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CBM reservoir fundamentals

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Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for coalbed methane (CBM). A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. Understanding the reservoir differences is key to successful evaluation and operation of a CBM project.

What is Coal?

Coal is a chemically complex, combustible solid consisting of a mixture of altered plant remains. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Coals are described and classified by differences in:

  • Composition (type)
  • Purity (grade)
  • Maturity (rank)

Type refers to the variety of organic constituents. Coals are composed of macerals, which are analogous to minerals in rocks. The three main maceral groups are:

  • Vitrinite
  • Liptinite (exinite)
  • Inertinite

Vitrinite macerals form the bright bands in hand samples of coals and originate from the woody and cellulose portions of plants. Liptinite-rich coals have a waxy texture and are the product of spores, resins, and algae. Inertinite-rich coals have a dull black luster and are composed of oxidized organic matter. These differences are the basis for classifying coal types by their appearance (such as bright-banded or dull-banded) or their composition (such as humic or sapropelic). Table 1 summarizes these coal industry terms and several others for convenient reference.

Table 6.4 summarizes the characteristics and genesis of coals and their precursors.

Grade is a measure of the coal’s purity and is based on the weight percentage of organic material as determined by chemical analyses. Impure coals are referred to as ash-rich or bony. Rank represents the level of compositional maturity attained during coalification. Changes in rank are caused by increases in temperature and pressure associated with deeper burial. Mature coals, such as bituminous and anthracite coals, form at depths of thousands of meters in a process that typically requires millions of years. As coals are buried more deeply, both their carbon content and their ability to reflect incident light (vitrinite reflectance) increase. The measurement of vitrinite reflectance is the most common means to assess coal rank.

Origin of CBM reservoirs

Coal originates as an accumulation of organic matter in swamps and marshes commonly associated with fluvial systems, deltas, and marine shorelines. It is critical to submerge the accumulating organic matter quickly beneath the water table to prevent oxidation. This requires a combination of basin subsidence and a rising water table sufficient to match the accumulation rate. Organic matter accumulates at an average rate of approximately a millimeter per year and compacts by a factor of seven to 10 times as it is transformed into coal.

As organic matter is buried, it is first transformed into peat, which consists of loosely compacted masses of organic material containing more than 75% moisture. This transformation takes place mainly through the compaction and expulsion of interstitial water. Biochemical reactions associated with this process transform the organic matter into humic substances, which are the precursors of coal macerals. These reactions can also generate significant amounts of biogenic methane, which often is referred to as swamp gas. Continued compaction and dehydration transform peat into a low-quality coal called lignite, which contains 30 to 40% interstitial water.

With deeper burial, temperatures increase, and geochemical processes dominate physical processes. Lignite evolves into subbituminous coal by expelling H2O, CO, CO2, H2S, and NH3, leaving behind a structure enriched in carbon and hydrogen. At temperatures greater than approximately 220°F (104.4°C), carbon-carbon bonds begin to break, generating gas and liquid hydrocarbons that become trapped in the coals. As these bituminous coals are buried more deeply, their hydrocarbons are cracked into thermogenic methane and expelled as an order of magnitude more gas is generated than the coal is capable of storing. In a typical coal, the H/C atomic ratio decreases from 0.75 to 0.25 as coals mature from high-volatile bituminous to anthracite.

The generation and expulsion of hydrocarbons is accompanied by several profound changes in coal structure and composition.[1] Moisture content is reduced to just a few percent as water is expelled. Microporosity increases as the atomic structure of the coal changes, generating a huge surface area for sorbing methane. These changes also lower the bulk density from 1.5 g/cm3 in high-volatile bituminous coals to less than 1.3 g/cm3 in low-volatile bituminous coals. Coal strength decreases, making it easier for the coal to fracture as volatiles evolve and the coal shrinks. This creates closely spaced cleats, which enhance permeability.

At temperatures exceeding approximately 300°F, bituminous coals are changed to anthracite (> 92% carbon). Methane generation and expulsion decrease, and the bulk density increases from 1.3 g/cm3 to more than 1.8 g/cm3 as the coal structure becomes more compact. Methane contents in anthracites are typically quite high, but permeability is lower than bituminous coals because of cleat annealing. With further maturation, remaining volatiles are driven off and carbon structures coalesce, resulting in a dense coal with very high carbon content and a chemical composition similar to graphite.

