Bibliography - S. Gasda

1. Gasda, S., Jan M. Nordbotten, and Michael Celia, 2012: Application of simplified models to CO₂ migration and immobilization in large-scale geological systems. International Journal of Greenhouse Gas Control, Elsevier, 9, doi:10.1016/j.ijggc.2012.03.001 72-84
   [ Abstract ]

   Long-term stabilization of injected carbon dioxide (CO₂) is an essential component of risk management for geological carbon sequestration operations. However, migration and trapping phenomena are inherently complex, involving processes that act over multiple spatial and temporal scales. One example involves centimeter-scale density instabilities in the dissolved CO₂ region leading to large-scale convective mixing that can be a significant driver for CO₂ dissolution. Another example is the potentially important effect of capillary forces, in addition to buoyancy and viscous forces, on the evolution of mobile CO₂. Local capillary effects lead to a capillary transition zone, or capillary fringe, where both fluids are present in the mobile state. This small-scale effect may have a significant impact on large-scale plume migration as well as long-term residual and dissolution trapping. Computational models that can capture both large and small-scale effects are essential to predict the role of these processes on the long-term storage security of CO₂ sequestration operations. Conventional modeling tools are unable to resolve sufficiently all of these relevant processes when modeling CO₂ migration in large-scale geological systems. Herein, we present a vertically-integrated approach to CO₂ modeling that employs upscaled representations of these subgrid processes. We apply the model to the Johansen formation, a prospective site for sequestration of Norwegian CO₂ emissions, and explore the sensitivity of CO₂ migration and trapping to subscale physics. Model results show the relative importance of different physical processes in large-scale simulations. The ability of models such as this to capture the relevant physical processes at large spatial and temporal scales is important for prediction and analysis of CO₂ storage sites.

2. Gasda, S., Jan M. Nordbotten, and Michael Celia, 2011: The impact of local-scale processes on large-scale CO₂ migration and immobilization. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia, doi:10.1016/j.egypro.2011.02.327 3896-3903
   [ Abstract ]

   Storage security of injected carbon dioxide (CO₂) is an essential component of risk management for geological carbon sequestration operations. During the injection and early post-injection periods, CO₂ leakage may occur along faults and leaky wells, but this risk may be partly managed by proper site selection and sensible deployment of monitoring and remediation technologies. On the other hand, long-term storage security is an entirely different risk management problem—one that is dominated by a mobile CO₂ plume that may travel over very large spatial distances, over long time periods, before it is trapped by a variety of different physical and chemical processes. In the post-injection phase, the mobile CO₂ plume migrates in large part due to buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over thousands to tens of thousands of years and can immobilize a significant portion of the mobile, free-phase CO₂ plume. However, both the migration and trapping processes are inherently complex, involving a combination of small and large spatial scales and acting over a range of time scales. Solubility trapping is a prime example of this complexity, where small-scale density instabilities in the dissolved CO₂ region leads to convective mixing that has that has a significant effect on the large-scale dissolution process over very long time scales. Another example is the effect of capillary forces on the evolution of mobile CO₂, an often-neglected process except with regard to residual trapping. As the plume migrates due to buoyancy and viscous forces, local capillary effects acting at the CO₂-brine interface lead to a transition zone where both fluids are present in the mobile state. This small-scale effect may have a significant impact on large-scale plume migration as well as long-term residual and dissolution trapping. Using appropriate models that can capture both large and small-scale effects is essential for understanding the role of these processes on the long-term storage security of CO₂ sequestration operations. There are several approaches to modeling long-term CO₂ trapping mechanisms. One modeling option is the use of traditional numerical methods, which are often highly sophisticated models that can handle multiple complex phenomena with high levels of accuracy. However, these complex models quickly become prohibitively expensive for the type of large-scale, long-term modeling that is necessary for risk assessment applications such as the late post-injection period. We present an alternative modeling option that combines vertically-averaged governing equations with an upscaled representation of the dissolutionconvective mixing process and the local capillary transition zone at the CO₂-brine interface. CO₂ injection is solved numerically on a coarse grid, capturing the large-scale injection problem and the post-injection capillary trapping, while the upscaled dissolution and capillary fringe models capture these subscale effects and eliminate the need for expensive grid refinement to capture the subscale instabilities associated with convective mixing or the details of the capillary transition zone. With thismodeling approach, we demonstrate the effect of different modeling choices associated with dissolution and capillary processes for typical large-scale geological systems.

