Summary The purpose of this paper is to investigate the main controlling factors during a continuum-flow regime in shale-gas production in the context where well-induced fractures, extending from the well perforations, improve reservoir conductivity and performance. A mathematical 1D+1D model is presented that involves a high-permeability fracture extending from a well perforation through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nanopores. The pressure gradient toward the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop. The production of shale gas and mass distributions indicate the efficiency of species transfer between fracture and matrix. We show that the behavior can be scaled and described according to the magnitude of two characteristic dimensionless numbers: the ratio of diffusion time scales in shale and fracture, α, and the pore-volume (PV) ratio between the shale and fracture domains, β. Fracture/matrix properties are varied systematically to understand the role of fracture/matrix interaction during production. Further, the role of fracture geometry (varying width) is investigated. Input parameters from experimental and field data in the literature are applied. The product αβ expresses how much time it takes to diffuse the gas in place through the fracture to the well compared with the time it takes to diffuse that gas from the matrix to the fracture. For αβ≪1, the residence time in the fracture is of negligible importance, and fracture properties such as shape, width, and permeability can be ignored. However, if αβ≈1, the residence time in the fracture becomes important, and variations in all those properties have significant effects on the solution. The model allows for intuitive interpretation of the complex shale-gas-production system. Furthermore, the current model creates a base that can easily incorporate nonlinear-flow mechanisms and geomechanical effects that are not readily found in standard commercial software, and further be extended to field-scale application.
Summary Only 3 to 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 carbon dioxide (CO2) than methane (CH4), which opens possibilities for carbon storage and new production strategies. This paper presents a new multicomponent adsorption isotherm that is coupled with a flow model for the evaluation of injection/production scenarios. The isotherm is dependent on the assumption that different gas species compete to adsorb 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 amounts 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 (RFs), and enhanced gas-recovery (EGR) potential according to the 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, assuming only a gas phase exists in the system. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection/production setting representative of laboratory and field implementation and compare that with regular pressure depletion. The production scenario we consider is a 1D shale-core or matrix system first saturated with free and adsorbed CH4 gas with only the 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 an increase in pressure, where CO2 is 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 farther 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 because the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is because CO2 takes approximately 24 times less space per mole than CH4.
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.
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