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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 4 Å is 0.005 26 Pa⋅S, which is 6.12 times the reference value of viscosity at 298 K. 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. [ABSTRACT FROM AUTHOR]

We explore the origins and the development of hydraulic fracking technology that made possible United States' unexpected rise as a top producer of oil and gas. As hydraulic fracking was first used extensively to produce shale gas and only later to produce shale oil, we focus on analyzing what is often referred to as the "shale gas revolution." We trace how the shale gas ecosystem evolved, what role different actors played in the unexpected shale gas revolution, and how the strategies and knowledge bases of the different actors differed and evolved over time. [ABSTRACT FROM AUTHOR]

The Upper Permian Wujiaping (WJP) Formation in the Yangtze Block (Southern China) has great potential for shale gas exploration. However, the sedimentary characteristics and environmental evolution of the WJP Formation are poorly understood. Based on 260 hand specimen samples obtained from 18 sections and 1 borehole in the eastern Yangtze Block, petrographic observations reveal that the WJP Formation is composed of 11 rock types. Combined with analyses of geochemical compositions, the sedimentary facies belts of the WJP Formation are divided into shoreland, shallow-water shelf, deep-water shelf shoal, restricted platform, and open platform. Bauxite was developed in the shoreland at the bottom of the WJP Formation, which is attributed to the Dongwu movement. The formation of paleo-uplift exerted a significant effect on paleogeomorphology and led to a major change in the sedimentary model from the underlying stratum to the WJP Formation. During the lower WJP Formation sedimentary period, gradual transgression occurred in the eastern Yangtze Block, and the lithology was mainly composed of clastic rocks. Shoreland, shallow-water shelf, and deep-water shelf were developed northeastward in turn. In the period of the upper WJP Formation, due to durative transgression, the area of the shoreland reduced southwestward. The lithology converted from clastic rocks into carbonates, and the restricted platform and open platform were developed northeastward. A few patched shoals formed in the restricted platform. [ABSTRACT FROM AUTHOR]

Wufeng–Longmaxi Formation and Qiongzhusi Formation are the significant shale gas exploration strata in China. The former has made a major breakthrough, and the exploration of the latter is restricted. At present, it shows good exploration potential in the Qiongzhusi Formation. Based on the field outcrop and core logging data, the production data from drilled shale gas wells and previous research results combined with the determination of organic matter content, laser Raman spectroscopy of organic matter, X‐ray diffraction experiments, and field emission scanning electron microscopy observations. This study compares the geological conditions and control factors of shale gas enrichment and high yield in the Wufeng–Longmaxi Formation and Qiongzhusi Formation and clarifies the enrichment mode of two sets of shale gas reservoirs. The results show that the organic geochemical conditions of two sets of shale reservoirs are similar, about 0.5%~4.5%. The quartz content of Wufeng–Longmaxi Formation shale (42.5%) is more than that of Qiongzhusi Formation (34.1%~40.2%), and the feldspar content (6.4%) is less than that of Qiongzhusi Formation (20.5~27.3%). The inorganic pores of the Qiongzhusi Formation are more developed than those of the Wufeng–Longmaxi Formation, and the pore size of inorganic pores can reach 100 nm~1 μm. Both of them have good preservation conditions. The enrichment of shale gas in the Wufeng–Longmaxi Formation is controlled by hydrocarbon generation reservoir‐preservation conditions, and the enrichment of shale gas in the Qiongzhusi Formation is mainly controlled by geological structure. It is of great significance to clarify the enrichment control factors of the Qiongzhusi Formation for effectively guiding the continuous exploration and development of the Qiongzhusi Formation. Shale gas exploration in the Qiongzhusi Formation has a very large prospect, which is expected to exceed the Longmaxi Formation. [ABSTRACT FROM AUTHOR]

Seismic events triggered by stress unloading during geo-energy extraction activities have become a key focus in both seismological research and engineering safety. This study presents a novel application of waveform neural networks, combining unsupervised and supervised learning techniques to classify and characterize fractures in laboratory-induced seismic events. Initially, A neural network model was initially developed that is capable of extracting time-frequency features from waveforms through unsupervised training on 1.2 million Acoustic Emission waveforms. Subsequently, this model was fine-tuned using a labeled dataset obtained from Brazilian split and uniaxial compression tests. The final result was a highly accurate model, achieving an accuracy rate of 97.6%. By applying this refined model, insights have been gained into the complex fault slip behaviors induced by geo-energy extraction activities. Our findings reveal that fluid infiltration at the onset triggers low-energy, shear-induced fractures in low-stress fault regions, which then escalate into tensile fractures during critical sliding in high-stress areas. Key precursors to fluidinduced seismicity have been identified, providing a major advance in early seismic hazard detection. These insights are essential for monitoring and early warning of induced seismicity during geo-energy extraction activities. Our work contributes significantly to improving the safety and efficiency of geo-energy extraction, including geothermal, shale gas, and conventional hydrocarbon production. [ABSTRACT FROM AUTHOR]

The study of gas transport in low-permeability rocks is both practical and of significant importance to produce tight rock reservoirs. The presence of nanopores in tight rocks results in distinctly different gas transport mechanisms from those found in conventional reservoirs. Traditional Darcy's law is inadequate for describing gas flow in this context. Instead, various modes of gas transport, such as continuum flow, slip flow, transition flow, and Knudsen diffusion for bulk gas, as well as surface diffusion and adsorption/desorption for adsorbed gas, coexist within these nanopores. This paper mainly focuses on studies of gas transport in nanopores that consider apparent permeability. To begin with, the pore structure characteristics and gas seepage mechanisms in shale are introduced. An overview of the three main methods for measuring apparent permeability including laboratory experiments, numerical simulations, and analytical techniques, is provided. Mathematical models describing gas transport within nanopores are emphasized as a foundational component of apparent permeability measurements. Furthermore, the factors that influence these models are discussed. Upon analyzing the existing models, it is evident that they are diverse and numerous. While these models typically encompass multiple mechanisms and influencing factors related to gas transportation, each model has its specific limitations. Therefore, there is a continued need for the development of more comprehensive and general models. This study offers the most detailed overview of gas transport mechanisms and mathematical models in low-permeability rocks, aiming to support the evaluation and exploitation of tight rock reservoirs. [ABSTRACT FROM AUTHOR]

