Salt water is produced from the Ferron Sandstone Member of the Mancos Shale in central Utah as part of the production of coalbed methane (CBM) and is disposed of by injection predominantly into the Navajo Sandstone between 4,500 feet to 7,300 feet and is considered to be a hazardous waste. Local government agencies are concerned about the potential impacts on shallow groundwater because of this disposal method. Water samples were gathered from four shallow water-supply wells, and nine salt water disposal (SWD) wells to compare hydrochemistries as an indicator of potential mixing. Shallow water-supply wells are likely recharged by local precipitation while the source of CO2 is from atmospheric and/or soil CO2 gas and comparatively, are low in total dissolved solids. Carbonate mineral dissolution is the source of CO2 in the SWD wells and is exceptionally high in TDS. The SWD water appears to be old water and displays an evaporative signature. A geologic analysis was conducted for the Drunkards Wash gas field using 479 digital gas well logs. Three subsurface faults were identified with one fault in the north and the other two in the central part of the gas field near the eastern and western flanks. These faults were further confirmed by comparing average monthly gas and water production from the first 24 months in these faulted areas to adjacent control areas. Areas near faults reveal two to six times greater gas production than that of the associated control areas, and water production is greater by nearly an order of magnitude. This difference is likely due to the fracturing associated with the damage zone near the faults allowing for increased flow of gas and water. Due to the high injection pressures the vertical hydraulic gradient has been reversed from downward to upward. However, due to the thick sequences of shale separating the disposal aquifers and the shallow aquifers the estimated time required for the disposal waters to migrate to the surface would be at least 2,000 years. I conclude that the saline waters produced from the Ferron Sandstone are being safely sequestered in deeply buried, extensive and geologically-sealed aquifers.

Coalbeds are an extremely complicated porous medium with characteristics of heterogeneity, dual porosity and stress sensitivity. In the past decades great achievements have been made to the simulation models of pressure depletion coalbed methane (CBM) recovery process and CO2 sequestration and enhanced coalbed methane (ECBM) recovery process. However, some important mechanisms are still not or not properly included. Among them, the influence of geomechanics is probably the most important one. Because of its influence coalbed permeability, the key parameter for the success of recovery processes, changes drastically with alterations of in situ stresses and strains during these processes. In present reservoir simulators, the change of coalbed permeability is estimated with analytical models. Due to the assumptions and over simplifications analytical models have limitations or problems in application. In this research to properly estimate the changes of permeability and porosity in the simulation of CO2 sequestration and ECBM recovery process, comprehensive permeability and porosity models have been developed with minimum assumptions and simulation methods established. Firstly, a set of continuum medium porosity and permeability coupling models is built up and a simulation procedure to apply these models in reservoir and geomechanical coupled simulations proposed. Using the models and simulation procedure a sensitivity study, mainly on the parameters related to coalbed permeability change and deformation, has been made for the CBM recovery process. Then based on the understanding, a set of discontinuum medium porosity and permeability coupling models is developed and a procedure to apply these models in reservoir and geomechanical coupled simulations presented. The new models are more comprehensive and adaptable, and can accommodate a wide range of coalbeds and in situ conditions. The proposed equivalent continuum deformation model for coal mass is validated by simulating a set of lab tests including a uniaxial compression test in vacuum and a CO2 swelling test under axial constraint in the longitudinal (vertical) direction. At last the discontinuum medium porosity and permeability coupling models and the simulation procedure are successfully applied to simulate part of a series of micro-pilot tests of ECBM and CO2 sequestration at Fenn Big Valley of Alberta, Canada. / Geotechnical Eengineering

Thesis (M.S.)--University of Missouri-Columbia, 2006. / The entire dissertation/thesis text is included in the research.pdf file; the official abstract appears in the short.pdf file (which also appears in the research.pdf); a non-technical general description, or public abstract, appears in the public.pdf file. Title from title screen of research.pdf file viewed on (February 6, 2007) Includes bibliographical references.

Thesis (M.S.)--University of Wyoming, 2008. / Title from PDF title page (viewed on August 7, 2009). Includes bibliographical references (p. 77-83).

Natural gas is an important transitional energy source to replace more carbon intensive coal combustion in the face of climate change and increasing global energy demands. A significant proportion of natural gas reserves (~20%) were recently generated by microorganisms that degrade organic-rich formations (i.e. coal, shale, oil) in-situ to produce methane. Recent studies have shown that these microbial communities may be potentially stimulated to generate more methane to extend the lifetime (~10 years) of existing biogenic gas wells. This dissertation investigates how microbial coalbed methane (CBM) systems are impacted by geochemical conditions, microbial community composition, and groundwater recharge. The first study is a review and synthesis of existing basic research and commercial activities on enhancement of microbial CBM generation, and identification of key knowledge gaps that need to be addressed to advance stimulation efforts. The second study couples water and gas geochemistry with characterization of microbial communities in coalbeds in the Powder River Basin (PRB), Wyoming to investigate the influence of microbiology on water and gas geochemistry. Geochemistry results indicated that nutrients are likely source in situ from coal, and that all sulfate must be removed from the system before methanogenesis will commence. Increased archaeal (i.e. methanogens) diversity was observed with decreasing sulfate concentration, while sulfate reducing bacterial communities were different in wells with high sulfate concentrations (sulfate reducing conditions) when compared to wells with low sulfate concentrations (methanogenic conditions). The third study uses noble gases to constrain the residence time of groundwater associated with CBM in the PRB. Measured diffusional release rates of 4He from PRB coals were ~800 times greater than typical rates observed in sandstone or carbonate aquifers, and measured 4He values far exceeded expected values from in-situ decay of U and Th. Groundwater 4He residence times ranged from <1 to ~800 years using the measured diffusion rates versus ~130 to 190,000 years using a standard model. Coal waters with the longest residence time had the highest alkalinity concentrations, suggesting greater extents of microbial methanogenesis, although there was no relationship between groundwater "age" and methane concentrations or isotopic indicators of methanogenesis. Constraining the relationship between microbial activity (e.g. mechanisms of coal biodegradation and methane generation), environmental geochemical conditions, and groundwater flow is important to better understand subsurface hydrobiogeochemical processes and to ensure the success of future projects related to stimulation of microbial CBM.

