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Based on the results of the National Oil Shale Resource Evaluation in China conducted from 2003 to 2006, and combined with the new exploration progress in recent years, the characteristics and resource potential of oil shale in China have been systematically studied in this paper. Oil shale resources in China are abundant, with deposits mainly found in the continental environment and, secondarily, in marine-continental facies. The color of oil shale is black to grayish black, black to gray brown or gray to dark gray. In general, the darker the color, the higher the quality of oil shale. The most common minerals in oil shale are clay minerals, quartz and feldspars. The concentration of organic carbon in Chinese oil shale is high, between 7.48 and 38.02%. By organic genetic type, oil shale can be divided into sapropelic, humosapropelic and saprohumic oil shale. Oil shale used for industrial purposes has a medium to high oil yield and high ash content. Oil shale resources in China are mainly concentrated in 20 provinces and autonomous regions, 50 basins and 83 petroliferous shale areas. Total oil shale resources are estimated at approximately 978 billion tons, i.e. about 61 billion tons of in-place shale oil, mainly distributed throughout eastern and central China and the Qinghai-Tibet Region in western China. This paper outlines the distribution of oil shale deposits in China with respect to depositional basin type, and oil shale age and grade. Oil shale in China was deposited mainly in extensional and intra-plate basins during the Mesozoic and the Cenozoic. The size of the basins diminishes from older to younger deposits. Oil shale resources that yield shale oil more than 5% by weight account for about 72% of the rock's total resources in the country.

The shale oil phase state is essential for assessing shale oil production, establishing development plans, and enhancing oil recovery. Previous studies on shale oil phase state mainly focused on bulk fluid phase based on fluid composition retrieved from drill holes, while nano-confined shale oil phase state based on subsurface in-situ fluid compositions is rarely discussed. In this work, we established a new workflow that used pressure-preserved shale cores and pyrolysis gas chromatogram (Py-GC) to retrieve in-situ shale oil compositions from various shales with different thermal maturities. The workflow includes retrieving pressure-preserved shale cores, cutting, transporting, and then preparing samples under the protection of liquid nitrogen; the new process makes the evaporation loss of lightweight hydrocarbons the least. By comparison, fluid samples from wellheads and wellbores were also retrieved from Gulong shale oil reservoirs in the Songliao Basin. Both bulk and nano-confined shale oil phases were then analyzed, and the results showed that methane content in the Gulong shale oil increased from 10.11 to 23.39% with increasing thermal maturity; by contrast, C 7+ hydrocarbons decreased from 64.73 to 41.13%. As for bulk fluid phases, Gulong shale oils are black oil phases, while in terms of nano-confined fluid phases, their phases are controlled by thermal maturity. They are black oil phases at lower thermal maturity with vitrinite reflectance (Ro) less than 1.4% and are condensate phases at higher thermal maturity with Ro greater than 1.4%. Shale oil production data showed that nano-confined phase analysis using in-situ shale oil compositions from pressure-preserved cores can best predict shale oil production in this study.

The Sichuan Basin is rich in shale oil and gas resources, with favorable geological conditions that the other shale reservoirs in China cannot match. Thus, the basin is an ideal option for fully “exploring petroleum inside source kitchen” with respect to onshore shale oil and gas in China. This paper analyzes the characteristics of shale oil and gas resources in the United States and China, and points out that maturity plays an important role in controlling shale oil and gas composition. US shale oil and gas exhibit high proportions of light hydrocarbon and wet gas, whereas Chinese marine and transitional shale gas is mainly dry gas and continental shale oil is generally heavy. A comprehensive geological study of shale oil and gas in the Sichuan Basin reveals findings with respect to the following three aspects. First, there are multiple sets of organic-rich shale reservoirs of three types in the basin, such as the Cambrian Qiongzhusi Formation and Ordovician Wufeng Formation-Silurian Longmaxi Formation marine shale, Permian Longtan Formation transitional shale, Triassic Xujiahe Formation lake-swamp shale, and Jurassic lacustrine shale. Marine shale gas enrichment is mainly controlled by four elements: Deep-water shelf facies, moderate thermal evolution, calcium-rich and silicon-rich rock association, and closed roof/floor. Second, the “sweet section” is generally characterized by high total organic carbon, high gas content, large porosity, high brittle minerals content, high formation pressure, and the presence of lamellation/bedding and natural microfractures. Moreover, the “sweet area” is generally characterized by very thick organic-rich shale, moderate thermal evolution, good preservation conditions, and shallow burial depth, which are exemplified by the shale oil and gas in the Wufeng-Longmaxi Formation, Longtan Formation, and Daanzhai Member of the Ziliujing Formation. Third, the marine, transitional, and continental shale oil and gas resources in the Sichuan Basin account for 50%, 25%, and 30% of the respective types of shale oil and gas geological resources in China, with great potential to become the cradle of the shale oil and gas industrial revolution in China. Following the “Conventional Daqing-Oil” (i.e., the Daqing oilfield in the Songliao Basin) and the “Western Daqing-Oil & Gas” (i.e., the Changqing oilfield in the Ordos Basin), the Southwest oil and gas field in the Sichuan Basin is expected to be built into a “Sichuan-Chongqing Daqing-Gas” in China.

