What Is CBM


Coalbed methane (CBM) – also known in Australia as coal seam gas (CSG) -- natural gas that is stored (‘adsorbed”) in deeply buried coal seams. CBM is pipeline-quality gas that requires no or minimal processing prior to sale. The presence of methane is well known from its occurrence in the coal mining industry, particularly underground mining where it can present serious safety risks. In fact, CBM production began as a technology for improving the safety and productivity of underground coal mining and preventing explosions. Not only does it provide the same service now, it also decreases emissions of greenhouse gas from coal mines and decreases air pollution because it is a clean-burning fuel.

Chemically, CBM is similar to other sources of natural gas (about 95% pure methane) and can be sold into any market. CBM is a “sweet gas” as it generally does not contain hydrogen sulfide and is considered to be more environmentally friendly than oil, coal or even conventional natural gas. CBM contains very little heavier hydrocarbons such as propane or butane, and no natural gas condensate which is often found in conventional natural gas. CBM may contain carbon dioxide, typically several percent or less.


Methane Generation

CBM is generated by the conversion of plant material to coal through burial and heating. As “coalification” progresses, increasingly dense coal is formed, in order from low to high rank: lignite, subbituminous, bituminous and anthracite. Biogenic methane (attributed to bacterial activity) is first to form, followed by thermogenic methane. Much of the methane generated by the coalification process escapes to the surface or migrates into adjacent reservoir or other rocks, but a significant volume remains trapped within the coal itself.

Methane Storage in Coal

Coal serves as both the source rock and the reservoir rock. Hydraulic pressure, rather than a pressure seal or closed structure (common for conventional oil and gas fields), is the major trapping force for CBM. Coal is extremely porous but has low permeability (connected openings).

Gas storage in coal beds is more complex than in most conventional reservoirs. Coal contains unique properties for gas storage that are not present in other reservoirs. Coalbed methane is stored in four ways:

1) as free gas within the micropores and cleats (natural fractures in the coal);

2) as dissolved gas in water within the coal;

3) as adsorbed gas held by molecular attraction on surfaces of macerals (organic constituents that comprise the coal mass), micropores, and cleats in the coal; and

4) as absorbed gas within the molecular structure of the coal molecules.

The amount of methane present within a particular volume of coal is very large. Coals at shallower depths with good cleat development contain significant amounts of free and dissolved gas while the percentage of adsorbed methane generally increases with increasing pressure (depth) and coal rank.

FACT: One gram of coal can contain as much surface area as several football fields and therefore is capable of adsorbing large quantities of methane. Depending on rank, one short ton of coal may store over 500 ft3 of methane. Source: USGS

Source: ARI

Cleats develop in the coal due to shrinking brought about by volatile loss during coalification, as well as due to tectonic stress. Primary cleats develop across coal layers and provide connections with non-coal interbeds. These cleat patterns are crucial for gas production because they allow for the release of adsorbed gas within coal beds and migration to the production well. Cleats can be destroyed by further burial in a process called healing or filled by secondary mineralization.

Calculating Methane Volume in Coal Seams

Gas-in-place (GIP) determination is relatively simple, requiring (1) the area of coal beds, (2) the thickness of the coal and carbonaceous shale, (3) average coal-bed interval density, (4) and in-situ gas content. The first three values are used to estimate coal mass in-place and can be determined from well log data and analysis of core or cuttings. The fourth parameter, in-situ gas content, varies widely and is most accurate if measured directly on fresh core. It is very important that the gas-in-place is corrected for moisture and ash content of the coals. These non-coal components adsorb negligible amounts of gas. The gas content determined from these analyses and methods can then be calculated from the coal mass to determine the GIP.

The basic volumetric formula to determine original gas in place (OGIP) volumes for CBM is

OGIP = H x (1-(a+m)) x GC x D x A


H = Completeable coal thickness GC = Gas content
a = Ash content D = Coal density
m = Moisture content A = Drillable area

Completeable coal thickness is based on the gross coal thickness, seam geometry, seam depth, faulting and intrusions. Coal ash and moisture content are taken directly from coal samples as is the coal density. The drillable area is determined by coal depths and surface geological/non geological obstructions such as lakes, rivers, parks, towns etc.

Determining Gas Content

Direct Method: actual measure of gas released from a coal sample sealed in a desorption canister is used in conjunction with other data such as coal ash and moisture content, fixed carbon, coal seam thickness and temperature.

Direct Measurements of Coal-Bed Methane Content

The direct method for measuring CBM content involves coring the coal, immediately placing the coal in a gas-tight container, and then measuring the gas evolved over time. The gas evolved, when corrected for gas lost after core drilling and before placement in canister, is a direct measurement of gas content.



Source: ARI

Indirect Method: based on empirical correlations of derived from sorption isotherm gas storage capacity data.