CO2 injection in shale reservoirs is more suitable than the conventional recovering methods due to its easier injectivity and higher sweep efficiency. In this work, Grand Canonical Monte Carlo (GCMC) simulation is employed to investigate the adsorption/desorption behavior of CH4-C4H10 and CH4-C4H10-CO2 mixtures in organic and inorganic nanopores during pressure drawdown and CO2 huff and puff processes. The huff and puff process involves injecting CO2 into the micro- and mesopores, where the system pressure is increased during the huffing process and decreased during the puffing process. The fundamental mechanism of shale gas recovery using the CO2 injection method is thereby revealed from the nanopore-scale perspective. During primary gas production, CH4 is more likely to be produced as the reservoir pressure drops. On the contrary, C4H10 tends to be trapped in these organic nanopores and is hard to extract, especially from micropores and inorganic pores. During the CO2 huffing period, the adsorbed CH4 and C4H10 are recovered efficiently from the inorganic mesopores. On the contrary, the adsorbed C4H10 is slightly extracted from the inorganic micropores during the CO2 puffing period. During the CO2 puff process, the adsorbed CH4 desorbs from the pore surface and is thus heavily recovered, while the adsorbed C4H10 cannot be readily produced. During CO2 huff and puff, the recovery efficiency of CH4 is higher in the organic pores than that in the inorganic pores. More importantly, the recovery efficiency of C4H10 reaches the highest levels in both the inorganic and organic pores during the CO2 huff and puff process, suggesting that the CO2 huff and puff method is more advanced for heavier hydrocarbon recovery compared to the pressure drawdown method. In addition to CO2 storage, CO2 sequestration in the adsorbed state is safer than that in the free state. In our work, it was found that the high content of organic matter, high pressure, and small pores are beneficial factors for CO2 sequestration transforming into adsorbed state storage. [ABSTRACT FROM AUTHOR]

Petroleum-based drilling cuttings (PBDCs), as hazardous waste, are characterized by high petroleum pollutant contents and complex compositions and must be properly treated. Their treatment by a hammermill thermal desorption system can generate a variety of products, necessitating better delineation of the transformation characteristics of organic matter at the molecular level. In this study, the transformation characteristics of organic matter in the treatment of PBDCs by a hammermill thermal desorption system have been analyzed by positive-ion atmospheric-pressure photo-ionization Fourier-transform ion cyclotron resonance mass spectrometry (+APPI FT-ICR MS). The results showed that the PBDCs contained large amounts of CH, CHO, and CHON compounds and a small amount of CHS compounds. Of these, CH and CHO compounds are easily separated and recovered by the hammermill thermal desorption treatment system. Most of this organic matter is separated directly through physical changes, whereas only 0.32% undergoes chemical reactions. The organic matter in the recovered petroleum and #110 industrial white oil was highly reproducible and similar in terms of saturation and aromaticity. The mineral composition of the PBDCs did not change significantly during treatment by the hammermill thermal desorption system. This research may provide theoretical guidance for the efficient treatment of PBDCs by the hammermill thermal desorption system. [ABSTRACT FROM AUTHOR]

After 5 different plans of development, the Weiyuan block is struggling to maintain stable production and urgently needs a new method to improve the recovery rate. Practice at home and abroad shows that three-dimensional development can effectively improve the degree of vertical shale gas utilization. Therefore, this paper first analyzes the distribution of reservoirs in the Weiyuan block and calculates the distribution of remaining reserves through the methods of fine description of gas reservoirs and establishment of a three-dimensional geological model. The results show that the recovery degree of the platform in the main production area of Weiyuan is 35~60%, and the average remaining reserves of the wells are (1.2~3) × 108 m3, and there is three-dimensional development potential in the local area. Secondly, through the establishment of a fracture and rock mechanics model, the target layer system for three-dimensional development of the Weiyuan block is preliminary selected from five aspects, namely, remaining reserves, reservoir characteristics, fracture density, mechanical characteristics, and the comparison of the height of the fracture network. Finally, in order to check the correctness of the target layer for three-dimensional development and evaluate the effect of the three-dimensional development, four scenarios for the lower branch of the H8 platform are designed and numerically simulated using Petrel RE software. The results of the numerical simulation show that Option 2 is the most effective, which can increase the production of the platform by 1.76 × 108 m3, and the recovery rate grows from 16.4% to 31.0%, with an overall increase of 14.6%. The relevant understanding can provide a reference for the three-dimensional development strategy of the Weiyuan shale gas block. [ABSTRACT FROM AUTHOR]

Horizontal well drilling and multi-stage hydraulic fracturing are key technologies for the development of shale gas reservoirs. Instantaneous acquisition of hydraulic fracture parameters is crucial for evaluating fracturing effectiveness, optimizing processes, and predicting gas productivity. This paper establishes a transient flow model for shale gas wells based on the boundary element method, achieving the characterization of stimulated reservoir volume for a single stage. By integrating pressure monitoring data following the pumping shut-in period of hydraulic fracturing for well testing interpretation, a workflow for inverting fracture parameters of shale gas wells is established. This new method eliminates the need for prolonged production testing and can interpret parameters of individual hydraulic fracture segments, offering significant advantages over the conventional pressure transient analysis method. The practical application of this methodology was conducted on 10 shale gas wells within the Changning shale gas block of Sichuan, China. The results show a high correlation between the interpreted single-stage total length and surface area of hydraulic fractures and the outcomes of gas production profile tests. Additionally, significant correlations are observed between these parameters and cluster number, horizontal stress difference, and natural fracture density. This demonstrates the effectiveness of the proposed fracture parameter inversion method and the feasibility of field application. The findings of this study aim to provide solutions and references for the inversion of fracture parameters in shale gas wells. [ABSTRACT FROM AUTHOR]

This paper explores the reasons for the perforation failure of the shale gas gathering pipeline in the E Gas Mine and proposes preventive measures. EDS experiment found that the corrosion products were mainly Fe2O3, FeS, and FeCO3. Shale gas contains 24.908 g/m3 CO2 and 0.384 g/m3 H2S, and formation water contains 20.445 g/m3 Cl−. Therefore, CO2/H2S corrosion has occurred in the pipeline, and Cl− exacerbated localized damage to the material matrix, accelerated corrosion of the pipeline. The base material was more corrosion resistant than the weld, but the weld was more erosion resistant than the base material. The CFD simulation results found that the main reason of pipeline erosion is that, the shale gas contains grit and the gas volume exceeds the designed gas volume. So, the perforation failure of the pipeline was a result of both corrosion and erosion, and the effect of erosion is stronger than that of CO2/H2S corrosion on the pipeline. [ABSTRACT FROM AUTHOR]

