The purpose of this study is to perform simulation studies for a specific coal bed methane reservoir. First, the theory and reservoir engineering aspects of coal bed methane reservoirs, such as dual porosity concept, permeability characteristics of CBM reservoirs and mechanism of gas storage and gas transportation in CBM reservoir have been discussed. Next, simulation results for the CBM reservoir presented. Simulation studies were carried out by using the CBM reservoir simulator, SIMED II. Injection/fall-off test pressure data were interpreted based on the pressure history matching method. The interpretation results include the determination of reservoir permeability and identification of the reservoir altered zone. Also available production histories were used to simulate the reservoir production behavior. Then the production model was used to predict the reservoir future production and to carry out sensitivity analysis on reservoir performance. For natural pressure depletion, methane recovery was increased significantly as reservoir permeability was increased. Well-bore fracturing creates a fractured zone with higher permeability. This increases methane production rate during early time of reservoir life. Reservoir matrix porosity has a significant effect on the reservoir performance. Higher production peak rate and also higher methane recovery was obtained for the reservoir with lower porosity values. Any increase in the reservoir compressibility causes greater reduction in reservoir absolute permeability as well as relative permeability to gas throughout the reservoir. Therefore, methane recovery decreased as the reservoir compressibility increased. The reservoir production behavior was strongly affected by changes in reservoir size. The production peak rate was significantly postponed and lowered as reservoir size was increased. The effect of reservoir initial pressure was investigated and the results show that higher initial reservoir pressure leads to higher production rate during early years of production. However, for the later years of reservoir life, the production profile is almost identical for different initial pressures. Coal desorption time constant affects the methane production by its own scale. In this study, the range of desorption time did not exceed longer than three days and therefore the difference in production rate was observed only in the first few days of production.

Coalbed methane reservoir (CBM) performance is controlled by a complex set of reservoir, geologic, completion and operational parameters and the inter-relationships between those parameters. Therefore in order to understand and analyze CBM prospects, it is necessary to understand the following; (1) the relative importance of each parameter, (2) how they change under different constraints, and (3) what they mean as input parameters to the simulator. CBM exhibits a number of obvious differences from conventional gas reservoirs, one of which is in its modeling. This thesis includes a sensitivity study that provides a fuller understanding of the parameters involved in coalbed methane production, how coalbed methane reservoirs are modeled and the effects of the various modeling parameters on its reservoir performance. A dual porosity coalbed methane simulator is used to model primary production from a single well coal seam, for a variety of coal properties for this work. Varying different coal properties such as desorption time ( τ), initial gas adsorbed (Vi), fracture and matrix permabilities (kf and km), fracture and matrix porosity ( φf and φm), initial fracture and matrix pressure (to enable modeling of saturated and undersaturated reservoirs), we have approximated different types of coals. As part of the work, I will also investigate the modeling parameters that affect the dual peaking behavior observed during production from coalbed methane reservoirs. Generalized correlations, for a 2-D dimensional single well model are developed. The predictive equations can be used to predict the magnitude and time of peak gas rate.

Thesis (M.S.)--West Virginia University, 2004. / Title from document title page. Document formatted into pages; contains viii, 132 p. : ill. (some col.). Includes abstract. Includes bibliographical references (p. 132).

The purpose of this study is to perform simulation studies for a specific coal bed methane reservoir. First, the theory and reservoir engineering aspects of coal bed methane reservoirs, such as dual porosity concept, permeability characteristics of CBM reservoirs and mechanism of gas storage and gas transportation in CBM reservoir have been discussed. Next, simulation results for the CBM reservoir presented. Simulation studies were carried out by using the CBM reservoir simulator, SIMED II. Injection/fall-off test pressure data were interpreted based on the pressure history matching method. The interpretation results include the determination of reservoir permeability and identification of the reservoir altered zone. Also available production histories were used to simulate the reservoir production behavior. Then the production model was used to predict the reservoir future production and to carry out sensitivity analysis on reservoir performance. For natural pressure depletion, methane recovery was increased significantly as reservoir permeability was increased. Well-bore fracturing creates a fractured zone with higher permeability. This increases methane production rate during early time of reservoir life. Reservoir matrix porosity has a significant effect on the reservoir performance. Higher production peak rate and also higher methane recovery was obtained for the reservoir with lower porosity values. Any increase in the reservoir compressibility causes greater reduction in reservoir absolute permeability as well as relative permeability to gas throughout the reservoir. Therefore, methane recovery decreased as the reservoir compressibility increased. The reservoir production behavior was strongly affected by changes in reservoir size. The production peak rate was significantly postponed and lowered as reservoir size was increased. The effect of reservoir initial pressure was investigated and the results show that higher initial reservoir pressure leads to higher production rate during early years of production. However, for the later years of reservoir life, the production profile is almost identical for different initial pressures. Coal desorption time constant affects the methane production by its own scale. In this study, the range of desorption time did not exceed longer than three days and therefore the difference in production rate was observed only in the first few days of production.