After the completion of in situ pyrolysis, oil shale can be used as a natural place for CO[sub.2] sequestration. However, the effects of chemical action and formation stress-state changes on the deformation of oil shale should be considered when CO[sub.2] is injected into oil shale after pyrolysis. In this study, combined with statistical damage mechanics, a transverse isotropic model of oil shale with coupled damage mechanisms was established by considering the decreased mechanical properties and the chemical damage caused by CO[sub.2] injection. The process of injecting supercritical CO[sub.2] into oil shale after pyrolysis was simulated by COMSOL6.0. The volume distribution of CO[sub.2] and the stress evolution in oil shale were analyzed. It is found that CO[sub.2] injection into oil shale after pyrolysis will not produce new force damage, and the force damage caused by the decrease in the mechanical properties of oil shale after pyrolysis can offset the ground uplift caused by CO[sub.2] injection to a certain extent. Under the combined action of chemical damage and mechanical damage, the uplift of a formation with a thickness of 200 m is only 10 cm. The injection of supercritical CO[sub.2] is beneficial for maintaining the stability of oil shale after in situ pyrolysis.

The Chang 7 member of the Ordos Basin hosts abundant shale oil and gas resources and plays a vital role in the development of unconventional energy. This study investigates differences in damage evolution and underlying mechanisms between representative shale oil and shale gas reservoir cores from the Chang 7 member under fracturing fluid hydration. A combination of high-temperature expansion tests, nuclear magnetic resonance (NMR), and micro-computed tomography (Micro-CT) was used to systematically characterize macroscopic expansion behavior and microscopic pore structure evolution. Results indicate that shale gas cores undergo faster expansion and higher imbibition rates during hydration (reaching stability in 10 h vs. 23 h for shale oil cores), making them more vulnerable to water-lock damage, while shale oil cores exhibit slower hydration but more pronounced pore structure reconstruction. After 72 h of immersion in fracturing fluid, both core types experienced reduced pore volumes and structural reorganization; however, shale oil cores demonstrated greater capacity for pore reconstruction, with a newly formed pore volume fraction of 34.5% compared to 24.6% for shale gas cores. NMR and Micro-CT analyses reveal that hydration is not merely a destructive process but a dynamic “damage–reconstruction” evolution. Furthermore, the addition of clay stabilizers effectively mitigates water sensitivity and preserves pore structure, with 0.7% identified as the optimal concentration. The research results not only reveal the differential response law of fracturing fluid damage in the Chang 7 shale reservoir but also provide a theoretical basis and technical support for optimizing fracturing fluid systems and achieving differential production increases.

Oil shale can produce oil and shale gas by heating the oil shale at 300–500 °C. The high temperature and the release of organic matter can change the physical and mechanical properties of rocks and make the originally tight impervious layer become a permeable layer under in situ exploitation conditions. To realize the potential impact of the in situ exploitation of oil shale on groundwater environments, a series of water–rock interaction experiments under different temperatures was conducted. The results show that, with the increase of the reaction temperature, the anions and cations in the aqueous solution of oil shale, oil shale–ash, and the surrounding rock show different trends, and the release of anions and cations in the oil shale–ash solution is most affected by the ambient temperature. The hydrochemical type of oil shale–ash solution is HCO3-SO4-Na-K at 80 °C and 100 °C, which changes the water quality. The main reasons are that (1) the high temperature (≥80 °C) can promote the dissolution of FeS in oil shale and (2) the porosity of oil shale increases after pyrolysis, making it easier to react with water. This paper is an important supplement to the research on the impact of the in situ exploitation of oil shale on the groundwater environment. Therefore, the impacts of in situ mining on groundwater inorganic minerals should be taken into consideration when evaluating in situ exploitation projects of oil shale.

