Deep Shale Research Articles

A model characterising the fractal supercritical adsorption behaviour of methane in shale: Incorporating principles, methods, and applications

The pore structure of shale is patently heterogeneous, with a conventional adsorption model being difficult to characterise the complex adsorption behavior of methane in shale. Therefore, a model is being proposed to characterise the fractal supercritical adsorption behavior of methane in shale. The principles and derivation of the model have been described in detail. The results showed that the adsorption characteristic parameters relating to different scale pores were affected by temperature and fractal dimension to different degrees. In addition, the relationship between isosteric heat of adsorption (qst) and adsorption capacity of different samples revealed different trends. The absolute values of ΔS of FC-66 and FC-72 decreased linearly. This might have been because of the fact that the adsorption saturation’s inflection point, which caused a fall in the absolute value of the entropy change (ΔS), was not reached. Compared with traditional adsorption models, the proposed model could reflect menthane’s adsorption in shale more accurately. The research results provide theoretical support for the evaluation of deep shale gas reserves, including the optimisation of exploitation strategies.

Mechanisms of Reservoir Space Preservation in Ultra-Deep Shales: Insights from the Ordovician–Silurian Wufeng–Longmaxi Formation, Eastern Sichuan Basin

This study aims to explore the reservoir characteristics and formation mechanisms of ultra-deep shale gas in the Ordovician–Silurian Wufeng–Longmaxi Formation in the Sichuan Basin in order to provide theoretical support and practical guidance for the exploration and development of ultra-deep shale gas. With recent breakthroughs in ultra-deep shale gas exploration, understanding its organic matter development, mineral composition, and reservoir space characteristics has become particularly important. The background of this research lies in the significant potential of ultra-deep shale gas, which remains inadequately understood, necessitating an in-depth analysis of its pore structure and reservoir quality. Through a systematic study of the ultra-deep shale in well FS1 of Sichuan Basin, that the following was found: (i) The ultra-deep shale in the Wufeng–Longmaxi Formation is mainly composed of quartz and clay minerals, exhibiting high total organic carbon (TOC) and high porosity characteristics, indicating it is in an overmature thermal evolution stage. (ii) Organic pores and microcracks in the ultra-deep shale are more developed compared to middle-shallow and deep shale, forming a complex pore structure that is conducive to gas storage. (iii) In the diagenesis process, the dissolution and recrystallization of the biogenic skeleton promote the cementation between autogenetic quartz particles, forming a rigid skeleton that effectively inhibits the impact of mechanical compaction. (iv) The overpressure environment created by the hydrocarbon generation process, along with gas production from hydrocarbon cracking, can effectively offset the mechanical compaction of overburden pressure on micropores, and this overpressure environment also promotes the further development of microfractures, which is beneficial for the development and preservation of ultra-deep shale pores. In summary, this study not only reveals the reservoir characteristics and formation mechanisms of ultra-deep shale but also provides essential references for the exploration and development of ultra-deep shale gas in the Sichuan Basin and similar regions, emphasizing the ongoing significance of research in this field.

Pore-Scale Simulation of Deep Shale Gas Flow Considering the Dual-Site Langmuir Adsorption Model Based on the Pore Network Model.

As a key resource in the oil and gas sector, shale gas development profoundly influences the advancement of the global energy industry. Deep shale gas reservoirs, typically found at depths exceeding 3500 m, represent a significant portion of total shale gas reserves. Currently, pore network models primarily simulate middle and shallow shale gas, insufficiently addressing the unique challenges posed by high-temperature and high-pressure conditions in deep shale gas formations. There is an urgent need to explore the microscale flow dynamics of deep shale gas. In this work, we use the pore network model to simulate the flow dynamics of deep shale gas, particularly under nanoconfinement conditions. The simulation integrates adsorption, slip flow, Knudsen diffusion, and bulk flow phenomena. Utilizing the dual-site Langmuir adsorption model tailored for high-temperature and high-pressure conditions enhances the accuracy of gas conductivity calculations for the adsorbed phase, thereby reflecting the specific characteristics of deep shale gas reservoirs. Moreover, this research investigates the flow characteristics of deep shale gas under varying sensitivity parameters, such as water saturation, temperature, and pressure. It explores methane flow dynamics, focusing on effective diffusion coefficients and permeability. The modified approach to calculating adsorption phase conductivity using the dual-site Langmuir adsorption model accurately captures the adsorption behaviors and characteristics of deep shale gas reservoirs.

