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

In this study, the Xgboost method is employed for TOC estimation in mixed carbonate and siliciclastic shale from the Hashan area, Junggar Basin. The results show that this approach is effective for TOC estimation in this area although the model performance is not very excellent with a correlation coefficient of 0.54 between measured TOC and predicted TOC values, likely due to a small samples dataset. Therefore, the PCA method is applied to debase dimension of well log data from five dimensional to two-dimensional data, which enhances the correlation coefficient between the predicted and measured TOC from 0.54 to 0.68. Based on the model, the isopleth maps of TOC distributions in Fengcheng Formation were redrawn showing two shale oil exploration targets, which likely correspond to two depositional centers of this strata. All the same, the model in this work provides reliable data for shale oil evaluation in the study area and a good example under similar geological setting. [ABSTRACT FROM AUTHOR]

The Permian Fengcheng Formation (P1f.) in the Hashan area, situated on the southwestern margin of the Junggar Basin, has witnessed a remarkable breakthrough in shale oil exploration in recent years with nearly 789 million tons of shale oil resources. As a unique set of mixed sedimentary shales, the Fengcheng Formation in the Hashan area is characterized by mixed sedimentation of terrigenous siliciclastic sediments, authigenic minerals, and tuffaceous materials. However, the understanding of pore characteristics in the mixed sedimentary reservoir still remains limited, prohibiting accurate estimation of the oil content and insights into oil mobility. Scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), X-Ray Computer Tomography (X-CT), and geochemical analysis were performed to investigate the pore size distribution and main controlling factors of the mixed sedimentary reservoir. Results showed that the main pore types in the mixed sedimentary reservoir are intergranular pores and dissolution pores. The pores of the P1f. mixed shales in the Hashan area were classified into II-micropores (< 25 nm), I-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (> 1000 nm). In general, the mixed sedimentary rocks of P1f. formation feature few macropores but a large number of micropores and mesopores. The CS exhibits the most favourable physical properties among all lithofacies. It is concluded that the abundance and maturity of organic matter, mineral composition, sedimentary structure, and diagenesis of reservoir together impact the pore structure in the mixed sedimentary reservoirs. The maturity of organic matter and the content of tuffaceous minerals are the most significant in influencing the pore structure of P1f. shales. Overall, the pore structure of complex lithologic reservoir formed by mixed deposition and its influence on physical properties are studied, and the characteristics of the microscopic pore-throat system of the dominant lithofacies in the Hashan area are clarified, which is of great significance as a guide for the exploration and development of mixed sedimentary reservoirs in continental shale oil in China. [ABSTRACT FROM AUTHOR]

The key scientific problem to be solved in this paper is the optimal development and utilization model and the economic evaluation model of China's land-phase shale oil and gas resources, and the purpose of the research is to promote the large-scale commercial development and utilization of China's shale oil and gas resources, and to safeguard China's oil and gas energy security and the sustainable development of the economy. The article proposes to adopt the small surface element volume method (oil content rate method) to evaluate the pure shale oil resources, adopt the Cobb–Douglas production function model as the optimization model to measure the boundary production capacity of shale oil and gas, construct the optimal development and utilization model for shale oil and gas resources considering the five first-level safeguard indexes, namely, science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), and establish the basic constraint model for the optimal development and utilization of shale oil and gas resources. The basic constraint model, as well as the evaluation model of economic coefficients for the development and utilization of shale oil and gas resources were established. The pure shale oil resources are mainly calculated based on the movable oil content of shale. In the paper, the S1 of normal pyrolysis (300 °C) is regarded as movable oil, and the sum of S1 and evaporated hydrocarbon (light hydrocarbon) loss is the movable oil content of shale. The integrated geological-physical exploration-engineering comprehensive evaluation of China's land-phase shale oil-rich and high-yielding "sweet spot" is an important prerequisite for the realization of shale oil and gas resources to build production scale and effective development, and the least-squares method is used to estimate the average production function, the distance to the maximum value of the residuals, and the boundary capacity production function. The average production function and residual maximum distance are estimated by the least squares method, and the production function of the boundary capacity is derived, and the quotient of the boundary capacity and the actual capacity is calculated to get the capacity utilization rate, which can be used to analyze the potential of future shale oil and gas growth. The development of shale oil and gas resources in a target block requires comprehensive consideration of the first-level guarantee indicators such as science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), as well as more than 10 s-level indicators and a number of third-level indicators, in order to ensure that the oil companies maximize their profits by organizing the development and production. The economic coefficient can be expressed as the ratio of economically recoverable resources to geological reserves. The larger the economic coefficient for the development and utilization of shale oil and gas resources is, the better the economy of the area is, and the larger the proportion of shale oil and gas resources that can be exploited. There is little special literature on the optimal development and utilization model of shale oil and gas resources and energy security among many research results at home and abroad. The evaluation of pure shale oil using the small surface element volume method (oil content rate method) and the construction of the boundary capacity calculation model, the optimal development of the basic constraints model and the economic evaluation model that we have determined, although they can not yet fully cover all the links and factors related to the development and utilization of shale oil and gas resources, are not yet fully covered by our research work. However, our research work has given the model more geological and economic theoretical connotations, and provided an economic basis and technical reference for the large-scale and commercial development and utilization of shale oil and gas resources as an effective alternative to oil imports. [ABSTRACT FROM AUTHOR]

The existence of high-density bedding planes is a typical characteristic of shale oil reservoirs. Understanding the behavior of hydraulic fracturing in high-density laminated rocks is significant for promoting shale oil production. In this study, a hydraulic fracturing model considering tensile failure and frictional slip of the bedding planes is established within the framework of the unified pipe-interface element method (UP-IEM). The model developed for simulating the interaction between the hydraulic fracture and the bedding plane is validated by comparison with experimental results. The hydraulic fracturing patterns in sealed and unsealed bedding planes are compared. Additionally, the effects of differential stress, bedding plane permeability, spacing, and the friction coefficient of the bedding plane are investigated. The results showed that a single main fracture crossing the bedding planes is more likely to form in sealed bedding planes under high differential stress. The decrease in bedding plane permeability and the increase in the friction coefficient also promote the fracture propagating perpendicular to the bedding planes. Shale with high-density bedding planes has a poorer fracturing effect than that with low-density bedding planes, as the hydraulic fracture is prone to initiate and propagate along the bedding planes. Moreover, higher injection pressure is needed to maintain fracture propagation along the bedding. An increase in bedding density will lead to a smaller fracturing area. Fracturing fluid seepage into the bedding planes slows shale fracturing. It is recommended that increasing the injection flow rate, selecting alternative fracturing fluids, and employing multi-well/multi-cluster fracturing may be efficient methods to improve energy production in shale oil reservoirs. [ABSTRACT FROM AUTHOR]

