Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802979
A. Chadwick, G. Williams
The Sleipner injection operation has stored over 17 Mt of CO2. Time-lapse seismic monitoring has provided high resolution images of CO2 plume development, constraining and verifying numerical flow simulations. Seismic velocity is a key diagnostic parameter for CO2 layer properties and we adopt a forensic interpretative approach to determine velocity variation in the topmost layer of the plume. The 2010 seismic dataset enables, for the first time, temporal thicknesses of the layer to be determined, taking into account interference-induced time-shifts. Combining these with CO2 layer thicknesses determined from structural analysis of the topseal topography allows layer velocity to be mapped. A marked spatial variation in velocity is evident across the layer with higher velocities (1630±103 ms-1) in the central part of the layer contrasting with lower values (~1370± 122 ms-1) to the north. Recent published work has identified a north-trending channel in the topmost Utsira sand unit, which greatly improves history-matching of the topmost CO2 layer with numerical flow simulations. This channel correlates almost exactly with the low velocity area mapped from the seismic, the higher velocity area corresponding to less permeable overbank deposits. The seismic therefore provides key corroborative evidence of permeability heterogeneity within the reservoir sand.
{"title":"Forensic Mapping Of Spatial Velocity Heterogeneity In A CO2 Layer At Sleipner Using Time-Lapse 3D Seismic Monitoring","authors":"A. Chadwick, G. Williams","doi":"10.3997/2214-4609.201802979","DOIUrl":"https://doi.org/10.3997/2214-4609.201802979","url":null,"abstract":"The Sleipner injection operation has stored over 17 Mt of CO2. Time-lapse seismic monitoring has provided high resolution images of CO2 plume development, constraining and verifying numerical flow simulations. Seismic velocity is a key diagnostic parameter for CO2 layer properties and we adopt a forensic interpretative approach to determine velocity variation in the topmost layer of the plume. The 2010 seismic dataset enables, for the first time, temporal thicknesses of the layer to be determined, taking into account interference-induced time-shifts. Combining these with CO2 layer thicknesses determined from structural analysis of the topseal topography allows layer velocity to be mapped. A marked spatial variation in velocity is evident across the layer with higher velocities (1630±103 ms-1) in the central part of the layer contrasting with lower values (~1370± 122 ms-1) to the north. Recent published work has identified a north-trending channel in the topmost Utsira sand unit, which greatly improves history-matching of the topmost CO2 layer with numerical flow simulations. This channel correlates almost exactly with the low velocity area mapped from the seismic, the higher velocity area corresponding to less permeable overbank deposits. The seismic therefore provides key corroborative evidence of permeability heterogeneity within the reservoir sand.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134454191","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201803002
A. Zappone, A. Rinaldi, M. Grab, A. Obermann, M. Claudio, C. Nussbaum, S. Wiemer
A key challenge for CO2 geological storage is the integrity of the caprock. This challenge is addressed by executing a decameter-scale experiment at the Mont Terri Underground Rock Laboratory in Switzerland, under the umbrella of ELEGANCY (Enabling a Low-Carbon Economy via Hydrogen and CCS). ELEGANCY is an European project aiming at advance sustainable geo-energy processes through studies on risk mitigation, characterization and public perception, whose achievements will benefit the fields of carbon dixode sequestration. The experiment will investigating the mechanisms and the physical parameters governing the migration of CO2-rich brine through a faults. In particular, the test seeks to understand the conditions for slip activation (seismic vs. aseismic slip) and the stability of clay faults, as well as the coupling between fault slip, pore pressure, fluid migration and possible induced “micro” seismicity. To this end, we will inject CO2-rich brine into the fault core for a period of about eight months, while monitoring its geo-mechanical response. Additional tracer and transmissivity tests will be conducted at regular time intervals to determine the fluid path evolution of the injected fluid and to infer the potential evolution of CO2 from the brine. Numerical simulation work assist the different phases of the field experiment.
