicomponent 3D seismic survey showed that areas of high well productivity correspond to zones of extensional fractures and lower in-situ stress.[5] The relationship between higher rates and lower stress also has been established in the Black Warrior basin by correlating the results of 70 well-test measurements with production from more than 600 wells.[6]

From these studies, it is clear that the prospective basins are relatively undeformed with low in-situ tectonic stresses. Within a given basin, knowledge of all structures, especially the locations of faults and folds, is very useful for siting prospective well locations.

Depositional setting

Coals are associated with a variety of depositional systems including alluvial fans, rivers, deltas, and coastlines. Coals originate as peat deposits consisting of organic matter preserved from oxidation by rapid submergence beneath the water table. Accumulation rates are highly variable and range up to approximately 2 mm/yr.[7] The thickest, purest coals form in raised peat bogs that are protected from inundation by floodwaters. In contrast, lower-lying fens, swamps, and marshes are vulnerable to flooding and erosion. This creates laterally discontinuous coals with higher ash contents and interbeds of sandstone and shale (splits).

The Powder River, Black Warrior, and San Juan basins are among the most studied coal basins in the world, and they contain a variety of coal depositional systems.[8] Coals of the Paleocene Fort Union formation in the Powder River basin were deposited in a meandering to anastamosing fluvial system. The coals are elongated parallel to depositional dip and typically are narrow lenticular bodies. Coals in the overlying Wasatch formation formed in front of alluvial fans and are thick, lenticular, and oriented transverse to depositional dip.

Coals in the Pennsylvanian Pottsville formation of the Black Warrior basin are also of fluvial origin, but their distribution is partially controlled by the structural setting.[9] Thicker, higher-quality coals were deposited on the elevated, upthrown sides of faults and were protected from fluvial inundation.[8] Thinner, more ash-rich coal bodies formed on the downthrown sides of the faults. In some of the upthrown blocks, fluvial systems carved paleovalleys that were later abandoned and filled with peat, forming dendritic coal bodies.

In the San Juan basin, coals of the Fruitland formation are associated with both delta-plain and back-barrier settings.[8] Back-barrier coal bodies are geographically continuous along depositional strike. Relative to back-barrier coals, deltaic coal bodies are oriented along depositional dip and typically are more discontinuous, numerous, and thicker. These differences exist because the deltaic coals are separated by distributary channels, whereas the back-barrier coals formed behind a laterally extensive shoreline.

Understanding the likely geometry, orientation, and distribution of prospective coal seams is an important element of successful appraisal and development programs. These insights are valuable for locating thicker and higher-quality coal bodies, predicting whether these will be connected at a given well spacing, and determining future appraisal or exploration well locations. However, the presence of thick, laterally extensive coal bodies does not guarantee connectivity among wells because individual bodies can be extremely heterogeneous. Conversely, in areas in which coal bodies are small, they may be stacked to form well-connected, areally extensive coal reservoirs. To understand these relationships in a new area, it is necessary to continuously core coal seams and the rocks interbedded with them in several wells and relate this information to logs, well tests, and depositional models. This strategy has the added benefit of identifying potential conventional gas reservoirs in sandstones and carbonates interbedded with the coal seams.


The hydrogeology of a CBM reservoir can strongly influence reservoir pressure and gas content. Regions of artesian overpressure may form, allowing coals to retain significantly more gas than at lower pressures. Although these regions will require more dewatering, the potential exists for very high gas rates if the coal seams are saturated with gas. Conversely, regions of underpressure may form if permeabilities are low and coals are poorly connected to recharge areas. Coals in these regions are likely to have lower gas contents and poorer well performance. Hydrogeologic studies can identify these different pressure regimes and intervening permeability barriers, which provide explanations for regional differences in reservoir behavior and offer predictive tools to identify areas with the potential for extraordinary gas production.

Because of their good permeability and lateral continuity, coal seams are excellent aquifers in most basins. The coals outcrop along the basin margins, where they are recharged and carry groundwater to the basin. As a result, produced waters are relatively fresh (< 10,000 g/m3) and can be discharged at the surface in some basins. Points of discharge (upward flow) in a basin coincide with major river valleys, no-flow boundaries, and topographically low outcrop belts.[10] For a given coal seam, pressure data from existing wells can be combined with outcrop and stream elevations to produce a potentiometric map. This map is a measure of the hydraulic head in the coal seam, and it quantifies the driving force behind groundwater movement. Groundwater flows down the hydraulic gradient, perpendicular to the contours of the map.

