Pre-injection brine production in CO2 storage reservoirs: An approach to augment the development, operation, and performance of CCS while generating water

Abstract

Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources—where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water-constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir.