Dissertations / Theses: 'Geologic storage'

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Okwen, Roland Tenjoh. "Enhanced CO2 Storage in Confined Geologic Formations." Scholar Commons, 2009. http://scholarcommons.usf.edu/etd/3683.

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Many geoscientists endorse Carbon Capture and Storage (CCS) as a potential strategy for mitigating emissions of greenhouse gases. Deep saline aquifers have been reported to have larger CO 2 storage capacity than other formation types because of their availability worldwide and less competitive usage. This work proposes an analytical model for screening potential CO 2 storage sites and investigates injection strategies that can be employed to enhance CO 2 storage. The analytical model provides of estimates CO 2 storage efficiency, formation pressure profiles, and CO 2 –brine interface location. The results from the analytical model were compared to those from a sophisticated and reliable numerical model (TOUGH 2 ). The models showed excellent agreement when input conditions applied in both were similar. Results from sensitivity studies indicate that the agreement between the analytical model and TOUGH2 strongly depends on irreducible brine saturation, gravity and on the relationship between relative permeability and brine saturation. A series of numerical experiments have been conducted to study the pros and cons of different injection strategies for CO 2 storage in confined saline aquifers. Vertical, horizontal, and joint vertical and horizontal injection wells were considered. Simulations results show that horizontal wells could be utilized to improve CO 2 storage capacity and efficiency in confined aquifers under pressure-limited conditions with relative permeability ratios greater than or equal to 0:01. In addition, joint wells are more efficient than single vertical wells and less efficient than single horizontal wells for CO 2 storage in anisotropic aquifers.

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Szulczewski, Michael Lawrence. "The subsurface fluid mechanics of geologic carbon dioxide storage." Thesis, Massachusetts Institute of Technology, 2013. http://hdl.handle.net/1721.1/82834.

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Thesis (Ph. D.)--Massachusetts Institute of Technology, Department of Civil and Environmental Engineering, 2013. Cataloged from PDF version of thesis. Includes bibliographical references (pages 157-168). In carbon capture and storage (CCS), CO₂ is captured at power plants and then injected into deep geologic reservoirs for long-term storage. While CCS may be critical for the continued use of fossil fuels in a carbon-constrained world, the subsurface behavior of CO₂ remains poorly understood, which has contributed to the absence of government policy to implement CCS. In this Thesis, we use simulations, experiments, and theory to clarify the fluid mechanics of CO₂ storage, with the goal of informing two practical questions. The first question is, how much CO₂ can be stored in the United States? This question is important to clarify the role of CCS among the portfolio of other climate-change mitigation options, such as renewable energy and reduced energy consumption. To address this question, we develop models of CO₂ injection and the post-injection migration, and apply them to several reservoirs in the US. We use the models to calculate the total amount of CO₂ that can be stored in these reservoirs without hydraulically fracturing the caprock or allowing the CO₂ to migrate to a major leakage pathway. We find that the US has sufficient storage capacity to stabilize emissions at the current rates for at least 100 years. The second question is, what are the long-term dissolution rates of CO₂ into the ambient groundwater? This question is important because dissolution mitigates the risk of CO₂ leakage to shallower formations or the surface. We address this question for storage in structural and stratigraphic traps, which are promising locations in a reservoir for injection and will likely be the first sites of large-scale CCS deployment. We describe several mechanisms of CO₂ dissolution in these traps and develop models to predict the dissolution rates. We apply the models to relevant subsurface conditions and find that dissolution rates vary widely depending on the reservoir properties, but that thick reservoirs with high permeabilities could potentially dissolve hundreds of megatons of CO₂ in tens of years. by Michael Lawrence Szulczewski. Ph.D.

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Steele-MacInnis, Matthew. "Thermodynamics of geologic fluids." Diss., Virginia Tech, 2013. http://hdl.handle.net/10919/22026.

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Fluids play a vital role in essentially all geologic environments and processes, and are the principal media of heat and mass transfer in the Earth. The properties of geologic fluids can be diverse, as fluids occur at conditions ranging from ambient temperatures and pressures at Earth's surface, to extreme temperatures and pressures in Earth's deep interior. Regardless the wide ranges of conditions at which geologic fluids occur, fluid properties are described and governed by the same fundamental thermodynamic relationships. Thus, application of thermodynamic principles and methods allows us to decipher the properties and roles of geologic fluids, to help understand geologic processes. Fluid inclusions in minerals provide one of the best available tools to study the compositions of geological fluids. Compositions of fluid inclusions can be determined from microthermometric measurements, based on the vapor-saturated liquidus conditions of model chemical systems, or by various microanalytical techniques. The vaporsaturated liquidus relations of the system H2O-NaCl-CaCl2 have been modeled to allow estimation of fluid inclusion compositions by either microthermometric or microanalytical methods. Carbon capture and storage (CCS) in deep saline formations represents one option for reducing anthropogenic CO2 emissions into Earth's atmosphere. Availability of storage volume in deep saline formations is a significant component of injection and storage planning. Investigation of the volumetric properties of CO2, brine and CO2-saturated brine reveals that storage volume requirements are minimized when CO2 dissolves into brine. These results suggest that a protocol involving brine extraction, CO2 dissolution and re-injection may optimize CCS in deep saline formations. Numerical modeling of quartz dissolution and precipitation in a sub-seafloor hydrothermal system was used to understand the role of fluid-phase immiscibility ("boiling") on quartz-fluid interactions, and to predict where in the system quartz could deposit and trap fluid inclusions. The spatial distribution of zones of quartz dissolution and precipitation is complex, owing to the many inter-related factors controlling quartz solubility. Immiscibility exerts a strong control over the occurrence of quartz precipitation in the deeper regions of fluid circulation. Ph. D.

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Parthasarathy, Hariprasad. "Arsenic Dissolution from Sedimentary Formations under Geologic Carbon Dioxide Storage Conditions." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/488.

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The overall goal of this Ph.D. study was to investigate the mobilization of arsenic (As) from sedimentary formations under conditions representative of geologic carbon dioxide storage (GCS) i.e., high pressure, temperature, and salinity. GCS is a promising technology for the mitigation of increasing CO2 emissions in the atmosphere. It primarily involves the capture of CO2 from point sources, followed by transport and injection into deep subsurface formations for long-term storage. Of the potential subsurface formations under consideration in the United States, saline formations, characterized by the presence of high salinity brines, are estimated to have the largest storage capacity. Potential for leakage of injected CO2, native brines, and CO2- saturated brines from these reservoirs exists and may lead to an increase in mineral dissolution from reservoir formations, and leakage pathways. Of particular interest in the risk assessment of GCS is the dissolution and mobilization of toxic metals such as arsenic (As) and lead. The primary mineral source of As in high and low permeability sedimentary formations is arsenopyrite (FeAsS (s)). While the oxidative dissolution of FeAsS (s) has been reported in the literature, the dissolution of FeAsS (s) under anoxic, high salinity conditions of GCS remains unexplored. To conduct dissolution experiments at high pressure, temperature, and salinity, a small-scale plug-flow system capable of measuring dissolution rates without mass transfer limitations was designed and constructed. The capacity of the system in measuring dissolution rates under GCS conditions was validated. The plug-flow system is capable of accurate and rapid measurement of dissolution rates for minerals with slow and moderate dissolution rates, with a maximum rate limitation of 5 x10-5 mol/m2s at a flow rate of 10 ml/min. To enable accurate determination of reaction rates, a method for preparation of uniformly sized arsenopyrite particles free of surface oxides was developed. The method involves sonication of crushed minerals with ethanol, washing with 12N HCl, and 50% ethanol, followed by drying in N2. Analysis of the arsenopyrite surface with X-ray photoelectron spectroscopy revelealed that the method was successful in removing all the oxides of As and S on the surface, while only 12% of Fe was left oxidized. Subsequently, the dissolution of arsenopyrite, galena, and pyrite in low-concentration alkali and alkaline metal chloride solutions under anoxic conditions was investigated. Further, the effect of Na-Ca-Cl brines on the release of arsenic was determined under ambient as well as GCS conditions. The result of these experiments revealed that electrolytes traditionally considered inert, such as NaCl, CaCl2, and MgCl2 are capable of effecting sulfide mineral dissolution. In particular, the dissolution of As increased with increasing cation activity, and the dissolution of sulfur decreased with an increase in chloride ion activity in solution. Dissolution experiments with 1.5M Na-Ca-Cl brines resulted in arsenic dissolution rates in the range of 10-10 to 10-11 mol/m2 s under anoxic conditions. The rate of As release was found to be dependent on the CaCl2 content of these Na-Ca-Cl brines. Upon the introduction of CO2 into the system, the dissolution rate of As decreased and was determined to be in the range of 10-11 to 10-12 mol/m2s. For comparison, the rate of As release from arsenopyrite under oxic conditions is in the range of X to Y mol/m2 s. Finally, dissolution experiments aimed at understanding the release of As from naturally occurring seal rocks of a GCS formation were conducted. A primary seal rock and two secondary seal rocks were obtained from the Cranfield oil field CO2- EOR site in Mississippi. The rock samples were characterized by micro Xray adsorption near edge structure analysis, which revealed that multiple sources of As exist in the reservoir seal rocks studied. Dissolution experiments with seal rocks and anoxic brines of 105g/L NaCl resulted in the dissolution of arsenic in concentrations of 70 to 80 ppb at steady state. Dissolution of CO2 in the brine had no discernible effect on the steady state release concentration of As.

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Singleton, Gregory R. (Gregory Randall). "Geologic Storage of carbon dioxide : risk analyses and implications for public acceptance." Thesis, Massachusetts Institute of Technology, 2007. http://hdl.handle.net/1721.1/40378.

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Thesis (S.M.)--Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program; and, (S.M.)--Massachusetts Institute of Technology, Dept. of Political Science, 2007. Includes bibliographical references (p. 99-103). Carbon Capture and Storage (CCS) technology has the potential to enable large reductions in global greenhouse gas emissions, but one of the unanswered questions about CCS is whether it will be accepted by the public. In the past, construction of large facilities such as nuclear power plants has been prevented or delayed by public opposition, and CCS proponents would like to know whether it will provoke similar public opposition. Since the Geologic Storage (GS) component of the CCS architecture has not been widely deployed, this thesis explores the characteristics of GS and how they might affect public perception and acceptance of the larger CCS architecture. To provide insight regarding public acceptance of CCS, this thesis addresses two questions; first asking how GS is likely to be perceived by the public and what can be done to improve that perception, and second asking whether financial compensation can be used to improve public acceptance of energy facilities. To address the first question about the public perception of GS, this thesis begins with a discussion of risk concepts and how it is used differently by experts, who use a realist perspective, and the general public, who use a social constructivist perspective. (cont.) After discussing how this difference in perspective leads to risk disputes, this thesis presents an overview of the risk elements of GS. It then reviews existing risk assessments of GS and qualitatively evaluates the risks of GS in terms of their likelihood, impact, and uncertainty. The discussion on risk assessment perspectives and methods is then integrated with the GS risk review to forecast whether GS is likely to be accepted by the public. By using a public perspective to compare GS to existing energy technologies, this thesis concludes that the risks of GS are likely to eventually be considered no worse than existing fossil fuel energy technologies. However, since GS is a new technology with little public awareness, additional demonstrations and field tests will be necessary to make this case to the public. To address the question of whether financial compensation can be used to improve public acceptance of energy facilities, this thesis presents analyses of data from a public opinion poll on compensation and facility siting. Survey respondents were asked whether they would accept the construction of a natural gas pipeline, nuclear power plant, or coal fired power plant near their home if they were given annual payments of $100. (cont.) The compensation offers had little net effect on the public's willingness to accept the facilities, and the survey results do not support the use of compensation to improve public acceptance of energy facilities. By investigating public risk perception and GS risk assessments, this thesis concludes that 1) full-scale demonstrations of GS will be needed to convince the public that the technology is safe and 2) that financial compensation is ineffective for improving public opinion. by Gregory R. Singleton. S.M.

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Popova, Olga. "Development of Geostatistical Models to Estimate CO2 Storage Resource in Sedimentary Geologic Formations." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/485.

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Carbon capture and sequestration (CCS) is a technology that provides a near-term solution to reduce anthropogenic CO2 emissions to the atmosphere and reduce our impact on the climate system. Assessments of carbon sequestration resources that have been made for North America using existing methodologies likely underestimate uncertainty and variability in the reservoir parameters. This thesis describes a geostatistical model developed to estimate the CO2 storage resource in sedimentary formations. The proposed stochastic model accounts for the spatial distribution of reservoir properties and is implemented to a case study of the Oriskany Formation of the Appalachian sedimentary basin. The developed model allows for estimation of the CO2 sequestration resource of a storage formation with subsequent uncertainty analysis. Since the model is flexible with respect to changing input parameters and assumptions it can be parameterized to calculate the CO2 storage resource of any porous subsurface unit. The thesis continues with evaluation of the cost of CO2 injection and storage for the Oriskany Formation utilizing storage resource estimates generated by our geostatistical model. Our results indicate that the cost of sequestering CO2 has significant spatial variation due to heterogeneity of formation properties and site geology. We identify the low-cost areas within the Oriskany footprint. In general, these areas correspond to the deepest portions of the Appalachian basin and could be considered as potential CO2 injection sites for CCS industrial scale projects. Overall, we conclude that significant improvement can be made by integrating basin geology and spatial heterogeneity of formation petrophysical properties into CCS cost assessments, and that should be a focus of future research efforts. This will allow for more accurate cost estimates for the entire CCS system and identify areas of sedimentary basins with optimal conditions for CO2 injection and storage. To mitigate the effects of climate change, the U.S. will need a widespread deployment of low-carbon electricity generating technologies including natural gas and coal with CCS. More precise CO2 storage resource and CCS cost estimates will provide better recommendations for government and industry leaders and inform their decisions on what greenhouse gas mitigation measures are the best fit for their regions.

