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Karsten Pruess - One of the best experts on this subject based on the ideXlab platform.
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toughreact version 2 0 a simulator for subsurface reactive transport under non isothermal multiphase flow conditions
Computers & Geosciences, 2011Co-Authors: Nicolas Spycher, Liange Zheng, Eric Sonnenthal, Guoxiang Zhang, Karsten PruessAbstract:TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media, and was developed by introducing reactive chemistry into the multiphase fluid and heat flow simulator TOUGH2 V2. The first version of TOUGHREACT was released to the public through the U.S. Department of Energy's Energy Science and Technology Software Center (ESTSC) in August 2004. It is among the most frequently requested of ESTSC's codes. The code has been widely used for studies in CO"2 Geological Sequestration, nuclear waste isolation, geothermal energy development, environmental remediation, and increasingly for petroleum applications. Over the past several years, many new capabilities have been developed, which were incorporated into Version 2 of TOUGHREACT. Major additions and improvements in Version 2 are discussed here, and two application examples are presented: (1) long-term fate of injected CO"2 in a storage reservoir and (2) biogeochemical cycling of metals in mining-impacted lake sediments.
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toughreact a simulation program for non isothermal multiphase reactive geochemical transport in variably saturated geologic media applications to geothermal injectivity and co2 Geological Sequestration
Computers & Geosciences, 2006Co-Authors: Eric Sonnenthal, Nicolas Spycher, Karsten PruessAbstract:TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media. The program was written in Fortran 77 and developed by introducing reactive geochemistry into the multiphase fluid and heat flow simulator TOUGH2. A variety of subsurface thermo-physical-chemical processes are considered under a wide range of conditions of pressure, temperature, water saturation, ionic strength, and pH and Eh. Interactions between mineral assemblages and fluids can occur under local equilibrium or kinetic rates. The gas phase can be chemically active. Precipitation and dissolution reactions can change formation porosity and permeability. The program can be applied to many geologic systems and environmental problems, including geothermal systems, diagenetic, and weathering processes, subsurface waste disposal, acid mine drainage remediation, contaminant transport, and groundwater quality. Here we present two examples to illustrate applicability of the program. The first example deals with injectivity effects of mineral scaling in a fractured geothermal reservoir. A major concern in the development of hot dry rock and hot fractured rock reservoirs is achieving and maintaining adequate injectivity, while avoiding the development of preferential short-circuiting flow paths. Rock-fluid interactions and associated mineral dissolution and precipitation effects could have a major impact on the long-term performance of these reservoirs. We used recent European studies as a starting point to explore chemically induced effects of fluid circulation in the geothermal systems. We examine ways in which the chemical composition of reinjected waters can be modified to improve reservoir performance by maintaining or even enhancing injectivity. The second TOUGHREACT application example is related to CO"2 geologic Sequestration in a saline aquifer. We performed numerical simulations for a commonly encountered Gulf Coast sediment under CO"2 injection conditions in order to analyze the impact of CO"2 immobilization through carbonate precipitation. Using the data presented in this paper, the CO"2 mineral-trapping capability after 10,000 years can reach 60kg/m^3 of sandstone by secondary carbonate mineral precipitation such as siderite, ankerite, and dawsonite. Most of the simulated mineral alteration pattern is consistent with the field observations of natural CO"2 reservoirs. s.
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co2 h2o mixtures in the Geological Sequestration of co2 ii partitioning in chloride brines at 12 100 c and up to 600 bar
Geochimica et Cosmochimica Acta, 2005Co-Authors: Nicolas Spycher, Karsten PruessAbstract:Correlations presented by Spycher et al. (2003) to compute the mutual solubilities of CO2 and H2O are extended to include the effect of chloride salts in the aqueous phase. This is accomplished by including, in the original formulation, activity coefficients for aqueous CO2 derived from several literature sources, primarily for NaCl solutions. Best results are obtained when combining the solubility correlations of Spycher et al. (2003) with the activity coefficient formulation of Rumpf et al. (1994) and Duan and Sun (2003), which can be extended to chloride solutions other than NaCl. This approach allows computing mutual solubilities in a noniterative manner with an accuracy typically within experimental uncertainty for solutions up to 6 molal NaCl and 4 molal CaCl2.
