Thesis (M.S.)--West Virginia University, 2006. / Title from document title page. Document formatted into pages; contains vi, 42 p. : ill. (some col.), map (part col.). Includes abstract. Includes bibliographical references (p. 40-41).

Thesis (M.S.)--West Virginia University, 2006. / Title from document title page. Document formatted into pages; contains xii, 87 p. : ill. (some col.), col. map. Includes abstract. Includes bibliographical references (p. 48-51).

Thesis (M.S.)--West Virginia University, 2007. / Title from document title page. Document formatted into pages; contains vii, 46 p. : ill. (some col.), col. map. Includes abstract. Includes bibliographical references (p. 42-43).

The cleat permeability of coal, a key to the success of any coalbed methane (CBM) recovery operation, is a dynamic parameter impacted by changes in effective stress and desorption-induced "matrix shrinkage". Most commonly-used theoretical models developed to predict CBM production as a result of permeability changes are based on the assumption that the deformation of a depleting coalbed is limited to the vertical direction; that is, the coal is under uniaxial strain conditions. However, most laboratory studies completed to estimate the changes in coal permeability have used triaxial state of stress, thus violating the underlying principles of the models. An experimental study was, therefore, undertaken to estimate the permeability variation of coal with a decrease in pore pressure under replicated in situ conditions where flow through coal, held under uniaxial strain conditions, was measured. Three samples were tested, one from the San Juan basin and the other two from the Illinois basin. The experimental results showed that, under uniaxial strain conditions, decreasing pore pressure resulted in a significant decrease in horizontal stress and increased permeability. The permeability increased non-linearly with decreasing pore pressure, with a small increase in the high pressure range, which increased progressively as the pressure dropped below a certain value. The experimental results were used to validate two theoretical models, namely the Palmer and Mansoori and Shi and Durucan, commonly used to project permeability variation with continued production. The models failed to provide good agreement with the experimental results below 300 psi, suggesting a shortcoming in the modeling philosophy. Although the measured permeability and stress changes were in qualitative agreement with the modeling results, both models predicted negative horizontal stresses at low pore pressures for one coal type, which was not supported by experimental results. The sorption-induced strain was also found to be significantly higher in the low pore pressure range, clearly suggesting a direct relationship between the sorption-induced strain and permeability. Moreover, the increase in permeability was different for the three coal types tested, with the largest increase for the core taken from maximum depth. Finally, a gradual increase in the logarithm of permeability was measured with reduction in horizontal stress. These results suggest a distinct advantage for deeper coals, which have generated limited interest to date, primarily due to the low initial permeability. Extending the deformation of a cylindrical rock sample loaded axially, a hypothesis was developed where coal undergoes maximum deformation at the middle of its length. Using this hypothesis, permeability variation with decreasing pore pressure was estimated and the established trend was used to modify one of the existing models. The agreement between laboratory results and the modified model showed definite promise for improving permeability projection capability.

Microbial actions on coal have long been identified as a source of methane in coalbeds. Andrew Scott (1995) was the first to propose imitating the natural process of biogenic gasification, possibly leading to recharging coalbed methane (CBM) reservoirs, or setting up natural gas reservoirs in non-producing coalbeds. This study was aimed at identifying the changes in coal properties that affect gas deliverability in coal-gas reservoirs, when treated with microbial consortia to generate/enhance gas production. The experimental work tested the sorption and diffusion properties for the coal treated and, more importantly, the variation in the relevant parameters with continued bio-conversion since these are the first two phenomena in CBM production. During the first phase, single component sorption-diffusion experiments were carried out using pure methane and CO2 on virgin/baseline coals, retrieved from the Illinois basin. Coals were then treated with nutrient amended microbial consortia for different periods. Gas production was monitored at the end of thirty and sixty days of treatment, after which, sorption-diffusion experiments were repeated on treated coals, thus establishing a trend over the sixty-day period. The sorption data was characterized using Langmuir pressure and volume constants, obtained by fitting it over the Langmuir isotherm. The diffusion coefficient, D, was estimated by establishing the variation trend as a function of pore pressure. The pressure parameter was considered critical since, with continued production of methane, the produced gas diffuses into the coal matrix, where it gets adsorbed with increasing pressure. During production, the pressure decreases and the process is reversed, gas diffusing out of the coal matrix and arriving at the cleat system. The results indicated an increase in the sorption capacity of coal as a result of bioconversion. This was attributed to increased pore surface areas as a result of microbial actions. However, significant hysteresis was observed during desorption of methane and was attributed to preferential desorption from sorption sites in the pathways leading to pore cavities. This is corroborated by the increased rates of diffusion, especially for methane, which exhibited rates higher than that for CO2. This contradicted the results for untreated/baseline coal, which were in agreement with previous studies. Effort was made to explain this anomaly by the non-monotonic dependence of effective diffusion coefficient on the size of the diffusing particles, where in coalbed environments, CO2 has smaller kinetic diameter than methane.