After shale gas well sites are exploited, remediation is essential to restore the ecological environment. Effective bioremediation often has long cycles, so reducing this period is a research focus. To elucidate the intrinsic mechanisms between microorganisms and oil removal and to support the acceleration of bioremediation, gas chromatography–mass spectrometry and high-throughput sequencing technologies were utilized. The oil transformation and microbial response mechanisms during the natural remediation process from August to December at an abandoned shale gas well site in Weiyuan County, Neijiang City, Sichuan Province, were analyzed, revealing the directions of microbial succession. The Results showed that from August to September, the greatest degradation of oil components (C10-C20、C21-C30 alkanes) occurred, with Actinobacteriota, Gemmatimonadota, Proteobacteria, Acidobacteriota, Bacteroidota, and Ascomycota playing major roles. Key contributors to oil degradation included Sphingomonas, Flavisolibacter, Ramlibacter, Mortierella, Fusarium, and Rectifusarium. These microorganisms, along with those such as Chloroflexi, Gemmatimonas, Ellin6067, Cercospora, Sarocladium, Preussia, Calyptrozyma, Staphylotrichum, and Exophiala, which facilitate the cycling of nutrients like carbon, nitrogen, and phosphorus, collectively promote the degradation of oil. Moisture content, electrical conductivity, total nitrogen, total phosphorus, and pH affect the activity of oil-degrading microbes and thus oil degradation. Conversely, microbes alter soil chemistry during degradation, impacting those physicochemical properties. This feedback mechanism influences the activity of other oil-degrading microbes, creating a dynamic interaction network. Ultimately, the microbial community shifts towards populations that aid soil ecosystem restoration. This study reveals microbial succession and its role in oil degradation, offering insights for improving and accelerating bioremediation. [ABSTRACT FROM AUTHOR]

To address the environmental and formation damage caused by traditional hydraulic fracturing in coalbed methane and shale gas extraction, supercritical CO2 (SC-CO2) fracturing technology has emerged as an effective alternative due to its low viscosity, high diffusivity, and waterless nature. This paper reviews recent advancements in experiments and numerical simulations to explore the mechanisms of fracture initiation and propagation in this technology, with a focus on analyzing fracture initiation pressure, propagation patterns, and influencing factors. The findings show that SC-CO2 fracturing can generate complex fracture networks at lower initiation pressures, with stress conditions, temperature, and natural fractures significantly impacting fracture initiation and propagation. Additionally, the paper highlights existing limitations in accurately simulating CO2 flow, phase transitions, and its interactions with natural fractures, offering optimization suggestions and future perspectives. [ABSTRACT FROM AUTHOR]

Conventional logging interpretation methods qualitatively identify shale reservoirs using shale attribute parameters and interpretation templates. However, improving the identification accuracy of complex shale reservoirs is challenging due to the numerous evaluation parameters and the complexity of model calculations. To quantitatively characterize high-quality shale reservoirs effectively, this study utilizes two wells in the Fuling shale gas field as examples and establishes a comprehensive evaluation method for identifying high-quality shale gas reservoirs utilizing multi-fractal spectral analysis of well logs. First, the conventional well logs are qualitatively analyzed and evaluated via multiple fractals and R/S analysis. Subsequently, a gray relational analysis is employed to combine the production well logging, which reflects dimensionless productivity contributions, with the fractal characteristics of conventional well logs to obtain the corrected weight multifractal spectrum width ∆α' and fractal dimension D'. Comprehensive fractal evaluation indices λ and γ are introduced, forming three categories of productivity evaluation standards for shale gas reservoirs characterized by fractals. Finally, a validation well is employed to demonstrate the effectiveness of the evaluation method. The results indicate that the identification of high-quality shale gas reservoirs based on the above comprehensive fractal evaluation method can reflect the productivity classification level of fractured well sections, simplify the calculation of formation evaluation parameters, and avoid the problem of poor correlation between predicted sweet spot zones and gas production. This approach has wide applicability and value for identifying high-quality reservoir areas in shale gas reservoirs and provides technical support for the effective large-scale development of shale reservoirs. [ABSTRACT FROM AUTHOR]

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources. [ABSTRACT FROM AUTHOR]

Organic-rich hot Qusaiba shale is the primary source rock of most of the Paleozoic hydrocarbon reservoirs of eastern and central Arabia. Representative near-surface Qusaiba shale samples were collected and characterized from one of its outcrop sections at the Tayma quadrangle in northwest Saudi Arabia. The petrophysical and geochemical characterization indicated porosity and permeability of 8.2% and 2.05 nD, respectively, with good total organic carbon (TOC) of 2.2 mg/g and mature kerogen of gas-prone type III. The tight characteristics of the formation can lead to high capillary pressure and extensive post-fracking water retention, leading to flow blockage and a reduction in gas productivity. Three different surfactants and one ionic liquid, namely, Triton X-100, Triton X-405 and Zonyle FSO surfactants and Ammoeng 102 ionic liquid, were tested as additives to fracking fluid to investigate their effectiveness in optimizing its performance. The chemical solutions exhibited no sign of instability when exposed to solution salinity and temperatures up to 70 °C. The investigated chemicals' performance was examined by measuring methane/chemical solutions' surface tension and their ability to alter shale's wettability. The results indicate that Zonyl FSO is the most effective chemical, as it is able to significantly reduce surface tension and, hence, capillary pressure by 66% when added at critical micelle concentration (CMC). Using Zonyl FSO surfactant at a maximum tested concentration of 0.2% induced a relatively smaller capillary pressure drop (54%) due to the drastic drop in the contact angle rendering shale very strongly water-wet. Such a drop in capillary pressure can lower the fracking fluid invasion depth and therefore ease the liquid blockage removal during the flowback stage, enhancing gas recovery during the extended production stage. Triton X-100 at CMC was the second most effective surfactant and was able to induce a quite significant 47% drop in capillary pressure when added at the maximum tested concentration of 0.05%. This was sufficient to remove any liquid blockage but was less likely to alter the wettability of the shale. Based on the findings obtained, it is suggested to reduce the blockage tendency during the fracking process and elevate any existing blockage during the flowback stage by using Zonyl FSO at CMC where IFT is at its minimum with a higher contact angle. [ABSTRACT FROM AUTHOR]