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co2 h2o mixtures in the Geological Sequestration of co2 i assessment and calculation of mutual solubilities from 12 to 100 c and up to 600 bar
Geochimica et Cosmochimica Acta, 2003Co-Authors: Nicolas Spycher, Karsten Pruess, Jonathan EnniskingAbstract:Abstract Evaluating the feasibility of CO 2 geologic Sequestration requires the use of pressure-temperature-composition ( P - T - X ) data for mixtures of CO 2 and H 2 O at moderate pressures and temperatures (typically below 500 bar and below 100°C). For this purpose, published experimental P - T - X data in this temperature and pressure range are reviewed. These data cover the two-phase region where a CO 2 -rich phase (generally gas) and an H 2 O-rich liquid coexist and are reported as the mutual solubilities of H 2 O and CO 2 in the two coexisting phases. For the most part, mutual solubilities reported from various sources are in good agreement. In this paper, a noniterative procedure is presented to calculate the composition of the compressed CO 2 and liquid H 2 O phases at equilibrium, based on equating chemical potentials and using the Redlich-Kwong equation of state to express departure from ideal behavior. The procedure is an extension of that used by King et al. (1992), covering a broader range of temperatures and experimental data than those authors, and is readily expandable to a nonideal liquid phase. The calculation method and formulation are kept as simple as possible to avoid degrading the performance of numerical models of water-CO 2 flows for which they are intended. The method is implemented in a computer routine, and inverse modeling is used to determine, simultaneously, (1) new Redlich-Kwong parameters for the CO 2 -H 2 O mixture, and (2) aqueous solubility constants for gaseous and liquid CO 2 as a function of temperature. In doing so, mutual solubilities of H 2 O from 15 to 100°C and CO 2 from 12 to 110°C and up to 600 bar are generally reproduced within a few percent of experimental values. Fugacity coefficients of pure CO 2 are reproduced mostly within one percent of published reference data.
David A Barnes - One of the best experts on this subject based on the ideXlab platform.
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effects of reduction in porosity and permeability with depth on storage capacity and injectivity in deep saline aquifers a case study from the mount simon sandstone aquifer
International Journal of Greenhouse Gas Control, 2011Co-Authors: Cristian R Medina, John A Rupp, David A BarnesAbstract:Abstract The Upper Cambrian Mount Simon Sandstone is recognized as a deep saline reservoir that has significant potential for Geological Sequestration in the Midwestern region of the United States. Porosity and permeability values collected from core analyses in rocks from this formation and its lateral equivalents in Indiana, Kentucky, Michigan, and Ohio indicate a predictable relationship with depth owing to a reduction in the pore structure due to the effects of compaction and/or cementation, primarily as quartz overgrowths. The regional trend of decreasing porosity with depth is described by the equation: ϕ ( d ) = 16.36 × e −0.00039* d , where ϕ is the porosity and d is the depth in m. The decrease of porosity with depth generally holds true on a basinwide scale. Bearing in mind local variations in lithologic and petrophysical character within the Mount Simon Sandstone, the source data that were used to predict porosity were utilized to estimate the pore volume available within the reservoir that could potentially serve as storage space for injected CO 2 . The potential storage capacity estimated for the Mount Simon Sandstone in the study area, using efficiency factors of 1%, 5%, 10%, and 15%, is 23,680, 118,418, 236,832, and 355,242 million metric tons of CO 2 , respectively.