Cleat permeability of coal is the most critical parameter affecting the amount of production from a coalbed methane (CBM) reservoir. As a result, there have been many studies about how cleat permeability changes over the life of a reservoir, leading to the development over time of several different permeability models. Most permeability models used today consider volumetric strain as an input parameter; however, permeability is impacted primarily by the increase in cleat aperture, resulting from matrix shrinkage in the horizontal direction. Recent work has shown that coal exhibits transverse isotropy, with total strain in the vertical direction being significantly higher than either horizontal direction. Hence, the inclusion of vertical strain through use of the volumetric strain parameter could be predicting inaccurate permeability variation results. The objective of this study was to determine the difference in permeability modeling with volumetric strain compared to permeability modeling with only horizontal strain, and assess the degree to which different parameters affect results from modeling using only horizontal strain. Experimental results showed that matrix strain remained consistent with transversely isotropic results of previous works. When included into the Palmer and Mansoori (P&M) permeability model, modeling results showed that permeability with horizontal strain is significantly lower than that with volumetric strain. The three unmeasured parameters in the Palmer and Mansoori permeability model have a major effect on the final results and need to be history matched in order to improve the level of accuracy in their estimation.

M.Sc. / The potential target areas for coalbed methane in South Africa are reviewed and a case study based on borehole data from the north-eastern Karoo basin was undertaken. The Early Permian coal seams of the Karoo Supergroup occur in several discrete sedimentary basins in South Africa, of which the Karoo basin is the largest. Using screening criteria based on geological, petrographical and analytical data some of the coal deposits can be excluded as potential coalbed methane producers. These include the Molteno Coalfield, large parts of the Karoo basin coal deposits and some of the Northern Province's coal deposits which are structurally disturbed. The traditional mining areas in the Free State, Witbank and Highveld coalfields are excluded from the coalbed methane study because the target seams occur at less than 200 metres below surface, too shallow for gas retention. Some of the coal seams in the Waterberg Coalfield occur at depths of several hundred metres below surface and these are unlikely to be mined by conventional means. These deep coals may be ideal coalbed methane producers. This regional overview was based on available, published data and two important parameters, permeability of coal and coalbed hydrology are unknown but important factors that will need to be taken into account in any future evaluations. The case study focused on an area close to Amersfoort that has a predicted potential for coalbed methane production. The study utilized 465 borehole descriptions from which isopach maps and geological cross-sections were constructed. Limited samples of borehole core provided lithological information from which a facies analyses was undertaken so as to establish the hydrodynamic origin of each facies types. The main lithofacies associated with the coal seams are mudstones, carbonaceous shales and fine- to coarse-grained sandstone. These data were combined with analyses from limited permeability data, petrographical data and proximate analyses for the Gus and Alfred seams. In addition to the sedimentary rocks, the role of dolerite intrusions was found to be significant as these occur as thick sills and dykes that occur below, within and above the coal seams. These may compartmentalize the seams into secondary targets within the study area. Thick sills overlying the coal zone also increase static loading and may be advantageous with respect to reducing the minimum depthbelow- surface requirements. Potential coalbed methane target areas are identified, although the entire study area is not suitable due to structural displacement of the coal seams, thinning of coal in places and devolatization caused by the dolerites.

