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Karsten Pruess - One of the best experts on this subject based on the ideXlab platform.
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numerical modeling of injection and Mineral Trapping of co2 with h2s and so2 in a sandstone formation
Lawrence Berkeley National Laboratory, 2008Co-Authors: Tianfu Xu, John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Numerical Modeling of Injection and Mineral Trapping of CO 2 with H 2 S and SO 2 in a Sandstone Formation Tianfu Xu 1 , John A. Apps 1 , Karsten Pruess 1 , and Hajime Yamamoto 2 Earth Sciences Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, CA 94720, USA Civil Engineering Research Institute, Taisei Corporation, 344-1, Nase-cho, Totsuka-ku, Yokohama 245-0051, Japan Abstract. Carbon dioxide (CO 2 ) injection into deep geologic formations could decrease the atmospheric accumulation of this gas from anthropogenic sources. Furthermore, by co-injecting H 2 S or SO 2 , the products respectively of coal gasification or combustion, with captured CO 2 , problems associated with surface disposal would be mitigated. We developed models that simulate the co-injection of H 2 S or SO 2 with CO 2 into an arkose formation at a depth of about 2 km and 75 ° C. The hydrogeology and Mineralogy of the injected formation are typical of those encountered in Gulf Coast aquifers of the United States. Six numerical simulations of a simplified 1-D radial region surrounding the injection well were performed. The injection of CO 2 alone or co-injection with SO 2 or H 2 S results in a concentrically zoned distribution of secondary Minerals surrounding a leached and acidified region adjacent to the injection well. Co-injection of SO 2 with CO 2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the co-injection of H 2 S or injection of CO 2 alone. Precipitation of carbonates occurs within a higher pH (pH > 5) peripheral zone. Significant quantities of CO 2 are sequestered by ankerite, dawsonite, and lesser siderite. The CO 2 Mineral-Trapping capacity of the formation can attain 40-50 kg/m 3 medium for the selected arkose. In contrast, secondary sulfates precipitate at lower pH (pH < 5) within the acidified zone. Most of the injected SO 2 is transformed and immobilized through alunite precipitation with lesser amounts of anhydrite and minor quantities of pyrite. The dissolved CO 2 increases with time (enhanced solubility Trapping). The Mineral alteration induced by injection of CO 2 with either SO 2 or H 2 S leads to corresponding changes in porosity.
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numerical modeling of injection and Mineral Trapping of co2 with h2s and so2 in a sandstone formation
Chemical Geology, 2007Co-Authors: Tianfu Xu, John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Abstract Carbon dioxide (CO 2 ) injection into deep geologic formations could decrease the atmospheric accumulation of this gas from anthropogenic sources. Furthermore, by co-injecting H 2 S or SO 2 , the products respectively of coal gasification or combustion, with captured CO 2 , problems associated with surface disposal would be mitigated. We developed models that simulate the co-injection of H 2 S or SO 2 with CO 2 into an arkose formation at a depth of about 2 km and 75 °C. The hydrogeology and Mineralogy of the injected formation are typical of those encountered in Gulf Coast aquifers of the United States. Six numerical simulations of a simplified 1-D radial region surrounding the injection well were performed. The injection of CO 2 alone or co-injection with SO 2 or H 2 S results in a concentrically zoned distribution of secondary Minerals surrounding a leached and acidified region adjacent to the injection well. Co-injection of SO 2 with CO 2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the co-injection of H 2 S or injection of CO 2 alone. Precipitation of carbonates occurs within a higher pH (pH > 5) peripheral zone. Significant quantities of CO 2 are sequestered by ankerite, dawsonite, and lesser siderite. The CO 2 Mineral-Trapping capacity of the formation can attain 40–50 kg/m 3 medium for the selected arkose. In contrast, secondary sulfates precipitate at lower pH (pH 2 is transformed and immobilized through alunite precipitation with lesser amounts of anhydrite and minor quantities of pyrite. The dissolved CO 2 increases with time (enhanced solubility Trapping). The Mineral alteration induced by injection of CO 2 with either SO 2 or H 2 S leads to corresponding changes in porosity. Significant increases in porosity occur in the acidified zones where Mineral dissolution dominates. With co-injection of SO 2 , the porosity increases from an initial 0.3 to 0.43 after 100 years. However, within the CO 2 Mineral-Trapping zone, the porosity decreases to about 0.28 for both cases, because of the addition of CO 2 mass as secondary carbonates to the rock matrix. Precipitation of sulfates at the acidification front causes porosity to decrease to 0.23. The limited information currently available on the Mineralogy of naturally occurring high-pressure CO 2 reservoirs is generally consistent with our simulations.
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Mineral sequestration of carbon dioxide in a sandstone shale system
Chemical Geology, 2005Co-Authors: Tianfu Xu, John A Apps, Karsten PruessAbstract:Abstract A conceptual model of CO2 injection in bedded sandstone–shale sequences has been developed using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments. Numerical simulations were performed with the reactive fluid flow and geochemical transport code TOUGHREACT to analyze mass transfer between sandstone and shale layers and CO2 immobilization through carbonate precipitation. Results indicate that most CO2 sequestration occurs in the sandstone. The major CO2 Trapping Minerals are dawsonite and ankerite. The CO2 Mineral-Trapping capacity after 100,000 years reaches about 90 kg/m3 of the medium. The CO2 Trapping capacity depends on primary Mineral composition. Precipitation of siderite and ankerite requires Fe+2 supplied mainly by chlorite and some by hematite dissolution and reduction. Precipitation of dawsonite requires Na+ provided by oligoclase dissolution. The initial abundance of chlorite and oligoclase therefore affects the CO2 Mineral-Trapping capacity. The sequestration time required depends on the kinetic rate of Mineral dissolution and precipitation. Dawsonite reaction kinetics is not well understood, and sensitivity regarding the precipitation rate was examined. The addition of CO2 as secondary carbonates results in decreased porosity. The leaching of chemical constituents from the interior of the shale causes slightly increased porosity. The limited information currently available for the Mineralogy of natural high-pressure CO2 gas reservoirs is also generally consistent with our simulation. The “numerical experiments” give a detailed understanding of the dynamic evolution of a sandstone–shale geochemical system.
