Berawala, Dhruvit Satishchandra (Department of Energy and Petroleum Technology, University of Stavanger, Norway and The National IOR Centre of Norway) | Østebø Andersen, Pål (Department of Energy Resources, University of Stavanger, Norway and The National IOR Centre of Norway)
Only 3-10 % of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for CO2 than methane, CH4, which opens possibilities for carbon storage and new production strategies.
This paper presents a new multicomponent adsorption isotherm which is coupled with a flow model for evaluation of injection-production scenarios. The isotherm is based on the assumption that different gas species compete for adsorbing on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles this finite surface area is filled with species taking different amount of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas in place reserves, recovery factors and enhanced gas recovery potential based on contributions from free gas and adsorbed gas components. The isotherm is further coupled with a dynamic flow model with application to CO2-CH4 substitution for CO2-ESGR. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection-production setting representative of lab and field implementation and compare with regular pressure depletion.
The production scenario we consider is a 1D shale core or matrix system intitally saturated with free and adsorbed CH4 gas with only left side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to increase in pressure where CO2 gets preferentially adsorbed over CH4. The injected CO2 displaces, but also mixes with the in situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel further into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism since the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is a result of CO2 being found to take ~24 times less space per mol than CH4.
Many experimental works have investigated smart water and low salinity water flooding and observed significant incremental oil recovery following changes in the injected brine composition. The commonway approach to model such EOR mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness may retain much oil at the outlet of the flooded core due to capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in high permeable cores at typical lab rates. Injecting a brine that changes the wetting state to less oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation.
This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing core flooding accounting for wettability changes due to changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability alteration component coupled to shifting of relative permeability and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically due to changing one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including 1) changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and 2) the magnitude of capillary end effects can be reduced due to increased water-wetness or due to reduction in water relative permeability giving a greater viscous drag on the oil.