Featured Application: The findings of this study can be utilized to enhance the operational parameters of the clean drilling process in shale gas horizontal wells. Additionally, the research offers technical solutions to prevent the accumulation of cuttings beds and mitigate drilling obstructions, while also providing theoretical backing for the development of specialized borehole purification tools for shale gas. The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at simulating cuttings transport under various operational conditions, with a particular emphasis on gas wells. The methodology encompasses the modulation of the drilling fluid flow rate and the drill's rotational speed to examine the transport velocity of cuttings. Furthermore, the study analyzes the impact of annular eccentricity on return volume, transport time, and cuttings bed height. Critical initiation velocities for cuttings across different motion modes were also determined, and theoretical calculations were compared with empirical data. The findings indicate that an increased flow rate of drilling fluid and higher rotation speed substantially improve the transport of cuttings, thereby minimizing bed formation, whereas increased eccentricity hinders this process. The results revealed that the theoretical model showed a greater overestimation of the start-up velocity for spherical particles, with average errors ranging from 15.50% to 17.56%. In contrast, the model exhibited better accuracy for non-spherical (flaky) particles, with errors between 8.63% and 9.61%. Under non-rotating conditions, the average error of the model was approximately 8.32%, while the introduction of drill tool rotation increased the average error to 11.94%. These results have the potential to optimize operational parameters in shale gas well drilling and may contribute to the development of specialized borehole purification tools. [ABSTRACT FROM AUTHOR]

The efficient utilization of methane, a vital component of natural gas, shale gas and methane hydrate, holds significant importance for global energy security and environmental sustainability. However, converting methane into value-added oxygenates presents a formidable challenge due to its inert nature. Direct selective oxidation of methane (DSOM) under mild conditions is essential for reducing energy consumption and carbon emissions compared with traditional indirect routes. Achieving total selectivity in methane hydroxylation remains elusive due to the competitive CO2 formation. This feature article highlights recent advancements in methane hydroxylation using thermo-, photo-, and electro-catalytic systems. Through strategically designing the structure of catalysts to control the reactive oxygen species and optimizing reaction parameters, significant progress has been made in enhancing oxygenate selectivity and minimizing overoxidation. A comprehensive understanding of the mechanisms underlying methane hydroxylation with total selectivity offers insights for improving catalyst design and reaction parameter optimization, promoting sustainable methane utilization. [ABSTRACT FROM AUTHOR]

The shale formation, a common carbon-hydrogen reservoir, has numerous nanoscale pores that facilitate multiple gas transport mechanisms, including viscous flow, slip flow, Knudsen diffusion, and surface diffusion. Additionally, various action mechanisms involving effective stress, real gas effect, gas adsorption and desorption, and fracture-pore characteristics significantly influence gas transport. In this study, we conceptualize shale as a triple porosity medium comprising organic matrix, inorganic matrix, and microfractures. For each system, its hydraulic-mechanical coupled model with action mechanisms and gas transport mechanisms is derived based on fractal theory. After validating the model with Barnett and Marcellus data, the evolution of apparent permeability and gas pressure is studied, as well as the influences of pore fractal features, the real gas effect, and the number of hydraulic fractures on gas extraction. Simulation results indicate that, in comparison to organic matrix, inorganic pore fractal features exert a more noticeable effect on cumulative production. The real gas effect is critical in gas transport and reservoir reserve estimation; disregarding this effect results in a 17.4% underestimation of cumulative gas production by the 1600th day. Fracture interference attenuates the improvement in cumulative production gains from increased hydraulic fracture numbers. • A hydraulic-mechanical coupled triple porosity fractal model is established. • Inorganic matrix pore fractal features have a greater impact on gas transport than organic matrix. • Ignoring the real gas effect leads to an underestimation of gas productivity. • The hydraulic fracture interference significantly reduces gas productivity in the late stage of shale gas exploitation. [ABSTRACT FROM AUTHOR]

Shale gas, as an environmentally friendly fossil energy resource, has gained significant commercial development and shows immense potential. However, accurately predicting shale gas production faces substantial challenges due to the complex law of decline, nonlinear and non-stationary features in production data, which greatly repair the robustness of current models in predicting shale gas production time series. To address these challenges and improve accuracy in production forecasting, this paper introduces a novel and innovative approach: a hybrid proxy model that combines the bidirectional long short-term memory (BiLSTM) neural network and random forest (RF) through deep learning. The BiLSTM neural network is adept at capturing long-term dependencies, making it suitable for understanding the intricate relationships between input and output variables in shale gas production. On the other hand, RF serves a dual purpose: reducing model variance and addressing the concept drift problem that arises in non-stationary time series predictions made by BiLSTM. By integrating these two models, the hybrid approach effectively captures the inherent dependencies present in long and nonstationary production time series, thereby reducing model uncertainty. Furthermore, the combination of BiLSTM and RF is optimized using the recently-proposed marine predators algorithm (MPA) to fine-tune hyperparameters and enhance the overall performance of the proxy model. The results demonstrate that the proposed BiLSTM-RF-MPA model achieves higher prediction accuracy and demonstrates stronger generalization capabilities by effectively handling the complex nonlinear and nonstationary characteristics of shale gas production time series. Compared to other models such as LSTM, BiLSTM, and RF, the proposed model exhibits superior fitting and prediction performance, with an average improvement in performance indicators exceeding 20%. This innovative framework provides valuable insights for forecasting the complex production performance of unconventional oil and gas reservoirs, which sheds light on the development of data-driven proxy models in the field of subsurface energy utilization. [ABSTRACT FROM AUTHOR]

