Shale Reservoirs Research Articles

Fluid–rock interaction controlled by integrated hydrothermal fluid and fault: Implications for reservoir development

Hydrothermal activity is prevalent in petroliferous basins, particularly in fractured reservoirs. Hydrothermal fluids enter the reservoirs and cause significant fluid–rock interaction, which ultimately controls reservoir development. The Mahu Sag in western China is a hydrocarbon-rich region where hydrothermal fluids and faults control the reservoirs, making it challenging to understand the development mechanism of the shale reservoirs. This study focused on the Fengcheng Formation in the Mahu Sag. Based on a range of previous lithological test results, numerical models of hydrothermal fluid charging were established to explore differences in fluid–rock interactions under varying temperature, fluid, and flow rates. Results revealed that within a specific range, increasing temperature and Mg2+ concentration promoted hydrothermal processes. The hydrothermal flow rate influenced ion accumulation on the fluid-rock contact surface, thus controlling mineral dissolution rates. In a certain range, when the flow rate is increased by 3 times, the growth rate of dolomite content is increased by more than 15 times. Hydrothermal fluid flowing near the fault underwent chemical action more readily than in other areas. The influence of hydrothermal fluid and fault on reservoir development was both constructive and destructive. The decrease and increase of porosity are 30 % and 25 %, respectively. This study could provide a theoretical basis for identifying factors influencing shale reservoir development.

Robotics and artificial intelligence in unconventional reservoirs: Enhancing efficiency and reducing environmental impact.

Shale, tight gas, and coal bed methane reservoirs are unconventional reservoirs that have geometrically complicated geological formations with low permeability, rendering their extraction operations difficult, expensive, and environmentally sensitive. On the other hand, recent developments in Robotics and Artificial Intelligence continue to transform how exploration, production, and maintenance activities are carried out in these reservoirs. This review paper encompasses how Robotics and AI technologies are applied to these unconventional reservoirs, improving operation efficiency, increasing the recovery rate and minimizing environmental damage. It updates on the latest status of autonomous drilling, AI-driven reservoir characterization and robotic fracturing. The paper also discusses future opportunities: emerging technologies, integration of AI with predictive analytics, and innovations toward sustainability. These are the challenges that come with possible solutions discussed in the paper: high costs, technical integration, and data quality. The review thereby presents the thought that robotics and AI will take a transformative role in the unconventional reservoir sector during the next few years, both in economic performance and environmental sustainability.

Refracturing Time Optimization Considering the Effect of Induced Stress by Pressure Depletion in the Shale Reservoir

Refracturing is an important technology for tapping remaining oil and gas areas and enhancing recovery in old oilfields. However, a complete and detailed refracturing timing optimization scheme has not yet been proposed. In this paper, based on the finite volume method and the embedded discrete fracture model, a new coupled fluid flow/geomechanics pore-elastic-fractured reservoir model is developed. The COMSOL 3.5 commercial software was used to verify the accuracy of our model, and by studying the influence of matrix permeability, initial stress difference, cluster spacing, and fracture half-length on the orientation of maximum horizontal stress, a timing optimization method for refracturing is proposed. The results of this paper show that the principle of optimizing the refracturing timing is to avoid the time window where the percentage of Type I (Type I indicates that stress inversion has occurred, 0∘≤α≤20∘; Type II indicates that the turning degree is strong, 20∘<α≤70∘; and Type III indicates less stress reorientation, 70∘<α≤90∘) stress reorientation area is relatively large, so that the fractures can extend perpendicular to the horizontal wellbore. At the same time, the simulation results show that with the increase in production time, the percentage of Type I and Type II increases first and then decreases, while the percentage of Type III decreases first and then increases. When the reservoir permeability, stress difference, and cluster spacing are larger, the two types of refracturing measures can be implemented earlier. But, with the increase in fracture half-length, the timing of refracturing Method I is earlier, and the timing of refracturing Method II is later. The research results of this paper are of great significance to the perfection of the refracturing theory and the optimization of refracturing design.

Hydrophilic Chain Length for Octylphenol Polyoxyethylene Ether Adsorption at the n-Hexadecane-Water Interface: Theoretical and Experimental Study.