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injection of co2 with h2s and so2 and subsequent Mineral Trapping in sandstone shale formation escholarship
2004Co-Authors: John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Injection of CO 2 with H 2 S and SO 2 and Subsequent Mineral Trapping in Sandstone-Shale Formation Tianfu Xu 1 , John A. Apps 1 , Karsten Pruess 1 , and Hajime Yamamoto 2 Earth Sciences Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, CA 94720, USA Civil Engineering Research Institute, Taisei Corporation, 344-1, Nase-cho, Totsuka-ku, Yokohama 245-0051, Japan Abstract. Carbon dioxide (CO 2 ) injection into deep geologic formations can potentially reduce atmospheric emissions of greenhouse gases. Sequestering less-pure CO 2 waste streams (containing H 2 S and/or SO 2 ) would be less expensive or would require less energy than separating CO 2 from flue gas or a coal gasification process. The long-term interaction of these injected acid gases with shale-confining layers of a sandstone injection zone has not been well investigated. We therefore have developed a conceptual model of injection of CO 2 with H 2 S and/or SO 2 into a sandstone-shale sequence, using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments of the United States. We have performed numerical simulations of a 1-D radial well region considering sandstone alone and a 2-D model using a sandstone-shale sequence under acid-gas injection conditions. Results indicate that shale plays a limited role in Mineral alteration and sequestration of gases within a sandstone horizon for short time periods (10,000 years in present simulations). The co-injection of SO 2 results in different pH distribution, Mineral alteration patterns, and CO 2 Mineral sequestration than the co-injection of H 2 S or injection of CO 2 alone. Simulations generate a zonal distribution of Mineral alteration and formation of carbon and sulfur Trapping Minerals that depends on the pH distribution. The co-injection of SO 2 results in a larger and stronger acidified zone close to the well. Precipitation of carbon Trapping Minerals occurs within the higher pH regions beyond the acidified zones. In contrast, sulfur Trapping Minerals are stable at low pH ranges (below 5) within the front of the acidified zone. Corrosion and well abandonment due to the co-injection of SO 2 could be important
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injection of co2 with h2s and so2 and subsequent Mineral Trapping in sandstone shale formation
Other Information: PBD: 7 Sep 2004, 2004Co-Authors: John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Carbon dioxide (CO{sub 2}) injection into deep geologic formations can potentially reduce atmospheric emissions of greenhouse gases. Sequestering less-pure CO{sub 2} waste streams (containing H{sub 2}S and/or SO{sub 2}) would be less expensive or would require less energy than separating CO{sub 2} from flue gas or a coal gasification process. The long-term interaction of these injected acid gases with shale-confining layers of a sandstone injection zone has not been well investigated. We therefore have developed a conceptual model of injection of CO{sub 2} with H{sub 2}S and/or SO{sub 2} into a sandstone-shale sequence, using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments of the United States. We have performed numerical simulations of a 1-D radial well region considering sandstone alone and a 2-D model using a sandstone-shale sequence under acid-gas injection conditions. Results indicate that shale plays a limited role in Mineral alteration and sequestration of gases within a sandstone horizon for short time periods (10,000 years in present simulations). The co-injection of SO{sub 2} results in different pH distribution, Mineral alteration patterns, and CO{sub 2} Mineral sequestration than the co-injection of H{sub 2}S or injection of CO{sub 2} alone. Simulations generate a zonal distribution of Mineral alteration and formation of carbon and sulfur Trapping Minerals that depends on the pH distribution. The co-injection of SO{sub 2} results in a larger and stronger acidified zone close to the well. Precipitation of carbon Trapping Minerals occurs within the higher pH regions beyond the acidified zones. In contrast, sulfur Trapping Minerals are stable at low pH ranges (below 5) within the front of the acidified zone. Corrosion and well abandonment due to the co-injection of SO{sub 2} could be important issues. Significant CO{sub 2} is sequestered in ankerite and dawsonite, and some in siderite. The CO{sub 2} Mineral-Trapping capability can reach 80 kg per cubic meter of medium. Most sulfur is trapped through alunite precipitation, although some is trapped by anhydrite precipitation and minor amount of pyrite. The addition of the acid gases and induced Mineral alteration result in changes in porosity. The limited information currently available on the Mineralogy of natural high-pressure acid-gas reservoirs is generally consistent with our simulations.
John A Apps - One of the best experts on this subject based on the ideXlab platform.
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numerical modeling of injection and Mineral Trapping of co2 with h2s and so2 in a sandstone formation
Lawrence Berkeley National Laboratory, 2008Co-Authors: Tianfu Xu, John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Numerical Modeling of Injection and Mineral Trapping of CO 2 with H 2 S and SO 2 in a Sandstone Formation Tianfu Xu 1 , John A. Apps 1 , Karsten Pruess 1 , and Hajime Yamamoto 2 Earth Sciences Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, CA 94720, USA Civil Engineering Research Institute, Taisei Corporation, 344-1, Nase-cho, Totsuka-ku, Yokohama 245-0051, Japan Abstract. Carbon dioxide (CO 2 ) injection into deep geologic formations could decrease the atmospheric accumulation of this gas from anthropogenic sources. Furthermore, by co-injecting H 2 S or SO 2 , the products respectively of coal gasification or combustion, with captured CO 2 , problems associated with surface disposal would be mitigated. We developed models that simulate the co-injection of H 2 S or SO 2 with CO 2 into an arkose formation at a depth of about 2 km and 75 ° C. The hydrogeology and Mineralogy of the injected formation are typical of those encountered in Gulf Coast aquifers of the United States. Six numerical simulations of a simplified 1-D radial region surrounding the injection well were performed. The injection of CO 2 alone or co-injection with SO 2 or H 2 S results in a concentrically zoned distribution of secondary Minerals surrounding a leached and acidified region adjacent to the injection well. Co-injection of SO 2 with CO 2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the co-injection of H 2 S or injection of CO 2 alone. Precipitation of carbonates occurs within a higher pH (pH > 5) peripheral zone. Significant quantities of CO 2 are sequestered by ankerite, dawsonite, and lesser siderite. The CO 2 Mineral-Trapping capacity of the formation can attain 40-50 kg/m 3 medium for the selected arkose. In contrast, secondary sulfates precipitate at lower pH (pH < 5) within the acidified zone. Most of the injected SO 2 is transformed and immobilized through alunite precipitation with lesser amounts of anhydrite and minor quantities of pyrite. The dissolved CO 2 increases with time (enhanced solubility Trapping). The Mineral alteration induced by injection of CO 2 with either SO 2 or H 2 S leads to corresponding changes in porosity.