Imbibition mechanism of water in illite nanopores of deep shales by molecular simulation

Hydraulic fracturing is an important technique to develop deep shale gas. After hydraulic fracturing, a large amount of fracturing fluid fails to flow back and retains in deep shales. This phenomenon leads to fracturing fluid imbibition and significantly impacts on gas production. However, the understanding of imbibition mechanism in deep shales is very limited. In this work, the microscopic mechanism of fracturing fluid imbibition into illite pores of deep shales was studied using molecular simulation. The factors affecting imbibition were also analyzed. Results show that water imbibition in illite pores can be divided into three stages. In stage 1, the hydrogen bonds between water molecules and illite pore walls are formed, which forces water to enter the pores and becomes a water layer. In stage 2, the hydrogen bonds between water molecules and the water layer are formed, and gas begins to be displaced out of the pores by water. In stage 3, water molecules no longer enter the pores, and the system becomes equilibrium. As for the influencing factors, fugacity pressure mainly affects the imbibition time. The imbibition time becomes longer when fugacity pressure rises. Pore size plays a significant role in imbibition. Gas in illite pores can be totally displaced if the pore size is smaller than 5 nm. The imbibition is also affected by the amount of water. More gas tends to be displaced out of the pores when the ratio of water volume to pore volume (RWP) increases.

The law of fracture propagation and intersection in zipper fracturing of deep shale gas wells

In response to the unclear understanding of fracture propagation and intersection interference in zipper fracturing under the factory development model of deep shale gas wells, a coupled hydro-mechanical model for zipper fracturing considering the influence of natural fracture zones was established based on the finite element – discrete element method. The reliability of the model was verified using experimental data and field monitoring pressure increase data. Taking the deep shale gas reservoir in southern Sichuan as an example, the propagation and interference laws of fracturing fractures under the influence of natural fracture zones with different characteristics were studied. The results show that the large approaching angle fracture zone has a blocking effect on the forward propagation of fracturing fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures exhibit continued expansion behavior under net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the response well pressure increase and the total length of the fractured fracture show a trend of first decreasing and then increasing, and first increasing and then decreasing, respectively. Compared to small approach angle fracture zones, natural fracture zones with large approach angles require longer time and have greater difficulty to intersect. The width of fractures and the length of natural fractures are negatively and positively correlated with the response well pressure increase, respectively, and positively and negatively correlated with the time required for intersection, the total length of hydraulic fractures, and fracturing efficiency, respectively. As the displacement distance of the well increases, the probability of fracture intersection decreases, but the regularity between displacement distance and the response well pressure increase and the total length of fractures is not obvious.

Application of distributed acoustic sensing technology in deep shale gas exploration

Abstract In the past decade, the exploration and development of deep shale gas usually adopted geophone acquisition for vertical seismic profile (VSP) to improve the accuracy and resolution of seismic data. However, it’s very hard to use the 10-20m level spacing geophones to meet the resolution of 2-5m thin reservoir. Distributed acoustic sensing (DAS) technology has been widely used in the oil and gas field due to its advantages of high density and high efficiency acquisition, especially in vertical seismic profile and dynamic monitoring. We have acquired zero offset VSP by DAS and geophone for the first time in deep shale gas wells at home, and successfully overcome the coupling problem in open-hole sections. Vibrators are used as sources for multiple stacking to improve the signal-to-noise ratio (SNR) of DAS VSP. The records show DAS has significant advantages in frequency, SNR and wavelet consistency. After data processing, the layer velocity characteristics of DAS VSP are more obvious. DAS VSP corridor stack has a high degree of consistency with the synthetic record and seismic profile, and the resolution of the reservoir was higher than geophone.

