Oil Shale Development Research Articles

Experimental study on the mechanical behavior of different lithologic shales in Qingshankou group under in-situ geological conditions

To investigate the mechanical behavior of shale under in-situ geological conditions, a novel experimental methodology called in-situ stress restoration triaxial compression (ISRTC) was proposed for testing shale under in-situ geostress. Then the ISRTC and conventional triaxial compression (CTC) tests were conducted on four different lithological shale core samples from the Qingshankou Formation reservoir to explore the differences in shale mechanical behavior between conventional laboratory conditions and in-situ geostress conditions. Compared to CTC tests, shale samples subjected to ISRTC tests demonstrated a noteworthy decrease in pre-peak elastic deformation, alongside an intensified and increased nonlinear deformation. These findings indicated that in-situ geostress restoration led to reduced brittleness and increased ductility of shale. Moreover, shale cores in the ISRTC test showed higher peak strength, residual strength, Young's modulus, and Poisson's ratio compared to CTC tests. The elastic energy, dissipative energy, and total energy in ISRTC tests were also greater than those in CTC tests. Furthermore, in-situ geostress restoration promoted numerous microcracks in shale, resulting in the release of more energy during failure, leading to a more complex failure mode. In CTC tests, shale damage concentrated in the stage of unstable crack propagation, whereas in ISRTC tests, the damage developed progressively throughout the entire loading stage. Additionally, the abundance of hard-phase minerals and scarcity of weak-phase minerals in shale had a smaller influence of in-situ stress restoration on peak strength and residual strength but a greater influence on the elastic modulus. This study provides valuable insights into the in-situ mechanical characteristics of different lithologies of Gulong shale in the Qingshankou group and serves as a scientific basis for the efficient development of shale oil.

Technological issues in shale oil development using horizontal wells in Ordos Basin, China

The PetroChina Changqing Oilfield Company has successfully achieved large-scale economical development of continental low-pressure freshwater lake interlayer shale oil in the Ordos Basin, China, targeting the gravity-flow sandstone thin interlayers in the organically rich mud shale formation of the seventh member of Yanchang Formation (Chang 7 Member) of Triassic,. Their significant discovery of the 1-billion-ton-level Qingcheng shale oil field, with a proven reserve of 1.052 × 109 t, has marked the establishment of China's first million-ton shale oil development zone. However, the extensive growth in production and construction has brought attention to notable challenges, including geological variances, low initial production, rapid decline, low recovery rates, and high development costs. Based on extensive field experience, this paper identifies several technological issues in shale oil development and offers comprehensive recommendations through systematic analysis. The encounter rate of horizontal shale oil wells, crucial for enhancing individual well productivity, can be improved both vertically and horizontally by prioritizing the extension direction of high-quality reservoirs during the deployment of horizontal wells. The contribution of fracturing fluid elasticity to the recovery rate is relatively low. Reservoir modification should not overemphasize large sand volume, fluid volume, or discharge. Additionally, optimizing parameters such as well spacing, vertical interlayer distribution, and fracture development is essential for maximizing the efficiency of fracturing scale, operation discharge, and other parameters. Variability in hydrocarbon source rock quality and the strength of diagenesis significantly impact oil saturation in sand bodies, affecting the selection of favorable areas and the distribution of high-quality reservoirs. Furthermore, the utilization of pre-fracturing with CO2 proves to be an effective approach in reducing viscosity and increasing the ultimate recovery rate. To ensure the efficient development of shale oil in the Changqing Oilfield, this paper emphasizes the necessity of deepening integrated geological studies, clarifying the main controlling factors of shale oil heterogeneous accumulation, and meticulously depicting three-dimensional sweet spots while exploring more effective development methodologies.