3. Gasda, S., Jan M. Nordbotten, and Michael Celia, 2011: Vertically averaged approaches for CO₂ migration with solubility trapping. Water Resources Research, American Geophysical Union, 47(W05528), doi:10.1029/2010WR009075 1-14
   [ Abstract ]

   The long-term storage security of injected carbon dioxide (CO₂) is an essential component of geological carbon sequestration operations. In the postinjection phase, the mobile CO₂ plume migrates in large part because of buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over hundreds to thousands of years and can immobilize a significant portion of the mobile CO₂ plume. However, both the migration and trapping processes are inherently complex, spanning multiple spatial and temporal scales. Using an appropriate model that can capture both large- and small-scale effects is essential for understanding the role of these processes on the long-term storage security of CO₂ sequestration operations. Traditional numerical models quickly become prohibitively expensive for the type of large-scale, long-term modeling that is necessary for characterizing the migration and immobilization of CO₂ during the postinjection period. We present an alternative modeling option that combines vertically integrated governing equations with an upscaled representation of the dissolution-convection process. With this approach, we demonstrate the effect of different modeling choices for typical large-scale geological systems and show that practical calculations can be performed at the temporal and spatial scales of interest.

4. Gasda, S., James Z. Wang, and Michael Celia, 2011: Analysis of in-situ wellbore integrity data for existing wells with long-term exposure to CO₂. Energy Procedia, Elsevier, 4, doi:10.1016/j.egypro.2011.02.525 5406-5413
   [ Abstract ]

   An important aspect of the risk associated with geological carbon dioxide sequestration is the integrity of existing wellbores that penetrate geological layers targeted for CO₂ injection. CO₂ leakage may occur through multiple pathways along a wellbore within the 'disturbed zone' surrounding the well casing. The disturbed zone is defined as the annular region along the exterior of the steel wellbore casing that includes the Portland cement sheath, the damage zone of the host rock and the casing-cement-rock interfaces. The effective permeability of this zone is a key parameter of wellbore integrity required for validation of numerical models. Effective permeability may depend on a number of complex factors, including long-term attack by aggressive fluids, poor well completion or actions related to production of fluids through the wellbore. Field tests are essential to understanding the in situ leakage properties of the millions of wells that exist in mature sedimentary basins in North America. We present results from recent field studies of different CO₂ producing wells from both natural CO₂ reservoirs and enhanced oil recovery (EOR) operations. These surveys have included a particular downhole pressure test, the vertical interference test (VIT), designed to determine the extent of hydraulic communication along the exterior of the well casing. The VIT test involves perforating the well casing in two separate intervals, both of which are located within the shale caprock and bracket a zone of cement identified to have a lower quality bond. Once the intervals are isolated with an inflatable packer, the system is pressurized from surface and held at a constant pressure, while simultaneously, the transient pressure response is measured in the lower isolated interval. The pressure transient data is an indicator of the extent of hydraulic communication and is the focus of subsequent analysis. The effective wellbore permeability can be determined through numerical analysis of the VIT data. Our objective is to identify to most effective method of analysis for estimating wellbore permeability. We evaluate two different automated parameter estimation methods, nonlinear regression and shuffled complex evolution metropolis methods. Within this study, we also estimated parameters such as permeability and compressibility of the low permeability shale zone to determine their effect on the resulting estimate of wellbore permeability. The results of this work demonstrate that parameter estimation can be effective at identifying the key parameters associated with wellbore integrity from VIT field tests, and ultimately reducing the uncertainty regarding the integrity of existing wellbores.

