Pore Size Distribution Of Shales Research Articles

A Dynamic Permeability Model in Shale Matrix after Hydraulic Fracturing: Considering Mineral and Pore Size Distribution, Dynamic Gas Entrapment and Variation in Poromechanics

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been thoroughly explored. To address this research gap, this study introduces an innovative workflow for dynamic permeability assessment. Initially, an accurate description of the pore size distribution (PSD) within three major mineral types in shale is developed using focussed ion beam-scanning electron microscopy (FIB-SEM) and nuclear magnetic resonance (NMR) data. Subsequently, an apparent permeability model is established by combining the PSD data, leading to the derivation of dynamic permeability. Finally, the PSD-related dynamic permeability model is refined by incorporating the effects of imbibition resulting from the fracturing process preceding shale gas production. The developed dynamic permeability model varies with pore and fracture pressures in the shale reservoir. The fracturing process induces water blockage, water-film formation, and water-bridging phenomena in shale, requiring additional pressure inputs to counteract capillary effects in hydrophilic minerals in shale, But also increases the overall permeability from increasing permeability at larger scale pores. Unlike traditional reservoirs, the production process commences when the fracture is depleted to 1–2 MPa exceeds the pore pressure, facilitated by the high concentration of hydrophobic organic matter pores in shale, this phenomenon explains the gas production at the intial production stage. The reduction in adsorption-layer thickness resulting from fracturing impacts permeability on a nano-scale by diminishing surface diffusion and the corresponding slip flow of gas. this phenomenon increases viscous-flow permeability from enlarged flow spacing, but the increased viscous flow does not fully offset the reduction caused by adsorbed-gas diffusion and slip flow. In addition to the phenomena arising from various field conditions, PSD in shale emerges as a crucial factor in determining dynamic permeability. Furthermore, considering the same PSD in shale, under identical pore spacing, the shape factor of slit-like clay minerals significantly influences overall permeability characteristics, much more slit-shaped pores(higher shape factor) reduce the overall permeability. The dynamic permeability-assisted embedded discrete fracture model (EDFM) showed higher accuracy in predicting shale gas production compared to the original model.

Pore Structure and Its Controls of Shale in the Qingshankou Formation, Sanzhao Sag, Songliao Basin

The exploration and development of Gulong shale oil in the Songliao Basin has achieved a major breakthrough, with the result that a national shale oil demonstration area is being built. The shale in the Sanzhao Sag is abundant in organic matter and is an important replacement area. For this reason, it has recently become a focus for research and exploration. Compared with the Gulong Sag, the Qingshankou Formation in the Sanzhao Sag is relatively immature, and comparatively little is known about its pore structure. For this study, well ZY1, a key well in the Sanzhao Sag, was selected as the research object. Thin section observation, high-resolution field emission scanning electron microscopy, Modular Automated Processing Systemimaging, X-ray diffraction of whole rock and clay, TOC pyrolysis, and Low-pressure N2 adsorption were used to investigate the pore structure in the sag to determine the factors influencing pore development. The principal understandings are as follows: (1) The Qingshankou Formation in the Sanzhao Sag is predominantly clay shale, with a high content of clay minerals (32.8 to 70%) and TOC contents of 0.7 to 11%. These values indicate good hydrocarbon generation potential. (2) Interparticle pores, intraparticle pores, and organic matter pores are developed. Intergranular pores are the main type, mostly observed between granular minerals or between granular minerals and clays. Intraparticle pores are observed in pyrite mass and dissolved unstable minerals. Organic matter pores (OMP) occur in primary organic matter and migrate into solid bitumen. (3) The shale pores in the Sanzhao Sag are mainly H3-type slit pores, with specific surface areas of 5.4~22.9 m2/g and pore volumes of 0.03~0.07 cm3/g. Mesopores make the largest contribution to pore volume and specific surface area. Scanning electron microscope (MAPS) imaging shows that the pore size distribution of shale is mainly 20~30 nm and 100~200 nm and that large pores, especially pores of 100~200 nm and 1~2 μm, make the largest contribution to the facies. (4) The pore structure in the Sanzhao Sag is affected by mineral composition, abundance of organic matter, thermal evolution degree, and diagenesis. Organic-inorganic interactions influence and determine the pore structure characteristics of the Qingshankou Formation shale. This paper is intended to provide scientific guidance and technical support for evaluating the effectiveness of shale oil reservoirs and selecting sweet spots in the Sanzhao Sag.