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numerical modeling of injection and Mineral Trapping of co2 with h2s and so2 in a sandstone formation
Chemical Geology, 2007Co-Authors: Tianfu Xu, John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Abstract Carbon dioxide (CO 2 ) injection into deep geologic formations could decrease the atmospheric accumulation of this gas from anthropogenic sources. Furthermore, by co-injecting H 2 S or SO 2 , the products respectively of coal gasification or combustion, with captured CO 2 , problems associated with surface disposal would be mitigated. We developed models that simulate the co-injection of H 2 S or SO 2 with CO 2 into an arkose formation at a depth of about 2 km and 75 °C. The hydrogeology and Mineralogy of the injected formation are typical of those encountered in Gulf Coast aquifers of the United States. Six numerical simulations of a simplified 1-D radial region surrounding the injection well were performed. The injection of CO 2 alone or co-injection with SO 2 or H 2 S results in a concentrically zoned distribution of secondary Minerals surrounding a leached and acidified region adjacent to the injection well. Co-injection of SO 2 with CO 2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the co-injection of H 2 S or injection of CO 2 alone. Precipitation of carbonates occurs within a higher pH (pH > 5) peripheral zone. Significant quantities of CO 2 are sequestered by ankerite, dawsonite, and lesser siderite. The CO 2 Mineral-Trapping capacity of the formation can attain 40–50 kg/m 3 medium for the selected arkose. In contrast, secondary sulfates precipitate at lower pH (pH 2 is transformed and immobilized through alunite precipitation with lesser amounts of anhydrite and minor quantities of pyrite. The dissolved CO 2 increases with time (enhanced solubility Trapping). The Mineral alteration induced by injection of CO 2 with either SO 2 or H 2 S leads to corresponding changes in porosity. Significant increases in porosity occur in the acidified zones where Mineral dissolution dominates. With co-injection of SO 2 , the porosity increases from an initial 0.3 to 0.43 after 100 years. However, within the CO 2 Mineral-Trapping zone, the porosity decreases to about 0.28 for both cases, because of the addition of CO 2 mass as secondary carbonates to the rock matrix. Precipitation of sulfates at the acidification front causes porosity to decrease to 0.23. The limited information currently available on the Mineralogy of naturally occurring high-pressure CO 2 reservoirs is generally consistent with our simulations.
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Mineral sequestration of carbon dioxide in a sandstone shale system
Chemical Geology, 2005Co-Authors: Tianfu Xu, John A Apps, Karsten PruessAbstract:Abstract A conceptual model of CO2 injection in bedded sandstone–shale sequences has been developed using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments. Numerical simulations were performed with the reactive fluid flow and geochemical transport code TOUGHREACT to analyze mass transfer between sandstone and shale layers and CO2 immobilization through carbonate precipitation. Results indicate that most CO2 sequestration occurs in the sandstone. The major CO2 Trapping Minerals are dawsonite and ankerite. The CO2 Mineral-Trapping capacity after 100,000 years reaches about 90 kg/m3 of the medium. The CO2 Trapping capacity depends on primary Mineral composition. Precipitation of siderite and ankerite requires Fe+2 supplied mainly by chlorite and some by hematite dissolution and reduction. Precipitation of dawsonite requires Na+ provided by oligoclase dissolution. The initial abundance of chlorite and oligoclase therefore affects the CO2 Mineral-Trapping capacity. The sequestration time required depends on the kinetic rate of Mineral dissolution and precipitation. Dawsonite reaction kinetics is not well understood, and sensitivity regarding the precipitation rate was examined. The addition of CO2 as secondary carbonates results in decreased porosity. The leaching of chemical constituents from the interior of the shale causes slightly increased porosity. The limited information currently available for the Mineralogy of natural high-pressure CO2 gas reservoirs is also generally consistent with our simulation. The “numerical experiments” give a detailed understanding of the dynamic evolution of a sandstone–shale geochemical system.
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injection of co2 with h2s and so2 and subsequent Mineral Trapping in sandstone shale formation escholarship
2004Co-Authors: John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Injection of CO 2 with H 2 S and SO 2 and Subsequent Mineral Trapping in Sandstone-Shale Formation Tianfu Xu 1 , John A. Apps 1 , Karsten Pruess 1 , and Hajime Yamamoto 2 Earth Sciences Division, Lawrence Berkeley National Laboratory, University of California, Berkeley, CA 94720, USA Civil Engineering Research Institute, Taisei Corporation, 344-1, Nase-cho, Totsuka-ku, Yokohama 245-0051, Japan Abstract. Carbon dioxide (CO 2 ) injection into deep geologic formations can potentially reduce atmospheric emissions of greenhouse gases. Sequestering less-pure CO 2 waste streams (containing H 2 S and/or SO 2 ) would be less expensive or would require less energy than separating CO 2 from flue gas or a coal gasification process. The long-term interaction of these injected acid gases with shale-confining layers of a sandstone injection zone has not been well investigated. We therefore have developed a conceptual model of injection of CO 2 with H 2 S and/or SO 2 into a sandstone-shale sequence, using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments of the United States. We have performed numerical simulations of a 1-D radial well region considering sandstone alone and a 2-D model using a sandstone-shale sequence under acid-gas injection conditions. Results indicate that shale plays a limited role in Mineral alteration and sequestration of gases within a sandstone horizon for short time periods (10,000 years in present simulations). The co-injection of SO 2 results in different pH distribution, Mineral alteration patterns, and CO 2 Mineral sequestration than the co-injection of H 2 S or injection of CO 2 alone. Simulations generate a zonal distribution of Mineral alteration and formation of carbon and sulfur Trapping Minerals that depends on the pH distribution. The co-injection of SO 2 results in a larger and stronger acidified zone close to the well. Precipitation of carbon Trapping Minerals occurs within the higher pH regions beyond the acidified zones. In contrast, sulfur Trapping Minerals are stable at low pH ranges (below 5) within the front of the acidified zone. Corrosion and well abandonment due to the co-injection of SO 2 could be important
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injection of co2 with h2s and so2 and subsequent Mineral Trapping in sandstone shale formation
Other Information: PBD: 7 Sep 2004, 2004Co-Authors: John A Apps, Karsten Pruess, Hajime YamamotoAbstract:Carbon dioxide (CO{sub 2}) injection into deep geologic formations can potentially reduce atmospheric emissions of greenhouse gases. Sequestering less-pure CO{sub 2} waste streams (containing H{sub 2}S and/or SO{sub 2}) would be less expensive or would require less energy than separating CO{sub 2} from flue gas or a coal gasification process. The long-term interaction of these injected acid gases with shale-confining layers of a sandstone injection zone has not been well investigated. We therefore have developed a conceptual model of injection of CO{sub 2} with H{sub 2}S and/or SO{sub 2} into a sandstone-shale sequence, using hydrogeologic properties and Mineral compositions commonly encountered in Gulf Coast sediments of the United States. We have performed numerical simulations of a 1-D radial well region considering sandstone alone and a 2-D model using a sandstone-shale sequence under acid-gas injection conditions. Results indicate that shale plays a limited role in Mineral alteration and sequestration of gases within a sandstone horizon for short time periods (10,000 years in present simulations). The co-injection of SO{sub 2} results in different pH distribution, Mineral alteration patterns, and CO{sub 2} Mineral sequestration than the co-injection of H{sub 2}S or injection of CO{sub 2} alone. Simulations generate a zonal distribution of Mineral alteration and formation of carbon and sulfur Trapping Minerals that depends on the pH distribution. The co-injection of SO{sub 2} results in a larger and stronger acidified zone close to the well. Precipitation of carbon Trapping Minerals occurs within the higher pH regions beyond the acidified zones. In contrast, sulfur Trapping Minerals are stable at low pH ranges (below 5) within the front of the acidified zone. Corrosion and well abandonment due to the co-injection of SO{sub 2} could be important issues. Significant CO{sub 2} is sequestered in ankerite and dawsonite, and some in siderite. The CO{sub 2} Mineral-Trapping capability can reach 80 kg per cubic meter of medium. Most sulfur is trapped through alunite precipitation, although some is trapped by anhydrite precipitation and minor amount of pyrite. The addition of the acid gases and induced Mineral alteration result in changes in porosity. The limited information currently available on the Mineralogy of natural high-pressure acid-gas reservoirs is generally consistent with our simulations.