5. Crow, W., J. W. Carey, S. Gasda, D. B. Williams, and Michael Celia, 2010: Wellbore integrity analysis of a natural CO₂ producer. International Journal of Greenhouse Gas Control, Elsevier, (4), doi:10.1016/j.ijggc.2009.10.010 186-197
   [ Abstract ]

   Long-term integrity of existing wells in a CO₂-rich environment is essential for ensuring that geological sequestration of CO₂ will be an effective technology for mitigating greenhouse gas-induced climate change. The potential for wellbore leakage depends in part on the quality of the original construction as well as geochemical and geomechanical stresses that occur over its life-cycle. Field data are essential for assessing the integrated effect of these factors and their impact on wellbore integrity, defined as the maintenance of isolation between subsurface intervals. In this report, we investigate a 30-year-old well from a natural CO₂ production reservoir using a suite of downhole and laboratory tests to characterize isolation performance. These tests included mineralogical and hydrological characterization of 10 core samples of casing/cement/formation, wireline surveys to evaluate well conditions, fluid samples and an in situ permeability test. We find evidence for CO₂ migration in the occurrence of carbonated cement and calculate that the effective permeability of an 11'-region of the wellbore barrier system was between 0.5 and 1 milliDarcy. Despite these observations, we find that the amount of fluid migration along the wellbore was probably small because of several factors: the amount of carbonation decreased with distance from the reservoir, cement permeability was low (0.3-30 microDarcy), the cement-casing and cement-formation interfaces were tight, the casing was not corroded, fluid samples lacked CO₂, and the pressure gradient between reservoir and caprock was maintained. We conclude that the barrier system has ultimately performed well over the last 3 decades. These results will be used as part of a broader effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO₂ storage sites.

6. Class, H., R. Ebigbo, R. Helmig, H. Dahle, Jan M. Nordbotten, Michael Celia, P. Audigane, M. Darcis, J. Ennis-King, Y. Fan, B. Flemisch, and S. Gasda, et al., 2009: A Benchmark Study on Problems Related to CO₂ Storage in Geological Formations: Summary and Discussion of the Results. Computational Geosciences, doi:10.1007/s10596-009-9146-x
   [ Abstract ]

   This paper summarises the results of a benchmark study that compares a number of mathematical and numerical models applied to specific problems in the context of carbon dioxide (CO₂) storage in geologic formations. The processes modeled comprise advective multiphase flow, compositional effects due to dissolution of CO₂ into the ambient brine, and non-isothermal effects due to temperature gradients and the Joule-Thompson effect. The problems deal with leakage through a leaky well, methane recovery enhanced by CO₂ injection, and a reservoir-scale injection scenario into a heterogeneous formation. We give a description of the benchmark problems, then briefly introduce the participating codes, and finally present and discuss the results of the benchmark study.

7. Crow, W., D. B. Williams, J. W. Carey, Michael Celia, and S. Gasda, 2009: Solubility and Diffusivity of SO₂ for Co-injection with CO₂ in Geological Sequestration. EOS Trans. AGU, 89(53), Fall Meet. S,
   [ Abstract ]

   There are potential economic benefits to the co-injection of SO₂ with CO₂ in the context of geological sequestration, but the impact of this co-injection on the fate and migration of SO₂ and CO₂ is poorly understood. Previous modeling studies have shown that injection of SO₂ with CO₂ would create highly acidic conditions due to formation of sulfuric acid. However, little is known regarding the solubility of SO₂ under high pressure, high salinity conditions, and the kinetic limitations of SO₂ diffusion in a CO₂ phase. A method to estimate the phase partitioning of SO₂ under geological storage conditions was developed in this study. The method uses the Krichevsky-Ilinskaya equation to correct for high pressures and the Schumpe model for mixed electrolyte solutions. Henry's constants for a broad range of brine solutions were calculated at storage conditions of 100 bar pressure. The Henry's constant for SO₂ is 1.5 M/atm at 40°C and is 0.86 M/atm at 60°C. Under these same conditions, the Henry's constant for CO₂ is much smaller, roughly 0.01 M/atm (40°C to 60°C). Henry's constants increase with increasing pressure but decrease with increasing temperature. These effects can be observed by comparing the SO₂ Henry's constants under storage conditions with the value under ambient temperature and pressure conditions in pure water, 1.2 M/atm. To simulate diffusion through stationary CO₂, a nonsteady state two-dimensional model of SO2 diffusion through supercritical CO₂ was also created. A binary diffusion coefficient of 5×10-8 m²/sec was estimated based on the Takahashi correlation to account for high pressures, where a low pressure coefficient was determined using the Fuller estimation. Binary diffusion coefficients for polar compounds in supercritical CO₂ have been previously studied and are on the same order of magnitude as the binary diffusion coefficient estimated in this study. The system that was modeled is a cone-shaped system representing separate-phase CO₂ confined in a formation after injection. Boundary conditions consisted of a no-flux boundary at the top of the cone to account for the impermeable confining caprock, and a zero concentration boundary at the cone edge to simulate a worst case scenario for dissolution. The initial conditions considered a uniform concentration of one percent SO₂ everywhere in the cone. To numerically simulate the concentration profile throughout the cone, a time-split explicit difference method was applied. The diffusion modeling results show that contact between SO₂ and formation brine will be diffusion limited; after 3000 years pproximately 75% of sulfur remains in the cone. In summary, while SO₂ is highly soluble in water, its slow diffusion through a supercritical CO2 phase will likely inhibit its mass transfer.

