Shale Gas Flow Research Articles

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

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

Theoretical stability analysis of mixed finite element model of shale-gas flow with geomechanical effect

In this work, we introduce a theoretical foundation of the stability analysis of the mixed finite element solution to the problem of shale-gas transport in fractured porous media with geomechanical effects. The differential system was solved numerically by the Mixed Finite Element Method (MFEM). The results include seven lemmas and a theorem with rigorous mathematical proofs. The stability analysis presents the boundedness condition of the MFE solution.

A comprehensive model for simulating gas flow in shale formation with complex fracture networks and multiple nonlinearities

Shale gas reservoirs are characterized by gas adsorption and multiple flow mechanisms in shale matrix and complex fracture networks after hydraulic fracturing stimulation. It is of significance to capture the dynamic pressure-dependent properties, including gas PVT properties, gas desorption, flow mechanisms, and stress-dependent fracture permeability. In this paper, this problem is handled by proposing a novel Green element method, which is a good extension of the traditional boundary element method. The domain is discretized into many Cartesian grids, and boundary element method is applied to each element. Discrete fractures are flexibly handled by embedding the fractures into the background grids for the domain, and finite difference method is applied to model flow within the fracture system. The flow between the fracture system and matrix system is coupled to obtain the eventual matrix equation, and Picard successive approximation method is applied to obtain the solution of the nonlinear system. The solution of the novel Green element method is validated by the commercial simulator Eclipse for a fractured tight gas well model. A field case from Longmaxi formation in Southwestern China is used to verify the utility of the model. Moreover, the effects of nonlinear parameters on the performance of the well are analyzed. The results show that the nonlinear factors in shale gas flow model have a great impact on the eventual results of gas production forecasts, especially gas PVT properties and stress-sensitive fracture conductivity.

Modeling of gas flow in fractured shale

Abstract In this paper equations and methodologies for the simple modeling of gas flow in fractured shale are developed. Transmissibility following hydraulic fracturing is related to the geo-mechanical properties of the shale. Methods for the application of these models using commercial conventional reservoir models to predict well productivity are developed. This provides a valuable tool in estimating the productivity and economic value of a potential shale gas play where only geological, petrophysical and geo-mechanical and limited or analogue production data is available.

Analytical Model for Real Gas Transport in Shale Reservoirs with Surface Diffusion of Adsorbed Gas

Shale is a kind of heterogeneous porous medium, which has a large number of nanopores. A model for shale gas flow is proposed and validated with published results. The transport mechanisms and the effect of surface diffusion are investigated. The results show that when the diameter of shale nanopore is 1 nm, the surface diffusion is dominant. With the increase in Knudsen number, the surface diffusion permeability decreases gradually. When the pore diameter is 8 nm, the Knudsen diffusion is dominant at a high Knudsen number. At low pressure, the apparent permeability predicted by the present model considering the surface diffusion is larger than that without considering the surface diffusion. At high pressure, the apparent permeability decreases when surface diffusion is considered. The study offers theoretical support for numerical simulations of shale gas development.

A generalized model for gas flow prediction in shale matrix with deduced coupling coefficients and its macroscopic form based on real shale pore size distribution experiments

As an unconventional natural gas resource, shale gas is attracting increasing attention worldwide because of its potential to strengthen global energy security and reduce carbon emissions. The shale gas flow in nanopores is one of the main concerns affecting its development process. However, due to the strong nonlinearity and complexity of gas flow at the nanoscale, there is no satisfactory consensus on a physically sound flow mechanism scheme and its corresponding coupling method. Furthermore, although the integration method using specific functions has been proposed to facilitate the consideration of various pore sizes in shale matrix, the real shale experiments are rarely involved to realize this integration method with definitely determined parameters. In this study, the concept of “wall-associated diffusion” is firstly utilized to clarify the relationship among several flow mechanisms, and thereby a comprehensive flow mechanism scheme differing from common research is proposed, which physically considers both the division of mechanical mechanisms in nanopores and partition of flow space. Besides, the deficiencies in the mathematical models of viscous flow and several diffusion processes for flow description are illustrated. Using the molecular collision frequency expressions, a new coupling coefficient-based flow model in nanopores is derived to eliminate the aforementioned deficiencies by strengthening the correspondence between the flow models and Knudsen number (Kn), which is applicable in the full flow regime scope and avoids segment processing. Furthermore, based on the pore size distribution experiments of the real shale samples from a gas field, the fitting parameters needed for the macroscopic form of the above coupled model are obtained, so as to establish an integration method-based unified model for gas flow prediction in shale matrix. Results show that the prediction accuracy of the new model for the two tested shale samples is at least 2.2 times higher than several typical models and is also 1.9 and 7.5 times more accurate than the model without coupling coefficients, respectively. And the application of the proposed model to the flow experiment on another shale sample at higher pressure levels is in accordance with these observations. Interestingly, as temperature increases, the flow rate decreases with minor amplitudes. Under the conditions studied, the pressure change can cause over 10 times variation of the flow rate, revealing measures should be taken to maintain relatively high reservoir pressures to guarantee appreciable gas production from matrix if the other factors remain unchanged. In addition, the difference between the average flow shape in the whole rock and the gas motion in the pore of mean radius is revealed. Sounder in theoretical bases and better in application effects, the proposed model is expected to be of practical significance for guiding shale gas reservoir development.

