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Copyright of Tunnel Construction / Suidao Jianshe (Zhong-Yingwen Ban) is the property of Tunnel Construction Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

To reveal the shale oil occurrence state and its controlling factors of the Jurassic Lianggaoshan Formation in the Sichuan Basin, experimental analyses, including total organic content, X-ray diffraction, low-temperature nitrogen adsorption-desorption, nuclear magnetic resonance, conventional, and multistage rock-eval, were conducted on the shale samples. The shale oil occurrence state, the amount/proportion of adsorbed/free oil, and their control factors were clarified. Moreover, the classification evaluation standard of shale oil resources was then determined. The results show that the selected shales are characterized by large oil contents. Total oil ranges from 0.08 mg/g to 10.06 mg/g (mean 2.82 mg/g). Adsorbed oil is between 0.03 mg/g and 5.66 mg/g (1.64 mg/g), while free oil spans from 0.05 mg/g to 4.94 mg/g (1.21 mg/g). The higher the total oil content, the higher the free oil content, indicating that the free oil sweet spot corresponds to the shale oil resource sweet spot. Shale oil is mainly adsorbed in organic matter; the larger TOC content results in the higher adsorbed oil content. Residual shale oil primarily occurs in pores less than 100 nm in diameter, and a higher pore volume corresponds to a higher total oil content. The shale oil enrichment resources refer to the shale with the TOC > 1.5%, S1 > 1.5 mg/g, and S1/TOC > 45 mg/g. This study is helpful for the prediction of shale oil resources and optimizing sweet spots in the Jurassic Lianggaoshan Formation of the Sichuan Basin. [ABSTRACT FROM AUTHOR]

A single planar hydraulic fracture is typically the primary component used to simulate hydraulic fracturing stimulation in conventional reservoirs. However, in ultra-low-permeability shale reservoirs, a large system of fracture networks must be generated to produce hydrocarbons economically. Therefore, traditional modeling approaches centered on single planar fractures are inadequate for accurately representing the intricate geometry and behavior of fractures in these reservoirs. In previous works, 2D fractal fracture networks (FFNs) have been used to generate sets of hydraulic and natural fractures based on microseismic event (MSE) data. Since microseismic data are retrieved in 3D space, the aforementioned model cannot accurately represent induced fracture properties. The objective of this paper is to study in detail the recently developed 2D FFN model and propose a novel solution by expanding the previous model to accommodate real 3D microseismic data. First, the definitions of the 2D FFN model are described, and associated calibration mechanisms are proposed. Next, the 3D FFN model and its calibration system are demonstrated. While the novel 3D calibration solution utilizes an identical matching concept to the 2D methodology, the residual distances between the nodes and the MSE are calculated in 3D spaces. Finally, a set of real microseismic data are used to calibrate the generation of 3D fractals using the proposed workflow. The interactions between microseismicity and fractured reservoir dynamics are represented through the integration of fractal fracture models and microseismic data. This work contributes to advancing the current understanding of hydraulic fracturing in unconventional reservoirs and provides a valuable framework for improving fracture modeling's accuracy in reservoir engineering applications. [ABSTRACT FROM AUTHOR]

Shale is a common rock in oil and gas extraction, and the study of its nonlinear mechanical behavior is crucial for the development of engineering techniques such as hydraulic fracturing. This paper establishes a new coupled elastic–plastic damage model based on the second law of thermodynamics, the strain equivalence principle, the non-associated flow rule, and the Drucker–Prager yield criterion. This model is used to describe the mechanical behavior of shale before and after peak strength and has been implemented in ABAQUS via UMAT for numerical computation. The model comprehensively considers the quasi-brittle and anisotropic characteristics of shale, as well as the strength degradation caused by damage during both the elastic and plastic phases. A damage yield function has been established as a criterion for damage occurrence, and the constitutive integration algorithm has been derived using a regression mapping algorithm. Compared with experimental data from La Biche shale in Canada, the theoretical model accurately simulated the stress–strain curves and volumetric–axial strain curves of shale under confining pressures of 5 MPa, 25 MPa, and 50 MPa. When compared with experimental data from shale in Western Hubei and Eastern Chongqing, China, the model precisely fitted the stress–strain curves of shale at pressures of 30 MPa, 50 MPa, and 70 MPa, and at bedding angles of 0°, 22.5°, 45°, and 90°. This proves that the model can effectively predict the failure behavior of shale under different confining pressures and bedding angles. Additionally, a sensitivity analysis has been performed on parameters such as the plastic hardening rate b, damage evolution rate Bω, weighting factor r, and damage softening parameter a. This research is expected to provide theoretical support for the efficient extraction technologies of shale oil and gas. [ABSTRACT FROM AUTHOR]

Temporary plugging and diverting fracturing (TPDF), involving inner-fracture temporary plugging (IFTP) and inner-stage temporary plugging (ISTP), has been proposed as a widely applied technique in China, for promoting the uniform initiation and propagation of multi-clustered hydraulic fractures (HFs) in a horizontal well of the shale oil/gas reservoirs. However, how the key plugging parameters controlling the multi-fracture growth and the pumping pressure response during TPDF in shale with dense bedding planes (BPs) and natural fractures (NFs) is still unclear, which limits the optimization of TPDF scheme. In this paper, a series of TPDF simulation experiments within a stage of multi-cluster in a horizontal well were carried out on outcrops of Longmaxi Formation shale using a large-scale true tri-axial fracturing simulation system, combined with the acoustic emission (AE) monitor and computed tomography (CT) scanning techniques. Each experiment was divided into three stages, including the conventional fracturing (CF), IFTP and ISTP. Multi-fracture initiation and propagation behavior, and the dominant controlling parameters were examined, containing the particle sizes, concentration of temporary plugging agent (TPA), and cluster number. The results showed that the number of transverse HFs (THFs) and the overall complexity of fracture morphology increase with the increase in TPA concentration and perforation cluster number. Obviously, the required concentration of TPA is positively correlated with the cluster number. Higher peak values and continuous fluctuations of pumping pressure during TPDF may indicate the creation of diversion fractures. The creation of standard THFs during CF is favorable to the creation of diversion fractures during TPDF. Moreover, the activation of BPs nearby the wellbore during CF is unfavorable to the subsequent pressure buildup during TPDF, resulting in poor plugging and diverting effect. Notably, under the strike-slip fault stress regime, the diversion of THFs is not likely during IFTP, which is similar as the results of ISTP to initiate mainly the un-initiated or under-propagated perforation clusters. Three typical pressure curve types during TPDF can be summarized to briefly identify the hydraulic fracture diversion effects, including good (multiple branches or/and THFs can be newly created), fair (HF initiation along the slightly opened BPs and then activating the NFs), and bad (HF initiation along the largely opened BPs and then connecting with the NFs). [ABSTRACT FROM AUTHOR]