Determining Nuclear Magnetic Resonance Surface Relaxivity of Shales

Nuclear magnetic resonance, as an extensively recognized technique, is utilized to measure the pore size distribution of shales. However, the pore size distribution interpreted by nuclear magnetic resonance noticeably relies on the surface relaxivity (SR) of shales, which is influenced by many factors, including the measurement approach and mineralogical compositions. This paper chiefly deals with two approaches to measuring the surface relaxivity of shales based on a one-dimensional relaxation model. In continuing, the effects of mineralogical compositions and measurement approaches on the surface relaxivity of shales are methodically assessed. The surface relaxivity of shales is measured to be 1.34–2.59 μm/s by the spin echo approach and 1.40–2.44 μm/s based on the Carr–Purcell–Meiboom–Gill approach. Compared with the nitrogen adsorption approach, the suggested methods are more suitable for measuring the SR of shales. The achieved results reveal that the shale SR is negatively correlated with quartz and calcite and is positively correlated with pyrite and clay. In particular, the clay content seems to be the most vital mineral factor in determining the SR of shales.

Fractal analysis of pore structures in transitional shale gas reservoirs in the Linxing area, Ordos Basin

Studying complex pore structures and fractal characteristics of gas shale provides significant guidance for clarifying the mechanism of shale gas accumulation and realizing its efficient development. In this paper, 12 samples of Taiyuan Formation shale are used as the research object, and the fractal theory is combined with mercury intrusion porosimetry and N2 adsorption technology to innovatively solve the problem of splicing point selection, which can reveal the full-scale pore size distribution of shale. The results demonstrate that the most common types of pores in the chosen samples are pores between or within clay minerals, micropores and mesopores inside organic matter, and microfractures, based on scanning electron microscopy imagery analyses. The pores of shale samples have fractal geometries. The fractal dimension DM1 values in the mercury intrusion porosimetry experiments range from 2.3060 to 2.6528. Two fractal dimensions, DN1 and DN2, may be obtained using the Frenkel-Halsey-Hill fractal method. DN1 values vary from 2.4780 to 2.6387, whereas DN2 values range from 2.5239 to 2.7388. Most macropores in shale samples have a size range of about 0.2 mm, with a wide pore size distribution, and the largest peak of the micro-mesopore volume is generally about 50 nm. The fractal dimension correlates positively with the corresponding pore volume, although the correlation between volume and composition is weak. The relatively strong correlation between fractals and the basic compositions of shale proves the fractal theory’s relevance in defining pore inhomogeneity. This study would contribute to the development of a fractal perspective-based method for pore splicing while also expanding our understanding of pore morphology and structure in transitional shale.

Insights into shale gas adsorption and an improved method for characterizing adsorption isotherm from molecular perspectives

• The specific multiscale inter-connected pore models of shale are proposed. • The dependences of diverse media properties and pore size on CH 4 adsorption behaviors are clearly examined by GCMC simulations. • An improved method for calibrating isothermal adsorption experimental result is proposed. Gas adsorption behavior in shale complex porous media is of great importance to gas in place (GIP) evaluation and exploration. At present, the mechanism of methane adsorption has not been adequately investigated in multi-size nanoscale space via experimental and simulation methods. In this work, the specific multi-size inter-connected pore models are proposed to study the adsorption isotherm and density profiles based on the veritable pore structure characterizations of shale samples. The grand canonical Monte Carlo (GCMC) simulations are utilized to give insight into methane adsorption behavior in organic matter and inorganic clay minerals with multi-size pores at reservoir conditions. Based on the proposed models, the effects on adsorption behaviors of methane molecules under the simultaneous action of diverse media surfaces and variable pore sizes are carefully examined. In addition, the adsorbent-adsorbate interactions, which involve the cation exchange and the isosteric heat variations with media surfaces, are carefully investigated to reveal complex adsorption behaviors in shale nanopores. Considering the identified factors influencing methane adsorption and the shortcomings of experimental test, an improved method for calibrating the gas adsorption isotherms in shale is proposed from a molecular perspective, which takes into account several factors, including i) the accessible volume of methane molecules, ii) the pore size distribution in shale, and iii) the composition of organic matter and clay minerals. The GCMC simulation results are integrated into the process of calibrating experimental results in a case study with a shale sample from the Longtan Formation in the Sichuan Basin, China. The findings of this study advance the in-depth understanding of gas adsorption mechanisms in complex nanoporous structure and provide a reliable approach to evaluate the GIP in shale.