{"title":"CO2 Sequestration: Studying Caprock And Fault Sealing Integrity, The CS-D Experiment In Mont Terri","authors":"A. Zappone, A. Rinaldi, M. Grab, A. Obermann, M. Claudio, C. Nussbaum, S. Wiemer","doi":"10.3997/2214-4609.201803002","DOIUrl":"https://doi.org/10.3997/2214-4609.201803002","url":null,"abstract":"A key challenge for CO2 geological storage is the integrity of the caprock. This challenge is addressed by executing a decameter-scale experiment at the Mont Terri Underground Rock Laboratory in Switzerland, under the umbrella of ELEGANCY (Enabling a Low-Carbon Economy via Hydrogen and CCS). ELEGANCY is an European project aiming at advance sustainable geo-energy processes through studies on risk mitigation, characterization and public perception, whose achievements will benefit the fields of carbon dixode sequestration. The experiment will investigating the mechanisms and the physical parameters governing the migration of CO2-rich brine through a faults. In particular, the test seeks to understand the conditions for slip activation (seismic vs. aseismic slip) and the stability of clay faults, as well as the coupling between fault slip, pore pressure, fluid migration and possible induced “micro” seismicity. To this end, we will inject CO2-rich brine into the fault core for a period of about eight months, while monitoring its geo-mechanical response. Additional tracer and transmissivity tests will be conducted at regular time intervals to determine the fluid path evolution of the injected fluid and to infer the potential evolution of CO2 from the brine. Numerical simulation work assist the different phases of the field experiment.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134253475","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802994
H. Rodrigues, E. Mackay, D. Arnold
CO2-WAG injection has been applied in offshore Brazilian carbonate reservoirs aiming to improve oil recovery and promote a safe destination to CO2 naturally being produced alongside with hydrocarbon gas. A gas re-utilisation strategy can potentially lead to multiple benefits: residual oil saturation reduction, maintenance of reservoir pressure, avoidance of gas flaring and development of the infrastructure and expertise necessary to make CO2 storage more accessible once oil production is complete, paving the path for a low carbon future, whereas mature basins can be a potential hub for Carbon Capture, Utilisation and Storage (CCUS). This study aims to develop a methodology to design CO2-WAG projects that not only achieve a high Net Present Value (NPV) but also maximizes the capacity and safety of geological CO2 storage.
{"title":"Impact Of CO2-WAG Design Optimisation On Coupled CO2-EOR And Storage Projects In Carbonate Reservoirs","authors":"H. Rodrigues, E. Mackay, D. Arnold","doi":"10.3997/2214-4609.201802994","DOIUrl":"https://doi.org/10.3997/2214-4609.201802994","url":null,"abstract":"CO2-WAG injection has been applied in offshore Brazilian carbonate reservoirs aiming to improve oil recovery and promote a safe destination to CO2 naturally being produced alongside with hydrocarbon gas. A gas re-utilisation strategy can potentially lead to multiple benefits: residual oil saturation reduction, maintenance of reservoir pressure, avoidance of gas flaring and development of the infrastructure and expertise necessary to make CO2 storage more accessible once oil production is complete, paving the path for a low carbon future, whereas mature basins can be a potential hub for Carbon Capture, Utilisation and Storage (CCUS). This study aims to develop a methodology to design CO2-WAG projects that not only achieve a high Net Present Value (NPV) but also maximizes the capacity and safety of geological CO2 storage.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"93 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124641240","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802953
S. Olaussen, K. Senger, T. Birchall, A. Braathen, S. Grundvåg, Ø. Hammer, M. Koevoets, Leif Larsen, M. Mulrooney, M. Mørk, K. Ogata, S. Ohm, B. Rismyhr
The UNIS CO2 Lab has evaluated the subsurface near the local coal-fueled power plant in Longyearbyen, Svalbard, Norway as a possible CO2 storage site. Extensive geological and pressure studies, including eight fully cored slim boreholes have proven a nearly 400 m thick shale dominated unit as an efficient cap rock for buoyant fluids. The underlying 300 m thick fractured and under-pressured heterolithic succession is identified as a potential unconventional reservoir The study concludes that the reservoir exhibits injectivity and storage capacity that are sufficient for the relative small volume of the CO2 emitted from the coal power plant.