With the advancement of technologies for developing tight and shale reservoirs, nonionic surfactants have garnered significant attention due to their remarkable properties. The structure of these surfactants plays a crucial role in determining the characteristics of the oil-water interface, particularly influencing emulsification behavior and crude oil recovery. This study investigates the effect of varying the number of hydrophilic polar groups (n = 10, 20, 30, 50) in octylphenol polyoxyethylene ether (OP-n) on its adsorption behavior at the n-hexadecane-water interface using molecular dynamics simulation. The impact of these variations on interfacial properties was further analyzed through measurements of interfacial tension and observations of emulsion droplet morphology. The study results indicate that variations in the number of hydrophilic polar groups significantly affect interfacial properties. Increasing the number of hydrophilic polar groups led to a notable increase in the thickness of the n-hexadecane or water phase, as well as the thickness of the water or oil layer and the surfactant layer. Moreover, when the number of hydrophilic polar groups reached 20, the OP-n molecules exhibited a more curled conformation at the interface, enhancing their ability to encapsulate water and resulting in a decrease in the diffusion coefficient of the molecules in each phase. Additionally, interfacial tension was found to be positively correlated with the number of hydrophilic polar groups and remained unchanged beyond a certain emulsion diameter. This study provides a theoretical basis and reference data for optimizing surfactant structures to improve crude oil recovery.

Integrated study of hydraulic/CO2 fracturing and production coupled with a THM-D process in ultra-shallow shale reservoirs

To explore fracturing technology for vertical wells in ultra-shallow shale gas reservoirs, a coupled thermo-hydro-mechanical-damage (THM-D) fracturing and production integration model is established in this study. In addition, a new coupled hydro-mechanical damage model is established to calculate fracture evolution. These two models are validated through theoretical models and field data, respectively. Based on these models, the quality of fracturing under different geological parameters, fracturing parameters, and fracturing technology is compared and analyzed. The results show that the distribution of natural fractures significantly influences fracturing and production. In addition, due to the high leak-off in the ultra-shallow shale reservoir, the total fracture length and cumulative production after 720 days of carbon dioxide fracturing are only 70.35% and 77.26% of the values achieved by hydraulic fracturing, respectively. Therefore, it is necessary to consider reducing carbon dioxide leak-off in the design of carbon dioxide fracturing in ultra-shallow shale reservoirs. Fracturing efficiency also should be considered when designing fracturing time. When the injection rate is 5 m3/min, the efficiency drops sharply if the fracturing time exceeds 67.45 min. The production of hydraulic fracturing and carbon dioxide fractured wells has also been studied when fracturing methods without proppant are used. This study found that a satisfactory production rate can also be achieved in ultra-shallow shale gas reservoirs when fracturing without proppant.

Modeling the effect of dispersion and attenuation for frequency-dependent amplitude variation with offset

As research in oil and gas exploration progresses, unconventional resources, such as shale gas, are increasingly becoming the focal point in the global pursuit of oil and gas resource. Shale gas reservoirs significantly differ from conventional sandstone reservoirs in aspects such as rock composition, pore type, occurrence mode, fluid, etc., thereby amplifying the challenges associated with geophysical modeling and the prediction of sweet spots. Since the formation and storage of shale gas are positively correlated with shale fracturing, a modeling approach based on Chapman theory is introduced to complete frequency-dependent petrophysical modeling. Additionally, the Frequency-dependent Amplitude Variation with Offset (FAVO) technique can estimate velocity dispersion by using the reflection coefficient information related to incidence angle and frequency. This method can more effectively identify fluids within shale reservoir. However, current FAVO forward modeling only considers the velocity dispersion and attenuation at the interface, neglecting the attenuation dispersion effects during interlayer propagation. To this end, we utilize Chapman-based petrophysical modeling as a foundation and conduct seismic forward modeling studies employing the compound matrix method. Through experimental analysis, we meticulously examine the attenuation dispersion effects at interfaces and within layers. Finally, we conduct FAVO simulations that vividly delineate the interplay between reservoir parameters and seismic responses.