An upscaled transport model for shale gas considering multiple mechanisms and heterogeneity based on homogenization theory

Because of the complex pore structure and multiple types of gas storage, the traditional Darcy permeability model is not valid for describing shale gas flow. In this paper, an upscaled transport model is established based on homogenization theory to consider multiple transport mechanisms and the heterogeneity of shale samples. This new transport model is employed to successfully explain pressure decay experimental data. The results show that absorbed gas cannot be ignored in pressure decay experiment and the pressure difference decreases rapidly when the absorbed gas is not considered. Then several critical conclusions have been drawn as follows. The permeability anisotropy for stochastic distribution model can be ignored and the effective permeability will be underestimated by double porosity model if surface diffusion dominates gas flow in shale reservoir. In addition, shale gas transport is dominated by Knudsen diffusion when the pore pressure is below 2 MPa and the contribution of surface diffusion increases as the pore pressure increases. The macroscopic effective permeability of the whole domain is dominated by the permeability of the connected phase; meanwhile, it can be influenced by the permeability of the disconnected phase. When the pore pressure is below 3.52 MPa, the effective permeability increases as the organic matter content (TOC) decreases. However, the effective permeability increases as the TOC increases when the pore pressure is above 3.52 MPa, which is different from traditionally believed when the relationship between the TOC and gas absorption capacity of the shale matrix is not considered. The effective permeability particularly increases at a high pore pressure as the Langmuir volume increases. In addition, the effective permeability increases as the Langmuir pressure decreases; however, this becomes apparent when the pore pressure is smaller.

Shale gas transport behavior considering dynamic changes in effective flow channels

AbstractShale gas transport is influenced by the changes in effective flow channels during production due to an effective stress sensitivity and a sorption layer effect. In this work, shale samples’ core analyses, methane adsorption experiments, and effective stress sensitivity experiments were conducted at in situ conditions. Then, a mathematical modeling was applied to quantitatively determine the real shale gas flow behavior considering the changes in effective flow channels during production. The results show that (1) the gas transport capability in matrix has an obvious tendency of increase in the mid‐late production period; (2) the decline of permeability of inorganic pores/fractures tends to be gentler during production, especially for the smaller flow channels; (3) surface diffusion is dominant in shale matrix throughout production; (4) the contribution of Knudsen diffusion to total gas flux cannot be neglected in flow channels with hydraulic radius of tens of nanometers in the early production period or of tens and hundreds of nanometers in the mid‐late production period; and (5) viscous flow generally dominates the total gas flux in flow channels with hydraulic radius more than 10 nm in the early production period or more than 100 nm in the mid‐late production period. This work is beneficial for an accurate evaluation of shale gas transport during production.

Comparative study on the Lower Silurian Longmaxi marine shale in the Jiaoshiba shale gas field and the Pengshui area in the southeast Sichuan Basin, China

The Jiaoshiba shale gas field and Pengshui area are both located in the southeast Sichuan Basin with only 100 km apart. Although these two areas obtained shale gas flow from the Lower Silurian Longmaxi marine shale, there is a huge difference of production in these two areas where the Jiaoshiba shale gas field is more productive than the Pengshui area. In order to figure out the reason that caused this difference, this study analyzed the Longmaxi marine shale in these two areas by using drilling cores, and mineralogical and geochemical data. The results show that the Jiaoshiba shale gas field has a higher quality shale reservoir (higher content of quartz, higher porosity, higher permeability and higher TOC (Total Organic Carbon)) in the Lower Silurian Longmaxi Formation than that of the Pengshui area. The Lower Silurian Longmaxi marine shale in the Jiaoshiba shale gas field contains a higher total gas content (3.65 m3/ton in average) than that of the Pengshui area (1.19 m3/ton in average). Through structure analysis, this study found that the Jiaoshiba shale gas field and the Pengshui area located in the different tectonic units. The Jiaoshiba shale gas filed is located in the East Sichuan fold belt (wide spaced anticlines area) at the west side of the Qiyue mountain fault where less fractures are developed and the pressure coefficient is more than 1.5, resulting in much more free gas preserved in the shale reservoirs in the Lower Silurian Longmaxi Formation (the ratio of free gas content and absorbed gas content is 1.6), while the Pengshui area is located in the Hunan-Hubei-Guizhou thrust belt area at the east side of the Qiyue mountain fault where much more fractures are developed and the pressure coefficient is less than 1.0, leading to less free gas preserved in the Longmaxi marine shale (the ratio of free gas content and absorbed gas content is 0.6), that is why the shale reservoir in the Pengshui area has a lower total gas content than that in the Jiaoshiba shale gas field.