Although many studies based on naturally deformed samples have been carried out to investigate the pore-crack characteristics of shales, studies based on high temperature (T) and high pressure (P) deformation experiments, which can exclude sample heterogeneity factors, simulate deep T-P conditions, and generate a continuous deformation sequence, are still rare. In this study, shales with different deformation levels are generated by triaxial compression experiments, and methods including scanning electron microscopy, mercury injection, and gas sorption are utilized to characterize their influence factors and pore-crack characteristics. Results indicate that T is the primary factor influencing shale deformation when P is low, while P is dominant under high P conditions. At T < 90 °C and P < 60 MPa, shales undergo brittle deformation and their macropores decrease due to the compaction of primary pores, while mesopores increase because of the interconnection of micropores. At 90 °C < T < 200 °C and 60 MPa < P < 110 MPa, shales experience brittle-ductile transitional deformation, and their macro- and micropores increase because of the extension of open cracks and the plastic deformation of clay flakes respectively, while mesopores decrease dramatically. At T > 200 °C and P > 110 MPa, shales are subjected to ductile deformation, and their micro- and mesopores drop significantly due to the intense compaction in the matrix while macropores continuously increase with crack expansion. The permeability of shale increases with the degree of deformation and ductile material contents are predicted to be a key factor determining whether open microcracks can be preserved after ductile deformation. To account for these experimental results, an ideal model of micro pore-crack system evolution in deformed shales is further proposed, which can provide guidance for the exploration of shale gas resources in the deep or structurally complex zones. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Journal of Engineering (17264073) is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

As energy demand continues to rise and conventional fuel sources dwindle, there is growing emphasis on previously overlooked reservoirs, such as tight reservoirs. Shale and coal formations have emerged as highly attractive options due to their substantial contributions to global gas reserves. Enhanced shale gas recovery (ESGR) and enhanced coalbed methane recovery (ECBM) based on gas injection are advanced techniques used to increase the extraction of gas from shale and coal formations. One of the key challenges associated with these formations and their enhanced recovery methods is accurately predicting the sorption process and its profile. This is crucial because it affects how methane (CH4) and carbon dioxide (CO2) are stored and released from the rock, and it significantly impacts the evaluation of gas content and the potential productivity of these formations. Due to the high cost of experimental procedures and the moderate accuracy of existing predictive approaches, this study proposes various cheap and consistent data‐driven schemes for predicting the sorption of CH4 and CO2 in shale and coal formations. In this regard, three intelligent models, including generalized regression neural network (GRNN), radial basis function neural network (RBFNN), and categorical boosting (CatBoost), were taught and tested using more than 3800 real measurements of CH4 and CO2 sorption in shale and coal formations. To find automatically their appropriate control parameters and improve their prediction ability, RBFNN and CatBoost were evolved using grey wolf optimization (GWO). The obtained results exhibited the encouraging prediction capabilities of the suggested models. In addition, it was found that CatBoost‐GWO is the most accurate scheme with total root mean square (RMSE) and determination coefficient (R2) of 0.1229 and 0.9993 for CO2 sorption, and 0.0681 and 0.9970 for CH4 sorption, respectively. Additionally, this approach demonstrated its physical validity by respecting the real sorption tendencies with respect to operational parameters. Furthermore, the CatBoost‐GWO model outperforms recently published machine learning approaches. Lastly, the findings of this study offer a significant contribution by demonstrating that the suggested model can greatly improve the ease of estimating CO2 and CH4 sorption in tight formations, thereby facilitating the simulation of other parameters related to this process. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract In this study, a Clastic reservoir in the Y oil field located in parts of the Niger Delta was characterized geomechanically using suits of well log to estimate and evaluate its geomechanical properties. The study aims to use the estimated properties to infer the rock strength and probable mechanical failure mechanism using the cross-plot method. The estimated average value of these properties is 5.4135GPa, 1.534GPa, 6.053GPa, 0.3478, 0.653GPa−1 and 27.457GPa for Young's modulus, Shear modulus, Bulk modulus, Poisson's ratio, compressibility, and unconfined compressive strength respectively. The result of the cross plots of these evaluated properties colour-coded with porosity for the reservoir 2 intervals distinguished three lithofacies: hydrocarbon sands, brine sands, and shale with varying sensitivities in the reservoir interval. The cross plots of Poisson's ratio versus elastic moduli and UCS show that the porous hydrocarbon sands exhibit high Poisson's ratio, low elastic moduli, and low UCS, while brine sands and shale exhibit moderate Poisson's ratio and medium to high elastic moduli and UCS respectively. These suggest that the hydrocarbon sands are brittle and are said to be more prone to lateral deformation being less stiff, rigid, and having less strength than the other lithologies. At the same time, shale is ductile the stiffest, and the most rigid rock in the reservoir. These observations are indications that the hydrocarbon sands are friable and unconsolidated compared to the consolidated brine sands and shale. Thus, the low strength hydrocarbon sands are prone to mechanical failures and are likely to deform easily under the influence of overburden in the reservoir interval during production.

Abstract Shale gas is a cutting edge energy source for development, and reserves are abundant. However, shale microcracks develop and tend to form macroscopic fractures during drilling, which can cause severe wellbore instability. Therefore, in combination with rock mechanics theory and fracture mechanics theory, the cohesive element method is adopted to establish a numerical model for differential crack propagation due to bottomhole pressure on the basis of the B-K fracture criterion. The propagation pattern of cracks around a wellbore is simulated, and the influences of rock mechanical parameters, the initial crack length, the direction of crack distribution, and minimum horizontal stress on crack propagation are analyzed. The research results indicate that the larger the Young’s modulus of shale is, the easier it is for cracks to propagate. The Poisson’s ratio of shale has a large influence on crack widening, but its effect on the crack length is weak. The larger the angle between the crack and the maximum horizontal stress is, the more difficult it is for the crack to propagate. The greater the minimum horizontal stress is, the more difficult it is for cracks to propagate. The initial crack length has a weak effect on crack propagation.

Methane in-situ explosion fracturing of shale is a revolutionary technology that utilizes the methane analyzed from shale reservoirs and the input combustion aids to carry out explosion reactions, thereby forming a three-dimensional fracture network in in-situ fracturing of shale reservoirs. This study conducted explosion experiments to investigate the variation patterns of key parameters of explosion (i.e. explosion pressure, explosion speed, rise time of peak pressure). We obtained the attenuation patterns of stress wave in shale reservoir through dimensionless analysis. We used the finite element software ANSYS/LS-DYNA to establish models of different working conditions for analyzing the number of cracks and damage evolution patterns of shale caused by explosion. Results show that: 1) The pressure during the methane/oxygen explosion is about 30 times the initial pressure. The rise time of peak pressure is 85 μs. 2) Peak stress of the stress wave and the specific distance in the shale reservoir under the explosion load are exponentially related. 3) The increase in loading rate could form multiple cracks around the explosion hole. 4) Compared with open hole completion, the presence of casing reduces the pressure near the wellbore wall, causing type Ⅰ cracks to extend along the initial fracture direction. The perforation length after extension increasesby 47 % compared to the original length.