Study on the mechanical properties of sandstone-shale composite continental shale gas based on the discrete element method

China has abundant continental shale oil resources, and multiple shale oil exploration and development demonstration zones have been established, making it a key field for oil and gas exploration and development. However, drilling and fracturing treatment often encounter vertically interlaced and superimposed sandstone and shale reservoirs, which significantly affect the stability of the reservoir and the propagation of fractures. Therefore, it is of great significance to study the rock mechanics characteristics of sandstone-shale composite. Using the orthogonal experimental method for microscale parameter calibration, this study established the relationship between the macroscopic and microscopic parameters of sandstone-shale in the parallel bond model. The results of the orthogonal experimental scheme were analyzed using multi-factor variance analysis and linear regression analysis to determine the influence and ranking of each microscale parameter on the macroscopic parameters. Based on the results of uniaxial and triaxial compression experiments, the particle flow simulation of sandstone-shale composite rock samples was studied using the discrete element method. The study investigated the influence of the thickness ratio, combination form, and confining pressure of sandstone-shale on the mechanical properties of composite rock samples. The results showed that: (1) Under uniaxial loading conditions, for the combination form of sandstone on top and shale on the bottom (M-S type), the peak stress of the composite rock sample increased first and then decreased and then increased again with the increase of the thickness of sandstone; for the combination form of shale on top and sandstone on the bottom (S-M type), the peak stress of the composite sample decreased first and then increased and then decreased again with the increase of the thickness of shale. (2) After applying confining pressure, the compressive strength of the M-S type composite sample decreased with the increase of the thickness ratio of sandstone, while the compressive strength of the S-M type composite sample increased with the increase of the thickness ratio of shale as well as the compressive strength of the composite sample was lower than that of any complete rock sample. (3) Under uniaxial loading, the fracture mode of the composite sample was related to the combination form and the thickness ratio of different lithologies. For the M-S type sample, when the thickness ratio of sandstone was <30%, the sample was mainly fractured by tension, and when the thickness ratio of sandstone was >30%, it was mainly fractured by shear mode. For the S-M type sample, when the thickness ratio of shale was <70%, the sample had the most internal shear cracks, and when the thickness ratio of shale was >70%, it had the most tension cracks.

Development characteristics and controlling factors of fractures in lacustrine shale and their geological significance for evaluating shale oil sweet spots in the third member of the Shahejie Formation in the Qikou Sag, Bohai Bay Basin

Natural fractures are critical for shale oil and gas enrichment and development. Due to the extremely high heterogeneity of shale, the factors controlling the formation of internal fractures, especially horizontal fractures, remain controversial. In this study, we integrate thin section analysis and micro-computed tomography (CT) data from several lacustrine shale samples from the third member (Es3) of the Shahejie Formation, Qikou Sag, Bohai Bay Basin, to assess the fractures in detail. The goal is to reveal the development characteristics, controlling factors, and geological significance for evaluating sweet spots in a shale oil play. The fractures in the Es3 contain high-angle structural and horizontal bed-parallel fractures that are mostly shear and extensional. Various factors influence fracture development, including lithofacies, mineral composition, organic matter content, and the number of laminae. Structural fractures occur predominantly in siltstone, whereas bed-parallel fractures are abundant in laminated shale and layered mudstone. A higher quartz content results in higher shale brittleness, causing fractures, whereas the transformation between clay minerals contributes to the development of bed-parallel fractures. Excess pore pressure due to hydrocarbon generation and expulsion during thermal advance can cause the formation of bed-parallel fractures. The density of the bed-parallel and structural fractures increases with the lamina density, and the bed-parallel fractures are more sensitive to the number of laminae. The fractures are critical storage spaces and flow conduits and are indicative of sweet spots. The laminated shale in the Es3 with a high organic matter content contains natural fractures and is an organic-rich, liquid-rich, self-sourced shale play. Conversely, the siltstone, massive mudstone, and argillaceous carbonate lithofacies contain lower amounts of organic matter and do not have bed-parallel fractures. However, good reservoirs can form in these areas when structural fractures are present and the source, and storage spaces are separated.

Investigation of Key Controlling Factors and Applicability Boundaries of Natural Gas Injection for Shale Oil Development: A Case Study of Chang 7 Reservoir, Ordos Basin, China

The development of shale oil often encounters a series of challenges, such as insufficient natural energy, rapid declines in production, and low oil recovery. Given its wide availability and low cost, natural gas serves as an ideal injection medium to enhance shale oil recovery. Based on the foundational data from Chang 7 block X in the Ordos Basin and considering the influence of reservoir stress sensitivity, this study uses numerical simulation methods in conjunction with the random forest algorithm to examine gas flooding in shale oil. This research aims to identify the key factors influencing the effectiveness of natural gas flooding for shale oil and to establish a chart for the adaptive natural gas flooding development boundary. The findings suggest that, for reservoirs with permeability less than 0.2 × 10−3 μm2 and oil saturation below 55%, it is advisable to adopt longer fracture lengths during hydraulic fracturing to achieve better development results. After 10 years of gas flooding, continuing the use of this method is not recommended, and adjusting of the development strategy becomes essential. For extended development periods, avoiding long-length fractures is crucial to mitigate gas channeling and ensure the effectiveness of the development process. This study offers theoretical guidance and technical support for developing shale reservoirs with natural gas flooding.