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Geological Sequestration of carbon dioxide in the cambrian mount simon sandstone regional storage capacity site characterization and large scale injection feasibility michigan basin
Environmental Geosciences, 2009Co-Authors: David A Barnes, Diana H Bacon, Stephen R KelleyAbstract:The Mount Simon Sandstone (Cambrian) is recognized as an important deep saline reservoir with potential to serve as a target for Geological Sequestration in the Midwest, United States. The Mount Simon Sandstone in Michigan consists primarily of sandy clastics and grades upward into the more argillaceous Eau Claire Formation, which serves as a regional confining zone. The Mount Simon Sandstone lies at depths from about 914 m (3000 ft) to more than 4572 m (15,000 ft) in the Michigan Basin and ranges in thickness from more than 396 m (1300 ft) to near zero adjacent to basement highs. The Mount Simon Sandstone has variable reservoir quality characteristics dependent on sedimentary facies variations and depth-related diagenesis. On the basis of well-log-derived net porosity from wells in the Michigan Basin, estimates of total Geological Sequestration capacity were determined to be in excess of 29 billion metric tons (Gt). Most of this capacity is located in the southwestern part of the state. Numerical simulations of carbon dioxide (CO2) injection were conducted using the subsurface transport over multiple phases-water-CO2-salt (STOMP-WCS) simulator code to assess the potential for geologic Sequestration into the Mount Simon saline reservoir in the area of Holland, Ottawa County, Michigan. At this locality, the reservoir is more than 260 m (850 ft) thick and has a minimum of 30 m (100 ft) of net porosity. The simulation used a CO2 injection period of 20 yr at a rate of 600,000 metric tons (t)/yr, followed by an equilibration period of 280 yr, for a total of 300 yr. After 20 yr, the total amount of CO2 injected is 12 million metric tons (Mt); after 300 yr, 9.8 Mt is modeled to remain as a free-phase (nonentrapped) supercritical CO2, 0.7 Mt is capillary-entrapped (residual) supercritical CO2, and 1.5 Mt dissolved into the brine. The injected CO2 spread to an area with a radius of 1.8 km (1.12 mi) after 20 yr of injection at a single well and to an area with a radius of 3.8 km (2.36 mi) after 300 yr. The low-permeability Eau Claire retards the upward migration of CO2. Pressures during injection at the bottom of the cap rock (1540.5-m [5054-ft] depth) are well below the fracture pressure limit of 27.9 MPa (4046.6 psi), assuming a fracture pressure gradient of 0.018 MPa/m (0.8 psi/ft) caused by the high permeability of the Mount Simon Sandstone.
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practical synergies for increasing domestic oil production and Geological Sequestration of anthropogenic co2 an example from the michigan basin
2009Co-Authors: Michael G Grammer, David A Barnes, William B Harrison, Anthony E Sandomierski, Robert G MannesAbstract:As oil imports in the United States approach 60% of total daily consumption, more efforts are being expended to maximize recovery from known domestic oil fields. As part of this effort, CO2 flooding of reservoirs has been proven to be an effective means to increase the recovery of oil bypassed during primary production, albeit commonly at significant cost because of capture, compression, and transportation of adequate CO2. At the same time, global and national interest in the viable Geological Sequestration of anthropogenic CO2, a major greenhouse gas when emitted into the atmosphere, is also becoming more significant. In the Michigan Basin, the juxtaposition of the Devonian Antrim Shale natural gas trend, one that contains high levels of associated CO2, with the mature Niagaran (Silurian) reef oil play, characterized by reservoirs with high percentages of stranded oil, may provide an economically viable model to combine enhanced oil recovery (EOR) efforts with the Geological Sequestration of CO2. Niagaran pinnacle reefs in the Michigan Basin have produced more than 450 MMBO since the late 1960s. Because of the complex heterogeneity of the reef reservoirs, however, primary production averages only around 30% with secondary waterflood programs typically capturing an additional 12%. The northern reef trend in the Michigan Basin comprises an immense hydrocarbon resource, located in hundreds of closely spaced but highly compartmentalized reef fields in northern lower Michigan. These Geologically complex carbonate reef reservoirs present not only significant opportunity for EOR operations because of known traps, quantifiable remaining oil, existing infrastructure, and very few secondary recovery projects to date, but also great challenges to modeling for maximum sweep efficiencies and recovery factors during miscible CO2-EOR projects. In the northern reef trend, a local source for subsequent CO2 flooding is readily available as a by-product of Antrim Shale production. The annual production of CO2 separated from Antrim gas is approximately 21 bcf, most of which is currently vented directly into the atmosphere. The close proximity of a source of high-quality CO2 from several gas-processing plants throughout the northern reef trend, a region with more than 800 Niagaran reef fields, provides an economically viable opportunity to combine CO2-flood EOR operations with Geological Sequestration of CO2 greenhouse gases. Initial results of a pilot project where CO2 from the Antrim Shale is being injected into several Niagaran reefs are discussed along with reservoir characterization issues associated with these heterogeneous reservoirs. Similar EOR projects throughout the northern reef trend could provide an economic foundation for CO2 Sequestration programs. This is especially the case if they are designed alongside industrial activities that generate easily captured CO2 emissions streams, such as other gas-processing plants or future ethanol plants planned for the region.