Taking Gonghe oil shale as raw material, the rapid pyrolysis experiment was carried out using the Py-GC/MS device under different atmospheres. The effects of different pyrolysis atmospheres on the rapid pyrolysis products of Gonghe oil shale were studied. The results show that the H2 atmosphere can not only increase the content of saturated hydrocarbons and reduce the content of unsaturated hydrocarbons but also reduce the content of oxygen-containing heterocyclic compounds. This may be because more H free radicals under the H2 atmosphere are produced to react with the free radical fragments formed by kerogen decomposition. The coupling between H free radicals and free radical fragments can prevent the polymerization among macromolecular free radicals and inhibit the generation of heavy byproducts, which can promote the kerogen pyrolysis and increase the release of volatile matter. In addition, the pyrolysis atmosphere is conducive to the deoxygenation of oxygen-containing heterocyclic compounds to a certain extent. [ABSTRACT FROM AUTHOR]

Hydrothermal activity is widespread in sedimentary basins, but its dual effects (chemistry and temperature) on shale reservoirs are rarely discussed. In this research, we systematically collected 33 well core samples from Q1 to Q9 units in Gulong Sag, Songliao Basin, and analyzed them using a variety of analytical techniques, including a field emission scanning electron microscopy (FE-SEM), an energy-dispersive spectrometer (EDS), X-ray diffraction (XRD), and stable C-O isotopes. Combined with the collected vitrinite reflectance (Ro), total organic carbon (TOC), and soluble hydrocarbon content data, which is the sum of free oil (pyrolysis S1) and sorb oil content (pyrolysis S2), the results show that (1) Q4 and Q8 units have large amounts of hydrothermal minerals, and its C-O isotope obviously shifts to negative, which implied those units are the main hydrothermal fluid influence area; (2) the hydrothermal activity occurred in the late depositional period of Q1–Q9 units such that its geochemistry has little effect on the proliferation of algae blooms, but its high temperature calculated by δ18O temperature formulas (around 208 °C) promoted the organic matter maturation process around Q4 and Q8; and (3) the overpressure caused by hydrothermal activity protected the shale reservoir and minimized the decrease in mineral reservoir brittleness index caused by hydrothermal fluid influence. We suggest that the shale reservoir affected by hydrothermal fluid will become a good geology "dessert", and its upper and/or lower bounds can form an engineering "dessert" due to the precipitation of large amounts of brittle carbonate minerals. [ABSTRACT FROM AUTHOR]

Despite the abundance of shale-oil and tight-oil reserves in the Fengcheng Formation within the Mahu Sag, exploration and development efforts for both types of reservoir are still in their early stages. A comprehensive examination and comparison of the pore structures of these reservoirs can establish rational classification and evaluation criteria. However, there is a dearth of comparative analyses focusing on the pore structures of shale-oil and tight-oil reservoirs within the Fengcheng Formation. This study addresses this gap by systematically analyzing and comparing the pore structures of these reservoirs using various techniques such as X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption, and mercury intrusion capillary pressure experiments (MICP). The results show that the shale oil within the Fengcheng Formation exhibits a higher content of carbonic acid compared to the tight-oil samples. Furthermore, it demonstrates smaller displacement pressure and median pressure, a larger sorting coefficient, and superior permeability in contrast to tight oil. Notably, the shale oil within the Fengcheng Formation is characterized by abundant striated layer structures and micro-fractures, which significantly contribute to the microstructural disparities between shale-oil and tight-oil reservoirs. These differences in microstructures between shale oil and tight oil within the Fengcheng Formation in the Mahu Sag region delineate distinct criteria for evaluating sweet spots in shale-oil and tight-oil reservoirs. [ABSTRACT FROM AUTHOR]

Real-time high-temperature CT scanning and a rock-mechanics test system were employed to investigate the mechanical properties of oil shale at temperatures from 20 to 600 °C. The results reveal that up to 400 °C, the aperture of fractures initially decreases and then increases when loading is perpendicular to the bedding. However, the number and aperture continuously increase when loading is parallel to the bedding. Beyond 400 °C, the number of pores increases and the aperture of the fractures becomes larger with rising temperature. The changes in microstructures significantly impact the mechanical properties. Between 20 and 600 °C, the compressive strength, elastic modulus, and Poisson's ratio initially decrease and then increase under perpendicular and parallel bedding loadings. The compressive strength and elastic modulus reach minimum values at 400 °C. However, for Poisson's ratio, the minimum occurs at 500 °C and 200 °C under perpendicular and parallel bedding loadings, respectively. Simultaneously, while the crack damage stress during perpendicular bedding loading, σcd-per, initially exhibits an upward trend followed by a decline and subsequently increases again with temperature increasing, the initial stress during perpendicular bedding loading, σci-per, parallel bedding loading, σci-par, and damage stress, σcd-par, decrease initially and then increase, reaching minimum values at 400 °C. These research findings provide essential data for reservoir reconstruction and cementing technology in the in situ mining of oil shale. [ABSTRACT FROM AUTHOR]

Oil content and the movability of shale oil are important indicators for the evaluation of continental shale oil. In recent years, the sandwiched shale oil in the fourth member of the Shahejie Formation in the Liaohe Western Depression area of the Bohai Bay Basin has shown great exploration potential, while the understanding of shale oil content and the movability of shale oil is weak. In this study, through a combination of core observations and experiments, we clarified the shale lithofacies types in the fourth member of the Shahejie Formation in the Liaohe Western Depression and explored the influencing factors of the characteristics in the oil-bearing and movability of shales in different lithofacies. The results of the study show that the organic matter content of the shale is high (TOC = 2.2–4.3%), but the maturity of thermal evolution is low (Ro = 0.38–0.55%), and the mineral component is dominated by clay minerals (30.3–72.7%), with quartz, feldspar, and other feldspar minerals developing secondarily. According to the content of organic matter, the mineral component, and the sedimentary structure, five types of lithofacies can be classified: organic-rich laminated clay-bearing felsic shale lithofacies (LS1), organic-rich laminated clay felsic mixed shale lithofacies (LS2), organic-rich layered clay felsic mixed shale lithofacies (LS3), organic-containing massive felsic-bearing clay shale lithofacies (LS4), and organic-containing massive clay felsic mixed shale lithofacies (LS5). The oil content of shale is mainly affected by the organic matter. The rate of increase in oil content of shale is fastest when the organic matter content is between 2 and 4%. The movability of shale oil is mainly controlled by the sedimentary structure, mineral component, and microscopic pore structure; the more the shale laminae is developed, the lower the clay content is, and the more the pore space is developed, the better the movability of shale oil is. Combined with the results of the shale oil content and mobility analysis in the study area, LS2 and LS3 are the dominant lithofacies in the fourth member of the Shahejie Formation in the study area, followed by LS1 >LS5 >LS4, so shale oil exploration should focus on the development of LS2 and LS3. [ABSTRACT FROM AUTHOR]

