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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.

Appreciable CO2 injectivity is required to inject large volumes of CO2 through a minimum number of wells. In situ geochemical CO2‐brine‐rock reactions may dissolve sandstone rock minerals, and consequently release fine particles into the pore fluid. If the fine particles (‘fines’) are mobilized during CO2 injection, well injectivity could be severely impaired. The transport of fines under CO2 injection conditions involves the complex multiphase flow of dry supercritical CO2, saline formation brine, and fine particles. While transported fines could plug narrow pore channels, the saline pore water could be vaporized by supercritical CO2 to precipitate solid salt into the pores. To understand the impact of mineral dissolution on CO2 injectivity, it is important to consider the coupled effect of fine particle mobilization and salt precipitation. We conducted core‐flood experiments and theoretical modelling to investigate the coupled effect of the fines mobilization and salt precipitation on CO2 injectivity. We found that salt precipitation could increase CO2 injectivity impairment induced by the fines mobilization. The deposited salt reduces the flow area, making the pores more susceptible to particle entrapment. Injectivity impairment increased with decreasing initial rock permeability and increasing saturating brine salinity. Irreducible brine saturation and pore size distribution were identified as parameters that strongly determine the contribution of salt precipitation during the transport of fines. Injectivity impairment was also slightly higher when the rock was first exposed to salt precipitation, before the entrapment of fines. The current findings highlight the complexity and uniqueness of fines transportation under CO2 injection conditions and the impact of mineral dissolution on CO2 injectivity. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

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