8. Crow, W., D. B. Williams, J. W. Carey, Michael Celia, and S. Gasda, 2009: Wellbore Integrity Analysis of a Natural CO₂ Producer. Energy Procedia, 1, doi:10.1016/j.egypro.2009.02.150 3561-3569
   [ Abstract ]

   The long-term integrity of wellbores in a CO₂-rich environment is a complex function of material properties and reservoir conditions including brine and rock compositions, CO₂- pressure, and formation pressure and temperature gradients. Laboratory experiments can provide essential information on rates of material reaction with CO₂-. However, field data are essential for assessing the integrated effect of these factors in subsurface conditions to provide a basis for validation of numerical models of wellbore behavior. We present a comprehensive study and conclusions from an investigation of a 30-year old well from a natural CO₂- production reservoir. The wellbore was exposed to a 96% CO₂- fluid from the time of cement placement. This site is unique for two reasons: it represents a higher, sustained concentration of CO₂- compared to enhanced oil recovery fields and both the reservoir and caprock are clastic rocks that may possess less buffering capacity than carbonate reservoirs. A sampling program resulted in the recovery of 10 side-wall cement cores extending from the reservoir through the caprock. The hydrologic, mineralogical and mechanical properties of these samples were measured and those results were combined with an in-situ pressure-response test to investigate cement integrity over a range of length scales. Fluid sampling was conducted with pressure and temperature measurements for geochemical analysis of the cemented annulus and the adjacent formation. These combined data sets provide an assessment of well integrity including original cement seal and the impacts of CO₂-. Cement evaluation wireline surveys indicate good coverage and bonding, consistent with observations from sidewall cement core samples that have tight interfaces with the casing and formation. Although alteration of the cement samples is present in all cores in varying degrees, hydraulic isolation has prevented leakage based on the pressure gradient measured between the caprock and CO₂- formation as well as lack of corrosion and no casing pressure history. Simulation of a hydraulic isolation test (Vertical Interference Test) indicates the best match for effective permeability of the wellbore system is approximately 1-10 millidarcies which suggests cement interfaces are a more significant potential migration pathway as compared with the cement matrix. Effective placement of the Portland-fly ash cement system was a key element in the observed performance of the barrier system that provides hydraulic isolation. The types of information collected in this survey permit analysis of individual components (casing, cement and reservoir fluid and pressure measurements) for comparison to the larger scale system including the interfaces. The results will be used as part of the CO₂- Capture Project’s effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO₂- storage sites.

