Shale Gas Transport Research Articles

Three-dimensional reconstruction and connectivity analysis of REV-size organic matter in shales

Organic matter (OM) serves as a crucial site for shale gas generation and occurrence. Its content and spatial connectivity significantly influence gas flow ability and gas occurrence. However, in characterizing the three-dimensional (3D) connectivity of OM, current imaging techniques such as FIB-SEM and nano-CT cannot balance field of view (FoV) and image resolution. To address this gap, in this work, we develop a novel workflow for numerical reconstruction of REV-size digital rocks of OM that integrates high-resolution information of pore structures in large-view MAPS (modular automated processing system) images. Specifically, the open source code, SliceGAN, is used in the 3D reconstruction of digital rocks of OM, while the high-resolution information of OM pore structures is integrated into the digital rocks in terms of the classification of OM in the MAPS images. The classification of OM is solely based on the surface or 2D porosity of individual OM watersheds. As a first attempt, we propose three types of OM including Type A with high porosity (>20%), Type B with medium porosity (10%∼20%), and Type C with low porosity (<10%). Based on the case studies of three in-situ shale samples with different OM contents, we show that at the REV size the three types of OM, as a whole, can form conducting pathways throughout the domains, but each type of OM is disconnected. Type A and Type B OM have poor connectivity, while Type C OM holds the best connectivity dominating gas transport at the REV scale. Moreover, the reconstructed 3D digital rocks of OM can be used in the numerical modeling of REV-size gas transport in shales.

Experimental Investigation of the Influence of Composition Changes in Shale on Pore Structure and Fractal Characteristics under Different HCl Concentrations.

Acidification is a promising stimulation technique for improving the pore structure of low-permeability shale reservoirs and enhancing shale gas production. Variations in the mineral composition and acid concentration play a significant role in altering the pore systems in shale reservoirs, thereby affecting shale gas transport and production. To investigate the effect of shale composition on pore structure and fractal characteristics under hydrochloric acid (HCl) treatment, experiments were carried out on carbonate-rich (68%), carbonate-medium (45%), and carbonate-poor (2%) shales with different concentrations of HCl solution (1, 5, 10 wt %). X-ray diffraction (XRD), low-temperature nitrogen adsorption, and fractal theory were performed to investigate variations in mineral composition, pore structure, and fractal characteristics of the unreacted and reacted shales. The results illustrated that the HCl treatment significantly reduced the content of carbonate minerals, and the dissolution degree of carbonate minerals increased with the increase in HCl concentration. More meso- and macropores were generated for carbonate-rich and carbonate-medium shale, while more micro- and mesopores were generated in carbonate-poor shale, which led to the increase in total pore volume (TPV) and total specific surface area (TSSA) at different degrees. Moreover, the pore surface roughness (D 1) and structure complexity (D 2) were reduced with the increase of HCl concentration for carbonate-rich shale, while the alteration of D 1 and D 2 showed an opposite trend for carbonate-poor shale. Additionally, D 1 decreased and D 2 increased for carbonate-medium shale. Relevant results could provide theoretical references for the acid fracturing of shale reservoirs with varying mineral compositions.

The greenhouse gas footprint of liquefied natural gas (LNG) exported from the United States

AbstractLiquefied natural gas (LNG) exports from the United States have risen dramatically since the LNG‐export ban was lifted in 2016, and the United States is now the world's largest exporter. This LNG is produced largely from shale gas. Production of shale gas, as well as liquefaction to make LNG and LNG transport by tanker, is energy‐intensive, which contributes significantly to the LNG greenhouse gas footprint. The production and transport of shale gas emits a substantial amount of methane as well, and liquefaction and tanker transport of LNG can further increase methane emissions. Consequently, carbon dioxide (CO2) from end‐use combustion of LNG contributes only 34% of the total LNG greenhouse gas footprint, when CO2 and methane are compared over 20 years global warming potential (GWP20) following emission. Upstream and midstream methane emissions are the largest contributors to the LNG footprint (38% of total LNG emissions, based on GWP20). Adding CO2 emissions from the energy used to produce LNG, total upstream and midstream emissions make up on average 47% of the total greenhouse gas footprint of LNG. Other significant emissions are the liquefaction process (8.8% of the total, on average, using GWP20) and tanker transport (5.5% of the total, on average, using GWP20). Emissions from tankers vary from 3.9% to 8.1% depending upon the type of tanker. Surprisingly, the most modern tankers propelled by two‐ and four‐stroke engines have higher total greenhouse gas emissions than steam‐powered tankers, despite their greater fuel efficiency and lower CO2 emissions, due to methane slippage in their exhaust. Overall, the greenhouse gas footprint for LNG as a fuel source is 33% greater than that for coal when analyzed using GWP20 (160 g CO2‐equivalent/MJ vs. 120 g CO2‐equivalent/MJ). Even considered on the time frame of 100 years after emission (GWP100), which severely understates the climatic damage of methane, the LNG footprint equals or exceeds that of coal.