An improved convolutional architecture for quantitative characterization of pore networks in fine-grained rocks using FIB-SEM

Focused ion beam scanning electron microscope (FIB-SEM) is one of the most advanced imaging techniques for analyzing and understanding complex pore networks in shale and other fine-grained formations. However, FIB-SEM imaging tends to be time-consuming and labor-intensive and can result in biased interpretations associated with pore analysis. Recently, U-Net or its variants for image segmentation have been applied to capture microscopic pores at higher resolutions. The ‘traditional’ encoder-decoder-based approaches tend to detect very fine-scale microscopic pores poorly. This study presents an improved convolutional architecture for automatically analyzing pore structures in shale reservoirs using FIB-SEM. It does so by applying an overcomplete convolutional architecture, KiU-Net, to capture very fine-scale microscopic pores by accurately defining their edges in the input FIB-SEM images. The KiU-Net learns low and high-level features by making the model more sensitive to fine-scale microscopic pores in the input images. The purpose of this study is to demonstrate KiU-Net's capabilities by analyzing different shale formations with varying characteristics. The results indicate that KiU-Net is more accurate and efficient than other methods in predicting nanopores in the Longmaxi, Niutitang, Qingshankou, Qianjiang, and Yanchang Formations (China), Bakken shale (Canada), and coal reservoirs (China). Furthermore, KiU-Net demonstrated the advantage of requiring fewer parameters and achieving super convergence compared to the Attention U-Net technique. KiU-Net addresses the challenges of the Edge-Threshold Automatic Processing (ETAP) methods by capturing very fine-scale microscopic pores with accurate edges. This study further enhances the accuracy and efficiency of pore analysis in shales, thereby offering an improved method for understanding shale reservoir quality with the potential to improve petroleum recovery from such formations.

Phase behavior analysis of methane confined in nanopores using molecular simulation

Interest in the phase behavior of hydrocarbons in shale reservoirs has grown in recent years. Petroleum fluid phase behavior has been observed to differ significantly between conventional reservoirs and shale reservoirs. Within shale reservoirs, notable surface-fluid interactions can lead to non-uniform molecule distribution and an alteration in fluid phase behavior, primarily caused by the existence of nano-scale porous materials. In this work, we study the phase behavior of methane in single cylindrical pore models. We apply the gauge Gibbs ensemble Monte Carlo (gauge-GEMC) simulation technique to investigate the phase behavior of methane in 4–10 nm single nanopores and calculate the saturation pressures at various temperatures using the grand canonical Monte Carlo (GCMC) simulation technique. A shift in the phase diagram has been found for methane in nanopores. As pore size decreases, the shift becomes more significant.

Analysis of the Impact of Clusters on Productivity of Multi-Fracturing Horizontal Well in Shale Gas

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.

A modified surface to volume (SVR) method to calculate nuclear magnetic resonance (NMR) surface relaxivity: Theory and a case study in shale reservoirs

Surface relaxivity (ρ2) is a critical parameter for converting nuclear magnetic resonance (NMR) T2 data to pore size distribution (PSD). The surface-to-volume ratio (SVR) method, known for its simplicity and ease of operation, has been widely used for ρ2 calculation in unconventional reservoirs. However, previous studies often overlooked the equivalence of pore ranges characterized when directly applying the classical SVR model. Moreover, shale reservoirs generally develop layered fractures, whose ρ2 values are different from matrix pores. The logarithmic mean value of the T2 distribution (T2LM) is significantly influenced by layered fractures, therefore, relying solely on the T2LM value of a whole sample under fluid-saturated state will lead to inaccurate ρ2 values of matrix pores, particularly in laminated shales where fractures are well developed. However, insufficient attention has been paid to the effect of fractures on the ρ2 calculation. In this study, a modified SVR method based on the theory of NMR relaxation in partially fluid-saturated pores was proposed to characterize the ρ2 of shale matrix pores. Twenty-four shale core samples from the Shahejie Formation in the Jiyang Depression, China were selected, and subjected to series of NMR experiments at varying oil-bearing conditions, and low-temperature nitrogen adsorption (LTNA) analysis. The results indicate a strong linear correlation (R2 > 0.85) between the inverse T2LM (1/T2LM) and the inverse fluid saturation (1/f) when oil molecules across the entire surface layer participate in the exchange process. For a whole core sample, ρ2 values obtained using the modified SVR model are higher than those obtained using the classical SVR model, especially in samples with numerous fractures. The modified SVR method effectively reduces the impact of fractures on the characterization of ρ2 of matrix pores. For shale pore ρ2 characterization, the classical SVR model may be more suitable for pores smaller than 300 nm, with a recommended T2 range of <33 ms. Additionally, ρ2 values for different pore ranges (<25 nm, 25–100 nm, and >100 nm) within individual samples were estimated. It is found that the ρ2 values of smaller pores is greater than those of larger pores, which may be due to differences in mineralogy of the pores across various size ranges. The small pores are more associated with clay minerals while large pores are surrounded by quartz and rigid minerals. In addition, ρ2 is lower in larger pores and fractures that do not contain organic matter and clays, thus the underestimation of ρ2 by the classical SVR method can be corrected by modified SVR method. This study represents the first attempt to examine ρ2 variations across different pore ranges in shale reservoirs. The methodology presented can be applied to other formations, enhancing NMR data application in both laboratory settings and well logging.

