Shale Gas Flow Research Articles

Pore network extraction for shale gas flow in nanoporous media

Most of pore network models were originally designed for conventional porous media (e.g. sandstone), where pore size is at micron-scale and the dominant flow is Darcy-flow. However, those models could be inapplicable for shale (a typical unconventional porous media), since plenty of nanopores exist therein and therefore the non-Darcy effects can no longer be ignored. In this contribution, the details of shale gas flow were analyzed, and it was found that flow resistance could be misestimated by previous models. For this reason, we propose a pore network model that takes into account the influences of non-Darcy effects on pore structure. In the model, pore/throat radius and throat length are not constant but change with pressure, which is distinguishable from previous models where parameters are independent of pressure. The proposed model and previous models are defined as apparent pore network (APN) and intrinsic pore network (IPN), respectively. A shale sample, imaged by focused ion beam-scanning electron microscope, was used to extract APN and IPN, and then, their network structures were compared in the terms of throat length and throat radius. Under different pressure conditions (ranging from 0.1 MPa to 48 MPa) and image resolutions (5 nm, 10 nm, 20 nm, 50 nm, and 100 nm), shale gas flow was simulated through APN and IPN, respectively. Numerical results show that apparent permeability is likely to be erroneously predicted by IPN, while APN provides a relatively reasonable solution.

Ultrahigh-Resolution 3D Imaging for Quantifying the Pore Nanostructure of Shale and Predicting Gas Transport

The pore and fracture microstructures are key to understanding gas flow in shales. The experimental determination of these microstructures is dependent on the measurement technique employed and its resolution. High-resolution three-dimensional imaging techniques coupled with image analysis and numerical simulations have been employed to characterize the petrophysical properties of shale samples. In this work, our particular focus is on using the Nano-CT and focused ion beam scanning electron microscopy (FIB-SEM) techniques at the same location in a shale rock sample to investigate the effect of their different resolutions and fields of view on the resulting imaged nanopore structure, as well as to determine any differences in the consequent measurements of the shale petrophysical properties. These petrophysical properties include porosity, permeability, pore volume and size distribution, the pore aspect ratio, the surface area to volume, and pore connectivity. The reconstructed matrix, kerogen, and pore space volumes from each approach showed significant scale-dependent differences in the microstructure. The shale sample displayed a high kerogen content with high connectivity. Porosity from the reconstructed shale volumes was observed to be 0.43 and 0.7% for FIB-SEM and Nano-CT approaches, respectively. The pore volume, size, surface area to volume ratio, and two orthogonal pore aspect ratio distributions have also been determined from the reconstructed image data by three-dimensional (3D) image analysis. These data show that voids within the rock are oblate at all scales. Permeabilities have been calculated from both the FIB-SEM and Nano-CT images and fall in the range of 2.55–9.92 nD. A simulation has also been produced based on the permeability calculation and parameters from the image analysis. The results of the simulation show connectivity in the x-, y-, and z-directions for both the FIB-SEM and Nano-CT images, with very low connectivity in the x-direction but higher connectivity in the y- and z-directions.

Lattice Boltzmann Simulations on Shale Gas Flow in Slit Micro/Nanopores in Kerogen and Prediction of Cut Off Pore Throat

A better understanding on gas flow in nanopores will advance the knowledge of gas accumulation and preservation in shale as well as development of shale gas exploitation. A modified LB model for na...

A Review of Gas Flow and Its Mathematical Models in Shale Gas Reservoirs

The application of horizontal wells with multistage hydraulic fracturing technologies has made the development of shale gas reservoirs become a worldwide economical hotspot in recent years. The gas transport mechanisms in shale gas reservoirs are complicated, due to the multiple types of pores with complex pore structure and special process of gas accumulation and transport. Although there have been many attempts to come up with a suitable and practical mathematical model to characterize the shale gas flow process, no unified model has yet been accepted by academia. In this paper, a comprehensive literature review on the mathematical models developed in recent years for describing gas flow in shale gas reservoirs is summarized. Five models incorporating different transport mechanisms are reviewed, including gas viscous flow in natural fractures or macropores, gas ad-desorption on shale organic, gas slippage, diffusion (Knudsen diffusion, Fick diffusion, and surface diffusion), stress dependence, real gas effect, and adsorption layer effect in the nanoshale matrix system, which is quite different from conventional gas reservoir. This review is very helpful to understand the complex gas flow behaviors in shale gas reservoirs and guide the efficient development of shale gas. In addition to the model description, we depicted the type curves of fractured horizontal well with different seepage models. From the review, it can be found that there is some misunderstanding about the essence of Knudsen/Fick diffusion and slippage, which makes different scholars adopt different weighting methods to consider them. Besides, the contribution of each mechanism on the transport mechanisms is still controversial, which needs further in-depth study in the future.