Currently, horizontal well fracturing is indispensable for shale gas development. Due to the variable reservoir formation morphology, the drilling trajectory often deviates from the high-quality reservoir, which increases the risk of fracturing. Accurately recognizing low-amplitude structures plays a crucial role in guiding horizontal wells. However, existing methods have low recognition accuracy, and are difficult to meet actual production demand. In order to improve the drilling encounter rate of highquality reservoirs, we propose a method for fine recognition of low-amplitude structures based on the non-subsampled contourlet transform (NSCT). Firstly, the seismic structural data are analyzed at multiple scales and directions using the NSCT and decomposed into low-frequency and high-frequency structural components. Then, the signal of each component is reconstructed to eliminate the low-frequency background of the structure, highlight the structure and texture information, and recognize the lowamplitude structure from it. Finally, we combined the drilled horizontal wells to verify the lowamplitude structural recognition results. Taking a study area in the west Sichuan Basin block as an example, we demonstrate the fine identification of low-amplitude structures based on NSCT. By combining the variation characteristics of logging curves, such as organic carbon content (TOC), natural gamma value (GR), etc., the real structure type is verified and determined, and the false structures in the recognition results are checked. The proposed method can provide reliable information on lowamplitude structures for optimizing the trajectory of horizontal wells. Compared with identification methods based on traditional wavelet transform and curvelet transform, NSCT enhances the local features of low-amplitude structures and achieves finer mapping of low-amplitude structures, showing promise for application. [ABSTRACT FROM AUTHOR]

The reduction in well spacing for multi-fractured horizontal wells (MFHWs) and the increase in infill drilling exacerbate the risk of fracture communication. This presents substantial challenges for the rate transient analysis of the parent–child well system. This study proposes an improved two-phase straight-line analysis method to evaluate the linear flow parameters of multiple communicating MFHWs in shale gas reservoirs. Considering shale gas adsorption–desorption mechanisms, nonuniform length of fractures, stress-dependent effects, and matrix shrinkage effects, two-phase productivity equation is established within the dynamic drainage area (DDA). Subsequently, we develop a three-well square root of time plot based on DDA correction and propose a rigorous workflow for evaluating linear flow parameters in single-well, two-well, and three-well systems. The straight lines on the parent well's square root of the time plot exhibit varying degrees of jumps, depending on the frequency of fracture communication. After communication, it is necessary to adjust the cumulative production and production time of the parent well to accurately recalculate the average pressure within the drainage area. Numerical simulations are employed to generate a series of cases under different reservoir conditions to validate the accuracy of the proposed model. The results show that the model estimates fracture half-lengths with errors within 8%, meeting the precision requirements for field applications. Additionally, the method exceeds numerical simulations in computational speed. Two field case studies in the WY Basin, China, further illustrate the effectiveness and practicality of the proposed method, providing theoretical support for hydraulic fracturing construction design and development planning. [ABSTRACT FROM AUTHOR]

The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments. [ABSTRACT FROM AUTHOR]

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan--Dishuiquan Sag, the Wucaiwan Sag--Dajing area, and the Dongdao Haizi Sag--Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900-4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions. [ABSTRACT FROM AUTHOR]

Through the analysis of natural gas composition, carbon and hydrogen isotopes of alkane gases, reservoir bitumen, source rock conditions, and source--reservoir combinations, this study clarifies the differences in gas sources and the origins of natural gas in the Permian Changxing Formation--Triassic Feixianguan Formation on both sides of the Kaijiang--Liangping Trough. Additionally, it identifies favorable exploration directions for coal-formed gas generated by the Longtan Formation in the Sichuan Basin. The following understanding was obtained: (1) The natural gas in the Changxing--Feixianguan formations mainly composed of alkane gas, typical of dry gas. (2) The carbon isotope values of methane and ethane in the Changxing--Feixianguan formations on the east side of the trough are lower than those on the west side. Specifically, the ethane carbon isotope value in the Longgang Gas Field on the west side is higher than that in the Yuanba Gas Field, while the methane hydrogen isotope value is lower in the Longgang Gas Field compared to the Yuanba Gas Field. (3) The natural gas in the Dongyuezhai, Puguang, and Yuanba gas fields predominantly originates from sapropelic organic matter of the Wujiaping Formation, with kerogen types II1--I; in contrast, the Longgang Gas Field contains a mixture of coal-formed gas and oil-type gas, with a slightly higher content of coal-formed gas, originating from mixed organic matter of the Wujiaping Formation, with kerogen type II1--II2. (4) Multiple types of gas, such as coal rock gas, tight sandstone gas, and shale gas, can be formed within the Longtan Formation. The Suining--Luzhou and Langzhong--Guang'an--Fuling areas are identified as favorable zones for the exploration of coal rock gas and marine--continental transitional shale gas, respectively. Additionally, the reef and shoal development areas of the Changxing Formation in the Suining--Hechuan and Guang'an--Nanchong regions are also favorable exploration areas for coal-formed gas. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Shale gas, mainly consisting of adsorbed gas and free gas, has served a critical role of supplying the growing global natural gas demand in the past decades. Considering that the adsorbed methane has contributed up to 80% of the total gas in place (GIP), understanding the methane adsorption behaviors is imperative to an accurate estimation of total GIP. Historically, the single-site Langmuir model, with the assumption of a homogeneous surface, is commonly applied to estimate the adsorbed gas amount. However, this assumption cannot depict the methane adsorption characteristics due to various compositions and pore sizes of shales. In this work, a multi-site model integrating the energetic heterogeneity in adsorption is derived to predict methane adsorption on shale. Our results show that the multi-site model is capable of addressing the heterogeneity of shales by a wide range of adsorption energy distributions (owing to the complex compositions and different pore sizes), which is different from the single-site model only characterized by single adsorption energy. Consequently, the multi-site model results have better accuracy against the experimental data. Therefore, applying the multi-site Langmuir model for estimating GIP in shales can achieve more accurate results compared with using the traditionally single-site model. [ABSTRACT FROM AUTHOR]

Liquefied 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. [ABSTRACT FROM AUTHOR]

Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents. [ABSTRACT FROM AUTHOR]

