A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

A temperature-profile method for estimating flow in geologic heat pipes

Above-boiling temperature conditions, as encountered, for example, in geothermal reservoirs and in geologic repositories for the storage of heat-producing radioactive wastes, may induce strong liquid and gas flow processes in porous subsurface environments. The magnitude of these flow processes is extremely hard to measure in the field. We therefore propose a simple temperature-profile method that uses high-resolution temperature data for deriving such information. The energy that is transmitted with the vapor and water flow creates a nearly isothermal zone maintained at about the boiling temperature, referred to as a heat pipe. Characteristic features of measured temperature profiles, such as the differences in the gradients inside and outside of the heat-pipe regions, are used to derive the approximate magnitude of the liquid and gas fluxes in the subsurface.     

Large-scale impact of CO2 storage in deep saline aquifers: A sensitivity study on pressure response in stratified systems

Large volumes of CO₂ captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO₂ plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO₂ and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO₂ injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO₂-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO₂ plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO₂ storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10^?18 m²). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.     

Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

Industrial-scale injection of CO₂ into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO₂ storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO₂ storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO₂ per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO₂–brine flow processes and the large-scale groundwater flow patterns in response to CO₂ storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO₂ storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO₂, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO₂ sequestration projects.