Advanced three-dimensional reservoir modeling was used to determine the optimum strategy for coalbed methane production in China's Qinshui Basin. Multiple completion strategies were analyzed for pre-mining methane drainage on the bases of economic, environmental, and mining-safety-based factors. Effective degasification in the Qinshui Basin is crucial to enhance the health and safety of the underground mining workforce and to decrease carbon dioxide equivalent greenhouse gas emissions. Active, large-scale degasification wells in the region include hydraulically stimulated vertical fracture wells and multilaterally drilled horizontal patterns, with the latter much less common. Reservoir modeling concludes that despite their limited implementation, horizontal coalbed methane drainage wells offer the benefits of faster reservoir depressurization, high gas production rates, and faster recovery times than traditional vertical fracture wells. Coupled with reservoir modeling results, discounted cash flow analyses show that high drilling density multilateral horizontal patterns are the most financially feasible degasification strategy in the Qinshui Basin, albeit a higher initial capital investment compared to traditional vertical fracture wells and lower drilling density horizontal patterns. Additionally, horizontal wellbore designs can be altered to account for varying permeability, enhancing the productivity of methane from reservoirs exhibiting permeability values less than 1 millidarcy. Furthermore, modeling suggests that proper orientation of select horizontal wellbore patterns is crucial to optimize recoverable reserves. Finally, a function was derived to represent the production rates of horizontal coalbed methane wells as a function of time. Analysis of the function's validity to actual production data and simulated production data suggest that it is most applicable in gassy coal seams up to 10 feet in thickness. The production rate curve was transformed to an analytical model, representing a function of well geometry and coal permeability as applied to other geological conditions of the Qinshui Basin. Scientific contributions associated with this research include: An in depth study of degasification associated with the Qinshui Basin's low permeability coals; The methodology for assessing environmental, safety and economic benefits of coal degasification; The relationship between lateral spacing and permeability to maintain substantial gas production rates; An improved production model to describe the entire producing period of coalbed methane wells. / Ph. D.

During the past decade, carbon capture, utilization, and storage (CCUS) has gained considerable recognition as a viable option to mitigate carbon dioxide (CO2) emissions. This process involves capturing CO2 at emission sources such as power plants, refineries, and processing plants, and safely and permanently storing it in underground geologic formations. Many CO2 injection tests have been successfully conducted to assess the storage potential of CO2 in saline formations, oil and natural gas reservoirs, organic-rich shales, and unmineable coal reservoirs. Coal seams are an attractive reservoir for CO2 storage due to coal's large capacity to store gas within its microporous structure, as well as its ability to preferentially adsorb CO2 over naturally occurring methane resulting in enhanced coalbed methane (ECBM) recovery. A small-scale CO2 injection test was conducted in Southwest Virginia to assess the storage and ECBM recovery potential of CO2 in a coalbed methane reservoir. The goal of this test was to inject up to 20,000 tons of CO2 into a stacked coal reservoir of approximately 15-20 coal seams. Phase I of the injection test was conducted from July 2, 2015 to April 15, 2016 when a total of 10,601 tons of CO2 were injected. Phase II of the injection was conducted from December 14, 2016 to January 30, 2017 when an additional 2,662 tons of CO2 were injected, for a total of 13,263 total tons of CO2 injected. A customized monitoring, verification, and accounting (MVA) plan was created to monitor CO2 injection activities, including surface, near-surface, and subsurface technologies. As part of this MVA plan, chemical tracers were used as a tool to help track CO2 plume migration within the reservoir and determine interwell connectivity. The work presented in this dissertation will discuss the development and implementation of chemical tracers as a monitoring tool, detail wellbore-scale tests performed to characterize CO2 breakthrough and interwell connectivity, and present results from both phases of the CO2 injection test. / PHD / During the past decade, carbon capture, utilization, and storage (CCUS) has gained considerable recognition as a viable option to mitigate carbon dioxide (CO2) emissions. This process involves capturing CO2 at emission sources such as power plants, refineries, and processing plants, and safely and permanently storing it in underground geologic formations. Many CO2 injection tests have been successfully conducted to assess the storage potential of CO2 in saline formations, oil and natural gas reservoirs, organic-rich shales, and unmineable coal reservoirs. Coal seams are an attractive reservoir for CO2 storage due to coal’s large capacity to store gas within its microporous structure, as well as its ability to preferentially adsorb CO2 over naturally occurring methane resulting in enhanced coalbed methane (ECBM) recovery. A small-scale CO2 injection test was conducted in Southwest Virginia to assess the storage and ECBM recovery potential of CO2 in a coalbed methane reservoir. The goal of this test was to inject up to 20,000 tons of CO2 into a stacked coal reservoir of approximately 15-20 coal seams. Phase I of the injection test was conducted from July 2, 2015 to April 15, 2016 when a total of 10,601 tons of CO2 were injected. Phase II of the injection was conducted from December 14, 2016 to January 30, 2017 when an additional 2,662 tons of CO2 were injected, for a total of 13,263 total tons of CO2 injected. A customized monitoring, verification, and accounting (MVA) plan was created to monitor CO2 injection activities, including surface, near-surface, and subsurface technologies. As part of this MVA plan, chemical tracers were used as a tool to help track CO2 plume migration within the reservoir and determine interwell connectivity. The work presented in this dissertation will discuss the development and implementation of chemical tracers as a monitoring tool, detail wellbore-scale tests performed to characterize CO2 breakthrough and interwell connectivity, and present results from both phases of the CO2 injection test.

