Lifetime of carbon capture and storage as a climate-change mitigation technology

Abstract

In carbon capture and storage (CCS), CO 2 is captured at power plants and then injected underground into reservoirs like deep saline aquifers for long-term storage. While CCS may be critical for the continued use of fossil fuels in a carbon-constrained world, the deployment of CCS has been hindered by uncertainty in geologic storage capacities and sustainable injection rates, which has contributed to the absence of concerted government policy. Here, we clarify the potential of CCS to mitigate emissions in the United States by developing a storage-capacity supply curve that, unlike current large-scale capacity estimates, is derived from the fluid mechanics of CO 2 injection and trapping and incorporates injection-rate constraints. We show that storage supply is a dynamic quantity that grows with the duration of CCS, and we interpret the lifetime of CCS as the time for which the storage supply curve exceeds the storage demand curve from CO 2 production. We show that in the United States, if CO 2 production from power generation continues to rise at recent rates, then CCS can store enough CO 2 to stabilize emissions at current levels for at least 100 y. This result suggests that the large-scale implementation of CCS is a geologically viable climate-change mitigation option in the United States over the next century.carbon sequestration | pressure dissipation | residual trapping | solubility trapping C arbon dioxide is a well-documented greenhouse gas, and a growing body of evidence indicates that anthropogenic CO 2 emissions are a major contributor to climate change (1). One promising technology to mitigate CO 2 emissions is carbon capture and storage (CCS) (2-4). In the context of this study, CCS involves capturing CO 2 from the flue gas of power plants, compressing it into a supercritical fluid, and then injecting it into deep saline aquifers for long-term storage (4, 5). Compared with other mitigation technologies such as renewable energy, CCS is important because it may enable the continued use of fossil fuels, which currently supply >80% of the primary power for the planet (6, 7). We focus on CO 2 produced by power plants because electric power generation currently accounts for >40% of worldwide CO 2 emissions (8) and because power plants are large, stationary point sources of emissions where CO 2 capture technology will likely be deployed first (4). We further restrict our analysis to coal-and gas-fired power plants because they emit more CO 2 than any other type of plant: Since 2000, they have emitted ∼97% by mass of the total CO 2 produced by electricitygenerating power plants in the United States (9). We focus on storing this CO 2 in deep saline aquifers because they are geographically widespread and their storage capacity is potentially very large (4, 5).We define the storage capacity of a saline aquifer to be the maximum amount of CO 2 that could be injected and securely stored under geologic constraints, such as the aquifer's size and the integrity of its caprock. Regulatory, legal, and economic factors...

Pattern formation and coarsening dynamics in three-dimensional convective mixing in porous media

“…It has been proposed as a promising technology for reducing atmospheric CO 2 emissions and mitigating climate change [2][3][4]. While CO 2 is less dense than water for all depths in onshore geological reservoirs, when CO 2 dissolves into water, the density of water increases.…”

Risk, Liability, and Economic Issues with Long-Term CO2 Storage—A Review

“…The layer of impermeable rock that forms the primary seal against the CO 2 escaping into the upper geological strata or to the surface is the caprock. If there are no lateral seals in addition to this primary seal, the CO 2 can still migrate more or less horizontally along the underside of the caprock until it is trapped or finds a pathway to escape the storage reservoir (Szulczewski et al 2012;Birkholzer et al 2015). Geologic uncertainty concerning the pathways that injected CO 2 and pressurized or displaced formation fluids will take is a major contributor to uncertainty in estimates of potential risk (Oldenburg et al 2009;Pawar et al 2015).…”

“…Without making any regulatory assumptions, Szulczewski et al (2012) estimated that the pressure-limited CO 2 storage capacity of the Mount Simon Sandstone (a prospective deep saline formation for CO 2 storage) could be about 15 Gt, which is about 10% of the DOE-NETLÕs upper bound on their 2010 estimate of the volumetric storage capacity and about 16% of the mean USGS estimate of the TASR for the same formation (NETL 2010(NETL , 2012USGS 2013). Birkholzer and Zhou (2009) estimated the pressurelimited capacity for the Mount Simon Sandstone to be as low as 5 Gt of CO 2 , under assumptions about the regulatory environment that these authors considered to be realistic.…”

“…If the net costs of fluid extraction and processing are less than that for reducing or suspending injection, then the storage operator can continue injecting CO 2 even after risks have become apparent. However, the costs of GCS will be significantly higher if the operator needs to extract, process, and dispose of formation fluids, and filling even a fourth of the TASR with CO 2 may not be economically feasible Szulczewski et al 2012;IEAGHG 2014). Harto and Veil (2011) estimated that the average net costs of water management for CO 2 storage could be about $1.50 per barrel of produced waters (at current prices between 1992 and 2006), and that this would correlate to costs of between $12/t and $14/t of stored CO 2 .…”

Two-phase flow effects on the CO2injection pressure evolution and implications for the caprock geomechanical stability

“…CO 2 forms a plume around the injection well, displacing the formation brine laterally [4,5]. CO 2 is the non-wetting phase and is partially miscible in brine [6].…”