A potentiometric map of Fruitland formation coals in the San Juan basin shows high values of hydrostatic head along the northern rim of the basin resulting from recharge. Farther south, the contours become tightly spaced and aligned in a northwest/southeast direction, indicating a buildup of fluid pressure caused by resistance to flow. This resistance is interpreted as a decrease in coal permeability and/or thickness coincident with a structural hingeline.[11] The hingeline forms the southern boundary of a large area of artesian overpressure, high gas content, and high gas rates known as the San Juan fairway. The artesian overpressure makes it possible for the coals to retain a large gas volume, and several gas sources (thermogenic, biogenic, and migrated gas) have combined to saturate these seams with gas. This recognition has led to the development of a model for identifying areas with extraordinary coal gas production potential in coal basins.[12]

In addition to potentiometric maps, chemical analyses of produced waters can be used to determine flow patterns within coal seams. This is possible because groundwater evolves chemically along its flow path, causing changes in pH, Eh, and in the composition and concentration of ions and isotopes. For example, recharge along basin margins creates plumes of low chloride, fresh water that follow the most-permeable flow paths within a coal reservoir. These meteroric waters are depleted in certain isotopes of oxygen and hydrogen.[10] Other isotopes can indicate the presence of bacterial activity or provide an absolute age for the waters. Abrupt differences between these values can help identify reservoir compartments.

Data sources

Openhole logs, mudlogs, mining data, drilling histories, and cores from conventional wells are valuable sources of data for determining the number, depth, thickness, and quality of coal seams in a frontier basin. Because of their low density, coals are identified most easily with openhole density logs. A combination of other log responses may be used to infer coals if density logs are not available. Mudlogs are useful for detecting coals through cuttings analysis and associated gas shows. Drilling histories should indicate an increase in rate of penetration through the coals, which are much softer than adjacent rocks. Gas kicks also may be noted, especially in high-pressure, gassy coal seams.

Cores are a critical source of information, but conventional wells typically cut cores only in sandstone or carbonate horizons. Descriptions of these intervals can provide insights into the depositional setting of associated coal horizons, while routine core analyses can indicate whether these intervals could be an important source of supplemental gas. If coal cores have been cut in conventional wells, they are unlikely to be described or analyzed in detail. However, if the cores have been placed in a storage facility, they can be described thoroughly and characteristics such as maceral composition and rank can be determined.

Well tests in conventional wells may provide indications as to the potential for coal gas production. Coals occasionally are included in a test interval and could be the source of any reported gas production. Because coals are damaged easily by conventional drilling muds, reports of produced gas from intervals that include coals may indicate the potential for much greater rates from an undamaged or stimulated coal completion.

Coal outcrops typically are found updip from CBM prospects and are often the site of extensive mining activity. Data from these mines can be very helpful in an initial assessment of CBM prospectivity. The amount of gas released can provide an indication as to whether the coals have high gas content. In some mines, horizontal and/or vertical boreholes are drilled ahead of mining operations to help reduce gas concentrations, and this gas may be captured and sold. Mining companies are keenly interested in coal quality and regularly collect information regarding ash content, coal composition, and maturity. As part of planning for future expansion, core holes are commonly drilled downdip from the mines. Core hole drilling histories may indicate gas kicks or report the flow of water and gas to the surface. Information from these core holes can be combined with data from the active mine to make maps of coal structure, thickness, and quality. A trip to an active mine may include the opportunity to obtain coal samples for analysis or examine an active coalface. This examination can yield important clues regarding cleat spacing, cleat orientation, variations in coal quality, and relationships with other lithologies.[13]