Occurrence of methane in organic pores with surrounding free water: A molecular simulation study

Free water contained in shale reservoirs can influence the enrichment and transportation of shale gas. To accurately assess shale gas adsorption in shale reservoirs and improve recovery, it is crucial to understand the occurrence of gas and water. In this study, the occurrence of methane occupying the organic pores surrounded by free water is investigated using Grand Canonical Monte Carlo/Molecular Dynamics simulations, considering the effects of pressure, temperature and pore size. The center of the model represents methane adsorbed/free within the organic pores, while the regions on either side depict free water. Although water does not significantly penetrate organic pores, pressure, temperature, and pore size have a notable impact on the wettability of water on organic surfaces, resulting in variations in the concave liquid surface morphology. This results in varying degrees of competitive adsorption of water and methane near the carbonyl group. At lower pressures, although the capillary pressure decreases sharply with increasing pore size, the improved water wettability increases the extent of its intrusion along the pore surface, thereby enhancing the competitive adsorption of methane and water. At higher pressures, capillary pressure acts as a resistance, preventing water from invading the organic pores in significant quantities. Due to the weak affinity of organic pores for water, the same phenomenon was observed even after increasing the pore size and temperature to improve water wettability. In addition, high temperatures can lead to more pronounced water intrusion. Finally, it is hypothesized that competitive adsorption of methane and water is more pronounced at shallower burial depths and slightly larger pore sizes. This result is expected to provide insights for the accurate evaluation of gas adsorption in water-bearing shales.

Development of coupled fluid-flow/geomechanics model considering storage and transport mechanism in shale gas reservoirs with complex fracture morphology

Field observations frequently demonstrate stress fluctuations resulting from the reservoir depletion. The development of reservoirs, particularly the completion of infill wells and refracturing, can be significantly impacted by stress changes in and around drainage areas. Previous studies mainly focus on plane fractures and few studies consider the influence of complex transport and storage mechanism and irregular fracture geometry on stress evolution in shale gas reservoirs. Based on the embedded discrete fracture model (EDFM) and finite-volume method (FVM), a coupled geomechanics/fluid model has been successfully developed considering the adsorption, desorption, diffusion and slippage of shale gas. This model achieves coupling simulation of natural fractures, hydraulic fractures with complex geometry, storage and transport mechanism, reservoir stress, and pore-elastic effect. The open-source software OpenFOAM is used as the main solver for this model. The stress calculation and productivity simulation of the model are verified by the classical poroelasticity problem and the simulation results of published research and commercial simulator with EDFM respectively. The simulation results indicate that σxx, σyy, σxy and Δσ changes with time and space due to the time effect and anisotropy of formation pressure depletion; Due to the influence of different mechanisms on shale gas storage and transport, the reservoir pressure and stress distribution under different mechanisms are different; Among them, the stress with full mechanisms differs the most compared to the stress without any mechanism. The reservoir with stronger stress sensitivity (smaller Biot coefficient) is less sensitive to formation pressure depletion, and the stress variation range is smaller. For reservoirs with weak stress sensitivity, formation pressure depletion is more likely to lead to stress reversal. Under the influence of fracture geometry, the pressure depletion regions caused by the three types of fracture geometry are approximately rectangular, parallelogram and square, respectively. The corresponding σxx, σyy and Δσ also have great differences in spatial distribution and values. Therefore, the time effect, shale gas storage and transport mechanism and the influence of complex fracture geometry should be considered when predicting pressure depletion induced stress under the condition of simultaneous production. This study is of great significance for understanding the evolution law of stress induced by pressure consumption, as well as the design of infill wells and repeated fracturing.