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Roberts-Ashby, Tina. "Evaluation of Deep Geologic Units in Florida for Potential Use in Carbon Dioxide Sequestration." Scholar Commons, 2010. http://scholarcommons.usf.edu/etd/3601.

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Concerns about elevated atmospheric carbon dioxide (CO 2 ) and the effect on global climate have created proposals for the reduction of carbon emissions from large stationary sources, such as power plants. Carbon dioxide capture and sequestration (CCS) in deep geologic units is being considered by Florida electric-utilities. Carbon dioxide-enhanced oil recovery (CO 2 -EOR) is a form of CCS that could offset some of the costs associated with geologic sequestration. Two potential reservoirs for geologic sequestration were evaluated in south-central and southern Florida: the Paleocene Cedar Keys Formation/Upper Cretaceous Lawson Formation (CKLIZ) and the Lower Cretaceous Sunniland Formation along the Sunniland Trend (Trend). The Trend is a slightly arcuate band in southwest Florida that is about 233 kilometers long and 32 kilometers wide, and contains oil plays within the Sunniland Formation at depths starting around 3,414 meters below land surface, which are confined to mound-like structures made of coarse fossil fragments, mostly rudistids. The Trend commercial oil fields of the South Florida Basin have an average porosity of 16% within the oil-producing Sunniland Formation, and collectively have an estimated storage capacity of around 26 million tons of CO 2 . The Sunniland Formation throughout the entire Trend has an average porosity of 14% and an estimated storage capacity of about 1.2 billion tons of CO 2 (BtCO2 ). The CKLIZ has an average porosity of 23% and an estimated storage capacity of approximately 79 BtCO 2 . Porous intervals within the CKLIZ and Sunniland Formation are laterally homogeneous, and low-permeability layers throughout the units provide significant vertical heterogeneity. The CKLIZ and Sunniland Formation are considered potentially suitable for CCS operations because of their geographic locations, appropriate depths, high porosities, estimated storage capacities, and potentiallyeffective seals. The Trend oil fields are suitable for CO 2 -EOR in the Sunniland Formation due to appropriate injected-CO 2 density, uniform intergranular porosity, suitable API density of formation-oil, sufficient production zones, and adequate remaining oil-in-place following secondary recovery. In addition to these in-depth investigations of the CKLIZ and Sunniland Formation, a more-cursory assessment of deep geologic units throughout the state of Florida, which includes rocks of Paleocene and Upper Cretaceous age through to rocks of Ordovician age, shows additional units in Florida that may be suitable for CO 2 -EOR and CCS operations. Furthermore, this study shows that deep geologic units throughout Florida potentially have the capacity to sequester billions of tons of CO 2 for hundreds of fossil-fuel-fired power plants. Geologic sequestration has not yet been conducted in Florida, and its implementation could prove useful to Florida utility companies, as well as to other energy-utilities in the southeastern United States.

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Azzolina, Nicholas A. "Statistical Approaches to Quantifying Uncertainty of Monitoring and Performance at Geologic CO2 Storage Sites." Research Showcase @ CMU, 2015. http://repository.cmu.edu/dissertations/567.

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Geologic carbon dioxide (CO2) storage is one approach for mitigating concentrations of CO2 in the atmosphere that are caused by stationary anthropogenic inputs. Injecting CO2 into the subsurface for long-term storage is an “engineered-natural system”. This engineered-natural system is complex, with potential interactions during CO2 injection between CO2 and other reservoir fluids and various components of the geologic system. The National Risk Assessment Partnership (NRAP) is an initiative within DOE’s Office of Fossil Energy that is improving the fundamental understanding of the complex science behind engineered-natural systems and is developing the risk assessment tools that are needed for safe, permanent geologic CO2 storage. The NRAP technical approach entails an iterative modeling process that integrates component models into a system model which may then be used to provide quantitative assessments of potential risks and to design monitoring protocols that will effectively monitor risks at a geologic CO2 storage project. A theme throughout all phases of the NRAP approach is quantifying uncertainty and variability. The focus of this dissertation is to contribute statistical methods and/or approaches for quantifying uncertainty and variability with respect to both monitoring and performance at geologic CO2 storage sites. These methods are intended for future use by NRAP or other geologic CO2 storage practitioners and may be incorporated into broader modeling approaches. However, the results and contributions from this work extend beyond geologic CO2 storage and apply to other subsurface engineered-natural systems.

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Gulliver, Djuna M. "Concentration - Dependent Effects of CO2 on Subsurface Microbial Communities Under Conditions of Geologic Carbon Storage and Leakage." Research Showcase @ CMU, 2014. http://repository.cmu.edu/dissertations/408.

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Geologic carbon storage (GCS) is a crucial part of a proposed mitigation strategy to reduce the anthropogenic CO2 emissions to the atmosphere. During this process, CO2 is injected as super critical carbon dioxide (SC-CO2) in confined deep subsurface storage units, such as saline aquifers and depleted oil reservoirs. The deposition of vast amounts of CO2 in subsurface geologic formations may ultimately lead to CO2 leakage into overlying freshwater aquifers. Introduction of CO2 into these subsurface environments will greatly increase the CO2 concentration and will create CO2 concentration gradients that drive changes in the microbial communities present. While it is expected that altered microbial communities will impact the biogeochemistry of the subsurface, there is no information available on how CO2 gradients will impact these communities. The overarching goal of this dissertation is to understand how CO2 exposure will impact subsurface microbial communities at temperature and pressure that are relevant to GCS and CO2 leakage scenarios. To meet this goal, unfiltered, aqueous samples from a deep saline aquifer, a depleted oil reservoir, and a fresh water aquifer were exposed to varied concentrations of CO2 at reservoir pressure and temperature. The microbial ecology of the samples was examined using molecular, DNA-based techniques. The results from these studies were also compared across the sites to determine any existing trends. Results reveal that increasing CO2 leads to decreased DNA concentrations regardless of the site, suggesting that microbial processes will be significantly hindered or absent nearest the CO2 injection/leakage plume where CO2 concentrations are highest. At CO2 exposures expected downgradient from the CO2 plume, selected microorganisms emerged as dominant in the CO2 exposed conditions. Results suggest that the altered microbial community was site specific and highly dependent on pH. The site-dependent results suggests no ability to predict the emerging dominant species for other CO2exposed environments. This body of work improves the understanding of how a subsurface microbial community may respond to conditions expected from geologic carbon storage and CO2 leakage. This is the first step for understanding how a CO2 altered microbial community may impact injectivity, permanence of stored CO2, and subsurface water quality. .

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Raza, Yamama. "Uncertainty analysis of capacity estimates and leakage potential for geologic storage of carbon dioxide in saline aquifers." Thesis, Massachusetts Institute of Technology, 2009. http://hdl.handle.net/1721.1/53063.

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Thesis (S.M. in Technology and Policy)--Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program, 2009. Includes bibliographical references (p. 61-62). The need to address climate change has gained political momentum, and Carbon Capture and Storage (CCS) is a technology that is seen as being feasible for the mitigation of carbon dioxide emissions. However, there is considerable uncertainty that is present in our understanding of the behavior of CO₂ that is injected into the sub-surface. In this work, uncertainty analysis is performed using Monte Carlo simulations for capacity estimates and leakage potential for a saline aquifer. Six geologic parameters are treated as uncertain: porosity, irreducible water saturation, the endpoint relative permeability of CO₂, residual gas saturation, viscosity of water, and viscosity of the brine. The results of the simulations for capacity indicate that there is a large uncertainty in capacity estimates, and that evaluating the model at using the mean values of the individual parameters does not give the same result as the mean of the distribution of capacity estimates. Sensitivity analysis shows that the two parameters that contribute the most to the uncertainty in estimates are the residual gas saturation and the endpoint relative permeability of CO₂. The results for the leakage simulation suggest that while there is a non-zero probability of leakage, the cumulative amount of CO₂ that leaks is on the order of fractions of a percent of the total injected volume, suggesting that essentially all the CO₂ is trapped. Additionally, the time when leakage begins is on the order of magnitude of thousands of years, indicating that CCS has the potential to be a safe carbon mitigation option. (cont.) Any development of regulation of geologic storage and relevant policies should take uncertainty into consideration. Better understanding of the uncertainty in the science of geologic storage can influence the areas of further research, and improve the accuracy of models that are being used. Incorporating uncertainty analysis into regulatory requirements for site characterization will provide better oversight and management of injection activities. With the proper management and monitoring of sites, the establishment of proper liability regimes, accounting rules and compensation mechanisms for leakage, geologic storage can be a safe and effective carbon mitigation tool to combat climate change. by Yamama Raza. S.M.in Technology and Policy

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Wolff, Joshua Michael. "Acceptance by proxy : analyzing perceptions of hydraulic fracturing to better understand public acceptance for geologic storage of carbon dioxide." Thesis, Massachusetts Institute of Technology, 2015. http://hdl.handle.net/1721.1/98605.

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Thesis: S.M. in Technology and Policy, Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program, 2015. Cataloged from PDF version of thesis. Includes bibliographical references (pages 90-97). Carbon capture and storage (CCS) represents an important pathway for reducing greenhouse gas emissions in order to mitigate climate change. However, there is significant uncertainty about how the technology will be accepted by the public, which is difficult to predict for relatively unknown technologies such as CCS. As such, this thesis explores the use of a similar but better known technology-hydraulic fracturing-as an analogue for learning lessons about public acceptance of the geologic storage component of CCS. The thesis asks two questions: (1) What factors are associated with public acceptance of geologic storage? And (2) What actions should communities, regulators, and stakeholders take to ensure the safe and efficient deployment of CCS technology? The thesis investigates these questions using three separate but related analyses. A series of regressions explores links between states' history of fossil fuel extraction and current regulatory attitudes toward hydraulic fracturing. A comparative case study characterizes trends in the development of laws and regulations related to hydraulic fracturing in three states: Pennsylvania, New York State, and Colorado. Finally, a survey identifies factors associated with positive and negative public perceptions of both hydraulic fracturing and CCS. The survey includes an experimental question that measures the extent to which compensation can be used to improve public acceptance for facility siting. Through these analyses, the thesis reaches several conclusions. States with an extensive history of fossil fuel extraction are more likely to regulate hydraulic fracturing with a moderate level of regulatory stringency, and similar tendencies toward CCS are likely. Municipalities are playing an increasingly significant role in the regulation of hydraulic fracturing, and are likely to be important stakeholders for CCS projects as well. A number of demographic and worldview factors are associated with public acceptance, but none were found to have substantial predictive power. However, the amount of compensation offered to nearby residents was found to have a moderate effect on public acceptance. Developers should therefore consider compensation a tool for increasing the likelihood of acceptance among residents nearby a potential project site. Policymakers should in turn institute market incentives such as robust carbon prices to foster a financial environment that encourages developers to engage with municipalities and residents. by Joshua Michael Wolff. S.M. in Technology and Policy

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Namhata, Argha. "Modeling and Statistical Assessment of Fluid Migration Response in the Above Zone Monitoring Interval of a Geologic Carbon Storage Site." Research Showcase @ CMU, 2016. http://repository.cmu.edu/dissertations/877.

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Carbon dioxide (CO2) capture and storage (CCS) into geological formations is regarded as an important strategy for achieving a significant reduction in anthropogenic CO2 emissions. An increasing emphasis on the industrial-scale implementation of CO2 storage in geological formations has led to the development of whole-system models to evaluate the performance of candidate geologic storage sites and the environmental risk associated with them. The United States Department of Energy (DOE), through its National Risk Assessment Partnership (NRAP) Program, is conducting research to develop science-based methods to quantify the likelihood of risks associated with the longterm geologic storage of CO2. A key component of this research is the development of an Integrated Assessment Model (IAM), which simulates the geologic storage system by integrating the primary sub-system components of the system for the purpose of elucidating the relationship between CO2 injection into the subsurface and the short- and long-term containment of the stored CO2. The sub-system components of that engineered geologic storage system include the storage reservoir, overlying aquitards (primary caprock and secondary seals) and aquifers (including the above zone monitoring interval, or AZMI, which directly overlays the primary seal), and potential leakage pathways including wells, fractures, and faults, to name a few. The subsystems are modeled using simplified reduced order models (ROMs), which are then coupled together to characterize the entire storage system. The construction of the IAM permits the quantification and assessment of the storage risks in a more computationally efficient manner as compared to the use of full physics-based models. This Ph.D. research was initiated with a review of the IAM development efforts of NRAP and an assessment of the current status of the ROMs for each of the sub-system components of the storage system. In addition, gaps in the development in the IAM structure were identified. The research also investigated the potential migration of subsurface fluids (i.e., CO2 and formation brine) in geologic storage sites. Leakage of CO2 and brine through the primary seal to the overlying porous and permeable formations, such as the AZMI, may occur due to the intrinsic permeability of the seal and/or the presence of natural fractures or induced perforations or fractures. Pressure modeling of the AZMI provides a useful source of information regarding seal performance and the subsurface pressure response to CO2 leakage from the reservoir. As part of this research, a ROM for the AZMI, a missing component of the current IAM of NRAP, was developed. This AZMI ROM simulates fluid flow above the primary seal and predicts spatial changes in pressure over time due to this fluid migration from the reservoir. The performance of the AZMI ROM was verified using full physicsbased models of the zone. A data-driven approach of arbitrary Polynomial Chaos (aPC) Expansion was then used to quantify the uncertainty in the pressure predictions in the AZMI based on the inherent variability of the different geologic parameters such as the porosity, permeability, and thickness of the AZMI, and the caprock permeability and thickness. The aPC approach, which represents the models as a polynomial-based response surface, was then used to perform stochastic model reduction. Finally, a global sensitivity analysis was performed with Sobol indices based on the aPC technique to determine the relative importance of the different system parameters on pressure prediction. The research results indicate that there can be substantial uncertainty in pressure prediction locally, around the leakage zones, and that the degree of the uncertainty depends on the quality of the site-specific information available for analysis. The research results confirm the need for site-specific data for the efficient predictions of risks associated with geologic storage activities. Lastly, the research investigated the use of the AZMI model outputs as a basis for the Bayesian design of a monitoring framework for this zone of a geologic carbon storage system. Monitoring of reservoir leakage requires the capability to intercept and resolve the onset, location, and volume of leakage in a systematic and timely manner. The results of this research suggest that an optimal monitoring system with these capabilities can be designed based on the characterization of potential CO2 leakage scenarios that are determined using an assessment of the integrity and permeability of the caprock inferred from pressure measurements in the AZMI.