Optimal Selection of Shale Gas Processing and NGL Recovery Plant from Multiperiod Simulation

The advent of unconventional oil and gas has resulted in a plethora of shale gas production, and it has been predicted to increase from 1 in 2000 to 40% in 2035 of the total US domestic gas produced. Since shale gas is both industrially economical and environmentally clean compared to oil or coal as a resource, many studies are focused on developing technologies to monetize shale gas. However, one of the key challenges in utilizing shale gas is its varied flow rate and uncertain compositional behavior. The flow rate of a shale gas well dwindles over a period of time, and the composition differs from well to well in the same shale play. This provides a challenge in designing a plant of optimum capacity for shale gas processing and natural gas liquids (NGL) recovery. In this study, the periodic variation in feed flow rate is addressed while designing shale gas processing and NGL recovery plant. Different shale gas flow rates as obtained from average shale gas rate declination curve of a shale play over the period of well life is used for the design of five different plants with varied capacities. The corresponding economics of different plants are compared to find optimal plant capacity. The base case scenario is further improved through incorporation of heat integration and optimization of individual units of the process using pinch and sensitivity analyses, respectively. Economic analysis of the optimum plant size is also performed with a constant feed flow rate over its entire life. From the economic analysis of various period studies, it is observed that the optimum plant design with highest ROI percentage has more than minimum ROI requirement both with declining and constant flow rate case, implying that the proposed processing plant is economically viable to implement. Finally, environmental impact of the base case and improved design is also discussed.

The influence of transient evaporation and geometric characteristics on shale gas transmission in inorganic nanopores

Transient evaporation characteristics of water film in inorganic nanopores play an important role in the shale gas storage and transmission. Meanwhile, Inorganic nanopores in shale minerals exhibit complex geometric characteristics. In this work, TESCAN MAIA3 is used to observe the pore shape and size of inorganic nanopores. The pore shapes of rectangular or wedge-shaped are frequently occurred in inorganic nanopores. Water distribution characteristic influenced by surface wettability and disjoining pressure in slit-like nanopores is then analyzed in detail. We divide the water film attached to the surface of the inorganic nanopores into two layers: the high-viscosity water film and the bulk water film. The Moving Mesh Method is used to simulate the evaporation of water film and a mass flow prediction model synthetically considering the pore shape, evaporation, water film slip and layering is established in a single inorganic nanopore. Based on this model, the influence of four different parameters including pressure gradient, water-methane diffusivity coefficient, pore size and wedging coefficient on the shale gas production are investigated. The results show that the presence of water film and its evaporation have significant influence on the production of shale gas. This phenomenon can be interpreted by the increase of pore size caused by evaporation. However, the water film slip and layering have little effect on the shale gas flow rate. With the increase of pressure gradient, the mass flow rate increases significantly. The water-methane diffusion has a considerable influence on the time to reach the steady state. Lower wedging coefficient and larger pore size contribute to higher mass flow rate. Meanwhile, as the wedging coefficient increases from 1.0 to 1.8, the contribution of evaporation increases from 39.34% to 45.33%. Generally, the effective migration space of shale gas directly determines the amount of gas production.

Quantitative study of the influence of organic-rich and natural fracture-rich regions on shale gas production

Natural fractures and organic matter are randomly and unevenly distributed in shale gas reservoirs. The presence of organic-rich and natural fracture-rich regions causes the simulation results of the multi-continuum model to exhibit deviations from the real gas flow process. This paper presents a multi-continuum, discrete fracture model that captures the discontinuous nature of kerogen and natural fractures. The mathematical model describes the collision-weighted gas flow in organic matrix pores, inorganic matrix pores, and natural fractures by use of the unified flow model. The influence of organic matter and natural fractures on shale gas production is then quantitatively investigated. We find that Knudsen diffusion plays a more important role in shale gas flow than the viscous flow mechanism. Good communication between hydraulic fractures and natural fracture-rich regions can greatly improve gas production.

