Coalbed methane

Coalbed methane

Coalbed methane (CBM) or Coal Bed Methane[1], coalbed gas or coal mine methane (CMM) is a form of natural gas extracted from coal beds. In recent decades it has become an important source of energy in United States, Canada, and other countries. Australia has rich deposits where it is known as coal seam gas (abbreviated "CSG"[1]).

The term refers to methane adsorbed into the solid matrix of the coal. It is called 'sweet gas' because of its lack of hydrogen sulfide. The presence of this gas is well known from its occurrence in underground coal mining, where it presents a serious safety risk. Coalbed methane, often referred to as CBM, is distinct from a typical sandstone or other conventional gas reservoir, as the methane is stored within the coal by a process called adsorption. The methane is in a near-liquid state, lining the inside of pores within the coal (called the matrix). The open fractures in the coal (called the cleats) can also contain free gas or can be saturated with water.

Unlike much natural gas from conventional reservoirs, coalbed methane contains very little heavier hydrocarbons such as propane or butane, and no natural gas condensate. It often contains up to a few percent carbon dioxide. Some coal seams, such as those in certain areas of the Illawarra Coal Measures in NSW, Australia, contain little methane, with the predominant coal seam gas being carbon dioxide.[2]


Permeability of coal bed methane reservoirs

Permeability is key factor for CBM. Coal itself is a low permeability reservoir. Almost all the permeability of a coal bed is usually considered to be due to fractures, which in coal are in the form of cleats and joints. 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 17:1. Because of this anisotropic permeability, drainage areas around coal bed methane wells are often elliptical in shape.

Intrinsic properties affecting gas production

Gas contained in coal bed methane is mainly methane and trace quantities of ethane, nitrogen, carbon dioxide and few other gases. Intrinsic properties of coal as found in nature determine the amount of gas that can be recovered.


The porosity of coal bed reservoirs is usually very small, ranging from 0.1 to 10%.

Adsorption capacity

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.

Fracture permeability

As discussed before, the fracture permeability acts as the major channel for the gas to flow. The higher the permeability, higher is the gas production. For most coal seams found in the US, the permeability lies in the range of 0.1 to 50 milliDarcies. The permeability of fractured reservoirs changes with the stress applied to them. Coal displays a stress-sensitive permeability and this process plays an important role during stimulation and production operations.

Thickness of formation and initial reservoir pressure

The thickness of the formation may not be directly proportional to the volume of gas produced in some areas.

For Example: It has been observed in the Cherokee Basin in Southeast Kansas that a well with a single zone of 1–2 ft of pay can produce excellent gas rates, whereas an alternative formation with twice the thickness can produce next to nothing. Some coal (and shale) formations may have high gas concentrations regardless of the formation's thickness, probably due to other factors of the area's geology.

The pressure difference between the well block and the sand face should be as high as possible as is the case with any producing reservoir in general.

Other properties

Other affecting parameters include coal density, initial gas phase concentration, critical gas saturation, irreducible water saturation, relative permeability to water and gas at conditions of Sw = 1.0 and Sg = 1-Swirreducible respectively.


To extract the gas, a steel-encased hole is drilled into the coal seam (100–1500 meters below ground). As the pressure within the coal seam declines due to natural production or the pumping of water from the coalbed, both gas and 'produced water' come to the surface through tubing. Then the gas is sent to a compressor station and into natural gas pipelines. The 'produced water' is either reinjected into isolated formations, released into streams, used for irrigation, or sent to evaporation ponds. The water typically contains dissolved solids such as sodium bicarbonate and chloride.

Coalbed methane wells often produce at lower gas rates than conventional reservoirs, typically peaking at near 300,000 cubic feet (8,500 m3) per day (about 0.100 m³/s), and can have large initial costs. 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. A dry CBM well is similar to a standard gas well.

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. A coal in Alabama and a coal in Colorado may have radically different Langmuir parameters, despite otherwise similar coal properties.

As production occurs from a coal reservoir, the changes in pressure are believed to 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 gas flow.

The potential of a particular coalbed as a CBM source depends on the following criteria. Cleat density/intensity: cleats are joints confined within coal sheets. They impart permeability to the coal seam. A high cleat density is required for profitable exploitation of CBM. Also important is the maceral composition: maceral is a microscopic, homogeneous, petrographic entity of a corresponding sedimentary rock. A high vitrinite composition is ideal for CBM extraction, while inertinite hampers the same.