Quattrocchi F. - One of the best experts on this subject based on the ideXlab platform.
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Mineralogy and geochemical Trapping of CO2 in an Italian carbonatic deep saline aquifer: preliminary results
2008Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Procesi M., Buttinelli M., Quattrocchi F.Abstract:CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2 . Among the several potential geologi- cal CO2 storage sites, e.g. depleted oil and gas field, unexploitable coal beds, saline aquifers, the latter are estimated to have the highest potential capacity (350-1000 Gt CO2 ) and, being relatively common worldwide, a higher probability to be located close to major CO2 anthropogenic sources. In these sites CO2 can safely be retained at depth for long times, as follows: a) physical Trapping into geologic structures; b) hy- drodynamic Trapping where CO2(aq) slowly migrates in an aquifer, c) solubility trap- ping after the dissolution of CO2(aq) and d) Mineral Trapping as secondary carbon- ates precipitate. Despite the potential advantages of CO2 geo-sequestration, risks of CO2 leakage from the reservoir have to be carefully evaluated by both monitoring techniques and numerical modeling used in “CO2 analogues”, although seepage from saline aquifers is unlikely to be occurring. The fate of CO2 once injected into a saline aquifer can be predicted by means of numerical modelling procedures of geochemical processes, these theoretical calculations being one of the few approaches for inves- tigating the short-long-term consequences of CO2 storage. This study is focused on some Italian deep-seated (>800 m) saline aquifers by assessing solubility and min- eral Trapping potentiality as strategic need for some feasibility studies that are about to be started in Italy. Preliminary results obtained by numerical simulations of a geo- chemical modeling applied to an off-shore Italian carbonatic saline aquifer potential suitable to geological CO2 storage are here presented and discussed. Deep well data, still covered by industrial confidentiality, show that the saline aquifer, includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l. These formations, belonging to Tuscan Nappe, consist of porous limestones (mainly calcite) and marly limestones sealed, on the top, by an effective and thick cap-rock (around 2500 m) of clay flysch belonging to the Liguride Units. The evaluation of the potential geochemical impact of CO2 storage and the quantification of water-gas-rock reactions (solubility and Mineral Trapping) of injection reservoir have been performed by the PRHEEQC (V2.11) Software Package via corrections to the code default ther- modynamic database to obtain a more realistic modelling. The main modifications to the Software Package are, as follows: i) addition of new solid phases, ii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iii) addi- tion of kinetic rate equations of several Minerals and iv) calculation of reaction sur- face area. Available site-specific data include only basic physical parameters such as temperature, pressure, and salinity of the formation waters. Rocks sampling of each considered formation in the contiguous in-shore zones was carried out. Mineralogy was determined by X-Ray diffraction analysis and Scanning Electronic Microscopy on thin sections. As chemical composition of the aquifer pore water is unknown, this has been inferred by batch modeling assuming thermodynamic equilibrium between Minerals and a NaCl equivalent brine at reservoir conditions (up to 135 ̊C and 251 atm). Kinetic modelling was carried out for isothermal conditions (135 ̊C), under a CO2 injection constant pressure of 251 atm, between: a) bulk Mineralogy of the six formations constituting the aquifer, and b) pre-CO2 injection water. The kinetic evolu- tion of the CO2 -rich brines interacting with the host-rock Minerals performed over 100 years after injection suggests that solubility Trapping is prevailing in this early stage of CO2 injection. Further and detailed multidisciplinary studies on rock properties, geochemical and micro seismic monitoring and 3D reservoir simulation are necessary to better characterize the potential storage site and asses the CO2 storage capacity
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Mineralogy and geochemical Trapping of CO2 in an Italian carbonatic deep saline aquifer: preliminary results
2008Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Procesi M., Buttinelli M., Quattrocchi F.Abstract:CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2 . Among the several potential geologi- cal CO2 storage sites, e.g. depleted oil and gas field, unexploitable coal beds, saline aquifers, the latter are estimated to have the highest potential capacity (350-1000 Gt CO2 ) and, being relatively common worldwide, a higher probability to be located close to major CO2 anthropogenic sources. In these sites CO2 can safely be retained at depth for long times, as follows: a) physical Trapping into geologic structures; b) hy- drodynamic Trapping where CO2(aq) slowly migrates in an aquifer, c) solubility trap- ping after the dissolution of CO2(aq) and d) Mineral Trapping as secondary carbon- ates precipitate. Despite the potential advantages of CO2 geo-sequestration, risks of CO2 leakage from the reservoir have to be carefully evaluated by both monitoring techniques and numerical modeling used in “CO2 analogues”, although seepage from saline aquifers is unlikely to be occurring. The fate of CO2 once injected into a saline aquifer can be predicted by means of numerical modelling procedures of geochemical processes, these theoretical calculations being one of the few approaches for inves- tigating the short-long-term consequences of CO2 storage. This study is focused on some Italian deep-seated (>800 m) saline aquifers by assessing solubility and min- eral Trapping potentiality as strategic need for some feasibility studies that are about to be started in Italy. Preliminary results obtained by numerical simulations of a geo- chemical modeling applied to an off-shore Italian carbonatic saline aquifer potential suitable to geological CO2 storage are here presented and discussed. Deep well data, still covered by industrial confidentiality, show that the saline aquifer, includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l. These formations, belonging