• Energy Research

AbstractFor industrial-scale CO2 injection in saline formations, pressure increase can be a limiting factor in storage capacity. To address this concern, we introduce Active CO2 Reservoir Management (ACRM), which combines brine extraction and residual-brine reinjection with CO2 injection, contrasting it with the conventional approach, which we call Passive CO2 Reservoir Management. ACRM reduces pressure buildup and CO2 and brine migration, which increases storage capacity. Also, “push-pull” manipulation of the CO2 plume can counteract buoyancy, exposing less of the caprock seal to CO2 and more of the storage formation to CO2, with a greater fraction of the formation utilized for trapping mechanisms. If the net extracted volume of brine is equal to the injected CO2 volume, pressure buildup is minimized, greatly reducing the Area of Review, and the risk of seal degradation, fault activation, and induced seismicity. Moreover, CO2 and brine migration will be unaffected by neighboring CO2 operations, which allows planning, assessing, and conducting of each operation to be carried out independently. In addition, ACRM creates a new product, as extracted brine is available as a feedstock for desalination technologies, such as Reverse Osmosis. These benefits can offset brine extraction and treatment costs, streamline permitting, and help gain public acceptance.

AbstractFor industrial-scale CO2 injection in saline formations, pressure increase can be a limiting factor in storage capacity. To address this concern, we introduce Active CO2 Reservoir Management (ACRM), which combines brine extraction and residual-brine reinjection with CO2 injection, contrasting it with the conventional approach, which we call Passive CO2 Reservoir Management. ACRM reduces pressure buildup and CO2 and brine migration, which increases storage capacity. Also, “push-pull” manipulation of the CO2 plume can counteract buoyancy, exposing less of the caprock seal to CO2 and more of the storage formation to CO2, with a greater fraction of the formation utilized for trapping mechanisms. If the net extracted volume of brine is equal to the injected CO2 volume, pressure buildup is minimized, greatly reducing the Area of Review, and the risk of seal degradation, fault activation, and induced seismicity. Moreover, CO2 and brine migration will be unaffected by neighboring CO2 operations, which allows planning, assessing, and conducting of each operation to be carried out independently. In addition, ACRM creates a new product, as extracted brine is available as a feedstock for desalination technologies, such as Reverse Osmosis. These benefits can offset brine extraction and treatment costs, streamline permitting, and help gain public acceptance.

We present an approach that uses the huge fluid and thermal storage capacity of the subsurface, together with geologic CO2 storage, to harvest, store, and dispatch energy from subsurface (geothermal) and surface (solar, nuclear, fossil) thermal resources, as well as energy from electrical grids. Captured CO2 is injected into saline aquifers to store pressure, generate artesian flow of brine, and provide an additional working fluid for efficient heat extraction and power conversion. Concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO2, and thermal energy. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. Stored CO2 functions as a cushion gas to provide enormous pressure-storage capacity and displaces large quantities of brine, which can be desalinated and/or treated for a variety of beneficial uses. Geothermal power and energy-storage applications may generate enough revenues to justify CO2 capture costs. 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12 Energy Procedia, 63 ISSN:1876-6102

We present an approach that uses the huge fluid and thermal storage capacity of the subsurface, together with geologic CO2 storage, to harvest, store, and dispatch energy from subsurface (geothermal) and surface (solar, nuclear, fossil) thermal resources, as well as energy from electrical grids. Captured CO2 is injected into saline aquifers to store pressure, generate artesian flow of brine, and provide an additional working fluid for efficient heat extraction and power conversion. Concentric rings of injection and production wells are used to create a hydraulic divide to store pressure, CO2, and thermal energy. Such storage can take excess power from the grid and excess/waste thermal energy, and dispatch that energy when it is demanded, enabling increased penetration of variable renewables. Stored CO2 functions as a cushion gas to provide enormous pressure-storage capacity and displaces large quantities of brine, which can be desalinated and/or treated for a variety of beneficial uses. Geothermal power and energy-storage applications may generate enough revenues to justify CO2 capture costs. 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12 Energy Procedia, 63 ISSN:1876-6102

Abstract We present an approach for managing geologic CO2 storage using wells that serve three sequential purposes (1) characterization and monitoring, (2) brine production, and (3) CO2 injection. Two reservoirs are deployed in tandem: (1) a CO2-storage reservoir and (2) a brine-storage reservoir. This approach provides data that can be analyzed prior to CO2 injection, enabling proactive reservoir management, which reduces cost and risk. We analyze a range of brine-disposition options, including 100% reinjection in a nearby brine-storage reservoir and cases where a portion of the produced brine is used to generate water, with the residual brine reinjected in the nearby reservoir. We also consider the option of time-shifting the parasitic load of brine production and injection, so that those operations can utilize excess energy from electric grids during periods of over-generation.

Abstract We present an approach for managing geologic CO2 storage using wells that serve three sequential purposes (1) characterization and monitoring, (2) brine production, and (3) CO2 injection. Two reservoirs are deployed in tandem: (1) a CO2-storage reservoir and (2) a brine-storage reservoir. This approach provides data that can be analyzed prior to CO2 injection, enabling proactive reservoir management, which reduces cost and risk. We analyze a range of brine-disposition options, including 100% reinjection in a nearby brine-storage reservoir and cases where a portion of the produced brine is used to generate water, with the residual brine reinjected in the nearby reservoir. We also consider the option of time-shifting the parasitic load of brine production and injection, so that those operations can utilize excess energy from electric grids during periods of over-generation.

AbstractTwo 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.