Physical simulation experiment and numerical inversion of the full life cycle of shale gas well

The ultra-low porosity and permeability, as well as complex occurrence and transport state of shale reservoir make it possess special L-type production characteristic curve and complicated shale gas flow mechanism. To solve the difficulty of collecting complete production data due to short production time and operation discontinuity, a full-diameter core physical simulation experiment on the full lifecycle production process of shale gas well depletion is conducted with the purpose of obtaining many important production data including complete pressure and daily gas output in the simulated production process of shale gas well. The experimental results show the production characteristic from simulation is consistent with those from gas well. Based on the simulation data, the critical desorption pressure (12 MPa) of core, free gas production (3820.8 mL), adsorbed gas production (2151.2 mL), the proportion of the daily gas production between free and absorbed gas under different time and formation pressure, as well as the production time and final recovery rate corresponding to abandoned pressure, can be determined accurately. Numerical inversion is carried out to calculate the production performance curve of shale gas well and predict the development effect of gas well based on well testing and similarity analysis of the dimensionless time between core experiment and gas well production. Finally, the permeability and the fracturing effect (fracture network density) as the keys to the effective development of shale gas reservoirs are proposed. The permeability is the fundamental factor and the fracturing technology is the major means.

History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

A simple permeability model for shale gas and key insights on relative importance of various transport mechanisms

Gas transport mechanism in a shale nanopore is investigated by considering convective flow, gas diffusion, and surface diffusion. A common practice in modeling shale gas permeability is to use Knudsen diffusion coefficient when calculating diffusive flux, but the use of Knudsen diffusion coefficient would be incorrect if the shale gas flow regime is lying either in the transition diffusion or Fick’s diffusion, in which case the diffusion coefficient must correspond to that regime. This study proposes an apparent permeability model of shale based on a unified diffusion coefficient that transforms its value per the flow regime, including the effect of molecular diffusion, viscous flow, and surface diffusion of adsorbed gas through linear superposition. The proposed model is verified by comparing against other models for shale gas permeability. Results of sensitivity analysis indicate that permeability of gas due to diffusive transport is independent of pressure and pore size when pressure is larger than 6.895 MPa, but is dominant at lower pressures and increases with pore size. For pore diameters larger than 100 nm, the permeability due to surface diffusion is independent of pressure or pore size, indicating negligible gas transport due to surface diffusion in relatively larger pores (>100 nm) at any pressure, but it is dominant in small pore sizes when pressure is below 10 MPa. Permeability of gas (with or without surface diffusion) increases with the decrease of pressure when the pore diameters are smaller than 100 nm, whereas for pore diameters larger than 300 nm it is not affected by pressure, but increases with the increase of pore size, indicating that Darcy’s law is applicable in pores with the diameters larger than 300 nm.

Organic Matter Pore Characterization of the Wufeng-Longmaxi Shales from the Fuling Gas Field, Sichuan Basin: Evidence from Organic Matter Isolation and Low-Pressure CO2 and N2 Adsorption

Organic matter (OM) pores are significant for shale gas accumulation and flow mechanisms. The pores of Wufeng-Longmaxi (W-L) shale in the Sichuan Basin, China have been extensively characterized, however, the proportion of OM pores in this shale have not been adequately discussed. In this study, the contribution of OM pores to the total pore volume of W-L shale was quantitatively studied through the analysis of OM isolation, field emission scanning electron microscopy (FE-SEM) and low-pressure CO2 and N2 adsorption (LPGA). FE-SEM images showed abundant OM pores, interparticle pores and intraparticle pores with various shapes and widths in the W-L shales. The pore size distribution (PSD) of the isolated OM from five shale samples showed a consistent, unimodal pattern. The pore volume of isolated OM was greater than that of the bulk shale samples, suggesting that OM is more porous than the inorganic compositions in shales. The average contribution of OM to the volumes of micropores, mesopores and macropores was 58.42%, 10.34% and 10.72%, respectively. Therefore, the pore volume of the W-L shale was dominantly related to inorganic minerals. This was probably due to the small weight ratio of OM in the shale samples (1.5 wt%–4.2 wt%). The findings of this study reveal the different effects of OM and minerals on pore development, and provide new insights into the quantitative contribution of OM pores to the total pore volume of the W-L shale.