to Tuscan Nappe, consist of porous limestones (mainly calcite) and marly limestones sealed, on the top, by an effective and thick cap-rock (around 2500 m) of clay flysch belonging to the Liguride Units. The evaluation of the potential geochemical impact of CO2 storage and the quantification of water-gas-rock reactions (solubility and Mineral Trapping) of injection reservoir have been performed by the PRHEEQC (V2.11) Software Package via corrections to the code default ther- modynamic database to obtain a more realistic modelling. The main modifications to the Software Package are, as follows: i) addition of new solid phases, ii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iii) addi- tion of kinetic rate equations of several Minerals and iv) calculation of reaction sur- face area. Available site-specific data include only basic physical parameters such as temperature, pressure, and salinity of the formation waters. Rocks sampling of each considered formation in the contiguous in-shore zones was carried out. Mineralogy was determined by X-Ray diffraction analysis and Scanning Electronic Microscopy on thin sections. As chemical composition of the aquifer pore water is unknown, this has been inferred by batch modeling assuming thermodynamic equilibrium between Minerals and a NaCl equivalent brine at reservoir conditions (up to 135 ̊C and 251 atm). Kinetic modelling was carried out for isothermal conditions (135 ̊C), under a CO2 injection constant pressure of 251 atm, between: a) bulk Mineralogy of the six formations constituting the aquifer, and b) pre-CO2 injection water. The kinetic evolu- tion of the CO2 -rich brines interacting with the host-rock Minerals performed over 100 years after injection suggests that solubility Trapping is prevailing in this early stage of CO2 injection. Further and detailed multidisciplinary studies on rock properties, geochemical and micro seismic monitoring and 3D reservoir simulation are necessary to better characterize the potential storage site and asses the CO2 storage capacity.PublishedVienna (Austria)2.4. TTC - Laboratori di geochimica dei fluidiope
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An approach to the geochemical modelling of water-rock interaction in CO2 storage geological reservoirs: the Weyburn Project (Canada) case study
2007Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Quattrocchi F.Abstract:Geological storage is one of the most promising technologies for reducing anthropogenic atmospheric emissions of CO2. Among the several CO2 storage techniques, sequestration in deep-seated saline aquifers implies four processes: a) supercritical fluid into geologic structure (physical Trapping), b) dissolved CO2(aq) due to very long flow path (hydrodynamic Trapping), c) dissolved CO2(aq) (solubility Trapping), and d) secondary carbonates (Mineral Trapping). The appealing concept that CO2 can permanently be retained underground has prompted several experimental studies in Europe and North America sponsored by IEA GHG R&D, EU and numerous international industrials and governments, the most important project being the International Energy Agency Weyburn CO2 Monitoring & Storage, an EnCana’s CO2 injection EOR project at Weyburn (Saskatchewan, Canada). Owing to the possible risks associated to this technique, numerical modelling procedures of geochemical processes are necessary to investigate the short- to long-term consequences of CO2 storage. Assumptions and gap-acceptance are made to reconstruct the reservoir conditions (pressure, pH, chemistry, and Mineral assemblage), although most strategic geochemical parameters of deep fluids are computed by a posteriori procedure due to the sampling collection at the wellhead, i.e. using depressurised aliquots. In this work a new approach to geochemical model capable of to reconstruct the reservoir chemical composition (T, P, boundary conditions and pH) is proposed using surface analytical data to simulate the short-medium term reservoir evolution during and after the CO2 injection. The PRHEEQC (V2.11) Software Package via thermodynamic corrections to the code default database has been used to obtain a more realistic modelling. The main modifications brought about the Software Package are: i) addition of new solid phases, ii) use of P>0.1 Mpa, iii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iv) addition of kinetic rate equations of several Minerals and v) calculation of reaction surface area. The Weyburn Project was selected as case study to test our model. The Weyburn oil-pull is recovered from the Midale Beds (1300-1500 m deep) that consist of two units of Mississippian shallow marine carbonate-evaporites: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. About 3 billions mc of supercritical CO2 have been injected into the “Phase A1” injection area. The INGV and the University of Calgary (Canada), have carried out a geochemical monitoring program (ca. thrice yearly- from pre-injection trip: “Baseline” trip, August 2000, to September 2004). The merged experimental data are the base of the present geochemical modeling. On the basis of the available data, i.e. a) bulk Mineralogy of the Marly and Vuggy reservoirs; b) mean gas-cap composition at the wellheads and c) selected pre- and post-CO2 injection water samples, the in-situ (62 °C and 0.1 MPa) reservoir chemical composition (including pH and the boundary conditions as PCO2, PH2S) has been re-built by the chemical equilibrium among the various phases, minimizing the effects of the past 30-years of water flooding in the oil field. The kinetic evolution of the CO2-rich Weyburn brines interacting with the host-rock Minerals performed over 100 years after injection have also been computed. The reaction path modeling suggests that CO2 can mainly be neutralized by solubility and Mineral Trapping via Dawsonite precipitation. To validate our model the geochemical impact of three years of CO2 injection (September 2000-2003) has been simulated by kinetically controlled reactions. The calculated chemical composition after the CO2 injection is consistent with the analytical data of samples collected in 2003 with a 90%), likely due to the complexation effect of carboxilic acid
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An approach to the geochemical modelling of water-rock interaction in CO2 storage geological reservoirs: the Weyburn Project (Canada) case study
