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Highlights • Application of National Risk Assessment Partnership (NRAP) tools to geologic CO 2 sequestration in the Kevin Dome in Montana. • Sensitivity analysis of various reservoir properties and quality of legacy wells. • The developed risk assessment workflow using NRAP tools is shown to greatly reduce the computational burden. • The powerful stochastic framework is capable of risk assessment in field-scale applications. Abstract Geologic CO 2 sequestration (GCS) has received high-level attention from the global scientific community as a response to climate change due to higher concentrations of CO 2 in the atmosphere. However, GCS in saline aquifers poses certain risks including CO 2 /brine leakage through wells or non-sealing faults into groundwater or to the earth's surface. Understanding crucial reservoir parameters and other geologic features affecting the likelihood of these leakage occurrences will aid the decision-making process regarding GCS operations. In this study, we develop a science-based methodology for quantifying risk profiles at geologic CO 2 sequestration sites as part of US DOE's National Risk Assessment Partnership (NRAP). We apply NRAP tools to a field scale project in a fractured saline aquifer located at Kevin Dome, Montana, which is part of DOE's Big Sky Carbon Sequestration Partnership project. Risks associated with GCS injection and monitoring are difficult to quantify due to a dearth of data and uncertainties. One solution is running a large number of numerical simulations of the primary CO 2 injection reservoir, shallow reservoirs/aquifers, faults, and wells to address leakage risks and uncertainties. However, a full-physics simulation is not computationally feasible because the model is too large and requires fine spatial and temporal discretization to accurately reproduce complex multiphase flow processes. We employ the NRAP Integrated Assessment Model (NRAP-IAM), a hybrid system model developed by the US-DOE for use in performance and quantitative risk assessment of CO 2 sequestration. The IAM model requires reduced order models (ROMs) developed from numerical reservoir simulations of a primary CO 2 injection reservoir. The ROMs are linked with discrete components of the NRAP-IAM including shallow reservoirs/aquifers and the atmosphere through potential leakage pathways. A powerful stochastic framework allows NRAP-IAM to be used to explore complex interactions among a large number of uncertain variables and to help evaluate the likely performance of potential sequestration sites. Using the NRAP-IAM, we find that the potential amount of CO 2 leakage is most sensitive to values of permeability, end-point CO 2 relative permeability, hysteresis of CO 2 relative permeability, capillary pressure, and permeability of confining rocks. In addition to demonstrating the application of the NRAP risk assessment tools, this work shows that GCS in the Kevin Dome has a higher probability of encountering injectivity limitations during injection of CO 2 into the Middle Duperow formation than previous studies have calculated. Finally, we estimate very low risk of CO 2 leakage to the atmosphere unless the quality of the legacy well completions is extremely poor. [ABSTRACT FROM AUTHOR]

Abstract: Injection of carbon dioxide captured from flue gas into coal beds is regarded as one of the value-added options of CO2 sequestration as the cost of injection can be partially or fully offset by the revenue generated through release of additional methane. The Powder River Basin is one of the major coalbed methane producing areas in the world. The paper presents findings of a preliminary reservoir simulation study on the feasibility of CO2 sequestration over a nine-section area (4.8km×4.8km) of the Powder River Basin into the thick Wyodak coal seam, one of the two major coal seams in the highly productive Fort Union formation. The reservoir model was built on the basis of information available in the public domain. Gamma ray logs from 60 wells were utilized for developing a 3-D geological model of the coal seam and overlying rocks in the area by employing geostatistical techniques. Considerable variability in gas and water production was observed in the 65 wells. This variability was utilized for capturing the reservoir heterogeneity by Gaussian geostatistical simulation, which produced realizations of fracture porosity and permeability distribution throughout the reservoir. Results of fluid flow simulation indicated that it would not be feasible to place more than one injector per 1.6km×1.6km (1mile×1mile) section of the area due to geomechanical constraint. As a preliminary estimate, it may be feasible to inject 0.658 million tons of CO2 through such injector over a period of 20 years. 12% more CO2 can be injected over the same period by using a horizontal well but the loss of injectivity may be substantial due to reduction of permeability by coal matrix swelling. The loss of permeability can partially be overcome by intermittent injection for 6 months followed by a similar soak period. Placing one vertical injector each into all the nine sections would result in a scaled-up volume of 5.5 million tons of CO2 injection. However, the nature of overlying rock could play a vital role in retention of injected CO2 and up to 20% of the gas may migrate up by buoyancy. [Copyright &y& Elsevier]

• An integrated analysis of data in a fractured saline aquifer at the Kevin Dome, Montana. • Well test models indicate a positive total skin factor supported by reservoir simulation. • Possible explanation to skin factor and permeability: partial penetration and formation damage. • Likely cause to formation damage: anhydrite fines migration and/or calcite precipitation. • Preventative and remediation measures to tackle these scenarios for future GCS projects. In this study, we investigate formation damage due to acidization and water injection tests into the naturally fractured carbonate Middle Duperow Formation at Kevin Dome, Montana, potentially diminishing the chance of a future successful Geological Carbon Sequestration (GCS) project. Multiple well-test analytical models, correlated with core description and lithology data, are used to determine flow behavior and communication between the water injection interval and surrounding formations. An improved three-dimensional (3D) geologic model with dual-continuum matrix and fracture properties is constructed based on most recent seismic, core, and water sample measurements. Brine injection is simulated to verify the interpretation from the analytical models, followed by CO 2 injection simulation. Geochemical calculations are performed to understand the in-situ processes that led to formation damage. Our findings suggest: (1) there are two possible scenarios that could lead to a positive total effective skin factor and permeability decline: partial penetration and formation damage; (2) analytical models indicate a positive total skin factor, contradicting results of a previous study suggesting that the well was mildly stimulated; (3) numerical simulation supports the formation damage hypothesis by matching the pressure buildup observed during the latter two brine injection tests; (4) several mechanical and chemical processes may have occurred during injection to clog the matrix/fracture system: anhydrite fines migration and/or calcite precipitation. We then make preventative suggestions for future GCS projects into carbonate reservoirs and remediation recommendations for GCS operation at the Kevin Dome. [ABSTRACT FROM AUTHOR]