Hydrodynamics in subsurface CO 2 storage: Tilted contacts and increased storage security

Abstract

Hydrodynamic aquifers with horizontal variations in overpressure and brine flow have been reported from sedimentary basins worldwide. In a hydrodynamic aquifer pore-waters flow in the direction of overpressure reduction, whereas trapped hydrocarbons remain static. The main effect of this pressure disequilibrium in the aquifer is a tilt of the free water levels (FWL) in the direction of lower overpressure. Although the impact of hydrodynamics on the petroleum system is established in the oil industry and provides important information for exploration and field development, the interaction of CO2 storage and hydrodynamic flow has hardly been investigated. Supercritical CO2 has a density comparable with oil densities in known hydrodynamic systems in the North Sea. Hence, a tilted CO2-water FWL is expected and has to be taken into account during the planning of CO2 storage. Hydrodynamic spill points will replace structural spill points as a parameter in CO2 storage capacity calculations. Storage security is dependent on CO2 dissolution rates, among other factors. The more effectively CO2 dissolves into brine the more CO2 will be permanently stored in the subsurface. Numerical simulations show that CO2 storage in hydrodynamic aquifers enhances the dissolution of CO2 compared with a static regime. When CO2 dissolves into brine, the brine density increases and the CO2-saturated brine sinks to the bottom of the reservoir and is replaced by under-saturated brine. In a hydrodynamic system the brine saturated with CO2 will be removed more effectively from the CO2brine interface. Hence, CO2 comes in contact with more under-saturated brine and dissolves at a greater rate. The presence of hydrodynamic flow in a reservoir requires a high degree of understanding but research on oil reservoirs has proven that it is an uncertainty that can be adequately characterized. For long term CO2 storage operations hydrodynamic flow can even be an opportunity for more secure CO2 storage.

Estimating geological CO2 storage security to deliver on climate mitigation

“…Our leakage model is based on assessments of volumes of subsurface fluids leaked from: active hydrocarbon industry wells (analogous to CO 2 injection–2a); abandoned wells (i.e., legacy hydrocarbon industry wells–2b); and natural examples of gases leaking from geological features (e.g., faults or poor caprock integrity–2c). For a given storage reservoir, the degree of leakage along a fluid migration pathway will depend on a number of factors, including: the areal density and depth of the migration pathways, proximity of the migration pathway to the injection well, plume geometry, reservoir pressure, free-phase CO 2 column height, the relative permeability of all geological formations and migration pathways, capillary entry pressure, fluid pore pressure, hydrodynamic flow regime, and temperature 30 – 35 . Precise modelling of potential leakage along migration pathways at a given storage site requires detailed constraints on all of these parameters, injection volume and pressure, and appropriate model-grid spacing and equations of state 30 – 32 .…”

Cyclic CO2 – H2O injection and residual trapping: Implications for CO2 injection efficiency and storage security

“…An alternative model for CO2 saturation has been devised in which the residual gas saturation for imbibition is increased for each cycle. The reservoir engineering software Eclipse 300 (Schlumberger) (Heinemann et al, 2016;Pickup et al, 2012), was used in this study with the CO2STORE option based on a modified Peng-Robinson equation of state (Peng and Robinson, 1976) that allows for the mutual solubility of CO2 and water.…”

Estimating geological CO2 storage security to deliver on climate mitigation

“…Our leakage model is based on assessments of volumes of subsurface fluids leaked from: active hydrocarbon industry wells (analogous to CO 2 injection-2a); abandoned wells (i.e., legacy hydrocarbon industry wells-2b); and natural examples of gases leaking from geological features (e.g., faults or poor caprock integrity-2c). For a given storage reservoir, the degree of leakage along a fluid migration pathway will depend on a number of factors, including: the areal density and depth of the migration pathways, proximity of the migration pathway to the injection well, plume geometry, reservoir pressure, free-phase CO 2 column height, the relative permeability of all geological formations and migration pathways, capillary entry pressure, fluid pore pressure, hydrodynamic flow regime, and temperature [30][31][32][33][34][35] . Precise modelling of potential leakage along migration pathways at a given storage site requires detailed constraints on all of these parameters, injection volume and pressure, and appropriate model-grid spacing and equations of state [30][31][32] .…”