Numerical Simulation Analysis of Wellbore Integrity and Casing Damage in High-Temperature Injection and Production of Shale Oil

Shale oil represents a relatively new form of unconventional oil and gas resource, and the extensive exploration and development of shale oil resources carry significant implications for China’s oil and gas supply and demand dynamics. At present, within the realm of low-maturity shale oil extraction technologies, the reservoir must be subjected to elevated temperatures ranging between 400 to 60 °C. Prolonged exposure of wellbores to such high temperatures can result in a substantial decrease in cement strength, the formation of microcracks due to cement cracking, and damage stemming from thermal stresses on the casing. Casing damage stands out as a prominent factor contributing to wellbore integrity failures and well shutdowns within the context of shale oil development. Given the limited natural energy reservoirs of shale oil formations, it becomes necessary to supplement the reservoir’s energy during the development process. Furthermore, shale oil exhibits high viscosity and poor flowability, and conventional water injection methods yield limited efficacy. This situation can induce significant shifts in the stress field and rock mechanical parameters, potentially activating specific formations and complicating the load dynamics on the casing. Consequently, the risk of failure increases. In light of these considerations, this study uses numerical simulations to study the integrity of high-temperature injection and production wellbores in shale oil and aims to encompass a comprehensive evaluation and analysis of the principal factors that influence casing damage, the fluctuations in thermal stress, and the yield strength of various steel grades of casings exposed to alternating stress conditions. Subsequently, this paper developed a model for simulating the temperature and pressure within shale oil and steam injection wellbores to support engineering design analysis. The research results indicate that the application of pre-stress results in a significant increase in stress at the casing pipe head while causing a noticeable decrease in stress within the pipe wall. When N80 casing is used, the entire casing experiences thermal stresses surpassing the casing’s yield limit. Stress concentration may arise at both ends of the external seal, potentially leading to casing contraction, shear failure, and, under non-uniform stress conditions, casing bending deformation. The temperature of steam injection significantly influences the temperature field of the casing wall, with stress values experiencing a marked reduction when the steam injection temperature decreases from 350 °C to 200 °C, underscoring the substantial impact of temperature on casing thermal stress. As the steam injection process advances along with injection-production cycles, shear stresses at the interface can exceed the bond strength, resulting in relative slippage between the cement and the casing. The bonding force between the wellbore and the cement primarily depends on the interface’s friction, particularly in the context of friction during wellhead lifting. This study endeavors to determine rational injection and production parameters under varying conditions, optimize completion methods, reduce casing damage, and extend the casing’s operational life; it aims to offer critical technical support for the safe and efficient development of shale oil resources.

Nanopore Structure and Multifractal Characteristics of Continental Shale Oil Reservoir: A Case Study from Ziliujing Shales in the Sichuan Basin