New model to evaluate the impact of quartz sand crushing on fracture conductivity in a proppant monolayer

The formation of a complex fracture network with sufficient proppant conductivity is crucial for the efficient development of deep shale gas. Due to cost considerations, quartz sand has commonly replaced ceramic proppant in the field. However, the significant crushing of quartz sand and its distribution as multiple particle sizes both before and after crushing, termed as particle size redistribution, raises concerns about its ability to meet the demands of the fracture network. Based on contact mechanics, we developed an evolutionary equation for fracture width that considers particle size redistribution. The particle crushing is described using a fragmentation replacement method, and changes in specific surface area before and after crushing are used to correct the permeability model of the fracture. By integrating models of fracture width and permeability evolution, we have established an analytical model for proppant conductivity that accounts for quartz sand crushing and its particle size redistribution. Numerical simulations further validate the predictive accuracy of our model. Sensitivity analyses investigate the impact of quartz sand degree of crushing, compressive strength, particle size, particle combination ratio, and closure pressure on fracture conductivity, demonstrating the reliability of quartz sand as a substitute for ceramic proppant in deep shale applications.

Study on the corrosion and damage behaviours of P110 tubing of deep shale gas wells

This study conducts weight loss corrosion experiments by a high-temperature autoclave to investigate the corrosion behaviours and the damage rules of mechanical properties of P110 tubing under coupling working conditions of multiple factors (temperature 50–155 °C, CO2 content 1%–2%, Cl− content 10,000–20,000 mg/L). It analyses the characteristics of corrosion products of P110 steel using X-ray diffraction, scanning electron microscopy, and energy dispersive spectroscopy (EDS). In addition, the 3D morphology and size of local corrosion pits are measured microscopically. The mechanical properties’ damage behaviours at different tubing positions are analysed by constant-load tensile stress corrosion tests. The results showed that the average corrosion rate of the tubing reaches the maximum value of 1.627 mm/a at the middle section of the shale gas well. With an increase in temperature and CO2 partial pressure, the depth of the local corrosion pits on the tubing rises from 3.8 to 25.0 μm. The yield strength and tensile strength of the tubing at the bottom-hole section reduced by less than 8%, and the coupling damage effect of stress and corrosive mediums is serious. The tubing shows a sensitivity to stress corrosion cracking at the bottom-hole section. It was recommended that corrosion inhibitors should be cyclically added to inhibit CO2 corrosion to control the corrosion rate of the tubing within the range of medium-degree corrosion, thus ensuring that the strength reduction of P110 tubing under the corrosion working conditions containing CO2 and sulphate-reducing bacteria coupled with tensile stress is within the controllable range of safety factor.

Insight into the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling

During deep shale gas production, flowing water-based working fluid inevitably cools shale reservoirs around boreholes and some fractures, and possible extraction methods induce dynamic stresses. To understand the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling, a split Hopkinson pressure bar was used for performing the dynamic Brazilian tests on shale samples with bedding angles of 0°, 30°, 45°, 60° and 90° after reservoir temperature realization (25–200 °C) and water cooling. The results illustrate that dynamic tensile strength of shale samples decreases gradually as reservoir temperature increases under the loading rates 100–1000 GPa/s. From room temperature to 200 °C the most strength deterioration appears on samples with the bedding angle of 90°. A dynamic tensile strength deterioration model for deep shale reservoirs after water-based working fluid cooling is proposed considering the influence of loading rate and bedding angle. Geometrical trajectories of the main failure cracks are separated into three types, i.e., fully central tensile failure, tensile-shear failure and fully shear failure (sliding of bedding planes). For samples with bedding angles of 30°, 45° and 60°, increasing reservoir temperature encourages tensile failure to change into shear failure. The roles that bedding planes play in interacting with failure crack growth are summarized as IP mode (intersecting propagation), TP mode (turning propagation) and PP mode (promoting propagation). Anisotropic dynamic tensile strength responses are systematically discussed by using thermal stress simulation in ABAQUS, microstructure analyses, crack interaction conditions and the one-dimensional stress wave propagation theory. Based on experimental observations, field implications in borehole stability and fracturing of deep shale reservoirs are proposed under medium and high loading rates. This work is instrumental in providing valuable information and technology assistance for real deep shale gas production projects.