The role of water bridge on gas adsorption and transportation mechanisms in organic shale

This work introduces and discusses the impacts of the water bridge on gas adsorption and diffusion behaviors in a shale gas-bearing formation. The density distribution of the water bridge has been analyzed in micropores and meso-slit by molecular dynamics. Na+ and Cl− have been introduced into the system to mimic a practical encroachment environment and compared with pure water to probe the deviation in water bridge distribution. Additionally, practical subsurface scenarios, including pressure and temperature, are examined to reveal the effects on gas adsorption and diffusion properties, determining the shale gas transportation in realistic shale formation. The outcomes suggest carbon dioxide (CO2) usually has higher adsorption than methane (CH4) with a water bridge. Increasing temperature hinders gas adsorption, density distribution decreases in all directions. Increasing pressure facilitates gas adsorption, particularly as a bulk phase in the meso-slit, whereas it restricts gas diffusion by enhancing the interaction strength between gas and shale. Furthermore, ions make the water bridge distributes more unity and shifts to the slit center, impeding gas adsorption onto shale while encouraging gas diffusion. This study provides updated guidelines for gas adsorption and transportation characteristics and supports the fundamental understanding of industrial shale gas exploration and transportation.

Novel methodology to couple decline curve analysis with CFD reservoir simulations for complex shale gas reservoirs

AbstractShale reservoirs are highly complex and are difficult to study using conventional reservoir simulation tools. This study introduces a novel methodology for estimating production from complex shale gas reservoirs by coupling decline curve analysis (DCA) with computational fluid dynamics (CFD) simulations. The proposed method uses exponential DCA to analyze production data from a dual porosity–permeability shale gas transport model. These complexities include fracture characteristics, geomechanical properties, nanopore confinement effects, and multiple flow mechanisms contributing to the total production performance. The shale gas transport model is validated through historical production data from Marcellus shale. The new methodology also tests fracture characteristics. It shows that increased porosity and permeability will increase the recoverable reserves but will have varying effects on the decline rate. The paper demonstrates the advantages of the proposed methodology over conventional reservoir simulation tools. It provides insights into the factors affecting shale gas production performance through the inclusion of the complexities of an unconventional shale gas reservoir. The paper provides a proof of concept on the particular reservoir of which the field data is provided—Barnett and Marcellus Shale.

Fast Detection of the Single Point Leakage in Branched Shale Gas Gathering and Transportation Pipeline Network with Condensate Water

The node pressure and flow rate along the shale gas flow process are analyzed according to the characteristics of the shale gas flow pipe network, and the non-leaking and leaking processes of the shale gas flow pipe network are modeled separately. The changes in pressure over time along each pipe segment in the network provide new ideas for identifying leaking pipe sections. This paper uses the logarithmic value of pressure as the basis for judging whether the flow pipe network is leaking or not, according to the process of varying flow parameters resulting in the regularity of leakage. A graph of the change in pressure of the pipe section after the leak compared to the pressure of the non-leaking section of pipe over time can be plotted, accurately identifying the specific section of pipe with the leak. The accuracy of this novel method is verified by the leakage section and statistical data of the shale gas pipeline network in situ used in this paper.

Effect of water film evaporation on the shale gas transmission in inorganic nanopores under viscosity.

Shale gas reservoirs generally have ultra-low water saturation, and the water in reservoirs is closely bound to the walls of inorganic nanopores, forming a water film structure on the hydrophilic surface. When shale gas enters the inorganic nanopores, the water films in the inorganic pores will be removed by evaporation instead of being driven away by the gas, which increases the difficulty of predicting production during shale gas extraction. Based on molecular dynamics simulations, a water film evaporation model is proposed, considering the evaporation of water films during shale gas transport and the influence of water film evaporation on the shale gas transport mechanism. The Green-Kubo method is employed to calculate the viscosity of the water film. The evaporation flux of the water film under the influence of viscosity is discussed in the evaporation model. The transport mechanisms of shale gas in nanopores and the effect of water film evaporation on shale gas transport mechanisms are analyzed in detail. The result indicates that the water films in the inorganic nanopores are constrained on the hydrophilic surface, and the viscosity normal to the surface of the water film of 4Å is 0.005 26 Pa⋅S, which is 6.12 times the reference value of viscosity at 298K. In the process of water film evaporation, the evaporation flux of the water film is influenced by viscosity. In the study of the shale gas transport mechanism, water films in inorganic nanopores can hinder the surface diffusion of the methane molecules adsorbed on boundary and significantly reduce the mass flux of shale gas.

