Currently, sweet spot evaluation plays an important role in unconventional oil and gas exploration and development, which is of great significance to the large-scale efficient development of unconventional oil and gas. The concept connotation of sweet spot has been increasingly expanded and more diversified and regional the corresponding evaluation parameters and standard values are more diversified and regionally distinctive. At present, the commonly-used sweet spot evaluation and prediction methods include the contour map semi-quantitative plane superimposition evaluation method, the sweet spot quantitative and semi-quantitative evaluation method based on multi-parameter co-constraint, the radar graphic method, and the sweet spots quantitative evaluation method established based on the geological anomaly theory. In the practical application, the applicability evaluation and prediction method should be developed according to the basic data such as tectonic depositional settings, lithological association and resource type of the basin, and the principle of superposed progressive discrimination. Continental shales in China are highly heterogeneous, and there is a significant difference in the enrichment laws and main controlling factors of different types of shale oil. Both interlayer and hybrid shale oil have experienced migration and accumulation in the source. The main lithology of the reservoir is sandstone (siltstone) and carbonate rock (hybrid sedimentary rock). The reservoir property, hydrocarbon potential and brittleness of reservoirs are the key indicators. The pure shale oil intervals in the thick and ultra-thick layers is generally oil-bearing, and the oil is mainly retained in the source. The source rocks are the reservoirs. It is suggested to use the trichotomy method to divide hydrocarbon enrichment layers into Type I, Type II and Type III using 5~8 key parameters based on the data of sedimentary cycle, laminated texture type, lithological association, hydrocarbon potential, reservoir property, compressibility, mobility and recoverability. During the optimization of enrichment layers, zoning should be planned according to the thermal evolution maturity of different basins and zones. In the medium-low maturity zone, the medium-high TOC content shale interval (felsic laminae develop) adjacent to the high TOC content shale interval should be optimized; in the medium-high maturity zone, the high TOC content shale interval should be optimized. As the "gold target layer", Type I oil reservoir should be developed and produced initially, and progressively exploited according to technological maturity, so as to realize the maximum development and utilization of China's continental shale oil resources, and effectively serve to guarantee the national energy security.

Three sets of bathyal lacustrine organic-rich shale are developed in the Jurassic of Sichuan Basin, characterized by superposed development and broad distribution; the bathyal lacustrine shale is characterized by "high TOC, high porosity and high gas content". Recently, new breakthroughs have been made in the exploration of continental shale oil and gas in multiple wells and sections of the Jurassic in Sichuan Basin, boasting of great exploration potential and abundant resources, which are key replacement resources instead of the marine shale gas in Wufeng Formation and Longmaxi Formation. Through comprehensive evaluation of fine-grained rocks, it is found that the continental shale oil and gas have strong heterogeneity. On this basis, a quaternary lithofacies division scheme was established to clarify the main controlling factors for the enrichment and high production of continental shale oil and gas. Specifically, the bathyal lacustrine organic-rich shale provides the material base, good tectonic preservation and high-pressure conditions are the key conditions, appropriate thermal evolution and microfracture development are conducive to hydrocarbon enrichment and flow, and the geology-engineering integrated research can guarantee high production. The Jurassic continental shale oil and gas resources have great potential, with the natural gas equivalent of 6.0×10 ¹²m ³, accounting for 27.7% of the total natural gas resources in Sichuan Basin. This is an important field for increasing reserves and production during the "14th Five-Year Plan" period (2021-2025). Multilayer superimposed shale is developed and bathyal lacustrine shale distributes extensively in northeastern Sichuan, which are important favorable zones for exploration. Sinopec has the total natural gas resources of 2.94 × 10 ¹²m ³ and crude oil of 12.03×10 ⁸ t in these areas, which are important replacement resource fields for oil-gas exploration and development in Southwest China. The exploration and development of continental shale oil and gas in Sichuan Basin is still in the early stage, and there are still deficiencies in research of fine-grained rock sedimentary reservoirs, reservoir properties, main controlling factors of enrichment and high production, and applicable engineering fracturing technology. It is still necessary to make more efforts to tackle key scientific and technical problems and practice deeply, and strive to achieve greater breakthroughs in the exploitation of continental shale oil and gas in Sichuan Basin during the "14th Five-Year Plan" period and increase reserves and production on a large scale.

Compared with marine shale oil in North America, continental shale oil in China has such characteristics as complex mineral composition, strong heterogeneity, thin single-layer thickness, and rapid vertical changes of lithologies and lithofacies. Thus, there are great difficulties in logging lithology identification, accurate calculation of rock mechanical parameters and fine division of reservoir qualities, which bring great challenges for the well logging evaluation of sweet spots in shale oil reservoirs. In view of the difficulties encountered in the logging evaluation of shale oil exploration areas in Songliao, Ordos, Junggar, and Bohai Bay basins, this paper mainly explores the new methods for shale rock physical experiment, represented by four-dimensional digital core, laboratory multi-state two-dimensional NMR spectroscopy, and onsite movable full-diameter rock core NMR spectroscopy; the new well logging technologies, represented by high-precision calculation of mineral components based on elemental logging, identification of sedimentary structure based on image logging, horizontal well interpretation, and fracturing evaluation.A complete technical system for well logging evaluation of continental shale oil has been formed, which shows the innovation and development of well logging evaluation technology of shale oil in recent years.

To address the key scientific problems involving diverse types of continental shale oil and gas deposition, complex reservoir space and unclear reservoir genesis in China, this paper systematically reviews the domestic and foreign research progress of continental deepwater sedimentary sequence, deposition system and shale oil and gas reservoirs, especially in China in the past 10 years. More importantly, in combination with the geological researches conducted by the authors' team in recent years on the deposition and reservoirs of continental shale oil and gas, the continental deepwater fine-grained sedimentary rocks are classified into four genetic types, i.e., terrestrial, endogenous, volcanic-hydrothermal, and hybrid-source types. Meanwhile, the paper proposes a comprehensive classification scheme for fine-grained sedimentary rocks based on inorganic mineral content (i.e., three end-members of carbonate minerals, felsic minerals and clay minerals), organic matter content (TOC contents ranges between 2.0% and 4.0%), and sedimentary structure (lamellar, thin-layered, and massive), and also summarizes a high-frequency cyclostratigraphic study method based on the Milankovitch astronomical orbital period, which is applicable for the subdivision and comparison of continental deepwater fine-grained sedimentary strata. Further, based on the high-frequency cyclostratigraphic correlation, a method is proposed for the industrial mapping of microphase planes of continental deepwater fine-grained sedimentary rocks, which is of important applicable value for the evaluation and prediction of favorable shale sedimentary reservoir lithologies. According to the matrix type for pore occurrence, pores in the continental shale oil and gas fine-grained sedimentary rock reservoir are divided into three categories:mineral matrix pore (or inorganic pore), organic pore, and fracture pore. Among them, the mineral matrix pore related to organic dissolution is an important storage space for shale oil and gas, and the development degree of organic matrix pore is mainly related to the degree of thermal evolution of organic matter. In general, the high degree of thermal evolution is conducive to the development of organic matter pores, and fracture pore is an important seepage channel for shale oil and gas. Moreover, the paper points out the problems requiring further studies and development directions regarding the deposition of fine-grained sedimentary rocks, formation mechanism and sweet spot evaluation of shale oil and gas reservoirs, and high-precision shale stratigraphic correlation methods.