Source: ARI

Methods for Determining Sorption Isotherms

Sorption isotherms indicate the maximum volume of methane that a coal can store under equilibrium conditions at a given pressure and temperature. The indirect method takes advantage of core or cuttings that have been stored and does not require fresh core, thus making this method more economical. Sorption isotherms are experimentally measured using a powdered coal sample whose saturated methane content at a single temperature is measured typically at six or more pressure points (Mavor and others, 1990).

Moisture in a coal decreases the sorption capacity of a coal. Because coal loses moisture at a variable rate subsequent to removal from the bore hole, the coals must first be re-saturated with water to equilibrium moisture levels prior to measuring sorption isotherms.

The methane desorption process follows a curve (of gas content vs. reservoir pressure) called a Langmuir isotherm. The isotherm can be analytically described by a maximum gas content (at infinite pressure), and the pressure at which half that gas exists within the coal. These parameters (called the Langmuir volume and Langmuir pressure, respectively) are properties of the coal, and vary widely.

Sorption isotherm data are useful in predicting theoretical gas-production characteristics. For example, desorption of gas will not occur at pressures above the critical desorption pressure in a coal that is undersaturated with gas. The reservoir pressure must be reduced by pumping and dewatering the coal until the critical sorption pressure is reached. In a case where the coal is saturated with gas, the reservoir pressure is equal to the critical desorption pressure, and dewatering causes immediate onset of gas production.

Adsorption capacity of coal is defined as the volume of gas adsorbed per unit mass of coal usually expressed in SCF (standard cubic feet, the volume at standard pressure and temperature conditions) gas/ton of coal. The capacity to adsorb depends on the rank and quality of coal. The range is usually between 100 to 800 SCF/ton for most coal seams found in the US. Most of the gas in coal beds is in the adsorbed form. When the reservoir is put into production, water in the fracture spaces is pumped off first. This leads to a reduction of pressure enhancing desorption of gas from the matrix.

Permeability is key CBM reservoir property. Most coals have relatively low permeability but even 1 mD can provide commercial gas flow rates. Permeability in a coal bed is dominated by natural fractures (cleats), whereas the permeability of the coal matrix is negligible by comparison. Coal cleats are of two types: butt cleats and face cleats, which occur at nearly right angles. The face cleats are continuous and provide paths of higher permeability while butt cleats are discontinuous and end at face cleats. Joints are larger fractures through the coal that may cross lithological boundaries. Hence, on a small scale, fluid flow through coal bed methane reservoirs usually follows rectangular paths. The ratio of permeabilities in the face cleat direction over the butt cleat direction may range from 1:1 to over 10:1. Because of this anisotropic permeability, drainage areas around coal bed methane wells are often elliptical in shape.


To extract CBM a steel-encased hole is drilled into the coal seam, which may be 100 to 1500 meters below ground. The well is equipped with a large water pump to lower the reservoir pressure within the coal seam. Water is produced to surface up the production tubing, whereas CBM gas is produced up the annulus. Produced gas is then sent to a compressor station and sold into natural gas pipelines. Produced water is either reinjected into isolated formations, released into streams, used for irrigation, or sent to evaporation ponds.

Coalbed methane wells often produce at lower gas rates than conventional reservoirs, typically peaking at <100,000 to >500,000 ft3/day. The production profiles of CBM wells are typically characterized by a "negative decline" in which the gas production rate initially increases as the water is pumped off and gas begins to desorb and flow.

As production occurs from a coal reservoir, the changes in pressure cause changes in the porosity and permeability of the coal. This is commonly known as matrix shrinkage/swelling. As the gas is desorbed, the pressure exerted by the gas inside the pores decreases, causing them to shrink in size and restricting gas flow through the coal. As the pores shrink, the overall matrix shrinks as well, which may eventually increase the space the gas can travel through the cleats, increasing permeability and gas flow.


Source: ARI

How Is CBM Extracted

Within coal beds, methane is contained in solution and on cleat surfaces and is held in place by hydraulic pressure. To develop these unconventional gas resources, coalbed methane projects involve the dewatering of coal beds which result in the production of gas at the surface. Lowering of the hydraulic pressure by withdrawal of water from wells completed in the coal bed, allows the methane to be released and recovered. Coalbed methane projects typically cover large areas of land with producers drilling hundreds of wells. Horizontal drilling is used to reduce the impact of land access issues.

Development of coalbed methane resources generally involves five phases:

Phase I

General Exploration involving identification of coal area, characterization of coal (rank, thickness, extent, depth of coal seam, etc.), identification of suitable areas for drilling; and core drilling and testing for gas content, gas saturation and permeability of the coal.

Phase II

Geology and geophysics

Phase III

Pilot Project to determine the economic viability of a site. Project economics are determined by a number of factors: well flow rates, well spacing, cost of drilling and development, developing costs, ability to dispose of water cheaply, good land access and market access.

Phase IV

Phased Development

Phase V