On the transport behavior of shale gas in nanochannels with fractal roughness

As an efficient and environmentally friendly source of energy, shale gas is abundantly available and continues to contribute to the economy growth because of its huge potential for production. However, accurately predicting the transport behavior of shale gas is still challenging due to the small scale and complexity of nanochannels, which impedes the efficiency of recovery. In this paper, the transport behavior of shale gas in nanochannels with fractal roughness is studied by molecular dynamics simulation and theoretical analysis. It is found that the present work functions well to predict the transport behavior of shale gas in nanochannels with roughness. The introduction of fractal roughness hinders the transport of shale gas and leads to a complex trajectory of methane molecules in nanochannels. Furthermore, it is interesting to find the average gas viscosity increases, while the gas flux decreases with the increase in the inclined angle due to the impediment effect after the deflection. These results are helpful for understanding the migration of shale gas in nanochannels with roughness and guiding the improvement of shale gas recovery in practical applications.

The erosion rate prediction for the elbow in shale gas gathering and transportation system: RSM and GA-BP-ANN modeling

Elbow erosion caused by sand mixed in shale gas is a significant issue faced by shale gas gathering and transportation systems, posing a serious threat to the safe and stable production of shale gas. In this paper, the factors affecting elbow erosion in the shale gas gathering and transportation system are identified. The computational fluid dynamics (CFD) two-way coupling Euler-Lagrange method is used to investigate the single-action of various parameters on particle trajectory, erosion morphology, and maximum erosion rate, including pipe inner diameter, pipe R/D ratio, pipe bending angle, pipe bending orientation, solid particle velocity, solid particle size, and solid particle mass flow rate. Subsequently, the response surface methodology (RSM) is employed to quantitatively explore the synergistic interactions between these factors that affect the maximum erosion rate of the elbow, and a surrogate model for simple and rapid evaluation of the maximum erosion rate for elbows at the engineering level is proposed. Finally, the backpropagation artificial neural network (BP-ANN) optimized by genetic algorithm (GA) is used to train the samples obtained by Latin hypercube sampling (LHS) in the multi-factor range. By comparison, the RSM surrogate model and the GA-BP-ANN model reveal a favorable level of agreement with the experimental data, while considering various influential factors. It is important to note that each method possesses distinct advantages, limitations, and specific application environments. This research can provide quantitative references for preventing and controlling erosion within the shale gas gathering and transportation system.

A novel apparent permeability model for shale considering the influence of multiple transport mechanisms

Changes in pore pressure during the extraction of shale gas lead to dynamic alterations in the pore structure and permeability, making it challenging to gain a comprehensive understanding of the flow behaviors of shale gas. The pore structure of shale is complex, with a variety of storage modes and gas transport processes constrained by a number of factors. For instance, when gas flows through a transport channel with a finite length, it is imperative to take into account the flow loss caused by the bending of inlet and outlet streamlines, prior models typically neglect the impact of end effects, resulting in an exaggerated estimation of the shale permeability. Furthermore, a decrease in pore pressure corresponds to an increase in the Knudsen number, resulting in the breakdown of the continuity assumption of the Navier–Stokes equation, this signifies the gradual shift of the transport regimes from continuum flow to other transport regimes. The gas flow process is nonlinear due to the alternating impact of multicomponent transport mechanisms and various microscale effects. In this paper, we presented a novel apparent permeability model for shale that incorporates the impact of real gas effect, end effects, transport regimes, adsorption, and effective stress. First, we assumed the channel for shale gas transport to be circular pore and calculated the viscosity under the influence of a real gas effect as well as the corresponding Knudsen number. Subsequently, building upon the foundation of the slip model, we introduce the influence of the end effects to establish a bulk phase permeability for shale, further considering the impact of surface diffusion. Then, the pore radius was quantified under the influences of adsorption and effective stress. Using the intrinsic correlation between permeability and pore radius as a bridge, a shale apparent permeability model was further derived. The model encompasses various transport regimes and microscale effects, replicating the gas flow behaviors in shale. The new model was verified through comparison with published experimental data and other theoretical models, while analyzing the evolution of apparent permeability. Additionally, this paper discusses the influence of various factors, including end effects, pore radius, internal swelling coefficient, sorption-induced strain, and model-related parameters on the shale apparent permeability.

Effects of π-π Stacking on Shale Gas Adsorption and Transport in Nanopores.