China is rich in lacustrine shale oil resource which has become one of national strategic resource. As a typical representative of self-sourced petroleum resources, shale oil enrichment has the characteristic of in-situ generation and inner-sourced storage. The occurrence and production mechanism of shale oil and gas in micro/nano-scale pore-fracture system is complex. Laboratory-based device innovation and technological revolution are important driving force to promote the theoretical innovation, large-scale exploration, and effective production of lacustrine shale oil. Through summarizing the research progress and main understandings of several hotspots involving the geological evaluation of shale oil such as fine-grained sedimentation and organic matter enrichment, rock structure and mineral composition, micro/nano-scale pore-fracture system, fluid occurrence and movable fluid, and fracability and fracture propagation, it is proposed that the experimental method for geological evaluation of shale oil is changing from source rock to reservoir, from hydrocarbon generation capacity to hydrocarbon storage capacity, and from hydrocarbon expulsion capacity to hydrocarbon production capacity. At present, there are three challenges in the development of experimental techniques for shale oil evaluation. (1) It is difficult to accurately characterize the shale oil reservoirs of different scales due to fine-grained sedimentation and its complex mineral composition. (2) The mechanism of pore evolution and hydrocarbon occurrence is complex under the combined action of organic and inorganic materials so that it is very difficult to evaluate the hydrocarbon mobility. (3) It is difficult to completely reproduce the real geological conditions at the laboratory, and the accuracy of laboratory-based evaluation needs to be further improved. The future experimental method for the geological evaluation of shale oil should focus on strengthening the research of the in-situ, refined, multi-scale experimental devices and evaluation methods, the dynamic evaluation of key shale reservoir attributes, as well as the construction of field laboratory and integration of geological and engineering technology, so as to improve the accuracy of reservoir characterization and prediction based on experimental technology, as well as the application of field laboratory. The relevant research and understanding are expected to provide the technical support for the geological evaluation of lacustrine shale oil, and a reference for the research on both enrichment theory and technological innovation of mobility evaluation.

After more than ten years of exploration and practice, a series of progress has been made in marine shale gas exploration in Sichuan Basin. During that period, focusing on Wufeng-Longmaxi formations as the most favorable pay zone, a few theories for the enrichment and high production of shale gas were proposed, the exploration and development technologies integrating geological evaluation, development optimization, optimal-fast drilling, volume fracturing, factory operation and clean exploitation was formed, and a large shale gas field with reserves of one trillion cubic meters was proved. At an important time for the development of shale gas exploration in China, it is of great significance to promote the exploration and development of marine shale gas by reviewing the exploration and development history of marine shale gas, summarizing the achievements and knowledge of shale gas in Wufeng-Longmaxi formations in terms of geological conditions and enrichment laws, and making an outlook on the key replacement fields for marine shale gas exploration in Sichuan Basin. (1) The exploration and development of marine shale gas in Sichuan Basin have gone through four stages:layer and zone evaluation stage to find the target; pilot test stage of shallow to medium-deep reservoir; demonstration zone construction stage of shallow to medium-deep reservoir; stage of shallow to medium-deep reservoir production, deep reservoir evaluation, non-pressurized shale gas evaluation, three-dimensional development evaluation, ultra-deep and new reservoir exploration. (2) The sedimentary conditions of the Wufeng-Longmaxi formations in Sichuan Basin are superior, in which the deepwater shelf shales with high organic content are continuously and stably distributed. Shale gas mainly occurs in organic matter pores, and its reservoirs are concentrated longitudinally with large continuous thickness. The structures are relatively simple in the southern Sichuan Basin and the Fuling block of southeastern Sichuan Basin. The conditions for shale gas enrichment and preservation include sustained gas supply and reservoirs far away from the ancient/present denudation areas and oil-gas escape areas in large faults. At present, the shale gas resources in Wufeng-Longmaxi formations are 33 19×10 ¹²m ³ with a proved rate of 9.4%, showing great exploration potential. (3) There are rich marine shale gas resources in Sichuan Basin. In addition to Wufeng-Longmaxi formations, there are several sets of marine shale gas reservoirs as reserves in the horizons shallower than 4 500 m. The Cambrian Qiongzhusi Formation, Permian Wujiaming Formation and Dalong Formation as the strategic breakthrough strata, the favorable shale gas reservoirs mainly lie in Weiyuan-Ziyang area inside and around aulacogen for Qiongzhusi Formation, with the predicted resource potential of 1.40×10 ¹²m ³, and in Jiange-Nanjiang area and Dazhu-Kaijiang area of northern Sichuan Basin, and Lichuan area of southeastern margin of Sichuan Basin for Wujiaping Formation and Dalong Formation, with the predicted resource potential of 0.91×10 ¹² m ³. The Member 1 of Xujiahe Formation as the strategic preparation layer, its favorable shale gas reservoirs mainly lie in Ya'an-Qionglai area, with the predicted resource potential of 0.88×10 ¹² m ³.

Continental shale oil is a unique type of unconventional oil and gas resource in China, and has become an important field for increasing oil reserves and production in our country. By systematically elaborating the exploration and development history of Gulong shale oil in Songliao Basin, the paper summarizes the geological conditions for the enrichment and accumulation of continental shale oil, clarifies the resource potential, and points out the favorable zones for Gulong shale oil and the direction of further exploration and development. (1) Gulong shale oil mainly went through three exploration and development stages, i.e., mudstone fractured reservoir, interlayer-type shale oil and shale-type shale oil. (2) Gulong shale was originated from continental fresh water or brackish water lake basin, where lamellar algae were enriched, thus forming the organic-rich shale with wide distribution, large thickness and strong oil generation capacity. This lays the material foundation for the scale development of Gulong shale oil. (3) Gulong shale has a large number of micro-nano organic fractures for hydrocarbon generation, pores and natural fractures, providing the enrichment space and seepage channels for shale oil. (4) Gulong shale oil has a high degree of thermal evolution, and is generated in large amount from organic matters and preserved in-situ under overpressure, and the formation energy is sufficient, which are conducive to the development and production of shale oil. (5) Gulong shale oil has the roofs and floors with tight lithology and faults with good sealing characteristics, which provides macro preservation conditions for large-scale contiguous distribution of Gulong shale oil. (6) Gulong shale oil has the favorable zone of 1.46×10 ⁴km ², which is a large-scale and continuous overpressure shale reservoir with the vast resources of (100-150) ×10 ⁸t. The light oil zone in Qijia-Gulong sag and the interior of Sanzhao sag are the core areas for exploration and development due to their superior geological conditions and good effects of oil well testing.

The saline lacustrine mixed shale reservoirs are developed in the Middle-Lower Permian formations of Junggar Basin, which are typically represented by Lucaogou Formation in Jimusar sag and Fengcheng Formation in Mahu sag. At present, they have entered the stage of comprehensive exploration and development, and become an important type of continental shale oil and field for increasing reserves and production in China. By reviewing the progress of exploration and development of Permian shale oil in Junggar Basin, this paper systematically summarizes the formation conditions and enrichment model of Permian shale oil. Further, based on the theoretical understanding of the whole petroleum system for the orderly accumulation from conventional oil to tight oil to shale oil in Fengcheng Formation of Mahu sag, the resource potential and exploration direction of the Middle-Lower Permian shale oil in Junggar Basin are explored herein. The results show that the Permian saline water environment in Junggar Basin not only promotes the development of large-scale high-quality source rocks with medium-high maturity, but also controls the mixed sedimentation of terrigenous clasts, endogenous carbonates and volcanic tuffaceous particles, forming a set of fine-grained mixed rocks such as dolomitic siltstone or fine sandstone, dolomitic mud shale, and argillaceous dolomite widely distributed in the sag. Meanwhile, three types of efficient source-reservoir assemblage have formed under the influence of high-frequency water turbulence. The shale oil has the mechanism of pressurization during hydrocarbon generation, transport by micro fractures, hydrocarbon generation in source rock and accumulation in adjacent reservoir, showing the enrichment model of oil coexistence in two occurrence states, sweet spots controlled by lithofacies, and oil enrichment controlled by sweet spots. The Middle-Lower Permian source rock strata in Mahu sag, Shawan sag, Well Pen-1 West sag and Fukang sag are favorable exploration areas for the further exploration of shale oil and gas, and have great exploration potential for the collaborative exploration of conventional-unconventional oil and gas.