{"title":"The Longyearbyen CO2 Lab Project: Lessons Learned From A Decade Of Characterizing An Unconventional Reservoir-Caprock System","authors":"S. Olaussen, K. Senger, T. Birchall, A. Braathen, S. Grundvåg, Ø. Hammer, M. Koevoets, Leif Larsen, M. Mulrooney, M. Mørk, K. Ogata, S. Ohm, B. Rismyhr","doi":"10.3997/2214-4609.201802953","DOIUrl":"https://doi.org/10.3997/2214-4609.201802953","url":null,"abstract":"The UNIS CO2 Lab has evaluated the subsurface near the local coal-fueled power plant in Longyearbyen, Svalbard, Norway as a possible CO2 storage site. Extensive geological and pressure studies, including eight fully cored slim boreholes have proven a nearly 400 m thick shale dominated unit as an efficient cap rock for buoyant fluids. The underlying 300 m thick fractured and under-pressured heterolithic succession is identified as a potential unconventional reservoir The study concludes that the reservoir exhibits injectivity and storage capacity that are sufficient for the relative small volume of the CO2 emitted from the coal power plant.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116596859","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802990
A. Shchipanov, L. Kollbotn, R. Berenblyum
Leakage of reservoir fluids from injection site, e.g. through faults, is one of the key risks associated with long-term CO2 geological storage. Leakage monitoring technologies applied at different levels: in-situ, groundwater and surface, are necessary to ensure safe CO2 storage. Development and testing of the monitoring technologies is an objective of the ENOS project. In this paper, in-situ leakage detection from analysis of well bottom hole pressure is discussed. Modern CO2 injection wells are usually equipped with Permanent Downhole Gauges (PDGs), providing pressure measurements during the whole well life-span including injection and shut-in periods. A practical way to apply Pressure Transient Analysis (PTA) to such measurements for leakage detection is in the focus. A simulated well test of near-fault water injection into saline aquifer was employed to evaluate capabilities of PTA in detecting leakage through the fault. These mechanistic reservoir simulations were followed by similar simulations on an actual geological setting. A reservoir segment of the potential LBr-1 injection site containing a fault was used to demonstrate PTA-based leakage detection under actual geological conditions. Both simulation studies have confirmed that the PTA-based detection may be a useful component of the multi-level leakage monitoring technologies relying on readily available facilities (PDGs).
{"title":"Fault Leakage Detection From Pressure Transient Analysis","authors":"A. Shchipanov, L. Kollbotn, R. Berenblyum","doi":"10.3997/2214-4609.201802990","DOIUrl":"https://doi.org/10.3997/2214-4609.201802990","url":null,"abstract":"Leakage of reservoir fluids from injection site, e.g. through faults, is one of the key risks associated with long-term CO2 geological storage. Leakage monitoring technologies applied at different levels: in-situ, groundwater and surface, are necessary to ensure safe CO2 storage. Development and testing of the monitoring technologies is an objective of the ENOS project. In this paper, in-situ leakage detection from analysis of well bottom hole pressure is discussed. Modern CO2 injection wells are usually equipped with Permanent Downhole Gauges (PDGs), providing pressure measurements during the whole well life-span including injection and shut-in periods. A practical way to apply Pressure Transient Analysis (PTA) to such measurements for leakage detection is in the focus. A simulated well test of near-fault water injection into saline aquifer was employed to evaluate capabilities of PTA in detecting leakage through the fault. These mechanistic reservoir simulations were followed by similar simulations on an actual geological setting. A reservoir segment of the potential LBr-1 injection site containing a fault was used to demonstrate PTA-based leakage detection under actual geological conditions. Both simulation studies have confirmed that the PTA-based detection may be a useful component of the multi-level leakage monitoring technologies relying on readily available facilities (PDGs).","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116908918","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802972
S. Simone, S. Jackson, R. Zimmerman, S. Krevor
Large scale CCS is crucial to reduce the cost associated with minimizing climate change. Energy system models should thus include CCS at regional or global scale with a proper evaluation of pressure limitations and injectivity, which are currently ignored. To this aim, the use of simplified analytical solutions is highly useful because they provide fast evaluation of pressure and plume evolution without the computational costs of the numerical models. Application of these solutions to assess storage capacity has been extended to cases of multiple well injection. In these cases, the pressure build-up is evaluated as the superposition of the analytical solutions for pressure associated with each individual well. In this study we investigate the validity of the superposition procedure, given the non-linearity of the multiphase flow. We quantify the error associated with the application of superposition to estimate reservoir pressurisation in different scenarios of.multi-site CO2 injection in a large regional aquifer. We find that the error associated with the adoption of this procedure increases with time and with the number of wells in proportion to the area invaded by CO2 in the reservoir.