The Chang 7, Chang 8, and Chang 9 members of the Triassic Yanchang Formation in the Fuxian–Ganquan area of the Ordos Basin all develop lacustrine shales. However, current geological research and shale oil and gas exploration mainly focus on Chang 7 shale, with little attention given to Chang 8 and Chang 9 shale formations. Based on the experimental data from whole-rock mineral analysis, organic geochemical analysis, field-emission scanning electron microscopy analysis, and hydrocarbon generation simulation experiments, combined with well-logging data, the shale distribution, mineral composition, source rock characteristics, reservoir properties, and oil and gas contents of Chang 7, Chang 8, and Chang 9 shales were comprehensively analyzed. Moreover, the effect of integrated exploration of multilayer shales was evaluated based on a specific example. The results indicate that three sets of shales are extensively developed in the Yanchang Formation in the study area, but their thicknesses and distribution ranges vary greatly, and Chang 7 shale has the largest thickness and distribution range. Their clay mineral contents are relatively high, reaching an average of 46.7%. Also, the types of their organic matter are mainly Type I-II1, with high abundance and an average organic carbon content of 4.7%. Their vitrinite reflectance is between 0.7% and 1.3%, indicating that they are in the oil–gas symbiosis stage. Furthermore, they develop various types of nanoscale pores, such as intergranular pores, intragranular pores, and organic pores, and their porosity has an average value of 2.51% and increases significantly after crude oil is extracted. Oil and gas coexist in these three sets of shales, with an average free hydrocarbon content of 3.9 mg/g and an average gas content of 2.6 m3/t. Finally, in order to explore the integrated exploration and development of multilayer shale oil and gas formations, multilayer staged fracturing tests were carried out on six vertical wells for three sets of shales; the production results show that the gas production rate significantly increased by threefold, with a daily oil production rate of more than 1 ton. [ABSTRACT FROM AUTHOR]

Following hydraulic fracturing operations within shale reservoirs, there frequently exists a considerable volume of residual oil that remains encapsulated within the matrix, thereby impeding the singular shale well's productivity from attaining projected yields. In pursuit of augmenting the recovery efficiency of shale oil, the industry has widely adopted a post-fracture shut-in strategy within shale oil wells. This methodology is predicated on the aspiration to escalate both the production output and the recovery factor of the oil well by leveraging the imbibition and displacement mechanisms of the fracturing fluid throughout the shut-in interval. There are many kinds of surfactants, and how to select surfactants suitable for shale reservoirs from these many surfactants has become a key issue in improving shale reservoir recovery. In this study, a new surfactant screening method for improving imbibition recovery in shale reservoirs is proposed. An interfacial tension test, contact angle test, and anti-adsorption test are carried out for the collected surfactant products, and the interfacial tension, contact angle, and anti-adsorption are gradually used as indicators. The type of surfactant is initially screened. On this basis, the static imbibition experiment of shale is made to determine the type and concentration of surfactants suitable for shale oil development. The results show that the surfactants screened by this method have the characteristics of decreasing oil–water interfacial tension, varying rock wettability, and strong anti-adsorption, which can effectively improve imbibition efficiency. The study results herein can provide technical support for optimizing shale oil surfactants and provide a new idea for improving oil exploitation in low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

Fluid components in cores are crucial parameters in evaluating the quality of a shale reservoir in both laboratory analyses and log interpretation. In the Gulong area, shale reservoirs are characterized by a high clay content, with clay spaces hosting both oil and water phases, complicating the occurrence mechanism of fluid components, as a result, traditional research methods are no longer applicable. As an advanced technique, nuclear magnetic resonance (NMR) has been applied in oilfields to determine the specific petrophysical properties of rocks. To more accurately identify the types of fluid components, this study carried out a new, well-designed 2D NMR experiment, rock pyrolysis experiment, and quantitative oil and water detection experiment (QOWDE) to study the Gulong shale. This study measured the 2D NMR map of the original state, saturation state, centrifugal state, and pyrolysis at different temperatures, and conducted mutual verification between the QOWDE and 2D NMR pyrolysis experiments to obtain the distribution of different components of Gulong shale on the 2D NMR map. Based on the experimental results, this study developed a component identification template suitable for the Gulong area and calculated the 2D NMR porosity and saturation from it. This lays a foundation for the analysis and application of fluid components in the Gulong region and provides a new experimental basis and methodological support for porosity and saturation calculations. [ABSTRACT FROM AUTHOR]

Given the friction and drag reduction effects observed in various biological hexagonal structures in nature, a new design was implemented on the rubber surface of the stator of a submersible screw pump. This design featured a multilayer concentric hexagonal groove structure. Furthermore, a composite multilayer hexagonal structure integrating grooves and pits was also developed and applied. This study investigated the influence of groove layer number, groove depth, pit depth, and multilayer hexagonal groove texture arrangement on the rubber surface flow characteristics. Additionally, the pressure field state, the degree of influence on the oil film-bearing capacity, and the biomimetic and hydrodynamic lubrication theories were tested using the finite element analysis method. Tribological experiments were conducted on nanosecond laser-processed rubber textures under simulated liquid lubrication conditions, reflecting actual shale oil well experiments. These experiments aimed to investigate the influence of multilayer hexagonal shape parameters on the tribological characteristics of the stator-rotor friction pair of a submersible screw pump. The results indicated that with a constant overall size, a multilayer hexagonal structure with ~0.1 mm groove depth enhanced the oil film-bearing capacity, providing significant friction and drag reduction. For composite textures, a deeper pit depth within the study area enhanced the oil film-bearing capacity. Furthermore, a gradient arrangement of groove textures featuring wider outer grooves and shallower depth exhibited superior performance in terms of bearing capacity. [ABSTRACT FROM AUTHOR]

