Gas flow in ultra-tight shale strata (original) (raw)
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Understanding fluid transport through the multiscale pore network of a natural shale
EPJ Web of Conferences
The pore structure of a natural shale is obtained by three imaging means. Micro-tomography results are extended to provide the spatial arrangement of the minerals and pores present at a voxel size of 700 nm (the macroscopic scale). FIB/SEM provides a 3D representation of the porous clay matrix on the so-called mesoscopic scale (10-20 nm); a connected pore network, devoid of cracks, is obtained for two samples out of five, while the pore network is connected through cracks for two other samples out of five. Transmission Electron Microscopy (TEM) is used to visualize the pore space with a typical pixel size of less than 1 nm and a porosity ranging from 0.12 to 0.25. On this scale, in the absence of 3D images, the pore structure is reconstructed by using a classical technique, which is based on truncated Gaussian fields. Permeability calculations are performed with the Lattice Boltzmann Method on the nanoscale, on the mesoscale, and on the combination of the two. Upscaling is finally done (by a finite volume approach) on the bigger macroscopic scale. Calculations show that, in the absence of cracks, the contribution of the nanoscale pore structure on the overall permeability is similar to that of the mesoscale. Complementarily, the macroscopic permeability is measured on a centimetric sample with a neutral fluid (ethanol). The upscaled permeability on the macroscopic scale is in good agreement with the experimental results.
Effect of microscale compressibility on apparent porosity and permeability in shale gas reservoirs
International Journal of Heat and Mass Transfer, 2018
The pore network in shale reservoirs comprise of nanoporous organic matter (OM) and micron-size pores in inorganic material (iOM). Accurate gas transport models in shale must include gas slippage, Knudsen diffusion, surface diffusion, and sorption. The change in pore size due to the applied stress could consequently affect gas transport processes. In this study we a compression coefficient to characterize the influence of stress sensitivity on key parameters for gas transport. We consider separate stress response in nanoporous organic matter and iOM because of their different mechanical properties. The effects of compressibility on apparent permeability of OM and iOM are analyzed at different pore sizes, pore pressures and for different gas compositions. Our results show that compressibility has a greater influence on the apparent permeability of iOM than on OM when pore sizes are smaller than 10 nm, whereas compression has similar impact on apparent permeability of both media when pore sizes are larger than 10 nm. With the same effective stress, lower pore pressure results in greater impair in permeability. We conducted a reservoir simulation study using conventional dual-continua model with our developed pressure dependent porosity and permeability to showcase field implication of this study. This work is an important and timely investigation of the development of shale-reservoir-flow simulators.
Upscaling pore pressure-dependent gas permeability in shales
Journal of Geophysical Research: Solid Earth
Upscaling pore pressure dependence of shale gas permeability is of great importance and interest in the investigation of gas production in unconventional reservoirs. In this study, we apply the Effective Medium Approximation, an upscaling technique from statistical physics, and modify the Doyen model for unconventional rocks. We develop an upscaling model to estimate the pore pressure-dependent gas permeability from pore throat size distribution, pore connectivity, tortuosity, porosity, and gas characteristics. We compare our adapted model with six data sets: three experiments, one pore-network model, and two lattice-Boltzmann simulations. Results showed that the proposed model estimated the gas permeability within a factor of 3 of the measurements/simulations in all data sets except the Eagle Ford experiment for which we discuss plausible sources of discrepancies.
Gas Flow Models of Shale: A Review
Energy & Fuels
Conventional flow models based on Darcy's flow physics fail to model shale gas production data accurately. The failure to match field data and laboratory-scale evidence of non-Darcy flow has led researchers to propose various gas-flow models for the shale reservoirs. There is extensive evidence that suggests the size of the pores in shale is microscopic in the range of a few to hundreds of nanometers (also known as nanopores). These small pores are mostly associated with the shale's organic matter portion, resulting in a dual pore system that adds to the gas flow complexity. Unlike Darcy's law, which assumes that a dominant viscous flux determines a rock's permeability, shale's permeability leads to other flow processes besides viscous flow such as gas slippage and Knudsen diffusion. This work reviews the dominant gas-flow processes in a single nanopore on the basis of theoretical models and molecular dynamics simulations, and lattice Boltzmann modeling. We extend the review to pore network models used to study the gas permeability of shale.
Transport In Porous Media, 2017
A nonlinear transport model for single-phase gas flow in tight porous media is developed. The model incorporates many important physical processes that occur in such porous systems: continuous flow, transition flow, slip flow, Knudsen diffusion, adsorption and desorption into and out of the rock material, and a correction for high flow rates. This produces a nonlinear advection-diffusion type of partial differential equation with pressure-dependent model parameters and associated compressibility coefficients, and highly nonlinear apparent convective flux (velocity) and apparent diffusivity. A key finding is that all model parameters should be kept pressure dependent for the best results. An application is to the determination of rock properties, such as porosity and permeability, by history matching of the simulation results to data from pressure-pulse decay tests in a rock core sample (Pong et al. in ASME Fluids Eng Div 197:51-56, 1994).
