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• The viability of carbon capture and storage depends in part on storage security in the subsurface. • Recently, new field data have become available on the permeability of abandoned wellbores. • We present simulations of CO 2 leakage as a function of spatial density and permeability of leaky wells. • We assess the results based on ranges of leaky well permeability and spatial density that are realistic. • Our results indicate that leakage through abandoned wells unlikely to be a major limitation for CCS. The viability of carbon capture and geological storage (CCS) projects depends in part on the risk that injected CO 2 or displaced pore fluid will leak out of the target formation into surrounding formations or to the surface. Abandoned oil and gas wells, of which millions exist both throughout the United States and globally, form a potential conduit for this leakage. Recently, specific field measurements have been made to quantify the range of effective permeabilities that can be expected in abandoned wells, enabling us to, for the first time, combine field-scale numerical simulations of CO 2 sequestration in deep saline aquifers with real data on effective permeabilities of leaky wells. Using a previously developed semi-analytical reservoir simulator that can accommodate an arbitrary sequence of alternating aquifers and aquicludes, as well as an arbitrary number of leaky wells, we investigated how the amount of CO 2 that leaks out of the target formation depends on the spatial density of nearby abandoned wells and their effective permeability. Furthermore, we assess the influence that variations in pressure and temperature found between geological targets have on this dependency. We find that the observed differences in leakage between geological targets are controlled almost exclusively by differences in density of CO 2 at the local subsurface conditions, causing the CO 2 plume to contact a different number of wells when injecting at the same constant mass rate. We quantitatively assess the results obtained from our numerical experiments by combining them with the permeability data that have recently become available, typical spatial densities of abandoned wells, and performance requirements put forward in the literature. Our results indicate that leakage of CO 2 through abandoned wells is unlikely to be a major limitation in storage security of CCS projects. [ABSTRACT FROM AUTHOR]

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 m2 and specific storage coefficient of 10−7/m, injection at a rate of 5455 m3/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 m2) 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 m2) and the surrounding crystalline basement (10−18 m2), the failure region can extend laterally 10 km away from the injection well. [ABSTRACT FROM AUTHOR]

The Mount Simon and Lower Knox Group Formations within the Illinois Basin, USA, are being considered as targets for carbon dioxide (CO $$_2$$ ) storage. Two main concerns related to the subsurface storage process are potential leakage of CO $$_2$$ from the storage formation to the atmosphere and possible migration of CO $$_2$$ or displaced brine into underground sources of drinking water. In this study we use a numerical model to represent the migration of both CO $$_2$$ and brine in the Mount Simon Sandstone and two overlying aquifers, the shallowest of which is considered a potential source of drinking water. A vertically-integrated approach is used to model the fluid flow, leading to a stack of two-dimensional subdomains which are connected by leakage through the aquitards which separate the aquifers. Each formation is discretized into 12,103 grid cells, each $$5 \times 5\,\mathrm{{km}}$$ , and permeability and porosity vary spatially. Two vertical refinements are used for the Mount Simon Sandstone: the first represents the Mount Simon as a single layer, while the second subdivides the formation into subunits within the formation that have varying petrophysical properties. The locations and injection rates of the hypothetical injection operations are based on existing sources of CO $$_2$$ associated with power generation, ethanol production, and oil and gas refineries. A total of 250.5 million metric tons are injected at 118 sites. The injection operations are assumed to continue for 50 years. Results indicate the maximum radial extent of the CO $$_2$$ plume increased from 40 to 50 km between the single layer and multi-layer representations of the Mount Simon. Maximum average pore pressures reached 8.6 MPa and the pressure envelop extended as much as 100 km from the injection wells with significant well-well pressure interference patterns. The maximum well head pressure exceeded the fracture pressure in some cases suggesting more wells may be needed at some of the lower permeability injection sites. Brine leakage into overlying shallower units was not significant. [ABSTRACT FROM AUTHOR]

Large-scale carbon capture, utilization, and storage (CCUS) requires development of critical infrastructure to connect capture locations to geological storage sites. Here, we investigate what government policies would be required to make the development of CO 2 pipelines and large-scale CCUS in the power sector economically viable. We focus on the transition from conventional coal to non-CO 2 -emitting natural gas-fired Allam-cycle power with CCUS and study a system in which 156 Allam-cycle power generators representing 100 GW of capacity send their captured CO 2 emissions to three geological storage locations in the central United States through 7500 miles of new pipeline. Enabling policies for this system include low-interest government loans of approximately $20 billion for pipeline construction and an extended 20-year Section 45Q tax credit, or similar longer-term carbon price incentive. Additional policy support will be needed to enable initial construction of pipelines and early-mover power generators, such as cost-sharing, governments assuming future demand risk, or increased subsidies to early movers. The proposed system will provide reliable, dispatchable, flexible zero-emission power generation, complementing the intermittent generation by renewables in a decarbonized U.S. power sector. The proposed pipeline network could also connect into future regional infrastructure networks and facilitate large-scale carbon management.