2007Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Quattrocchi F.Abstract:Geological storage is one of the most promising technologies for reducing anthropogenic atmospheric emissions of CO2. Among the several CO2 storage techniques, sequestration in deep-seated saline aquifers implies four processes: a) supercritical fluid into geologic structure (physical Trapping), b) dissolved CO2(aq) due to very long flow path (hydrodynamic Trapping), c) dissolved CO2(aq) (solubility Trapping), and d) secondary carbonates (Mineral Trapping). The appealing concept that CO2 can permanently be retained underground has prompted several experimental studies in Europe and North America sponsored by IEA GHG R&D, EU and numerous international industrials and governments, the most important project being the International Energy Agency Weyburn CO2 Monitoring & Storage, an EnCana’s CO2 injection EOR project at Weyburn (Saskatchewan, Canada). Owing to the possible risks associated to this technique, numerical modelling procedures of geochemical processes are necessary to investigate the short- to long-term consequences of CO2 storage. Assumptions and gap-acceptance are made to reconstruct the reservoir conditions (pressure, pH, chemistry, and Mineral assemblage), although most strategic geochemical parameters of deep fluids are computed by a posteriori procedure due to the sampling collection at the wellhead, i.e. using depressurised aliquots. In this work a new approach to geochemical model capable of to reconstruct the reservoir chemical composition (T, P, boundary conditions and pH) is proposed using surface analytical data to simulate the short-medium term reservoir evolution during and after the CO2 injection. The PRHEEQC (V2.11) Software Package via thermodynamic corrections to the code default database has been used to obtain a more realistic modelling. The main modifications brought about the Software Package are: i) addition of new solid phases, ii) use of P>0.1 Mpa, iii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iv) addition of kinetic rate equations of several Minerals and v) calculation of reaction surface area. The Weyburn Project was selected as case study to test our model. The Weyburn oil-pull is recovered from the Midale Beds (1300-1500 m deep) that consist of two units of Mississippian shallow marine carbonate-evaporites: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. About 3 billions mc of supercritical CO2 have been injected into the “Phase A1” injection area. The INGV and the University of Calgary (Canada), have carried out a geochemical monitoring program (ca. thrice yearly- from pre-injection trip: “Baseline” trip, August 2000, to September 2004). The merged experimental data are the base of the present geochemical modeling. On the basis of the available data, i.e. a) bulk Mineralogy of the Marly and Vuggy reservoirs; b) mean gas-cap composition at the wellheads and c) selected pre- and post-CO2 injection water samples, the in-situ (62 °C and 0.1 MPa) reservoir chemical composition (including pH and the boundary conditions as PCO2, PH2S) has been re-built by the chemical equilibrium among the various phases, minimizing the effects of the past 30-years of water flooding in the oil field. The kinetic evolution of the CO2-rich Weyburn brines interacting with the host-rock Minerals performed over 100 years after injection have also been computed. The reaction path modeling suggests that CO2 can mainly be neutralized by solubility and Mineral Trapping via Dawsonite precipitation. To validate our model the geochemical impact of three years of CO2 injection (September 2000-2003) has been simulated by kinetically controlled reactions. The calculated chemical composition after the CO2 injection is consistent with the analytical data of samples collected in 2003 with a 90%), likely due to the complexation effect of carboxilic acid.PublishedRimini, Italy2.4. TTC - Laboratori di geochimica dei fluidiope
M S A Perera - One of the best experts on this subject based on the ideXlab platform.
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geochemical aspects of co2 sequestration in deep saline aquifers a review
Fuel, 2015Co-Authors: G P D De Silva, P G Ranjith, M S A PereraAbstract:Carbon dioxide has been identified as one of the main compounds affecting the stability of the earth’s climate. The reduction of the total volume of greenhouse gases emitted to the atmosphere is considered a key mechanism to mitigate climate change. Geological storage of CO2 in deep saline aquifers is currently a well-accepted method of storage, because saline aquifers have larger storage capacities than other geological media. Rock–water–CO2 interactions initiated in the aquifer with CO2 injection play a vital role in CO2 sequestration in saline aquifers, and include different Trapping mechanisms: geological Trapping, hydrodynamic Trapping and geo-chemical Trapping (solubility Trapping and Mineral Trapping). Of these, geological Trapping and solubility Trapping are more effective in the short term, but Mineral Trapping is safer and more economical in the long term. Current knowledge of geochemical Trapping is still at an early stage compared to other Trapping mechanisms due to the extensive time required to complete the process. To date, very few studies have been conducted on sandstone reservoirs, which are considered to have the largest storage capacity among geological formations. However, due to the long-term safety of CO2 storage with geochemical Trapping, there has been a recent trend to research this process. Both solubility and Mineral Trapping processes in saline aquifers depend on injecting CO2 and the fluid–rock Mineral properties of the aquifers. Until very recently, although it was assumed that temperature, pressure, the salinity of the formation water and the Mineral composition of the formation rock are the only parameters which affect Mineral Trapping, recent research has shown that a number of other reservoir parameters, such as layer thickness, tilt angle, anisotropy and bedding pattern may also significantly affect geochemical Trapping. This review provides a comprehensive examination of the current knowledge of the geo-chemistry of solubility and Mineral Trapping processes in deep saline aquifers.
Cantucci B. - One of the best experts on this subject based on the ideXlab platform.