To ensure long-term safety and performance, geological nuclear waste repositories require low-permeability barriers such as bentonite buffers and/or shale host rock. Shale is not only known for its low permeability but also for its trend to undergo time-dependent deformation (i.e., creep), which could heal damage, but the effects of shale creep on the long-term performance of nuclear waste repositories have not been clearly understood. In particular, the anisotropic nature of shale (i.e., bedding) could have a significant effect on its creep behavior, and consequently, on the long-term performance of nuclear waste repositories. In this research, numerical simulations were carried out with the objective of showing the effects of anisotropic shale creep on the stress and permeability evolution of a generic geological nuclear waste repository in shale. The TOUGH-FLAC simulator, a thermo-hydromechanically (THM) coupled numerical code, was used for the simulations. To achieve the objective, comparisons were performed between the results of anisotropic shale creep simulations and those of different simulation cases, namely, no creep (i.e., elastic), isotropic creep, and long-term creep shale cases. Results of the comparisons show that the elastic and isotropic creep shale cases respectively led to the overestimation and underestimation of stress and permeability in the repository, whereas the long-term creep shale case, which accumulated greater creep in later periods than in earlier periods, helped to keep large shear and tensile stresses from developing while maintaining compressive spherical stress, resulting in consistently low permeability levels. These results indicate that performance assessments with elastic and isotropic creep formation models will provide the upper and lower bound estimates of stress and permeability, while more reasonable estimates will be given by an anisotropic creep formation model, and that shale with long-term creep characteristics will be beneficial in many aspects of the safety and performance of nuclear waste repositories.

The SEM image method is commonly used in the qualitative characterization of shale pores. The development of shale micro-reservoir pores can be visually observed through SEM images, but the efficiency of manual image processing is low and subjective. The introduction of deep learning greatly improves the efficiency of pore analysis. In this paper, the argon ion polishing SEM image of Longmaxi Formation shale in southern Sichuan is taken as an example. Intelligent identification and quantitative characterization of pores in shale SEM images are realized by Pore-net network model. Pore-net is based on the U-net network model. The way the model reads the data is changed so that the model does not focus on the region of interest. The number of convolutional layers of the model is increased. The Canny edge extraction algorithm is added. It not only reduces the workload of data set production, but also enhances the ability of network model to identify pores. The results show that the deep learning semantic image segmentation method is suitable for pore recognition of shale SEM images. The full convolutional neural network model is used to train the manually labeled shale SEM images, which can realize the intelligent recognition and quantitative characterization of shale SEM images. Compared with FCN and DeepLab V3+ network model, Pore-net performs better. Only 170 data sets are used to train the model. The Pore-net network model still has a good recognition effect on pores, which solves the problem of low accuracy of traditional pore recognition methods. The deviation between the porosity calculated by the Pore-net network model and the experimental data is between 12% and 19%. Compared with the porosity results calculated by the binarization method and other network models, the results calculated by Pore-net are closer to the real values, which proves that the porosity calculated by the Pore-net network model is reliable. [ABSTRACT FROM AUTHOR]

Overpressure prediction for exploratory drilling has become robust in most basins with increasing well control, high-quality seismic datasets, and proactive real-time overpressure monitoring while drilling. However, accurate overpressure prediction remains challenging in offshore Northwest Borneo despite several decades of drilling experience. This paper focuses on two exploration wells drilled by Brunei Shell Petroleum 40 years apart that faced similar challenges with overpressure prediction and well control. An integrated lookback study is attempted using seismic and well-log data to explore the causes of the unsatisfactory Pore Pressure Prediction (PPP) outcome in pre-drill and real-time operation settings for these wells. Our study indicates that the misprediction of overpressures is due to real differences in shale pressure (basis of pre-drill work and monitoring) and sand pressure (source of drill kick and well control challenges) due to large-scale vertical leak or expulsion of deep-seated fluids into pre-compacted normally pressured overlying sediments in several regions through a mix of shear and tensile failure mechanisms. Such migrated fluids inflate the sand pressure in the normally compacted shallower sequences with the shale pressure remaining low. A predictive framework for upward fluid expulsion was attempted but found impracticable due to complex spatial and temporal variations in the horizontal stress field responsible for such leakage. As such, it is proposed that these migratory overpressures are essentially 'unpredictable' from conventional PPP workflows viewed in the broad bucket of compaction disequilibrium (undercompaction) and fluid expansion (unloading) mechanisms. Further study is recommended to understand if such migrated overpressures in the sand can produce a discernible and predictable geophysical or petrophysical signature in the abutting normally compacted shales. The study highlights the possibility of large lateral variability in the sand overpressure within the same stratigraphic unit in regions with complex tectonostratigraphic evolution like Northwest Borneo. [ABSTRACT FROM AUTHOR]

[Purposes] The development of shale oil and gas often requires a thorough understanding of the internal pore-fracture distribution patterns within shale reservoirs to optimize development strategies and enhance production capacity. In this context, the fractal dimension holds significant importance for reflecting the distribution patterns of pores and fractures within shale formations. [Methods] In this study, a convolutional neural network-based method for predicting the fractal dimension of shale Computed Tomography (CT) images is proposed. An independent convolutional neural network model is constructed, specifically designed for oil shale CT images. CT slices of oil shale samples treated with different temperatures, along with their corresponding fractal dimensions, are employed as the dataset and labels. The constructed convolutional neural network is trained and utilized for prediction to realize, effectively extracting fractal dimensions from shale CT images. [Findings] The trained model is applied to various practical scenarios and compared with the box-counting method. The results demonstrate a high degree of similarity between the predicted fractal dimensions of shale CT images by using the convolutional neural network and those computed through the box-counting method, with a difference of approximately 0.01. Additionally, the convolutional neural network method exhibits robustness against interference while also significantly accelerating the computation process compared with the box-counting method. Therefore, it can be concluded that the proposed method effectively captures the structural characteristics of images, allowing for reliable estimation of image fractal dimensions with notable resilience to noise and artifacts.

Abstract Ureolysis-induced calcium carbonate precipitation (UICP) is a biomineral solution where the urease enzyme converts urea and calcium into calcium carbonate. The resulting biomineral can bridge gaps in fractured shale, reduce undesired fluid flow, limit fracture propagation, better store carbon dioxide, and potentially enhance well efficiency. The mechanical properties of shale cores were investigated using a modified Brazilian indirect tensile strength test. An investigation of intact shale using Eagle Ford and Wolfcamp cores was conducted at varying temperatures. Results show no significant difference between shale types (average tensile strength = 6.19 MPa). Eagle Ford displayed higher strength at elevated temperature, but temperature did not influence Wolfcamp. Comparatively, cores with a single, lengthwise heterogeneous fracture were sealed with UICP and further tested for tensile strength. UICP was delivered via a flow-through method which injected 20–30 sequential patterns of ureolytic microorganisms and UICP-promoting fluids into the fracture until permeability reduced by three orders of magnitude or with an immersion method which placed cores treated with guar gum and UICP-promoting fluids into a batch reactor, demonstrating that guar gum is a suitable inclusion and may reduce the number of flow-through injections required. Tensile results for both delivery methods were variable (0.15–8 MPa), and in some cores the biomineralized fracture split apart, possibly due to insufficient sealing and/or heterogeneity in the composite UICP-shale cores. Notably in other cores the biomineralized fracture remained intact, demonstrating more cohesion than the surrounding shale, indicating that UICP may produce a strong seal for subsurface application.

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.