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Ripepi, Nino Samuel. "Carbon Dioxide Storage in Coal Seams with Enhanced Coalbed Methane Recovery: Geologic Evaluation, Capacity Assessment and Field Validation of the Central Appalachian Basin." Diss., Virginia Tech, 2009. http://hdl.handle.net/10919/28697.

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The mitigation of greenhouse gas emissions and enhanced recovery of coalbed methane are benefits to sequestering carbon dioxide in coal seams. This is possible because of the affinity of coal to preferentially adsorb carbon dioxide over methane. Coalbed methane is the most significant natural gas reserve in central Appalachia and currently is economically produced in many fields in the Basin. This thesis documents research that assesses the capacity of coal seams in the Central Appalachian Basin to store carbon dioxide and verifies the assessment through a field validation test. This research allowed for the first detailed assessment of the capacity for coal seams in the Central Appalachian Basin to store carbon dioxide and enhance coalbed methane recovery. This assessment indicates that more than 1.3 billion tons of carbon dioxide can be sequestered, while increasing coalbed methane reserves by as much as 2.5 trillion cubic feet. As many of the coalbed methane fields are approaching maturity, carbon sequestration and enhanced coalbed methane recovery has the potential to add significant recoverable reserves and extend the life of these fields. As part of this research, one thousand tons of carbon dioxide was successfully injected into a coalbed methane well in Russell County, Virginia as the first carbon dioxide injection test in the Appalachian coalfields. Research from the field validation test identified important injection parameters and vital monitoring technologies that will be applicable to commercial-scale deployment. Results from the injection test and subsequently returning the well to production, confirm that fractured coal seams have the potential to sequester carbon dioxide and increase methane production. It was demonstrated through the use of perfluorocarbon tracers that there is a connection through the coal matrix between the injection well and surrounding producing gas wells. This connection is a cause for concern because it is a path for the carbon dioxide to migrate to the producing wells. The thesis concludes by presenting options for mitigating carbon dioxide breakthrough in commercial-scale injection projects. Ph. D.

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Shu, Yutong. "Natural analogues for geological carbon storage." Thesis, University of Edinburgh, 2018. http://hdl.handle.net/1842/31393.

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In CO2 storage sites, seal has a vital role in inhibiting migration of the supercritical CO2 to other geological strata. The major difficulties in studying seals include two aspects: lack of available samples (especially for saline aquifers), and the difficulty to study over geological time and spatial scales. The analysis of natural analogue has been chosen to overcome these difficulties. Hydrocarbon fields are used to investigate the pore throat radii, which is the major factor for capillary sealing of caprocks, using newly established statistics model. Natural CO2 springs at Green River, Utah are used to study how the long-term CO2 charge triggers chemical reactions and migration in shales. One of the major sealing mechanism of caprocks is capillary sealing. Pore throat radius, as the main factor to decide the capillary sealing, has been investigated in this study. As an alternative to the traditional method of mercury injection porosimetry, a statistical model for effective pore throat radii determination has been established. The cumulative percentage and the probability distribution of the effective pore throat radii of the shale caprocks in the UK North Sea oil fields are obtained, which would be used as a reference for the saline aquifers in CO2 storage siting in the future work. Monte Carlo simulation is utilised to get the distribution of the effective pore throat radii. The cumulative distribution from this study has been compared with the distribution by Yang and Aplin (1998). The distribution by the statistical model enables to narrow down the range of effective pore throat radii to 37nm~1700nm, and help to make a better prediction on the pore throat radii. The correlation between the controlling factors of faulting, burial depth, caprock thickness and the pore throat radii have been examined. Good correlation between the depth less than 3000m and the effective pore throat radii indicates clay diagenesis should be the major factor for shallowly buried caprocks. Faulting and caprock thickness present no significant correlation with the effective pore throat radii. Crystal Geyser is used as an ideal natural analogue to study the Mancos Shale alteration. The interacted fluid that deposited travertine is important for the study. Hence, carbonate veins and reduction zones that associated with the activity of the main fault are used as records of the geochemistry of the paleo-fluid, the features of which are compared to the present spring water. The result shows the paleo-fluid was much more saline than the present fluid, with greater flow-rate. The decreased flow-rate might be owing to the self-healing of the fault during the time. Mancos shales outcropped in the hanging wall of the Little Grand Wash fault were sampled to investigate on the alterations triggered by the CO2-charged fluid from the fault and fractures. The result shows the alteration radius of the Mancos has limited within the distance of 20m away from the fault. CO2-rich fluid could interact with deformed shale (both dissolution and precipitation might happen), but no evidence shows the intact Mancos has been altered. The calcite cements in Mancos derived from CO2 sequestration could reach up to 27% (%weight of the whole rock) at 15m away from the fault. The conclusion facilitates the carbon storage siting criteria by Chadwick et al., (2009), who proposed the cautionary thickness of the caprock to be 20m.

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15

Qi, Ran. "Simulation of geological carbon dioxide storage." Thesis, Imperial College London, 2009. http://hdl.handle.net/10044/1/1358.

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We modifed a streamlined-based simulator based on the work of Batycky et al. (1997) [7] to solve CO2 transport in aquifers and oil reservoirs. We then use this to propose design strategy for CO2 injection to maximise storage in aquifers and to maximise both CO2 storage and enhanced oil recovery (EOR) in oil reservoirs. We first extended Batycky et al. (1997) [7]'s streamline simulator from two phases (aqueous phase and hydrocarbon phase) and two components (water and oil) to a three- phase (aqueous phase, hydrocarbon phase and solid phase) and four-component (water, oil, CO2 and salt) simulator specialized for CO2 injection. We solved CO2 transport equations in the hydrocarbon and aqueous phases along streamlines and in the direction of gravity. To capture the physics of CO2 transport, in the hydrocarbon phase, we used the Todd-Longsta® (1972) [112] model to represent sub-grid-block viscous fingering. We implemented a thermodynamic model of mutual dissolution between CO2 and water and resulting salt precipitation [104; 105]. The resultant changes in porosity and permeability due to chemical reaction and salt precipitation were also considered. We accounted for two cycles of relative permeability hysteresis (primary and secondary drainage and imbibition) by applying two di®erent trapping models: Land (1968) [69] and Spiteri et al.(2005) [103]. Therefore, relative permeability changes and variations in the trapped non-wetting phase saturations due to hysteresis can be updated on a block-by-block basis. We then used this streamline-based simulator to design CO2 storage in aquifers. We propose a carbon storage strategy where CO2 and brine are injected into an aquifer together followed by brine injection alone. This renders 80-95% of the CO2 immobile in pore-scale (10s ¹m) droplets within the porous rock; over thousands to billions of years the CO2 may dissolve or precipitate as carbonate, but it will not migrate upwards and so is e®ectively sequestered. The CO2 is trapped during the decades-long lifetime of the injection phase, reducing the need for extensive monitoring for centuries. The method does not rely on an impermeable cap rock to contain the CO2; this is only a secondary containment for the small amount of remaining mobile gas. Furthermore, the favorable mobility ratio between injected and displaced fluids leads to a more uniform sweep of the aquifer leading to a higher storage e±ciency than injecting CO2 alone. This design was demonstrated through one-dimensional simulations that were verified through comparison with analytical solutions. We then performed simulations of CO2 storage in a North Sea aquifer. We design injection to give optimal storage e±ciency and to minimise the amount of water injected; for the case we study, injecting CO2 with a fractional flow between 85 and 100% followed by a short period of chase brine injection to give the best performance. Sensitivity studies were conducted for different rock wettabilities and comparison with the Land trapping model. We found that the effectiveness of our proposed strategy is very sensitive to the estimated residual CO2-phase trapping. We then extended our study of the design of CO2 storage in aquifers to oilfields. We again constructed analytical solutions to the transport equations accounting for relative permeability hysteresis. We used this to design an injection strategy where CO2 and brine are injected simultaneously followed by chase brine injection. We studied field- scale oil production and CO2 storage for di®erent CO2 volumetric fractional flowrates. While injecting at the optimum WAG ratio gives the fastest oil recovery, this allows CO2 to channel through the reservoir, leading to rapid CO2 breakthrough and extensive recycling of the gas. We propose to inject more water than optimum. This causes the CO2 to remain in the reservoir, increases the field life and leads to improved storage of CO2 as a trapped phase. Again, a short period of chase brine injection at the end of the process traps most of the remaining CO2. Finally, we investigated the e®ect of salt (halite) precipitation during dry, supercritical CO2 injection using our modifed streamline-based simulator. In this study, pseudo one- dimensional and two-dimensional homogeneous and heterogeneous systems were used to study the sensitivity of di®erent parameters, which include relative permeability, grid size and brine salinity to salt precipitation. In our three-dimensional model, based on a geological model of a CO2 injection site, we constructed a near wellbore fine grid model with almost 1.5 million grid cells. Simulations were conducted successfully, and we found that salt precipitation can be a very important e®ect to consider when dry CO2 is injected into a high salinity reservoir. In this reservoir, after only 2 years of CO2 injection, about 20% of permeability of the reservoir was reduced, which will seriously reduce the injectivity of the injector and fluid flow within the reservoir.

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16

Espinoza, David Nicolas. "Carbon geological storage - underlying phenomena and implications." Diss., Georgia Institute of Technology, 2011. http://hdl.handle.net/1853/42701.

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The dependency on fossil fuels faces resource limitations and sustainability concerns. This situation requires new strategies for greenhouse gas emission management and the development of new sources of energy. This thesis explores fundamental concepts related to carbon geological storage, including CO2-CH4 replacement in hydrate-bearing sediments. In particular it addresses the following phenomena: - Interfacial tension and contact angle in CO2-water-mineral and CH4-water-mineral systems. These data are needed to upscale pore phenomena through the sediment porous network, to define multiphase flow characteristics in enhanced gas recovery operations, and to optimize the injection and storage CO2 in geological formations. - Coupled processes and potential geomechanical implications associated to CH4-CO2 replacement in hydrate bearing sediments. Results include physical monitoring data gathered for CH4 hydrate-bearing sediments during and after CO2 injection. - Performance of cap rocks as trapping structures for CO2 injection sites. This study focuses on clay-CO2-water systems and CO2 breakthrough through highly compacted fine-grained sediments. Long term experiments help evaluate different sediments according to their vulnerability to CO2, predict the likelihood and time-scale of breakthrough, and estimate consequent CO2 leaks.

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17

Wang, Zhiyu. "Effects of Impurities on CO2 Geological Storage." Thesis, Université d'Ottawa / University of Ottawa, 2015. http://hdl.handle.net/10393/32061.

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This project studied the physical and chemical effects of typical impurities on CO2 storage using both experimental approaches and theoretical simulation. Results show that the presence of typical non-condensable impurities from oxyfuel combustion such as N2, O2, and Ar resulted in lower density than pure CO2, leading to decreased CO2 storage capacity and increased buoyancy in saline aquifers. In contrast, inclusion of condensable SO2 in CO2 resulted in higher density than pure CO2 and therefore increased storage capacity. These impurities also had a significant impact on the phase behaviours of CO2, which is important to CO2 transportation. Different effects on rock chemistry were detected with experimental systems containing pure CO2, CO2 with SO2, or CO2 with SO2 and O2 under conditions simulating that in a potential storage site. An equation was proposed to predict the effects of the rock chemistry on the porosity of rocks.

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18

Marieni, Chiara. "Geological storage of carbon dioxide in oceanic crust." Thesis, University of Southampton, 2016. https://eprints.soton.ac.uk/402631/.

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The rise of atmospheric carbon dioxide (CO2), due to decades of burning of fossil fuels, is a key driver of anthropogenic climate change. Carbon Capture and Storage (CCS) is one of the most promising mitigation strategies for long-term sequestration of CO2. Unlike most conventional CCS investigations targeting deep saline aquifers, this thesis focuses on the potential of the uppermost oceanic crust, inspired by the strong evidence that basaltic seafloor has acted, in the past, as a major sink for CO2. The study of temperature, pressure, and density of CO2 and seawater at the sediment-basement interface for the whole seafloor highlights the influence of water depth, sediment thickness, and oceanic crustal age on the relative gravitational stability of CO2. Consequently, 8% of the entire oceanic crust is recognised as suitable for gravitational and physical trapping of CO2 injected into the basement. Five potential targets are proposed, and even the smallest of these provides sufficient carbon dioxide sequestration capacity for the next centuries. Batch experiments on the mineral dissolution of submarine mafic rocks and ophiolitic gabbro, in CO2-rich solutions, contribute to improve the fundamental understanding of geochemical reactions at mid-ocean ridge flank temperatures (40 ?C). Concentrations of silicon and calcium in solution, and particle size are identified as the key factors to quantify the rock reactivity. Ca dissolution rates suggest calcite, plagioclase and amphibole are the principal sources of calcium at pH ~5. The attempted estimation of costs related to the transport and storage of 20 Mt/yr of CO2 in deep-sea basalts, as a function of distance from the shore, injection rate, and water depth, shows the economic feasibility of potential offshore CCS projects. Overall, the expenditures are dominated by the number of ships and wells required to deliver large volumes of CO2 to reservoirs located far from the coast, rather than by the water depth. These financial considerations could potentially improve if the CCS strategies conquered a significant place in the global market.