Nicolas Spycher - One of the best experts on this subject based on the ideXlab platform.
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toughreact version 2 0 a simulator for subsurface reactive transport under non isothermal multiphase flow conditions
Computers & Geosciences, 2011Co-Authors: Nicolas Spycher, Liange Zheng, Eric Sonnenthal, Guoxiang Zhang, Karsten PruessAbstract:TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media, and was developed by introducing reactive chemistry into the multiphase fluid and heat flow simulator TOUGH2 V2. The first version of TOUGHREACT was released to the public through the U.S. Department of Energy's Energy Science and Technology Software Center (ESTSC) in August 2004. It is among the most frequently requested of ESTSC's codes. The code has been widely used for studies in CO"2 Geological Sequestration, nuclear waste isolation, geothermal energy development, environmental remediation, and increasingly for petroleum applications. Over the past several years, many new capabilities have been developed, which were incorporated into Version 2 of TOUGHREACT. Major additions and improvements in Version 2 are discussed here, and two application examples are presented: (1) long-term fate of injected CO"2 in a storage reservoir and (2) biogeochemical cycling of metals in mining-impacted lake sediments.
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toughreact a simulation program for non isothermal multiphase reactive geochemical transport in variably saturated geologic media applications to geothermal injectivity and co2 Geological Sequestration
Computers & Geosciences, 2006Co-Authors: Eric Sonnenthal, Nicolas Spycher, Karsten PruessAbstract:TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media. The program was written in Fortran 77 and developed by introducing reactive geochemistry into the multiphase fluid and heat flow simulator TOUGH2. A variety of subsurface thermo-physical-chemical processes are considered under a wide range of conditions of pressure, temperature, water saturation, ionic strength, and pH and Eh. Interactions between mineral assemblages and fluids can occur under local equilibrium or kinetic rates. The gas phase can be chemically active. Precipitation and dissolution reactions can change formation porosity and permeability. The program can be applied to many geologic systems and environmental problems, including geothermal systems, diagenetic, and weathering processes, subsurface waste disposal, acid mine drainage remediation, contaminant transport, and groundwater quality. Here we present two examples to illustrate applicability of the program. The first example deals with injectivity effects of mineral scaling in a fractured geothermal reservoir. A major concern in the development of hot dry rock and hot fractured rock reservoirs is achieving and maintaining adequate injectivity, while avoiding the development of preferential short-circuiting flow paths. Rock-fluid interactions and associated mineral dissolution and precipitation effects could have a major impact on the long-term performance of these reservoirs. We used recent European studies as a starting point to explore chemically induced effects of fluid circulation in the geothermal systems. We examine ways in which the chemical composition of reinjected waters can be modified to improve reservoir performance by maintaining or even enhancing injectivity. The second TOUGHREACT application example is related to CO"2 geologic Sequestration in a saline aquifer. We performed numerical simulations for a commonly encountered Gulf Coast sediment under CO"2 injection conditions in order to analyze the impact of CO"2 immobilization through carbonate precipitation. Using the data presented in this paper, the CO"2 mineral-trapping capability after 10,000 years can reach 60kg/m^3 of sandstone by secondary carbonate mineral precipitation such as siderite, ankerite, and dawsonite. Most of the simulated mineral alteration pattern is consistent with the field observations of natural CO"2 reservoirs. s.
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co2 h2o mixtures in the Geological Sequestration of co2 ii partitioning in chloride brines at 12 100 c and up to 600 bar
Geochimica et Cosmochimica Acta, 2005Co-Authors: Nicolas Spycher, Karsten PruessAbstract:Correlations presented by Spycher et al. (2003) to compute the mutual solubilities of CO2 and H2O are extended to include the effect of chloride salts in the aqueous phase. This is accomplished by including, in the original formulation, activity coefficients for aqueous CO2 derived from several literature sources, primarily for NaCl solutions. Best results are obtained when combining the solubility correlations of Spycher et al. (2003) with the activity coefficient formulation of Rumpf et al. (1994) and Duan and Sun (2003), which can be extended to chloride solutions other than NaCl. This approach allows computing mutual solubilities in a noniterative manner with an accuracy typically within experimental uncertainty for solutions up to 6 molal NaCl and 4 molal CaCl2.