The Yingxiongling shale oil reservoir in Qaidam Basin is a global unique thick saline-lacustrine shale oil reservoir developed in plateau mountainous area, and its main oil beds are in Paleogene. Recently, major breakthroughs have been made in oil and gas exploration in the Yingxiongling shale oil reservoir, and industrial oil flow has been obtained in the formation test of 31 layers of 11 prospecting wells. The cumulative oil production of Well Chaiping1 exceeds 10 000 tons in 295 days, showing good exploration potential and development prospect. This paper systematically analyzes the geological setting and main accumulation factors of the Yingxiongling shale oil reservoir, and establishes the enrichment model of shale oil reservoir. The thick plateau mountainous shale oil reservoir is distinctive in terms of the surface and subsurface conditions, so that the existing theories and technologies of shale oil exploration and development at home and abroad cannot be followed completely. Further research progresses are as follows. (1) The key factors for the enrichment of sweet spots in the Yingxiongling shale oil reservoir include the two-stage continuous and efficient hydrocarbon generation of low organic matter abundance shale in saline lacustrine basin, the good reservoir spaces provided by the bedded and laminated calcite dolomite in the thick mixed sedimentary system, the easy stimulation condition due to reservoir with high carbonate mineral and low clay mineral contents, and the high shale oil recovery due to high formation pressure, high gas-oil ratio and good crude oil quality. (2) There are four kinds of enrichment zones with significant different reservoir spaces developed in the Yingxiongling structural belt, i.e., tectonic-stable zone, fault-deformation zone, fault-fracture/fault-karst zone and inter-salt crumple zone, corresponding to four kinds of sweet spot enrichment models, namely stratabound mode, bed-fracture compound control mode, fault control mode and salt control mode. (3) The Yingxiongling shale oil reservoir is located in a unique plateau mountainous environment. The extremely thick deposits of more than kilometers and the rugged landscape of ravines determine the difficulty and diversity of well sites, well patterns and well types. The cold weather, hypoxia and water shortage also greatly increase the difficulty of exploitation. (4) F our well patterns and development modes can be used to achieve efficient production in the Yingxiongling shale oil reservoir, including the zipper-like fracturing mode for stereo horizontal-well network, separate fracturing and commingling production for cluster vertical well or highly inclined well, multi-layer fracturing communication production mode for vertical well or highly inclined well or directional well, and continuous perforation combined with acidification production mode for directional well. The relevant understandings are expected to provide scientific guidance and technical support for the study of shale oil enrichment mode and efficient production mode, and the practice of well pattern and geological-engineering integration in plateau mountainous area.

The exploration practice in recent years has proved that the retained shale oil is developed in the main source rock series in Member 2 of Kongdian Formation, Member 3 of Shahejie Formation and Member 1 of Shahejie Formation in the Paleogene of Huanghua depression, Bohai Bay Basin. However, in Huanghua depression, the expanded exploration and large-scale development of shale oil are restricted by unclear enrichment laws and favorable layers/areas of shale oil. Based on testing data of the Paleogene of Huanghua depression regarding coring, rock slice, well logging, oil test, source rock evaluation and comparative experiment of slippery water imbibition under atmospheric pressure, this paper systematically analyzes the source rocks, reservoir properties and preservation conditions of shale oil in Huanghua depression, and explores the enrichment modes of shale oil and the distribution laws of favorable areas in Huanghua depression. It is found through the research that the enrichment of the Paleogene shale-type shale oil in Huanghua depression is mainly controlled by the source material supply and source rock conditions such as moderate source material supply, moderate total organic carbon content (TOC content of 2%~6%), moderate organic matter type (dominated by Type I, followed by Type III), and moderate thermal evolution maturity ( R _o of 0.7%~1.2%); suitable reservoir conditions such as high density of micro-nano laminae (up to 15 000 laminae/m), high proportion of micro-nano pores (average porosity of 4.5%), and high content of retained movable hydrocarbons (average S ₁ of 4.2 mg/g); excellent preservation conditions such as ideal roof and floor sealing conditions (caprock thickness of 50~100 m), weak fault damage (distance between faults and the target layers of a horizontal well:450~550 m). The shale oil enrichment law in the Paleogene of Huanghua depression, which features "a matching between medium and high level" that involves good fabric facies, excellent cross-over effect and perfect match between source rock and reservoir has been established, as well as the enrichment modes of shale oil respectively based on three types of dominant fabric facies in the Paleogene (namely the millimeter-grade organic matter-felsic lamina, the centimeter-grade organic matter-siltstone lamina, and the millimeter-grade organic matter-carbonate lamina in Huanghua depression). Additionally, this paper puts forwards the selection criteria and quantitative evaluation method for favorable layers and areas of shale-type shale oil in the study area, and selects seven sets of Type I shale oil layers in the Paleogene of Huanghua depression as the preferred target layers for drilling. By now, under the guidance of relevant theoretical understandings and technical methods, breakthroughs have been made in the large-scale development of shale oil in Cangdong sag and the exploration of shale oil in Qikou sag. Specifically, the shale oil development demonstration area with a production capacity of 10×10 ⁴t/a has been preliminarily completed, and the economically viable development of shale oil at the oil price of 65 dollar/barrel has been achieved, which demonstrates the promising exploration and development prospects of continental shale oil in the faulted basins in eastern China.

The proved rate of conventional crude oil in Qintong sag of Subei Basin is more than 40%, and resource replacement is facing great challenges. Compared with other basins in China, Qintong sag is characterized as being fragmented, small, poor, and deep. The mud shale in Qintong sag has a low abundance of organic matter, in which the total organic carbon (TOC) content is generally lower than 1.5%. In recent years, by strengthening the basic geological research of accumulation, the main controlling factors of shale oil accumulation have been identified, including special organic maceral types, favorable lithofacies association, complex three-dimensional pore-fracture system, good preservation conditions and good transformability. The dynamic accumulation model of shale oil in Qintong sag of Subei Basin has been established, and the evaluation index of the sweet spot of continental shale oil with low TOC content has been established, which has laid a theoretical foundation for the exploration and development of shale oil. Through the deployment and implementation of risk exploration wells, Well SD1 obtained the highest test oil production of 50.9 t/d and the cumulative flowing oil production of 1.5×10 ⁴t, making a great breakthrough in the exploration of continental shale oil in Subei Basin, and showing a good prospect of shale oil exploration and development in Member 2 of Funing Formation. According to the resource evaluation results, the favorable area of shale oil in Member 2 of Funing Formation of Qintong sag is 420 km ², and possess the resources of 2.95×10 ⁸t. The breakthrough of shale oil exploration in Qintong sag has changed the evaluation criteria of continental shale oil in China, and boosted the confidence of increasing reserves and production of shale oil in small continental basins of eastern China, which is of important theoretical and practical significance.

Tight reservoirs are mostly developed by volumetric fracturing horizontal wells with the elastic drive of natural energy in China. As the production of horizontal well decreases rapidly, the primary oil recovery is less than 10%. To effectively supplement the formation energy is the key for stable production of the volumetric fracturing horizontal wells in tight reservoirs. Water huff-n-puff is an effective method for the supplementation of formation energy in tight reservoir for horizontal wells. In recent years, a lot of researches and practice have been performed on this method. This paper introduces the process of water huff-n-puff technology, outlines the research progress on the mechanism of water huff-n-puff from two aspects:micro-mechanism of imbibition oil recovery and influence law of pressure on imbibition oil recovery, and further systematically summarizes the influence law of reservoir properties and process parameters on the oil recovery of water huff-n-puff technology. To improve the oil recovery of water huff-n- puff, there are mainly three technologies, including the water huff-n-puff technology assisted by chemical treatment agent and enhanced by large displacement water injection, and inter-fracture asynchronous injection-production technology in the same horizontal wells. Through summarizing the research results from reservoir numerical simulation and process parameter optimization for water huff-n-puff, and analyzing field practise experience, this paper further proposes the future development trends of water huff-n-puff technology in tight reservoirs.