Thermal maturity of the shales from the Ziliujing Formation of the Jurassic age in the Sichuan Basin is in the hydrocarbon generation window, which makes it a candidate for shale oil and gas development. The meso- and macropore characteristics and heterogeneity of shales are important factors affecting the occurrence and development of oil and gas. However, the meso- and macropores of the Ziliujing shales have not been systematically studied. Thus, the mineral compositions and total organic carbon (TOC) of samples from this formation, as well as its pore structure, are analyzed by low-temperature N2 adsorption technique. Moreover, the heterogeneity of the pores was determined by multifractal analysis. The results show that the Ziliujing shales can be classified into three types according to the distributions of mineral compositions of carbonate and mixed and argillaceous shales. Results revealed that the smallest meso- and macropore volume (PV), the smallest specific surface area (SSA), and the largest average pore diameter (APD) occur in the carbonate shales. However, the largest PV and SSA and the smallest APD are observed in the argillaceous shales. The porosity of carbonate shales is mainly concentrated between 5 nm and 30 nm. Compared with carbonate shales, the porosity with pore sizes less than 30 nm of mixed and argillaceous shales shows a rapid increase. Furthermore, inorganic minerals are the main factors affecting the pore distributions, while TOC shows a weak effect. Herein, clay minerals significantly increase the mesopore volume and the pore number with a size of less than 30 nm. The Dq-q curves reveal that the meso- and macropore distributions of Ziliujing shales show multifractal behavior, but the multifractal characteristics of pores of various shales are distinctly different. The information dimension D1, the Hurst exponent H, and the width of the right side D0–D10 are key indicators to distinguish the local variations within the pore structure of different types of shales. The carbonate shales have the largest multifractal spectra width and the smallest D1 and H, while the opposite trend is found for the argillaceous shales. Clay minerals reduce the heterogeneity of the meso- and macropore distributions and increase the pore connectivity. Nevertheless, the carbonate minerals exhibit a reverse trend. Finally, it was found that TOC does not impact pore complexity as much. Collectively, this study supports our understanding of the occurrence of shale oil within various reservoir facies, thereby providing a guideline for future explorations in the Ziliujing Formation of the Jurassic age in the Sichuan Basin.

Depositional evolution of Eocene deep-lake mudrock lithofacies driven by astronomical forcing in the Dongying Depression, China

With the deepening of shale oil and gas exploration and development, researchers are more eager to understand the depositional evolutionary pattern of mudrock lithofacies, and the astronomical cycle is an important mechanism driving the depositional evolution of mudrock. In this paper, stratigraphy is divided based on astronomical cycle, and a stratigraphic sequence is established by using long eccentricity and precession cycles to dissect well sections with cores in the connecting well profiles. The relationship between the type of lithofacies development in response to the long eccentricity cycle is found. The lake basin mainly developed mudstone-dominated facies during high-value periods of long eccentricity, while sandstone facies developed in the slope zone and marl facies developed in the deep-lake zone during low-value periods. The relationship between lithofacies subcycles and amplitude variations in precession within the long eccentricity cycles has been determined. Sandstone or marl developed during periods of maximum precession, while mudstone developed during periods of minimum precession. The model of climate and depositional cycles controlled by long eccentricity and precession has been summarized. First, during periods of low long eccentricity, the amplitude of precession is small. This leads to cold and arid climates with reduced rainfall, resulting in less terrestrial input to the basin and a period of contraction. During periods of high long eccentricity, the climate is hot. This leads to hot and humid climates with increased rainfall, resulting in stronger terrestrial input to the lake basin and a period of expansion. Second, the amplitude variations in precession also affect the strength of terrestrial input. During periods of maximum precession, the received solar radiation is low, resulting in a dry and cold climate with reduced rainfall, weakening the terrestrial input to the basin. During periods of minimum precession, the received solar radiation increases, resulting in a hot and humid climate with increased rainfall, strengthening the terrestrial input to the basin. This study systematically investigates the depositional model and factors controlling the mudrock layers in the research area. The research results can contribute to the prediction of “sweet spots” for shale oil and gas and provide references for similar sedimentary basins.

Experimental Simulation on the Stress Disturbance Mechanism Caused by Hydraulic Fracturing on the Mechanical Properties of Shale Formation

Hydraulic fracturing is an indispensable technology for the development of shale oil and shale gas. Knowing the changes in the rock mechanical properties and failure modes during hydraulic fracturing is the key to improving the efficiency of hydraulic fracturing. Based on experiments and simulations, it can be concluded that the injection of fracturing fluid in the hydraulic fracturing caused deformation of the fracture surface, and the rock mechanical properties experienced degradation with a maximum reduction in the rock mechanical properties of 44.24%. As indicated in the experiments, the displacement of the measurement point was decreased with the distance increase between the injection point and the measurement point. According to the numerical simulations, tensile failure is the main failure mode in hydraulic fracturing, but the percentage of shear failure had an obvious increase with the increase in distance between the injection point and the measurement point. Comparing DDS #1 and DDS #5, the DDS #5 measurement point was farther away from the injection point, and the average percentage of shear failure increased from 21.94 to 52.72%. Meanwhile, the increase in the branch fractures also caused shear failure to occur. Comparing Sample 1 and Sample 3, in Sample 3, which had more branch fractures, the average percentage of shear failure increased from 33.12 to 37.58%. Due to the porous medium of the reservoir rock, the enormous pressure generated during the injection of fracturing fluid caused significant deformation of the fracture surface, leading to the tensile failure of the rock. The displacement of the fracture surface caused by the fracturing fluid injection also led to the deformation of the pore throat structure; thus, the shear failure increased when the measurement point was away from the injection point.