Predicting ground motions due to induced seismicity is a challenging task owing to the scarcity of data and heterogeneity of the uppermost crust. Dealing with this requires a thorough understanding of the underlying physics and consideration of inter-site variability. The most common ground motion model used in practice is the parametric ground motion prediction equation (GMPE), of which hundreds exist in the literature. However, relatively few are developed with a focus on induced seismicity. Developing GMPEs that are specific to an appropriate magnitude-distance range ( R < 30 km; 2 ≤ M ≤ 6 ) is important for induced seismicity applications. This paper proposes a framework for the development of physically-based GMPEs to provide more accurate and reliable estimates of the potential induced-seismicity ground motion hazard, allowing for better risk assessment and management strategies. To demonstrate this approach, a new set of GMPEs for the 2018-2019 induced seismicity sequence at the Preston New Road (PNR) shale gas site near Blackpool, United Kingdom, is presented. The physically-based GMPE was developed based on a pseudo-finite-fault stochastic ground motion simulation, calibrated with parameters derived from the spectral analysis of weak-motion records from induced seismic events. An optimization-based calibration technique using the area metric (AM) was subsequently performed to calibrate optimal parameters for simulating ground motion at the PNR site. Finally, using a suite of forward simulations for events with 1 ≤ M ≤ 6 recorded at distances up to 30 km, combined with empirical data, a location-specific GMPE was derived through adjustment of an existing model. [ABSTRACT FROM AUTHOR]

Magnetic flux leakage (MFL) is a non-destructive testing method for shale gas pipeline safety monitoring. Despite many pipelines have completed two or more rounds of internal inspection and have accumulated substantial data, effectively analyzing and utilizing this MFL data remains a significant challenge. To that end, this study proposes a novel combined model that integrates Iterative Closest Point (ICP) and DBSCAN (Density-Based Spatial Clustering of Applications with Noise) fusion to match multiple MFL data. The model outputs the matching result and visualisation images of MFL data acquired in different years. Furthermore, RMSE (root mean square error) and overlap rate have been used to evaluate the model. The results indicate that the average distance error of matched defects between two datasets decreased by 72.5%, and the overlap rate increased by 20%. Additionally, the DBSCAN Fusion shows better computational efficiency with an increase in defect quantity within the pipe segments. Finally, the impact of different datasets on the model’s matching accuracy is discussed in this study. The findings show that small-scale datasets or higher false detection rates lead to decreased accuracy. The proposed model fully leverages MFL data to achieve rapid matching of defects, offering a dependable and effective technical solution for safety monitoring and corrosion prediction in shale gas pipelines. [ABSTRACT FROM AUTHOR]

To solve the problem of thinning of the wall thickness of the sewage pipeline on the side of the shale gas separator of Sichuan E Oil and Gas Field Company, this study explores the reasons for the failure of sewage pipelines by macroscopic inspection, mechanical property experiment, metallographic structure analysis, (electron microscope scanning) SEM, (energy-dispersive spectrometry) EDS, (X-ray polycrystalline diffractometer) XRD, and CFD simulation analysis. Inspection found corrosion on the weld seam and inner wall surface of the pipeline. The elements in the corrosion products are mainly C, O, Fe, and Cl, and the corrosion products are mainly FeCO3. Therefore, one of the causes of pipeline failure is CO2 corrosion. Cl- exists in the transportation medium of the pipeline, which promotes CO2 corrosion under the action of acidification and autocatalysis; CFD simulation analysis found that the erosion of pipeline by grits is concentrated at the diameter change location of the pipeline, which is the same as the location of corrosion. Therefore, the cause of pipeline failure is the combined effect of CO2 corrosion and grits erosion. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is an effective technology for hydrocarbon extraction from unconventional shale and tight gas reservoirs. A potential risk of hydraulic fracturing is the upward migration of stray gas from the deep subsurface to shallow aquifers. The stray gas can dissolve in groundwater leading to chemical and biological reactions, which could negatively affect groundwater quality and contribute to atmospheric emissions. The knowledge of light hydrocarbon solubility in the aqueous environment is essential for the numerical modelling of flow and transport in the subsurface. Herein, we compiled a database containing 2129 experimental data of methane, ethane, and propane solubility in pure water and various electrolyte solutions over wide ranges of operating temperature and pressure. Two machine learning algorithms, namely regression tree (RT) and boosted regression tree (BRT) tuned with a Bayesian optimization algorithm (BO) were employed to determine the solubility of gases. The predictions were compared with the experimental data as well as four well-established thermodynamic models. Our analysis shows that the BRT-BO is sufficiently accurate, and the predicted values agree well with those obtained from the thermodynamic models. The coefficient of determination (R2) between experimental and predicted values is 0.99 and the mean squared error (MSE) is 9.97 × 10−8. The leverage statistical approach further confirmed the validity of the model developed. [ABSTRACT FROM AUTHOR]

Well shut-in time significantly affects the production performance of shale-gas-well. However, interaction between shale powders and fracking fluid on methane desorption has been rarely reported. In this work, based on the volume method following Boyle's law under higher pressure, the experimental setup was conducted to obtain the adsorption and desorption isotherms to explore the effect of different shut-in times (including 0, 1, 3, 5, 10, and 30 days) on methane desorption. We fitted the methane adsorption and desorption isotherms by the Freundlich model, and the results show that the interaction can obviously impact desorption isotherm, desorption efficiency and adsorbed phase methane content. The inflection points of the constant k and n reduction curves, desorption efficiency reduction curve and adsorbed gas content reduction curve all occur when the interaction time is to 10 days, indicating that 10 days is the best value for the interaction between slick water and gas shale. The results provide an essential supplement that can help elucidate the impact of shut-in time on gas-shale-well production performance experimentally. [ABSTRACT FROM AUTHOR]

