The variation in the cleat permeability of coalbed methane (CBM) reservoirs is attributed primarily to two cardinal processes, with opposing effects. Increase in effective stresses with reduction in pore pressure tends to decrease the cleat permeability, whereas the sorption-induced coal matrix shrinkage actuates reduction in the effective stresses which increases the reservoir permeability. The net effect of the two processes determines the pressure-dependent-permeability and, hence, the overall trend of CBM production with depletion. Several analytical models have been developed and used to predict the dynamic behavior of CBM reservoir permeability during production through pressure depletion, all based on combining the two effects. The purpose of this study was to introduce modifications to two most commonly used permeability models, namely the Palmer and Mansoori, and Shi and Durucan, for permeability variation and evaluate their performance when projecting gas production. The basis for the modification is the linear relationship between the volume of sorbed gas and the associated matrix shrinkage. Hence, the impact of matrix shrinkage is incorporated as a function of the amount of gas produced, or that remaining in coal, at any time during production. Since the exact production from a reservoir is known throughout its life, this significantly simplifies the process of permeability modeling. Furthermore, the modification is also expected to streamline the process of modeling by classifying the shrinkage parameters for coals of different regions, but with similar characteristics. A good analogy is the San Juan basin, where sorption characteristics of coal are so well understood and defined that operators no longer carry out laboratory sorption work. The goal is to achieve the same for incorporation of the matrix shrinkage behavior. Another modification is to incorporate the matrix, or grain, compressibility effect of coal as a correction factor in the Shi and Durucan model so as to assess the permeability variation based on the true shrinkage of coal matrix with reservoir drawdown. Finally, application of the modified models may be carried out for scenarios where the gas content of coal varies with time, either due to injection of a second gas to enhance the recovery of methane, or gas enhancing techniques, such as, bio-stimulation of coal. The original models are currently unable to handle this, particularly when the gas content of the reservoir increases. The research is aimed at simplifying and, in fact, improving the performance of the theoretical models in predicting the variation of coal reservoir permeability.

>Magister Scientiae - MSc / The Kalahari Karoo Basin is one of several basins in southern Africa filled with Late Carboniferous to Jurassic sediments that are primary targets for Permian aged coal. In order to determine the Coalbed Methane (CBM) potential of the Central Kalahari Karoo Basin, 9 exploration boreholes were drilled. Vitrinite reflectance (%Ro) and proximate analysis were conducted on cored coal intervals. Passey’s ΔLogR method used in this thesis employs the use of resistivity and porosity logs to identify and quantify total organic carbon (%TOC) in potential source rocks. Compared with lab measured %Fixed Carbon, the results showed that Passey’s ΔLogR method effectively identifies coal intervals as organic enriched. In terms of %TOC calculations, the method works poorly in coal metamorphosed by dolerite intrusions. These heat affected coal samples display %Ro from 0.77% to 5.53% and were increased in rank from primarily sub-bituminous to higher ranking volatile bituminous and finally to anthracitic coal. Their higher level of organic metamorphism (LOM), accompanying compositional changes and increased density associated with accelerated coal rank seem to have hindered the method in its estimations or lack thereof. Compositional changes in the coal were controlled by proximity to sill intrusion, with a decrease in fixed carbon and volatile matter, and increases in ash and moisture in the contact metamorphism zone (2-12m from sill). In heat unaltered coal that has undergone normal burial maturation characterized by %Ro of 0.44% to 0.65%, the method works very well even attaining accuracy in some samples. In unintruded boreholes CH1 and CH6, correlations between fixed carbon and generated %TOC curves indicate strong relationships with R2 from 0.70 to 0.83. Therefore, it was found that Passey’s ΔLogR method can be applied effectively on coal that has undergone normal burial maturation only.

Studies completed recently have shown that desorption of methane results in a change in the matrix volume of coal thus altering the permeability of, and production rates from, coalbed methane (CBM) reservoirs. An accurate estimation of different coal compressibilities is, therefore, critical in CBM operations in order to model and project gas production rates. Furthermore, a comprehensive knowledge of the dynamic permeability helps in understanding the unique feature of CBM production, an initial negative gas decline rate. In this study, different coal compressibility models were developed based on the assumption that the deformation of a depleting coalbed is limited to the vertical direction, that is, the reservoir is under uniaxial strain conditions. Simultaneously, experimental work was carried out replicating these conditions. The results showed that the matrix volumetric strain typically follows the Langmuir-type relationship. The agreement between the experimental results and those obtained using the proposed model was good. The proposed volumetric strain model successfully isolated the sorption-induced strain from the strain resulting from mechanical compression. It, therefore, provides a technique to integrate the sorption-induced strain alone into different analytical permeability models. The permeability variation of coal with a decrease in pore pressure under replicated in situ stress/strain conditions was measured. The results showed that 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, increasing progressively as the pressure dropped below a certain value. The experimental results were also used to test the proposed coupled sorption-induced strain model and several analytical permeability models. One of the commonly used models overestimated the permeability increase between 200 and 900 psi. The other two models were able to predict the permeability trend with constant cleat compressibility although the values used for the two models were different. Finally, the coupled strain and permeability models were employed to validate the field observed permeability increase data. The results indicated that the coupled models can predict the permeability trend with accuracy as long as the input parameters used are reasonable. The technique can thus serve as a particularly powerful tool for new CBM regions with limited production data since it only requires the basic adsorption data and mechanical properties and both are typically available. However, the physical meaning of the cleat compressibility term used in the permeability models needs to be clarified to ensure that its effect is not counted twice.

No description available.