Abstract The quartz content and internal fractures of shale are important factors affecting its mechanical properties and damage modes. To study the mechanical properties of shale under the effect of quartz content and internal cracks, this study used CT scanning technology and digital image processing technology, combined with finite element software to establish a three-dimensional numerical model of shale with different quartz contents and different angles of internal prefabricated cracks, and carried out numerical simulations of Brazilian splitting. Both the quartz content and internal prefabricated cracks in shale can significantly affect the tensile strength of shale. The tensile strength is positively correlated with the quartz content in shale, and tends to increase and then decrease with increasing angle of the internal prefabricated cracks. The quartz content and the internal prefabricated cracks together control the damage of shale, the quartz content increases the damage degree of shale, and the internal prefabricated cracks control the rupture mode of shale, The cracks will have a significant guiding role in crack expansion with increasing angle, and finally show a significant influence on crack expansion from type I to type II. The research results of this paper will play a certain role in promoting the exploitation of shale gas.

The Upper Cretaceous Qingshankou Formation in the Songliao Basin contains thick, widespread, and organic matter-rich shale layers, offering abundant shale oil resources. Studying the sedimentary environment during shale formation and exploring the oil-bearing characteristics of shale oil enrichment intervals provide a theoretical basis for the prediction of the intervals and sweet spots. Based on previous research, the study compared organic carbon content, pyrolysis data, types of organic macerals, and major and trace elements of samples from two typical wells of different sags, well GY8HC in the Gulong Sag and well ZY1 in the Sanzhao Sag, in the central depression zone of the Songliao Basin. The analysis delved into the differences in oil-bearing characteristics and sedimentary environment of the Qingshankou Formation shales in two different sags, further analyzing the factors influencing these differences. The oil-bearing indicators of shales from the two wells in the Qingshankou Formation of the Songliao Basin showed that the total organic carbon (TOC) content in well ZY1 was significantly higher than that in well GY8HC. However, the free hydrocarbon content (S1) and oil saturation index (OSI) in well ZY1 were lower than those in well GY8HC. The geochemical environment during shale formation controlled organic matter enrichment. Comparing major and trace elements in samples from both wells, it was found that the climate in well ZY1 was more humid during its sedimentary period, the water body had stronger reducing conditions, and its paleoproductivity and paleo-water depth were significantly higher than those in well GY8HC. These conditions were favorable for the preservation of organic matter, thereby forming a higher organic matter abundance in the shale of well ZY1. In addition, it was found that the organic matter type in well GY8HC is mainly Type Ⅰ, sapropelic kerogen, at a mature to highly mature stage, whereas well ZY1 contains mainly Type Ⅱ1 kerogen, with less Type Ⅰ, at a low to mature stage. Therefore, the shale in well GY8HC possesses better oil generation potential.

Objective Chemical oxidation and infiltration technology has become a mature method for shale gas exploitation. This study aims to investigate the influence of geochemical factors on the exploitation process. Methods In this study, the Doushantuo Formation shale in Yichang, Hubei Province, which exhibits significant potential for shale gas exploitation and contains a high organic matter content along with pyrite, was selected as the research object. Two commonly used oxidants, 15% H2O2 and 0.5 mol/L Na2S2O8, were selected for oxidation corrosion experiments conducted at normal temperature and pressure. Post-reaction measurements included cation concentration, pH, Eh, mass loss and XRD analysis. Results The results show that Na2S2O8 outperforms H2O2, and the advanced oxidation process driven by pyrite and the erosion effect of carbonate under acid production make the acidic environment more suitable for the dissolution of carbonate-rich shale. An increase in temperature enhances the thermal decomposition of Na2S2O8 and H2O2. The thermal decomposition of H2O2 produces O2, and Na2S2O8 produces H2SO4, O2 and SO4- with strong oxidation. Thus, the temperature's enhancement effect on Na2S2O8 is greater than that on H2O2. Sodium ions (chloride) can promote the release of Ca2+ and Mg2+ during Na2S2O8 and H2O2 oxidation, indicating that a high concentration of NaCl in groundwater plays a positive role in the oxidation and dissolution of shale. Both calcium ions and sulfate ions can cause gypsum precipitation by influencing the interactions between the reactions, thus affecting the oxidative dissolution of shale. Low concentrations of exogenous calcium ions reduce the buffering effect of carbonate and promote its dissolution, while high concentrations of exogenous calcium ions cause secondary mineral precipitation, block shale pores and hinder the oxidation and dissolution of shale. However, the effect of sulfate ions on the oxidative corrosion of shale differs from that of calcium ions. A low concentration of exogenous sulfate ions inhibits the oxidative corrosion of shale by generating secondary ore and impeding the oxidation of pyrite. Conclusion Therefore, in the future process of shale gas oxidative fracturing for extraction, it is necessary to preassess the water chemical parameters of the exploitation formation in advance and select the oxidation liquid and mining modes based on the temperature, pH and cationions.

Shale oil resources are abundant in the second member of the Kongdian Formation, Cangdong Sag, Bohai Bay Basin, China. However, the shale oil here has high viscosity and poor fluidity, resulting in low recovery and huge difficulty in development, gathering, and transporting. This study assembled a catanionic surfactant (PSG) through electrostatic interactions between cetyltrimethylammonium bromide (CTAB) and α-olefin sulfonate (AOS) in an aqueous phase, which can be used as an effective emulsifying and viscosity-reducing agents for shale oils of Dagang oilfield. The interfacial activity and emulsification performance of PSG can be optimized by changing the molar ratio of CTAB to AOS. Notably, the PSG assembled at the molar ratio of 6:4 shows the best performance, with ultra-high surface activity and excellent salt resistance. At an oil/water ratio of 1:1 and 50 °C, an aqueous solution of 0.2% PSG can emulsify five types of shale oil, making it form shale oil-in-water (O/W) emulsion with a viscosity of less than 35 mPa·s, thereby reducing the viscosity of shale oil and improving its flowability. Importantly, shale oil and water can be separated by simple sedimentation without adding demulsifiers. This study has important guiding significance for the efficient development and transportation of shale oil. [ABSTRACT FROM AUTHOR]

This study investigates the effects of microwave radiation on the fracture characteristics and thermal damage mechanisms of shale. Microwave heating response tests were conducted on Shuigoukou Formation shale to examine its heating characteristics under varying microwave irradiation durations. Fracture toughness tests were performed to assess the impact of different bedding angles on shale fracture toughness and to elucidate the failure modes of shale at various bedding orientations. Results reveal that shale fracture toughness exhibits temperature thresholds under microwave action, which vary with bedding angle. For crack-splitter, crack-arrester, and crack-divider type shales, the temperature thresholds were determined to be 50 °C, 125 °C, and 200 °C, respectively. The fracture toughness decreases sequentially from crack-divider to crack-arrester to crack-splitter type shales, with all types showing a reduction as microwave radiation time increases. The thermal damage observed in shale under microwave heating correlates with the wave-absorbing characteristics of its various components. Moisture content, dielectric constant, and mineral composition were identified as the primary factors influencing the microwave thermal effect on shale. The findings contribute to a deeper understanding of the structural damage characteristics and fracturing mechanisms of shale reservoirs during thermal stimulation. [ABSTRACT FROM AUTHOR]