Geologic maps of the earth’s surface exist for many coal basins. If the maps contain the coal outcrop belt, they can be used to determine the strike and dip of coal seams, identify faults or folds, and determine the relationship of coal horizons to underlying and overlying strata. Geophysical data also may exist, especially seismic data, which are very useful for estimating the depth and lateral extent of thick coal seams and recognizing faults that displace them. Remote sensing data, including aerial photos and satellite photos, can be used to delineate geomorphic patterns that may be controlled by the underlying structural geology. These patterns include linear features that may indicate faults, closely spaced linear features that could represent fracture zones, and annular drainage patterns that may indicate structural highs.[14]


  1. 1.0 1.1 Pashin, J.C. 1998. Stratigraphy and Structure of Coalbed Methane Reservoirs in the United States: An Overview. Intl. J. of Coal Geology 35 (1–4): 209–240.
  2. Choate, R. and Rightmire, C.T. 1982. Influence of the San Juan Mountain Geothermal Anomaly and Other Tertiary Igneous Events on the Coalbed Methane Potential in the Piceance, San Juan, and Raton Basins, Colorado and New Mexico. Presented at the SPE Unconventional Gas Recovery Symposium, Pittsburgh, Pennsylvania, 16-18 May 1982. SPE-10805-MS.
  3. Law, B.E., Rice, D.D., and Flores, R.M. 1991. Coalbed Gas Accumulations in the Paleocene Fort Union Formation, Powder River Basin, Wyoming. Coalbed Methane of Western North America: Rocky Mountain Assn. of Geologists Bulletin, ed. S.D. Schwochow, 179-190. Denver, Colorado: US Geological Survey.
  4. Briscoe, F.H. et al. 1988. A Study of Coalbed Methane Production Trends as Related to Geologic Features, Warrior Basin, Alabama. Coalbed Methane, San Juan Basin, Rocky Mountain Assn. of Geologists, Denver, 237–246.
  5. Davis, T.L., Benson, R.D., and Shuck, E.L. 1995. Coalbed Methane Multi-Component 3-D Reservoir Characterization Study, Cedar Hill Field, San Juan Basin, New Mexico. High-Definition Seismic Guidebook, Rocky Mountain Assn. of Geologists, 1–7.
  6. Sparks, D.P., McLendon, T.H., Saulsberry, J.L. et al. 1995. The Effects of Stress on Coalbed Reservoir Performance, Black Warrior Basin, U.S.A. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22–25 October. SPE-30734-MS.
  7. Cameron, C.C. 1970. Peat Deposits of Northeastern Pennsylvania. United States Geological Survey Bull, 1317-A, 90.
  8. 8.0 8.1 8.2 Flores, R.M. 1993. Coal-Bed and Related Depositional Environments in Methane Gas-Producing Sequences. Hydrocarbons from Coal, ed. B.E. Law and D.D. Rice, American Assn. of Petroleum Geologists Studies in Geology, Tulsa, Oklahoma, 38, 13–37.
  9. Pashin, J.C. 1991. Subsurface Models of Coal Occurrence, Oak Grove Field, Black Warrior Basin, Alabama. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 275–291.
  10. 10.0 10.1 Kaiser, W.R. 1997. Hydrogeology of Coalbed Reservoirs. Defining Coalbed Methane Exploration Fairways and Resources, ed. R. Tyler and A. R. Scott, 1997 Intl. Coalbed Methane Symposium Short Course, 253–315.
  11. Kaiser, W.R. and Jr., W.B.A. 1994. Geologic and Hydrologic Characterization of Coalbed-Methane Reservoirs in the San Juan Basin. SPE Form Eval 9 (3): 175-184. SPE-23458-PA.
  12. Tyler, R. et al. 1997. The Application of a Coalbed Methane Producibility Model in Defining Coalbed Methane Exploration Fairways and Sweet Spots: Examples from the San Juan, Sand Wash, and Piceance Basins. Bureau of Economic Geology, The University of Texas at Austin, and the Gas Research Inst., Report of Investigations No. 244, 59.
  13. Zhang, S. et al. 1997. Coal Fracture Studies of the Eastern Margin of the Ordos Basin: Guides for Coalbed Methane Exploration and Development. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 225–233.
  14. Jenkins, C.D. et al. 1997. Reservoir Characterization of the Hedong Coalbed Methane Prospect, Ordos Basin, China. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 389–408.

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See also

Coalbed methane

CBM reservoir fundamentals

CBM reservoir evaluation

CBM case studies


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