No description available.

Coalbed methane (CBM) is a growing resource for "clean" natural gas and is becoming of great interest for academic research. Despite much research already be done, geochemical investigations, especially with focus on the stable carbon and hydrogen isotope composition of CBM, are rare. For this study, over 1,000 CBM samples were analyzed. The samples were collected during 10 different sample campaigns from seven different coal bearing basins worldwide. Seven sample sets were collected during desorption experiments following drilling of exploration wells and three sample sets were collected from CBM producing wells. The considered coals range in maturity from sub bituminous A (min. 0.57%Ro) to anthracite (max. 4.55%Ro), cover a wide range of different maceral compositions and were accessed in depths between 10m and 1312m beneath surface. Samples cover a production time of up to 6312 hours and a desorption time of up to 2773 hours. The geochemical analyzes were carried out using GC—IRMS. Analyzes include gas composition (methane, ethane, propane, n—butane, i—butane and carbon dioxide) and the proportions of the different gas species, as well as stable carbon isotope ratios for all gas species and stable hydrogen isotope ratios for methane. The analyzed averaged and normalized gas composition of the considered samples reveals average proportions for methane between 44.3% and 98.7%, for ethane between 0% and 9.98%, for propane between 0% and 1.15%, for n–butane between 0% and 1.09%, for i–butane between 0% and 0.003% and for carbon dioxide between 1.34% and 53.9%. The gas composition does not show conclusive trends with increasing production/desorption time. Methane stable carbon isotope ratios vary with production/desorption time. Samples from production scenarios show a general depletion in 13C for methane with increasing production time and isotope shifts between -1.6% and -35.8%0. Samples from desorption experiment scenarios show mostly enrichment in 13C for methane with increasing desorption time and isotope shifts of up to -43.4%0, but also 12C enrichment was observed in some sample sets with isotope shifts of up to +32.1%0. Overall, the magnitudes of the observed isotope shifts vary considerably between different sample sets, but also within samples from the same source. The stable carbon isotope composition of methane does not display the expected composition of methane generated from coal. This indicates the influence of secondary processes. The secondary processes mixing, adsorption, desorption and diffusion/migration cannot be separated and considered individually, because they overlap and have identical directions for compositional and isotope alteration. The significant alteration of the considered gases generated from coal has therefore to be considered as a combined effect of the mentioned secondary processes. Because of multiple complicating factors it was not possible to delineate the presence of primary and secondary microbial gas, but due to the geologic context and the retentive ability of coal the presence of these gases is reasonable to assume. Indications were found in samples for the presence of gases generated from a Kerogen Type II shale in CBM gases. The unaltered molecular and isotope composition of CBM gases is unknown. This parameter cannot be estimated, because during the physical history of a coal seam, the coal probably had experienced the loss of gas accompanied by molecular and isotope effects of unknown extent and magnitude. Based on the current knowledge and the data available from this and other studies, a classification of CBM is unreasonable and more work is required for the establishment of a stable isotope systematic for CBM, including the separate experimental evaluation of molecular and isotope effects of adsorption, desorption and diffusion/migration of gases in coal.

In 1997, Rogner published a paper containing an estimate of the natural gas in place in unconventional reservoirs for 11 world regions. Rogner's work was assessing the unconventional gas resource base, and is now considered to be very conservative. Very little is known publicly about technically recoverable unconventional gas resource potential on a global scale. Driven by a new understanding of the size of gas shale resources in the United States, we estimated original gas in place (OGIP) and technically recoverable resource (TRR) in highly uncertain unconventional gas reservoirs, worldwide. We evaluated global unconventional OGIP by (1) developing theoretical statistic relationships between conventional hydrocarbon and unconventional gas; (2) fitting these relationships to North America publically available data; and (3) applying North American theoretical statistical relationships to evaluate the volume of unconventional gas resource of the world. Estimated global unconventional OGIP ranges from 83,300 (P10) to 184,200 (P90) Tcf. To assess global TRR from unconventional gas reservoirs, we developed a computer program that we call Unconventional Gas Resource Assessment System (UGRAS). In the program, we integrated a Monte Carlo technique with an analytical reservoir simulator to estimate the original volume of gas in place and to predict production performance. We used UGRAS to evaluate the probabilistic distribution of OGIP, TRR and recovery factor (RF) for the most productive unconventional gas formations in the North America. The P50 of recovery factor for shale gas, tight sands gas and coalbed methane is 25%, 79% and 41%, respectively. Finally, we applied our global OGIP assessment and these distributions of recovery factor gained from our analyses of plays/formations in the United States to estimate global technically recoverable unconventional gas resource. Global technically recoverable unconventional gas resource is estimated from 43,000 (P10) to 112,000 (P90) Tcf.

Thesis (Ph. D.)--West Virginia University, 2008. / Title from document title page. Document formatted into pages; contains xiv, 258 p. : ill., maps. Includes abstract. Includes bibliographical references.

Thesis (Ph.D.)--University of Alberta, 2009. / Title from PDF file main screen (viewed on Apr. 1, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Doctor of Philosophy in Geotechnical Engineering, [Department of] Civil and Environmental Engineering, University of Alberta. Includes bibliographical references.