To generate temperatures high enough to produce large quantities of hydrocarbons, coals must be buried deeply, typically to depths greater than 3000 m. Exceptions to this are coals transformed by local heat sources such as igneous intrusions. After sufficient burial and time to generate hydrocarbons, coals must be uplifted to shallower depths to be exploited commercially. At depths shallower than a few hundred meters, there is not enough pressure in the cleat system to hold economic quantities of sorbed gas in the coal. At depths greater than approximately 1200 m, permeabilities are generally too low to produce gas at economic rates.

Gas content

Gas contents in coal seams vary widely and are a function of coal composition, burial and uplift history, and the addition of migrated thermal or biogenic gas. Both vitrinite- and liptinite-rich coals can generate large quantities of hydrocarbons, but inertinite-rich coals, which consist of oxidized organic material, generate very little gas. The highest gas contents are found in anthracite coals, although their permeabilities are often too low to achieve commercial gas rates. High-volatile A to low-volatile bituminous coals have lower gas contents than anthracites but higher permeabilities. These bituminous coals have been the primary target of CBM exploration, primarily because coals of this rank are CBM reservoirs in the San Juan and Black Warrior basins where the modern CBM industry began.

During the 1990s, CBM reservoirs in the Uinta basin of Utah (high-volatile B) and Powder River basin of Wyoming (subbituminous B) were developed successfully despite being of lower rank than San Juan or Black Warrior coals. In the Uinta basin, gas contents have been enhanced by biogenic and migrating thermogenic gases. In the Powder River basin, the coals have low gas contents but are very thick, laterally extensive, and located close to the surface, allowing wells to be drilled and completed cheaply. These two projects have caused the industry to broaden its perspective and include lower rank coals as commercially viable targets.

Most CBM reservoirs contain both thermogenic and biogenic methane. Thermogenic methane is generated on burial, whereas biogenic methane is formed by late-stage bacteria that are introduced through groundwater flow and convert longer-chain hydrocarbons to methane. This gas augments the existing thermogenic methane and may increase gas contents significantly. Conversely, groundwater flow can reduce gas content by dissolving gas from the coal. An example of this is found in the Ferron coals located south of the Drunkard’s Wash CBM project in the Uinta basin of the western U.S. Groundwater is believed to have moved downward along the Joe’s Valley fault system, entering the coal seams at depth and pushing the gas updip where it is expelled at the outcrop.[2]

Another mechanism for decreasing gas contents is the uplift and reburial of coal seams. For example, in the Hedong basin of China, Carboniferous coal seams are located beneath Plio-Pleistocene loess, which is up to several hundred meters deep. Before the deposition of this loess, the coal seams were closer to the surface and possibly were equilibrated to a lower pressure before reburial. As a result, the gas contents could be lower than expected, unless biogenic gas or migrated thermogenic gas augmented the existing gas fraction after reburial.

Coalbeds often contain gases other than methane, including:

  • Carbon dioxide
  • Ethane
  • Hydrogen
  • Nitrogen

Coal has a greater affinity for carbon dioxide and ethane than for methane and may contain substantial quantities of these gases. Proper coal desorption and sorption isotherm work can quantify the amount of each species and generate a composite isotherm representative of the coal’s sorption character. If carbon dioxide and ethane are present in the reservoir, it is likely that the produced gas will become enriched in these components as the reservoir is depleted.

Gas saturation state

Fluid movement in a coal is controlled by diffusion in the coal matrix and by Darcy flow in the fracture (cleat) system. In most CBM reservoirs, the cleat system is filled with water at initial conditions, although, in some cases, the system also may contain some free gas. The reservoir pressure is decreased by producing water from the cleats. This causes gas to desorb from the coal matrix at the matrix/cleat interfaces, creating a methane concentration gradient across the coal matrix. Gas diffuses through the matrix and is released into the cleat system. When the gas saturation exceeds a critical value in the cleats, gas will flow to the wellbore.

The capacity of the coal matrix to store gas as a function of pressure is described by the Langmuir sorption isotherm. The gas content at a specified pressure is defined by Eq. 1, which is modified from Langmuir.[3] The Langmuir volume is the maximum volume of gas a coal can sorb onto its surface area. The Langmuir pressure is the pressure at which the storage capacity of a coal is equal to half the Langmuir volume.


where Cm = matrix gas concentration, scf/ft3; ρB = bulk density, g/cm3; VL = dry, ash-free Langmuir volume constant, scf/ton; pL = Langmuir pressure constant, psia; and p = pressure in the fracture system, psia.