9. Gasda, S., Michael Celia, and Jan M. Nordbotten, 2009: Vertical Equilibrium with Subscale Analytical Methods for Geological CO₂ Sequestration. Computational Geosciences, doi:10.1007/S10596-009-9138-X
   [ Abstract ]

   Large-scale implementation of geological CO₂ sequestration requires quantification of risk and leakage potential. One potentially important leakage pathway for the injected CO₂ involves existing oil and gas wells. Wells are particularly important in North America, where more than a century of drilling has created millions of oil and gas wells. Models of CO₂ injection and leakage will involve large uncertainties in parameters associated with wells, and therefore a probabilistic framework is required. These models must be able to capture both the largescale CO₂ plume associated with the injection and the small-scale leakage problem associated with localized flow along wells. Within a typical simulation domain, many hundreds of wells may exist. One effective modeling strategy combines both numerical and analytical models with a specific set of simplifying assumptions to produce an efficient numerical–analytical hybrid model. The model solves a set of governing equations derived by vertical averaging with assumptions of a macroscopic sharp interface and vertical equilibrium. These equations are solved numerically on a relatively coarse grid, with an analytical model embedded to solve for wellbore flow occurring at the sub-gridblock scale. This vertical equilibrium with sub-scale analytical method (VESA) combines the flexibility of a numerical method, allowing for heterogeneous and geologically complex systems, with the efficiency and accuracy of an analytical method, thereby eliminating expensive grid refinement for sub-scale features. Through a series of benchmark problems, we show that VESA compares well with traditional numerical simulations and to a semi-analytical model which applies to appropriately simple systems. We believe that the VESA model provides the necessary accuracy and efficiency for applications of risk analysis in many CO₂ sequestration problems.

10. Gasda, S., Jan M. Nordbotten, and Michael Celia, 2008: Determining Effective Wellbore Permeability from a Field Pressure Test: A Numerical Analysis of Detection Limits. Environmental Geology, 54(6), doi:10.1007/S00254-007-0903-7 1207-1215
    [ Abstract ]

    We propose a simple pressure test that can be used in the field to determine the effective permeability of existing wellbores. Such tests are motivated by the need to understand and quantify leakage risks associated with geological storage of CO₂ in mature sedimentary basins. If CO₂ is injected into a deep geological formation, and the resulting CO₂ plume encounters a wellbore, leakage may occur through various pathways in the ‘‘disturbed zone’’ surrounding the well casing. The effective permeability of this composite zone, on the outside of the well casing, is an important parameter for models of leakage. However, the data that exist on this key parameter do not exist in the open literature, and therefore specific field tests need to be done in order to reduce the uncertainty inherent in the leakage estimates. The test designed and analyzed herein is designed to measure effective wellbore permeability within a lowpermeability caprock, bounded above and below by permeable reservoirs, by pressurizing the reservoir below and measuring the response in the reservoir above. Alternatively, a modified test can be performed within the caprock without directly contacting the reservoirs above and below. We use numerical simulation to relate pressure response to effective well permeability and then evaluate the range of detection of the effective permeability based on instrument measurement error and limits on fracture pressure. These results can guide field experiments associated with site characterization and leakage analysis.

11. Gasda, S., Michael Celia, and Jan M. Nordbotten, 2008: Upslope Plume Migration and Implications for Geological CO₂ Sequestration in Deep Saline Aquifers. IES Journal A: Civil and Structural Engineering, 1(1), doi:10.1080/19373260701620154
    [ Abstract ]

    Recent investigations regarding CO₂ sequestration in deep saline aquifers have focused on characterization of the injected plume, its migration within the aquifer over time, and possible leakage out of the aquifer. To study these complex flow systems, simplified models are sometimes used to describe both plume evolution and the amount of leakage. Simplifications may include an assumption of perfectly horizontal geological formations, negligible capillary pressure, and symmetry of the injection plume. In this study, we explicitly test the limits of the assumption of a horizontal aquifer through numerical simulation of typical injection scenarios in continental sedimentary basins. Our approach is to simulate injection of CO₂ into a confined saline aquifer for an extended period (we have used 15 years) and examine the effect of different degrees of slope, as well as other system parameters, on plume asymmetry using measures such as the location of the centroid of the CO₂ plume. Dimensional analysis of this system shows that the centroid migrates upslope in proportion with buoyancy, aquifer permeability, and slope, whereas increased porosity and CO₂ viscosity mitigate upslope migration of the centroid. The results of this study show that the effect of slope can be ignored for many aquifers likely to become CO₂ sequestration sites in North America. However, slope will be more important for higher permeability aquifers, such as the site used in the Sleipner sequestration project in the North Sea.