Thirty-two coal (lignite-bituminous in rank) and carbonaceous shale samples, ranging from immature to overmature, were collected from the various coal-bearing basins (Saurashtra Basin, Bikaner Nagaur Basin, Damodar Basin, Mahanadi Basin, and Foreland Basin) in India and characterized petrographically (vitrinite reflectance and maceral composition), geochemically (total organic carbon and total sulfur) and chemically (Fourier Transform Infrared spectroscopy, FTIR). This paper explores utilization of FTIR study on bulk non-demineralized carbonaceous shale and coal to examine the interference between mineral and organic matter visible on FTIR spectra and application of such techniques to assess organic matter chemistry based on FTIR signal. Mineral matter is considerably affecting the organic matter FTIR signal in the region between 1700–1350 and 900–700 cm−1, while the 3100–2800 cm−1 region is unaffected. The general trends of organic matter evolution with thermal maturity, i.e. a decrease of aliphatic and oxygen-bearing groups and increase in aromatic signal, are visible in bulk non-demineralized samples; however, the interpretation of the signal is problematic due to the dilution-related signal weakening and region-specific overlapping. The quality of the FTIR signal is lower than the signal from demineralized kerogens or targeted specific maceral grains via combination of FTIR with microscopy. The spectra can still be useful for more qualitative aspects of FTIR, like assessment of organic functional groups, study of coal impurities, or as a complementary method in conjunction with other analytical techniques such as X-ray for mineral matter characterization. [ABSTRACT FROM AUTHOR]

Mantis shrimp (Stomatopoda) are extant, marine, predatory arthropods, but these malacostracan pancrustaceans are also occasionally preserved in fossil assemblages, particularly in Carboniferous and Cretaceous deposits. Carboniferous species fall into two suborders—Palaeostomatopodea and Archaeostomatopodea—and represent the ancestral forms that gave rise to modern lineages. Herein, we describe hitherto unknown specimens belonging to the archaeostomatopod genus Tyrannophontes from the Pennsylvanian-aged Wea Shale Member, eastern Nebraska. We explore the preservation of these fossils using scanning electron microscopy and energy dispersive X-ray spectroscopy. These approaches reveal additional morphological characteristics, including unique appendicular data, such as the earliest occurrence of biramous gilled appendages in Stomatopoda. We suggest that further examination of black shales will likely uncover novel records of these rare pancrustaceans. [ABSTRACT FROM AUTHOR]

Using micro-CT scanning technology, the characterization and evolution of the fractures in the Fuxing continental shales before and after high-temperature soaking are quantitatively analyzed. The continental shales are soaked in bentonite slurry, Nanodrill water based drilling fluid and white oil based drilling fluid, and are scanned with micro-CT at different soaking times. The effects of the different drilling fluids on the evolution of the fractures are analyzed. The study results show that the rock samples taken from the Liangshan Formation have more fractures than other rock samples, and different drilling fluids have different inhibitive capacities for the extension of the fractures. After soaking for 10 d in bentonite slurry, the percent layered fractures with the maximum width found in the rock samples is 12%, significantly higher than that of the rock samples in the white oil based drilling fluid, which is 6.13%, and the percent layered fractures with the maximum width of the rock samples in the water based drilling fluid lies in between the two. Using microscope, the distribution of the fracture widths of the rock samples before soaking is studied, and the percent increase of the fracture widths of the rock samples after soaking for 10 d is analyzed; the rock samples in the bentonite slurry have the highest percent increase in fracture width, which is 61.6%, the rock samples in the Nanodrill water based drilling fluid have the intermediate percent increase in fracture width, which is 52.1%, and the rock samples in the white oil based drilling fluid have the lowest percent increase in fracture width, which is 39.8%. Quantitative study on the distribution of the lengths of the fractures shows that the rock samples soaked in the bentonite slurry have the most fractures with lengths between 50 μm and 100 μm, and the numbers of the fractures with the same length distribution in the rock samples soaked in the Nanodrill water based drilling fluid and in the white oil based drilling fluid are basically remained unchanged. These data indicate that the white oil based drilling fluid has the best inhibitive capacity in inhibiting fracture extension in shales, with the Nanodrill water based drilling fluid inferior in inhibiting fracture extension to the oil based drilling fluid, and the bentonite slurry performs the poorest in this aspect. The results of this study can be used as a technical reference for efficient and safe drilling of the continental shale formations in the Fuxing area. [ABSTRACT FROM AUTHOR]

The Late Cretaceous deposits in the south of the Western Desert in the Dakhla Basin are well exposed, comprising variegated shales which contain a variety of vertebrates. In this contribution, we describe a new sauropod specimen from the Quseir Formation, represented by an almost complete humerus. The humerus shows a set of morphological features that allow us to refer it to the Saltasauridae, such as divided and well-developed distal condyles. Saltasaurids are ones of the smallest sauropod dinosaurs. The saltasaurids are newly recorded in Africa, although it was previously discovered on almost all the other continents in the Late Cretaceous. This study mentions the first record of saltasaurid humerus in Africa. [ABSTRACT FROM AUTHOR]

The Abu Darag sub-basin in Egypt is a significant hydrocarbon province. This study provides the first thorough evaluation of the petroleum system in the Northern Gulf of Suez, specifically targeting regions with tectonically influenced paleo highs. The research is novel in its holistic approach, linking tectonic activity with hydrocarbon generation and accumulation, particularly in the Nukhul Formation. In the NDARAG-1 well, with the Nukhul Formation serving as its main reservoir, petrophysical analysis estimates an average net pay of 126 ft in the Nukhul Formation, with 19% average shale volume, 17% average effective porosity, and 57% average water saturation. Geochemical evaluation of the shales in the Thebes, Matulla, Raha, and Nubia-A formations indicate source rock potential ranging from fair to very good, with TOC values between 0.5 wt% and 5.4 wt%. The burial history model outlines gradual subsidence and sediment deposition from the Paleozoic to the Early Cretaceous, followed by significant compression and uplift during the Late Cretaceous. Early oil generation in the Nubia-A Lower shales began during the Early Cretaceous (~132 Ma) at a depth of 4000 ft while it occurred in the Early Miocene (~22 Ma) at a depth of 7400 ft. The Nubia-A Lower Member is identified as the key source rock, with vitrinite reflectance values above 0.70%. Continuous subsidence during the Eocene led to the deposition of the Nukhul, Rudeis, and Kareem formations. Oil generation in the Nubia-A Lower shales occurred during both the Early Cretaceous and Early Miocene. The main risk to hydrocarbon accumulation in the Abu Darag sub-basin is related to potential seal failures due to the erosion and/or non-deposition of the Belayim, South Gharib, and Zeit evaporites. The only producing wells are situated in the northwest of the study area, where conditions are conducive to hydrocarbon entrapment and preservation, and secondary migration has occurred in a northwestward direction. [ABSTRACT FROM AUTHOR]