An improved inversion method for shale elastic parameters measurement based on ultrasonic resonance spectroscopy

The accurate measurement of elastic parameters of shale cores has important guidance for the exploration and development of shale oil and gas. The traditional shale acoustic experiment requires multiple samples from different angles and its preparation process is complex. Resonant Ultrasound Spectroscopy has the advantages of repeatable measurement, high accuracy, and the ability to obtain all elastic parameters from a single small sample. However, the influence of clamping force and measuring angle needs comprehensive analysis to ensure that formant can be measured as many and accurately as possible. This research first conducts sensitivity analysis on the elastic parameters of different shale to guide the experiment. In addition, due to the more complex inversion objective function of the anisotropic shale compared to isotropic samples, the traditional Levenberg–Marquardt method has a strong dependence on the initial value and is prone to falling into local optimal solution. The L-BFGS (limited memory BFGS) method is introduced into the inversion of anisotropic elastic parameters of shale, which can significantly improve the inversion efficiency. Finally, the robustness and reliability of the inversion method are validated through theoretical and experimental measurement results. [Work supported by the National Natural Science Foundation of China (42004117 and 42127807).]

Characteristics of Hydrocarbon-Generating Pressurization in Shale Series of Fengcheng Formation in the West and South of Mahu Sag, the Junggar Basin, China

Formation overpressure is an important controlling factor for the formation of high-yield oil reservoirs in the shale series of the Permian Fengcheng Formation in the west and south of Mahu Sag, the Junggar Basin. Hydrocarbon-generating pressurization (HGP) is an important cause of overpressure in the shale series of Fengcheng Formation, but the evidence for this viewpoint is insufficient. There is still no systematic study on the quantitative calculation and distribution characteristics of HGP in the Fengcheng Formation shale series. The control effect of HGP on the formation of high-pressure and high-yield reservoirs is still unclear. Therefore, by using the data of mudstone logging and measured formation pressure, the causes of overpressure in the Fengcheng Formation shale series are clarified. The predicted organic matter abundance, the predicted maturity and thickness of source rocks, and the statistical ratios of mudstone thickness to formation thickness in each section of Fengcheng Formation are used for HGP of shale series. Combined with the physical characteristics of reservoir rocks and the geochemical characteristics of oil, the control effect of HGP on the formation of high-pressure and high-yield reservoirs is analyzed. The results indicate the following: (1) The organic matter abundance and the thickness of source rocks predicted by the logging data gradually decrease from the eastern lake basin area to the western slope area. (2) The HGP of shale series in Fengcheng Formation is related to the hydrocarbon generation capacity and the overpressure preservation conditions of the source rocks. The HGP can be quantitatively predicted by comprehensively using the organic matter abundance, the maturity, the thickness of source rocks, and the ratios of mudstone thickness to formation thickness. (3) The HGP in the Fengcheng Formation shale series also gradually decreases in distribution characteristic from the eastern lake basin area to the western slope area. (4) The oil accumulation mode of the Fengcheng Formation shale series is that, with the drive of overpressure, the oil migrates slightly within the layer, and finally accumulates to form the oil reservoir. The research results are helpful to understand the distribution characteristics of HGP and the formation mechanism of high-pressure and high-yield reservoirs in the shale series of Fengcheng Formation in the west and south of Mahu Sag, and are of great significance to guide the exploration and development of shale oil and tight oil.