12. Celia, Michael, , Jan M. Nordbotten, D. Kavetski, and S. Gasda, 2006: A Risk Assessment Modeling Tool to Quantify Leakage Potential through Wells in Mature Sedimentary Basins. Proceedings of the 8th International Conference on Greenhouse Gas Control Technologies (GHGT-8),
    [ Abstract ]

    The mature sedimentary basins of North America have a long history of oil and gas exploration and production. This has resulted in many wells being drilled, with a substantial number of them now abandoned. Therefore, injection and storage of CO₂ in these basins requires analysis of possible leakage along those wells. A computationally fast semianalytical model of CO₂ injection and potential leakage along wells has been developed, capturing many of the dominant physical characteristics of largescale injection systems. This paper illustrates the capabilities of the model using a case study based on a potential CO₂ sequestration site in Alberta, Canada. The selection of model inputs reflecting the uncertainty in the condition of abandoned wells is considered. The use of the semianalytical model in a probabilistic risk assessment framework is discussed, outlining avenues for systematic regulatory analysis of injection scenarios and systems.

13. Gasda, S., Jan M. Nordbotten, and Michael Celia, June 2006: Significance of Dipping Angle on CO₂ Plume Migration in Deep Saline Aquifers. Proceedings of the XVI Intl Conf on Computational Methods in Water Resources, Copenhagen, http://proceedings.cmwr-xvi.org/getFile.py/access?contribId=63,
    [ Abstract ]

    Recent investigations regarding CO₂ sequestration in deep, saline aquifers have focused on characterization of the injected plume, its migration within the aquifer over time, and possible leakage out of the aquifer. As part of our efforts to understand and quantify leakage potential in CO₂ storage systems, a semi-analytical solution has been developed that describes the plume shape evolution as well the amount of leakage, with a focus on leakage along abandoned wells. The semi-analytical solutions require a number of simplifying assumptions, including a perfectly horizontal aquifer, negligible capillary pressure, and symmetry of the injection plume. Each of these assumptions can be tested systematically through application of more general numerical simulators. In typical sedimentary basins, it is common to have sloping aquifers with a vertical rise of up to 3-4 km over the total horizontal length of the basin (hundreds of kilometers). In this study, we use a general two-phase numerical simulator to assess the limitations of the assumptions required to derive semi-analytical solutions to these systems. In this presentation we will present results from these simulations and discuss their implications regarding the extent to which CO₂ injection systems can be simplified.

14. Celia, Michael, , Jan M. Nordbotten, D. Kavetski, and S. Gasda, May 2005: Modeling Critical Leakage Pathways in a Risk Assessment Framework: Representation of Abandoned Wells. Proceedings of the 4th Annual Conference on Carbon Capture and Sequestration, http://www.netl.doe.gov/publications/proceedings/05/carbon-seq/Tech%20Session%20Paper%20115.pd,
    [ Abstract ]

    In many locations in North America, likely injection sites for CO₂ storage in deep geological formation are located in mature sedimentary basins. These basins have a century-long history of oil and gas exploration and production, which has led to hundreds of thousands of wells (the Alberta Basin) to more than a million wells (Texas) being drilled. The spatial density of these wells is on the order of 0.5 to 5 wells per square kilometer. Therefore, a typical injection will produce a CO₂ plume that intersects hundreds of existing wells, many of which are abandoned and some of which have uncertain or unknown locations. In order to analyze the leakage potential in such situations, computational models must be developed that can cover large spatial areas (of order 1,000 km²) while resolving the local flow dynamics in all of the hundreds of wells. In addition, both the layered structure of the subsurface, and possible leakage along wells and into successive overlying permeable layers in the subsurface, also need to be represented. We have developed a semi-analytical model that can simulate all of these attributes, over decadal to century time scales, while running quickly on a laptop computer. With this tool, risk assessment based on Monte Carlo analysis can be carried out, and a quantitative analysis of leakage potential can be performed.