Lower Jurassic marine basins across the northwest European epicontinental shelf were commonly marked by deposition of organic-rich black shales. Organic-carbon burial was particularly widespread during the Toarcian Oceanic Anoxic Event (T-OAE: also known as the Jenkyns Event) with its accompanying negative carbon-isotope excursion (nCIE). Lower Toarcian black shales in central and southern Germany are known as the Posidonia Shale Formation (Posidonienschiefer) and are thought to have formed during the T-OAE nCIE. Here, we present stratigraphic (carbon-isotope, Rock–Eval, calcareous nannofossil) data from the upper Pliensbachian and lower Toarcian strata from a core drilled on the northern flank of the Lower Saxony Basin, north–west Germany. The bio- and chemostratigraphic framework presented demonstrates that (i) the rock record of the T-OAE at the studied locality registered highly condensed sedimentation and/or multiple hiatuses and (ii) the deposition of organic-rich black shale extended significantly beyond the level of the T-OAE, thereby contrasting with well-studied sections of the Posidonia Shale in southern Germany but showing similarities with geographically nearby basins such as the Paris Basin (France). Prolonged and enhanced organic-carbon burial represents a negative feedback mechanism in the Earth system, with locally continued environmental perturbance accelerating the recovery of the global climate from T-OAE-associated hyperthermal conditions, whilst also accelerating a return to more positive δ13C values in global exogenic carbon pools. [ABSTRACT FROM AUTHOR]

Based on low temperature nitrogen adsorption experiment, the quantitative characterization of Marine mud shale from Qiongzhusi formation of the lower Cambrian and Longmaxi formation of the lower Silurian in the Upper Yangzi Massif and Terrestrial mud shale of chang 9 and chang7 oil layers in Ordos Basin is finished. The pore characteristics and influencing factors of shale reservoirs with different sedimentary environments and maturity are discussed systematically from the aspects of material composition and thermal evolution. The results show that the brittle mineral content is negatively correlated with the specific surface area and pore volume. The content of clay minerals is weakly positively correlated with specific surface area and pore volume. TOC content is weakly positively correlated with pore volume, strongly positively correlated with specific surface area, and not correlated with average pore diameter. With the increasing of Ro, the average pore diameter decreases, and the decreasing speed decreases with the increasing of Ro. When Ro is between 0.5% and 2.8%, the specific surface area increases with Ro. When Ro is between 2.8% and 5%, the specific surface area decreases with the increase of Ro. The pore volume was negatively correlated with Ro value due to the decrease of pore diameter. [ABSTRACT FROM AUTHOR]

Sediment and metasediment-hosted copper-cobalt deposits play an important role in global Co and Cu resources, with Co reserve exceeding 48% of the world's cobalt reserves and production accounting for over 68% of the world. The Cu reserve accounts for 20% of the world. second only to porphyry copper. The types of host rock for the copper-cobalt deposits are various, and few studies have been conducted on the characteristics and controlling factors of distribution, grade, and resource of the copper-cobalt deposits in different host rocks. Statistical analysis on the grade and resource data of the 98 collected sediment and metasediment-hosted copper-cobalt deposits on land were conducted. The copper-cobalt deposit on global land can be further subdivided into four types, including breccia-type, shale-type, sandstone-type and metasediment-type. The deposits are mainly distributed in Democratic Republic of Congo (DRC) and Zambia in Central Africa, followed by China, the United States, Finland, and Australia. The breccia-type deposits are characterized by higher Co and Cu grades, and the deposits with abnormally high Co and Cu resources are mainly breccia-type. The sandstone and shale-type deposits are generally characterized by lower Co grades, and the shale-type deposits have typically high Cu/Co ratios. The metasediment-type deposits are usually characterized by lower Cu grades. Cu/Co ratio. and Co and Cu resources. The grade. Cu/Co ratio, and resource characteristics of sediment and metasediment-hosted cobalt copper deposits are mainly influenced by metal source and multi-stage hydrothermal fluid activities. The supernormal enrichment of Cu and Co is the result of multiple factors (such as mafic-ultramafic rocks. low grade Cu and Co mineralization. Co-rich shale and late transformation). The low Cu grade and resource of metasediment-type deposits may be attributed to significant geochemical dispersion during Cu activation and migration. The mismatch between the relatively widespread distribution and low resources of sediment and metasediment-hosted copper-cobalt deposits in China is prominent, which may indicate that there is still significant potential for mineral exploration. The future exploration of sediment and metasediment-hosted copper-cobalt deposits should focus on high grade blind deposits. [ABSTRACT FROM AUTHOR]

As a hydrocarbon reservoir rock, shale is generally composed of highly compacted clay particles with submicrometer sizes and includes nanometric porosity and different hard particles, like quartz, pyrite, etc. One of the key reasons for the formation of a complex fracture network via hydraulic fracturing is the multiscale heterogeneity of shale, especially heterogeneity on the microscale. This paper conducted on an experimental investigation of shale and explored the intrinsic relationship between the microstructure, the related mechanical properties at the micrometer level and the anisotropic failure mechanism. Small-scale specimens with micrometer dimensions in the form of cantilever beams with rectangular cross-section were fabricated by means of a focused ion beam (FIB) and tested via bending with a nanoindenter. The load–deflection curves of these bending beams were monitored up to failure, and the tensile strength of the shale composite was directly derived from the load–deflection curves at 474.5 MPa (parallel to the bedding plane) and 168.9 MPa (vertical to the bedding plane). The results show that the strength anisotropy of shale at the micrometer scale is driven by the clay particles and other minerals, and the bonds of these particles. The modulus anisotropy of the shale composite at the microscale is dominated by the orientation of clay particles. Moreover, the shale composite embedded with pyrite exhibited strong softening characteristics. [ABSTRACT FROM AUTHOR]

This study demonstrates an integrated approach using a seismic-coloured inversion to derive the hydrocarbon potential of a field in the Upper Assam basin. The well-log analysis indicated the presence of hydrocarbon in the form of gas, oil, and water in sandstones with thin streaks of limestone and shale layers. The Acoustic Impedance (AI) model was generated from post-stack seismic data using a coloured inversion. Shale volume (Vshale), density, porosity and water saturation are the petrophysical parameters spatially populated using a multilayered feed-forward neural network on the inversion-based AI model. The estimated range of model-derived parameters varies as Velocity: 2136–5034 m/s, Vshale: 0–48%, Density: 2.14–2.72 gm/cc, Porosity: 6–29%, Water saturation: 9–28%, and demonstrates a reasonable correlation to well-log data. Seismic attribute for thin-fault likelihood was used to interpret the major faults. From the combined analysis based on interpreted faults and modelled parameters, the northwestern part of the study area displays a thick hydrocarbon-bearing zone (due to increasing thickness and reservoir quality). This interpretation is based on the consideration that faults are open. Thus, assuming continuity in the sequence, this northwestern region can be considered as one of the promising candidates for further exploration. [ABSTRACT FROM AUTHOR]