Understanding the mechanism of solid-gas interface adsorption and gas injection displacement at the microscopic scale contributes to perfect the theory of shale gas extraction. GCGM (Grant Canonical Monte Carlo) and MD ( Molecular Dynamics) methods were consulted to simulate the methane adsorption and diffusion in the pores of rough wall structures. The investigation indicated that the rough structures significantly influence methane adsorption,which is greater in the rough models when the pressure is less than 20 MPa. The breakthrough time of carbon dioxide and methane recovery in the rough models are increased compared to the slit model during gas injection displacement. Due to the larger surface area of the rough shale models,the gas adsorption capacity is stronger at low pressure. The rectangular structures shale model has stronger selective adsorption than the triangular and silt models. The research clarifies the microscopic mechanism of methane absorption and displacement and provides guidance for improving shale gas recovery. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Based on sedimentary characteristics of the fine-grained rocks of the lower submember of second member of the Lower Cretaceous Shahezi Formation (K1sh2L) in the Lishu rift depression, combined with methods of organic petrology, analysis of major and trace elements as well as biological marker compound, the enrichment conditions and enrichment model of organic matter in the fine-grained sedimentary rocks in volcanic rift lacustrine basin are investigated. The change of sedimentary paleoenvironment controls the vertical distribution of different lithofacies types in the K1sh2L and divides it into the upper and lower parts. The lower part contains massive siliceous mudstone with bioclast-bearing siliceous mudstone, whereas the upper part is mostly composed of laminated siliceous shale and laminated fine-grained mixed shale. The kerogen types of organic matter in the lower and upper parts are types II2-III and types I-II1, respectively. The organic carbon content in the upper part is higher than that in the lower part generally. The enrichment of organic matter in volcanic rift lacustrine basin is subjected to three favorable conditions. First, continuous enhancement of rifting is the direct factor increasing the paleo-water depth, and the rise of base level leads to the expansion of deep-water mudstone/shale deposition range. Second, relatively strong underwater volcanic eruption and rifting are simultaneous, and such event can provide a lot of nutrients for the lake basin, which is conducive to the bloom of algae, resulting in higher productivity of types I-II1 kerogen. Third, the relatively dry paleoclimate leads to a decrease in input of fresh water and terrestrial materials, including Type III kerogen from terrestrial higher plants, resulting in a water body with higher salinity and anoxic stratification, which is more favorable for preservation of organic matter. The organic matter enrichment model of fine-grained sedimentary rocks of volcanic rift lacustrine basin is established, which is of reference significance to the understanding of the organic matter enrichment mechanism of fine-grained sedimentary rocks of Shahezi Formation in Songliao Basin and even in the northeast China. [ABSTRACT FROM AUTHOR]

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source-reservoir relationship and accumulation model of the Upper Triassic-Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight-conventional gas in the Upper Triassic-Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas-conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources. [ABSTRACT FROM AUTHOR]

The pivotal areas for the extensive and effective exploitation of shale gas in the Southern Sichuan Basin have recently transitioned from mid-deep layers to deep layers. Given challenges such as intricate data analysis, absence of effective assessment methodologies, real-time control strategies, and scarce knowledge of the factors influencing deep gas wells in the so-called flowback stage, a comprehensive study was undertaken on over 160 deep gas wells in Luzhou block utilizing linear flow models and advanced big data analytics techniques. The research results show that: (1) The flowback stage of a deep gas well presents the characteristics of late gas channeling, high flowback rate after gas channeling, low 30-day flowback rate, and high flowback rate corresponding to peak production; (2) The comprehensive parameter AcmKm1/2 in the flowback stage exhibits a strong correlation with the Estimated Ultimate Recovery (EUR), allowing for the establishment of a standardized chart to evaluate EUR classification in typical shale gas wells during this stage. This enables quantitative assessment of gas well EUR, providing valuable insights into production potential and performance; (3) The spacing range and the initial productivity of gas wells have a significant impact on the overall effectiveness of gas wells. Therefore, it is crucial to further explore rational well patterns and spacing, as well as optimize initial drainage and production technical strategies in order to improve their performance. [ABSTRACT FROM AUTHOR]

Today, China's main interest in geological exploration is focused on shale strata, whose high potential has already been proven in a number of fields, which ensures China's stable socio-economic growth. The goal of this study is to research and analyse the factors controlling the oil and gas potential of the peripheral zone of the Sichuan shale gas basin and the poorly studied folded region adjacent to the basin from the southeast. The materials of this study are represented by 15 core samples. The following research methods were used in this study: optical and electron microscopic examination of sections, tomography, geochemical studies and X-ray fluorescence analysis (XRF). The pore types were found to be intergranular and microfractures. The results of petrological, mineralogical and geochemical analyses of the Wufeng-Longmaxi Formation are presented. It was defined that the folded thrust area adjacent to the Sichuan Basin from the southeast is not of practical interest. [ABSTRACT FROM AUTHOR]

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (IR) to denote the intensity of these reactions. Based on the IR value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater IR, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well. [ABSTRACT FROM AUTHOR]

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Accurate shale gas reserves estimation is essential for development. Existing machine learning (ML) models for predicting gas isothermal adsorption are limited by small datasets and lack verified generalization. We constructed an "original dataset" containing 2112 data points from 11 measurements on samples from 8 formations in 3 countries to develop ML‐based prediction models. Similar to previous ML models, total organic matter, pressure, and temperature are characterized as the three most significant features using the mean impurity method. In contrast to previous ML models, the study reveals that these three features are inadequate to be used to make reasonable predictions for the datasets from the measurements different from those used to train the models. Instead, the extreme gradient boosting decision trees (XGBoost) model with two more features (specific surface area and moisture) exhibits good robustness, generalization, and precision in the prediction of gas isothermal adsorption. Overall, An XGBoost model with optimal input features is developed in this work, which exhibits both good performance in gas adsorption prediction and good potential for the estimation of gas storage in shale gas development. [ABSTRACT FROM AUTHOR]

Well logging interpretation and evaluation of reservoirs in horizontal wells plays an important role in shale gas exploration and development. The accuracy of the interpreted petrophysical parameters is directly affected by well logging curves. This study focuses on a horizontal well targeting deep shale gas layers in the Luzhou block, Southern Sichuan Basin. It employs an interactive forward and inversion scheme to precisely reconstruct the borehole trajectory using a comprehensive dataset encompassing well logs, mud logs, and seismic data. The research introduces a method for anisotropic correction of sonic log, crucial for calculating reservoir parameters, and assess payzone targeting in the horizontal well. The research results show that the interactive forward and inverse simulation method can achieve the recovery of horizontal well borehole trajectory and finely delineate the sublayers, improving the evaluation accuracy of platinum target drilling encounter ratio by over 6%. Numerically simulated acoustic wave can be used to carry out the anisotropy correction of acoustic wave in horizontal wells and calculate reservoir parameters, reducing the relative error in computed porosity to 1.72%. The comprehensive logging evaluation results from both geological and engineering aspects provide the data basis for planning the fracturing program of the shale gas horizontal well. This research has established a new method and idea for well logging evaluation in shale gas horizontal wells, marking a significant step toward integrating geological and engineering aspects in shale gas exploration. [ABSTRACT FROM AUTHOR]