It is important to study the theory and technology of coal-based oil shale dry beneficiation in China. Traditional separation density models are obtained through particle force analysis, but most studies tend to ignore the influence of medium resistance and bubble disturbance, which seriously limit the predicted accuracy of the separation density model. Therefore, the force on simulated mineral particles (steel balls) in pulsed fluidized bed (PFB) under different operating conditions was tested. It was found that the force decreases with the increase of gas velocity and distance from the distributor. The change of pulsation frequency has less influence on force. The force equilibrium equation was established and verified to be within 10% error; Finally, we obtain a new separation density model of PFB. This is of great importance for the industrialization and scale-up of dry beneficiation. [ABSTRACT FROM AUTHOR]

This study investigates the genesis of analcite in black shale from continental lakes and its implications for hydrocarbon enrichment, with a case study of the Permian Pingdiquan Formation in the Junggar Basin, Xinjiang, China. As an alkaline mineral, analcite is extensively developed in China's lacustrine black shale hydrocarbon source rocks and is linked to hydrocarbon distribution. However, the mechanisms of its formation and its impact on hydrocarbon generation and accumulation remain insufficiently understood. This paper employs a multi-analytical approach, including petrological observations, geochemical analysis, and X-ray diffraction, to characterize analcite and its association with hydrocarbon source rocks. The study identifies a hydrothermal sedimentary origin for analcite, suggesting that it forms under conditions of alkaline lake water and volcanic activity, which are conducive to organic matter enrichment. The analcite content in the studied samples exhibits a significant variation, with higher contents associated with hydrocarbon accumulation zones, suggesting its role in hydrocarbon generation and accumulation. This paper reports that analcite-bearing rocks display characteristics of high-quality reservoirs, enhancing the permeability and porosity of the rock, which is essential for hydrocarbon storage and migration. In conclusion, this paper underscores the importance of analcite as a key mineral indicator for hydrocarbon potential in black shale formations and provides valuable insights for further geological and hydrocarbon exploration in similar settings. [ABSTRACT FROM AUTHOR]

The comment by Yin (2024) referred to the systematic morphology and identification of the newly recovered in situ ammonite assemblage Tiltoniceras sp. and Hildoceratidae sp. from the Bilong Co section in the Qiangtang Basin. Yin (2024) suggests that Tiltoniceras sp. should be assigned to Oxycerites aspidoides. Upon re-examination of our paper and the reply to the released comment, it is demonstrated that the morphologic characteristics of the recovered ammonites are more consistent with Tiltoniceras rather than Oxycerites aspidoides. These ammonites, along with in situ calcite U–Pb age (ca. 181 Ma), carbon isotope stratigraphy, and age-diagnostic palynomorphs, constrain the age of the Bilong Co oil shale to the Lower Jurassic (Toarcian) with plausible credentials. [ABSTRACT FROM AUTHOR]

In-situ conversion presents a promising technique for exploiting continental oil shale formations, characterized by highly fractured organic-rich rock. A 3D in-situ conversion model, which incorporates a discrete fracture network, is developed using a self-developed thermal-flow-chemical (TFC) simulator. Analysis of the model elucidates the in-situ conversion process in three stages and defines the transformation of fluids into three distinct outcomes according to their end stages. The findings indicate that kerogen decomposition increases fluid pressure, activating fractures and subsequently enhancing permeability. A comprehensive analysis of activated fracture permeability and heating power reveals four distinct production modes, highlighting that increasing heating power correlates with higher cumulative fluid production. Activated fractures, with heightened permeability, facilitate the mobility of heavy oil toward production wells but hinder its cracking, thereby limiting light hydrocarbon production. Additionally, energy efficiency research demonstrates the feasibility of the in-situ conversion in terms of energy utilization, especially when considering the surplus energy from high-fluctuation energy sources such as wind and solar power to provide heating. [ABSTRACT FROM AUTHOR]

The continental shale reservoirs of Jurassic Lianggaoshan Formation in Sichuan Basin contain thin lamina, which is characterized by strong plasticity and developed longitudinal shell limestone interlayer. To improve the production efficiency of reservoirs by multi-cluster fracturing, it is necessary to consider the unbalanced propagation of hydraulic fractures and the penetration effect of fractures. This paper constructed a numerical model of multi-fracture propagation and penetration based on the finite element coupling cohesive zone method; considering the construction cluster spacing, pump rate, lamina strength and other parameters studied the influencing factors of multi-cluster fracture interaction propagation; combined with AE energy data and fracture mode reconstruction method, quantitatively characterized the comprehensive impact of the strength of thin interlayer rock interfaces on the initiation and propagation of fractures that penetrate layers, and accurately predicted the propagation pattern of hydraulic fractures through laminated shale oil reservoirs. Simulation results revealed that in the process of multi-cluster fracturing, the proportion of shear damage is low, and mainly occurs in bedding fractures activated by outer fractures. Reducing the cluster spacing enhances the fracture system's penetration ability, though it lowers the activation efficiency of lamina. The high plasticity of the limestone interlayer may impact the vertical propagation distance of the main fracture. Improving the interface strength is beneficial to the reconstruction of the fracture height, but the interface communication effect is limited. Reasonable selection of layers with moderate lamina strength for fracturing stimulation, increasing the pump rate during fracturing and setting the cluster spacing reasonably are beneficial to improve the effect of reservoir stimulation. [ABSTRACT FROM AUTHOR]

The efficient pyrolysis and conversion of organic matter in organic-rich shale, as well as the effective recovery of pyrolysis shale oil and gas, play a vital role in alleviating energy pressure. The state of carbon dioxide (CO2) in the pyrolysis environment of shale reservoirs is the supercritical state. Its unique supercritical fluid properties not only effectively heat organic matter, displace pyrolysis products and change shale pore structure, but also achieve carbon storage to a certain extent. Shale samples were made into powder and three sizes of cores, and nitrogen (N2) and supercritical carbon dioxide (ScCO2) pyrolysis experiments were performed at different final pyrolysis temperatures. The properties and mineral characteristics of the pyrolysis products were studied based on gas chromatography analysis, Xray diffraction tests, and mass spectrometry analysis. Besides, the pore structure characteristics at different regions of cores before and after pyrolysis were analyzed using N2 adsorption tests to clarify the impact of fracturing degree on the pyrolysis effect. The results indicate that the optimal pyrolysis temperature of Longkou shale is about 430 °C. Compared with N2, the oil yield of ScCO2 pyrolysis is higher. The pyrolysis oil obtained by ScCO2 extraction has more intermediate fractions and higher relative molecular weight. The ScCO2 can effectively improve the pore diameter of shale and its effect is better than that of N2. The micropores are produced in shale after pyrolysis, and the macropores only are generated in ScCO2 pyrolysis environments with temperatures greater than 430 °C. The pore structure has different development characteristics at different pyrolysis temperatures, which are mainly affected by the pressure holding of volatile matter and products blocking. Compared to the surface of the core, the pore development effect inside the core is better. With the decrease in core size, the pore diameter, specific surface area, and pore volume of cores all increase after pyrolysis. [ABSTRACT FROM AUTHOR]