Shale reservoirs are characterized by their nanometer pore size. At the nanoscale, fluid flow mechanisms and phase behaviors are significantly influenced by the size and surface effects, resulting in deviations from classical fluid theories. Conventional oil and gas reservoir engineering theory is not fully applicable to shale reservoirs, restricting the efficient development of shale oil and gas. It is thus of both scientific significance and engineering value to clarify fluid transport and phase properties at the nanometer pore scale of shale. Nanofluidics, with the capabilities of precisely manufacturing pore structure and observing in-situ fluid behaviors at the nanoscale, gives new experimental insights into microscopic seepage and phase behavior of shale oil and gas, and provides essential validation for theoretical studies. This paper reviews recent research progress on the nanofluidic study of the nanoscale single- and two-phase flow of oil, gas and water, phase behavior of single- and multi-component hydrocarbons, diffusion and mixing process, as well as microphysical model of shale reservoirs. We focus on introducing nanofluidic methods to detect fluid characteristics, and the differences between experimental results and theoretical descriptions. The current limitations of nanofluidic studies of shale reservoir fluids are discussed in the end, and future directions in this field are foreseen.

Archean buried-hill zone in the western section of Bonan low salient of Bohai Bay Basin has good conditions for hydrocarbon accumulation. Bozhong26-6 oilfield is an Archaean integrated oilfield with proven reserves of crude oil exceeding 100 million tons. Based on a large number of core, thin section, well logging and geochemical data, a systematical study was performed on Bozhong26-6 oilfield. The analysis suggests that the Archean buried-hill reservoirs can be vertically divided into weathered conglomerate zone, weathered fracture zone and bedrock zone, among which the weathered fracture zone is the key reservoir development zone. The superimposed fractures formed by the Indosinian, Yanshanian and Himalayan movements provided the foundation for the development of Archaean buried-hill reservoirs. The Indosinian compression and collision and the Yanshanian strike-slip thrust were the main driving forces for the formation of fractures, and the south-north extension of the Himalayan epoch maintained the validity of earlier fractures. Under the communication of fractures, a wide area of high-quality buried-hill reservoirs is formed by the dissolution of atmospheric fresh water, and the high-quality reservoirs are developed in the zone within 420 m away from the unconformity. The mudstone of Dongying Formation with weak overpressure and strong stability overlying buried hill provides good sealing conditions for the preservation of large-scale oil reservoirs. The Archean buried hills are in direct contact with the source rocks of Huanghekou sag in the south, and are connected with the source rocks of Bozhong sag in the north by the unconformity, thus forming a multi-dimensional oil-gas migration and charging mode. In conclusion, the above findings provide a guidance for the efficient exploration of Archean high-abundance oil reservoirs in Bozhong26-6 oilfield, further improve the hydrocarbon accumulation and reservoir mode of deep Archean buried hills in Bohai Bay Basin, and are of important guiding significance for the oil and gas exploration of the Archean buried hill zone around the southwest Bozhong sag.

At present, there are disputes on whether the degree of water retention at the turn of Ordovician and Silurian has an impact on the enrichment of organic matter. Based on the division of biostratigraphic framework, the paper analyzes the sedimentological and geochemical characteristics of shale in different periods in western Hubei, and explores the relationship between the degree of water retention and the enrichment of organic matter. The findings show that the turn of Ordovician and Silurian in western Hubei can be divided into three periods from early to late:pre-glacial period (WF2-WF3 graptolite zone), glacial period (WF4 graptolite zone-Guanyinqiao section), and post-glacial period (LM1-LM5 graptolite zone), all in deep water environment. The degree of water retention has no significant impact on the preservation conditions of organic matter; it mainly controls marine productivity and further affects the enrichment of organic matter. The depositional period of the pre-glacial WF2 graptolite zone was in the stage of platform-shelf transition, and the sea level was low. Meanwhile, the surrounding paleo-land and local underwater paleo-uplift were uplifted dramatically, the degree of water retention was the strongest (strong retention), and the nutrient exchange with the open sea was the weakest, resulting in the lowest level of paleoproductivity and the lowest TOC content (2.9% on average). After entering the depositional period of the WF3 graptolite zone, the sea level continued to rise to a high level, and the degree of water retention was weakened significantly (moderate retention). With the increase of paleoproductivity level, the TOC content increased (3.6% on average); although the sea level was the lowest in the glacial period, the rising ocean currents were extremely active and the degree of water retention was the weakest. Plenty of nutrients flowed into the Yangtze Sea Basin with upwelling currents, resulting in the highest level of paleoproductivity and the highest TOC content (4.6% on average); in the post-glacial period, the climate warmed up, Gondwana glacier melted rapidly, the tectonic activities remained stable, the sea level rose significantly to a high level, the degree of water retention was moderate, the paleoproductivity was high, and the TOC content was high (4.0% on average).

It is generally considered that the reservoir properties will be destroied once silicification occurs in carbonate reservoirs, leading to difficulty in the storage of oil and gas. However, some scholars have found that siliceous rocks originated from completely corroded carbonates can also develop dissolved pores, where oil and gas have also been discovered. There still lack systematic studies on the genesis of silica in the Lower Cretaceous lacustrine carbonate rocks of Campos Basin, relationship between silica and reservoir space, and evolution law of the reservoir space. After the silicification of carbonate rocks, it is difficult to grasp the changes in the evolution of reservoir porosity. Based on previous studies and the analyses of microscopic rock characteristics under microscope and geochemical characteristics, the paper investigates the petrologic features, reservoir space types, silica source and storage space evolution law of Lower Cretaceous silicified carbonate reservoirs in Campos Basin. The results suggest that dissolved siliceous rocks can act as reservoirs; silica in carbonates was formed due to metasomatism, and silica-rich hydrothermal fluid flowed into the carbonate formations through major faults, producing a cementation and metasomatism on the carbonate rocks; there were multi-stage hydrothermal fluid activities, including the dissolution of original carbonate rocks, cementation and metasomatism of silica, and dissolution of the siliceous rocks from completely corroded carbonate rocks. In general, the reservoir space evolution of the silicified carbonate rocks can be divided into five stages, including carbonate rocks with high porosity, siliceous carbonate rocks with medium porosity, carbonate siliceous rocks with low porosity, siliceous rocks with medium porosity, and siliceous rocks with high porosity. In addition, fractured-cavity type reservoirs with better physical properties can be found in siliceous rocks distributed along major faults.

In Pearl River Mouth Basin, Kaiping sag is located in the deep-water continental slope area beyond the existing continental shelf slope break zone, where oil and gas resources are less explored. It is of great significance to carry out source rock evaluation and clarify its crude oil source for deepening the understandings of oil and gas accumulation in Kaiping sag and guiding the next step of oil and gas exploration. Based on the test data including TOC content, rock pyrolysis, source rock and crude oil biomarker characteristics, the paper systematically analyzes the geochemical characteristics of source rocks of Wenchang Formation and Enping Formation, and conducts the oil-source correlation. The results show that:(1) The argillaceous source rocks of the Lower and Upper Wenchang Formation and Lower Enping Formation tend to be thick in the core area of Kaiping sag and gradually thinned towards the peripheral slope zone, of which the medium to high organic matter abundance and Type Ⅱ ₁-Ⅱ ₂ kerogen demonstrate that they are in the mature stage as a whole. (2) The source rocks of Wenchang Formation has the low values of Pr/Ph, C ₁₉₊₂₀TT/C ₂₃TT and low to medium OL/C ₃₀H. C ₂₇-C ₂₈-C ₂₉ regular steranes on the gas chromatography-mass spectrum present "V" shape, and C ₃₀ 4-methylsteranes have high abundance. The source rocks of Enping Formation have high values of Pr/Ph and C ₁₉₊₂₀TT/C ₂₃TT, as well as low values of OL/C ₃₀H and low C ₃₀ 4-methylsterane content, and the distribution of C ₂₇-C ₂₈-C ₂₉ regular steranes shows an inverted "L" shaped pattern. (3) There are two types of crude oil produced from Kaiping sag. As for Type A oil, the Pr/Ph values are within the range of 1.13 and 1.82, the C ₁₉₊₂₀TT/C ₂₃TT values range from 0.32 to 0.89, the OL/C ₃₀H values are between 0.03 and 1.02, and the average relative content of C ₂₇ and C ₂₉ regular steranes is 26.20% and 46.44%, respectively. The C ₃₀ 4-methylsteranes have high abundance. As for Type B oil, the Pr/Ph values are greater than 2.00, the C ₁₉₊₂₀TT/C ₂₃TT values are between 1.00 and 2.28, the OL/C ₃₀H values range from 0.04 to 0.13, and the average relative content of C ₂₇ and C ₂₉ regular steranes is 9.92% and 65.54%, respectively. The content of C ₃₀ 4-methylsteranes is extremely low. (4) Oil-source correlation analysis shows that Type A oil is originated from the hybrid organic matters of Type Ⅱ and Ⅲ formed by plankton and terrestrial plants in lacustrine source rock of Wenchang Formation; Type B oil comes from the deltaic swamp mudstone of Enping Formation in the background of oxidation sedimentation, and the hydrocarbon generation parent material is dominated by Type Ⅲ organic matter formed by terrestrial higher plants. In conclusion, the research has clarified the sources of oil and gas in Kaiping sag, which is of theoretical guiding significance for future oil and gas exploration.

