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Coalbed methane (CBM or Coal Bed Methane), 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").
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 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.
The first permit for a coalbed methane well in Alabama was issued in May 1980. Gustavson Associates, a Colorado based geological consultant firm had been selected by the American Public Gas Association to conduct coalbed degasification tests as well as Devonian shale tests across the United States. Pleasant Grove, Alabama was chosen to test commercial drilling of coalbed methane.
In a time of rising gas prices, American Public Gas Association under a U. S. Department of Energy grant first funded this three-well research program to produce coalbed methane at Pleasant Grove, Alabama. This program is the first aimed at commercial recovery of gas rather than mine degasification. It is also the first attempt to produce from more than one coal seam in the same wellbore.
The coalbed methane wells were drilled on the lawn of the Pleasant Grove court house. The gas was of sufficient quality to be ducted into the kitchens of domestic users after minor processing including odorization as a safety measure.
The Pleasant Grove Field, which was established in July of the same year at a ceremony attended by U.S. Senators, Congressmen and officials of the Administration, was Alabama's first coal degasification field. Later, John Gustavson, a Boulder geologist testified on the results in front of the State Oil and Gas Board of Alabama, who in 1983 established the nation's first comprehensive rules and regulations governing the drilling for and production of coalbed methane gas resources. These rules have served as a model for other states. 
 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.
 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.
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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 but varies depending on the formation geology.
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. Depending on aquifer connectivity, water withdrawal may depress aquifers over a large area and affect groundwater flows.
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. Operators are required to obtain building permits for roads, pipelines and structures, obtain wastewater (produced water) discharge permits, and prepare Environmental Impact Statements. 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.
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.
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.
Recent depressed natural gas prices have made CBM less economically viable compared to the past few years.
Currently[when?] it is 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. 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.
Production forecasting of CBM wells and fields can be performed using specialised Material Balance tools or Numerical simulators, as it requires an explicit coupling of the matrix gas diffusion process with the flow within fractures (Darcy law applies).
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