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co2 h2o mixtures in the Geological Sequestration of co2 i assessment and calculation of mutual solubilities from 12 to 100 c and up to 600 bar
Geochimica et Cosmochimica Acta, 2003Co-Authors: Nicolas Spycher, Karsten Pruess, Jonathan EnniskingAbstract:Abstract Evaluating the feasibility of CO 2 geologic Sequestration requires the use of pressure-temperature-composition ( P - T - X ) data for mixtures of CO 2 and H 2 O at moderate pressures and temperatures (typically below 500 bar and below 100°C). For this purpose, published experimental P - T - X data in this temperature and pressure range are reviewed. These data cover the two-phase region where a CO 2 -rich phase (generally gas) and an H 2 O-rich liquid coexist and are reported as the mutual solubilities of H 2 O and CO 2 in the two coexisting phases. For the most part, mutual solubilities reported from various sources are in good agreement. In this paper, a noniterative procedure is presented to calculate the composition of the compressed CO 2 and liquid H 2 O phases at equilibrium, based on equating chemical potentials and using the Redlich-Kwong equation of state to express departure from ideal behavior. The procedure is an extension of that used by King et al. (1992), covering a broader range of temperatures and experimental data than those authors, and is readily expandable to a nonideal liquid phase. The calculation method and formulation are kept as simple as possible to avoid degrading the performance of numerical models of water-CO 2 flows for which they are intended. The method is implemented in a computer routine, and inverse modeling is used to determine, simultaneously, (1) new Redlich-Kwong parameters for the CO 2 -H 2 O mixture, and (2) aqueous solubility constants for gaseous and liquid CO 2 as a function of temperature. In doing so, mutual solubilities of H 2 O from 15 to 100°C and CO 2 from 12 to 110°C and up to 600 bar are generally reproduced within a few percent of experimental values. Fugacity coefficients of pure CO 2 are reproduced mostly within one percent of published reference data.
Peixue Jiang - One of the best experts on this subject based on the ideXlab platform.
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assessing the feasibility and co2 storage capacity of co2 enhanced shale gas recovery using triple porosity reservoir model
Applied Thermal Engineering, 2017Co-Authors: Kecheng Zeng, Chunwei Zhang, Peixue JiangAbstract:Abstract The depletion of conventional energy sources is leading to increased demand for unconventional energy sources. Shale gas is an important unconventional energy source that has been successfully developed and utilized in the United States. CO2 enhanced shale gas recovery (CO2-ESG) is a promising shale gas extraction technology. Supercritical CO2 injection can enhance the shale gas recovery through competitive absorption between the methane and the CO2 while also providing CO2 Geological Sequestration. However, assessments of the feasibility of CO2 enhanced shale gas recovery in field scale trials is quite complicated given the complex pore structures in shale reservoirs and the ultralow permeability. This paper describes a triple porosity, dual permeability (TP-DK) model that includes the effects of the shale gas adsorption and desorption, the competitive adsorption and binary gas diffusion. The Sichuan basin in China is selected as the target reservoir. The key parameters in this simulation were determined by experimental measurements of shale samples from the Lower Silurian Longmaxi Formation (LSLF) shale in the Sichuan basin. The results show that the CO2 injection can significantly enhance the shale gas recovery. A 90 m thick shale gas reservoir with a 1200 m horizontal well absorb injections of CO2 captured from a large 1000 MWe coal-fired power plant for 2 years. However, the volume flow rate of the CO2 Sequestration decreased with time as the production pressure decreased. Both the production time and the production pressure should be considered on the synergy between the CO2 Sequestration and the shale gas recovery.