Research on resin modified gelatin as environmental-friendly high temperature resistant wellbore stabilizer

In the development of deep shale oil and gas, the working temperature of the water-based drilling fluids is relatively high, which can cause wellbore instability due to the poor temperature resistance of the traditional environmental-friendly additives. To address this issue, this study presents a wellbore stabilizer called PMG, prepared by modifying gelatin (GT) with a resin synthesized by polyvinyl alcohol (PVA) and methacrylic acid (MA) through hydrothermal free radical polymerization, and it can withstand temperature up to 200 °C. The synthesis and thermal stability of PMG were confirmed by Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). The wellbore stability performance of PMG was evaluated by linear swelling test, rolling recovery test, core immersion experiment and point load test and the wellbore stability mechanism was also investigated. The results reveal that the swelling height of sodium-based bentonite (Na-BT) in 2.0 % PMG solution at 150 °C is only 0.97 mm; the hot-rolling recovery rate in 2.0 % PMG solution at 200 °C is 72 %; the artificial core still maintains its original appearance after being immersed in 2.0 % PMG solution at 200 °C for 16 h, and the compressive strength increases by 12 %, effectively strengthening the wellbore. In addition, the EC50 value of PMG is > 106 mg/L, and the BOD5/CODcr value is 31 %, indicating that it is non-toxic and biodegradable. PMG has excellent wellbore stability performance, in addition to being able to adsorb on the surface of Na-BT by electrostatic action and hydrogen bonding, the PMG micelles that precipitated from the aqueous solution due to the breaking of hydrogen bonds in the molecular chain at high temperature also form a film on the clay surface, aggregating and cementing the clay particles together, further enhancing the wellbore stability.

Influence of the sedimentary environment of the Wufeng-Longmaxi shale on organic matter accumulation in the Dingshan area, Sichuan Basin

The sedimentary environment and organic matter (OM) accumulation are vital indicators for shale gas exploration. However, research on deep shale gas systems is relatively limited; moreover, the exploration of deep shale gas in the southeastern Sichuan Basin has entered a period of stagnation. In this study, systematic geochemical analysis of Wufeng (WF) and the first member of the Longmaxi (Long-1) deep shale samples from the recently drilled DY7 well in the Dingshan area of the Sichuan Basin is carried out, and the longitudinal variations in major and trace elements are revealed. The differences in the WF, lower section of the Long-1 (Long-11) and upper section of the Long-1 (Long-12) shales are studied in terms of redox conditions, paleoproductivity, terrigenous detrital input, sedimentation rate and paleoclimate, and the different main controlling factors of OM accumulation for these three layers are discussed. The WF shale has a higher TOC content (mean: 5.73%), the Long-11 shale has a high TOC content (mean: 2.89%), while the Long-12 shale has a low TOC content (mean: 1.44%). For the WF shale, due to complex geological events and large fluctuations in element contents, its TOC content is poorly correlated with these indices, redox and paleoproductivity proxies have a positive association with the Long-11 shale’s TOC content, but negatively correlated with terrigenous input and sedimentation rate indices. The formation of these two sets of organic-rich shales (TOC > 2%) is jointly controlled by good preservation conditions. In contrast, the TOC content of the WF shale is higher than that of the Long-11 shale as the result that terrigenous input and sedimentation rate of the Long-11 shale represent the dilution and destruction of OM, which is different from the former. During the Long-12 depositional period, the water column experienced weak reducing conditions and low productivity, and its high terrigenous debris input further diluted the OM, leading to a low TOC content.

Analysis of Critical Instability Conditions for Solid-Phase Plugging of Natural Fractures during Temporary Plugging and Fracturing.

