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.

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.

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.

A better understanding of the brine-rock- supercritical CO2 interaction is needed to evaluate the risks of geologic CO2 sequestration. The geochemical effects of brine and supercritical CO2 were examined via laboratory modeling of in situ conditions on two reservoir caprocks in the Black Warrior River Basin, the Pottsville and Parkwood Formations. The clay fraction was extracted and treated at ~ 100 bar and 363 K (90 °C) over periods of up to 70 hours. Supercritical CO2 was introduced as dry ice in a pressurized vessel. Samples were observed using XRD, WD-XRF, AA, SEM, and EDS. Clay fractions contained Fe-chlorite, illite, kaolinite, and quartz. Results show the dissolution of illite, CO2-brine induced cation exchange ok K+, and the dissolution of silicate minerals. Steady-state K/Si ratios in the fluid suggest quartz re-precipitation. These interactions could adversely affect the long-term storativity of the caprock and point to a need for further study.