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Mineralogy and geochemical Trapping of CO2 in an Italian carbonatic deep saline aquifer: preliminary results
2008Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Procesi M., Buttinelli M., Quattrocchi F.Abstract:CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2 . Among the several potential geologi- cal CO2 storage sites, e.g. depleted oil and gas field, unexploitable coal beds, saline aquifers, the latter are estimated to have the highest potential capacity (350-1000 Gt CO2 ) and, being relatively common worldwide, a higher probability to be located close to major CO2 anthropogenic sources. In these sites CO2 can safely be retained at depth for long times, as follows: a) physical Trapping into geologic structures; b) hy- drodynamic Trapping where CO2(aq) slowly migrates in an aquifer, c) solubility trap- ping after the dissolution of CO2(aq) and d) Mineral Trapping as secondary carbon- ates precipitate. Despite the potential advantages of CO2 geo-sequestration, risks of CO2 leakage from the reservoir have to be carefully evaluated by both monitoring techniques and numerical modeling used in “CO2 analogues”, although seepage from saline aquifers is unlikely to be occurring. The fate of CO2 once injected into a saline aquifer can be predicted by means of numerical modelling procedures of geochemical processes, these theoretical calculations being one of the few approaches for inves- tigating the short-long-term consequences of CO2 storage. This study is focused on some Italian deep-seated (>800 m) saline aquifers by assessing solubility and min- eral Trapping potentiality as strategic need for some feasibility studies that are about to be started in Italy. Preliminary results obtained by numerical simulations of a geo- chemical modeling applied to an off-shore Italian carbonatic saline aquifer potential suitable to geological CO2 storage are here presented and discussed. Deep well data, still covered by industrial confidentiality, show that the saline aquifer, includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l. These formations, belonging to Tuscan Nappe, consist of porous limestones (mainly calcite) and marly limestones sealed, on the top, by an effective and thick cap-rock (around 2500 m) of clay flysch belonging to the Liguride Units. The evaluation of the potential geochemical impact of CO2 storage and the quantification of water-gas-rock reactions (solubility and Mineral Trapping) of injection reservoir have been performed by the PRHEEQC (V2.11) Software Package via corrections to the code default ther- modynamic database to obtain a more realistic modelling. The main modifications to the Software Package are, as follows: i) addition of new solid phases, ii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iii) addi- tion of kinetic rate equations of several Minerals and iv) calculation of reaction sur- face area. Available site-specific data include only basic physical parameters such as temperature, pressure, and salinity of the formation waters. Rocks sampling of each considered formation in the contiguous in-shore zones was carried out. Mineralogy was determined by X-Ray diffraction analysis and Scanning Electronic Microscopy on thin sections. As chemical composition of the aquifer pore water is unknown, this has been inferred by batch modeling assuming thermodynamic equilibrium between Minerals and a NaCl equivalent brine at reservoir conditions (up to 135 ̊C and 251 atm). Kinetic modelling was carried out for isothermal conditions (135 ̊C), under a CO2 injection constant pressure of 251 atm, between: a) bulk Mineralogy of the six formations constituting the aquifer, and b) pre-CO2 injection water. The kinetic evolu- tion of the CO2 -rich brines interacting with the host-rock Minerals performed over 100 years after injection suggests that solubility Trapping is prevailing in this early stage of CO2 injection. Further and detailed multidisciplinary studies on rock properties, geochemical and micro seismic monitoring and 3D reservoir simulation are necessary to better characterize the potential storage site and asses the CO2 storage capacity
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Mineralogy and geochemical Trapping of CO2 in an Italian carbonatic deep saline aquifer: preliminary results
2008Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Procesi M., Buttinelli M., Quattrocchi F.Abstract:CO2 Capture & Storage (CCS) is presently one of the most promising technologies for reducing anthropogenic emissions of CO2 . Among the several potential geologi- cal CO2 storage sites, e.g. depleted oil and gas field, unexploitable coal beds, saline aquifers, the latter are estimated to have the highest potential capacity (350-1000 Gt CO2 ) and, being relatively common worldwide, a higher probability to be located close to major CO2 anthropogenic sources. In these sites CO2 can safely be retained at depth for long times, as follows: a) physical Trapping into geologic structures; b) hy- drodynamic Trapping where CO2(aq) slowly migrates in an aquifer, c) solubility trap- ping after the dissolution of CO2(aq) and d) Mineral Trapping as secondary carbon- ates precipitate. Despite the potential advantages of CO2 geo-sequestration, risks of CO2 leakage from the reservoir have to be carefully evaluated by both monitoring techniques and numerical modeling used in “CO2 analogues”, although seepage from saline aquifers is unlikely to be occurring. The fate of CO2 once injected into a saline aquifer can be predicted by means of numerical modelling procedures of geochemical processes, these theoretical calculations being one of the few approaches for inves- tigating the short-long-term consequences of CO2 storage. This study is focused on some Italian deep-seated (>800 m) saline aquifers by assessing solubility and min- eral Trapping potentiality as strategic need for some feasibility studies that are about to be started in Italy. Preliminary results obtained by numerical simulations of a geo- chemical modeling applied to an off-shore Italian carbonatic saline aquifer potential suitable to geological CO2 storage are here presented and discussed. Deep well data, still covered by industrial confidentiality, show that the saline aquifer, includes six Late Triassic-Early Jurassic carbonatic formations at the depth of 2500-3700 m b.s.l. These formations, belonging to Tuscan Nappe, consist of porous limestones (mainly calcite) and marly limestones sealed, on the top, by an effective and thick cap-rock (around 2500 m) of clay flysch belonging to the Liguride Units. The evaluation of the potential geochemical impact of CO2 storage and the quantification of water-gas-rock reactions (solubility and Mineral Trapping) of injection reservoir have been performed by the PRHEEQC (V2.11) Software Package via corrections to the code default ther- modynamic database to obtain a more realistic modelling. The main modifications to the Software Package are, as follows: i) addition of new solid phases, ii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iii) addi- tion of kinetic rate equations of several Minerals and iv) calculation of reaction sur- face area. Available site-specific data include only basic physical parameters such as temperature, pressure, and salinity of the formation waters. Rocks sampling of each considered formation in the contiguous in-shore zones was carried out. Mineralogy was determined by X-Ray diffraction analysis and Scanning Electronic Microscopy on thin sections. As chemical composition of the aquifer pore water is unknown, this has been inferred by batch modeling assuming thermodynamic equilibrium between Minerals and a NaCl equivalent brine at reservoir conditions (up to 135 ̊C and 251 atm). Kinetic modelling was carried out for isothermal conditions (135 ̊C), under a CO2 injection constant pressure of 251 atm, between: a) bulk Mineralogy of the six formations constituting the aquifer, and b) pre-CO2 injection water. The kinetic evolu- tion of the CO2 -rich brines interacting with the host-rock Minerals performed over 100 years after injection suggests that solubility Trapping is prevailing in this early stage of CO2 injection. Further and detailed multidisciplinary studies on rock properties, geochemical and micro seismic monitoring and 3D reservoir simulation are necessary to better characterize the potential storage site and asses the CO2 storage capacity.PublishedVienna (Austria)2.4. TTC - Laboratori di geochimica dei fluidiope
