Coalbed methane reservoirs are considered as a dual-porosity reservoirs. Dual porosity reservoirs are reservoirs in which porosity related to cleats (natural fractures) are responsible for flow behavior and reservoir porosity of the matrix is responsible for the storage of gas. The porosity of a coalbed methane reservoir can vary from 10%-20%; However, the cleat porosity of the reservoir is estimated to be in the range of 0.1%-1% 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 and 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 Fracture permeability acts as the major channel for the gas to flow. The higher the permeability, the higher the gas production. For most coal seams found in the US, the permeability lies in the range of 0.1–50 milliDarcys. 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. Fracture permeability in Coalbed methane reservoir tends to increase with depletion of gas; in contrast to conventional reservoirs. This unique behavior is because of shrinking of coal, when methane is released from its matrix, which results in opening up of fractures and increased permeability. It is also believed that due to shrinkage of coal matrix at lower reservoir pressures, there is a loss of horizontal stress in the reservoir which induces in-situ failure of coal. Such a failure has been attributed to sudden decrease in the fracture permeability of the reservoir 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 of pay can produce excellent gas rates, whereas an alternative formation with twice the thickness can produce next