Lamellar calcite veins are widely developed in the lacustrine dark fine-grained sedimentary rocks from the upper submember of Member 4 to the lower submember of Member 3 of Shahejie Formation in Niuzhuang subsag. The distribution of these veins is characterized by strong heterogeneity, which is of great significance for the development of shale oil sweet spots. The research shows that the development of lamellar calcite veins is controlled by the lithofacies of fine-grained sedimentary rocks, which are mainly developed in organic-rich lamellar calcareous mudstones and argillaceous limestones. In fine-grained sedimentary rocks, the well-developed lamellar structure and the lithofacies type with the TOC content of more than 2%, carbonate content of 10%-70%, and argillaceous content of greater than 20% are favorable for the development of calcite veins. Among them, TOC content plays a more significant role in controlling the development of lamellar calcite veins. The lamellar bright calcite veins were mainly formed in the semi-mature and mature stage of organic matters. The carbonate minerals precipitated in the early stage of fine-grained sedimentary rocks serve as the main material source for veins formation. These minerals dissolve under the action of organic acids and enter the vein-forming fluids formed by hydrocarbon generation and clay mineral transformation. Under the effect of hydrocarbon generation pressure, horizontal microfractures are formed along the laminas of fine-grained sedimentary rocks, and vein-forming fluids migrate along this channel and recrystallize in the surrounding pressure relief area to form lamellar bright calcite veins. Research shows that only the fine-grained sedimentary rocks corresponding to the evolution depth of source rocks, which can provide sufficient vein-forming materials and fluids and have rich laminated structure, are easy to develop calcite veins in Niuzhuang subsag. Based on this, the development model of calcite veins has been established.

In recent years, several wells in Santai area in the east of Junggar Basin have obtained high-yield industrial oil-gas flow in the Permian System, showing the characteristics of multiple-layer complex oil-gas accumulation, and great exploration potential in oil-gas rich zones. Based on drilling, logging, sample analysis, and oil testing data, a systematic study is performed on the enrichment conditions and reservoir formation characteristics of multi-layer oil-gas, so as to deeply investigate the geological characteristics and exploration prospects of multi-layer oil-gas in Santai area and its surrounding areas. Santai area is adjacent to the hydrocarbon rich sag and is supplied with multiple sources of hydrocarbons from the Carboniferous, Permian, and Jurassic reservoirs. The Permian Lucaogou Formation is the primary source rock of oil-gas in the study area. Under the tectonic setting of low uplift, the trough system is developed, and large-scale sand bodies are developed in the main trough area, characterized by "trough controlling sand bodies". Multiple sets of positive cycle sedimentary combinations are developed in Carboniferous and Cretaceous reservoirs, and possess favorable reservoir-cap conditions. There are differences in the main control factors for oil-gas accumulation in different layers. The Carboniferous is controlled by fault fractures and structures, characterized by mixed-source hydrocarbon supply, where fault blocks or stratigraphic oil-gas reservoirs are mainly developed. The Permian is controlled by faults, paleogeomorphology and lithologic pinch-out, characterized by single-source hydrocarbon supply, where fault-lithologic petroleum reservoirs are developed. The Permian and Jurassic are controlled by faults and lithologic pinch-out, where faults and fault-lithologic petroleum reservoirs are developed. Tectonic activities are strong in the southern part of Santai area and the Ji'nan uplift, due to which large faults are developed, and there are favorable conditions for oil-gas migration and accumulation; they are key areas for multi-layer exploration, and the predicted resource is about 2.45×10 ⁸t.

The shale in deep water areas of a continental lacustrine basin represented by the Member 2 of Kongdian Formation of Cangdong sag in Bohai Bay Basin boasts good shale oil exploration and development potential. However, the relationship between macroscopic distribution of lithofacies and microscopic characteristics of reservoirs is still unclear. Based on high frequency transgressive-regressive (T-R) sequence division of shale, using the methods such as core observation description, rock thin section identification, quantitative analysis of minerals by X-ray diffraction, elemental and organic geochemical testing, logging curve, field emission scanning electron microscopy analysis, nitrogen adsorption experiment, high pressure mercury injection experiment, and focused ion beam scanning electron microscope analysis, this paper analyzes the lithofacies filling evolution of different types of sequences and reservoir characteristics of different lithofacies, and explores the effect of high frequency sequence on reservoir development. The research results show that organic-rich shale section of the Member 2 of Kongdian Formation in Cangdong sag can be divided into 11 high frequency T-R sequences (5th-order sequence SQ①-SQ⑪, of which SQ⑨ develops gravity flow sandstone). According to the symmetry of lacustrine T-R cycles in high-frequency sequences, the sequences can be divided into asymmetric type dominated by T cycle, asymmetric and nearly symmetric types dominated by R cycle. Shale reservoirs mainly develop micropores such as intergranular pores, intra-granular pores, organic matter pores, and microcracks, among which inorganic pores such as intergranular pores and intra-granular pores are the main ones. The lamellar felsic shale facies and lamellar hybrid shale facies with higher content of felsic minerals and more laminated structures develop more macropores with better connectivity, while the massive hybrid shale facies and lamellar/massive carbonate shale facies with higher carbonate mineral content and more massive structures develop mesopores with general connectivity. Affected by mineral content and sedimentary structure, the shale reservoirs demonstrate the obvious characteristic of being controlled by facies, and the high frequency sequence can be regarded as a response to the changes in sedimentary environment in continuous time series, thus influencing the sedimentation of shale in the center of lacustrine basin. The significantly different reservoir characteristics correspond to high-frequency sequences at different evolutionary stages. Specifically, the middle-upper sequence at the rapid lacustrine transgression stage and bottom sequence at the oscillating lacustrine transgression stage are the high quality reservoir development section, and only local sequences at the stable high stage develop high quality reservoirs. These results are expected to provide theoretical support for the division of high-frequency shale sequences in deep water areas of a continental lacustrine basin as well as evaluation and prediction of high-quality reservoirs.