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An approach to the geochemical modelling of water-rock interaction in CO2 storage geological reservoirs: the Weyburn Project (Canada) case study
2007Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Quattrocchi F.Abstract:Geological storage is one of the most promising technologies for reducing anthropogenic atmospheric emissions of CO2. Among the several CO2 storage techniques, sequestration in deep-seated saline aquifers implies four processes: a) supercritical fluid into geologic structure (physical Trapping), b) dissolved CO2(aq) due to very long flow path (hydrodynamic Trapping), c) dissolved CO2(aq) (solubility Trapping), and d) secondary carbonates (Mineral Trapping). The appealing concept that CO2 can permanently be retained underground has prompted several experimental studies in Europe and North America sponsored by IEA GHG R&D, EU and numerous international industrials and governments, the most important project being the International Energy Agency Weyburn CO2 Monitoring & Storage, an EnCana’s CO2 injection EOR project at Weyburn (Saskatchewan, Canada). Owing to the possible risks associated to this technique, numerical modelling procedures of geochemical processes are necessary to investigate the short- to long-term consequences of CO2 storage. Assumptions and gap-acceptance are made to reconstruct the reservoir conditions (pressure, pH, chemistry, and Mineral assemblage), although most strategic geochemical parameters of deep fluids are computed by a posteriori procedure due to the sampling collection at the wellhead, i.e. using depressurised aliquots. In this work a new approach to geochemical model capable of to reconstruct the reservoir chemical composition (T, P, boundary conditions and pH) is proposed using surface analytical data to simulate the short-medium term reservoir evolution during and after the CO2 injection. The PRHEEQC (V2.11) Software Package via thermodynamic corrections to the code default database has been used to obtain a more realistic modelling. The main modifications brought about the Software Package are: i) addition of new solid phases, ii) use of P>0.1 Mpa, iii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iv) addition of kinetic rate equations of several Minerals and v) calculation of reaction surface area. The Weyburn Project was selected as case study to test our model. The Weyburn oil-pull is recovered from the Midale Beds (1300-1500 m deep) that consist of two units of Mississippian shallow marine carbonate-evaporites: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. About 3 billions mc of supercritical CO2 have been injected into the “Phase A1” injection area. The INGV and the University of Calgary (Canada), have carried out a geochemical monitoring program (ca. thrice yearly- from pre-injection trip: “Baseline” trip, August 2000, to September 2004). The merged experimental data are the base of the present geochemical modeling. On the basis of the available data, i.e. a) bulk Mineralogy of the Marly and Vuggy reservoirs; b) mean gas-cap composition at the wellheads and c) selected pre- and post-CO2 injection water samples, the in-situ (62 °C and 0.1 MPa) reservoir chemical composition (including pH and the boundary conditions as PCO2, PH2S) has been re-built by the chemical equilibrium among the various phases, minimizing the effects of the past 30-years of water flooding in the oil field. The kinetic evolution of the CO2-rich Weyburn brines interacting with the host-rock Minerals performed over 100 years after injection have also been computed. The reaction path modeling suggests that CO2 can mainly be neutralized by solubility and Mineral Trapping via Dawsonite precipitation. To validate our model the geochemical impact of three years of CO2 injection (September 2000-2003) has been simulated by kinetically controlled reactions. The calculated chemical composition after the CO2 injection is consistent with the analytical data of samples collected in 2003 with a 90%), likely due to the complexation effect of carboxilic acid
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An approach to the geochemical modelling of water-rock interaction in CO2 storage geological reservoirs: the Weyburn Project (Canada) case study
2007Co-Authors: Cantucci B., Montegrossi G., Vaselli O., Quattrocchi F.Abstract:Geological storage is one of the most promising technologies for reducing anthropogenic atmospheric emissions of CO2. Among the several CO2 storage techniques, sequestration in deep-seated saline aquifers implies four processes: a) supercritical fluid into geologic structure (physical Trapping), b) dissolved CO2(aq) due to very long flow path (hydrodynamic Trapping), c) dissolved CO2(aq) (solubility Trapping), and d) secondary carbonates (Mineral Trapping). The appealing concept that CO2 can permanently be retained underground has prompted several experimental studies in Europe and North America sponsored by IEA GHG R&D, EU and numerous international industrials and governments, the most important project being the International Energy Agency Weyburn CO2 Monitoring & Storage, an EnCana’s CO2 injection EOR project at Weyburn (Saskatchewan, Canada). Owing to the possible risks associated to this technique, numerical modelling procedures of geochemical processes are necessary to investigate the short- to long-term consequences of CO2 storage. Assumptions and gap-acceptance are made to reconstruct the reservoir conditions (pressure, pH, chemistry, and Mineral assemblage), although most strategic geochemical parameters of deep fluids are computed by a posteriori procedure due to the sampling collection at the wellhead, i.e. using depressurised aliquots. In this work a new approach to geochemical model capable of to reconstruct the reservoir chemical composition (T, P, boundary conditions and pH) is proposed using surface analytical data to simulate the short-medium term reservoir evolution during and after the CO2 injection. The PRHEEQC (V2.11) Software Package via thermodynamic corrections to the code default database has been used to obtain a more realistic modelling. The main modifications brought about the Software Package are: i) addition of new solid phases, ii) use of P>0.1 Mpa, iii) variation of the CO2 supercritical fugacity and solubility under reservoir conditions, iv) addition of kinetic rate equations of several Minerals and v) calculation of reaction surface area. The Weyburn Project was selected as case study to test our model. The Weyburn oil-pull is recovered from the Midale Beds (1300-1500 m deep) that consist of two units of Mississippian shallow marine carbonate-evaporites: i) the dolomitic “Marly” and ii) the underlying calcitic “Vuggy”, sealed by an anhydrite cap-rock. About 3 billions mc of supercritical CO2 have been injected into the “Phase A1” injection area. The INGV and the University of Calgary (Canada), have carried out a geochemical monitoring program (ca. thrice yearly- from pre-injection trip: “Baseline” trip, August 2000, to September 2004). The merged experimental data are the base of the present geochemical modeling. On the basis of the available data, i.e. a) bulk Mineralogy of the Marly and Vuggy reservoirs; b) mean gas-cap composition at the wellheads and c) selected pre- and post-CO2 injection water samples, the in-situ (62 °C and 0.1 MPa) reservoir chemical composition (including pH and the boundary conditions as PCO2, PH2S) has been re-built by the chemical equilibrium among the various phases, minimizing the effects of the past 30-years of water flooding in the oil field. The kinetic evolution of the CO2-rich Weyburn brines interacting with the host-rock Minerals performed over 100 years after injection have also been computed. The reaction path modeling suggests that CO2 can mainly be neutralized by solubility and Mineral Trapping via Dawsonite precipitation. To validate our model the geochemical impact of three years of CO2 injection (September 2000-2003) has been simulated by kinetically controlled reactions. The calculated chemical composition after the CO2 injection is consistent with the analytical data of samples collected in 2003 with a 90%), likely due to the complexation effect of carboxilic acid.PublishedRimini, Italy2.4. TTC - Laboratori di geochimica dei fluidiope