{"title":"Analysis Of The Use Of Superposition For Analytic Models Of CO2 Injection Into Reservoirs With Multiple Injection Sites","authors":"S. Simone, S. Jackson, R. Zimmerman, S. Krevor","doi":"10.3997/2214-4609.201802972","DOIUrl":"https://doi.org/10.3997/2214-4609.201802972","url":null,"abstract":"Large scale CCS is crucial to reduce the cost associated with minimizing climate change. Energy system models should thus include CCS at regional or global scale with a proper evaluation of pressure limitations and injectivity, which are currently ignored. To this aim, the use of simplified analytical solutions is highly useful because they provide fast evaluation of pressure and plume evolution without the computational costs of the numerical models. Application of these solutions to assess storage capacity has been extended to cases of multiple well injection. In these cases, the pressure build-up is evaluated as the superposition of the analytical solutions for pressure associated with each individual well. In this study we investigate the validity of the superposition procedure, given the non-linearity of the multiphase flow. We quantify the error associated with the application of superposition to estimate reservoir pressurisation in different scenarios of.multi-site CO2 injection in a large regional aquifer. We find that the error associated with the adoption of this procedure increases with time and with the number of wells in proportion to the area invaded by CO2 in the reservoir.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128895369","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802965
B. Bellwald, M. Waage, S. Planke, N. Lebedeva-Ivanova, S. Polteau, A. Tasianas, S. Bünz, A. Plaza-Faverola, C. Berndt, H. Stokke, J. Millett, R. M. As
Injection of CO2 in subsurface reservoirs may cause overburden deformation and CO2 leakage. The aim of this study is to apply technologies for detection and monitoring of CO2 leakage and deformation above the injection reservoirs. The examples of this study include data from the Vestnesa Ridge natural seep site, the Snohvit gas field and CO2 storage site region, and the Gemini North gas reservoir. Reprocessing of existing 3D high-resolution seismic data allows resolving features with a vertical and lateral resolution down to c. 1 m and c. 5 m respectively. The current acquisition systems could be modified to image structures down to one meter in both the vertical and horizontal directions. We suggest a monitoring workflow that includes baseline and time-lapse acquisition of high-resolution 3D seismic data, integrated with geochemical, geophysical, and geotechnical seabed core and water-column measurements. The outcome of such a workflow can deliver reliable quantitative property volumes of the subsurface and will be able to image meter-sized anomalies of fluid leakage and deformation in the overburden.