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19

Al, Mansoori Saleh K. "Impact of carbon dioxide trapping on geological storage." Thesis, Imperial College London, 2009. http://hdl.handle.net/10044/1/5282.

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If we are to avoid potentially dangerous climate change, we need to capture and store CO2 emitted by fossil-fuel burning power stations and other industrial plants [123]. Saline aquifers provide the largest potential for storage and the widest geographical spread [66]. Subsequent leakage of CO2 into the atmosphere, even over hundreds of years, would render any sequestration scheme inefficient. However, based on the experience of the oil and gas industry, there is a good understanding of trapping mechanisms that take place in geological formations. Carbon capture and storage (CCS), where carbon dioxide, CO2, is collected from industrial sources and injected underground is one way to mitigate atmospheric emissions of this major greenhouse gas (GHG). Possible sites to accommodate CO2 storage are saline aquifers and oil reservoirs. These two types of location are considered for two reasons: the enormous storage potential in aquifers and the additional hydrocarbon production that could be produced by oil reservoirs. It is important that the injection scheme is designed such that the CO2 is safely stored and will not escape to the surface. Residual trapping offers a potentially quick and effective alternative method by which a non-wetting phase is rendered immobile as recent modelling has suggested that up to 90% of CO2 can be effectively immobilised by residual trapping in a short (years to decades) timescale [133]. There are only a few experimental measurements of capillary trapping in unconsolidated media in the literature. This is because the experimental measurements of multi-phase flow are extremely difficult to perform and the results are frequently not reliable at low saturations [119]. Most of the studies concentrate on trapped gas and rather than the residual saturation of a liquid phase: CO2 stored underground will be super-critical and liquid-like. In this work, we focus on measuring reliably and precisely residual saturations for both two- and three-phase flow covering the entire saturation range, including very low residual saturations. We performed drainage-imbibition and buoyancy-driven experiments for two-phase flow (oil-water and gas-water systems) and three-phase gravity drainage experiments for an oil-gas-water system on unconsolidated sand (LV60). The measured porosity of the sand was 0.37 obtained from three replicates (each replicate is a completely new experiment). The mean absolute permeability was 3.1 x 10-11 m2. The initial water saturation (Swi), residual oil saturation (Sor) and residual gas saturation (Sgr) were measured by two methods, namely mass balance (MB) and volume balance (VB). Mean values were 0.27 for Swi, 0.13 for Sor, and 0.14 for Sgr. Accuracy was maintained to be within 0.1% for every measurement. The buoyancy-driven experiments results show that Sor and Sgr are 11% and 14% respectively and generally lower than consolidated media. The trapped saturations initially rise linearly with initial saturation to a maximum value, followed by a constant residual as the initial saturation increases further. This behaviour is not predicted by the most commonly-used empirical models, but is physically consistent with poorly consolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data was achieved with the trapping model proposed by Aissaoui [2]. The three-phase gravity drainage experiments results show that for high initial gas saturations more gas can be trapped in the presence of oil than in a two-phase (gaswater) system. This is unlike previous measurements on consolidated media, where the trapped gas saturation is either similar or lower to that reached in an equivalent twophase experiment. The maximum residual gas saturation is over 20%, compared to 14% for two-phase flow. For lower initial gas saturation, the amount of trapping follows the initial-residual trend seen in two-phase experiments, although some values lie below the two-phase correlation These results are discussed in relation to pore-scale displacement processes and compared to literature values – mainly on consolidated media – that find that both gas and oil residuals are lower in three-phase than twophase flow [32, 52, 70, 81, 95, 97, 101, 108, 143-145]. This work implies that CO2 injection in poorly consolidated media would lead to rather poor storage efficiencies, with at most 4-6% of the rock volume occupied by trapped CO2; this is at the lower end of the compilation of literature results shown in Fig. 5.2. Using the Land correlation to predict the behaviour would tend to over-estimate the degree of trapping except for high initial saturations. The presence of a third phase (such as in an oil field, for instance) may improve the trapping efficiency.

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20

Gunnarsson, Niklas. "3D modeling in Petrel of geological CO2 storage site." Thesis, Uppsala universitet, Institutionen för geovetenskaper, 2011. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-162124.

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If mitigation measures are not made to prevent global warming the consequences of a continued global climate change, caused by the use of fossil fuels, may be severe. Carbon Capture and Storage (CCS) has been suggested as a way of decreasing the global atmospheric emission of CO2. In the realms of MUSTANG, a four year (2009-2013) large-scale integrating European project funded by the EU FP7, the objective is to gain understanding of the performance as well as to develop improved methods and models for characterizing so- called saline aquifers for geological storage of CO2. In this context a number of sites of different geological settings and geographical locations in Europe are also analyzed and modeled in order to gain a wide understanding of CO2 storage relevant site characteristics. The south Scania site is included into the study as one example site with data coming from previous geothermal and other investigations. The objective of the Master's thesis work presented herein was to construct a 3D model for the south Scania site by using modeling/simulation software Petrel, evaluate well log data as well as carry out stochastic simulations by using different geostatistical algorithms and evaluate the benefits in this. The aim was to produce a 3D model to be used for CO2 injection simulation purposes in the continuing work of the MUSTANG project. The sequential Gaussian simulation algorithm was used in the porosity modeling process of the Arnager greensand aquifer with porosity data determined from neutron and gamma ray measurements. Five hundred realizations were averaged and an increasing porosity with depth was observed. Two different algorithms were used for the facies modeling of the alternative multilayered trap, the truncated Gaussian simulation algorithm and the sequential indicator simulation algorithm. It was seen that realistic geological models were given when the truncated Gaussian simulation algorithm was used with a low-nugget variogram and a relatively large range. Den antropogena globala uppvärmningen orsakad av användandet av fossila bränslen kan få förödande konsekvenser om ingenting görs. Koldioxidavskiljning och lagring är en åtgärd som föreslagits för att minska de globala CO2-utsläppen. Inom ramarna för MUSTANG, ett fyra år långt (2009-2013) integrerande projekt finansierat av EU FP7 (www.co2mustang.eu), utvecklas metoder, modeller och förståelse angående så kallade saltvattenakviferers lämplighet för geologisk koldioxidlagring. En del av projektet är att analysera ett antal representativa formationer i olika delar av Europa för att få kunskap angående förekommande koldioxidlagringsspecifika egenskaper hos saltvattenakviferer. Ett av områdena som har inkluderats är i sydvästra Skåne. Syftet med detta examensarbete var att konstruera en 3D modell över detta område med hjälp av modellerings/simuleringsprogrammet Petrel, utvärdera borrhålsdata samt genomföra stokastiska simuleringar med olika geostatistiska algoritmer och utvärdera dem. Målsättningen var att konstruera en modell för CO2 injiceringssimuleringar i det forstsatta arbetet inom MUSTANG-projektet. En algoritm av sekventiell Gaussisk typ användes vid porositetsmodelleringen av Arnager Grönsandsakviferen med porositetsdata erhållen från neutron- och gammastrålningsmätningar. Ett genomsnitt av femhundra realisationer gjordes och en porositetstrend som visade en ökning med djupet kunde åskådligöras. Två olika algoritmer användes vid faciesmodelleringen av den alternativa flerlagrade fällan: en algoritm av trunkerade Gaussisk typ och en sekventiell indikatorsimuleringsalgoritm. Resultaten tyder på att en realistisk geologisk modell kan erhållas vid användandet av den trunkerande algoritmen med ett låg-nugget variogram samt en förhållandevis lång range.

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21

Warr, Oliver William Peter. "Understanding phase behaviour in the geological storage of carbon dioxide." Thesis, University of Manchester, 2013. https://www.research.manchester.ac.uk/portal/en/theses/understanding-phase-behaviour-in-the-geological-storage-of-carbon-dioxide(8e772ee9-057c-49d8-afb4-5f8e2931bb8e).html.

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Noble gas partitioning between supercritical CO2-H2O phases can be used to monitor Carbon Capture and Storage (CCS) sites and their natural analogues. However, in order for viable application, noble gas partitioning within these environments must be well constrained. Present estimates of partition coefficient for these systems are taken from the low pressure pure noble gas-water experiments of Crovetto et al. and Smith (Crovetto et al., 1982; Smith, 1985). The effect a supercritical CO2 phase may have on noble gas partitioning is assumed negligible, although this has not been empirically verified. In this work this assumption of noble gas behaviour within a supercritical CO2-H2O binary phase system is evaluated using a combined approach of experiment and simulation. Using a specially commissioned high pressure system at the British Geological Survey paired CO2 and H2O samples were collected from noble gas-enriched systems at pressures and temperatures ranging between 90 – 140 bar and 323.15 – 373.15 K. These were analysed for their noble gas content using a quadrupole mass spectrometer system developed specifically for this project. By comparing the relative concentrations of noble gases in each phase partition coefficients were defined for the experimental conditions. These were compared to their low pressure analogues. At higher CO2 densities all noble gases expressed a significant deviation from predicted partition coefficients. At the highest density (656 kg/m3) helium values decreased by -54% (i.e. reduced solubility within CO2) while argon, krypton and xenon values increased by 76%, 106% and 291% respectively. These deviations are due to supercritical CO2 acting as a polar solvent, the solvation power of which increases as a function of density. Polarisation is induced in each noble gas within this solvent based on their respective polarisabilities. Hence xenon, krypton and argon become more easily solvated as a function of CO2 density while solvating helium becomes harder. These deviation trends are well described using a second order polynomial. This fit defines a deviation coefficient which can be used to adapt low pressure partition coefficients to allow accurate predictions of partitioning within highly dense CO2 phases. Concurrently a Gibbs Ensemble Monte Carlo (GEMC) molecular model was iteratively developed to reproduce noble gas behaviour within these experimental systems. By optimising noble gas-water interactions a pure noble gas-water system was constructed for each noble gas at low pressure which replicated published partition coefficients. These optimised interactions were subsequently applied to low pressure CO2-H2O systems where partition coefficients were derived by calculating excess chemical potentials of noble gases in each phase. Again a good agreement was observed with published values. When the model was applied to the experimental conditions however, a poor agreement with the experimental values was observed. Instead simulated values replicated the low pressure Crovetto et al. and Smith datasets (Crovetto et al., 1982; Smith, 1985). This was due to no CO2-noble gas polarisation terms being included in the current iteration of the model. By including this within the model in the future a full reconciliation between the datasets is expected.

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22

Kilpatrick, Andrew David. "Fluid-mineral-CO2 interactions during geological storage of carbon dioxide." Thesis, University of Leeds, 2014. http://etheses.whiterose.ac.uk/8889/.

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In order utilise geological carbon dioxide storage (GCS) at an industrial scale predictions of reservoir scale behaviour, both chemical and physical must be made. In order to ground-truth the geochemical data underlying such predictions, laboratory experiments at temperatures and CO2 pressures relevant to GCS are essential. Mineral dissolution rate, CO2 solubility and pH data has been collected from batch experiments carried out on quartz, K-feldspar, albite, calcite, dolomite and Sherwood Sandstone materials. These experiments were designed to assess the influence of a variety of factors on dissolution rates: changes in grain size from 125μm - 180μm to 500μm - 600μm; changes in fluid composition from deionised water to 1.36M NaCl solution; changes in CO2 pressure from 4 bar to 31 bar; changes in temperature from 22°C to 70°C. Experiments carried out on the Sherwood Sandstone material also included work on consolidated rock, rather than the powder used in other experiments. Calculated dissolution rates for silicates were found to agree well with values calculated from literature-sourced dissolution equations and the USGS-produced general rate equation (USGS 2004) was found to be suitable for predicting these rates. Calculated dissolution rates for the carbonate minerals was found to be strongly retarded due to transport effects, with literature-sourced equations significantly over-predicting dissolution rates. Dissolution of the sandstone material was found to be dominated by K-feldspar and dolomite dissolution, rates of which compare favourably with those obtained from the single mineral experiments. A significant increase in porosity was observed in the core flow-through experiment, associated with dolomite dissolution. Several experiments were carried out using a Hele-Shaw cell in order to visualise the formation and migration of density plumes which form as CO2 dissolved into unsaturated fluids. Introduction of NaCl and decreases in permeability were found to significantly retard migration of CO2 saturated fluid, while minor heterogeneities in the cells served to focus and accelerate plume movement. Modelling work suggests that predictive models currently underestimate the rapidity of formation and migration of these plumes.

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23

Hedley, Benjamin James. "Feasibility of geological carbon dioxide storage : from exploration to implementation." Thesis, Durham University, 2014. http://etheses.dur.ac.uk/10549/.