Estimation of shale pore-size-distribution from N2 adsorption characteristics employing modified BJH algorithm

Accurate pore-size-distribution (PSD) is the key to comprehending porous media and shale rock characteristics. There are multiple methods for calculating the PSD of porous media. The Barrett–Joyner–Halenda (BJH) method is the most widely used and simplest calculation, and therefore, this study focus on the BJH algorithm to discuss the accurate shale PSD based on N2 adsorption characteristics. Despite conducting more than a hundred experiments there are certain phenomena for which the calculated pore volume is smaller than the actual pore volume. Therefore, we combined the Brunauer–Emmet–Teller (BET) multilayer adsorption theory and Halsey adsorption equation to analyze the capillary evaporation and desorption demarcation points in the desorption isotherm of each shale sample, and a modified PSD calculation model was established. In addition, we applied the modified BJH algorithm to a homogeneous silicon material with the pore radius known, for calculating the theoretical pore radius and subsequently the pore radii; this allowed determining the correctness of the modified algorithm. The calculation error was approximately 5% that indicated the accuracy of this algorithm. Therefore, this study could provide meaningful insights into the accurate PSD calculation and gas-in-place estimation in shale nanoporous media.

Fractal and multifractal characteristics of shale nanopores

Shale pore structure is an important factor in shale adsorption and percolation. To better characterize the pore structure of shales, this paper selects 24 shale core samples for high-pressure mercury intrusion (HPMI) test, and fractal theory and multifractal theory are applied to analyze the pore structures of shale nanopores. The fractal dimensions using different fractal models and the multifractal parameters are calculated from mercury intrusion capillary pressure (MICP). The correlations between fractal/multifractal parameters and shale nanopore structures are analyzed. The study reveals that the fractal dimension calculated from 3D capillary model can be used as an index for evaluating complex of shale nanopores. The fractal dimension increases with the increase of displacement pressure and homogeneity coefficient and decreases with the increase of the permeability and pore-throat radius. The multifractal analysis shows that shale nanopores have multifractal characteristics, and multifractal parameters can reflect the size, concentration, and asymmetry of pore size distribution (PSD). The PSD of shales are similar when they have similar multifractal parameters (Δα,Δf,α0,α1,α2). The information dimension D1 and correlation dimension D2 are positively correlated to the sizes of shale nanopores, and with the decreasing information dimension D1, the pore size distributes more contributed. Besides, the information dimension D1 has a strong and negative correlation with the fractal dimension derived from 3D capillary model.

Pore Size Distribution and Fractal Characteristics of the Nanopore Structure in Organic-Rich Shales Using the Neimark-Kiselev Fractal Approach.

Shale gas has been playing an increasingly important role in meeting global energy demands. The heterogeneity of the pore structure in organic-rich shales greatly affects the adsorption, desorption, diffusion and flow of gas. The pore size distribution (PSD) is a key parameter of the heterogeneity of the shale pore structure. In this study, the Neimark-Kiselev (N-K) fractal approach was applied to investigate the heterogeneity in the PSD of the lower Silurian organic-rich shales in South China using low-pressure N₂ adsorption, total organic carbon (TOC) content, maturity analysis, X-ray diffraction (XRD) and field emission scanning electron microscopy (FE-SEM) measurements. The results show that (1) the fractal dimension DN-K obtained by N-K theory better represents the heterogeneity of the PSD in shale at an approximately 1-100 nm scale. The DN-K values range from 2.3801 to 2.9915, with a mean of 2.753. The stronger the PSD heterogeneity is, the higher the DN-K value in shale is. (2) The clay-rich samples display multimodal patterns at pore sizes greater than 20 nm, which strongly effect the PSD heterogeneity. Quartz-rich samples display major peaks at less than or equal to a 10 nm pore size, with a smaller effect on the PSD heterogeneity in most cases. In other brittle mineral-rich samples, there are no obvious major peaks, and a weak heterogeneity of the PSDs is displayed. (3) A greater TOC content, maturity, clay content and pore size can cause stronger heterogeneity of the PSD and higher fractal dimensions in the shale samples. This study helps to understand and compare the PSD and fractal characteristics from different samples and provides important theoretical guidance and a scientific basis for the exploration and development of shale gas resources.