{"title":"Monitoring Of CO2 Leakage Using High-Resolution 3D Seismic Data – Examples From Snøhvit, Vestnesa Ridge And The Western Barents Sea","authors":"B. Bellwald, M. Waage, S. Planke, N. Lebedeva-Ivanova, S. Polteau, A. Tasianas, S. Bünz, A. Plaza-Faverola, C. Berndt, H. Stokke, J. Millett, R. M. As","doi":"10.3997/2214-4609.201802965","DOIUrl":"https://doi.org/10.3997/2214-4609.201802965","url":null,"abstract":"Injection of CO2 in subsurface reservoirs may cause overburden deformation and CO2 leakage. The aim of this study is to apply technologies for detection and monitoring of CO2 leakage and deformation above the injection reservoirs. The examples of this study include data from the Vestnesa Ridge natural seep site, the Snohvit gas field and CO2 storage site region, and the Gemini North gas reservoir. Reprocessing of existing 3D high-resolution seismic data allows resolving features with a vertical and lateral resolution down to c. 1 m and c. 5 m respectively. The current acquisition systems could be modified to image structures down to one meter in both the vertical and horizontal directions. We suggest a monitoring workflow that includes baseline and time-lapse acquisition of high-resolution 3D seismic data, integrated with geochemical, geophysical, and geotechnical seabed core and water-column measurements. The outcome of such a workflow can deliver reliable quantitative property volumes of the subsurface and will be able to image meter-sized anomalies of fluid leakage and deformation in the overburden.","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131538564","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802986
R. Rommerskirchen
{"title":"Influencing The CO2-Oil Interaction For Improved Miscibility And Enhanced Recovery In CCUS Projects","authors":"R. Rommerskirchen","doi":"10.3997/2214-4609.201802986","DOIUrl":"https://doi.org/10.3997/2214-4609.201802986","url":null,"abstract":"","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"68 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132669148","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2018-11-21DOI: 10.3997/2214-4609.201802956
S. Tveit, S. Gasda, H. Hægland, G. Bødtker, M. Elenius
In this abstract, we develop simulation models to study and show the potential for field-scale application of microbially induced calcite precipitation (MICP) as a leakage mitigate solution in CO2 sequestration. Based on laboratory experiments, field-scale cases, and numerical studies from the literature, two injection strategies for efficient MICP are developed: (I) injection of pre-stimulated microorganisms and urea into the subsurface, resulting in calcite precipitation around the body of the microbes; and (II) the classic approach of injecting microorganisms together with chemicals to stimulate growth of biofilm, and subsequent calcite precipitation from the biofilm. To enable field-scale simulations of (I) and (II) at low computational cost, we simplify the processes that have little contribution to the flow, while keeping input parameters and assumptions as realistic as possible. The injection strategies were simulated on field-scale, synthetic 2D radial models. The simulation results showed that both injection strategies produce significant porosity/permeability decrease at targeted locations away from the injection well. Moreover, it was seen that injection strategy (II) produced significantly more porosity/permeability decrease compared to (I).
{"title":"Numerical Study Of Microbially Induced Calcite Precipitation As A Leakage Mitigation Solution For CO2 Storage","authors":"S. Tveit, S. Gasda, H. Hægland, G. Bødtker, M. Elenius","doi":"10.3997/2214-4609.201802956","DOIUrl":"https://doi.org/10.3997/2214-4609.201802956","url":null,"abstract":"In this abstract, we develop simulation models to study and show the potential for field-scale application of microbially induced calcite precipitation (MICP) as a leakage mitigate solution in CO2 sequestration. Based on laboratory experiments, field-scale cases, and numerical studies from the literature, two injection strategies for efficient MICP are developed: (I) injection of pre-stimulated microorganisms and urea into the subsurface, resulting in calcite precipitation around the body of the microbes; and (II) the classic approach of injecting microorganisms together with chemicals to stimulate growth of biofilm, and subsequent calcite precipitation from the biofilm. To enable field-scale simulations of (I) and (II) at low computational cost, we simplify the processes that have little contribution to the flow, while keeping input parameters and assumptions as realistic as possible. The injection strategies were simulated on field-scale, synthetic 2D radial models. The simulation results showed that both injection strategies produce significant porosity/permeability decrease at targeted locations away from the injection well. Moreover, it was seen that injection strategy (II) produced significantly more porosity/permeability decrease compared to (I).","PeriodicalId":254996,"journal":{"name":"Fifth CO2 Geological Storage Workshop","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-11-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129321393","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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