The solid-liquid interface characteristics of oil, water and rock are critical to the imbibition behaviors of tight and shale reservoirs. Especially for the imbibitionsystem with ultralow interfacial tension and solubilization and emulsification effects. It is urgent to clarify the relationship between the interface action mechanism and imbibition behaviors. This paper is a case study of tight reservoirs in Member 7 and 8 of Yanchang Formation and shale reservoirs in Longmaxi Formation; five typical imbibition fluids were developed, including simulated formation water, basic surfactant (AES), surfactant system that can form nanoemulsion(nE-S), prefabricated nanoemulsion containing oil shell (nE)and in-situ microemulsion (mE-FS), and a systematic and deep study was carried out on interface interaction, physical simulation of imbibition, normalized recovery model, scale equation and imbibition mathematical model. The results indicate as follows.(1)mE-FS is characterized with solubilization ability and ultralow interfacial tension, and thus can significantly improve the rock surface wettability and imbibition recovery; (2)The recovery ratio of imbibition fluids is ranked as follows:mE-FS>nE>nE-S>AES>simulated formation water; (3)mE-FS imbibition recovery is linearly correlated with core permeability, i.e., the lower the permeability, the poor the imbibition effect; (4)A dimensionless time scale model with a wide range of application has been established by taking into full account interfacial tension and wettability changes; (5)Solubilization coefficient is introduced into the imbibition theory mathmatical model to establish a linear relationship between imbibition distance and time of imbibition fluids with different interface properties.

With the continuous development of unconventional oil-gas reservoirs, it has been quite difficult for the traditional Arps decline equation to describe the production decline process of large-scale volume fracturing and horizontal wells in unconventional oil-gas reservoirs. Therefore, by summarizing and studying the mathematical model of the existing production decline equation, the observation time in Arps production decline differential equation is replaced by a composite function that has time attribute and reflects the development and change of oil-gas reservoir system, and a general production decline equation with more general adaptability has been established. Under certain conditions, this general equation can be transformed into various existing common production decline equations, and also form new high-precision production decline equations. It is expected that in the future, the research of production decline equation will mainly focus on the determination of the relationship between composite function and decline time. Once the new relationship between composite function and decline time is determined, a new production decline equation can be formed. Meanwhile, for the convenience of application, the paper systematically provides the calculation method of the general production decline equation under the condition of two kinds of relationship between composite function and decline time. Through practical applications, it has been found that it is highly effective to use the time-varying structure estimation method and perform fitting between the general equation of production decline when T= mt ^b and the production decline curve of unconventional oil reservoirs in Ma 56 wellblock, and the estimated production is very close to the actual value.

Large-scale fracturing technique is one of the important means to effectively develop shale oil. After large-scale fracturing, complex fracture networks will be formed around the wellbore. The inversion of fracture parameters after fracturing is the key to fracturing performance evaluation and parameter optimization for hydrocarbon development. However, it is difficult for the existing mathematic and well test models to meet the inversion needs of complex fracture network in shale oil. For this reason, the paper investigates the characterization of complex fracture networks in shale oil fractured horizontal wells, establishes semi-analytical well test models for multi-mode fracture network of shale oil, including volume fracturing model, compound fracturing model, and discrete fracture network model. The semi-analytical well test model of multi-mode fracture network is solved using point source method, semi-analytical method and Laplace transformation. Moreover, efforts are made to perform numerical verification, divide flow phases and analyze the characteristics of flow section. Based on the semi-analytical well test model established for multi-mode fracture network, a sensitivity analysis was performed on well test characteristic curve, and then a well test curve fitting method was established. Supported by the production history fitting method, the scheme for parameter evaluation of shale oil multi-mode fracture network was initially developed based on well test theory. The fracture network parameter evaluation method was actually applied in the shale oil fractured horizontal wells JA and JB in Jimsar. An evaluation was performed on fracture network parameters, including fracture network geometries, half length of primary and secondary fractures, hydraulic conductivities of primary and secondary fractures, storage coefficient before and after crack closure, and fracture closure time. In addition, the accuracy and practicality of the evaluation method of complex fracture network parameters were proved by field applications.

To solve the technical bottleneck problem of slow footage and rapid wear rate of milling tools for workover under complex wellbore conditions, the early recommended slope milling tool for workover was taken as the research object based on previous research. First of all, a mechanical analysis model of the abrasive grain based on the shear slip line theory model was established, and the quantitative relationship between abrasive grain angle and working torque of the milling tool was clarified. Then a single abrasive grain cutting simulation software based on the secondary development of ABAQUS in Python language was developed, and the parametric modeling of single abrasive grain cutting simulation model was realized. Besides, the milling tool for workover with single abrasive grain of different angles was developed and the cutting experimental tests were completed. At last, the preferred angle of the abrasive grain was determined from five aspects including angle type, chip formation process, chip morphology, cut scar morphology and work characteristics. The results show that the cutting force of the abrasive grain with zero angle has the fastest growth rate, the value of the abrasive grain with positive angle is the largest, and the value the abrasive grain with negative angle is the smallest with a smoothly fluctuating in the range of 642.5-785.3 N. With the increase of the angle of the abrasive grain from 0° to 45°, the chip volume gradually decreases, the chip length decreases from 5 mm to 2 mm, and the chip shape changes from roll-like type to irregular granular type. When the angle of the abrasive grain is 5° and 10°, the cut depth of the workpiece surface is the largest that reaching 1.0 mm. When the angle of the abrasive grain is 8°, the material removal mass is the largest that reaching 9.49 g, and the working torque is only 28.7 N ·m, which shows the working process is relatively smooth. Considering the working efficiency as well as working safety, the preferred angle of the abrasive grain on the slope milling tool for workover is -8°.

Qingshimao gas field was explored in 2022, which has the proved area of 2 151 km ² and proved reserves of 1 459×10 ⁸m ³, making it the eighth gas field of hundred billion cubic meters in Changqing oilfield. By reviewing the exploration history of Qingshimao gas field, the geological characteristics of natural gas accumulation are summarized as follows. The main gas-bearing stratum of Qingshimao fas field is the Member 8 of the Permian Xiashihezi Formation; the main source rocks are coal seams and dark mudstones in Carboniferous Benxi Formation, Permian Taiyuan Formation and Shanxi Formation, characterized by widespread hydrocarbon generation. Delta front subfacies sedimentary system is developed, where the distributions of sand bodies are controlled by multiple provenances, multiple drainage systems, strong supply and multiple channel. The reservoir is dominated by fluvial channel sandstones with an average porosity of 7.9% and an average permeability of 0.363 mD, indicating a tight reservoir, and the connectivity of sand bodies is controlled by their distribution. The pressure coefficients of gas reservoir range from 0.78 to 0.90, demonstrating a low pressure gas reservoir. The reconstructed gas reservoir under the control of lithology and structure was formed due to long-term continuous charging under low hydrocarbon generation intensity, adjustment and transformation of tight reservoirs by fault systems, and high source-reservoir pressure difference. The three-dimensional seismic exploration, sand body fine characterization, and well location selection under complex gas-water relationships are key technologies for exploration and development of Qingshimao gas field.

China has a complete range of coalbed methane (CBM) resources, which are extremely rich and relatively reliable. The resource foundation can completely form an emerging industry with an annual gas production of hundreds of billions of cubic meters. With strong national support, after 30 years of arduous efforts, China has made significant progresses in the exploration and development of coalbed methane, forming an industry with an annual production of 10 billion cubic meters. However, this is too far from the goal of 100 billion cubic meters of coalbed methane annually, and the national task has not been completed for three consecutive Five-year plans. At the same time, China CBM industry has lost its clear development direction. Only a small contribution can be made to the urgently needed natural gas industry in China. The fundamental reason is that the theory and technology of CBM exploration and development established domestically and internationally over the past 30 years can not fully reflect the composition and pore structure characteristics of coal, as well as the occurrence state of methane mainly in an adsorbed state, which is not fully in line with the mechanism of CBM production, of which applicability is too small to be universal. On the basis of in-depth analysis of the mechanism of coalbed methane production, it is proposed that only the integration of coal mine gas and natural gas development disciplines can establish scientific and practical theories and technologies for CBM exploration and development. Then, four types of CBM resources are divided. Moreover, each CBM resource can be established with scientific and practical theories and technologies to achieve efficient exploration and effective development. This article discusses the possibility and implementation path of building a 100 billion-cubic-meter-scale CBM industry in China from aspects such as the status of CBM resources, progress in oil and gas exploration and development technology, occurrence and migration laws of methane in coal. This article proposes to rely on the cross integration of coal and oil and gas industries, strengthen basic research, establish a theoretical and technical system suitable for efficient exploration and effective development of various types of coalbed methane reservoirs, generate a new discipline (direction), form a new production, technology, and industry field, and build a path of a large industry, To achieve the development strategy of forming an emerging coalbed methane industry supported by original theories and technologies of coalbed methane exploration and development, and to ensure the rapid formation of China's annual production of a 100 billion-cubic-meter-scale CBM industry, in order to significantly reduce China's dependence on external natural gas.