Hydraulic fracturing has become a key technology for the development of unconventional oil and gas resources, such as deep shale. Due to the development of natural fractures in deep shale reservoirs, the opening of natural fractures during the fracturing process can cause a significant loss of fracturing fluid, resulting in a reduction in the width of the main fracture and construction risks, such as sand plugging. It is important to improve the fracturing effect of deep shale reservoirs by plugging natural fractures with solid phases, reducing filtration, and improving the efficiency of the fracturing fluid. Ensuring the effectiveness of solid plugging is key to optimizing the fracturing design and improving the stimulation effect after fracturing. In this study, solid plugging technology is introduced into the filtration control process of natural fractures. By setting a plugging zone with a certain length and permeability inside the natural fracture, a stability prediction model for the plugging zone of natural fractures is established, and the instability conditions of the plugging zone are analyzed. The simulation results indicate that the instability of the plugging zone is related to permeability and there is a critical permeability. When the permeability of the plugging zone is greater than this value, expansion instability will occur, and when it is less than or equal to this value, shear slip instability may occur. The strength of shear slip instability is mainly determined by the length of the plugging zone, the friction angle of the natural fracture surface, the friction angle between the plugging particles, and the porosity of the plugging zone. The friction angle of natural fracture surfaces affects only the strength of slip instability, while the friction angle of plugging particles and porosity mainly affect the strength of shear instability. The research results provide a theoretical basis for the optimization of fracturing construction parameters in deep shale reservoirs.

Hydrocarbon accumulation and orderly distribution of whole petroleum system in marine carbonate rocks of Sichuan Basin, SW China

Based on the situation and progress of marine oil/gas exploration in the Sichuan Basin, SW China, the whole petroleum system is divided for marine carbonate rocks of the basin according to the combinations of hydrocarbon accumulation elements, especially the source rock. The hydrocarbon accumulation characteristics of each whole petroleum system are analyzed, the patterns of integrated conventional and unconventional hydrocarbon accumulation are summarized, and the favorable exploration targets are proposed. Under the control of multiple extensional-convergent tectonic cycles, the marine carbonate rocks of the Sichuan Basin contain three sets of regional source rocks and three sets of regional cap rocks, and can be divided into the Cambrian, Silurian and Permian whole petroleum systems. These whole petroleum systems present mainly independent hydrocarbon accumulation, containing natural gas of affinity individually. Locally, large fault zones run through multiple whole petroleum systems, forming a fault-controlled complex whole petroleum system. The hydrocarbon accumulation sequence of continental shelf facies shale gas accumulation, marginal platform facies-controlled gas reservoirs, and intra-platform fault- and facies-controlled gas reservoirs is common in the whole petroleum system, with a stereoscopic accumulation and orderly distribution pattern. High-quality source rock is fundamental to the formation of large gas fields, and natural gas in a whole petroleum system is generally enriched near and within the source rocks. The development and maintenance of large-scale reservoirs are essential for natural gas enrichment, multiple sources, oil and gas transformation, and dynamic adjustment are the characteristics of marine petroleum accumulation, and good preservation conditions are critical to natural gas accumulation. Large-scale marginal-platform reef-bank facies zones, deep shale gas, and large-scale lithological complexes related to source-connected faults are future marine hydrocarbon exploration targets in the Sichuan Basin.

Electrical structure identification of deep shale gas reservoir in complex structural area using wide field electromagnetic method

Electrical structure identification of deep shale gas reservoir in complex structural area using wide field electromagnetic method

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

Multi-fractal characteristics of pore system in deep organic-rich shales of the Wufeng-Longmaxi formation in the Sichuan Basin and their geological significance