Analysis of Thermal Stimulation to Enhance Shale Gas Recovery through a Novel Conceptual Model

To investigate the effect of thermal stimulation on shale gas recovery, a novel conceptual model coupling shale gas flow and temperature is proposed. The adsorption process is nonisothermal, and adsorption capacity changes with temperature. The local thermal nonequilibrium can explicitly describe the convective heat exchange between rock and fluids. The fluid flow model takes Knudsen diffusion, slippage effect, and non-Darcy flow into account. The complex geometry of fracture network due to hydraulic fracturing can also be considered. A series of synthetic tests are designed to demonstrate the model performance. The results show that the dynamic characteristics of heat diffusion and pressure spread can be reasonably obtained. Gas recovery decreases with the increase of volumetric heat transfer coefficient, and there exists a threshold value of the effect of volumetric heat transfer coefficient on gas recovery. Gas recovery increases with the gas and rock thermal conductivity and decreases with heat capacity of rock, but the decrease level becomes insignificant when heat capacity of rock is sufficiently high. Increasing the heating temperature and decreasing the production pressure are beneficial to enhance shale gas recovery, but the rate of recovery enhancement tends to decrease for sufficiently high heating temperature.

Micro-scale investigation on coupling of gas diffusion and mechanical deformation of shale

The nanopore structure usually exhibit complex geometry in the shale formation. The interactions between gas and pore structure in such heterogeneous property impacts the properties of shale gas transport in micro-scale. The precise description of this shale gas flow processes in detail is impossible if the micropore is not properly characterized. Thus, this study provides a simulation approach to model the complex geometry of nanopore structures in the shale formation. Based on SEM image segmentation of the shale matrix, the geometry of three compositions (nanopore, kerogen, and matrix) are explicitly simulated. Mass storage, transport mechanisms, and geomechanical properties are fully modeled in the micro-scale model. It demonstrates that the conventional dual porosity model fails to capture the storage and transport mechanisms in micro-scale by comparison with the micro-scale model. The simulation results reveal that stress-induced decrease of the diffusion coefficient is both time-dependent and space-dependent. The reduction of the diffusion coefficient can significantly cut down the adsorbed gas production in kerogen. It results in the low recovery rate of shale gas that a large proportion of adsorbed gas is unable to liberate. Moreover, the later stage of gas production is depended on the supply of adsorbed gas in kerogen.

Influence of reservoir primary water on shale gas occurrence and flow capacity

In this paper, shale samples of Lower Silurian Longmaxi Fm, taken from the Changning–Weiyuan area in the Sichuan Basin, were selected to figure out the influence of reservoir primary water on the adsorption laws and the flow capacity of shale gas. Experimental samples with different water saturations were prepared using the adsorption equilibrium method. Then, high-pressure isothermal adsorption experiments were carried out, and the isothermal adsorption effects and mechanisms of shale under different water saturations were discussed. Finally, the flow capacity of shale gas under different water saturations was tested using the independently developed steady-state flow test device. And the following research results were obtained. First, the presence of primary water in micron–nanometer pores of shale reservoirs reduces the adsorption capacity of shale. When the water saturation is 40%, the simulated total gas content is 18% lower than that in the conventional calculation result. Second, the apparent shale permeability is a function of pressure. Due to the effect of Knudsen diffusion, the apparent shale permeability increases significantly with the decrease of pressure under low pressure. When the average pressure is 5 MPa and the water saturation reaches 50%, the apparent shale permeability is about 70% lower than that of a dry sample. Third, when the water saturation is lower than the critical value, water is mainly presented as non-movable water in micropores and mesopores, and it has less effect on the flow capacity of shale gas. When the water saturation is greater than the critical value, the lodging point of water is changed, resulting in significant reduction of the shale gas flow capacity. It is concluded that an accurate understanding of the original water saturation and critical water saturation of shale reservoirs helps to calculate shale gas reserves accurately and predict gas well production rate rationally.