This document is a special issue of the journal Catalysts, focusing on catalysis for bitumen/heavy oil upgrading and petroleum refining. The issue explores various approaches and methods to enhance the extraction and upgrading of heavy and extra-heavy oil from unconventional reserves. It discusses the use of enhanced oil recovery techniques such as chemical methods, electromagnetic energy, and thermal enhanced oil recovery. The issue also covers the use of catalysts in steam injection for heavy oil upgrading, the impact of rock formations on aquathermolysis, and the use of nanoparticles for in situ upgrading of heavy crude oil. Additionally, it examines catalytic cracking and hydrocracking for secondary refining processes and explores the production of hydrocarbon feedstocks from food and solid waste materials. The issue concludes with a review of catalysts for biodiesel production. Overall, the findings presented in this special issue contribute to our understanding of heavy oil upgrading, secondary refining processes, and the extraction of petrochemical products from waste materials. [Extracted from the article]

Shale oil and gas resources are abundant in the Chang 7 shale of the Yanchang Formation in Ordos Basin. To determine the characteristics and influencing factors of hydrocarbon generation evolution of the Chang 7 shale, a series of thermal simulation experiments were conducted on low‐maturity shale and kerogen samples. The results indicate that the maximum yield of shale oil are 294.5 and 304.3 mg/g TOC for kerogen sample at heating rates of 20 and 2°C/h, and the corresponding experimental temperatures are 360.2°C and 408.0°C, respectively. The utilization of lower heating rates is favourable for shale oil generation and it is recommended to employ a lower heating rate during in situ heating processes to maximize the economic benefits. The formation of crude oil cracking gas begins when simulating temperature exceeds 528.0°C (Easy Ro 2.6%) at a heating rate of 20°C/h and 480.0°C (Easy Ro 2.5%) at a heating rate of 2°C/h, as indicated by the carbon isotopic composition of gaseous hydrocarbons. The maximum oil production rate of the rock powder sample is 159.8 mg/g TOC, which is lower than that of the kerogen sample. It suggests that certain minerals in the Chang 7 shale may impede hydrocarbon generation. After the addition of pyrite, the highest yield of shale oil is 213.96 mg/g TOC, 33.9% higher than the yield of the original rock powder sample, reflecting the positive catalytic effect of pyrite on hydrocarbon generation of Chang 7 shale. Under geologic conditions, pyrite catalytic hydrocarbon generation may act primarily on the migration of organic matter by macromolecules, which considerably increases the probability of direct contact between pyrite and organic matter. Therefore, the organic‐rich shale with high pyrite content in Chang 7 member is the preferred target for in situ conversion of shale oil and gas in the Ordos Basin. [ABSTRACT FROM AUTHOR]

Shale oil has become a crucial unconventional resource, bolstering energy supply security, and it is important to accurately predict shale oil production dynamics. However, traditional prediction methods are faced with the challenges of large data fluctuations and numerous interference factors, which make accurate prediction difficult. This paper introduces a deep learning approach, specifically a physical constraint-based convolutional neural network combined with long short-term memory and attention mechanism (CNN-LSTM-AM), to predict shale oil production dynamics. Initially, the correlation analysis method is used to analyze the correlation strengths of features with the prediction target, and the data that are most strongly correlated with the daily oil production are screened out and preprocessed. Key features are then extracted; that is, the CNN layer's output is fed into the LSTM layer, the output of which informs a fully connected layer for time-series production predictions. The model integrates an AM to concentrate on vital data aspects. In the "five-linear flow" formula, the imbibition is hard-coded into the shale oil production prediction model. Physical constraints are introduced into the model. Data driven and empirical formulas are used to introduce a loss function as a constraint condition in the training process of a machine learning model to improve the interpretability and predictive ability of the model. During the tuning phase, Bayesian optimization is used to fine-tune the model's hyperparameters. Shapley additive explanation and accumulated local effects analyses are used to further assess and quantify the significance of the essential parameters, thus optimizing the prediction effectiveness. [ABSTRACT FROM AUTHOR]

Oil shale's natural floatability depends on its organic content which is negatively affected by the presence of inorganic impurities. Thus, the feed preparation, particularly in the crushing and grinding processes, affects the liberation of organic components as well as their surface properties. In this article, attrition scrubbing and ball milling, as different feed preparation techniques, were used to study their effects on oil shale flotation. The ground products using either technique were floated, using either pine oil or sodium oleate. The flotation results indicated that the organic recovery was improved using both reagents with higher improvement in the case of pine oil. Starting from 10% organics in the feed, the floated organics, at pH 3 using 0.4 kg/t pine oil and particle size of −0.1 + 0.045 mm, are improved to 23.5% and 17.8% using ball mill and attrition products, respectively. Interestingly, at a higher pine oil dosage, floated attrition products result in a higher grade and recovery than the ball mill products. The shearing mechanism in attrition is found to be more suitable for liberating organics in oil shale whereas maximum organic content and recovery of 25.7% and 91.4%, respectively were achieved using 7.5 kg/t pine oil. [ABSTRACT FROM AUTHOR]

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the "injection + soaking" stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the "huff" stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved. [ABSTRACT FROM AUTHOR]

This paper reviews the basic research means for oilfield development and also the researches and tests of enhanced oil recovery (EOR) methods for mature oilfields and continental shale oil development, analyzes the problems of EOR methods, and proposes the relevant research prospects. The basic research means for oilfield development include in-situ acquisition of formation rock/fluid samples and non-destructive testing. The EOR methods for conventional and shale oil development are classified as improved water flooding (e.g. nano-water flooding), chemical flooding (e.g. low-concentration middle-phase micro- emulsion flooding), gas flooding (e.g. micro/nano bubble flooding), thermal recovery (e.g. air injection thermal-aided miscible flooding), and multi-cluster uniform fracturing/water-free fracturing, which are discussed in this paper for their mechanisms, approaches, and key technique researches and field tests. These methods have been studied with remarkable progress, and some achieved ideal results in field tests. Nonetheless, some problems still exist, such as inadequate research on mechanisms, imperfect matching technologies, and incomplete industrial chains. It is proposed to further strengthen the basic researches and expand the field tests, thereby driving the formation, promotion and application of new technologies. [ABSTRACT FROM AUTHOR]