China's deep coalbed methane (CBM) resources, with the burial depths exceeding 1 500 m, are abundant and coexist with adsorbed and free gases. The occurrence state, accumulation characteristics, and development laws of deep CBM differ significantly from those of mid-shallow CBM, and the unclear evolution patterns have restricted its efficient exploration and development. Taking the No.8 deep coal seam in Daning-Jixian block on the eastern margin of Ordos Basin for example, this study finely characterizes the accumulation characteristics of deep CBM and simulates the burial evolution history, thermal evolution history, and hydrocarbon generation history of deep coal seams, thus improving the deep CBM enrichment and accumulation laws and patterns; moreover, the targeted exploration and development strategies are proposed. The results show that the No.8 deep coal seam is widespread in Daning-Jixian block, with high organic matter thermal maturity and Type III kerogen. This indicates significant hydrocarbon generation potential, with the total hydrocarbon intensity of (20.2-34.7) ×10 ⁸m ³/km ². The deep coal reservoir develops cleats, fractures, texture pores, cell pores, gas pores, intergranular pores, and dissolution pores, providing favorable conditions for the accumulation of deep free-state CBM. The structural-lithologic-hydrodynamic coupling closure is favorable for the preservation of deep CBM. The evolution stages of hydrocarbon accumulation in deep coal seams in the study area include the initial hydrocarbon generation stage (Stage I, 306-251 Ma), the first thermal hydrocarbon generation stage (Stage II, 251-203 Ma), the decreasing stage of organic matter thermal evolution (Stage III, 203-145 Ma), the hydrocarbon generation peak stage (Stage IV, 145-130 Ma), and the final formation stage of the oil/gas accumulation pattern (Stage V, 130 Ma to present). The deep CBM under free and adsorbed states coexist in the study area. On this basis, the paper proposes the hydrocarbon enrichment and accumulation pattern of "wide covering hydrocarbon generation, box-type closure, microstructure adjustment, self-generation and self-storage, and blanket-type accumulation", and establishes three types of deep CBM accumulation models:microfold and physical property coupling control (Type I), microfault monocline and hydrodynamic force coupling control (Type II), and physical property and hydrodynamic force coupling control (Type III) on reservoir accumulation. These understandings can effectively guide the selection of favorable areas for deep CBM exploration in Daning-Jixian block, establish an evaluation index system for favorable areas in deep coal reservoirs, propose differentiated development plans for exploration areas with different accumulation models, and help achieve the truly efficient and low-cost development of deep CBM in the study area. The research findings have important reference significance for carrying out deep CBM exploration and development in other blocks in China.

Based on the analysis of deep oversaturated coalbed methane (CBM) reservoirs, the following understandings are obtained. (1) As the buried depth of coal seam increases to a certain depth, the positive effect of coal rank and formation pressure on adsorption is less than the negative effect of temperature on adsorption, as result of which the adsorption gas is gradually saturated (adsorption saturation of 100%) and enters in the stage of in-situ free gas occurrence, thus forming deep oversaturated CBM reservoirs. The formation pressure and temperature keep increasing with the buried depth, and this objective law provides natural conditions for the formation of oversaturated CBM reservoirs in deep strata of the basin. (2) The critical depth of oversaturated CBM reservoirs varies in different basins, and the critical depth difference of oversaturated CBM reservoirs is determined by the basin geothermal gradient and pressure gradient. Abnormal high pressure and temperature (such as the high temperature caused by volcanic thermal events) can reduce the critical depth of oversaturated CBM reservoirs. (3) Deep oversaturated CBM reservoirs have the advantages of short gas breakthrough time, full utilization of formation energy and low cumulative water production in the exploitation, which is expected to become an important field of CBM exploration and development in the future, possessing broad exploration prospects in China's large-scale basins with deep coal seam burial conditions. The understandings of deep oversaturated CBM reservoirs come from the analysis of static data and production dynamic data on-site, reflecting the epistemological view that the knowledge originates from practice and in turn serves practice. This has great significance for guiding deep CBM exploration and development.

Deep coalbed methane (CBM) will become an important field for China to increase the large-scale natural gas reserves and production in the future. It is of great significance to review the history and progress of the geological research on deep CBM propose and evaluate the existing problems and exploration directions, which can provide a reference for developing applicable exploration and development technologies. Analyses reveal that China has made three major advances in the geological research of deep CBM in the past 20 years. First, the basic concept and its scientific connotation of deep CBM have been defined. It is found that there is a critical depth for the absorbed gas content of deep coalbeds, which mainly depends on the coupling relationship between geothermal gradient and geo-stress gradient, and other geological factors can adjust the critical depth. A decrease in the adsorbed gas content may lead to an increase in free gas content, resulting in the orderly accumulation of CBM in the depth sequence and the formation of highly to super saturated reservoirs with abundant free gas in the deep coal. Second, remarkable progress has been made in research of the geological properties of deep coal reservoirs, and it has been recognized that the weakening adsorption of deep coal reservoirs and the increase of free gas content are resulted from the dynamic equilibrium between the positive effect of pressure and the negative effect of temperature. Moreover, it has been found that there is a "highly permeability window" of coal reservoirs near the transition zone of geo-stress state on the depth profile, and the formation temperature and pressure indices related to the reconstruction of deep coal reservoirs may have a threshold property, and the temperature compensation and variable pore compressibility effects may significantly lower the decay rate of permeability for deep coal reservoirs. Third, an in-depth research is gradually implemented on the accumulation and geological evaluation of deep CBM reservoirs, and the exploration on accumulation mechanism focuses on CBM gas-bearing property formed by buried depth changes, vertical permeability distribution and its geological control, thus initially revealing the "depth effect" for CBM reservoir formation. Through on-site case analysis, the relevant understandings have been deepened and expanded from basin to favorable zone, then to sweet spot and from reservoir control to production control. The analyses suggest that the organic connection and deep coupling of basic geology (reservoir-forming process), exploration geology (evaluation optimization) and development geology (dynamic process) are key directions for the geological-engineering integration in deep CBM exploration and development. Therefore, it is suggested future research should focus on "depth effect", including the systematic description of deep CBM reservoir and the characterization of gas reservoir engineering responses to geological conditions.