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This study utilises a range of techniques to investigate the feasibility of the geological storage of carbon dioxide. Three specific themes were addressed. Saline aquifers have been proposed as an attractive geological storage medium due to the theoretical storage capacity offered, despite the poor quality and quantity of date available to appraise them. Published methodologies are numerous, which attempt to refine the uncertainty by the introduction of capacity coefficients producing estimates with a variance of up to five orders of magnitude. The source of this uncertainty is investigated using Monte Carlo based sensitivity on a North Sea case study site. This shows the limitations and sources of error inherent in the application of such method. A new method is proposed to account for the limited available input data. Injectivity of geological reservoirs has been highlighted as a potential setback for CO2 storage. Reservoir hosted compartmentalising membrane seals are shown to permit CO2 migration without compromising storage integrity in three North Sea examples. The presence of oil as a wetting fluid in the substrate significantly reduces the capillary entry pressure of a membrane seal as a product of CO2 water contact angle of cos 85° to cos 90°. Cross fault flow rates are shown to be on operational timescales. CO2 storage projects have been cancelled as a consequence of public objection. Public Engagement has been proven to affect the public’s perception of CCS in both positive and negative directions by facilitating informed decision making. The perception of trust and impartiality are demonstrated to outdo the perception of knowledge and experience. Furthermore the perceived benefits of CCS are evidenced to be tempered by person’s preordained perception either of the technology, or those who advocate it.

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24

Wang, Bo [Verfasser]. "Compressed air energy storage in porous geological formations - Investigation of storage characteristics and induced impacts / Bo Wang." Kiel : Universitätsbibliothek Kiel, 2019. http://d-nb.info/1180387678/34.

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Alcalde, Martín Juan. "3D seismic imaging and geological modeling of the Hontomin CO2 storage site, Spain." Doctoral thesis, Universitat de Barcelona, 2014. http://hdl.handle.net/10803/284824.

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This thesis is organized as a compendium of three scientific articles, describing the geological characterization of the Hontomín site for Geological Storage of CO2 by means of 3D seismic data, acquired for this purpose, as well as the available well-log and regional data. The three articles form the core of this thesis and constitute the main scientific effort developed therein. These are: • Alcalde, J., Martí, D., Calahorrano, A., Marzán, I., Ayarza, P., Carbonell, R., Juhlin, C. and Pérez-Estaún, A. 2013a. Active seismic characterization experiments of the Hontomín research facility for geological storage of CO2, Spain. International Journal of Greenhouse Gas Control, 19, 785-795. • Alcalde, J., Martí, D., Juhlin, C., Malehmir, A., Sopher, D., Saura, E., Marzán, I., Ayarza, P., Calahorrano, A., Pérez-Estaún, A., and Carbonell, R. 2013b. 3D Reflection Seismic Imaging of the Hontomín structure in the Basque-Cantabrian Basin (Spain). Solid Earth4, pp. 481-496. • Alcalde, J., Marzán, I., Saura, E., Martí, D., Ayarza, P., Juhlin, C., Pérez-Estaún, A., and Carbonell, R. 2014. 3D geological characterization of the Hontomín CO2 storage site, Spain: multidisciplinary approach from seismics, well-logging and regional data. Tectonophysics (accepted). The thesis begins with an Introduction (Chapter I), in which the motivations and aims of the thesis are presented. These include the problematic derived from anthropogenic emissions of CO2, and present Carbon Capture and Storage technology as an effective method to reach energetic sustainability. This chapter also includes the state-of-the-art seismic reflection method applied to CO2 storage, as well as an outline of the regional and local geology of the study area. The first article (Alcalde et al., 2013a) constitutes Chapter II of the thesis. It presents and describes the active seismic experiments conducted at the Hontomín site for the seismic characterization. The data acquisition is described in detail, with an emphasis on the most relevant factors that affected the quality of the acquired data. These factors include the geomorphological/topographical aspects of the study area, logistical issues during the acquisition. The effects on the seismic records of a near-surface velocity inversion are also discussed. This contribution also shows a preliminary seismic image of the subsurface, which allows outlining the general dome shape of the target structure. The second article (Alcalde et al., 2013b) comprises Chapter III of the thesis. It outlines the processing applied to the seismic data that led to the final migrated seismic image. It includes a detailed discussion about which processes were more effective in enhancing the quality of the obtained image. The image was judged to be suitable for interpretation and constitutes the primary seismic model, to be used as reference baseline during the monitoring stage. Furthermore, the top of the Jurassic dome structure was mapped, allowing us to provide an overall estimation of the size of the target structure, which is a 107 m2 elongated dome with a maximum CO2 storage capacity of 1.2 Gt. The third article (Alcalde et al., 2014), included in Chapter IV of the thesis, focuses on the interpretation of the seismic image and the building of a 3D geological model. The quality of the seismic data required a geologically driven approach to enable interpretation. This approach used a conceptual model as reference, which was inferred in the first place from the correlation of the available well-log data and later improved by the seismic facies analysis and the regional geological data. The conceptual model was used to interpret the seismic data and resulted in a 9-layered 3D geological model and a thorough description of the fault system present in the area. Esta tesis tiene como objetivo la caracterización geológica 3D de la Planta de Desarrollo Tecnológico para el Almacenamiento Geológico de CO2 de Hontomín (Burgos). Esta caracterización se ha llevado a cabo mediante el procesado y la interpretación de datos de sísmica de reflexión 3D adquiridos para ese propósito en verano de 2010.

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Bey, Scott Michael. "Reservoir Characterization and Seismic Expression of the Clinton Interval over Dominion's Gabor Gas Storage Field in North-East Ohio." Wright State University / OhioLINK, 2012. http://rave.ohiolink.edu/etdc/view?acc_num=wright1347391687.

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Kim, Seunghee. "CO₂ geological storage: hydro-chemo-mechanically coupled phenomena and engineered injection." Diss., Georgia Institute of Technology, 2012. http://hdl.handle.net/1853/50110.

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Global energy consumption will increase in the next decades and it is expected to largely rely on fossil fuels. The use of fossil fuels is intimately related to CO₂ emissions and the potential for global warming. Geological CO₂ storage aims to mitigate the global warming problem by sequestering CO₂ underground. Coupled hydro-chemo-mechanical phenomena determine the successful operation and long term stability of CO₂ geological storage. This research explores various coupled phenomena, identifies different zones in the storage reservoir, and investigates their implications in CO₂ geological storage. Spatial patterns in mineral dissolution and precipitation are examined based on a comprehensive mass balance formulation. CO₂-dissolved fluid flow is modeled using a novel technique that couples laminar flow, advective and diffusive mass transport of species, mineral dissolution, and consequent pore changes to study the reactive fluid transport at the scale of a single rock fracture. The methodology is extended to the scale of a porous medium using pore network simulations to study both CO₂ reservoirs and caprocks. The two-phase flow problem between immiscible CO₂ and the formation fluid (water or brine) is investigated experimentally. Plug tests on shale and cement specimens are used to investigate CO₂ breakthrough pressure. Sealing strategies are explored to plug existing cracks and increase the CO₂ breakthrough pressure. Finally, CO₂-water-surfactant mixtures are evaluated to reduce the CO₂-water interfacial tension in view of enhanced sweep efficiency. Results can be used to identify optimal CO₂ injection and remediation strategies to maximize the efficiency of CO₂ injection and to attain long-term storage.

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Brochard, Laurent. "Poromechanics and adsorption : application to coal swelling during carbon geological storage." Thesis, Paris Est, 2011. http://www.theses.fr/2011PEST1067/document.

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Le stockage géologique du carbone dans les veines de charbon est une solution transitoire pour lutter contre le réchauffement climatique. La faisabilité de ce stockage à un coût abordable reste incertaine, en particulier parce que l'injection de dioxide de carbone dans les veines de charbon est lente. Les projets pilotes ont montré que la perméabilité du réservoir diminue lors de l'injection, suite au gonflement du charbon induit par l'adsorption préférentielle du dioxyde de carbone par rapport au méthane présent naturellement. Ce mémoire de thèse est consacré à l'étude de ce gonflement. Un premier travail théorique a consisté à étendre les équations constitutives de poromécanique classique dans les cas où l'adsorption sur des surfaces ou dans des micropores devient significative. Nous avons montré que le comportement poromécanique du solide ne peut être compris que si la dépendance de l'adsorption en fonction de la déformation du milieu poreux est connue. Le couplage entre adsorption et déformation est peu étudié dans la littérature et difficile à mesurer expérimentalement. Dans ce travail, nous avons utilisé la simulation moléculaire qui permet facilement de contrôler indépendamment la pression du fluide adsorbé et la déformation du milieu poreux. A l'aide de simulations moléculaires d'adsorption dans des systèmes modèles unidimensionnels, nous avons validé les nouvelles équations consitutives. Nous avons montré également que l'adsorption peut dépendre de la déformation de façon complexe et qu'elle est très sensible à la structure des micropores. Les résultats de simulations moléculaires d'adsorption dans un modèle moléculaire réaliste de la matrice organique du charbon nous ont permis de montrer que le gonflement du charbon en présence de fluide peut être expliqué par l'adsorption dans les micropores, mais pas dans les mésopores. Nous avons étudié numériquement le couplage entre adsorption et déformation dans le charbon. Le gonflement estimé en associant les simulations moléculaires d'adsorption aux nouvelles équations constitutives de poromécaniques est en bon accord avec les mesures expérimentales. De même, nous avons simulé l'adsorption de mélanges de dioxide de carbone et de méthane dans le charbon à des températures et pressions représentatives des conditions souterraines. Le résultat de ces simulations a permis d'estimer le gonflement différentiel durant l'injection de carbone pour des veines de charbon à différentes profondeurs Pas de résumé en anglais

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29

Lynch, Thomas Oakley. "Geological storage of carbon dioxide in the UK : opportunities and risks." Thesis, University of Leeds, 2014. http://etheses.whiterose.ac.uk/7669/.

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Climate change caused by greenhouse gas emissions from anthropogenic sources, primarily from fossil fuel combustion, is a major global challenge that threatens many serious adverse impacts, including sea level rise, food and water scarcity, extreme weather events and species extinction. Curbing global emissions from fossil fuels has become a major and urgent priority. Carbon Capture and Storage (CCS) has been proposed as a method to capture greenhouse gas (GHG) emissions from large point source fossil fuel combustion and store these emissions away from the atmosphere to reduce the impact on the climate. CCS involves capturing the predominant GHG produced in fossil fuel combustion, CO2, at the point source and transporting it to a location where is can be stored for thousands of years to limit its impact on the climate. Geological storage is considered to be the most advanced and realistic option for CO2 storage, and is the focus of this thesis. The aim of this thesis is to assess the risks and opportunities for CO2 storage in the UK offshore region, where the majority of UK CO2 storage capacity is expected to exist in saline aquifers and depleted hydrocarbon reservoirs. A review of the technical considerations for geological CO2 storage is presented and the potential storage capacities and risks to secure storage in the UK are identified. Fluid flow simulation and coupled fluid flow-geomechanical modelling are used to assess several aspects of storage, based on the assessment of the potential risks for storage in the UK. These include assessment of current capacity estimates for CO2 injection into the largest potential source of UK storage capacity the Bunter Saline Aquifer; opportunities for brine extraction to increase capacity in saline aquifers and the potential for a reduction in capacity and risk of leakage through fracture pressure hysteresis in depleted hydrocarbon reservoirs. Three key results are identified from the work. Firstly, significantly lower capacities are modelled for the Bunter Aquifer, compared to both static estimates and more complex models in the literature. This is due to the potential variability in parameters, such as the compressibility and fracture pressure, which control capacity. Estimates for the capacity in the Bunter from the modelling range between 3.1 and 8.7 Gt CO2 which corresponds to between 20 and 56 years of storage capacity for the UK, this is compared to an initial estimate of 90 years of storage capacity from static estimates. Fracture pressure estimation is uncertain and fracture pressure is a significant control on capacity in the generic modelling it is shown to reduce capacity by 32 – 60% with a 20% reduction in fracture pressure. The most conservative fracture pressure assumption for the modelled capacities in the Bunter Aquifer would indicate a reduced capacity as low as 2.5 Gt CO2 . Potential variability in the fracture pressure is the second major finding of this work and is intrinsically related to variability in capacity. Coupled fluid flow geomechanical modelling indicates that the fracture pressure in depleted hydrocarbon reservoirs with similar stress conditions and material parameters to those found in the UK North Sea could be up to 19% lower during injection compared to the depletion fracture pressures. This is without including the effect of thermally induced tensile stresses developed due to the injection of cold CO2 which may reduce fracture pressures further. Finally, capacity modelling in the Bunter Aquifer has also identified a potential legacy risk for CO2 storage in a large aquifer such as the Bunter. The peak fracture pressure risk is not observed in the model until 6 – 136 years after injection has stopped, and occurs great distances from the injection point. This poses questions as to the methodology for monitoring this risk, the potential remediation options and the impact on other activities within the aquifer. The research highlights several areas where further investigation are essential for constraining CO2 storage capacity and leakage risks, with the primary uncertainty relating to the quantification of fracture pressure in both saline aquifers and depleted hydrocarbon reservoirs.

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Chanrithyrouth, Mao. "Assessment of the Potential for Geological Storage of Carbon Dioxide in Cambodia." 京都大学 (Kyoto University), 2014. http://hdl.handle.net/2433/192170.

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Pfeiffer, Wolf Tilmann [Verfasser]. "Hydrogen energy storage in porous geological formations - Investigation of storage dimensioning, induced effects and monitoring methods / Wolf Tilmann Pfeiffer." Kiel : Universitätsbibliothek Kiel, 2017. http://d-nb.info/1132134102/34.

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32

MacMinn, Christopher William. "Analytical modeling of CO₂ migration in saline aquifers for geological CO₂ storage." Thesis, Massachusetts Institute of Technology, 2008. http://hdl.handle.net/1721.1/45642.