The increased level of greenhouse gases due to human activity is the main factor for climate change. CO2 is the main constitute among these gases. Subsurface storage of CO2 in geological systems such as coal reservoirs is considered as one of the promising perspectives. Coal can be safely and effectively utilized to both store CO2 and recover CH4. By injecting CO2 into the coal beds, methane is released with CO2 adsorption in the coal matrix and this process is known as enhanced coal bed methane recovery (ECBM). Zonguldak Coal Basin is one of the Turkey&amp / #8217 / s important coal resources. Since the coal seams in Bartin-Amasra field are found relatively deeper parts of the basin comparing to other places, this basin was not studied detailed enough yet. Bartin-Amasra basin was found convenient for enhanced coalbed methane recovery. The lithologic information taken from the Turkish Hard Coal Enterprise (TTK) was examined and the depths of the coal seams and the locations of the wells were visualized to perform a reliable correlation between seams existed in the area. According to the correlations, 63 continuous coal layers were found. A statistical reserve estimation of each coal layer for methane was made by using Monte Carlo simulation method. Uncertainty is an important parameter in risk analysis, for this reason the results were determined at probabilities of P10, P50 and P90. Enhanced coalbed methane recovery was simulated with CMG-GEM module using Coal Layer #26 which has more initial gas in place. The effects of adsorption, cleat spacing, compressibility, density, permeability, permeability anisotropy, porosity and water saturation parameters were examined in enhanced coalbed methane recovery by the simulation runs. The initial methane in place found in all these coal layers both in free and adsorbed states were estimated using probabilistic calculations resulted in possible reserve (P10) of 72.97 billion scf, probable reserve (P50) of 47.74 billion scf and proven reserves (P90) of 30.46 billion scf. Since the Amasra coal reservoir is not saturated with water, almost 10% of the total gas in place was found to be in the cleats as free gas. Coal layer #26 has an area of 4099 acres, average thickness of 6.23 ft and depth of 545 m (Karadon formation). P50 reserve estimation was 6.47 billion scf in matrix and 0.645 billion scf in fracture. Although the decrease in cleat porosity was less when shrinkage and swelling effects included, the decrease in cleat permeability as a function of porosity diminished the methane production. Cumulative methane production was enhanced with the injection of carbon dioxide (ECBM) approximately 23% than that of CBM recovery. Although closing the wells to production because of CO2 breakthrough had a negative effect on methane production initially, there was no difference between ultimate methane productions whether the wells remained open or closed, but more carbon dioxide was sequestered when the production ceased at the wells. Injected carbon dioxide amount of 5192 tonnes/year in base case was only capable to sequester only 0.3% of the yearly carbon dioxide emission of Zonguldak &Ccedil / atalagzi Power Plant nearby. Considering the gas in place capacity of the coal layer #26 as 15% of the resource area-A, it can be said that the project aiming ECBM recovery rather than carbon dioxide sequestration would be successful. In spite of water saturated coal reservoirs where the water production is required initially, it can be possible to start immediately the injection of CO2 with methane production for a dry coal reservoir. Cleat permeability being one of the most crucial parameter in the coal reservoir affected the rate of methane production. The more free gas was found in higher porosity cleat systems. Although the cumulative methane production was increased when the cleat porosity rose, methane recovery percentages were remained almost constant. The lower the cleat spacing the higher the rate of transfer between fracture and matrix was observed. The rate of gas desorption from the coal matrix and subsequent diffusion to both butt and face cleats was higher than the rate of flow in the face cleats, then production was flow-limited, pressure-driven and was defined by Darcy&amp / #8217 / s Law. The cumulative CH4 production was higher when the coal was denser. The change in coal compressibility affected slightly the cleat porosity and therefore the cleat permeability due to the change in reservoir pressure. Langmuir volume is defined as maximum adsorption capacity. Kozlu formation (deeper than Karadon formation) having lower Langmuir volume resulted in higher ultimate recovery because of lower Langmuir pressure than that of Karadon formation. In base case (Karadon formation), although the higher Langmuir volume was used, less methane production was observed. Permeability anisotropy generated the CO2-CH4 front in elliptic shape.