Pore‐Scale Study of Water Adsorption and Subsequent Methane Transport in Clay in the Presence of Wettability Heterogeneity

AbstractClay minerals are abundant in shale, characterized by a lamellar structure and dimensions smaller than a micron, giving rise to nanometer‐scale pore sizes and large specific surface area. They are commonly associated with water. However, the spatial distribution of the unsaturated water in clay is not very well understood, which significantly affects the subsequent shale gas flow capacity. Wettability heterogeneity in the presence of hydrocarbons further complicates the water distribution in clay. In this study, we use a 3‐D lattice Boltzmann model to study water adsorption and condensation in a reconstructed clay microstructure based on broad‐ion‐beam scanning electron microscopy images. Three wettability conditions are considered including a water‐wet case, a water‐repellent case, and a mixed‐wet case. The spatial distribution of the condensed liquid water phase is visualized, and the connectivity of the remaining open pore spaces is characterized. For the water‐wet case, water preferentially condenses in the small and narrow pore spaces, while the water‐repellent case reports the opposite trend. The mixed‐wet case results in mixed behavior, and connectivity of the pore space is bound by the former two cases. We then study the subsequent methane flow capacity with the presence of water for these three cases, and the calculated methane relative permeability curves show a percolation threshold for the water‐wet case, which is in good agreement with available experimental data in the literature measured on geosynthetic clay liners.

A semi-analytical model for horizontal-well productivity in shale gas reservoirs: Coupling of multi-scale seepage and matrix shrinkage

Matrix permeability is an important parameter in shale gas productivity prediction. However, the permeability affected by multi-scale seepage is difficult to calculate accurately. The object of this study is to develop an integrated apparent permeability model for multi-scale seepage mechanisms. The apparent permeability model considered shale gas flow from shrinkable matrix to fracture system with slip flow, Knudsen diffusion, and surface diffusion. The transport capacity change with different seepage mechanisms under different conditions was specifically analyzed. The importance of each parameter in the apparent permeability model was qualified using Grey correlation method. In addition, a semi-analytical model for horizontal-well productivity was developed to describe shale gas transport in reservoir. The semi-analytical model was solved using Laplace integral transformation and point source method. According to the results based on Grey correlation method, the effects of pore radius and Langmuir volume on dimensionless-type curves were discussed. Compared with the pore radius, the Langmuir volume had more influences on the shape of typical curve. The slip flow played the most important role in gas transport in mesopores and macropores when the pressure was more than 2 MPa and the surface diffusion was the primary transporting mechanism at any pressure in micropores but it can be negligible in macropores. The research result presented that the multi-scale seepage mechanisms would be considered in well tests and shale gas production.

Effect of Surface Force on Nanoconfined Shale-Gas Flow in Slit Channels

Summary A model for gas transport in nanoscale channels in shale-gas reservoirs (SGRs) is proposed using a new effective mean free path (MFP) model, which considers the effects of surface/gas interaction and the geometrical termination of a nanochannel boundary. In addition, the influences of the nanochannel dimension, formation-burial depth, surface type, and gas type on nanoconfined gas flow in slit channels are addressed. The nanoconfined gas-flow behavior is investigated for a wide range of temperature and pressure in this work because of the large prospects of shale gas in deep and ultradeep formations with pressure up to 100 MPa and temperature up to 480 K. The newly developed effective MFP model and the gas-flow-rate model are successfully validated with data from molecular dynamics (MD) simulations and experiments. Results show that the effect of surface force reduces the MFP and gas-flow capacity, which increases with a decreasing pressure, a decreasing channel size, and an increasing temperature; that the nanoconfinement effect has weaker influence on gas-transport capacity as the formation-burial depth increases and greater influence as formation pressure decreases during hydrocarbon production from SGRs; that a surface type affects the gas transport, and the gas-flow capacity in carbon (C) channels (organic channels) is stronger than that in silicon (Si) channels (inorganic channels) with the same size; and that the differences among the transport capacities of nitrogen (N2), argon (Ar), and methane (CH4) are not obvious, while the transport capacities of helium (He) are greatly lower compared with CH4 at both the SGR temperature and the laboratory temperature.