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Thesis (S.M.)--Massachusetts Institute of Technology, Dept. of Mechanical Engineering, 2008. This electronic version was submitted by the student author. The certified thesis is available in the Institute Archives and Special Collections. Includes bibliographical references (p. 53-55). Injection of carbon dioxide into geological formations for long-term storage is widely regarded as a promising tool for reducing global atmospheric CO₂ emissions. Given the environmental and health risks associated with leakage of CO₂ from such a storage site, it is critical to ensure that injected CO₂ remain trapped underground for the foreseeable future. Careful site selection and effective injection methods are the two primary means of addressing this concern, and an accurate understanding of the subsurface spreading and migration of the CO₂ plume during and after injection is essential for both purposes. It is well known that some CO₂ will be trapped in the pore space of the aquifer rock as the plume migrates and spreads; this phenomenon, known as capillary trapping, is an ideal mechanism for geological CO₂ storage because the trapped gas is immobile and distributed over a large area, greatly decreasing the risk of leakage and enhancing the effectiveness of slower, chemical trapping mechanisms. Here, we present an analytical model for the post-injection spreading of a plume of CO₂ in a saline aquifer, both with and without capillary trapping. We solve the governing equation both analytically and numerically, and a comparison of the results for two different initial plume shapes demonstrates the importance of accounting for the true initial plume shape when capillary-trapping effects are considered. We nd that the plume volume converges to a self-similar, power-law trend at late times for any initial shape, but that the plume volume at the onset of this late-time behavior depends strongly on the initial shape even for weakly trapping systems. by Christopher William MacMinn. S.M.

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33

Holtman, Jade Aiden. "Geological modelling for carbon storage opportunities in the Orange Basin South Africa." University of the Western Cape, 2019. http://hdl.handle.net/11394/7019.

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>Magister Scientiae - MSc This study investigates the viability of the sedimentary deposits in the Northern Orange basin for carbon storage and sequestration. A combination of geological modelling, petrographic and geochemical techniques are used to investigate this scenario after an initial seismic-well tie had been performed to match the formation tops in Well AF-1 with the 3D seismic volume acquired in this basin in 2009. Core description of well AF-1 assisted in identifying different facies and samples taken at specific depths for petrographic and geochemical analyses, while different geological formations were mapped from the calibrated positions of seismic-well tie throughout the seismic volume. The well data and geophysical logs were utilized to generate petrophysical properties and used to calibrate observations made from seismic interpretations. The facies log used in this study was generated using the Python’s script on Petrel 2014 Gamma Ray, while the density log was used to generate the porosity log. The generated facies and porosity logs were upscaled and used to populate a 3D grid using faults and surfaces identified in the seismic volume. The sedimentological properties of the subsurface were identified utilizing petrographic descriptions including measurements of sorting, colour and grain sizes. While the mineralogical properties of the record was verified through XRD analyses and thin section. The facies and porosity modelling revealed the dominance of siltstones and sandstones as the main sedimentary facies throughout the sequence. Sandstones are extensive and prominent within the Cenozoic and Mastrichtian, while the unit dated to the Barremian is identified as having the best potential for CO2 storage based on the overlaying capping unit. Quartz, Plagioclase feldspar (Albite), Biotite and Kaolinite are the major minerals identified in all four samples. Each of these minerals has an implication for which may influence the long term storage of CO2 with the potential to form as they may form part of the inra-porous post-depositional cementation and hence change the porosity and permeability properties. The presence of Albite as observed on the XRD may predict possible mineralisation of CO2 to form Dawsonite when reservoir is injected with CO2. The Barremian sandstone which straddles the Aptian shale at the top and the Hauterivian Shale and Siltsone deposit at the bottom holds a good promise for a potential CO2 storage. An estimated volume of CO2 that could be stored in the reservoir of the Barremian sandstone in zone 8 is limited to the lateral seal of shale above the reservoir in zone 7 of the Aptian age. The method used to determine the potential storage capacity of CO2 was performed by Alexandros Tasianas and Nikolaos Koukouzas (2016). The Equation used to determine CO2 storage capacity is: mCO2 = RV * Ø * Sg * δ(CO2) . 2021-09-01

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Mullendore, Marina Anita Jacqueline. "Assessment of the Geological Storage Potential of Carbon Dioxide in the Mid-Atlantic Seaboard: Focus on the Outer Continental Shelf of North Carolina." Diss., Virginia Tech, 2019. http://hdl.handle.net/10919/100687.

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In an effort to mitigate carbon dioxide (CO2) emissions in the atmosphere, the Southeast Offshore Storage Resource Assessment (SOSRA) project has for objective to identify geological targets for CO2 storage in two main areas: the eastern part of the Gulf of Mexico and the Atlantic Ocean subsurface. SOSRA's second objective is to estimate the geological targets' capacity to store up to 30 million metric tons of CO2 each year with an error margin of ±30%. As part of this project, the research presented here focuses on the outer continental shelf of North Carolina and its potential for the deployment of large-scale offshore carbon storage in the near future. To identify geological targets, workflow followed typical early oil and gas exploration protocols: collecting existing datasets, selecting the most applicable datasets for reservoir exploration, and interpreting datasets to build a comprehensive regional geological framework of the subsurface of the outer continental shelf. The geomodel obtained can then be used to conduct static volumetric calculations estimating the storage capacity of each identified target. Numerous uncertainties regarding the geomodel were attributed to the variable coverage and quality of the geological and geophysical data. To address these uncertainties and quantify their potential impact on the storage capacity estimations, dynamic volumetric calculations (reservoir simulations) were conducted. Results have shown that, in this area, both Upper and Lower Cretaceous Formations have the potential to store large amounts of CO2 (in the gigatons range). However, sensitivity analysis highlighted the need to collect more data to refine the geomodel and thereby reduce the uncertainties related to the presence, dimensions and characteristics of potential reservoirs and seals. Reducing these uncertainties could lead to more accurate storage capacity estimations. Adequate injection strategies could then be developed based on robust knowledge of this area, thus increasing the probability of success for carbon capture and storage (CCS) offshore projects in North Carolina's outer continental shelf. Doctor of Philosophy

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35

Shen, Jiyun. "Reactive transport modeling of CO2 through cementitious materials under CO2 geological storage conditions." Phd thesis, Université Paris-Est, 2013. http://tel.archives-ouvertes.fr/tel-00861130.

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A reactive transport model is proposed to simulate the reactivity of cement based material in contact with CO2-saturated brine and supercritical CO2 (scCO2) under CO2 geological storage conditions. This code is developed to solve simultaneously transport and chemistry by a global coupled approach, considering the effect of temperature and pressure. The variability of scCO2 properties with pressure and temperature, such as solubility in water, density and viscosity are taken into account. It is assumed that all chemical processes are in thermodynamical equilibrium. Dissolution and precipitation reactions for portlandite (CH) and calcite (CC) are described by mass action laws and threshold of ion activity products in order to account for complete dissolved minerals. A chemical kinetics for the dissolution and precipitation of CH and CC is introduced to facilitate numerical convergence. One properly chosen variable is able to capture the precipitation and dissolution of the relevant phase. A generalization of the mass action law is developed and applied to calcium silicate hydrates (C-S-H) to take into account the continuous variation (decrease) of the Ca/Si ratio during the dissolution reaction of C-S-H. The changes in porosity and microstructure induced by the precipitation and dissolution reactions are also taken into account. Couplings between transport equations and chemical reactions are treated thanks to five mass balance equations written for each atom (Ca, Si, C, K, Cl) as well as one equation for charge balance and one for the total mass. Ion transport is described by using the Nernst-Plank equation as well as advection, while gas and liquid mass flows are governed by advection. Effect of the microstructure and saturation change during carbonation to transport properties is also considered. The model is implemented within a finite-volume code, Bil. Principles of this method and modeling approach are discussed and illustrated with the help of a simple example. This model, with all the efforts above, is able to simulate the carbonation processes for cement based materials, at both saturated and unsaturated conditions, in a wide CO2 concentration, temperature and pressure range. Several sets of experiments, including sandstone-like conditions, limestone-like conditions, supercritical CO2 boundary and unsaturated conditions reported in the literature are simulated. Good predictions are provided by the code when compared with experimental observations. Some experimental observed phenomena are also explained by the model in terms of calcite precipitation front, CH dissolution front, porosity profile, etc

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Tian, Liang. "CO2 storage in deep saline aquifers : Models for geological heterogeneity and large domains." Doctoral thesis, Uppsala universitet, Luft-, vatten och landskapslära, 2016. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-279382.

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This work presents model development and model analyses of CO2 storage in deep saline aquifers. The goal has been two-fold, firstly to develop models and address the system behaviour under geological heterogeneity, second to tackle the issues related to problem scale as modelling of the CO2 storage systems can become prohibitively complex when large systems are considered. The work starts from a Monte Carlo analysis of heterogeneous 2D domains with a focus on the sensitivity of two CO2 storage performance measurements, namely, the injectivity index (Iinj) and storage efficiency coefficient (E), on parameters characterizing heterogeneity. It is found that E and Iinj are determined by two different parameter groups which both include correlation length (λ) and standard deviation (σ) of the permeability. Next, the issue of upscaling is addressed by modelling a heterogeneous system with multi-modal heterogeneity and an upscaling scheme of the constitutive relationships is proposed to enable the numerical simulation to be done using a coarser geological mesh built for a larger domain. Finally, in order to better address stochastically heterogeneous systems, a new method for model simulations and uncertainty analysis based on a Gaussian processes emulator is introduced. Instead of conventional point estimates this Bayesian approach can efficiently approximate cumulative distribution functions for the selected outputs which are CO2 breakthrough time and its total mass. After focusing on reservoir behaviour in small domains and modelling the heterogeneity effects in them, the work moves to predictive modelling of large scale CO2 storage systems. To maximize the confidence in the model predictions, a set of different modelling approaches of varying complexity is employed, including a semi-analytical model, a sharp-interface vertical equilibrium (VE) model and a TOUGH2MP / ECO2N model. Based on this approach, the CO2 storage potential of two large scale sites is modelled, namely the South Scania site, Sweden and the Dalders Monocline in the Baltic Sea basin. The methodologies developed and demonstrated in this work enable improved analyses of CO2 geological storage at both small and large scales, including better approaches to address medium heterogeneity. Finally, recommendations for future work are also discussed.

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Nie, Zhenggang. "Life Cycle Modelling of Carbon Dioxide Capture and Geological Storage in Energy Production." Thesis, Imperial College London, 2009. http://hdl.handle.net/10044/1/9016.

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Carbon dioxide (CO2) capture and geological storage (CCS) is recognised as one of themain options in the portfolio of greenhouse gas (GHG) mitigation technologies beingdeveloped worldwide. The CO2 capture and storage technologies require significantamounts of energy during their implementation and also change the environmentalprofile of power generation. The holistic perspective offered by Life Cycle Assessment(LCA) enables decision makers to quantify the trade-offs inherent in any change to thepower production systems and helps to ensure that a reduction in GHG emissions doesnot result in significant increases in other environmental impacts. Early LCA studies ofpower generation with CCS report a wide range of results, as they focus on specific CO2capture cases only. Furthermore, previous work and commercial LCA software have arigid approach to system boundaries and do not recognise the importance of the level ofdetail that should be included in the Life Cycle Inventory (LCI) data. This research developed a complete LCA framework for the ?cradle-to-grave?assessment of alternative CCS technologies in carbon-containing fuel power generation. A comprehensive and quantitative Life Cycle Inventory (LCI) database, which modelsinputs/outputs of processes at high level of detail, accounts for technical and geographicdifferences, generates LCI data in a consistent and transparent manner was developedand arranged and flexible structure. The developed LCI models were successfully applied to power plants with alternativepost-combustion chemical absorption capture and oxy-fuel combustion capture. Theresults demonstrate that most environmental impacts come from power generation withCCS and the upstream process of coal production at a life-cycle perspective. LCAresults are sensitive to the type of coal used and the CO2 capture options chosen. Moreover, the models developed successfully trace the fate of elements (including tracemetals) of concern throughout the power generation, CO2 capture, transport andinjection chain. Monte Carlo simulation method combined with the LCI models wasapplied to quantify the uncertainty of emissions of concern. A novel analytical framework for the LCA of CO2 storage was also developed andapplied to a saline aquifer storage field case. The potential CO2 leakage rates werequantified and the operational and geological parameters that determine the ratio of CO2leakage total volume of CO2 injected were identified.

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Rasmusson, Kristina. "Modeling of geohydrological processes in geological CO2 storage – with focus on residual trapping." Doctoral thesis, Uppsala universitet, Luft-, vatten och landskapslära, 2017. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-327994.