The heterogeneity of pore system of deep shale reservoir determines the occurrence, enrichment and migration behavior of shale gas within shales. In this study, multi-fractal analysis was applied to analyze CO2 and N2 adsorption data for obtaining multi-fractal parameters including Hurst index and multi-fractal spectrum (D5--D5+) of the deep Wufeng-Longmaxi shales collected from the Sichuan Basin, China, in order to study the connectivity and heterogeneity of micropore pores and meso-macropores as well as their influencing factors. The results showed that pore system of the Wufeng-Longmaxi deep shale exhibits distinct multifractal nature. There exists significant differences in the pore volume (PV) of micropores (<2 nm), mesopore (2–50 nm), and macropore (>50 nm) across different shale lithofacies due to their differences in TOC content and mineral composition. The heterogeneity and connectivity of micropores and meso-macropores within deep shales in the Sichuan Basin are controlled by multiple factors including shale lithofacies, burial depth, and pressure coefficients. Notably, siliceous shale (SL) and calcareous/argillaecous siliceous shale (C/ASL), known as sweet spot for current shale gas exploitation, exhibits characteristics such as relative low micropore connectivity, high micropore heterogeneity, high micropore PV and low meso-macropore connectivity. These suggest that isolated pressure-sealing compartment is easier formed within the overpressured SL and C/ASL. Thus, pressure in these shales is less likely to release during the Yanshanian-Xishanian tectonic uplift process, favoring the preservation of organic matter (OM) pores and residual interparticle pores, which is conducive to the accumulation of deep shale gas dominated by free gas.

The Analysis of Transient Temperature in the Wellbore of a Deep Shale Gas Horizontal Well

The Analysis of Transient Temperature in the Wellbore of a Deep Shale Gas Horizontal Well

Methane-Water Interfacial Tension in Nanopores: A Dissipative Particle Dynamics Study.

Imbibition of fracturing fluid in deep shale nanopores has a significant effect on shale gas production. One of the key parameters affecting imbibition is the interfacial tension of the methane-water system. However, studies on the methane-water interfacial tension in nanopores are very limited, and obtaining the accurate value of the methane-water interfacial tension at the nanoscale is difficult and time-consuming. In this work, a dissipative particle dynamics simulation model was built to study the methane-water interfacial tension in nanopores. This model provides reliable access to methane-water interfacial tension for deep shales under high-temperature, high-pressure conditions at low computation cost. It can be easily used to compute the methane-water interfacial tension in nanopores or the confined space in wide application scenarios. A sensitivity study of methane-water interfacial tension on a variety of factors was conducted. Results demonstrate that under high-pressure conditions, the increase in pressure leads to the rise of interfacial tension. When pressure increases from 20 to 120 MPa, interfacial tension rises from 0.0275 to 0.12 N/m, which contributes to the severe imbibition of fracturing fluid in deep shales. The confinement effect was observed by investigating the influence of pore size. Interfacial tension almost remains unchanged in pores smaller than 7 nm because most of the confined space is occupied by interface layer molecules in these pores. When pore size increases from 7 to 15 nm, the confinement effect is reduced. The interfacial tension experiences a growth from 0.1155 to 0.27 mN/m. Compared with pressure and pore size, the effect of temperature on interfacial tension can be neglected during deep shale gas production.

Thermal dynamics in deep shale reservoirs: Influences of the kerogen microstructural behavior on the gas adsorption/desorption capacity

In shale gas extraction projects, an investigation into the mechanisms of energy/mass transfer associated with shale gas adsorption/desorption in organic matter (kerogen) microstructure under high temperature and stress condition is crucial for improving the efficiency of shale gas production. This study presents a coupling thermo-hydro-mechanical model based on an improved fractal method that could explain the microstructural evolution of the kerogen system and the resultant alterations during the gas adsorption/desorption process under varying thermal conduction, gas seepage, and stress conditions. The influence of porosity, diameter, and tortuosity on the abundance, length, and complexity of kerogen networks under coupled multi-field effects is evaluated. The significance of this study is it could address the following aspects quantitively: (1) the spatiotemporal evolution of kerogen fractal dimensions following various extraction timelines; (2) the influence of shale temperatures on kerogen structures; (3) the influence of the kerogen fractal dimension on the shale gas desorption capacity and production efficiency; and (4) under different temperatures, when the fractal dimension/tortuosity fractal dimension of kerogen changes due to extraction disturbances, the volumetric deformation induced by gas adsorption increases by a maximum of 26.1%/decreases by 28.1% and in the later stages of extraction, the maximum gas pressure decreases by 44.7%/increases by 47.1%. The proposed fractal method adeptly reveals shale gas desorption behaviors under multi-field coupling conditions from a microscopic perspective, which cannot be found in the literature.