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

Experimental study on water-based drilling fluid for horizontal wells

ABSTRACT High-yield shale gas flow has been discovered in the Cambrian Shuijingtuo group shale (the Shuijingtuo shale) of the first shale gas well of Yichang, West Hubei, China. However, there are very few papers or reports involving high-performance water-based drilling fluid for the Shuijingtuo shale. X-ray diffraction (XRD) analysis and scanning electron microscope (SEM) tests were conducted on the outcrop of the Shuijingtuo shale samples collected from Zigui County, West Hubei. Then, the screening experiments on mud-making materials, salt additives, nanoparticles, fluid loss additives, mixed metal hydroxides (MMH), and surfactants were carried out. A high-performance water-based drilling fluid for the Shuijingtuo shale (the SWDF drilling fluid) was proposed based on physical plugging by nanoparticles, electrical property inhibition, and wettability control theory. Finally, comprehensive appraisals on rheology, filtration, lubricity, temperature resistance, inhibition, anti-pollution capability, and expense of the SWDF drilling fluid were accomplished. XRD results showed that the Shuijingtuo shale samples had 55%~67% brittle minerals. Clay minerals were mainly illite (13%~27%), and no montmorillonite was observed, which indicated that the Shuijingtuo shale was a weak-expansive rock. SEM analysis results show that pore and micro-cracks on the surface of the Shuijingtuo shale could provide natural channels for the invasion of drilling fluid. Nanomaterials were found to reduce the fluid loss of drilling fluid and thermal stability of the nano-silica dispersion was better. As a whole, the SWDF drilling fluid had suitable viscosity and gel strength, a low API fluid loss of 7.2 mL, a lubricity coefficient of 0.21, temperature-resistance capability up to 120°C, and good inhibition to shale hydration. In addition, it had excellent resistance capability to inorganic salts (NaCl, MgCl2, and CaCl2) and low-yield mud-making materials (simulated cuttings). Also, the cost of the SWDF drilling fluid was competitive compared to common oil-based drilling fluids. As a consequence, the SWDF drilling fluid can meet the requirements of drilling horizontal wells in the Shuijingtuo shale of West Hubei, China.

Modeling of geomechanics and fluid flow in fractured shale reservoirs with deformable multi-continuum matrix

The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production.

Matrix-fracture transfer shape factor for modeling multimechanisitc multicomponent shale gas flow

Numerical simulation of multimechanisitc multicomponent shale gas flow is computationally intensive and a challenging task. Upscaling of pore scale phenomena to Darcy scale simulations is highly desirable to cut down the computational time. Mass transfer between matrix and fracture in dual-porosity simulators has been traditionally upscaled through a pseudo steady state shape factor, which can be obtained analytically thanks to the linear nature of the pressure diffusion in conventional reservoirs. The use of such a shape factor is well established in modeling of fluid flow and transport in conventional reservoirs. However, the shape factor for multimechanisitc multicomponent shale gas flow is not fully realized and its determination is not straightforward due to the non-linear nature of the governing equations. In this work, we present detailed numerical simulation of multimechanisitc multicomponent shale gas flow to obtain shape factor required for Darcy scale numerical simulation of unconventional reservoirs. It is shown that shape factor can be presented as a function of dimensionless pressure (pseudo pressure), which makes application of transient shape factor independent of time. The dependence of the derived shape factor on pressure drawdown, reservoir temperature, Darcy permeability and fluid composition are also investigated. The theoretical analysis improves our knowledge of shale gas flow dynamics and the results find applications in reservoir simulation of gas production from unconventional reservoirs.