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Geological storage of carbon dioxide (CO2) in deep saline aquifers is one approach to mitigate release from large point sources to the atmosphere. Understanding of in-situ processes providing trapping is important to the development of realistic models and the planning of future storage projects. This thesis covers both field- and pore-scale numerical modeling studies of such geohydrological processes, with focus on residual trapping. The setting is a CO2-injection experiment at the Heletz test site, conducted within the frame of the EU FP7 MUSTANG and TRUST projects. The objectives of the thesis are to develop and analyze alternative experimental characterization test sequences for determining in-situ residual CO2 saturation (Sgr), as well as to analyze the impact of the injection strategy on trapping, the effect of model assumptions (coupled wellbore-reservoir flow, geological heterogeneity, trapping model) on the predicted trapping, and to develop a pore-network model (PNM) for simulating and analyzing pore-scale mechanisms. The results include a comparison of alternative characterization test sequences for estimating Sgr. The estimates were retrieved through parameter estimation. The effect on the estimate of including various data sets was determined. A new method, using withdrawal and an indicator-tracer, for obtaining a residual zone in-situ was also introduced. Simulations were made of the CO2 partitioning between layers in a multi-layered formation, and parameters influencing this were identified. The results showed the importance of accounting for coupled wellbore-reservoir flow in simulations of such scenarios. Simulations also showed that adding chase-fluid stages after a conventional CO2 injection enhances the (residual and dissolution) trapping. Including geological heterogeneity generally decreased the estimated trapping. The choice of trapping model may largely effect the quantity of the predicted residual trapping (although most of them produced similar results). The use of an appropriate trapping model and description of geological heterogeneity for a site when simulating CO2 sequestration is vital, as different assumptions may give significant discrepancies in predicted trapping. The result also includes a PNM code, for multiphase quasi-static flow and trapping in porous materials. It was used to investigate trapping and obtain an estimated trapping (IR) curve for Heletz sandstone.

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Gomes, Ana Sofia Ferrada. "Matching CO2 large point sources and potential geological storage sites in mainland Portugal." Master's thesis, FCT - UNL, 2008. http://hdl.handle.net/10362/1884.

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Dissertação apresentada na Faculdade de Ciências e Tecnologia da Universidade Nova de Lisboa para obtenção do grau de Mestre em Engenharia do Ambiente, Perfil Gestão e Sistemas Ambientais Fossil fuel combustion is the major source of the increasing atmospheric concentration of carbone dioxide (CO2) since the pre-industrial period. Combustion systems like power plants, cement, iron and steel production plants and refineries are the main stationary sources of CO2 emissions. The reduction of greenhouse gas emissions in one of the main climate change mitigation measures. Carbon dioxide capture and storage (CCS) is one of the possible mitigation measures. The objective of this study was to analyze the hypothesis for the implementation of CCS systems in mainland Portugal based on source-sink matching. The CO2 large point sources (LPS) considered in mainland Portugal were the largest installations included in the Phase II of the European Emissions Trading Scheme with the highest CO2 emissions, representing about 90% of the total CO2 emissions of the Trading Scheme, verified in 2007. The potential geological storage locations considered were the geological formations formerly identified in existing studies. After the mapping of LPS and potential geological sinks of mainland Portugal, an analysis based on the proximity of the sources and storage sites was performed. From this it was possible to conclude that a large number of LPS are within or near the potential storage areas. An attempt of estimating costs of implementing a CCS system in mainland Portugal was also performed, considering the identified LPS and storage areas. This cost estimate was a very rough exercise but can allow an order of magnitude of the costs of implementing a CCS system in mainland Portugal. Preliminary results suggest that at present CCS systems are not economically interesting in Portugal, but this may change with increasing costs of energy and emission permits. The present lack of information regarding geological storage sites is an important limitation for the assessment of implementing a CCS system in mainland Portugal. Further detailed studies are required, starting with the characterisation of geological sites and the candidate sources to CCS, from technical aspects to environmental and economical factors.

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Andin, Eric. "Relationship Between Hekla’s Magmatic System and Its Eruptive Behavior." Thesis, Uppsala universitet, Institutionen för geovetenskaper, 2017. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-329521.

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The southern part of Iceland incorporates two parallel volcanic zones, the Eastern Volcanic Zone and the Western Volcanic Zone. These two branches are connected by an E-W transform. Hekla is located close to intersection between the two plate boundaries. Hekla is one of Iceland's most active and explosive volcanoes. Unique to Hekla is that it is one of the few volcanoes on Iceland that produces explosive silica rich magma. Hekla gives no clear warning of its eruptions and sends out seismic signals with very short notice. It is therefore of interest to try to understand Hekla's magma system and magmatic processes in order to gain an increased knowledge of its volcanic processes. The study is based on calculating crystallization conditions for the minerals plagioclase, clinopyroxene and orthoproxene. Calculations is based on the assumption that minerals, which are in equilibrium with the associated melt are directly associated with the thermodynamics of crystallization. The result of the study shows that Hekla's magma chamber is located at a depth of 8-12 km. The samples from Hekla are poor in minerals, which can be explained by separation due to fractional crystallization that forms a crystal mush. Fast ascending primitive magma along with degassing will eventually lead to an eruption. The absence of crystal zoning indicates a limited chance of magma mixing or crustal contamination. Oxides related to the eruption tend to comprise a low titanium content, which is related with an increased pressure condition. Geospeedometry suggested that recharge occurred up to 10 days before eruption. Erupted oxides shows up to 30 years residence which suggest long-term crystal mush. Hekla är en av Islands mest aktiva och explosiva vulkan. Dess vulkaniska beteende grundar sig i det underliggande magma systemet samt kompositionen av magman. Unikt för Hekla är att det är en av få vulkaner på Island som producerar explosiv kiselrik magma. Hekla sänder dessutom inte ut tydliga varnings signaler innan utbrott. Det är därför av intresse att försöka förstå Heklas magma system och magmatiska processer för att kunna få en ökad uppfattning om dess vulkaniska processer.Undersökningen grundar sig i att beräkna kristalliseringsförhållanden för mineralerna plagioklas, klinopyroxen samt ortopyroxen. Resultatet av studien påvisar att Heklas magmaförvar är belägget på ett djup av 8-12 km. Proverna från Hekla har varit fattiga i mineraler vilket kan förklaras genom att mineraler har separerats från magman genom kristallisering. Magmas komposition kommer därför att ändras i och med att mineraler som kristalliserats tar bort element från den. Mineralkristallerna bildar sedan en egen zon som innefattar en liten del magma. Utbrotten triggas sedan när varm mafisk magma från ett större djup infiltrerar den grunda magma kammaren samt frisläppandet av gaser som sker vid kristallisering av mineraler.Beräkningar av tiden det tar för oxider att svalna tyder på att ny magma har infiltrerat magma kammaren upp till 10 dagar innan utbrottet. Den nya magman hinner inte blanda sig med den mer utvecklade magman. Detta event skulle leda till att kluster av mineral skulle följa med i utbrottssekvensen. Ett antal oxider visar även på att det börjat svalna upp till 30 år sedan, vilket kan förklaras av en zon bestående av kristaller.

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Lu, Jiemin. "CO2 interaction with aquifer and seal on geological timescales : the Miller oilfield, UK North Sea." Thesis, University of Edinburgh, 2008. http://hdl.handle.net/1842/2568.

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Carbon Capture and Storage (CCS) has been identified as a feasible technology to reduce CO2 emissions whilst permitting the continued use of fossil fuels. Injected CO2 must remain efficiently isolated from the atmosphere on a timescale of the order of 10000 years and greater. Natural CO2-rich sites can be investigated to understand the behaviour of CO2 in geological formations on such a timescale. This thesis examines the reservoir and seal on one such oilfield. Several hydrocarbon fields in the South Viking Graben of the North Sea naturally contain CO2, which is thought to have charged from depth along the western boundary fault of the graben. The Miller oil field which contains ~ 28 mol% CO2, of isotopic composition δ13C = -8.2‰. The Upper Jurassic Brae Formation reservoir sandstones and the Kimmeridge Clay Formation (KCF) seal have been exposed to the CO2 accumulation since its emplacement. Rock samples from the reservoir sandstone and bottom of the seal mudrock were examined using multiple techniques, including XRD, SEM, fluid inclusion and carbonate stable isotope analyses. The sandstones show no features directly attributable to abundant CO2 charge. SEM analyses reveal significant heterogeneities in diagenesis within the KCF. The silt/sand lithologies of the KCF have undergone a diagenetic history similar to that of the Brae Formation sandstones. In contrast, the KCF shales display a distinctly different diagenesis of dominant dissolution of quartz and feldspar with little evidence of mineral precipitation. In both the Brae Formation and the KCF, pore-filling kaolinite, illite and carbonates are relatively late diagenetic events which can be associated with CO2-induced feldspar dissolution. Mudrock X-ray diffraction mineralogical data reveal abrupt vertical mineralogical variations across the reservoir crest in the Miller Field, while such variations are absent in a low-CO2 control well in the same geological settings. This suggests that reactions induced by abundant CO2 dissolved feldspar and produced kaolinite, carbonates and quartz in the seal, while oil emplacement inhibited the reactions in the oil leg. However, petrographic evidence and comparison between different sections argue against CO2 reactions as the sole cause for such large mineralogical variations, especially for quartz. The vertical mineralogical variations to a certain extend represent original sedimentary heterogeneity. Linear variations of carbonate δ13C with depth were discovered in both shale and silt/sand lithologies of the KCF in a 12m zone immediately above the reservoir. These features are absent in the low-CO2 control well. These trends are interpreted as dissolution of original carbonates by CO2 slowly ascending from the reservoir. New carbonates precipitated from a carbon source with upwards decreasing δ13C due to mixing between three carbon sources with different C isotopes at systematically varying ratios. The isotopes in the reservoir and the bottom of the seal suggests initial CO2 charge at about 70-80 Ma. CO2 infiltration rate is estimated at about 9.8×10-7g·cm-2·y-1. Geochemical modelling was applied to reconstruct the reservoir fluid evolution by calibrating it to mineralogy, fluid chemistry, diagenesis and fluid inclusion data. The modelling suggests that CO2 migrated into the reservoir together with a saline basinal fluid derived from the underlying evaporites at ~ 70 Ma. The CO2 and basinal water charge imposed an important influence on the mineral reactions and fluid chemistry. This study suggests that the KCF has formed an excellent CO2 seal, with no substantial breach since its charge at 70-80 Ma.

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BASILE, FRANCYANE ROZESTOLATO. "ANALYSIS OF WAG-CO2 INJECTION FOR OIL RECOVERY AND GEOLOGICAL STORAGE OF CARBON DIOXIDE." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2015. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=26866@1.

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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO A redução drástica no valor do barril de petróleo em decorrência do crescimento desacelerado das maiores economias do mundo e da queda no consumo está promovendo uma mudança no comportamento da Indústria de Petróleo, uma vez que a redução dos custos de produção associado ao aumento da produtividade é essencial para o setor. Além disso, os aspectos ambientais estão em evidencia devido ao aumento da temperatura global nos últimos anos. Sendo assim, o Método de Recuperação Avançado WAG (Water Alternating Gas) com injeção de dióxido de carbono (CO2) é capaz de aliar aumento de produção de óleo com redução da emissão de dióxido de carbono na atmosfera. Essa dissertação tem o objetivo de estudar o efeito do WAG-CO2 sobre o fator de recuperação e sequestro de dióxido de carbono em reservatório arenítico. Para isso, serão realizadas simulações numéricas de fluxo contínuo em modelos blackoil e composicional utilizando as ferramentas WinProp, Builder, IMEX e GEM, do pacote de simuladores da CMG (Computer Modelling Group). Sendo o IMEX usado para modelos black-oil e o GEM para composicional. O conhecimento das permeabilidades, fenômenos de histerese e tensão interfacial para a simulação numérica são fundamentais para definir o plano de desenvolvimento e as variáveis do processo, responsáveis pelo acréscimo do fator de recuperação e economicidade. Porém, o IMEX e o GEM não permitem que a tensão interfacial e histerese sejam estudos simultaneamente. O fator de recuperação das simulações considerando tensão interfacial foram, em média, 3 por cento maiores que para os casos com histerese, e 0,6 por cento superiores nas injeções iniciando com o gás. Além disso, o aumento no número de poços produtores e injetores melhorou o varrido do reservatório, porém, aspectos como pressão do reservatório, produção de gás e de água devem ser monitorados. The drastic reduction in the amount of oil as a result of slowed growth of the world s largest economies and the fall in consumption, is promoting a change in the behavior of the Petroleum Industry, since the reduction in production costs coupled with increased productivity is essential for the sector. Moreover, environmental aspects are evident due to the global temperature rise in recent years.Therefore the Advanced Recovery Method WAG (Water Alternating Gas) with carbon dioxide injection (CO2) is able to combine oil production increase with a reduction in carbon dioxide emissions in the atmosphere. This dissertation is intended to study the effect of WAG-CO2 on the recovery factor and carbon dioxide sequestration in sandstone reservoir. For this, numerical simulations streaming will be held in black-oil and compositional models using the WinProp tools, Builder, IMEX and GEM, the simulator package CMG (Computer Modelling Group). Being the IMEX used for black-oil models and the GEM to compositional. Knowledge of permeability, hysteresis phenomena and interfacial tension for the numerical simulation are essential to define the development plan and the process variables responsible for the increase in the recovery factor and economy. However, IMEX and GEM not allow the interfacial tension and hysteresis be studied simultaneously. The result of simulations for interfacial tension were, on average, greater than 3 percent for the cases with hysteresis, and 0.6 percent higher in injections with starting gas. Furthermore, the increase in number of producing and injection wells improved sweep of the reservoir, however, aspects such as reservoir pressure, gas production and water must be monitored.

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Carruthers, Christopher Ian Andrew. "Metal mobility in sandstones and the potential environmental impacts of offshore geological CO2 storage." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/20377.