In general, coal seam gas contents are less than the amount of gas a coal is capable of storing; therefore, the coals are undersaturated with gas. This phenomenon occurs because as the coals are uplifted, their temperature decreases allowing them to sorb more gas.[4] However, once the coals are uplifted above the hydrocarbon generation window, no additional gas can be generated in situ to keep the coals saturated. Gases from other sources must be introduced for the coals to remain saturated. These sources include migrated thermogenic gas from deeper in the basin or biogenic gas created by the breakdown of longer-chain hydrocarbons in the coal from the action of bacteria introduced by groundwater.

For coals that are 100% gas saturated, gas will be produced as soon as the pressure is decreased by producing water from the cleats. Gas rates will ramp up to a peak over several years and then decline. For undersaturated coals, gas will not be produced until the pressure in the cleats has been drawn down below the saturation pressure. Gas will be liberated more slowly, resulting in a longer period to achieve peak gas rates, as well as lower peak rates. There have been several cases in which companies have drilled numerous development wells based on early gas rates of a few hundred Mscf/D per well, believing that the rates would increase substantially with additional dewatering and well interference. Failure to recognize the undersaturated state of their coals and the impact of this condition left them with dozens of low-rate, marginally economic or uneconomic wells.

The parameters affecting the saturation state of the coal, such as coal rank, composition, and moisture content, may vary greatly within a CBM reservoir. To assess this variation, an isotherm should be obtained from each major coal seam. These isotherms can be used to determine the saturation state and estimate a recovery factor by comparing the expected gas content at an assumed abandonment pressure with the initial gas content at reservoir conditions. Fig. 1 shows a sorption isotherm curve that illustrates how a recovery factor is calculated. Numerical simulation can be used to estimate the impact of initial saturation conditions on production.

Coal permeability

Coal permeability is controlled primarily by two fracture sets called face cleats and butt cleats. These sets are aligned at right angles to each other (orthogonal) and are perpendicular to bedding. Face cleats are continuous while butt cleats terminate into the face cleats. Face cleats often are aligned parallel to faults and fold axes, indicating that local stresses exert control on their development. Because of the dominance of face cleats over butt cleats, a 5-spot pilot well pattern will show early interference between the center well and the two offset wells aligned parallel to the face cleat direction. An elliptical drainage area will form around each well and overlap the drainage area of the adjacent well. This will cause a greater pressure drop in these three wells than observed in the two wells aligned in the butt cleat direction. Sec. 6.8.5 discusses this phenomenon in a five-well pilot in the Hedong Coal basin of China.

Cleats are believed to form during coalification by shrinkage caused by moisture loss and by compactional folding of brittle coal beds.[5] Cleat spacing ranges from approximately 2 cm in lignites to 0.08 cm in medium-volatile bituminous coals.[6] Cleats are more closely spaced in vitrain-rich and thinner-bedded coals. Coals with high ash (> 45%) and high inertinite (> 40%) contents tend to have very poorly developed cleats.[7] In-situ cleat aperture widths vary from approximately 0.0001 to 0.1 mm and can be filled by calcite, gypsum, or pyrite minerals.[6] In addition to cleats, it is common to find shear-related fractures (joints) dipping 45 to 60° to bedding. These typically are much more widely spaced than cleats but can enhance permeability.

Laboratory testing and field observations indicate that cleat permeability decreases during initial gas production because of coal swelling as the reservoir pressure decreases. If the cleat permeabilities are very low, this swelling can effectively close the cleats. Conversely, coals will shrink as the gas desorbs, increasing permeabilities and gas rates. This phenomenon has been observed in several San Juan basin CBM wells that have been producing gas for the last 10 years. In addition, like conventional oil and gas reservoirs, CBM reservoirs exhibit changes in relative permeability as fluid saturations change during production.

Well behavior

CBM wells usually produce little or no gas initially and have moderate to high initial water rates. On a per well basis, water rates may range from a few barrels per day for low-permeability coals up to thousands of barrels per day for high-permeability coals. The wells may produce water for several months or years before producing significant volumes of gas. As the water is produced, the pressure near the wellbore is reduced, allowing gas to desorb from the coal matrix. When the gas saturation exceeds the critical value, the gas begins to flow to the wellbore. If the well pattern allows for adequate interference between wells and the coals are not connected to a strong aquifer, the water rates will decline over time to some minimum that will likely continue for the life of the well.