Analysis of Controlling Factors of Pore Structure in Different Lithofacies Types of Continental Shale—Taking the Daqingzi Area in the Southern Songliao Basin as an Example

Due to the influence of terrigenous debris, the internal pore structure of continental shale is highly heterogeneous, and the controlling factors are complex. This paper studies the structure and controlling factors of shale reservoirs in the first member of the Qingshankou Formation in the Southern Songliao Basin using core data and various analytical test data. The results show that the original deposition and subsequent diagenesis comprehensively determine the shale reservoirs’ pore structure characteristics and evolution law. According to the severity of terrigenous debris, the shale reservoirs in the study area are divided into four categories and six subcategories of lithofacies. By comparing the characteristics of different shale lithofacies reservoirs, the results show that the lithofacies with a high brittle mineral content have more substantial anti-compaction effects, more primary pores to promote retention and a relatively high proportion of mesopores/macropores. Controlling the organic matter content when forming high-quality reservoirs leads to two possibilities. An excessive organic matter content will fill pores and reduce the pore pressure resistance. A moderate organic matter content will make the inorganic diagenesis and organic hydrocarbon generation processes interact, and the development of organic matter mainly affects the development of dissolution pores. The comprehensive results show that A3 (silty laminated felsic shale) reservoirs underwent the pore evolution process of “two drops and two rises” of compaction, cementation and pore reduction, dissolution and pore increase, and organic matter cracking and pore increase, and they are the most favourable lithofacies of the shale reservoirs in the study area.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

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.

Geological and Engineering Integration Fracturing Design and Optimization Study of Liushagang Formation in Weixinan Sag

The Weixinan Sag in the Beibuwan Basin is rich in shale oil resources. However, the reservoirs exhibit rapid phase changes, strong compartmentalization, thin individual layers, and high-frequency vertical variations in the thin interbedded sandstone and mudstone. These factors can restrict the height of hydraulic fracture propagation. Additionally, the low-porosity and low-permeability shale oil reservoirs face challenges such as low production rates and rapid decline. To address these issues, the Plannar3D full 3D fracturing model was used to simulate hydraulic fracture propagation and to study the main controlling factors for fracture propagation in the second member of the Liushagang Formation. Based on the concept of geological–engineering integration, a sweet spot evaluation was conducted to identify reservoirs with relatively better brittleness, reservoir properties, and oil content as the fracturing targets for horizontal wells. The UFM model was then applied to optimize fracturing parameters. This study indicates that the matrix-type oil shale has a high clay mineral content, resulting in a low Young’s modulus and poor brittleness. This makes hydraulic fracture propagation difficult and leads to less effective reservoir stimulation. In contrast, hydraulic fractures propagate more easily in high-brittleness interlayer-type oil shale. Therefore, it is recommended to prioritize the extraction of shale oil from interlayer-type oil shale reservoirs. The difference in interlayer stress is identified as the primary controlling factor for cross-layer fracture propagation in the study area. Based on the concept of geological–engineering integration, a sweet spot evaluation standard was established for the second member of the Liushagang Formation, considering both reservoir quality and engineering quality. Four sweet spot zones of interlayer-type oil shale reservoirs were identified according to this evaluation standard. To achieve uniform fracture initiation, a differentiated segment and cluster design was implemented for certain high-angle sections of well WZ11-6-5d. Interlayer-type oil shale was selected as the fracturing target, and the UFM was used for hydraulic fracture propagation simulation. Fracturing parameters were optimized with a focus on hydraulic fracture characteristics and the estimated ultimate recovery (EUR). The optimization results were as follows: a single-stage length of 50 m, cluster spacing of 15 m, pump injection rate of 10 m3/min, fluid intensity of 25 m3/m, and proppant intensity of 3.5 t/m. The application of these optimized fracturing parameters in field operations resulted in successful fracturing and the achievement of industrial oil flow.