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Geological carbon dioxide (CO2) storage in the United Kingdom (UK) will likely be entirely offshore, which may lead to the production and disposal into the sea of reservoir waters to increase storage capacity, or through CO2-Enhanced Oil Recovery (CO2-EOR). These produced waters have the potential to contain significant concentrations of trace metals that could be of harm to the environment. Batch experiments with CO2, warm brines, and reservoir sandstones were undertaken for this thesis to determine concentrations of 8 trace metals (arsenic, cadmium, chromium, copper, mercury, nickel, lead, zinc) which could be leached during CO2 storage in 4 UK North Sea hydrocarbon reservoirs. A sequential extraction procedure (SEP) was also used to determine the potential mobility of these metals under CO2 storage from mineral phases making up the reservoir samples. The results broadly showed that mobilised trace metal concentrations were low (parts per billion, ppb) in the batch experiments, with the exceptions of nickel and zinc. These metals were associated with carbonate and some feldspar dissolution, with other metals apparently desorbed from mineral surfaces, probably clays. The results of the SEP, however, were a poor predictor of actual mobility with respect to the batch experiments, although useful in determining the distribution of trace metals within the defined mineral phases (water soluble, ion exchangeable, carbonate, oxide, sulphide, silicate). In addition, fieldwork was carried out at Green River, Utah, to collect 10 CO2-driven spring water samples and 5 local aquifer rock samples. This area was used as a natural analogue for CO2-mobilised trace metals from sandstone aquifers. Trace metal concentrations in spring waters were very low (ppb) and batch experiments using Utah rock samples, spring water collected from Crystal Geyser, and CO2 confirmed very low mobility of these metals. The SEP was repeated for the Utah reservoir rocks, but again was not a reliable predictor for actual mobility, other than to confirm that overall bulk concentrations of trace metals was low. Comparison of trace metal concentrations from the batch experiments with data from UK North Sea oil and gas produced waters shows that overall, concentrations mobilised in batch experiments are within the range of concentrations across all North Sea fields reporting their data. However, on a field-by-field basis, some CO2 mobilised concentrations exceeded those currently produced by oil and gas activities. Furthermore, average batch experiment trace metal loads are higher than average oil and gas produced waters, and in some cases exceed international guidelines. Therefore, while the majority of trace metals have low mobility and therefore low environmental impact, this should be assessed on a case-by-case basis. Regular monitoring of dissolved constituents in produced waters carried should also be carried out, particularly in the initial stages of CO2 storage operations, with remedial action taken as required to reduce the environmental impact of offshore carbon capture and storage.

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Lincoln, Darren L. "Theoretical and numerical aspects of modelling geological carbon storage with application to muographic monitoring." Thesis, University of Sheffield, 2015. http://etheses.whiterose.ac.uk/15693/.

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The storage of waste carbon dioxide (CO2) from fossil fuel combustion in deep geological formations is a strategy component for mitigating harmfully increasing atmospheric concentrations to within safe limits. This is to help prolong the security of fossil fuel based energy systems while cleaner and more sustainable technologies are developed. The work of this thesis is carried out as part of a multi-disciplinary project advancing knowledge on the modelling and monitoring of geological carbon storage/sequestration (GCS). The underlying principles for mathematically describing the multi-physics of multiphase multicomponent behaviour in porous media are reviewed with particular interest on their application to modelling GCS. A fully coupled non-isothermal multiphase Biot-type double-porosity formulation is derived, where emphasis during derivation is on capturing the coupled hydro-thermomechanical (HTM) processes for the purposes of study. The formulated system of governing field equations is discretised in space by considering the standard Galerkin finite element procedure and its spatial refinement in the context of capturing coupled HTM processes within a GCS system. This presents a coupled set of nonlinear first-order ordinary differential equations in time. The system is discretised temporally and solved using an embedded finite difference method which is schemed with control theoretical techniques and an accelerated fixed-point-type procedure. The developed numerical model is employed to solve a sequence of benchmark problems of increasing complexity in order to comprehensively study and highlight important coupled processes within potential GCS systems. This includes fracture/matrix fluid displacement, formation deformation and Joule-Thomson cooling effects. The computational framework is also extended to allow for the simulation of cosmic-ray muon radiography (muography) in order to assess the extent to which detected changes in subsurface muon flux due to CO2 storage can be used to monitor GCS. This study demonstrates promise for muography as a novel passive-continuous monitoring aid for GCS.

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Benvenutti, Carlos Felipe [UNESP]. "Estudo da porção offshore da bacia do Benin e o seu potencial no armazenamento de hidrocarbonetos, margem equatorial africana." Universidade Estadual Paulista (UNESP), 2012. http://hdl.handle.net/11449/92925.

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Made available in DSpace on 2014-06-11T19:26:14Z (GMT). No. of bitstreams: 0 Previous issue date: 2012-04-20Bitstream added on 2014-06-13T18:47:38Z : No. of bitstreams: 1 benvenutti_cf_me_rcla.pdf: 5702564 bytes, checksum: 3468aeafad128f8380c10b5ae674509f (MD5) A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades... The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below)

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Benvenutti, Carlos Felipe. "Estudo da porção offshore da bacia do Benin e o seu potencial no armazenamento de hidrocarbonetos, margem equatorial africana /." Rio Claro : [s.n.], 2012. http://hdl.handle.net/11449/92925.

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Resumo: A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades... (Resumo completo, clicar acesso eletrônico abaixo) Abstract: The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below) Orientador: Nelson Angeli Coorientador: Maria Gabriela C. Vincetelli Banca: George Luiz Luvizotto Banca: Adilson Viana Soares Júnior Mestre

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Miocic, Johannes Marijan. "A study of natural CO₂ reservoirs : mechanisms and pathways for leakage and implications for geologically stored CO₂." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/17881.

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Carbon Capture and Storage (CCS) is a suite of technologies available to directly reduce carbon dioxide (CO2) emissions to the atmosphere from fossil fuelled power plants and large industrial point sources. For a safe deployment of CCS it is important that CO2 injected into deep geological formations does not migrate out of the storage site. Characterising and understanding possible migration mechanisms and pathways along which migration may occur is therefore crucial to ensure secure engineered storage of anthropogenic CO2. In this thesis naturally occurring CO2 accumulations in the subsurface are studied as analogue sites for engineered storage sites with respect to CO2 migration pathways and mechanisms that ensure the retention of CO2 in the subsurface. Geological data of natural CO2 reservoirs world-wide has been compiled from published literature and analysed. Results show that faults are the main pathways for migration of CO2 from subsurface reservoirs to the surface and that the state and density of CO2, pressure of the reservoir, and thickness of the caprock influence the successful retention of CO2. Gaseous, low density CO2, overpressured reservoirs, and thin caprocks are characteristics of insecure storage sites. Two natural CO2 reservoirs have been studied in detail with respect to their fault seal properties. This includes the first study of how fault rock seals behave in CO2 reservoirs. It has been shown that the bounding fault of the Fizzy Field reservoir in the southern North Sea can with hold the amount of CO2 trapped in the reservoir at current time. A initially higher gas column would have led to across fault migration of CO2 as the fault rock seals would not have been able to withhold higher pressures. Depending on the present day stress regime the fault could be close to failure. At the natural CO2 reservoir of St. Johns Dome, Arizona, migration of CO2 to the surface has been occurring for at least the last 500 ka. Fault seal analysis shows that this migration is related to the fault rock composition and the orientation of the bounding fault in the present day stress field. Using the U-Th disequilibrium method the ages of travertine deposits of the St. Johns Dome area have been determined. The results illustrate that along one fault CO2 migration took place for at least 480 ka and that individual travertine mounds have had long lifespans of up to ~350 ka. Age and uranium isotope trends along the fault have been interpreted as signs of a shrinking CO2 reservoir. The amount of CO2 calculated to have migrated out of the St. Johns Dome is up to 113 Gt. Calculated rates span from 5 t/yr to 30,000 t/yr and indicate that at the worst case large amounts of CO2 can migrate rapidly from the subsurface reservoir along faults to the surface. This thesis highlights the importance of faults as fluid pathways for vertical migration of CO2. It has been also shown that they can act as baffles for CO2 migration and that whether a fault acts as pathway or baffle for CO2 can be predicted using fault seal analysis. However, further work is needed in order to minimise the uncertainties of fault seal analysis for CO2 reservoirs.

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Okwananke, Anthony. "Flue gas injection for methane recovery from gas hydrate reservoirs and geological Storage of CO2." Thesis, Heriot-Watt University, 2017. http://hdl.handle.net/10399/3395.

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The global energy system has been gradually de-carbonised over the years, from wood to coal, coal to oil, and then natural gas. Natural gas hydrates with their abundance in nature, therefore represent a potentially significant new clean energy source for the future. A few field trials have been conducted to recover natural gas (methane) from gas hydrate reservoirs. While the outcomes of these trials offer a glimmer of hope on the possibility of methane production from gas hydrate resources, there remains the nagging question of production sustainability as most field trials are short-lived due to high energy penalty, sand management issues, excessive water production, and potential environmental risks. This thesis reports the development of a novel technique for methane recovery from natural gas hydrate reservoirs by flue gas injection. Compared to the existing methods, the principal concept of the technique is to break the thermodynamic equilibrium of methane hydrate by flue gas injected, causing a shift in the equilibrium phase boundary to accommodate the presence of flue gas while releasing methane from hydrate dissociation. A series of experiments were conducted at different simulated hydrate reservoir conditions to demonstrate the feasibility of the technique vis-à-vis understanding how methane hydrate decomposes in the presence of flue gas, the impact of flue gas on the depressurisation process, and the possibility of the CO2 component in the flue gas being sequestered as CO2 or CO2-mixed hydrates. Furthermore, the impact of the excess aqueous phase, salinity, and sediment mineralogy on methane recovery were also investigated. Finally, peculiarities of gas flow in hydrate-bearing sediments were also investigated and modelled with existing permeability models. Results indicated significant dissociation of methane hydrate by a shift in the methane hydrate equilibrium phase boundary leading to a rise in methane concentration in the vapour phase. Enhanced methane recovery by depressurisation in the presence of flue gas generated a methane-rich vapour phase of up to 80 mol% methane at experimental conditions within the methane hydrate stability zone (HSZ). CO2 hydrate, N2-CO2-CH4 hydrate, and CO2-CH4 were formed simultaneously alongside methane recovery after flue gas injection. Up to 70% of CO2 in the vapour phase was captured and retained in the hydrate phase. Increased aqueous phase salinity enhanced methane recovery and increased CO2 capture and storage in excess water environments. Extension of the concept to air and nitrogen injection showed enhance depressurisation compared to flue gas injection with up to 90 mol% methane in the vapour phase at conditions still within the methane HSZ. It is also flexible, with the possibility of stepwise depressurisation with continuous and incremental methane recovery. Potentially these techniques are economically feasible as they save on costs in terms of thermal energy supply and chemical additives. On the operational front, it is not subject to injectivity constraints due to secondary hydrate formation. It also has the capacity to maintain reservoir energy, limit water production, and deliver better sand management. Additionally, direct capture and storage of CO2 from flue gas could provide huge savings in carbon capture and storage processes.

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PEREIRA, FERNANDA LINS GONCALVES. "SEMI-QUANTITATIVE METHODOLOGY FOR ASSESSING THE RISK OF CO2 INJECTION FOR STORAGE IN GEOLOGICAL RESERVOIRS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2015. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=27549@1.

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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO CONSELHO NACIONAL DE DESENVOLVIMENTO CIENTÍFICO E TECNOLÓGICO A última etapa do sequestro e armazenamento de carbono (CCS) pode ser realizada pela de injeção de CO2 em reservatórios geológicos. Projetos de CCS fazem parte de uma série de técnicas para a mitigação dos gases do efeito estufa. Neste trabalho, uma metodologia semi-quantitativa para avaliação do risco da injeção de CO2 em reservatórios geológicos é apresentada. Essa metodologia é desenvolvida a partir da criação e utilização de uma matriz de risco. Essa matriz possui em uma direção categorias de severidade ajustadas de forma qualitativa e na outra direção categorias de probabilidade ajustadas a partir de análises probabilísticas. Os valores de risco de uma fonte de perigo são calculados pelo produto de suas severidades com suas probabilidades associadas. As fontes de perigo são problemas relacionados à injeção de CO2 que são selecionadas para análise de um cenário específico. As categorias de severidade são definidas por faixas de níveis de funcionamento de uma fonte de perigo. Diversos métodos de análise probabilística são investigados e a família de métodos do valor médio apresenta características favoráveis ao seu emprego em funções de estado limite complexas. A metodologia é aplicada em um estudo de caso ilustrativo. Com os valores de risco resultantes, faz-se a identificação da principal fonte de perigo e das variáveis aleatórias mais influentes. A avaliação da metodologia indica que ela é uma ferramenta poderosa para os analistas e tomadores de decisão, e tem potencial para auxiliar na fase de planejamento de projetos de CCS. The last stage of carbon capture and sequestration (CCS) can be performed by CO2 injection process in geological reservoirs. CCS projects belong to a number of ways to mitigate greenhouse gases. In this work, a semi-quantitative methodology to assess the risk of CO2 injection in geological reservoirs is developed. This methodology is based on the establishment and application of a risk matrix. This matrix has in one direction severity categories set in a qualitative way and in the other direction probability categories set from probabilistic analysis. The risk values of a hazard source are calculated by the product of their severities with their associated probabilities. Hazard sources are problems related to the injection of CO2 that are selected for a specific scenario analysis. The severity categories are defined by operating level ranges of a hazard source. Several probabilistic analysis methods are investigated and the family of the mean value methods shows characteristics favoring their use in complex limit state functions.The methodology is applied in an illustrative case study. With the resulting risk values, the identification of the main hazard source and the most inuential random variables are made. Assessment of the methodology indicates that it is a powerful tool for analysts and decision makers, and it has the potential to assist in the CCS project planning phase.

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Andres, Jeanne Therese Hilario. "The interaction of chemical kinetics and fluid flow in the geological storage of carbon dioxide." Thesis, University of Cambridge, 2013. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.608059.

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Dissertations / Theses on the topic 'Geologic storage'

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