By benchmarking with the iteration of drilling technology, fracturing technology and well placement mode for shale oil and gas development in the United States and considering the geological characteristics and development difficulties of shale oil in the Jiyang continental rift lake basin, East China, the development technology system suitable for the geological characteristics of shale oil in continental rift lake basins has been primarily formed through innovation and iteration of the development, drilling and fracturing technologies. The technology system supports the rapid growth of shale oil production and reduces the development investment cost. By comparing it with the shale oil development technology in the United States, the prospect of the shale oil development technology iteration in continental rift lake basins is proposed. It is suggested to continuously strengthen the overall three-dimensional development, improve the precision level of engineering technology, upgrade the engineering technical indicator system, accelerate the intelligent optimization of engineering equipment, explore the application of complex structure wells, form a whole-process integrated quality management system from design to implementation, and constantly innovate the concept and technology of shale oil development, so as to promote the realization of extensive, beneficial and high-quality development of shale oil in continental rift lake basins. [ABSTRACT FROM AUTHOR]

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle--Late Devonian, Early Carboniferous (Middle--Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian--Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and "shale reservoirs" are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246x1012 t and 290x1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the "shale revolution", the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007--2023, shale oil and gas production in the United States increased from approximately 11.2x104 tons of oil equivalent per day (toe/d) to over 300.0x104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on "cube development" or "co-development". Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of "U-shaped" wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production. [ABSTRACT FROM AUTHOR]

Based on the production curves, changes in hydrocarbon composition and quantities over time, and production systems from key trial production wells in lacustrine shale oil areas in China, fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity. The concept of "component flow" for shale oil was proposed, and the formation mechanism and conditions of component flow were discussed. The research reveals findings in four aspects. First, a miscible state of light, medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles, which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents, such as heavy hydrocarbons, thereby decreasing shale oil viscosity and enhancing fluidity and outflows. Second, small-molecule aromatic hydrocarbons act as carriers for component flow, and the higher the content of gaseous and light hydrocarbons, the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt, thus increasing their plastic deformation ability and bringing about better component flow efficiency. Third, higher formation temperatures reduce the viscosity of heavy hydrocarbon components, such as wax, thereby improving their fluidity. Fourth, preservation conditions, formation energy, and production system play important roles in controlling the content of light hydrocarbon components, outflow rate, and forming stable "component flow", which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil. The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil. [ABSTRACT FROM AUTHOR]

This paper expounds the basic principles and structures of the whole petroleum system to reveal the pattern of conventional oil/gas -- tight oil/gas -- shale oil/gas sequential accumulation and the hydrocarbon accumulation models and mechanisms of the whole petroleum system. It delineates the geological model, flow model, and production mechanism of shale and tight reservoirs, and proposes future research orientations. The main structure of the whole petroleum system includes three fluid dynamic fields, three types of oil and gas reservoirs/resources, and two types of reservoir-forming processes. Conventional oil/gas, tight oil/gas, and shale oil/gas are orderly in generation time and spatial distribution, and sequentially rational in genetic mechanism, showing the pattern of sequential accumulation. The whole petroleum system involves two categories of hydrocarbon accumulation models: hydrocarbon accumulation in the detrital basin and hydrocarbon accumulation in the carbonate basin/formation. The accumulation of unconventional oil/gas is self-containment, which is microscopically driven by the intermolecular force (van der Waals force). The unconventional oil/gas production has proved that the geological model, flow model, and production mechanism of shale and tight reservoirs represent a new and complex field that needs further study. Shale oil/gas must be the most important resource replacement for oil and gas resources of China. Future research efforts include: (1) the characteristics of the whole petroleum system in carbonate basins and the source-reservoir coupling patterns in the evolution of composite basins; (2) flow mechanisms in migration, accumulation, and production of shale oil/gas and tight oil/gas; (3) geological characteristics and enrichment of deep and ultra-deep shale oil/gas, tight oil/gas and coalbed methane; (4) resource evaluation and new generation of basin simulation technology of the whole petroleum system; (5) research on earth system -- earth organic rock and fossil fuel system -- whole petroleum system. [ABSTRACT FROM AUTHOR]

We build and estimate a dynamic, structural model of the world oil market to quantify the impact of the shale revolution. We model the shale revolution as a decrease in shale production costs and find that the resultant increase in shale production lowers oil prices by 24% in the short run and 48% once the shale oil transition is complete. Current oil price volatility is lowered by 8% to 23% depending on the horizon. We also find that OPEC core acts to keep its market share constant in the face of the dramatic increase in shale production. [ABSTRACT FROM AUTHOR]

The underground environmental problems caused by oil shale in-situ mining are complexed and continuous. Core stress seepage experiment is an effective method for understanding contaminant migration. The scanning electron microscope (SEM) and mercury intrusion porosimetry (MIP) showed that permeability was improved largely in oil shale residual (500°C). The transform of basic characteristics of oil shale was the key factor to promote the migration and release of pollutants. This paper analyzed dynamic migration of eight elements (Co, Cu, Zn, Ni, As, Cd, Cr, and Pb) in oil shale residues under in-situ seepage stress. Physical characterization of oil shale were combined with geochemical fractions of metals to comprehensively analyse the influence of seepage processes on the release of heavy metal. The results revealed that the migration of heavy metals was divided into rapid stage and equilibrium stage. Highest concentrations of all aimed elements were observed in the first day. Leaching content of elements was related to environmental change of water-rock interface reactions, particularly on the pH. Based on speciation of heavy metal, Ni, Cd, Co, and Zn were considered easily mobile element. Our study indicated that oil shale in-situ mining required more attention for controlling heavy metals risk of groundwater. [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 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 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 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 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 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 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.)