Multi-scale model for evaluating stress fluctuation in shale gas reservoirs considering geomechanical heterogeneity

In this article, a numerical model considering multi-scale flow and heterogeneity of shale reservoirs is developed to analyze the spatiotemporal evolution of the stress field in shale gas production. After considering the geomechanical heterogeneity, the variation in the local rock mechanical parameters of the reservoir, and the increase in the effective stress of the reservoir will cause local stress fluctuations. In the hydraulic fracture control area, the average stress fluctuation coefficient is higher, indicating a stronger “stress heterogeneity.” When the homogeneity increases from 5 to 100, the fluctuation range of the minimum horizontal principal stress increases by 28.89 MPa, and the fluctuation range of the principal stress difference increases by 7.35 MPa. The presence of natural fractures can significantly impact the coupled hydraulic-mechanical processes of the reservoir, increasing the number of high-speed permeation channels penetrating the system. The greater the density and permeability, the smaller the minimum horizontal principal stress and the larger the principal stress difference. The angle of natural fractures directly influences the direction of stress drop, with an average minimum horizontal principal stress occurring when the angle of natural fractures is at 60°/120°.

Multilayer Adsorption Characteristics of CO2 in Organic Nanopores with Different Pore Sizes: Molecular Simulation and Ono-Kondo Lattice Model.

Shale contains numerous organic micropores with significant potential for CO2 storage. To precisely evaluate the CO2 storage potential of shale reservoirs, it is essential to accurately quantify the adsorption of CO2 within these pores. This study used Grand Canonical Monte Carlo (GCMC) molecular simulations to analyze the CO2 adsorption behavior in organic micropores of varying sizes. The study clarified the number and width of the CO2 adsorption layers in micropores of various sizes and proposed a method for segmenting the multilayer adsorption structure. Additionally, the classic Ono-Kondo lattice (OK) model was extended to characterize pore-filling adsorption, incorporating solid-gas and gas-gas interactions. Accurate characterization of CO2 multilayer adsorption and precise calculation of CO2 absolute adsorption in micropores were achieved. Results indicate that CO2 exhibits pore-filling adsorption behavior in organic micropores, forming a multilayer adsorption structure governed by the pore size. Following symmetry principles, the adsorption layer structure in organic micropores can be simplified to a maximum of three layers. When only one adsorption layer forms, its width equals the gas-accessible pore size. For two or more layers, the width of the original layer stabilizes as additional layers form. The stable adsorption layer widths, from nearest to farthest from the pore wall, are 0.33, 0.45, and 0.39 nm. The improved OK model accurately describes CO2 excess and absolute adsorption isotherms across different pore sizes and calculates the CO2 density in each adsorption layer, showing high consistency with GCMC simulation results. These findings highlight the importance of understanding the CO2 multilayer adsorption structure for accurately estimating CO2 adsorption in organic micropores.

Pore Space Characteristics and Migration Changes in Hydrocarbons in Shale Reservoir

Pore Space Characteristics and Migration Changes in Hydrocarbons in Shale Reservoir

Surrogate Model of Shale Stress Based on Plackett-Burman and Central Composite Design

