Carbon capture and storage (CCS) is the only viable technology to mitigate carbon emissions while allowing continued large-scale use of fossil fuels. The storage part of CCS involves injection of carbon dioxide, captured from large stationary sources, into deep geological formations. Deep saline aquifers have the largest identified storage potential, with estimated storage capacity sufficient to store emissions from large stationary sources for at least a century. This makes CCS a potentially important bridging technology in the transition to carbon-free energy sources. Injection of CO 2 into deep saline aquifers leads to a multicomponent, multiphase flow system, in which geomechanics, geochemistry, and nonisothermal effects may be important. While the general system can be highly complex and involve many coupled, nonlinear partial differential equations, the underlying physics can sometimes lead to important simplifications. For example, the large density difference between injected CO 2 and brine may lead to relatively fast buoyant segregation, making an assumption of vertical equilibrium reasonable. Such simplifying assumptions lead to a range of simplified governing equations whose solutions have provided significant practical insights into system behavior, including improved estimates of storage capacity, easy-to-compute estimates of CO 2 spatial migration and pressure response, and quantitative estimates of leakage risk. When these modeling studies are coupled with observations from well-characterized injection operations, understanding of the overall system behavior is enhanced significantly. This improved understanding shows that, while economic and policy challenges remain, CO 2 storage in deep saline aquifers appears to be a viable technology and can contribute substantially to climate change solutions.

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A series of Mb 3.8-5.5 induced seismic events in the midcontinent region, United States, resulted from injection of fluid either into a basal sedimentary reservoir with no underlying confining unit or directly into the underlying crystalline basement complex. The earthquakes probably occurred along faults that were likely critically stressed within the crystalline basement. These faults were located at a considerable distance (up to 10 km) from the injection wells and head increases at the hypocenters were likely relatively small (∼70-150 m). We present a suite of simulations that use a simple hydrogeologic-geomechanical model to assess what hydrogeologic conditions promote or deter induced seismic events within the crystalline basement across the midcontinent. The presence of a confining unit beneath the injection reservoir horizon had the single largest effect in preventing induced seismicity within the underlying crystalline basement. For a crystalline basement having a permeability of 2 × 10(-17)  m(2) and specific storage coefficient of 10(-7) /m, injection at a rate of 5455 m(3) /d into the basal aquifer with no underlying basal seal over 10 years resulted in probable brittle failure to depths of about 0.6 km below the injection reservoir. Including a permeable (kz  = 10(-13)  m(2) ) Precambrian normal fault, located 20 m from the injection well, increased the depth of the failure region below the reservoir to 3 km. For a large permeability contrast between a Precambrian thrust fault (10(-12)  m(2) ) and the surrounding crystalline basement (10(-18)  m(2) ), the failure region can extend laterally 10 km away from the injection well.

Conventional vertically integrated models for CO 2 storage usually adopt a vertical equilibrium (VE) assumption, which states that due to strong buoyancy, CO 2 and brine segregate quickly, so that the fluids can be assumed to have essentially hydrostatic pressure distributions in the vertical direction. However, the VE assumption is inappropriate when the time scale of fluid segregation is not small relative to the simulation time. By casting the vertically integrated equations into a multiscale framework, a new vertically integrated model can be developed that relaxes the VE assumption, thereby allowing vertical dynamics to be modeled explicitly. The model maintains much of the computational efficiency of vertical integration while allowing a much wider range of problems to be modeled. Numerical tests of the new model, using injection scenarios with typical parameter sets, show excellent behavior of the new approach for homogeneous geologic formations.

Industrial-scale storage of CO 2 in saline sedimentary basins will cause zones of elevated pressure, larger than the CO 2 plume itself. If permeable conduits (e.g., leaking wells) exist between the injection reservoir and overlying shallow aquifers, brine could be pushed upwards along these conduits and mix with groundwater resources. This paper discusses the potential for such brine leakage to occur in temperature-and salinitystratified systems. Using static mass-balance calculations as well as dynamic well flow simulations, we evaluate the minimum reservoir pressure that would generate continuous migration of brine up a leaking wellbore into a freshwater aquifer. Since the brine invading the well is denser than the initial fluid in the wellbore, continuous flow only occurs if the pressure perturbation in the reservoir is large enough to overcome the increased fluid column weight after full invasion of brine into the well. If the threshold pressure is exceeded, brine flow rates are dependent on various hydraulic (and other) properties, in particular the effective permeability of the wellbore and the magnitude of pressure increase. If brine flow occurs outside of the well casing, e.g., in a permeable fracture zone between the well cement and the formation, the fluid/solute transfer between the migrating fluid and the surrounding rock units can strongly retard brine flow. At the same time, the threshold pressure for continuous flow to occur decreases compared to a case with no fluid/solute transfer.