This study evaluated the potential and environmental benefits of using oil shale residue as a replacement for fine aggregate in concrete through a series of experiments. Initially, the crushing value test confirmed the oil shale residue's value at 16.7%, meeting the load-bearing standards for fine aggregates, thus proving its viability as a complete substitute. Further, the oil shale residue was treated with a 60 mg/L concentration of Tween 80 and other surfactants for oil removal. The treated concrete specimens demonstrated excellent compressive performance and a dense internal structure. Building on this, the mechanical properties of the oil shale residue concrete were explored across different replacement ratios (from 40% to 100%), revealing an increase in compressive strength with higher replacement ratios. In the durability tests, compared to the JZ group, the oil shale residue concrete modified with desulfurization gypsum exhibited a 0.03% reduction in mass loss rate and a 10.13% reduction in relative moving elasticity modulus loss rate, particularly noticeable after 175 freeze–thaw cycles where specimens B1 to B4 exhibited no significant damage, highlighting its remarkable durability. Overall analysis indicated that using oil-removed oil shale residue as a substitute for fine aggregate in concrete, combined with desulfurization gypsum modification, not only enhances concrete performance but also significantly reduces the consumption of natural aggregates and environmental pollution, promoting resource utilization and sustainable development. [ABSTRACT FROM AUTHOR]

In recent years, the Chang 7 member of the Mesozoic Triassic Yanchang Formation in the Ordos Basin has emerged as a significant repository of abundant and distinctive unconventional oil resources. The Heshui area boasts substantial shale oil reserves, with reported third-level reserves surpassing 600 million tons. However, the region in the southern part of Heshui is marked by pronounced variability in reservoir quality, intricate oil–water dynamics, low formation energy, and suboptimal fluid properties, leading to divergent development outcomes for horizontal wells. There is an imperative need to devise and refine new geological models to underpin the efficient exploitation of shale oil in the southern Heshui area. This study focuses on the shale oil reservoir of the Chang 7 member in the southern Heshui area of the Ordos Basin, conducting detailed stratigraphic correlation and establishing a refined isochronous stratigraphic framework. Utilizing PetrelTM modeling software (version 2018), we integrate deterministic and stochastic modeling approaches, adhering to the principles of isochronous and phased modeling. By assessing the thickness of sand and mudstone layers and the overall stratigraphic sequence, we derive a geological probability surface. Subsequently, this surface is harnessed to constrain the lithofacies, yielding a constrained lithofacies model. Employing sequential indicator simulation and sequential Gaussian stochastic simulation, we develop a reservoir attribute model that is anchored in the lithofacies model and its controls, culminating in a robust and dependable static model. Employing the geological probability surface constraint method, we meticulously construct the reservoir matrix model, amalgamating individual well data with the inherent certainty and randomness of reservoir plane thickness. This approach further enhances the model's accuracy and mitigates the uncertainty and randomness associated with inter-well interpolation to a significant degree. [ABSTRACT FROM AUTHOR]

The production capacity of shale oil reservoirs after hydraulic fracturing is influenced by a complex interplay involving geological characteristics, engineering quality, and well conditions. These relationships, nonlinear in nature, pose challenges for accurate description through physical models. While field data provides insights into real-world effects, its limited volume and quality restrict its utility. Complementing this, numerical simulation models offer effective support. To harness the strengths of both data-driven and model-driven approaches, this study established a shale oil production capacity prediction model based on a machine learning combination model. Leveraging fracturing development data from 236 wells in the field, a data-driven method employing the random forest algorithm is implemented to identify the main controlling factors for different types of shale oil reservoirs. Through the combination model integrating support vector machine (SVM) algorithm and back propagation neural network (BPNN), a model-driven shale oil production capacity prediction model is developed, capable of swiftly responding to shale oil development performance under varying geological, fluid, and well conditions. The results of numerical experiments show that the proposed method demonstrates a notable enhancement in R² by 22.5% and 5.8% compared to singular machine learning models like SVM and BPNN, showcasing its superior precision in predicting shale oil production capacity across diverse datasets. [ABSTRACT FROM AUTHOR]

This study extensively investigates the influence of different pyrolysis temperatures and organic matter contents on the fluid flow and heat transfer properties in oil shale samples. Utilizing CT images to generate three-dimensional digital rock, coupled simulations of CO 2 flow and heat transfer were conducted, analyzing parameters such as velocity fields, permeability, temperature fields, average temperatures, and heat transfer coefficients. The results reveal that, for relatively homogeneous oil shale samples, the permeability exhibits a monotonous increase with rising pyrolysis temperature. While the effect of pyrolysis temperature on the distribution characteristics of velocity and temperature fields is minimal, it significantly impacts the heat transfer coefficients. Specifically, the heat transfer coefficients increase significantly in the direction perpendicular to the bedding plane, while they decrease or remain unchanged parallel to it. Additionally, the organic matter content significantly influences the fluid flow and heat transfer properties of shale samples. After undergoing heat treatment, the heterogeneity of pore structures in shale samples varies significantly, affecting the characteristics of fluid flow and heat transfer. The influence of organic matter content and pyrolysis temperature on fluid flow and heat transfer in shale primarily stems from the effect of organic matter pyrolysis on the original pore structure. The development and connectivity of pore networks are closely related to the distribution characteristics of the original organic matter and are not directly correlated with the organic matter content. These findings provide essential theoretical guidance and technical support for the development and utilization of oil shale resources, while also offering valuable references and insights for future research. [ABSTRACT FROM AUTHOR]

The zero-lower bound (ZLB) may constrain the ability of Federal Reserve (Fed) to influence financial markets and the economy. This note examines the effectiveness of the interest rate channel and the credit channel of conventional and unconventional monetary policy while accounting for business cycle fluctuations. We use intraday industry returns and a number of industry-specific and firm-specific indicators to capture the sensitivity of firms' demand to interest rates (interest rate channel) and firms' financial constraints (credit channel). Our results indicate a dramatic change in the effectiveness of the transmission channels across business cycles and across periods. We find that the interest rate channel operates equally well during recessions and expansions pre-ZLB, but that this channel has ceased to function during the ZLB regardless of the stage of the business cycle. In contrast, the credit channel operates only during recessions in the conventional period, while it has been remarkably effective during both recessions and expansions in the ZLB era.1 [ABSTRACT FROM AUTHOR]