Molecular insight on competitive adsorption and diffusion characteristics of shale gas in water-bearing channels

The shale gas adsorption and flow characteristics play essential roles in improving shale gas recovery. Motivated by the desire to clarify these characteristics carefully and precisely, a series of shale models with different water contents from 0.6 to 2.4 wt% were established. Presumably, these characteristics were sought to pin down answers by using the grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) methods respectively. Importantly, the analysis of the pore structure of these models is firstly taken into account considering its microstructure to meet the demand for the explanation of the adsorption characteristics of methane. The results showed that the enterable volumes decrease significantly with the increase of water content due to the diffusion and aggregation of water molecules in the middle of enterable pores. Intuitively, it could lead to a marked linear decrease in the adsorption amount of methane from 1.2 mmol/g to 0.6 mmol/g. A curiosity of this study is that the diffusion coefficients of methane increase as the increase of temperature and ensuring the low pressure outside the channel could boost the flux of methane intriguingly. Suffice to say, the optimum development shale gas conditions in this work are at the temperature of 358 K and in the presence of water content of 2.4 wt%. Hence, there is an expectation that this study would provide a guidance for the exploitation of shale gas in the presence of water.

Comprehensive modeling of multiple transport mechanisms in shale gas reservoir production

A boom in the production of shale gas has recently impacted the world’s energy supply. The hydraulic fracturing technology has been widely used in the development of shale gas reservoirs. Models for accurate reservoir simulation are essential for their economic production. In this paper, a model for shale gas reservoir production is proposed to account for slip flow, Knudsen diffusion, surface diffusion, gas adsorption/desorption, stress dependence of a pore structure, a non-ideal gas effect, and a flow mechanism difference between organic and inorganic content in the shale matrix. This model is implemented in our in-house simulator with a coupled MINC-EDFM approach to study and predict shale gas production behavior. Comprehensive sensitivity studies are performed to analyze the importance of different parameters in shale gas production. These parameters are divided into two categories. The first category includes reservoir data, such as shale matrix porosity, a nanopore radius, an organic/inorganic volume ratio, hydraulic fracture half-length, and fracture spacing. The second category includes parameters relevant to flow mechanisms, such as a non-ideal gas effect, stress dependence, presence of an adsorbed layer as well as a selection of a flow mechanism model. It is found that parameters related to hydraulic fractures impact calculated gas production more than reservoir matrix data. Among the fracturing parameters, hydraulic fracture half-length has a stronger effect than fracture spacing, and among matrix properties, porosity has a larger impact than a nanopore radius or the assumed organic/inorganic content ratio. These results help to optimize a shale gas reservoir production design. In addition, in a synthetic case assuming a 1 nm pore radius, the presence of an adsorbed gas layer has a more tremendous effect compared to the non-ideal gas and stress dependence phenomena. Moreover, the developed simulator with the multiple transport mechanisms can be used to accurately predict shale gas reservoir production. The findings of this study help a better understanding of shale gas flow and can be used to enhance the production of shale gas reservoirs.

An efficient laboratory method to measure the combined effects of Knudsen diffusion and mechanical deformation on shale permeability

In a shale gas reservoir, the rock matrix has a relatively large porosity and gas in place, but extremely low permeability. Thus, the rock matrix is a bottleneck for shale gas flow from the reservoir to hydraulic fractures and then to the production well. We speculate that the next big thing after hydraulic fracturing for unconventional resources development is to enhance the matrix permeability in an economically feasible way. Consequently, the efficient and accurate characterization of rock matrix permeability in the laboratory is a critical task. The current laboratory techniques for source rock permeability measurement follow a “point-by-point” approach. They need multiple test runs to obtain a permeability-pressure curve, because they can only measure one permeability data point for one test run, and are thus time consuming. The root cause of this “point-by-point” approach is that these laboratory techniques are based on linearized gas flow theory requiring only small pore pressure disturbances to the experiment system. Liu et al. (2019) and this work introduce a new methodology that is based on the nonlinear gas flow theory and allows for direct measurement of the permeability-pressure curve with a single test run. This makes the approach highly time efficient. The feasibility and validity of the methodology are demonstrated in this work based on laboratory measurement results and their consistency with theoretical expectations and other independent measurements. The observed permeability exhibits a complex relationship with pore pressure as a result of the combined effects of Knudsen diffusion and mechanical deformation. For a given confining pressure, the observed permeability initially decreases with pore pressure because of Knudsen diffusion and then increases with pore pressure owing to the mechanical deformation. A rock sample with a lower permeability corresponds to a stronger Knudsen diffusion effect and weaker mechanical diffusion effect. This complex behavior highlights the need to accurately and efficiently measure the combined effects that may have important impacts on shale gas production.

