Experimental measurements and characterization models of caprock breakthrough pressure for CO2 geological storage
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Cited by 3 publications
References 128 publications
Quantitative assessment of CO2 leakage risk in geologic carbon storage management
Large‐scale geological storage of carbon dioxide (CO2) is indispensable for mitigating climate change but faces significant challenges, especially in the accurate quantitative assessment of leakage risks to ensure long‐term security. Given these circumstances, this paper proposes an innovative approach for quantitatively assessing CO2 leakage risk to address the previous limitations of limited accuracy and insufficient data. We construct a fault tree and transform it into a Bayesian network–directed acyclic graph, and then use judgment sets along with fuzzy set theory to obtain prior probabilities of root nodes. The feature, event, and process method was utilized to identify key components and subsequently determine the conditional probability table (CPT) of the leaf node. The subjective experience assessments from experts are defuzzified to obtain the CPTs of intermediate nodes. The obtained basic probability parameters are input into the directed acyclic graph to complete the model construction. After calculating the leakage probability using this model, it is combined with the severity of impacts to conduct a comprehensive risk assessment. Furthermore, critical CO2 risk sources can be determined through posterior probability calculations when intermediate nodes are designated as deterministic risk events. The gradual implementation process of the proposed model is demonstrated via a typical case study. The results indicate an overall CO2 leakage probability of 29%, with probabilities of leakage along faults/fractures, caprock, and well identified as 32%, 28%, and 19%, respectively. The project is categorized as a medium‐low risk level. When leakage is confirmed, tectonic movement, thickness, and delamination at interface connections/the presence of cracks are the critical risk sources, and measures to mitigate key risks are outlined. The identified key risk factors conform to empirical evidence and previous research, validating the accuracy of the model. This study is instrumental in CO2 geological storage risk assessment and scalable development program design. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.
Quantitative assessment of CO2 leakage risk in geologic carbon storage management
Large‐scale geological storage of carbon dioxide (CO2) is indispensable for mitigating climate change but faces significant challenges, especially in the accurate quantitative assessment of leakage risks to ensure long‐term security. Given these circumstances, this paper proposes an innovative approach for quantitatively assessing CO2 leakage risk to address the previous limitations of limited accuracy and insufficient data. We construct a fault tree and transform it into a Bayesian network–directed acyclic graph, and then use judgment sets along with fuzzy set theory to obtain prior probabilities of root nodes. The feature, event, and process method was utilized to identify key components and subsequently determine the conditional probability table (CPT) of the leaf node. The subjective experience assessments from experts are defuzzified to obtain the CPTs of intermediate nodes. The obtained basic probability parameters are input into the directed acyclic graph to complete the model construction. After calculating the leakage probability using this model, it is combined with the severity of impacts to conduct a comprehensive risk assessment. Furthermore, critical CO2 risk sources can be determined through posterior probability calculations when intermediate nodes are designated as deterministic risk events. The gradual implementation process of the proposed model is demonstrated via a typical case study. The results indicate an overall CO2 leakage probability of 29%, with probabilities of leakage along faults/fractures, caprock, and well identified as 32%, 28%, and 19%, respectively. The project is categorized as a medium‐low risk level. When leakage is confirmed, tectonic movement, thickness, and delamination at interface connections/the presence of cracks are the critical risk sources, and measures to mitigate key risks are outlined. The identified key risk factors conform to empirical evidence and previous research, validating the accuracy of the model. This study is instrumental in CO2 geological storage risk assessment and scalable development program design. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.
Adapting Conventional Laboratory Protocols to Characterize Rock-Fluid Systems to Comply with CCS Regulations
The characterization of the rock-fluid system is a fundamental step for planning, implementation and monitoring of Carbon Capture, Utilization, and Storage (CCUS) projects. The evaluation and understanding of the of the rock-fluid interaction properties are required for the storage selection to determine whether a geological formation is suitable for CO2 storage, to ensure an effective injection and safe containment of CO2 to prevent leakage or migration, to verify if the CO2 remains trapped in the formation and does not migrate to the surface or deep aquifers, to comply with regulations, and to minimize environmental impacts. To characterize rock-fluid properties, special core analysis (SCAL) is used. Those tests include the evaluation of the wettability, capillary pressure, and relative permeability between other properties. There are several SCAL methods that have been adopted worldwide through best practices and lessons learned; however, they were developed for general reservoir evaluation and there are no standards associated to their use to evaluate the feasibility of CSS/CCUS projects, making the evaluation of these properties more complex. It is also important to consider that each project is unique due to the nature of the reservoir rock, fluids, and conditions (temperature, pressure, salinity, etc.), so to meet regulatory framework, the results obtained for a specific formation cannot be used to predict the parameters in a different one. This work's objective is to contribute to the establishment of laboratory protocols that can be used for CSS/CCUS to comply with regulations. A laboratory protocol is proposed adopting existing SCAL methods to characterize rock-fluid systems according to the rock and fluid types. The protocol starts with recommendations to select representative rock and fluid samples, the initial characterization of the physical properties (porosity, permeability and grain density) of the rock, and the advanced testing including the evaluation of pore volume changes in presence of CO2, seals characterization for geomechanically modeling, trapping mechanisms, mobility, capillary pressure and the threshold pressure, injectivity, reactions between the CO2 and the rock and fluids in the storage site, and the relative permeability. The SCAL protocol for CCUS was developed using reported laboratory practices reported in the literature and based on our own experience aimed to get more reliable data and hence a more precise reservoir model. The proposed laboratory protocol includes three main phases: (1) Selection and preparation of representative rock samples and fluids. (2) Static testing at reservoir conditions to evaluate the effect of the rock-fluid interaction over time and assess the potential damage to the rock when the CO2 interacts with the rock and the reservoir fluids. (3) Dynamic experiments to evaluate the flow properties required for reservoir modeling and simulation including capillary pressure, injectivity and relative permeability. Formation damage testing is included in the third phase aimed to assess the potential damage associated with the CO2 injection and to understand mechanisms involved in the fluids flow through the porous media. In each phase of the laboratory protocol, a quality assurance check is included to ensure the repeatability of the data. The proposed protocol is recommended to get the required information for permits, project planning and execution. It has been used to successfully characterize several formations selected for carbon storage. Examples of application of the proposed protocol are analyzed and presented as part of the results. From these studies, recommendations for an accurate characterization of the rock-fluid system are presented as lesson learned to minimize the risks associated to the CO2 injection into the geological formation, including the need to perform experiments under the right simulated reservoir conditions (temperature, pressure), the importance of having representative rock and fluid samples, the proper handle of samples, and the selection of the method to get the fluid-rock interaction parameters according to reservoir type. Recommendations about the best materials to be used to set up the core flood apparatus and examples of failures associated with the use of wrong materials are included. Lessons learned through experience, after completing several formation evaluation projects focused on CSS/CCUS, aimed to optimize laboratory evaluation of rock-fluid properties are translated in cost and time reduction.
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