The π-π interaction is a prevalent driving force in the formation of various organic porous media, including the shale matrix. The configuration of π-π stacking in the shale matrix significantly influences the properties of shale gas and plays a crucial role in understanding and exploiting gas resources. In this research, we investigate the impact of different π-π stacking configurations on the adsorption and transport of shale gas within the nanopores of the shale matrix. To achieve this, we construct kerogen nanopores using π-π stacked columns with varying stacking configurations, such as offset/parallel stacking types and different orientations of the stacked columns. Through molecular dynamics simulations, we examined the adsorption and transport of methane within these nanopores. Our findings reveal that methane exhibits stronger adsorption in smoother nanopores, with this adsorption remaining unaffected by the nanoflow. We observe a heterogeneous distribution of the 2D adsorption free energy, which correlates with the specific π-π stacking configurations. Additionally, we introduce the concept of "directional roughness" to describe the surface characteristics, finding that the nanoflow flux increases as the roughness decreases. This research contributes to the understanding of shale gas behavior in the shale matrix and provides insights into nanoflow properties in other porous materials containing π-π stackings.

Occurrence state and nuclear magnetic resonance relaxation characteristics of confined water in quartz nanopores

Water in the shale obstructs the enrichment and transportation of shale gas, so it is crucial to identify the occurrence mechanism of water in shale. In this work, molecular dynamics (MD) simulation had been performed to explore the occurrence state, dynamic characteristics, and nuclear magnetic resonance (NMR) relaxation properties of confined water in shale inorganic nanopores (quartz). The results show that the number of adsorbed layers, diffusion coefficients (D) and rotational correlation time (τ c) of water in quartz pores are strongly influenced by pore width (H). Layer analysis of water held in confinement indicates that the D value increases and the τc value decreases as the water approaches the centre of the pore. Furthermore, varying occurrence states lead to different NMR relaxation mechanisms. With the increase of H, the transverse relaxation time of adsorbed water is basically stable at 10−1 s. Finally, an exponential formula for evaluating pore size distribution is established. The total thickness of the water layer with the ratio of the intramolecular relaxation rate to the total relaxation rate less than 40% is defined as the thickness of the adsorbed water film.

Pore Pressure Diffusion Waves Transmission in Oil Reservoir

Recent studies on seismic wave excitation have revealed that mesoscopic wave-induced fluid flow (WIFF) is a process that attenuates the compressional (P) waves in reservoir rocks at seismic frequency bands. Fluid flow and Biot's slow diffusion (pressure) waves are produced when the P-waves create fluid-pressure gradients at mesoscopic-scale heterogeneities. Pore pressure continuity can be sustained by converting seismic energy into diffusion waves that diffuse away from the interfaces or boundaries. Biot’s diffusion waves fail to comply with a square-law approach because of their slow propagation velocity and higher attenuation. It is currently uncertain how to characterize reservoir fluids in mature oil reservoirs during seismic wave-based enhanced oil recovery (EOR). A simplified 1D two-layer reservoir model was investigated in this study. The findings demonstrate that diffusion wave propagation in oil reservoirs is frequency-dependent and affected by rock permeability and fluid viscosity. At a formation layer interface, it was discovered that diffusion waves obeyed the accumulation-depletion relationship rather than the reflection-refraction approach. Therefore, pore pressure diffusion waves can characterize reservoir fluid during seismic EOR and monitor the CO2 front in depleted reservoirs during storage for CCUS projects. It can also detect shale gas transport in low permeability layers and identify the propagation of fractures during gas/oil recovery.

A Multi-Period Model of Compressor Scheme Optimization for the Shale Gas Gathering and Transportation System

In the process of shale gas production, with the change in gas productive parameters, the pressurization demand for the shale gas gathering and transportation system (SGGTS) also changes, which affects the choice of pressurizing location and timing. Our purpose is to effectively respond to the impact of parameter changes during shale gas production and to better select the pressurization schemes. Therefore, we considered the modularization of the compressors and established a mixed-integer nonlinear programming (MINLP) model to minimize the total cost of the SGGTS. Taking an actual shale gas field as an example, by discretizing the time during a given production period to solve the model under multi-period and single-period conditions, the optimal pressurization scheme for the SGGTS in the specified production period is obtained. It indicates that the results obtained under a multi-period condition are more conducive to actual production. Compared with the results obtained under the single-period condition, the cumulative cost obtained in the multi-period condition is reduced by 17.19%. By deploying the MINLP model in the specified production period, the pressurization demand is met in each time period. This greatly improves the utilization rate of modular compressors, reduces the total cost, and improves the economic benefits of the SGGTS.

Nano-Scale Pore Structure Characterization and Its Controlling Factors in Wufeng and Longmaxi Shale in the Zigong Area, Southwest Sichuan Basin

The nano-scale pore systems in shale reservoirs control shale gas transportation and aggregation, which is of great significance for the resource evaluation of shale oil and gas and the selection of a “sweet spot”. Taking twelve marine shale samples from the Wufeng–Longmaxi Formation in the Zigong area, southwest Sichuan Basin, as the research target, we carried out a series of experiments, including total organic carbon (TOC) analysis, X-ray diffraction (XRD), gas adsorption (CO2 + N2), and mercury intrusion porosimetry (MIP), to study the full-scale pore structure characterization and controlling factors of pore volume and specific surface area. The results presented the following findings. (1) Marine shale samples from the target area are rich in organic matter, with an average TOC value of 3.86%; additionally, the mineral composition was dominated by quartz and clay minerals, with average contents of 44.1% and 31.4%, respectively. (2) The full-scale pore size distribution curves of pore volume developed multimodally, with the main peaks at 0.5 nm–2 nm, 3 nm–6 nm, and 700 nm–2.2 um; moreover, the full-scale pore size distribution curves of a specific surface area developed unimodally, with the main peak ranging from 0.5 nm to 1.2 nm. (3) Pore volume was mainly contributed by mesopores and macropores, with an average contribution of 46.66% and 42.42%, respectively, while the contribution of micropores was only 10.91%. The specific surface area was mainly contributed by micropores and mesopores, with an average contribution of 64.63% and 29.22%, respectively, whereas the contribution of micropores was only 6.15%. (4) The TOC content mainly controlled the pore volume and specific surface area of micropores and mesopores, while the clay and feldspar content generally controlled the pore volume and specific surface area of macropores. Additionally, the quartz content had an inhibitory effect on the development of all pore types. These results will help researchers understand the laws of gas accumulation and migration.

Research on Erosion Characteristics of the Sleeve-Type Blowdown Valve in the Shale Gas Gathering and Transportation Station

Summary In the shale gas separation and sewage system, the separator removes the sand and sewage in the produced gas and releases the sand-carrying sewage to the blowdown pipeline. As an important throttling component in this system, the sleeve-type blowdown valve is severely eroded during operation. To address the problem, this paper carries out numerical research on the erosion characteristics during the real opening and closing process of the sleeve-type blowdown valve based on the FLUENT fluid simulation software. The change of the erosion at different velocities, sand mass flow, sand size, and shape coefficient is analyzed, and the main factor affecting the erosion characteristics is evaluated. Based on the above research, a novel blowdown valve is proposed, and the erosion characteristics and flow performance before and after improvement are compared. The results show that when the velocity is 8 m/s, the maximum erosion rate after improvement is 4.79×10−5 kg/(m2·s). Compared with the maximum erosion rate before improvement of 1.22×10−2 kg/(m2·s), the erosion inhibition rate reaches 99.6%. Moreover, the pressure loss is obviously reduced after the improvement, and the flow capacity is enhanced. This provides useful guidance for the improvement of blowdown valves and ensures the safe operation of shale gas production.

A Review of Macroscopic Modeling for Shale Gas Production: Gas Flow Mechanisms, Multiscale Transport, and Solution Techniques

The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing.

Corrosion Mechanism of Typical Shale Gas Gathering and Transportation Pipelines in Southwest China

The shale gas surface gathering and transportation pipeline in southwest China has experienced serious internal corrosion, which affects the production of shale gas wells and has great potential safety hazards. To find out the corrosion type and corrosion mechanism, the corrosion analysis and mechanism research of gathering and transportation pipelines are carried out, including corrosion morphology observation, corrosion product analysis, fluid mechanics calculation, etc. The results show that the corrosion products of the gathering and transportation pipeline are mainly FeCO3 with high S content, and the corrosion type is sulfate-reducing bacteria (SRB) and CO2 corrosion. At the same time, the corrosion pits are mainly distributed on the approach stream side, which is closely related to the scouring effect of the medium flow in the vertical branch pipe on the wall surface of the tee. The corrosion weight loss test shows that the corrosion rate of sterile solution is significantly lower than that of bacterium solution, indicating that the presence of SRB significantly expedites the corrosion of materials.