15. Gasda, S., and Michael Celia, 2005: Upscaling Relative Permeabilities in a Structured Porous Medium. Advances in Water Resources, 28(5), doi:10.1016/j.advwatres.2004.11.009
    [ Abstract ]

    Upscaling of multi-phase flow problems for a heterogeneous porous medium requires modification of constitutive functions at the grid-block scale. A particular type of heterogeneity that has important environmental consequences involves thin, continuous streaks of high permeability through lower-permeability background rocks. These streaks, which may correspond to features like abandoned wells in mature sedimentary basins, can become preferential flow paths for an invading fluid. Quantification of flow through these types of heterogeneities in deep, geological formations is necessary for estimates of migration and possible leakage of injected fluids such as hazardous liquid wastes, municipal liquid wastes, and, possibly, carbon dioxide. One of the important constitutive functions for proper estimation of flow through these flow paths is the relative permeability function. In the simple case of a single high-permeability streak in a uniform rock matrix, with both materials having identical (local) relative permeability functions, the upscaled relative permeability must be changed significantly to capture the proper leakage. Standard petroleum reservoir pseudo-functions for relative permeability capture the general features of the upscaled function, but they still produce errors of several hundred percent in the leakage estimation. Detailed three-dimensional numerical simulations and associated upscaled calculations demonstrate the proper form for the upscaled relative permeability, and provide a modified derivation of pseudo-functions to capture the leakage behavior in upscaled models.

16. Scherer, George, Michael Celia, Jean Hervé Prévost, , R. Bruant, A. Duguid, R. Fuller, S. Gasda, M. Radonjic, and W. Vichit-Vadakan, 2005: Leakage of CO₂ through Abandoned Wells: Role of Corrosion of Cement. The CO₂ Capture and Storage Project (CCP), Volume II, Chapter 10, 823-844
    [ Abstract ]

    The potential leakage of CO₂ from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative of North American basins, shows that a CO₂ plume and/or acidified brine may encounter up to several hundred wells. A review of the literature indicates that cement is not resistant to attack by acid, but little work has been reported for temperatures and pressures comparable to storage conditions. Therefore, an experimental program has been undertaken to determine the rate of corrosion and the changes in properties of oil well cements exposed to carbonated brine. Preliminary results indicate a very high rate of attack, so it is essential to have accurate models of the composition and pH of the brine, and the time that it will remain in contact with cement in abandoned wells. A model has been developed that incorporates a flash calculation of the phase distribution, along with analysis of the fluxes and pressure of the liquid, solid and vapor phases. A sample calculation indicates that wells surrounding the injection site may be in contact with the acidified brine for years.

17. Celia, Michael, , Jan M. Nordbotten, S. Gasda, and H. Dahle, September 2004: Quantitative Estimation of CO₂ Leakage from Geological Storage: Analytical Models, Numerical Models, and Data Needs. Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies, (GHGT-7), http://uregina.ca/ghgt7/PDF/papers/peer/228.pdf,
    [ Abstract ]

    Geological storage of CO₂ in mature sedimentary basins of North America requires special consideration of the large number of existing wells. Those wells represent potential leakage pathways for the stored CO₂, and must be analyzed in the context of an overall environmental risk assessment. Analysis of well patterns in the Alberta basin, Canada, indicates that injected CO₂ plumes are expected to contact from several tens to several hundreds of existing wells, depending on the local density of wells in the vicinity of the injection. Quantitative analysis of the impact of these wells requires an extensive data collection effort, analysis of materials used in well construction and abandonment, and different levels of computational modeling to ascertain the risk associated with these wells. New analytical solutions provide a promising avenue for leakage analysis at the large scale. Results from these models show accuracy comparable to more complex numerical simulators at a small fraction of the computational time. This allows many simulations to be run so that different parameters values can be explored. These large-scale models need to be coupled to smaller-scale detailed models of material behavior within the leaky well to provide a complete analysis of the problem.

18. Gasda, S., , and Michael Celia, 2004: Spatial characterization of the location of potentially leaky wells penetrating a deep saline aquifer in a mature sedimentary basin. Environmental Geology, 46(6-7), doi:10.1007/s00254-004-1073-5 707-720
    [ Abstract ]

    This work was motivated by considerations of potential leakage pathways for CO₂ injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO₂ injection, as defined by the spread of an injected CO₂ plume, varies from several hundred in high welldensity areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.

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