Characterization of shales from Damodar valley coalfields for CH4 recovery and CO2 sequestration

Anthropogenic emission of greenhouse gases particularly, CO2 is believed to be responsible for the global climate change. Carbon sequestration has been identified as one of the technological alternatives of reducing CO2 emission from the atmosphere. Disposal of CO2 in unconventional reserves such as shale formations may help in achieving the objectives of sequestration of the CO2 coupled with enhanced recovery of methane. The methane/CO2 storage potential of shale mainly depends on its porous nature which is very complex due to the presence of micro-, meso-, and macro-pores. Understanding the pore size distribution of shales is important because the storage and transport mechanisms of methane and CO2 vary as per the size of the pore. Further, the clay minerals present may also contribute significantly to the adsorption capacity of shale and may thus control the gas storage. In the present study, an attempt is made to investigate the pore structure of some shale samples from Damodar valley coalfields (Jharia and Raniganj coalfields), India in detail and correlate the pore parameters with adsorption of methane. Secondly, the clay mineral composition of studied shales is analyzed and its effect on porosity and adsorption are examined. Low pressure nitrogen and carbon dioxide adsorption tests, mercury intrusion and helium pycnometry tests are carried out to ascertain the pore sizes, surface area, and pore volume. It is observed that the porosity for most of the studied shales are dominated by mesopores. A moderate correlation is observed between nitrogen BET surface area and porosity suggesting lesser amount of micropores and dominance of mesopores. Porosity of the studied shales varied with clay mineral content exhibiting a U-shaped relationship.

CH4 and CO2 adsorption-induced deformation of carbon slit pores with implications for CO2 sequestration and enhanced CH4 recovery

Geological sequestration of carbon dioxide (CO2) into coal seams and shale gas reservoirs have the benefits of CO2 storage as well as enhanced gas recovery. However, the coal or shale swelling during CO2 enhanced methane (CH4) production significantly reduces the gas injection and production rate. In this work, the CH4 and CO2 adsorption-induced deformation of carbon slit pores as representative of coal and shale nanopores was studied using grand canonical Monte Carlo simulation. We focused on the strain difference by comparing the CO2 and CH4 adsorption-induced deformation of pores with various widths. The effect of each pore width on the bulk swelling was analyzed under different pressures and temperatures. The results showed that the strain difference between CO2 and CH4 at different conditions oscillates with a damped amplitude as the pore width increases, which can be positive or negative indicating pore swelling or contraction when CH4 is displaced by CO2. The maximum swelling occurs among the pores inaccessible to CH4 but accessible to CO2 molecules and the contracting pores contribute negatively to the bulk swelling. Furthermore, this study provided fundamental adsorption induced strain of each pore width for predicting the bulk deformation during CO2 enhanced CH4 production when the coal or shale pore size distribution is known.

Effects of internal gradients on pore-size distribution in shale

In porous media, effects of internal gradient caused by magnetic susceptibility contrast between the matrix and infilling fluid shifts transverse relaxation time (T2) to shorter time, resulting in imprecise classification of pore sizes. In shale, details of the effects of paramagnetic and clay minerals that induce the internal gradients are poorly understood. We measured a brine mixture with a granular form of minerals, including kaolinite, montmorillonite, glauconite, illite, pyrite, celadonite, and chamosite, to infer contributions of each to T2 relaxation in shale. Nuclear magnetic resonance (NMR) response of these samples was used to calculate the total mean logarithm of T2 (T2ML) and volume of water in the samples. Additionally, physical properties such as magnetic susceptibility, specific surface area, and elemental composition were acquired. Pore geometry, magnitude of internal gradients, pore-size distributions, and secular regimes in which the media relaxed (based on their shortest characteristic time scales) were characterized from these properties. These time scales measure the behavior of the relaxation regimes such as longitudinal relaxation time-to-T2 ratio and dependence of relaxation rate on echo spacing (tE). Glauconite illite, pyrite, chamosite, and kaolinite grouped into a small-pore system, whereas montmorillonite and celadonite grouped into large-pore systems. A free diffusion regime governed secular relaxation for kaolinite; a motional-averaging regime governed montmorillonite, celadonite, and large tE chamosite; whereas a localization regime dominated the rest of the minerals. We conclude that understanding the effects of internal gradients in shale is important to quantify the shortening of T2ML, which leads to overestimation of bulk fluid volume and, thus, underestimating NMR permeability when used as an input into permeability estimator equations.