Summary Multifactor analysis and accurate prediction of dynamic stress in shale reservoirs are of great practical significance for designing hydraulic fracturing. In this paper, a surrogate model for the rapid prediction of shale stress is proposed by considering the geomechanical heterogeneity and multiscale seepage mechanism of shale gas. The Plackett-Burman method is used to compare the influence of different parameters on shale stress, and significant parameters are selected as decision variables for establishing a surrogate model. The surrogate model for predicting stress is obtained by central composite design fitting, and the interaction of significant factors on shale stress is studied. The results show that after considering the heterogeneity, the minimum horizontal stress fluctuation range is 20.25 to 44.03 MPa and the maximum horizontal stress fluctuation range is 26.46 to 49.77 MPa in the area controlling hydraulic fracture. The initial reservoir pressure, as well as the length and width of hydraulic fractures, are the key factors influencing reservoir stress. The analysis of variance demonstrates that the proposed method is effective for predicting shale stress. The research results are helpful for gaining a deeper understanding of the evolution mechanism of dynamic stress fields in shale reservoirs and provide guidance for treatment design and dynamic optimization of gas wells.

Three-dimensional physical experimental study on mechanisms and influencing factors of CO2 huff-n-puff and flooding process in shale reservoirs after fracturing

Carbon dioxide (CO2) capture and geological storage technology is a promising strategy for enhancing oil and gas production and mitigating climate change in unconventional formations. In shale reservoirs, production decline is rapid under volumetric fracturing development. Currently, CO2 injection and huff-n-puff techniques are cost-effective methods to boost shale oil recovery. However, traditional huff-n-puff techniques are limited in capturing reservoir heterogeneity and intricate fracture conditions. This study employed a three-dimensional physical experimental apparatus to explore CO₂ huff-n-puff dynamics across six distinct fracture patterns. By implementing a real-time monitoring system with multiple pressure points, the study elucidated the impacts of varying fracture penetration levels and spacing on dynamic pressure wave patterns, mobilization extent, and development outcomes during CO2 huff-n-puff. The results demonstrate that fractures substantially improve CO₂ huff-n-puff efficiency in shale reservoirs compared to a seamless model, with Model 6 achieving the highest recovery rate of 42.38%. As fracture penetration increases, CO₂ dynamic coverage expands. However, full penetration leads to preferential flow through fractures, reducing matrix contact and diminishing huff-n-puff efficiency. Reduced fracture spacing enlarges the well's control domain, amplifies CO2 huff-n-puff dynamic coverage area, and increases oil production and recovery rate. Conversely, decreasing fracture spacing accelerates oil and gas displacement rates, leading to higher economic expenses. The study concludes that 2/3 fracture penetration in five fractures offers the most efficient recovery method. For a 500 m horizontal well, optimal fracture spacing is recommended at 125 m, with a fracture length of 145.8 m for a well spacing of 417 m.

Classification systems of pore-fractures structures and its effects on fracturing fractures propagation in shale reservoir

Marine shales serve as the primary source of shale gas in China, having attained industrial development, whereas transitional shales constitute a significant focus for ongoing exploration and exploitation. Understanding the pore-fracture structures in marine and transitional shales is strategic importance for the advancement of shale gas and oil resources in China. This study focuses on marine and transitional shales, using core samples for physical simulations to classify pore-fracture structures and reveal their impact on fracturing fractures propagation. The pore-fracture structures in shale are categorized into three primary types: pore-pore, pore-fracture, and fracture-fracture structures, with further subdivision into 12 subtypes based on the spatial distribution and types of pores and fractures. The genesis types of pore-fracture structures in different depositional facies were revealed, and characteristic models for the development of pore-fracture structure development were established. In marine shales, dense pore, pores-within-pores and interconnected pore structures are primarily controlled by organic hydrocarbon generation, as well as interconnected fracture structures formed under depositional and stresses. Interconnected fracture structures, being advantageous, are the primary targets for enhancing fracture connectivity and extension. Meanwhile, fracturing fractures preferentially connect with interconnected fracture structures developed between minerals, followed by those between clay and mineral particles. The influence of trending fracture structures on fracturing fractures is location-dependent; structures developed between skeleton mineral particles facilitate fracturing fractures propagation, while the ends of trending fracture structures retain energy, promoting spontaneous connection with surrounding pore-fracture structures, resulting in secondary fractures and aiding in multi-directional fracture propagation, enhancing the effectiveness of fracturing treatments and providing valuable theoretical support for their design.

Utilization law of shale gas in hydraulic fracturing with the Changning–Weyuan block in China as an example

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.