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flow and thermal modeling of co2 in injection well during Geological Sequestration
International Journal of Greenhouse Gas Control, 2013Co-Authors: Binglu Ruan, Lingli Wei, Xiaolong Ouyang, Feng Luo, Peixue JiangAbstract:Abstract A two-dimensional (2D) axisymmetric (radial) model, considering the effects of the fluid in annulus and heat transfer with surrounding rocks is developed to investigate the flow and thermal behavior of CO2 in injection well during its Geological Sequestration. The mass equation, the momentum equations with turbulent model and energy equation are solved both in the wellbore flow direction and the radial direction using computational fluid dynamics (CFD) method. Real-gas properties are employed to ensure the calculation accuracy. The wellhead pressure and bottomhole temperature behavior with injection time are predicted. The impact of natural convection of water in the annulus on flow and thermal behavior of injected CO2 are also studied. Besides, factors impacting the bottomhole temperature of CO2 are analyzed. It is found that the work done by pressure (compressibility), potential energy loss and the heat exchange with surrounding rocks are three major factors leading to an increase in the bottomhole temperature of CO2 comparing to the injection temperature. With an increase in injection mass flow rate, the wellhead pressure decreases firstly and then increases, and the bottomhole temperature of CO2 decreases nonlinearly. However, both of them increase linearly with an increase in the injection temperature. This study may help deepen our understanding of the mechanisms of CO2 injection and generate quantitative information in support of design, monitoring and risk assessment of the CO2 Geological Sequestration.
Stefan Bachu - One of the best experts on this subject based on the ideXlab platform.
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screening and ranking of sedimentary basins for Sequestration of co2 in Geological media in response to climate change
Environmental Earth Sciences, 2003Co-Authors: Stefan BachuAbstract:Sedimentary basins are suitable to different degrees for CO2 Geological Sequestration as a result of various intrinsic and extrinsic characteristics, of which the geothermal regime is one of the most important. Warm basins are less favorable for CO2 Sequestration than cold basins because of reduced capacity in terms of CO2 mass, and because of higher CO2 buoyancy, which drives the upward CO2 migration. A set of 15 criteria, with several classes each, has been developed for the assessment and ranking of sedimentary basins in terms of their suitability for CO2 Sequestration. Using a parametric normalization procedure, a basin's individual scores are summed to a total score using weights that express the relative importance of different criteria. The total score is ranked to determine the most suitable basin or region thereof for the Geological Sequestration of CO2. The method is extremely flexible in that it allows changes in the functions that express the importance of various classes for any given criterion, and in the weights that express the relative importance of various criteria. Examples of application are given for Canada's case and for the Alberta basin in Canada.
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Geological Sequestration of anthropogenic carbon dioxide in the western canada sedimentary basin suitability analysis
Journal of Canadian Petroleum Technology, 2002Co-Authors: Stefan Bachu, S StewartAbstract:Geological Sequestration of anthropogenic CO2 is a potential solution to the release into the atmosphere of CO2, a greenhouse gas thought as significantly contributing to the global warming trend observed since the beginning of the industrial revolution. Basically, CO2 can be sequestered in Geological media: 1) through enhanced oil recovery (EOR), 2) by storage in depleted oil and gas reservoirs, 3) through replacement by CO2 of methane in deep coal beds (ECBMR), 4) by injection into deep saline aquifers, and 5) by storage in salt caverns. Criteria in assessing the suitability of a sedimentary basin for CO2 Sequestration are: a) tectonism and geology, b) the flow of formation waters and geothermal regime, and c) the existence of storage media (hydrocarbon reservoirs, coal seams, deep aquifers and salt structures).
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Sequestration of co2 in Geological media in response to climate change road map for site selection using the transform of the Geological space into the co2 phase space
Energy Conversion and Management, 2002Co-Authors: Stefan BachuAbstract:Abstract Geological Sequestration of CO 2 is an immediately available and technologically feasible means of reducing CO 2 emissions into the atmosphere, which is particularly suited to landlocked sedimentary basins. Geoscience, engineering, economic and public issues need addressing by governments and industry before proceeding with full scale implementation. Specific site selection should be based on a suitability analysis, a proper inventory of potential sites, an assessment of the fate of the injected CO 2 and a capacity determination, together with surface criteria such as CO 2 capture and transport. The suitability analysis, both at the basin and regional scales, is based on Geological, geothermal, hydrodynamic, basin maturity, economic and societal criteria. The inventory of Sequestration sites needs also identification of major CO 2 point sources and a cost benefit analysis. The potential for CO 2 escape and migration is a deciding factor in screening out unsafe sites. Site capacity should be determined based on in situ conditions and CO 2 properties and behavior. Transforming the Geological space into the CO 2 space is an important step along the road map for selection of suitable CO 2 injection sites that allows the identification of safe large capacity sites. An example of application from the Alberta basin is presented.