Responses of specific surface area and micro- and mesopore characteristics of shale and coal to heating at elevated hydrostatic and lithostatic pressures

Samples of the low-maturity New Albany Shale (Middle and Upper Devonian to Lower Mississippian) and Mowry Shale (Late Cretaceous), both containing kerogen Type II, and samples of Wilcox Coal (Eocene), containing kerogen Type III, were heated to 60, 100, and 200 °C at hydrostatic ambient pressure, 100, or 300 MPa for 6 or 12 months in sealed glass and gold cells to investigate temperature and pressure effects on porosity and thermal maturity. In addition, lithostatic experiments were conducted in a hydraulic press at 100 MPa and 100 °C over a period of 6 months. Porosimetric characteristics of samples before and after experiments were investigated by using low-pressure gas adsorption and scanning electron microscope (SEM).An increase from ambient temperature to 200 °C caused increases in random vitrinite reflectance (Ro) for all samples, with Mowry Shale showing the largest increase from 0.57% to 0.65% and Wilcox Coal showing the smallest increase from 0.39% to 0.41%. For Mowry Shale and New Albany Shale, specific surface areas did not change in any notable way with an increase in temperature; specific surface area values for Mowry Shale ranged from 2.0 to 3.2 m2/g, and for New Albany Shale from 13.7 to 15.6 m2/g. Differences in Barrett-Joyner-Halenda (BJH) specific mesopore volumes and average mesopore size for the shales were also small to negligible. Considering the values of the original samples, we propose that these small differences are related to internal inhomogeneity of samples rather than to any temperature effect. Temperature-related changes in Wilcox Coal were more distinct. Specifically, there was a marked decrease in BET surface area, from 4.9 m2/g at 60 °C to 1.5 m2/g at 200 °C, and a decrease in both BJH mesopore volume and average mesopore size. The Wilcox Coal sample had large micropore surface areas (110–148 m2/g) compared to both shales, which had micropore surface areas below 10 m2/g. While Wilcox Coal showed a drop in micropore volume between 60 °C and 200 °C, no distinct or regular changes in micropore volume with temperature were documented for the other two samples.A sustained hydrostatic pressure increase from ambient to 300 MPa for 6 to 12 months resulted in insignificant changes in vitrinite reflectance values. Small differences in Brunauer-Emmett-Teller (BET) specific surface areas, micropore surface area, and volume may be related to internal sample heterogeneity rather than pressure treatment. Similar to the temperature effect, the Wilcox Coal sample experienced more pronounced changes compared to the shales. SEM observations on shales did not reveal porosity-related changes between the original and treated samples. No marked changes were documented for lithostatic pressure conditions at 100 MPa and 100 °C. We conclude that elevated isotropic hydrostatic or lithostatic pressure is unable to significantly affect the pore structure and pore-size distribution of shales, but it can make some modifications in the micropore and mesopore pore characteristics of low-rank coal.

Porosity and pore size distribution of shales: a case study of the Carynginia Formation, Perth Basin, Western Australia

The evaluation of the gas storage potential of shale reservoirs requires a good understanding of their pore network. Each of the laboratory techniques used for pore characterisation can be applied to a specific range of pore sizes; but if the lithology of the rock is known, usually one suitable method can be selected to investigate its pore system. Shales do not fall under any particular lithological classification and can have a wide range of minerals present, so a combination of at least two methods is typically recommended for a better understanding of their pore network. In the laboratory, the Low-Pressure Nitrogen Gas Adsorption (LP-N2-GA) technique is typically used to examine micropores and mesopores, and Mercury Injection Capillary Pressure (MICP) tests can identify pore throats larger than 3 nm. In contrast, a wider range of pore sizes in rock can be screened with Nuclear Magnetic Resonance (NMR), either in laboratory measurements made on cores or through well logging, provided that the pores are saturated with a fluid. The pore network of a set of shale core samples from the Carynginia Formation was investigated using a combination of laboratory methods. The cores were studied using the NMR, LP-N2-GA and MICP techniques, and the experimental porosity and pore size distribution results are presented. When NMR results were calibrated with MICP or LP-N2-GA measurements, then the pore size distribution of the shale samples studied could be estimated.

