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Summary The current approach to carbon capture and sequestration (CCS) from pulverized-coal-fired power plants is not economically viable without either large subsidies or a very high price on carbon. Current schemes require roughly one-third of a power-plant's energy for carbon dioxide (CO2) capture and pressurization. The production of energy from geopressured aquifers has evolved as a separate, independent technology from the sequestration of CO2 in deep, saline aquifers. A game-changing new idea is described here that combines the two technologies and adds another—the dissolution of CO2 into extracted brine that is then reinjected. A systematic investigation covering a range of conditions was performed to explore the best strategy for the coupled process of CO2 sequestration and energy production. Geological models of geopressured/geothermal aquifers were developed with available data from studies of Gulf Coast aquifers. These geological models were used to perform compositional reservoir simulations of realistic processes with coupled aquifer and wellbore models.

Unconventional oil wells exhibit rapid decline in oil production rate and low ultimate oil recovery, even though the lateral drilling and completion technology have advanced drastically in the past decade. The petroleum industry has been seeking to develop economic enhanced oil recovery methods to improve the overall recovery factor. The gas huff-n-puff process has been performed and shown the potential of improving the recovery factor from tight oil reservoirs. The objective of the study was to investigate the performance of huff-n-puff EOR in Midland Basin. The studied section of the field contains 2 horizontal producers. The wells produced on primary production for 3 years. The sector was selected as a candidate for performing gas huff-n-puff to enhance the oil recovery factor. Recently, this huff-n-puff EOR project has been performing in the studied volatile oil field in the Permian Basin. In this study, compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. An Embedded Discrete Fracture Model (EDFM) was used for modeling the fractures and stimulated reservoir volume (SRV). A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. A thorough phase behavior analysis was conducted to understand the miscibility of the injected field gas and the in-situ fluid. A Bayesian Assisted History Matching (AHM) algorithm with a neural-network-proxy sampler was applied to quantify uncertainty and find the best model matches for the pair of wells in the Wolfcamp B and C formations of Midland Basin. From 1400 total simulation runs, the AHM algorithm generated 100 solutions that satisfy predefined selection criteria. Even though the primary production were the same for the two wells, the forecasts were dissimilar. It is discussed that the dissimilarity in huff-n-puff performance between two wells is caused by interwell communications. The well interference through fracture hits play an important role in the studied reservoir. The field data show the pressure communication between the two wells. Also, the injected gas was observed in the offset wells about one month after the start of injection. Several long fractures were added to the reservoir model to capture the characteristics of fracture interference. The prospects of EOR were proven decent for the wells of interest. We reported 29% and 82% incremental recovery for the P50 predictions of wells BH and CH, respectively. The results of field operation have been in agreement with the simulation forecasts after two cycles of gas injection and production.

a b s t r a c tTechnologies considered for separating CO 2 from flue gas and injecting it into saline aquifers are energy intensive, costly, and technically challenging. Production of dissolved natural gas and geothermal energy by extraction of aquifer brine has shown the potential of offsetting the cost of CO 2 capture and storage along with other technical and environmental advantages. Preliminary investigations demonstrate that the amount of produced energy by extracted methane exceeds the energy required for pressurization of CO 2 and extracted brine to be injected into the same aquifer. In case of brine temperatures of higher than 150 • C, geothermal energy from the produced hot brine can be used in amine scrubbing process to capture CO 2 from flue gas. The amount of thermal energy from hot brine exceeds the amount of energy required for amine scrubbing. In case of lower temperatures, it is suggested that the produced geothermal energy can be converted to power required for pressurization in a membrane separation process. It is estimated that the total power produced from methane and geothermal energy exceeds the power required for capture and pressurization.

First, I would like to express my profound gratitude to my academic supervisor Dr. Sepehrnoori for the continuous guidance and support during these two years of graduate school. I am truly grateful for his interest and willingness to guide me since the very first day of my graduate studies. I would also like to express sincere gratefulness to Dr. Wei Yu for his dedication, expertise advises, and insistent valuable guidance. I will always appreciate how he shared part of his extensive expertise in unconventional reservoirs, and reservoir modeling with me. Also, I would like to thank Erich Kerr and his company for supplying the field data that made this research possible. I gained great practice and understanding through their suggestions for my research work. Their invaluable support received weekly through my entire career will always be appreciated. There are not enough words to express how convinced I am that this would not have been possible without the support of my family. I thank my father Mario and my mother María for covering part of my tuition, and also my sister Carla Adriana for their continuous encouragement to pursue my dreams. I would like to thank Carolina for her caring love and support. I am indebted to my parents, my sister and my girlfriend who never stopped encouraging during both the good and the not so good times. I would also like to thank Reza, Sutthaporn, Fabio, Jorge, and Esmail for their collaboration and assertive comments for my work and my research. Finally, a very special acknowledgment is extended to the Fulbright Commission of Ecuador, the Department of State of the United States, and the Cockrell School of Engineering for being the sponsoring entities which provided me the scholarships to fund and make this accomplishment possible.

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The accumulation of condensate in fractures is one of the challenges of producing gas from gas-condensate reservoirs. When the bottomhole pressure drops below the dew point, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gas production rate. This reduction of gas productivity is in addition to the reduction due to water blocking by the fracking water. Solvents can be used to remove liquid blocks and increase gas and condensate production rates. In this paper, dimethyl ether (DME) is introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flow back after the treatment. We compare its behavior with both methanol and ethanol solvents.

The accumulation of condensate in fractures is one of the challenges of producing gas from gas/condensate reservoirs. When the bottomhole pressure drops to less than the dewpoint, condensate forms in and around fractures and causes a significant drop in the gas relative permeability, which leads to a decline in the gasproduction rate. This reduction of gas productivity is in addition to the reduction because of water blocking by the fracturing water. Solvents can be used to remove liquid blocks and increase gasand condensate-production rates. In this paper, dimethyl ether (DME) is introduced as a novel solvent for this purpose. In addition to good partitioning into condensate/gas/aqueous phases, DME has a high vapor pressure, which improves the flowback after the treatment. We compare its behavior with both methanol (MeOH) and ethanol (EtOH) solvents.