The rank of coal has also been linked to CBM content: a vitrinite reflectance of 0.8-1.5% has been found to imply higher productivity of the coalbed.

The gas composition must be considered, because natural gas appliances are designed for gas with a heating value of about 1000 BTU (British thermal units) per cubic foot, or nearly pure methane. If the gas contains more than a few percent non-flammable gases such as nitrogen or carbon dioxide, either these will have to be removed or it will have to be blended with higher-BTU gas to achieve pipeline quality. If the methane composition of the coalbed gas is less than 92%, it may not be commercially marketable.

Environmental impacts

CBM wells are connected by a network of roads, pipelines, and compressor stations. Over time, wells may be spaced more closely in order to extract the remaining methane. Additionally, the produced water may contain undesirable concentrations of dissolved substances. Water withdrawal may depress aquifers over a large area and affect groundwater flows.[3]

In Australia, produced water is typically evaporated in large ponds due to the high salinity of the water. When these ponds fail (e.g. Chinchilla), the salinity content has destroyed contiguous soil quality and vegetation. Recently a number of gas companies have commenced operating or developing plant to treat the product water for use as domestic supply, cooling water for power stations, or discharge to streams. These plant typically use reverse osmosis to treat the product water.[citation needed]

The environmental impacts of CBM development are considered by various governmental bodies during the permitting process and operation, which provide opportunities for public comment and intervention.[4] Operators are required to obtain building permits for roads, pipelines and structures, obtain wastewater (produced water) discharge permits, and prepare Environmental Impact Statements.[5] As with other natural resource utilization activities, the application and effectiveness of environmental laws, regulation, and enforcement vary with location. Violations of applicable laws and regulations are addressed through regulatory bodies and criminal and civil judicial proceedings.

Several environmental and conservation organizations work specifically on advocating for responsible coal bed methane development. Northern Plains Resource Council has been leading this fight in Montana since 1999, and the Citizens Concerned About Coalbed Methane has worked out of Fernie, BC since 1998.


Coalbed methane reserve estimates vary; however a 1997 estimate from the U.S. Geological Survey predicts more than 700 trillion cubic feet (20 trillion cubic metres) of methane within the US. At a natural gas price of US$6.05 per million Btu (US$5.73/GJ), that volume is worth US$4.37trillion. At least 100 trillion cubic feet (2.8 trillion cubic metres) of it is economically viable to produce.[6]

In Canada, British Columbia is estimated to have approximately 90 trillion cubic feet (2.5 trillion cubic metres) of coalbed gas. Alberta, to date the only province with commercial coalbed methane wells, is estimated to have approximately 170 trillion cubic feet (4.8 trillion cubic metres) of economically recoverable coalbed methane.[7]

Recent depressed natural gas prices have made CBM less economically viable compared to the past few years.

Currently considered a non-renewable resource, there is evidence by the Alberta Research Council, Alberta Geological Survey and others showing coalbed methane is a renewable resource, because the bacterial action that formed the methane is ongoing. The assertion of being renewable, however, has itself become one of debate since it has also been shown that the dewatering that accompanies CBM production destroys the conditions needed for the bacteria to produce methane.[8] In addition, the rate of formation of additional methane is undetermined. This debate is currently causing a right of ownership issue in the Canadian province of Alberta, as only non-renewable resources can legally be owned by the province.[9]

See also


  1. ^ a b "Jargon Buster". BG Group. Retrieved 18 July 2010. 
  2. ^ "Briefing Note - Lord Mayor - Response to SRACSG - Coal Seam Methane". Retrieved 9 November 2011. 
  3. ^ Montana State University; Frequently Asked Questions; Coal Bed Methane (CBM)
  4. ^ State of Montana Department of Environment Quality; Coal Bed Methane; Federal, State, and Local Laws, Regulations, and Permits - That May Be Required
  5. ^ State of Montana Department of Environment Quality; Final Statewide Oil and Gas EIS and Proposed Amendment of the Powder River and Billings RMPs
  6. ^
  7. ^ John Squarek and Mike Dawson, Coalbed methane expands in Canada, Oil & Gas Journal, 24 July 2006, p.37-40.
  8. ^
  9. ^

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