In general, gas rates will increase until a peak rate is achieved, although the reservoir behavior and the influence of offset wells may create a flat production profile or an early decline in gas rate. Ramp-up periods of 3 to 5 years or more are common and wells may produce near the peak rate for several years before gas rates begin to decline. It is possible, although not typical, to have high initial gas rates and relatively low water rates if the reservoir is fully gas saturated and not supported by a large, active aquifer.

Multiple wells are needed to develop a CBM reservoir. Well interference helps dewater the reservoir more quickly, and closely spaced wells achieve peak rates more quickly than widely spaced wells. Numerical simulation may be used to evaluate the effects of well spacing and well patterns on production rates and ultimate recoveries. CBM wells may have a long life compared with conventional gas wells. Numerical reservoir simulations for several basins indicate that typical CBM wells may produce 20 to 40 years at economical rates. These estimates are supported by current production trends in the San Juan basin.

Enhanced recovery

Methane recovery can be enhanced in CBM reservoirs by the injection of CO2 or nitrogen. Coal prefers carbon dioxide, and it will release methane to sorb injected CO2. This significantly increases the amount of methane available for production, but also causes the coal to swell, reducing permeability with time. Nitrogen reduces the partial pressure of methane, causing it to desorb from the coal.[8] The injected gas reduces the partial pressure of methane more rapidly than the total pressure can be reduced by dewatering, resulting in accelerated production.[9] An additional benefit of nitrogen or CO2 injection is that the methane can be desorbed while maintaining higher reservoir pressures, resulting in added energy to drive the methane to the wellbore. Both injection processes have been tested over the past decade. The largest pilot projects are Burlington Resources’ Allison pilot and BP’s Tiffany Unit pilot, which are both located in the San Juan basin. While these pilots were primarily designed to enhance methane recovery, pilots that are more recent focus on the benefits of both CO2 sequestration and enhanced methane recovery.


Cm = matrix gas concentration, scf/ft3
ρB = bulk density, g/cm3
VL = dry, ash-free Langmuir volume constant, scf/ton
pL = Langmuir pressure constant, psia
p = pressure in the fracture system, psia


  1. Levine, J.R. 1993. Coalification: The Evolution of Coal as Source Rock and Reservoir Rock for Oil and Gas. Hydrocarbons from Coal, 38, 39-78, ed. B.E. Law and D.D. Rice. American Assn. of Petroleum Geologists Studies in Geology, Tulsa.
  2. Montgomery, S.L., Tabet, D.E., and Barker, C.E. 2001. Upper Cretaceous Ferron Sandstone: Major Coalbed Methane Play in Central Utah. American Assn. of Petroleum Geologists Bulletin 85 (2): 199.
  3. Langmuir, I. 1916. The Constitution and Fundamental Properties of Solids and Liquids. J. of the American Chem. Society 38: 221.
  4. 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.
  5. Close, J.C. 1993. Natural Fractures in Coal. Hydrocarbons from Coal, 38, 119-132, ed. B.E. Law and D.D. Rice. Tulsa, Oklahoma: American Assn. of Petroleum Geologists Studies in Geology.
  6. 6.0 6.1 Law, B.E. 1993. The Relationship between Coal Rank and Cleat Spacing: Implications for the Prediction of Permeability in Coal. Proc., Intl. Coalbed Methane Symposium, Birmingham, Alabama, 435–441.
  7. Rogers, R.E. 1994. Coalbed Methane: Principles and Practice, 345. Englewood Cliffs, New Jersey: Prentice Hall.
  8. Puri, R. and Yee, D. 1990. Enhanced Coalbed Methane Recovery. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23–26 September. SPE-20732-MS.
  9. Fulton, P.F., Parente, C.A., Rogers, B.A. et al. 1980. A Laboratory Investigation of Enhanced Recovery of Methane From Coal by Carbon Dioxide Injection. Presented at the SPE Unconventional Gas Recovery Symposium, Pittsburgh, Pennsylvania, 18-21 May 1980. SPE-8930-MS.

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See also

Coalbed methane

CBM reservoir evaluation

CBM basin assessment

CBM well drilling and completion

CBM production operations

CBM case studies


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George J. Koperna, Jr.