Application of low pressure gas adsorption to the characterization of pore size distribution of shales: An example from Southeastern Chongqing area, China

Pore size distribution is vital in the preservation and exploitation of shale gas; the pores in shales are mainly of nanometer scale. This study focuses on the pore structures of the Upper Ordovician-Lower Silurian black shales that were sampled from the Well YC7 in southeastern Chongqing area. Nitrogen and carbon dioxide gas adsorption were conducted at 77.4 K and 273.15K, respectively. Pore structures were characterized by the modified BET, BJH, DFT, and Stoeckli methods. The results show that: (1) micropores, mesopores, and macropores are all well developed in both the Lower Silurian and Upper Ordovician shales; (2) the mean diameter of micropores for our samples is approximately 1.26 nm; and (3) the micropore size distribution curves derived from the Stoeckli method together with the CO2 adsorption data at 273.15K can be well connected with the calculated DFT model values through nitrogen adsorption data at 77.4 K, indicating that a full pore size distribution curve could be achieved for micropores, mesopores, and a portion of macropores in the shales by combing the N2 and CO2 adsorption data.

Study on pore structure characteristics of marine and continental shale in China

Shale gas is a key natural gas resource and has been a certain success in China. The Weiyuan marine shale (1#), Jiaoshiba marine shale (2#), Yaoqu tuff (4#) and Yaoqu continental shale (5# and 6#) were selected and subjected to thin section analyses, ice field emission scanning electron microscope (FE-SEM), mercury intrusion capillary pressure (MICP) and gas adsorption tests to study the pore structure characteristics of typical marine and continental shale. Results of pore structure characteristics and controlling factors, puts forward a new standard of pore size naming for hydraulic fracturing technology. Pore distribution uniformity coefficient hu is proposed to describe the continuity of different pore size distribution of shale. The test results of N2 adsorption and CO2 adsorption can be unified to attain continuous distribution of nanometer pore by using density function theory (DFT) model. The pore development degree of the samples from high to low are from 2#, 5#, 1#, 6# to 4# in the pore range of 2–100 nm while for the pore range of 10–100 μm the pore development degree from high to low are 2#, 1#, 4#, 6# to 5# in that order. Micro-nano pore of sample 2# and 5# are more developed compared to the other samples. Also gas storage capacity of sample 2# and 5# are stronger. The results can thus be used to guide the shale gas development, optimize shale location and increase production of shale gas.

A Comprehensive Reservoir Simulator for Unconventional Reservoirs That Is Based on the Fast Marching Method and Diffusive Time of Flight

SummaryModeling of fluid flow in unconventional reservoirs requires accurate characterization of complex flow mechanisms because of the interactions between reservoir rock, microfractures, and hydraulic fractures. The pore-size distribution in shale and tight sand reservoirs typically ranges from nanometers to micrometers, resulting in ultralow permeabilities. In such extremely low-permeability reservoirs, desorption and diffusive processes play important roles in addition to heterogeneity-driven convective flows.For modeling shale and tight oil and gas reservoirs, we can compute the well-drainage volume efficiently with a fast marching method (FMM) and by introducing the concept of “diffusive time of flight” (DTOF). Our proposed simulation approach consists of two decoupled steps—drainage-volume calculation and numerical simulation with DTOF as a spatial coordinate. We first calculate the reservoir drainage volume and the DTOF with the FMM, and then the numerical simulation is conducted along the 1D DTOF coordinate. The approach is analogous to streamline modeling whereby a multidimensional simulation is decoupled to a series of 1D simulations resulting in substantial savings in computation time for high-resolution simulation. However, instead of a “convective time of flight” (CTOF), a DTOF is introduced to model the pressure-front propagation.For modeling physical processes, we propose triple continua whereby the reservoir is divided into three different domains: microscale pores (hydraulic fractures and microfractures), nanoscale pores (nanoporous networks), and organic matter. The hydraulic fractures/microfractures primarily contribute to the well production, and are affected by rock compaction. The nanoporous networks contain adsorbed gas molecules, and gas flows into fractures by convection and Knudsen diffusion processes. The organic matter acts as the source of gas. Our simulation approach enables high-resolution flow characterization of unconventional reservoirs because of its efficiency and versatility. We demonstrate the power and utility of our approach with synthetic and field examples.