Pore Structure and Geochemical Characteristics of Alkaline Lacustrine Shale: The Fengcheng Formation of Mahu Sag, Junggar Basin

Shale oil and gas are currently the major fields of unconventional hydrocarbon exploration and development. The Fengcheng Formation (FF) shale in the Mahu Sag of the Junggar Basin is an alkaline lacustrine organic-rich shale with an extremely prospective shale oil potential. However, its strong heterogeneity and complex pore structure greatly influence the development of shale oil. It is significant to investigate the pore and geochemical characteristics of shale reservoirs for shale oil extraction. In this study, the pore structure and geochemical characteristics of FF have been investigated using core analysis, Rock-Eval pyrolysis, X-ray diffraction (XRD), field-emission scanning electron microscopy (FE-SEM), mercury injection capillary pressure (MICP), low-temperature gas adsorption (LTGA), and X-ray computed tomography (X-ray CT). The results show that the shale of FF has moderate organic matter abundance, and the kerogen is mainly of Type II, which is now at the peak of oil generation. Shale minerals are mainly composed of carbonate (dolomite and calcite) and siliceous (quartz and feldspar) minerals, with extremely low clay mineral content. The pore types are mainly intergranular pores (inter-P), intragranular pores (intra-P), and microfractures associated with mineral particles. The pore space is contributed predominantly by micropores of 0.5–1.2 nm and mesopores of 10–50 nm, whereas macropores are underdeveloped. The pores are mostly ink bottle- and slit-shaped, and the pore connectivity is relatively poor. The pore development of shale in the FF is influenced by organic matter abundance, thermal maturity, mineral composition, etc. Organic matter content (TOC), thermal maturity (Ro), and carbonate minerals have a positive effect on pore development, and the pore volume (PV) increases with TOC, Ro, and carbonate minerals. While clay minerals show a negative effect, the PV decreases with clay minerals. Additionally, the influence of the clay mineral content on the pore morphology of shale should not be ignored. This study investigates the pore structure and geochemical characteristics of the alkaline lacustrine shale of FF in Mahu Sag, which is significant to deepen the understanding of alkaline lacustrine shale and to improve the production of shale oil.

Pore Characteristics, Oil Contents and Factors Influencing Laminated Shale in the First Member of the Qingshankou Formation in the Gulong Sag, Northern Songliao Basin

To clarify the reservoir characteristics of laminated shale, the occurrence mechanism of shale oil and its influencing factors in the Gulong Sag, northern Songliao Basin, are studied to better guide the exploration and development of shale oil there. First, X-ray diffraction (XRD) and field-emission scanning electron microscopy (FE-SEM) are used to characterize the pore types, pore geneses and factors influencing the pore volume in the study area. Second, the organic matter of the samples is extracted with a mixture of dichloromethane and methanol. Total organic carbon (TOC), nitrogen adsorption and Rock-Eval tests are performed on the samples before and after extraction to reveal the pore size distribution after extraction. The factors influencing free and adsorbed shale oil and the lower limit of pore size are discussed in detail. The results show that interparticle pores (interP pores), intraparticle pores (intraP pores), organic matter pores (OM pores) and microfractures can be found in the laminated shale (Q1) in the Gulong Sag, Songliao Basin, and that the interP pores and intercrystalline pores in clay minerals are the main pores. The FE-SEM results show that the diameters of interP pores vary from several hundred nanometers to several microns, and their morphologies are mainly triangular, strip-shaped or irregular. The morphology of the intercrystalline pores in the clay minerals is generally irregular, depending on the crystal type and arrangement of clay minerals. According to the characteristics of the nitrogen adsorption and desorption curves, the pore morphologies are mainly slit-shaped pores, parallel-plate-shaped pores and ink-bottle-shaped pores. The pore size distribution is mostly bimodal, and the pore volume contribution is the greatest in the pore size range of 10~20 nm. Before and after extraction, the overall characteristics of the pore size distribution change only slightly, but the number of micropores increases significantly. Different minerals have different degrees of influence on the proportions of micropores, mesopores and macropores. Quartz mainly inhibits the formation of micropores, while the overall effect on mesopores and macropores is positive depending on the diagenetic period. Feldspar has a strong positive correlation with the micropore and mesopore proportions but is not highly correlated with the macropore proportions. The influence of the carbonate mineral content on the pore volume is not obvious because of its complex composition. The TOC content and vitrinite reflectance (Ro) are the two most important factors controlling free oil and adsorbed oil, and the contents of mineral components, such as felsic minerals, carbonate minerals and clay minerals, have no obvious correlation with shale oil content. With increasing pore volume, the contents of free oil and adsorbed oil increase, but the proportion of adsorbed oil decreases gradually. The correlation between the specific surface area and adsorbed oil content is poor. At normal temperatures and pressures, the lower limit of the pore diameters that can contain free oil is 4 nm, and the lower limit of the pore diameters that can contain movable oil is 10 nm.

