Apparent permeability of gas shales – Superposition of fluid-dynamic and poro-elastic effects

气页岩的表观渗透率 -- 流体动力与孔-弹效应叠加

Fuel, Volume 199, 1 July 2017, Pages 532-550

Reinhard Fink, Bernhard M. Krooss, Yves Gensterblum, Alexandra Amann-Hildenbrand

Abstract:The permeability of low-permeable gas shales is affected by both, fluid-dynamic (slip flow) and poro-elastic effects over a large pore pressure range. To analyse and separate the influence of these superposed effects, an apparent permeability model has been set up. The model’s poro-elastic and fluid-dynamic parameters were adjusted simultaneously to match own experimental data for an intact Bossier Shale (“matrix”) sample, a fractured Haynesville Shale sample and previously published literature data.

The effective stress-permeability relationship can only be described by a modified effective stress law:image. Here the fitted permeability effective stress coefficients χ, were consistently ≤1, indicating that pore pressure has a lesser influence on effective stress than confining pressure. Fluid-dynamic gas slippage effects were found to be significant up to pore pressures of 20 MPa in low permeable (<10 μD) matrix samples.

Pitfalls in the separation of fluid-dynamic and poro-elastic effects are wrong a priori assumptions. These are neglecting gas slippage above a certain pore pressure and assuming effective stress conditions to be constant in the Klinkenberg evaluation. Ignoring gas slippage in the evaluation of stress effects results in underestimation of χ values whereas undetected stress effects (by wrong a priori χ values) lead to incorrect predictions of the fluid-dynamic effects with increasing pore pressures.

The predictions of the apparent permeability model were validated and checked for consistency and plausibility by (1) visualization in a k(Pp, Pc) diagram, (2) preparation of Klinkenberg plots over large pore pressure ranges (>10 MPa) and (3) analysis of the different slippage behaviour of He and Ar.

The apparent permeability model predicts that during depletion of a shale gas reservoir apparent permeability passes through a minimum in the pressure range from 2 to 10 MPa due to the transition from a poro-elastic to a fluid-dynamic dominated realm.

Evaluation of CO2 injection in shale gas reservoirs with multi-component transport and geomechanical effects

页岩气储层注二氧化碳评估及其多组分运移和地球化学影响

Applied Energy, Volume 190, 15 March 2017, Pages 1195-1206

Tae Hong Kim, Jinhyung Cho, Kun Sang Lee

Abstract:Although research on CO2 injection in shale gas reservoirs has been focused for enhanced gas recovery (EGR) and CO2 storage, previous studies have not examined both multi-component transport and geomechanical effects. Therefore, this study presents new shale gas models for CO2 injection considering multi-component adsorption, dissolution, molecular diffusion, and stress-dependent compaction. Based on these mechanisms and data for Barnett shale field, a simulation model was constructed for CO2 flooding and huff and puff. The proposed model was used to examine the effects of CO2 injection to EGR and CO2 storage and various mechanisms. The results presented that CO2 flooding and huff and puff improve CH4 production by 24% and 6% respectively compared with no injection scenario. At the end of simulated time, the injected CO2 is stored as free, adsorbed, and dissolved states in proportions of 42%, 55%, and 3% respectively. To confirm these results, Marcellus and New Albany shale models, which have different reservoir properties, are generated and compared with Barnett shale model. However, in Marcellus and New Albany shale models, effects of CO2 injection are lower than that of Barnett shale model. Therefore, to investigate factors affecting to the efficiency of CO2 injection in shale gas reservoirs, extensive simulations were performed. Results of the simulation analyses show that natural fracture permeability, hydraulic fracture half-length, well spacing, and Langmuir constants are significant factors for EGR and CO2 storage. For the real applications, these parameters should be mainly considered. The investigations performed in this study present better understanding of CO2 injection processes to EGR and CO2 storage and they are important for optimizing the designs of CO2 injection in field applications.

