The economics of an integrated CO2 capture and sequestration system: Texas Gulf Coast case study

Abstract

Abstract Using a power generation dispatch model of the Electric Reliability Council of Texas (ERCOT) to estimate CO 2 capture from retrofitting an existing coal power plant, this paper estimates the system cost and revenue associated with handling CO 2 input and output mismatch in an integrated source-sink pipeline by installing more injection wells into a saline reservoir to handle peak CO 2 capture rates. The fluctuations in CO 2 capture (e.g. supply) are assumed to come from an existing coal-fired power plant in Texas operating according to a merit-order dispatch model with an imposed CO 2 price. We analyze a 20-year cash flow with CO 2 demand for enhanced oil recovery (EOR) based upon a nominal purchase schedule over an 11-year lifespan of a high-quality candidate oil field, Conroe, along the Gulf Coast of Texas. With an assumed structured and inflexible use of CO 2 for EOR, the deeper saline reservoir can sequester captured CO 2 that is not injected for EOR. By performing a cash flow analysis with and without the EOR field and saline reservoirs included, the economic costs and benefits of coupling EOR and saline storage to a single coal generator are determined for a specific Texas case study. At low CO 2 prices, the EOR reservoir contributes more value than the saline reservoir, but the opposite is true at high CO 2 prices. This answer can be partly explained because as CO 2 price increases, the analysis assumes constant demand of electricity and endogenously increases electricity prices but uses an exogenous constant oil price. The method can be generalized to include additional coal-based plants as well as EOR and saline reservoirs in Texas to envision an entire carbon capture and sequestration network in a region with high EOR potential.