Shale oil production predication based on an empirical model-constrained CNN-LSTM

Accurately predicting the production rate and estimated ultimate recovery (EUR) of shale oil wells is vital for efficient shale oil development. Although numerical simulations provide accurate predictions, their high time, data, and labor demands call for a swifter, yet precise, method. This study introduces the Duong–CNN–LSTM (D-C-L) model, which integrates a convolutional neural network (CNN) with a long short-term memory (LSTM) network and is grounded on the empirical Duong model for physical constraints. Compared to traditional approaches, the D-C-L model demonstrates superior precision, efficiency, and cost-effectiveness in predicting shale oil production.

Impact of fracturing fluid retention and flowback on development effect after large scale fracturing in shale oil wells: A case study from the shale oil of Chang 7 Member, Yanchang Formation, Ordos Basin

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

Hydrous Pyrolysis of Source Rocks with Different Maturity in Dongying Sag, Bohai Bay Basin, China: Implications for Shale Oil Exploration and Development

Shale oil yield, movability, and reservoir brittleness are three factors that must be focused on for shale oil exploration and development. The yield and composition of hydrocarbons and mineral composition have changed significantly during diagenesis, affecting the yield and movability of shale oil and the brittleness of the rock. In this study, the source rocks at different depths in the Dongying Sag were subjected to hydrous pyrolysis, and the yield and composition of pyrolyzed hydrocarbons and mineral composition were systematically analyzed. The brittleness index (BEI), weighted average specific surface area (SSAWA), and polarity index (PI) have been established to quantitatively characterize the brittleness and adsorption capacity of rock as well as the mobility of shale oil. The results suggest that diagenetic evolution controls rocks’ brittleness and adsorption capacity by changing their mineral composition. In the low-temperature stage, the mineral transformation is not obvious, and the BEI and SSAWA fluctuate in a small range. In the high-temperature stage, the rapid smectite illitization leads to an increase in the brittleness and a decrease in the adsorption capacity. In addition, the nonpolar components such as saturates and aromatics in the pyrolyzed hydrocarbons gradually increased with the increasing temperature, enhancing the mobility of the shale oil. Based on the three evaluation indexes of BEI, PI, and SSAWA, and combined with the changes in hydrocarbon yields during hydrous pyrolysis, we comparatively analyzed the differences in the mobility and yields of original soluble organic matter as well as pyrolyzed hydrocarbons of the source rocks at different depths. Based on the above results, it can be concluded that the shale in the depth range of 3300–3795 m is a favorable area for shale oil exploration and development in the study area. This work suggests that predicting the sweet spot for shale oil exploration and development requires more attention to the impact of diagenetic evolution on the composition of minerals and hydrocarbons.

Present-day in-situ stress prediction in the Duvernay shale of Simonette Block, Western Canada Sedimentary Basin

The Duvernay Formation of Simonette Block is rich in shale oil and gas resources. The present-day in-situ stress field is a crucial parameter during the exploration and development in this block, a better understanding of which can assist with drilling and completion engineering, fracturing stimulation, and well deployment. In this study, the present-day in-situ stress in the Duvernay shale is predicted and analyzed based on well calculations and geomechanical modeling. The findings indicate that, I, NE-SW-trending is the dominant S Hmax orientation. The S Hmax and S hmin are the maximum and minimum principal stress, indicating that the Duvernay shale of Simonette Block is under a strike-slip faulting stress regime. II, The present-day in-situ stress in the Duvernay shale is heterogeneously distributed, which is controlled by lithology difference, fault development, and distribution. High stress values in the upper shale member D layer are mainly in the northwestern and central parts of Simonette Block. III, The present-day differential stress in the Duvernay shale mainly ranges from 15 MPa to 30 MPa. Bedding-parallel fractures are relatively developed, aiding in the creation of complex fracture networks. The results are expected to offer geological references for further development of shale oil and gas in the Simonette Block.

