Both carbon dioxide and hydrogen can be stored in coal seams as two enabling components of energy transition from fossil-based systems to renewable sources. In both cases, understanding the evolution of coal permeability under the influence of gas adsorption is extremely important. The gas sorption-induced deformation is commonly treated by analogous calculation of thermal expansion. This assumption has long been proved to be inconsistent with observations as reported in the literature. In this study, we hypothesize that the difference between the assumption and the reality is due to self-constrained/facilitated swelling phenomena during gas injection. Under this new hypothesis, coal could be constrained or facilitated depending on coal internal structures and processes. A concept of fictitious stress is introduced to quantify coal self-constrained or facilitated degree and converted into the equivalent effective stress. This conversion has transformed the conventional effective stress principle to unconventional one. This has led to new generic coal permeability model, which has been validated by experimental data. An analysis of stress state evolution during gas storage process is conducted. Our results suggest that our coal permeability model is a valuable tool for evaluation of gas storage in coal seams.
Permeability is the most important property that controls the transfer of gas mass across a hierarchy of scales within a shale gas reservoir. When gas diffuses from the fracture wall into the matrix, the gas adsorbs onto shale grains. This adsorption may result in matrix swelling. In previous studies, it is commonly assumed that this swelling is uniform within the matrix. Under this assumption, the impact of the gas diffusion process would be neglectable. In this study, we hypothesize that this uniform swelling assumption is responsible for the inconsistencies between poroelastic solutions and experimental or field observations as reported in the literature. We introduce a volumetric ratio of the gas-invaded volume to the whole matrix volume to quantify the impact of matrix swelling volume expansion on the evolution of shale permeability. The gradual matrix pressure increase in the vicinity of fracture walls leads to local swelling. As the gas invaded zone expands within the matrix, the local effect weakens. When the matrix is completely invaded by the injected gas, a new homogeneous state is achieved, and the local effect ends. We find that the evolution of shale permeability from initial to final homogeneous states is a result of the propagation of the gas invaded area. We apply this approach to generate a series of shale permeability maps. These maps explain experimental observations under a spectrum of conditions from constant confining pressure, to constant average pore pressure, to constant effective stress, and to constant total volume conditions.
Abstract Stimulated shale reservoirs consist of kerogen, inorganic matter, secondary and hydraulic fractures. The dispersed distribution of kerogen within matrices and complex gas flow mechanisms make production evaluation challenging. Here we establish an analytical method that addresses kerogen-inorganic matter gas transfer, dispersed kerogen distribution, and complex gas flow mechanisms to facilitate evaluating gas production. The matrix element is defined as a kerogen core with an exterior inorganic sphere. Unlike most previous models, we merely use boundary conditions to describe kerogen-inorganic matter gas transfer without the instantaneous kerogen gas source term. It is closer to real inter-porosity flow conditions between kerogen and inorganic matter. Knudsen diffusion, surface diffusion, adsorption/desorption, and slip corrected flow are involved in matrix gas flow. Matrix-fracture coupling is realized by using a seven-region linear flow model. The model is verified against a published model and field data. Results reveal that inorganic matrices serve as a major gas source especially at early times. Kerogen provides limited contributions to production even under a pseudo-steady state. Kerogen properties’ influence starts from the late matrix-fracture inter-porosity flow regime, while inorganic matter properties control almost all flow regimes except the early-mid time fracture linear flow regime. The contribution of different linear flow regions is also documented.
Many field observations have indicated that permeabilities of both conventional and unconventional gas reservoirs are not constant when gas pressure drops. For conventional reservoirs, permeability will decrease while for unconventional gas rocks, the apparent permeability may increase as gas pressure decreases to a lower magnitude. Evolution trends of permeability for different natural gas reservoirs are distinct. These differences are observed by laboratory experiments of sandstones, coals, or shales. In this study, we present a general permeability model to bridge the gaps between conventional and unconventional gas reservoirs. This model coupled three critical factors namely effective stress, adsorption, and flow regimes to reflect dynamic performances of permeability. On the basis of specific reservoirs properties, the model degenerates into four reduced types. The first reduced model is applicable for reservoirs with lower adsorption capacity. The second reduced model is adopted by unconventional reservoirs like coal seams when the intrinsic permeability is big and adsorption capacity is high. For the third reduced model, effective stress is the dominating factor for permeability evolution, which means that it is applicable for conventional reservoirs like sandstones. Unconventional gas reservoirs with low adsorption capacity like gas shales can apply the fourth reduced model because the flow regimes dominate the evolution. These reduced models are verified against the experimental data. Results show that effective stress is the main reason for the change of permeability for conventional gas reservoirs. Both effective stress and flow regimes together determine the apparent permeability of unconventional gas reservoirs. The impact of adsorption on permeability is relatively small. Permeability evolution trends can be classified into different zones for conventional and unconventional gas reservoirs. When the gas is depleted from reservoirs, the gas permeability has two bounds. For the upper bound, permeability is only affected by flow regimes and the apparent permeability will increase when gas pressure drops. For the lower bound, permeability is only affected by effective stress and the apparent permeability will decrease when the gas is depleted from the reservoirs.
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