Multiscale, Multiphysics Network Modeling of Shale Matrix Gas Flows
Transport in Porous Media, 2013
We present a pore network model to determine the permeability of shale gas matrix. Contrary to the conventional reservoirs, where permeability is only a function of topology and morphology of the pores, the permeability in shale depends on pressure as well. In addition to traditional viscous flow of Hagen-Poiseuille or Darcy type, we included slip flow and Knudsen diffusion in our network model to simulate gas flow in shale systems that contain pores on both micrometer and nanometer scales. This is the first network model in 3D that combines pores with nanometer and micrometer sizes with different flow physics mechanisms on both scales. Our results showed that estimated apparent permeability is significantly higher when the additional physical phenomena are considered, especially at lower pressures and in networks where nanopores dominate. We performed sensitivity analyses on three different network models with equal porosity; constant cross-section model (CCM), enlarged crosssection model (ECM) and shrunk length model (SLM). For the porous systems with variable pore sizes, the apparent permeability is highly dependent on the fraction of nanopores and the pores' connectivity. The overall permeability in each model decreased as the fraction of nanopores increased. Keywords Nanoscale and microscale gas flow • Network modeling • Gas slip • Knudsen diffusion Nomenclature A Cross-sectional area, m 2 f Nanopore fraction, dimensionless
Open Geosciences, 2019
Shale, a heterogeneous and extremely complex gas reservoir, contains low porosity and ultra-Low permeability properties at different pore scales. Its flow behaviors are more complicated due to different forms of flow regimes under laboratory conditions. Flow regimes change with respect to pore scale variation resulting in change in gas permeability. This work presents new insights regarding the change of pore radius due to gas adsorption, effective stress and impact of both on shale gas permeability measurements in flow regimes. From this study, it was revealed that the value of Klinkenberg coefficient has been affected due to gas adsorption-induced pore radius thickness impacts and resulting change in gas permeability. The gas permeability measured from new proposed equation is provides better results as compare to existing equation. Adsorption parameters are the key factors that affect radius of shale pore. Both adsorption and effective stress have an effect on the pore radius and...
Investigation of the 3D pore structure of a natural shale - implications for mass transport
E3S Web of Conferences
The multiscale pore structure of a natural shale is obtained by three distinct imaging means. First, micro-tomography image data are extended to provide the spatial arrangement of the minerals and pores observable with a voxel size of 700 nm (denoted here as the macroscopic scale). Second, FIB/SEM provides a 3D representation of the porous clay matrix on the so-called mesoscopic scale (10-20 nm); a connected pore network, devoid of cracks, is obtained for two samples out of five, while the pore network is connected through cracks for two other samples out of five. Third, the nanometric pore network is characterized with tomographic STEM. Using these experimental pore structure data, permeability calculations are performed by the Lattice Boltzmann Method on the nanoscale, on the mesoscale, and on the combination of the two. Upscaling is finally done (by a finite volume approach) on the larger macroscopic scale. Calculations show that, in the absence of cracks, the contribution of the...
Semi-quantitative multiscale modelling and flow simulation in a nanoscale porous system of shale
Fuel, 2018
Numerical flow simulation in shale, especially in the nanoscale porous system of a shale matrix, is still challenging because no imaging device can effectively describe the nanoscale porous structure of shale to satisfy both resolution and field of view (FOV). The resolution of an X-ray computed tomography (µ-CT) image is too low to detect the nanoscale features of porous structure in shale. The FOV of a focused ion beam scanning electron microcopy (FIB-SEM) image, on the other hand, is too small to capture the heterogeneity of a shale matrix. Therefore, we propose a semi-quantitative, Multiscale reconstruction strategy to build an image based network model of a shale sample with nanoscale resolution covering three orders of magnitude of FIB-SEM image volume. In this study, shale is considered a Multiscale porous media consisting of microscale and nanoscale structures. The microscale structures reflect the morphological features of organic matter, clay minerals, intergranular pores and micro-cracks that can be detected by µ-CT. The nanoscale features focus on the inner porous structure of organic matter and clay minerals that can be characterised using a scanning electron microcopy (SEM) or a FIB-SEM. nanoscale. Multiscale means reconstruction work that is carried out at the microscale and nanoscale separately, using the multiple-point statistics (MPS) method. Microscale reconstruction aims to recover the connections that are undetected among microscale objects due to the low resolution of the µ-CT image. Within the organic and clay phases, a nanoscale reconstruction is then carried out to model the nanoscale porous structure. Semi-quantitative means the segmented µ-CT image is used as conditional data in microscale reconstruction to maintain the reality of microscale structures. To relieve the heavy burden of data storage, a network modelling procedure is simultaneously undertaken alongside nanoscale reconstruction to transfer the reconstructed structure to a network model. Based on the established network model, flow simulation is undertaken by applying an extended Beskok-Karniadakis (B-K) model considering continuum, non-continuum and surface diffusion. The results show that the permeability ratio is affected by pressure, the molecule diameter of gas and surface diffusion.