Viscosity of shale gas

页岩气的粘度（性）

Fuel, Volume 191, 1 March 2017, Pages 87-96

Huy Tran, A. Sakhaee-Pour

Abstract:Nanofluidics, which analyzes fluid transport through sub 100-nm conduits, has fascinated engineers in different fields and we petroleum engineers are no exception. This field gained a significant interest in petroleum engineering only when hydrocarbon production from shales became economically feasible. The basic transport properties of the fluid change for this range of conduit size. With this in mind, we analyze the effective gas viscosity of a shale at different pore pressures. Our objective is not to derive detailed information about the gas transport at a pore or a sub-pore scale, but rather to discuss the implications of pore-scale simulations on the effective gas viscosity at the core scale. We use an acyclic pore model to account for the effective connectivity of the pore space at the core scale. The acyclic model is physically representative because it can capture capillary pressure measurements of the drainage obtained from mercury intrusion experiments. We present the effective gas viscosity with respect to the nominal value, under unconfined conditions. Our analysis shows that the reported permeability in a pressure-driven flow has to be considered an effective transport property if nominal viscosity and density are used for interpretation. That is, we have to modify viscosity and permeability simultaneously in our reservoir model. Our study has major implications for building a realistic reservoir model for shales based on petrophysical measurements.

A universal nanoscopic swell behavior model for gas shales

气页岩纳米级溶胀特性模型

Journal of Natural Gas Science and Engineering, In Press, Corrected Proof, Available online 13 February 2017

H.R. Ahmed, S.N. Abduljauwad

Abstract:Hydraulic fracturing to tap unconventional shale gas reservoirs causes a volume change of the active clay minerals matrix in the gas shale structure, resulting in the clogging of the tiny nanopores and consequently undermining the production of the shale gas. Due to the complex natural structure and fabric of clay and non-clay minerals associated with high in-situ stresses at pre and post-fracking and the practical difficulties in the replication of the field stress conditions in the lab testing facilities, swell potential from the macro and micro investigations do not provide reliable and universally applicable results. None of the existing macro level and few molecular-level studies incorporate simulations cover natural structure of gas shales. In this study, we present comprehensive molecular level simulations based volume change constitutive model for clay minerals combining the effects of cation exchange capacity, density, water content, in-situ stress state, exchangeable-cations type and proportion, pore fluids, and the dissolved salts. Although in this paper, the developed protocol have been demonstrated for the gas shales, it can equally be used for several other fields involving the use of clay minerals such as agriculture, medicine, petroleum, environment, and geotechnical engineering.

Numerical simulation of shale gas flow in three-dimensional fractured porous media

页岩气流在三维裂缝多孔介质中的数值模拟

Journal of Unconventional Oil and Gas Resources, Volume 16, December 2016, Pages 90-112

Samuel J. Kazmouz, Andrea Giusti, Epaminondas Mastorakos

Abstract:In this study, a Computational Fluid Dynamics (CFD) solver able to simulate shale gas flow as fluid flow in a porous medium on the macro level is presented. The shale gas flow is described by means of a tailored governing equation with both fluid properties and permeability expressed as a function of the effective pore pressure (stress effect) and with Knudsen effects included through an apparent permeability. This CFD solver, developed in the OpenFoam framework, allows for the simulation of three-dimensional fractured geometries without limitations on the shape of the domain. The solver was assessed and validated against literature data showing good agreement in terms of both recovery rate and pressure field profiles. The solver was then used to explore two different phenomena affecting shale gas dynamics: the diffusion behaviour and the influence of fracture geometry. It was shown that shale gas flow, on the macro level, is a diffusion-dominated phenomenon, and its behaviour can also be qualitatively represented by a diffusion equation. It was also shown that the early behaviour of shale gas flow is dictated by the fracture geometry, and that the reservoir dimensions have no effect on the flow at early times. Finally, a newly developed “dual-zone” solver, where the shale matrix and the fracture network are modelled as two distinct domains interacting through the common boundaries, is presented and discussed.