Recent exploration efforts have revealed significant industrial gas flow from the Wujiaping Formation marine shale in the Longmen-Wushankan area of the eastern Sichuan Basin, underscoring its considerable exploration potential. In this study, the reservoir characteristics and exploration potential of the Wujiaping Formation shale gas in this area are further evaluated. On the basis of well rock electrical properties, experimental analyses, and depositional and structural patterns in the eastern region, we characterize the reservoir properties and identify the primary factors controlling shale gas accumulation. The results indicate that the Wujiaping shale is characterized by a high organic matter content, favorable pore types, high porosity, and a high content of brittle minerals, which are conducive to subsequent development and fracturing. A positive correlation is observed between the total organic carbon (TOC) content, porosity, brittle mineral content, and shale gas content. The TOC content is strongly correlated with the gas content (the correlation coefficient is 0.75). The high shale gas yield of the Wujiaping Formation is attributed to a combination of favorable sedimentary environments, pore conditions, roof and floor conditions, and fracturing capabilities. However, compared with the Longmaxi Formation in the Sichuan Basin, the Wujiaping Formation shale is characterized by a lower porosity, thinner shale, and deeper burial, posing challenges for exploration and development. In this study, criteria for evaluating Wujiaping Formation shale gas are established, and four favorable exploration areas are identified. Overall, the Permian Wujiaping Formation marine shale in the Longmen-Wushankan area holds promising exploration and development potential. Further exploration and an enhanced understanding of this formation will provide valuable guidance for future marine shale gas exploration and development in this area. [ABSTRACT FROM AUTHOR]

Nano-plugging agents have become the key to efficiently extracting shale gas, which is a clean energy source. Poly-(St-(1-Octene)-EGDMA) was synthesized by emulsion polymerization of 1-octene, styrene (St), and ethylene dimethacrylate (EGDMA). Fourier transform infrared spectroscopy, laser scattering, thermogravimetric analysis, scanning electron microscopy (SEM), pressure transfer experiment, and artificial mud cake plugging experiments were used to characterize poly-(St-(1-Octene)-EGDMA). The results indicate that poly-(St-(1-Octene)-EGDMA) has a particle size of 38.8 nm. After 16 h at 180 °C, the particle size is 49 nm. Based on thermogravimetric analysis, poly-(St-(1-Octene)-EGDMA) can tolerate temperatures up to 394 °C, demonstrating excellent high-temperature stability. The rheology of the drilling fluid remains unaltered by poly-(St-(1-octene)-EGDMA). With the addition of 2% poly-(St-(1-octene)-EGDMA) water-based drilling fluid, the permeability decreased to 2.4 × 10–3 mD and the blocking rate increased to 50%. Simulations are performed with Ansys Fluent 19.2 to verify the experimental results. The potential plugging mechanism of poly-(St-(1-Octene)-EGDMA) as a plugging agent was explored. Shale nanopores and nanofractures are invaded by poly-(St-(1-Octene)-EGDMA) under pressure. Shale nanopores and nanofractures are plugged by poly-(St-(1-Octene)-EGDMA). In water-based drilling fluids, poly-(St-(1-Octene)-EGDMA) has a broad range of applications as a possible nano-plugging agent. [ABSTRACT FROM AUTHOR]

Current shale gas well production capacity predictions primarily rely on analytical and numerical simulation methods, which necessitate extensive calculations and manual parameter tuning and produce lowly accurate predictions. Although employing neural networks yields highly accurate predictions, they can easily fall into local optima. This paper suggests a new way to use Cuckoo Search (CS)-optimized neural networks to make shale gas well production capacity predictions more accurate and to solve the problem of local optima. It aims to assist engineers in devising more effective development plans and production strategies, optimizing resource allocation, and reducing risk. The method first analyzes the factors influencing the production capacity of shale gas wells in a block located in western China through correlation coefficients. It identifies the main factors affecting the gas test absolute open flow as organic carbon content, small-layer passage rate, fracture pressure, acid volume, pump-in fluid volume, brittle mineral content in the rock, and rock density. Subsequently, we used the CS algorithm to conduct the global training of the neural network, avoiding the problem of local optima, and established a neural network model for predicting shale gas well production capacity optimized by the CS algorithm. A comparative analysis with other relevant methods demonstrates that the CS-optimized neural network model can accurately predict production capacity, enabling a more rational and effective exploitation of shale gas resources, which lower development costs and increase the economic returns of oil and gas fields. Compared to numerical simulation, SVM, and BP neural network algorithms, the CS-optimized BP neural network (CS-BP) exhibits significantly lower prediction error. Its correlation coefficient between predicted and actual values reaches as high as 0.9924. Verification experiments conducted on another shale gas well also demonstrate that, in comparison to the BP neural network algorithm, CS-BP offers superior prediction performance, with model validation showing a prediction error of only 0.05. This study can facilitate more rational and efficient exploitation of shale gas resources, reduce development costs, and enhance the economic benefits of oil and gas fields. [ABSTRACT FROM AUTHOR]

The evaluation methods for shale gas resources and the key parameters involved are diverse. The main research object of this article is the key parameters in shale gas resource evaluation, and this study aims to quantitatively evaluate the required key parameters for calculation, thereby improving the credibility of shale gas resource evaluation results. This article mainly analyzes the weight analysis of the key parameters used in the resource evaluation process, focusing on the analysis and determination of key parameters controlling the generation, enrichment, and preservation of shale gas. The key parameters are graded and evaluated layer by layer, and the common key parameters that participate in the determination are extracted. Based on the above analysis, a weight conversion model is proposed to quantitatively evaluate the actual importance of key parameters in resource evaluation. By combining statistical research, the partial correlation coefficients in the correlation coefficients are applied to estimate the resource quantities in the exploration field in order to quantitatively evaluate the credibility of the resource evaluation results. This article focuses on the weight assignment of key parameters for calculating the resource quantity of the Jiaoshiba shale gas field in the Fuling area of Chongqing and obtains different weight results for different parameters. Using this method to assign key parameter weights to the target block can provide reliable parameter support for shale gas resource evaluation and provide strong support for shale gas resource estimation. [ABSTRACT FROM AUTHOR]