Using CO2 in enhanced oil recovery (CO2-EOR) is a promising technology for emissions management because CO2-EOR can dramatically reduce sequestration costs in the absence of emissions policies that include incentives for carbon capture and storage. This study develops a multiscale statistical framework to perform CO2 accounting and risk analysis in an EOR environment at the Farnsworth Unit (FWU), Texas. A set of geostatistical-based Monte Carlo simulations of CO2-oil/gas-water flow and transport in the Morrow formation are conducted for global sensitivity and statistical analysis of the major risk metrics: CO2/water injection/production rates, cumulative net CO2 storage, cumulative oil/gas productions, and CO2 breakthrough time. The median and confidence intervals are estimated for quantifying uncertainty ranges of the risk metrics. A response-surface-based economic model has been derived to calculate the CO2-EOR profitability for the FWU site with a current oil price, which suggests that approximately 31% of the 1000 realizations can be profitable. If government carbon-tax credits are available, or the oil price goes up or CO2 capture and operating expenses reduce, more realizations would be profitable. The results from this study provide valuable insights for understanding CO2 storage potential and the corresponding environmental and economic risks of commercial-scale CO2-sequestration in depleted reservoirs.

a b s t r a c tMany geologic carbon storage site options include not only excellent storage reservoirs bounded by effective seal layers, but also Underground Sources of Drinking Water (USDWs). An effective risk assessment and mitigation plan provides maximum protection for USDWs, to respect not only current policy but also to accommodate likely future USDW-specific regulatory protections. The goal of this study is to quantify possible risks to USDWs, specifically risks associated with chemical impacts on USDWs. Reactive transport models involve tremendous computational expense. Therefore, a secondary purpose of this study is to develop, calibrate and test reduced order models specifically for assessing risks of USDW chemical impacts by CO 2 leakage from a storage reservoir. In order to achieve these goals, a geochemical model was developed to interpret changes in water chemistry following CO 2 intrusion. A response surface methodology (RSM) based on these geochemical simulations was used to quantify associated risks. The case study example for this analysis is the Ogallala aquifer overlying the Farnsworth unit (FWU), an active commercial-scale CO 2 -enhanced oil recovery field. Specific objectives of this study include: (1) to understand how CO 2 leakage is likely to influence geochemical processes in aquifer sediments; (2) to quantify potential risks to the Ogallala groundwater aquifer due to CO 2 leakage from the FWU oil reservoir; and (3) to identify water chemistry factors for early detection criteria.Results indicate that the leakage rate would most likely range between 10 −14 -10 −10 kg/(m 2 year) for typical and likely leakage pathway permeability ranges. Within this range of CO 2 leakage rate, groundwater quality is not likely to be significantly impacted. The worst-case scenario yields trace metal concentrations approximately twice as much as the initial value, but these predicted concentrations are still less than one-fifth of regulation-stipulated maximum contamination levels and do not exceed the no-impact thresholds. Finally, the results of this analysis suggest that pH may be an effective geochemical indicator of CO 2 leakage.

No abstract

Groundwater chemistry and rock properties can change dramatically following CO 2 injection in a geologic sequestration system. A favored target for subsurface sequestration is clastic reservoirs, due to their limited tendency to impact water quality or porosity and permeability due to dissolution or precipitation compared to carbonate reservoirs. However, most clastic reservoirs will exhibit geochemical changes, especially during the injection phase and over the long term. And, in most oil reservoirs targeted for enhanced recovery and concomitant CO 2 storage, water-alternating-gas, or so-called "WAG" injection schemes are preferred to maximize CO 2 mobility and minimize viscous fingering of CO 2 . Under WAG schemes, reactive transport processes and resulting water quality changes and rock property changes may differ when compared to continuous CO 2 injection (CCI) schemes.The purpose of this paper is to analyze and quantify the extent of geochemical changes to both water chemistry and rock properties, specifically for the "low hanging fruit" of CO 2 storage targets: a sandstone formation using a WAG injection scheme.Specifically, the objectives of this study are: (1) to evaluate the evolution of formation water chemistry and mineral alteration induced by WAG injection in a typical southwestern U.S. sandstone reservoir; (2) to quantify CO 2 trapping mechanisms and associated porosity and permeability evolution over the long term following injection; (3) to investigate whether different injection schemes (WAG vs. CCI designs) may affect the evolution of water chemistry and mineral alteration during the injection phase. Because it is not just a candidate formation, but rather is already undergoing CO 2 injection for enhanced oil recovery (EOR) and sequestration, the Morrow Sandstone Formation in the