This study addresses stability challenges in oil shale reservoirs during the in situ conversion process by developing a thermo-hydro-mechanical damage (THMD) coupling model. The THMD model integrates thermo-poroelasticity theory with a localized gradient damage approach, accounting for thermal expansion and pore pressure effects on stress evolution and avoiding mesh dependency issues present in conventional local damage models. To capture tensile–compressive asymmetry in geotechnical materials, an equivalent strain based on strain energy density is introduced, which regularizes the tensile component of the elastic strain energy density. Additionally, the model simulates the multi-layer wellbore structure and the dynamic heating and extraction processes, recreating the in situ environment. Validation through a comparison of numerical solutions with both experimental and analytical results confirms the accuracy and reliability of the proposed model. Wellbore stability analysis reveals that damage tends to propagate in the horizontal direction due to the disparity between horizontal and vertical in situ stresses, and the damaged area at a heating temperature of 600 °C is nearly three times that at a heating temperature of 400 °C. In addition, a cement sheath thickness of approximately 50 mm is recommended to optimize heat transfer efficiency and wellbore integrity to improve economic returns. Our study shows that high extraction pressure (−4 MPa) nearly doubles the reservoir’s damage area and increases subsidence from −3.6 cm to −6.5 cm within six months. These results demonstrate the model’s ability to guide improved extraction efficiency and mitigate environmental risks, offering valuable insights for optimizing in situ conversion strategies.

Most oil shale deposits in Kazakhstan were estimated without detailed calculations of the grade and tonnages and included low confidence categories, i.e., Inferred, Off-Balance, and Non-Economic oil shales, on which cannot be given any oil reserves. An analysis of Kazakhstan oil shale deposits in accordance with resource estimation practices for consideration of potential shale oil tonnages has been produced. The developed methodology considers extraction and processing recoveries of conventional and unconventional mining methods. The methodology uses Monte Carlo modeling to estimate a range of oil content and oil recoveries and uses the event tree analysis to demonstrate how the initial oil shale material tonnages and grades go through various fault and success branches, considering probabilities distributions and estimating potential shale oil tones at the end. As a result, this estimation methodology has been validated by high-ranked resource category oil shale deposits, which demonstrated the range of potential shale oil in the range of 10.7–16.8 Mt at the 50% confidence level. The results will be used for further consideration in financial-economic feasibility studies, which must take into account operational and capital expenses, product sale prices and market, and social-environmental aspects.

Continental shale oil resource is an important alternative source for increasing and stabilizing China’s crude oil production. China has abundant continental shale oil resources. The opinions of researchers are divided over the classification of shale oil resources in China, resource evaluation methods and criteria, and resource potential prediction. Considering this fact, the authors of this article first summarized and analyzed the exploration progresses made in the typical shale oil exploration areas in China and the geological insights gained through exploration activities. Then, based on the current shale oil research status and actual oil production conditions in China, shale oil resources were classified into three types: interlayer shale oil, pure shale oil, and in-situ converted shale oil. Furthermore, the corresponding resource evaluation methods and quantitative models were proposed, the key parameters and their lower limits were determined and the resources of the three major types of shale oil in the shale formations in China’s major basins were evaluated using a set of unified evaluation criteria. The in-place resources of pure shale oil, interlayer shale oil and in-situ converted shale oil are 145.4 × 108 t, 95.1 × 108 t and 708.2 × 108 t, respectively, and the recoverable resources are respectively 9.4 × 108 t, 7.1 × 108 t and 460.3 × 108 t. The research results can provide guidance for the evaluation of shale oil resources in China and the exploration planning for such resources and serve as valuable references for international peers to understand China’s current status of research and development potential of shale oil.