Geologic sequestration of CO2 into unmineable coal seams is proposed as a way to mitigate the greenhouse gas effect and potentially contribute to economic prosperity through enhanced methane recovery. In 2009, the Virginia Center for Coal and Energy Research (VCCER) injected 907 tonnes of CO2 into one vertical coalbed methane well for one month in Russell County, Virginia (VA). The main objective of the test was to assess storage potential of coal seams and to investigate the potential of enhanced gas recovery. In 2014, a larger scale test is planned where 20,000 tonnes of CO2 will be injected into three vertical coalbed methane wells over a period of a year in Buchanan County, VA. During primary coalbed methane production and enhanced production through CO2 injection, a series of complex physical and mechanical phenomena occur. The ability to represent the behavior of a coalbed reservoir as accurately as possible via computer simulations yields insight into the processes taking place and is an indispensable tool for the decision process of future operations. More specifically, the economic viability of projects can be assessed by predicting production: well performance can be maximized, drilling patterns can be optimized and, most importantly, associated risks with operations can be accounted for and possibly avoided. However, developing representative computer models and successfully simulating reservoir production and injection regimes is challenging. A large number of input parameters are required, many of which are uncertain even if they are determined experimentally or via in-situ measurements. Such parameters include, but are not limited to, seam geometry, formation properties, production constraints, etc. Modeling of production and injection in multi-seam formations for hydraulically fractured wells is a recent development in coalbed methane/enhanced coalbed methane (CBM/ECBM) reservoir modeling, where models become even more complex and demanding. In such cases model simulation times become important. The development of accurate simulation models that correctly account for the behavior of coalbeds in primary and enhanced production is a process that requires attention to detail, data validation, and model verification. A number of simplifying assumptions are necessary to run these models, where the user should be able to balance accuracy with computational time. In this thesis, pre- and post-injection simulations for the site in Russell County, VA, and preliminary reservoir simulations for the Buchanan County, VA, site are performed. The concepts of multi-well, multi-seam, explicitly modeled hydraulic fractures and skin factors are incorporated with field results to provide accurate modeling predictions. / Ph. D.

Methane, the natural by product of the coalification process, is held within coal beds under pressure. It is recognized that most of the methane present in coal occurs in the adsorbed state. The amount of methane present depends mainly on the pressure, temperature, adsorptive capacity and moisture content of the coal. Permeability, porosity, degree of fracturing of the coal and adjacent rocks and distance from the outcrop may also affect the methane content of a coal bed. The methane content of coal seams can be estimated by the direct, indirect and the estimation methods. The first two methods require drinking of holes and taking samples, whereas, the third method estimates the methane content from a predetermined relationship involving the physical and chemical characteristics of coal. In this study, since no samples are to be taken and evaluation is to be based on existing data, to be estimation method has been chosen to determine the methane content in the basin. The coal resources have been estimated from the data and applied to the methane content determined, to arrive at the methane resources. The results indicate that there may be 2 to 4 billion tons of coal in the basin and about 700 billion cubic feet of methane may be held within it. / Master of Science

Most of the coal properties depend on carbon content and vitrinite reflectance, which are rank dependent parameters. In this study, a new approach was followed by constructing a simulation input database with rank-dependent coal properties published in the literature which are namely cleat spacing, coal porosity, density, and parameters related to strength of coal, shrinkage, swelling, and sorption. Simulations related to enhanced coalbed methane (ECBM) recovery, which is the displacement of adsorbed CH4 in coal matrix with CO2 or CO2/N2 gas injection, were run with respect to different coal properties, operational parameters, shrinkage and swelling effects by using a compositional reservoir simulator of CMG (Computer Modeling Group) /GEM module. Sorption-controlled behavior of coalbeds and interaction of coal media with injected gas mixture, which is called shrinkage and swelling, alter the coal properties controlling gas flow with respect to injection time. Multicomponent shrinkage and swelling effects were modeled with extended Palmer and Mansoori equation. In conclusion, medium-volatile bituminous coal rank, dry coal reservoir type, inverted 5-spot pattern, 100 acre drainage area, cleat permeability from 10 to 25 md, CO2/N2 molar composition between 50/50 % and 75/25 %, and drilling horizontal wells rather than vertical ones are better selections for ECBM recovery. In addition, low-rank coals and dry coal reservoirs are affected more negatively by shrinkage and swelling. Mixing CO2 with N2 prior to its injection leads to a reduction in swelling effect. It has been understood that elastic modulus is the most important parameter controlling shrinkage and swelling with a sensitivity analysis.

This thesis explores the concept of displacement of sorbed methane and enhancement of methane recovery by injection of CO2 into coal, while sequestering CO2. The objective of this study was to investigate the diffusion behavior of San Juan Basin coal under single and competitive gas environments. The movement of gas in a coalbed reservoir starts in the coal matrix with diffusion towards the naturally occurring cleat network surrounding the matrix blocks. The gas production potential from coalbed reservoirs under different gas environments was, therefore, estimated by studying the diffusion behavior of the coal type. The results clearly showed that the rate of diffusion increases with decreasing reservoir pressure, the increase being exponential at low/very low pressure. As a final step, a simulation study was carried out using the experimental results to predict long-term gas production from coalbed reservoirs with and without CO2 injection. This was followed by a preliminary economic analysis in order to estimate the feasibility of enhanced recovery method by CO2 injection by calculating the net present value of a project with and without carbon credits. The results showed that it is possible to obtain significant improvement in methane recovery by CO2 injection. However, it becomes economically feasible only with carbon credits.

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.

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.