The purpose of this study is to perform simulation studies for a specific coal bed methane reservoir. First, the theory and reservoir engineering aspects of coal bed methane reservoirs, such as dual porosity concept, permeability characteristics of CBM reservoirs and mechanism of gas storage and gas transportation in CBM reservoir have been discussed. Next, simulation results for the CBM reservoir presented. Simulation studies were carried out by using the CBM reservoir simulator, SIMED II. Injection/fall-off test pressure data were interpreted based on the pressure history matching method. The interpretation results include the determination of reservoir permeability and identification of the reservoir altered zone. Also available production histories were used to simulate the reservoir production behavior. Then the production model was used to predict the reservoir future production and to carry out sensitivity analysis on reservoir performance. For natural pressure depletion, methane recovery was increased significantly as reservoir permeability was increased. Well-bore fracturing creates a fractured zone with higher permeability. This increases methane production rate during early time of reservoir life. Reservoir matrix porosity has a significant effect on the reservoir performance. Higher production peak rate and also higher methane recovery was obtained for the reservoir with lower porosity values. Any increase in the reservoir compressibility causes greater reduction in reservoir absolute permeability as well as relative permeability to gas throughout the reservoir. Therefore, methane recovery decreased as the reservoir compressibility increased. The reservoir production behavior was strongly affected by changes in reservoir size. The production peak rate was significantly postponed and lowered as reservoir size was increased. The effect of reservoir initial pressure was investigated and the results show that higher initial reservoir pressure leads to higher production rate during early years of production. However, for the later years of reservoir life, the production profile is almost identical for different initial pressures. Coal desorption time constant affects the methane production by its own scale. In this study, the range of desorption time did not exceed longer than three days and therefore the difference in production rate was observed only in the first few days of production.

Thesis (M.S.)--West Virginia University, 2005. / Title from document title page. Document formatted into pages; contains vii, 38 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 37-38).

Thesis (M.S.)--West Virginia University, 2002. / Title from document title page. Document formatted into pages; contains x, 93 p. : ill. (some col.). Vita. Includes abstract. Includes bibliographical references (p. 71-72).

Greenhouse gases such as carbon dioxide (CO2) may be to blame for a gradual rise in the average global temperature. The state of Texas emits more CO2 than any other state in the U.S., and a large fraction of emissions are from point sources such as power plants. CO2 emissions can be offset by sequestration of produced CO2 in natural reservoirs such as coal seams, which may initially contain methane. Production of coalbed methane can be enhanced through CO2 injection, providing an opportunity to offset the rather high cost of sequestration. Texas has large coal resources. Although they have been studied there is not enough information available on these coals to reliably predict coalbed methane production and CO2 sequestration potential. The goal of the work was to determine if sequestration of CO2 in low rank coals is an economically feasible option for CO2 emissions reduction. Additionally, reasonable CO2 injection and methane production rates were to be estimated, and the importance of different reservoir parameters investigated. A data set was compiled for use in simulating the injection of CO2 for enhanced coalbed methane production from Texas coals. Simulation showed that Texas coals could potentially produce commercial volumes of methane if production is enhanced by CO2 injection. The efficiency of the CO2 in sweeping the methane from the reservoir is very high, resulting in high recovery factors and CO2 storage. The simulation work also showed that certain reservoir parameters, such as Langmuir volumes for CO2 and methane, coal seam permeability, and Langmuir pressure, need to be determined more accurately. An economic model of Texas coalbed methane operations was built. Production and injection activities were consistent with simulation results. The economic model showed that CO2 sequestration for enhanced coalbed methane recovery is not commercially feasible at this time because of the extremely high cost of separating, capturing, and compressing the CO2. However, should government mandated carbon sequestration credits or a CO2 emissions tax on the order of $10/ton become a reality, CO2 sequestration projects could become economic at gas prices of $4/Mscf.

Thesis (Ph.D.)--University of Wyoming, 2009. / Title from PDF title page (viewed on May 28, 2010). Includes bibliographical references.

Cleats are natural fractures in coal that serve as permeability avenues for darcy flow of gas and water to the well bore during production. Theoretically, the development of cleat and coal-seam permeability is related to the rank, type and grade of the coal concerned. The permeability of a coal seam, moreover, may change during gas production, due to either matrix shrinkage, cleat closure or both. Matrix shrinkage and cleat closure are also affected by numerous geological factors, including coal rank, desorption character and geological setting. A method integrating geochemical and petrographic analysis, reservoir engineering diagnosis, geophysical data and production characteristics has been developed, and used to determine the initial permeability of coal seam on a metre by metre scale. This overcomes the constraint of conventional well test by refining the test intervals. The effect of coal rank, grade and type on the initial permeability of coal seams was also investigated, with the special reference to the coals of the Galilee Basin. The permeability was estimated using analytical equations based on the permeability data obtained from well tests and from cleat descriptions within the seam section. This aspect of the study showed that the coal type, rank and grade strongly influence the initial permeability of individual coal seams. Increase in ash content has negative effect on cleat development and permeability. On contrast, increasing coal rank and proportion of bright coal lead to reduction in cleat spacing and increase in permeability. Twenty three core samples collected from the Qinshui Basin in China were evaluated in the laboratory to investigate the effects of coal grade, rank and type on the change in permeability during pressure depletion. The experimental factors included the coal's geochemical properties, the permeability against changing pressure, and strain with pore pressure depletion. This part of the study fund that permeability changes with pore pressure depletion in relation to coal rank, grade and type. The strain values determined by the experiments with pressure depletion were used to identify the mechanical principles associated with changes in permeability during pressure depletion in relation to the rank, grade and type of the coal concerned. A reservoir simulation study was used to investigate the effects of desorption pressure, geological setting and coal rank on the variation in permeability under in-situ conditions during coalbed methane production, based on a study in the Hedong area, Ordos Basin, China. The simulations allowed history matching of gas and water production from 12 wells with the actual well conditions specified as the model pressure. Good agreement was achieved between the model yields and the actual production data, suggesting that the changing permeability interpreted from the simulation is a realistic representation of the in-situ reservoir properties. The reservoir simulation study found that the decreases in permeability with production exceeded the increase in permeability caused by matrix shrinkage for nearly all wells in the Hedong area. The magnitude of the decrease in permeability increases as the gap between initial pressure and desorption pressure increases. The decrease in permeability is slower in the zone closest to the fault. The reservoir simulation has demonstrated that coal rank influences significantly the change in permeability during coalbed methane production.