The inherent anisotropy in shale is an attribute associated with its clay minerals platelets alignment and layering and very common with transversely isotropic (TI) medium. This implies that velocity is fastest along the horizontal axis and slowest along the vertical axis, which could affect velocity signature from sonic tools measurements in deviated wells. This may lead to wrong amplitude variation with offset (AVO) signature, inaccurate depth conversions, seismic-to-well tie difficulty etc. Nineteen (19) wells in Forties field andthirteen (13) in Huntington field were investigated and interpreted for the presence of anisotropy effect within the caprock over the reservoir Forties sands of the Sele (shales) Formation. In order to analyse the Thomsen weak anisotropy parameters (ϵ, γ and δ) per field, wells with closer Sele depth range were considered. The well inclinations ( $ \theta $ θ), average compressional (α) and shear (β) velocities per well were utilised for forward and inverse modelling of Thomsen anisotropy equations. The estimated anisotropy (VTI) parameters and the P-wave ( $ {\alpha _o} $ α o ) and S-wave velocities (βo) at zero inclinations in Sele Formation for the studied wells are: $ {\alpha _o} $ α o = 2448 $ \pm $ ± 15.9 m/s, $ {\beta _o} $ β o = 1003 $ \pm $ ± 34.8 m/s, ϵ = 0.15 $ \pm $ ± 0.02, γ = 0.33 $ \pm $ ± 0.10, $ \delta $ δ = 0.030 $ \pm $ ± 0.015 in the Forties field Sele, while $ {\alpha _o} $ α o = 2775 $ \pm $ ± 23.6 m/s, $ {\beta _o} $ β o = 1306 $ \pm $ ± 47.9 m/s, ϵ = 0.22 $ \pm $ ± 0.02, γ = 0.43 $ \pm $ ± 0.14, δ = 0.022 $ \pm $ ± 0.018 in the Huntington field. AVO responses were compared, assuming both isotropic and anisotropic P–P reflectivity models. Result shows an increase in AVO gradient for all anisotropic case in both fields. AVO signatures were either completely or averagely masked in both fields using the isotropic assumptions. There is also an increase in AVO gradient for all anisotropic cases in both fields. Velocity decreases of about 1.2% and 3.5% were observed in the Sele Formation for the Forties and Huntington fields respectively for anisotropy. The corrected two-way traveltime (TWT) should in principle allow for a better seismic-to-well tie estimation. Similarly, using the faster deviated velocity (i.e. uncorrected velocity) in any depth conversion would result in under estimation of the actual depth across the field. [ABSTRACT FROM AUTHOR]

Multi-stage and multi-cluster hydraulic fracturing treatments of horizontal wells play a crucial role in the successful development of unconventional shale reservoirs. Completion design and optimization require a good understanding of proppant placement in multiple simultaneously propagating hydraulic fractures in horizontal wells. In this study, we simulate proppant placement in multiple hydraulic fractures in a rapid fashion by implementing an efficient proppant transport model in a rapid multi-cluster, multi-stage hydraulic fracture model. Our simulations take into account proppant settling and embedment during shut-in, critical but often overlooked aspects in proppant transport simulations. Sensitivity analyzes are performed to investigate the effects of various parameters, including pumping rate, fluid leak-off rate, number of perforations per cluster, and excess stress in the barrier layers, on the final proppant distribution, fracture residual aperture, and fracture conductivity. The simulation results reveal that increasing the pumping rate or decreasing the number of perforations per cluster can help achieve a more uniform proppant distribution among multiple hydraulic fractures. Higher fluid leak-off rates can cause the formation of proppant patches at the top of the fractures, leading to uneven proppant distribution within the fractures. In addition, higher levels of excess stress in the barrier layers may reduce the uniformity of fracture geometry and proppant distribution across multiple fractures. These findings provide valuable insights into the placement of proppant in multiple simultaneously propagating hydraulic fractures and may be helpful for the completion design and optimization of horizontal wells. Highlights: Proppant placement in multiple simultaneously propagating hydraulic fractures is simulated. Proppant settling and embedment during shut-in are taken into consideration. The effects of pumping rate, fluid leak-off rate, number of perforations per cluster, and excess stress in the barrier layers on the final proppant distribution and fracture conductivity were studied. [ABSTRACT FROM AUTHOR]

The development of shale oil reservoirs is significant for the petroleum industry. Fluids in shale oil play exist in nanoscale pores, and the interaction between fluids and shale rock surface walls can lead to the expansion and deformation of the entire pore medium thus affecting the development and production of oil reservoirs. We used an organic matter (graphene) pore model to represent the nanopore structure of shale reservoir. Methane, n-hexane and n-dodecane multi-component fluids were used to characterize shale oil. The adsorption and deformation law of multi-component shale oil in the nanopore was systematically studied by using the molecular simulation method. The results showed that the adsorption of multi-component shale oil in organic nanopores was positively correlated with pressure. The total adsorption amount increased with the increase of pressure. Firstly, when the ratio of CO2 was higher, it was more favorable for the development of crude oil and the large amount of CO2 sequestration. The adsorption amount was negatively correlated with temperature. Secondly, the adsorption amount of multicomponent shale oil is proportional to the pore size; The adsorption amount of large-size pore model is more sensitive to pressure changes than that of small-size pore model. Finally, the trend of adsorption deformation volume is similar to that of adsorption volume, which decreases with the increase of temperature. The shale deformation caused by CO2 injection at this time is much smaller than the other component ratios, indicating that the magnitude of deformation is positively related to the adsorption volume. [ABSTRACT FROM AUTHOR]

The quartz content and internal fractures of shale are important factors affecting its mechanical properties and damage modes. To study the mechanical properties of shale under the effect of quartz content and internal cracks, this study used CT scanning technology and digital image processing technology, combined with finite element software to establish a three-dimensional numerical model of shale with different quartz contents and different angles of internal prefabricated cracks, and carried out numerical simulations of Brazilian splitting. Both the quartz content and internal prefabricated cracks in shale can significantly affect the tensile strength of shale. The tensile strength is positively correlated with the quartz content in shale, and tends to increase and then decrease with increasing angle of the internal prefabricated cracks. The quartz content and the internal prefabricated cracks together control the damage of shale, the quartz content increases the damage degree of shale, and the internal prefabricated cracks control the rupture mode of shale, The cracks will have a significant guiding role in crack expansion with increasing angle, and finally show a significant influence on crack expansion from type I to type II. The research results of this paper will play a certain role in promoting the exploitation of shale gas. [ABSTRACT FROM AUTHOR]

Copyright of Nonferrous Metals (Extractive Metallurgy) is the property of Beijing Research Institute of Mining & Metallurgy Technology Group and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Hydraulic fracturing is the predominant technology for the development of unconventional resources, and understanding multi-fracture propagation behavior is the foundation for hydraulic fracturing optimization. To deeply understand multi-fracture propagation behavior in natural formations, this paper proposes a numerical simulation which considers the fluid-solid coupling process based on the displacement discontinuity method and the finite volume method. The simulation indicates that high stress difference and low approach angle are the main factors limiting the stimulated volume, while low stress difference and high approach angle are beneficial for creating modification zones. In addition, the natural fracture density also has a great effect on fracture propagation. With increasing natural fracture density, the stimulated volume also increases greatly, which plays a significant role in enhancing the SRA. These findings are critical in comprehending the impact of geological parameters on deep fractured shale reservoirs. [ABSTRACT FROM AUTHOR]

The direct shear tests showed that the degradation of unevenness and waviness of the laminae plane is the primary reason for the dynamic decrease in shear strength. A shear constitutive model was proposed which considers the scale effect and the asperity geometry of the unevenness and waviness of the laminar plane. The evolution of the shear strength and stiffness with a normal stress and scale effect during the shearing of shale laminae planes was explored. The results show that high normal stress aggravates the stiffness hardening of laminae planes and forms larger peak shear stress and peak shear displacement. At the lab scale, the increase in the unevenness wavelength has a hardening effect on the shear stiffness and strength. The small-scale unevenness contributes most to the shear strength of shale laminae planes at the lab scale. At the field scale, the increase in the waviness wavelength has a softening effect on the shear stiffness and strength. [ABSTRACT FROM AUTHOR]