A new analysis model for heterogeneous shale gas reservoirs

In this paper, a new analysis model (MNH), which considers the interactions of flow regimes in matrix, natural fractures and hydraulic fractures, is developed for heterogeneous shale gas reservoirs. In this model, the gas flow in shale matrix is described by non-Darcy law and gas desorption is also considered. Gas flow in discrete natural fractures follows the cubic law in each fracture and these natural fractures are described by a discrete fracture model. An equivalent method is put forward to describe the flow regime in hydraulic fractures. This model is used to analyse the flow regimes of shale gas flow within a multi-stage fractured horizontal well. It also investigates the influences of gas desorption, fracture aperture, spacing and number on the gas production rate. The results show that the MNH model can provide insights into flow mechanisms and production prediction for a multi-stage fractured horizontal well in shale gas reservoirs. [Received: November 2, 2017; Accepted: June 19, 2018]

Dissolution of marine shales and its influence on reservoir properties in the Jiaoshiba area, Sichuan Basin, China

The dissolution of marine shales and its influence on reservoir physical properties was revealed based on shale samples from the Ordovician-Silurian Wufeng and Longmaxi Formations in the southeast of the Sichuan Basin, China. Three kinds of gas storage spaces were formed by dissolution, including intergranular dissolution (InterD) pores, intragranular dissolution (IntraD) pores and dissolution microfractures (DmF). The diameters of the InterD and IntraD are 10.2–72.4 μm and 0.13–1.52 μm, respectively. The apertures of the DmF are between 0.5 and 11.2 μm. The dissolution effect resulted in a diagenetic environment for quartz cementation and a material basis for calcite veins. The main controlling factors of the dissolution effect are the mineral constituent content in the matrix, the amount of organic matter and the strata burial rate. Dissolution pores and fractures play important roles in shale gas enrichment and migration. The porosity of shale reservoirs with DmF is twice the porosity of reservoirs without DmF, and the spaces formed by dissolution pores and fractures are well connected. A new model for shale gas flow in shale reservoirs was proposed, which provides a new understanding for the connection between organic material pores, and the results can be used for shale reservoirs worldwide.

Study on the 3D fluid-solid coupling model with multi-pressure system of shale

The study of fluid solid coupling process in fractured shale reservoir, with massive hydraulic and natural fracture networks, during production is a key scientific issue for accurately understanding the production performance of multi-stage fractured wells. In view of the complicated flow mechanism of shale gas flow, multi-scale media and multiple pressure systems of organic matter/matrix pore/natural fractures and discrete artificial fractures are established to accurately describe the gas flow in shale reservoir. The mathematic model considers mechanisms of non-equilibrium desorption and surface diffusion of the adsorbed gas, the viscous flow and Knudsen diffusion of the free gas, and the influence of matrix pore, natural fracture and artificial fracture pressure system on shale deformation. A fully coupled dual effective stress fluid-solid coupling is established, which considers different pressure system respectively. The influence of rock deformation on shale gas flow in the fractured well production is analyzed. It is found that the natural fracture pressure system is the main influence factor that causes stress sensitivity during the shale gas production. The impact of solid deformation on the permeability of matrix pores continuum is smaller than that of Knudsen diffusion. The apparent permeability of matrix pores continuum is still larger than its original permeability, thus there is no stress sensitivity of matrix pore permeability. With the increase of natural fracture density, the effective stress coefficient of natural fracture pressure system increases rapidly, and the stress sensitivity effect during shale gas production process is stronger.

Temporal scale analysis of shale gas dynamic coupling flow

Shale gas is one of the world’s strategic energy reserves. The microscopic pores and the fracture structure of the shale rocks play an important role in shale gas flow. An effective reservoir simulation must account for the heterogeneity and anisotropy of the microscopic pore structure as well as the dynamics between the gas flow and the gas diffusion processes. In this study, the time lag effect, the dynamic coupling of gas flow and diffusion as well as the heterogeneity and anisotropy of the pores are taken into account in order to properly model shale gas production on a large scale. The effect of these variables on the temporal scale analysis of the wellbore gas pressure is presented, as the reliable estimate of wellbore pressure would allow better prediction of the duration of well shut-in periods. Gas production under the intermittent operation scheme at different temporal scales is discussed. The results showed that the well startup is composed of five stages, while the well shut-in is composed of only three stages. The crossflow stage is prolonged by the dynamic coupling. The heterogeneity, anisotropy and dynamic coupling phenomena are accurately presented on the temporal scale diagram. Moreover, the impact of time lag on the gas pressure is better captured by the dynamic coupling between the gas flow and the gas diffusion. The proposed model better simulates actual shale reservoirs and, hence, would be helpful in selecting suitable production rates.