Using pressure pulse decay experiments and a novel multi-physics shale transport model to study the role of Klinkenberg effect and effective stress on the apparent permeability of shales

The confining pressure imposed on a shale formation has a significant impact on the apparent permeability of the rock. Gas flow in low-permeability shales differs significantly from liquid flow because of the Klinkenberg effect, which results from gas molecule slip at the wall surfaces inside the nanopores. This effect causes the increase of apparent permeability (i.e., the measured permeability). In this study, cores extracted from four U.S. shale formations were tested using a pulse decay permeameter (PDP) under varying combinations of confining and pore pressures. The Klinkenberg coefficient was calculated to interpret the change in the measured apparent permeability as a function of pore pressure and effective stress. Next, based on the various combinations of confining and pore pressures, the actual values of the Biot coefficient were calculated by data fitting. Moreover, the samples were cored in the directions parallel to and perpendicular to the shale bedding planes to unravel the role of bedding plane direction on the apparent permeability. Furthermore, a novel, multi-physics shale transport (MPST) model was developed to account for the coupled multi-physics processes of geomechanics, fluid dynamics, and Klinkenberg effect for gas transport in shales. In the MPST model, pore pressure and effective stress are the two independent input variables, and the measured apparent permeability is the model output. The MPST model was then used to fit the PDP experimental data, and the successful data fitting confirmed that the MPST model captures the critical multi-physics processes that regulate the apparent permeability.

Gas transport characteristics in shale matrix based on multiple mechanisms

Gas transport characteristics in shale matrix can be represented by permeability. However, shale gas flow is influenced by multiple mechanisms, and existing matrix permeability models cannot comprehensively reflect these mechanisms. Therefore, current permeability models are reviewed first, and the multiple mechanisms are summarized based on previous achievements. Next, given the influence of adsorption on the gas–solid boundaries, the effect of shale gas slippage is corrected. Then, a new permeability model of shale matrix is derived based on rock and fluid properties, and its reliability is proved by using four methods. The proposed model contains 12 action mechanisms, including as many existing mechanisms as possible. Finally, the characteristics of matrix permeability are successfully analyzed by using this model and a simplified method of model application is given. The results show that, for action mechanisms, adsorption has the greatest effect on matrix permeability under small aperture at low pressure, and the influence of matrix stress sensitivity is greater than that of matrix shrinkage. Gas slippage in pores with adsorption capacity should take into account gas–gas interaction; otherwise, matrix permeability is underestimated. For flow mechanisms, the influence of viscous flow is important in all cases except for small apertures at low pressure. When the aperture is small and the pressure is low, surface diffusion and Knudsen diffusion become obvious, and the influence of surface diffusion even exceeds that of viscous flow. Pore size has a great effect on matrix permeability. The complex model can be simplified by ignoring special mechanisms, such as ratio of pores with adsorption capacity, adsorption, matrix shrinkage, and surface diffusion in most cases, even in nanopores.

Lattice Boltzmann method for simulation of shale gas flow in kerogen nano-pores considering temperature dependent adsorption

Due to the combined action of gas adsorption, surface diffusion and slippage, classical simulation approaches based on Darcy's law may not be appropriate for simulating shale gas flow in shale. In this work, a novel lattice Boltzmann (LB) model is proposed to study shale gas flow in a kerogen pore by introducing temperature dependent thickness of adsorption layer. The surface diffusion, which is caused by gradient of adsorption density, is considered as the slippage velocity on the surface of adsorption layer. The proposed LB model was adopted to simulate shale gas flow in a nano-pore. The results show that adsorption can significantly decrease the permeability of nano-pores. Surface diffusion improves the gas movement in nano-pores at lower pressure. With the decrease of pore size, the adsorbed layer had more impacts on gas permeability. Increasing temperature improves gas flow ability in nano-pores when pore size is less than 10nm. [Received: December 18, 2017; Accepted: May 2, 2018]