The shale sedimentary environment is crucial for evaluating shale gas reservoirs and sweet spot zones. The Xiahuayuan Formation in the Xuanlong Depression of the Yanshan area is an important exploration and development region for shale gas due to its multi-layer dark shale. The paleosedimentary environment and organic matter accumulation mechanism of organic-rich shale were discussed through geochemical methods such as total organic carbon (TOC) content and elemental analysis. The results indicate that the shale exhibits a high TOC content. The Mo content and the P/Al and P/Ti ratios indicate that the primary productivity of the ancient lake is high. The Ceanom, V/(V + Ni) ratio and MoEF-UEF covariation model reveal that the sedimentary environment of shale is characterized by anoxic conditions. The ratios of K/Al and Ti/Al suggest significant variations in the input of fine-grained clay clastics and terrigenous clastics. The Ca/(Fe + Ca) and Sr/Ba ratios suggest that the paleowater was a freshwater environment. The paleoclimatic conditions, as indicated by CIA, Sr/Cu, and C-value, suggest a range from semi-humid to humid. The ratios of Rb/K and Mn/Ti reflect that the water primarily existed in a shore–shallow lake environment. The correlation analysis between organic matter accumulation and sedimentary environment parameters indicates that the primary factors influencing the organic matter accumulation in the Xiahuayuan Formation shale are redox conditions, terrigenous clastic input, paleoclimate conditions, and paleowater depth. The organic matter accumulation is characterized by a "preservation condition" pattern. This study provides theoretical support for the accumulation mechanism, potential evaluation of resources, and optimal selection of favorable regions for Jurassic shale gas in the Xuanlong Depression. [ABSTRACT FROM AUTHOR]

The increasing depletion of natural clay resources and the indiscriminate dumping of solid waste has exerted unprecedented pressure on the environment. This study primarily aims to assess the efficacy of waste glass (WG) in enhancing the compressive strength of sludge-shale bricks. The mass loss (ML), apparent porosity (AP), bulk density (BD), water absorption (WA), and compressive strength (CS) of the sludge-shale bricks were evaluated in accordance with the relevant Chinese standards. The optimal parameters were determined to be a WG dosage of 30%, a molding pressure of 20 MPa, a sintering temperature of 1000 °C, and a holding time of 2 h. The performance of the products under optimum conditions was further evaluated through freeze–thaw tests, leaching tests, microstructural and mineralogical analysis. The results indicated that the AP, BD, WA, and CS of sludge-shale bricks prepared under optimum conditions were 35.31%, 1.69 g/cm3 and 15.29% 52.01 MPa, respectively. Leaching tests revealed that incorporating WG and elevation of sintering temperature enhance the efficacy of heavy metal immobilization. Following 25 freeze–thaw cycles, weight loss values for all sludge-shale bricks remained considerably below national limits. Elevated WG dosage and sintering temperature promote structure vitrification and densification, facilitating anorthite formation that enhances CS. This study provides robust data support for the synergistic preparation of sintered bricks using shale, municipal sewage sludge (MSS) and WG. [ABSTRACT FROM AUTHOR]

The present study evaluated the Paleogene Sokor-1 clastic reservoirs in the Fana Field on the Agadem Block, Termit Basin, Niger Republic. The evaluation of the hydrocarbon prospect of the Field, which involved petrophysical analysis of six wells namely Fana_2, Fana E_1, Fana N_2, Fana W_1, Fana S_1, Fana SW_1, and sidewall core sample description of Fana_2 well. The petrophysical interpretation of the well-log data was carried out using Interactive Petrophysics software. The petrophysical properties of the hydrocarbon-bearing reservoirs were rated to be suitable reservoirs with average effective porosities varying from 25.8 to 31.6%, permeability varying from 123.6 to 427.7 mD, average water saturation values ranging from 15.2 to 33.0%, and the average range of hydrocarbon saturation is 67.0 to 84.8%. The values of volume of shale (Vsh) of the identified reservoirs indicated that the reservoirs are generally shaly to a high shale/clayey content. The dia-porosity and M-N cross plots revealed that the reservoirs of the Sokor-1 Formation are predominantly sandstone with shale/clay intercalations. The shale structural behaviour of the reservoirs revealed that the dominant shale was mainly dispersed and laminated shale volumes that could impact on the reservoir qualities. The spatial variations of petrophysical parameters indicated that lower N/G values favour the northeast and southern part of the map while the south area has a higher average effective porosity value. This study identified the southern part of the Fana Field as the most prospective and should be considered for the future exploration and development of the Fana field. [ABSTRACT FROM AUTHOR]

The petroleum system elements in the Komombo Basin have not yet been fully assessed. This study aims to evaluate source rocks, reservoirs and seals within the basin by integrating 2D seismic profiles and well logs together with geochemical, core and petrophysical data. Four source rocks are identified within the Cretaceous shale intervals of the B Member of the Six Hills, upper Maghrabi, Quseir and Dakhla formations. The quality of the B Member, upper Maghrabi and Quseir source rocks is good to very good, while the Dakhla Formation demonstrates good to excellent quality. Geochemical characteristics vary across the basin, with higher kerogen quality and thermal maturity observed in the depocentre compared to the flanks. Four reservoirs are recognized in the basin, including the A Member, C Member, sandstones within the D–G members of the Six Hills Formation, and the Sabaya and Maghrabi formations. The A Member reservoir demonstrates a moderate reservoir quality, while the C Member reservoir displays a fair quality. Numerous sandstones with 15–25% porosity values are observed within the D–G members. The Sabaya–Maghrabi reservoir generally exhibits good to very good quality, and is characterized by high porosity and varying permeability. Due to their high organic matter content, the Dakhla and Quseir formations show potential as unconventional reservoirs. Several shale units within the Komombo Basin serve as potential seal rocks. These include the B Member of the Six Hills, Abu Ballas, upper Maghrabi and Taref formations, as well as intra-formational shales within the reservoir rocks. Seismic interpretation indicates that faults are the predominant trapping mechanism in the basin. [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]

This study integrated palynological, geochemical, and petrophysical analysis that maybe used to analyze petroleum rocks. Shales and sediments rich in carbonate are essential in assessing the geological history of source rocks for the generation of petroleum. This emphasizes the important role of carbonate source rocks on a global level. This study evaluated the source and reservoir rocks of Meyal oilfield, Potwar Basin. Twenty-five well cutting samples from two wells and four fresh outcrop samples were studied. Results of TOC and Rock-Eval of Sakesar Formation samples showed fair to good TOC, Patala Formation in well had very good TOC contents in well both wells. S2 values of both formations' samples showed fair to good generative potential. Both formations lie in the maturity window having primarily mixed Type II/III and Type III kerogen with good oil/gas-generation potential. Palynological analysis also shows Type III kerogen in productive oil/gas window and in good agreement with pyrolysis data. Three forms of kerogen assemblages were identified: Structured and Bio-structured phytoclasts, opaque phytoclasts, and AOM. Petrophysical analysis of Chorgali formation showed average porosity ∼12.01%, average water saturation ∼37.71%, and average hydrocarbon saturation ∼62.28%, indicating average to good reservoir potential. Findings of this research will help and guide exploration and production companies. [ABSTRACT FROM AUTHOR]