Explainable Machine Learning-Based Method for Fracturing Prediction of Horizontal Shale Oil Wells

Hydraulic fracturing is a crucial method in shale oil development, and predicting production after hydraulic fracturing is one of the challenges in shale oil development. Conventional methods for predicting production include analytical methods and numerical simulation methods, but these methods involve many parameters, have high uncertainty, and are time-consuming and costly. With the development of shale oil development, there are more and more sample data on the geological parameters, engineering parameters, and development parameters of shale oil hydraulic fracturing, making it possible to use machine learning methods to predict production after hydraulic fracturing. This article first analyzes the impact of different parameters on initial production and recoverable reserves based on field data from Chang-7 shale oil in the Ordos Basin of China. Then, using the Particle Swarm Optimization (PSO) algorithm and the Gradient Boosting Decision Tree (GBDT) algorithm, machine learning models for initial production and recoverable reserves are established. The Local Interpretable Model-Agnostic Explanations (LIME) and Shapley Additive exPlanations (SHAP) explanation methods are used to explain the models. The study found that initial production is highly correlated with parameters such as the number of fracturing stages and fracturing fluid volume, while recoverable reserves are significantly related to parameters such as well spacing, area, and reserver-controlled. The PSO-GBDT model established in this study has an accuracy of over 85% and can be used for production prediction and subsequent parameter optimization research. By comparing the LIME and SHAP local explanation methods, it is shown that different explanation methods can obtain reasonable and credible local explanation results. This article establishes a high-precision shale oil well production prediction model and two model interpretation methods, which could provide technical support for shale oil well production prediction and production analysis.

A Study on the Mechanism of Casing Deformation and Its Control Strategies in Shale Oil Hydraulic Fracturing

The problem of casing deformation caused by large-scale hydraulic fracturing in shale oil wells severely restricts the efficient development of Gulong shale oil. In order to clarify the mechanism of casing deformation in shale oil wells, comprehensive analysis was conducted on engineering factors, multi-arm caliper logging, seismic attributes, and the distribution characteristics of casing deformations. This study shows that casing strength, cementing quality, and wellbore curvature are not the main controlling factors for casing deformation. Casing deformation is caused by the communication between hydraulic fractures and natural fractures during the fracturing process, which increases the fluid pressure in the natural fracture and induces shear slip, resulting in casing deformation due to shear stress. Based on the understanding of the mechanism of casing deformation in shale oil wells, two targeted casing deformation prevention and control methods are proposed. First, temporary plugging was implemented during the hydraulic fracturing process when the fluid volume reached 1000 m3, and the pumping rate was reduced to below 16 m3/min to reduce the internal fluid pressure of the fractures and control fracture slip, thereby minimizing the risk of casing deformation. Second, hollow particles were added to the cement to enhance the consolidation effect of the cement sheath and mitigate casing deformation caused by fracture slip. Research indicates that a hollow particle content of 15% can meet the requirements for casing deformation control in Gulong shale oil. These research results can provide important references for the prediction and prevention of casing deformation risks in shale oil and similar unconventional reservoirs during hydraulic fracturing.

Lithofacies influence characteristics on typical shale pore structure

Clarifying the three-dimensional pore throat structure characteristics of shale is the foundation for efficient development of shale oil and gas. In this paper, firstly, by using FIB-SEM high-tech characterization technology, three-dimensional quantitative characterization of shale pore-throat structures under different lithological conditions was carried out. Secondly, reconstruct through binary images to establish a three-dimensional pore-throat structure model. Thirdly, the coupling mechanism of “pore distribution, form factor, coordination number, throat diameter” is quantitatively clarified. Results show that: (a). For six shale samples, the volume fraction is mostly concentrated in the range of pore diameter greater than 20 nm and less than 300 nm. When the pore diameter is greater than 300 nm, the proportion of volume fraction is lower. (b). For six shale samples, the pore quantity distribution is mostly concentrated in the range of pore shape factor greater than 0.04 and less than 0.07. When the pore diameter is less than 0.04 or greater than 0.07, the pore quantity distribution is lower. (c). For six shale samples, the pore volume distribution is mostly concentrated in the range of coordination number greater than 1 and less than 4. When the pore diameter is less than 1 or greater than 4, the pore volume distribution is lower. (d). For six shale samples, the throat volume distribution is mostly concentrated in the range of throat diameter greater than 8 nm and less than 120 nm. When the throat diameter is less than 8 nm or greater than 120 nm, the throat volume distribution is lower. The pore structure of shale is very complex, mainly manifested by a variety of pore types.