Microscopic pore structure in continental shale oil reservoirs is characterized by small pore throats and complex micro-structures. The adsorption behavior of hydrocarbons on the pore walls exhibits unique physical and chemical properties. Therefore, studying the adsorption morphology of hydrocarbon components in nanometer-sized pores and clarifying the exploitation limits of shale oil at the microscopic level are of great practical significance for the efficient development of continental shale oil. In this study, molecular dynamics simulations were employed to investigate the adsorption characteristics of various single-component shale oils in inorganic quartz fissures, and the influence of pore size and shale oil hydrocarbon composition on the adsorption properties in the pores was analyzed. The results show that different molecules have different adsorption capacities in shale oil pores, with lighter hydrocarbon components (CH) exhibiting stronger adsorption abilities. For the same adsorbed molecule, the adsorption amount linearly increases with the increase in pore diameter, but larger pores contribute more to shale oil adsorption. In shale pores, the thickness of the adsorption layer formed by shale oil molecules ranges from 0.4 to 0.5 nm, which is similar to the width of alkane molecules. Shale oil in the adsorbed state that is difficult to be exploited is mainly concentrated in the first adsorption layer. Among them, the volume fraction of adsorbed shale oil in 6 nm shale pores is 40.8%, while the volume fraction of shale oil that is difficult to be exploited is 16.2%. [ABSTRACT FROM AUTHOR]

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

In order to solve the problems of conventional water injection development difficulties and low recovery factor in low-permeability reservoirs, the method of high-pressure air drive is adopted to achieve the purpose of reservoir energy enhancement and efficiency improvement. This paper conducted an experimental study on the mechanism of low-temperature oxidation (LTO) for crude oil in the process of high-pressure air flooding, elaborated the relationship between the LTO properties of crude oil and the temperature, pressure, and water saturation of the reservoir, and analyzed the differences in LTO oxygen consumption and oil components under different reaction conditions. In addition, combined with the air flooding physical simulation experiment, the dynamic evolution law of recovery rate in the air flooding process was revealed. Findings from this inquiry indicate that an escalation in the oxidation temperature significantly amplifies the oxygen incorporation reaction within the crude oil matrix. This augmentation in oxidative conditions leads to an uptick in oxygen consumption, which subsequently precipitates a reduction in the lighter fractions of the oxidized oil while enriching its heavier components. Elevated pressures were found to enhance the propensity for the amalgamation of unstable hydrocarbons with oxygen, fostering comprehensive and heterogeneous oxidation reactions. Notably, an excessive presence of water was observed to detrimentally affect the thermal efficacy of crude oil oxidation processes. In the context of low-permeability reservoirs, air injection techniques have emerged as superior in effectuating oil displacement, although an increase in injection pressures has been associated with the phenomenon of gas channeling. Interestingly, adopting a sequential strategy of initiating water flooding before air flooding facilitated the conveyance of high-pressure air via established flushing channels, although it appeared to attenuate the intensity of crude oil oxidation, culminating in an oil recovery efficiency peaking at 51%. [ABSTRACT FROM AUTHOR]

The Paleogene-Neogene strata in the Western Depression of the Qaidam Basin represent a primary focus for oil and gas exploration and development. Influenced by both terrigenous clastic influx and endogenic carbonate deposition, these strata exhibit significant variation in sedimentary systems and reservoir characteristics. This study comprehensively examines the depositional patterns and reservoir properties of the Paleogene-Neogene sequence across the inner, middle, and outer belts of the basin, employing core analysis, thin section petrography, and physical property assessment of reservoirs. Key findings include 1) The development of a concentric sedimentary system in the Western Depression during the Paleogene-Neogene period, characterized by increased carbonate mineral content and decreased clastic material from the periphery to the center of the basin. 2) Varied sedimentary facies associations across different zones, with the outer belt dominated by fan delta and braided river delta deposits, and the middle and inner belts characterized by near- shore shallow lacustrine carbonates and algal mat deposits, and offshore semi-to deep-lacustrine fine sediments, respectively. 3) The outer belt exhibits reservoirs with favorable physical properties and connectivity, while the inner and middle belts show high heterogeneity, indicating potential for lithological traps and shale oil exploration. These insights offer scientific guidance for further investigation into the depositional systems of lacustrine basins in the Western Depression of the Qaidam Basin and for identifying promising reservoirs. [ABSTRACT FROM AUTHOR]

The presence of highly developed micro-nano pores and poor pore connectivity constrains the development of shale oil. Given the rapid decline in oil production , enhanced oil recovery (EOR) technologies are necessary for shale oil development. The shale oil reservoirs in China are mainly continental and characterized by high heterogeneity, low overall maturity, and inferior crude oil quality. Therefore, it is more challenging to achieve a desirably high recovery factor. The Qingshankou Formation is a typical continental shale oil reservoir, with high clay content and well-developed bedding. This paper introduced high-precision non-destructive nuclear magnetic resonance technology to carry out a systematic and targeted study. The EOR performances and oil recovery factors related to different pore sizes were quantified to identify the most suitable method. The results show that surfactant, CH4, and CO2 can recover oil effectively in the first cycle. As the huff-and-puff process continues, the oil saturated in the shale gradually decreases, and the EOR performance of the surfactant and CH4 is considerably degraded. Meanwhile, CO2 can efficiently recover oil in small pores (<50 nm) and maintain good EOR performance in the second and third cycles. After four huff-and-puff cycles, the average oil recovery of CO2 is 38.22%, which is much higher than that of surfactant (29.82%) and CH4 (19.36%). CO2 is the most applicable medium of the three to enhance shale oil recovery in the Qingshankou Formation. Additionally, the injection pressure of surfactant increased the fastest in the injection process, showing a low flowability in nano-pores. Thus, in the actual shale oil formations, the swept volume of surfactant will be suppressed, and the actual EOR performance of the surfactant may be limited. The findings of this paper can provide theoretical support for the efficient development of continental shale oil reservoirs. [ABSTRACT FROM AUTHOR]

Applying chemical enhanced oil recovery (EOR) to shale and tight formations is expected to accelerate China's Shale Revolution as it did in conventional reservoirs. However, its screening and modeling are more complex. EOR operations are faced with choices of chemicals including traditional surfactant solutions, surfactant solutions in the form of micro-emulsions (nano-emulsions), and nano-fluids, which have similar effects to surfactant solutions. This study presents a systematic comparative analysis composed of laboratory screening and numerical modeling. It was conducted on three scales: tests of chemical morphology and properties, analysis of micro-oil-displacing performance, and simulation of macro-oil-increasing effect. The results showed that although all surfactant solutions had the effects of reducing interfacial tension, altering wettability, and enhancing imbibition, the nano-emulsion with the lowest hydrodynamic radius is the optimal selection. This is attributed to the fact that the properties of the nano-emulsion match well with the characteristics of these shale and tight reservoirs. The nano-emulsion is capable of integrating into the tight matrix, interacting with the oil and rock, and supplying the energy for oil to flow out. This study provides a comprehensive understanding of the role that surfactant solutions could play in the EOR of unconventional reservoirs. [ABSTRACT FROM AUTHOR]