Deep coalbed methane (CBM) with a buried depth of greater than 2 000 m is an important field of CBM exploration and development. Different from the middle-shallow CBM that mainly consists of adsorbed gas, the occurrence state of deep CBM is characterized by the coexistence of free gas and adsorbed gas. At present, the desorption law of deep CBM, the opportunity for conversion between free gas and desorbed gas and the reasons for the difference in development effect are still unclear. This paper is a case study of Daning-Jixian block in the eastern margin of Ordos Basin. Since the distribution law of its key geological parameters is consistent with the tectonic trend, the block can be divided into four development areas based on the microstructural morphology, including negative microtectonic area, gentle tectonic area, positive microtectonic area and tectonic uplift area, of which the geological characteristics have been determined. The key factors that impact the development effect of deep CBM can be summarized as "five essential conditions" and "one degree". Moreover, an analysis is performed on the coupling control mechanism of these key factors in deep CBM development. The "five essential conditions" include the preservation condition, resource condition, desorption condition, seepage condition, and reservoir stimulation condition, which are the geological foundation; the "one degree" refers to the degree of fracturing reformation, which needs to be differentially adjusted according to the "five essential conditions" in the hydrocarbon development process. Based on the "five essential conditions" (25 geological parameters), the paper systematically summarizes the evaluation results, comprehensive production characteristics, and typical production curves of coalbed methane development in 4 development areas, and further proposes corresponding engineering countermeasures. Based on the desorption condition that has been neglected in the evaluation of CBM, the main controlling factors affecting the isothermal adsorption characteristics of deep CBM were identified through isothermal adsorption experiments. The adsorption capacity of deep coal rock is weakened with the increase of temperature, ash content, and moisture content, and increased with the increasing level of the thermal evolution of organic matter. Meanwhile, Langmuir pressure keeps increasing with the increase of moisture content; when the ash content in coal rock varies greatly, the adsorption capacity of coal rock is not significantly correlated with the thermal evolution level of coal rock, and the ash content becomes the main controlling factor for desorption; from the gentle tectonic area to positive microtectonic area, the isothermal adsorption curve of coal rock is varied from steep to gentle, the Langmuir volume is decreased by 10.7%, and the Langmuir pressure is increased by 36.8%. In combination with the experimental results from basic theoretical methods, the paper further determines the desorption laws of deep CBM in different tectonic development areas, and compares and analyzes the differences in desorption characteristics. The production process of deep CBM can be divided into four stages:(1) low efficiency desorption stage + free gas dominant stage (Stage Ⅰ), (2) slow desorption stage (Stage Ⅱ), (3) high efficiency desorption stage (Stage Ⅲ), and (4) sensitive desorption stage (Stage Ⅳ). The starting pressure for the desorption of deep CBM in Daning-Jixian block is 9.05 MPa to 9.30 MPa, the desorption turning pressure is about 6.00 MPa, and the desorption sensitive pressure is 2.30 MPa to 2.70 MPa. In the production of deep CBM wells, the transition from dominant free gas production to dominant adsorbed gas production is a process that mainly depends on the duration of the slow desorption stage, the size of key desorption pressure points (desorption starting pressure and turning pressure), pressure drop, and the characteristics of desorption curve. Finally, based on geological laws and relevant understandings, the reasons for the difference in the development effect of CBM wells in the gentle tectonic area and positive microtectonic area have been analyzed in detail, which aims to provide scientific guidance for the fine geological evaluation and units division, prediction of development laws, optimization of gas production equipment, and formulation of drainage and production system in promoting the efficient development of deep CBM.

As an important alternative energy in the unconventional oil-gas field, coalbed methane (CBM) has enormous potential. The deep coal seams are developed on a large scale in Ordos Basin. However, CBM exploration and development is restricted due to complex geological and engineering conditions in the eastern margin of the basin. This paper is a case study of Linxing-Shenfu block in Ordos Basin. The scientific issues such as geological characteristics of sedimentation and hydrocarbon accumulation, production characteristics, and fracturing mining technology regarding deep coal seams in Ordos Basin are explored based on a large amount of drilled data, core analysis data, and drainage dynamic data. The results show as follows:both semi-bright and semi-dark coal in deep coal seams are developed, dominated by primary structure; the deep CBM is characterized by high gas saturation, sufficient reservoir energy, and favorable coal body structure; two core indicators for evaluating sweet spot area of deep CBM have been determined, i.e., resource availability (coal reservoir energy) and feasibility of fracturing (structure, vertical fracture zone, stress difference between roof and floor and coal seam); a new method has been established by quantification of fractal theory and numerical simulation to characterize the complexity of fractures, forming a horizontal well segmented extreme volume fracturing technology system featured with "dense cutting+large displacement+combined proppant+pre-positioned acid+variable viscosity slickwater"; two gas production control parameters (gas saturation and gas content) have been determined for deep coal seams, and production wells can be divided into three categories based on the characteristics of gas production, i.e., self-flowing after pressure, immediate gas production after discharge, as well as conventional discharge and production. The large-scale efficient development of deep CBM needs to tackle a number of fundamental problems. Great efforts should be paid on making a breakthrough in hydrocarbon expulsion and occurrence process of deep coal seams, determining the boundary conditions for the enrichment area of sweet spots, studying the mechanical properties of deep coal seams and volume transformation. Moreover, it is required to continuously strengthen the integrated technical management of geology, engineering, drainage and production, innovate the enterprise-locality integration and management patterns, and keep improving the assessment of the ultimate recoverable reserves of a single well, so as to achieve the large-scale beneficial development of deep CBM.

Sweet spot prediction is a key and difficult area for deep coalbed methane (CBM) exploration and development, which will restrict whether the large-scale efficient development of deep CBM can be achieved. The conventional sweet spot prediction method is to study the geological or engineering sweet spots separately. The sweet spot prediction/evaluation system based on the geology and engineering integration concept needs to be established urgently. The urgent task is to find an effective theoretical method for realizing the organic unity of geological and engineering sweet spots of deep CBM. The rock mechanical stratigraphy has the inherent attributes and innate advantages of connecting the geology and reservoir engineering of CBM, which provides a new method for overcoming the technical difficulties in the integrated prediction of deep CBM sweet spots. By summarizing the development characteristics of the geological and engineering sweet spots of deep CBM and the difficulties and challenges faced in sweet spot prediction, this paper discussed and analyzed the methodology of rock mechanical stratigraphy for the integrated prediction of deep CBM sweet spots, and carried out the application research of deep CBM sweet spot prediction based on rock mechanical stratigraphy. The research results show that the development law of natural fractures in deep coal reservoirs under the control of rock mechanical stratigraphy is a key constraint for predicting the geological sweet spots of deep CBM, while the development law of fracturing induced fractures under the control of rock mechanical stratigraphy, physical changes in reservoir rocks, and reservoir stimulation are the key factors for evaluating the deep CBM engineering sweet spots. With rock mechanical stratigraphy as a method mechanism, it is possible to realize the organic connection between sedimentary diagenesis, rock mechanical characteristics, geological structure and geostress field characteristics, geological accumulation response, reservoir engineering response, and integrated prediction of deep CBM sweet spots. The application and practice of rock mechanical stratigraphy in the fracture characteristic analysis and high permeability zone prediction of coal reservoir, coal-rock fracture behavior analysis and production zone selection, and fracturing and drainage optimization of CBM reservoir have preliminarily proved that it will be expected to be a technical tool to solve difficulties in the integrated prediction of deep CBM sweet spots.

Due to the complex deep geological environment, the pore, fracture structure and gas occurrence state of deep coal reservoirs are different from those of shallow coal reservoirs. The conventional and unconventional geologic attributes of deep coalbed methane are attributed to the coexistence of multi-phase gas. Using the deep coal and rock samples systematically collected from Daning-Jixian block in the eastern margin of Ordos Basin, the full-diameter pore and fracture structure of deep coal was fine characterized by field emission scanning electron microscopy analysis, high-pressure mercury intrusion experiment, and joint measurement of low-temperature N ₂ adsorption and CO ₂ adsorption. Moreover, the movable fluid space and accommodation potential of free gas in deep coal was analyzed by means of low-field nuclear magnetic resonance technology. The research results show that the pore types of deep coal in Daning-Jixian block are dominated by gas pore, intergranular pores as well as compressed and deformed residual pores in plant cells. The fractures are composed of exogenous fractures, endogenous fractures and micro-fractures in clay minerals, and the micro-fractures are widely developed in the sheet-like and accordion-like kaolinite. There are mainly air-tight pores closed at one end and breathable pores open at both ends, and a small amount of ink bottle pores. The pore structure exhibits significant cross-scale effects and strong heterogeneity. Micropores with a pore diameter less than 2 nm are the most developed, followed by macropores with a diameter from 50 nm to 1 μm and fractures with a diameter greater than 10 μm. Mesopores (with the diameter from 2 nm to 50 nm) and macropores with a diameter from 1 μm to 10 μm are least developed. Micropores have a large specific surface area and strong adsorption potential energy, and are the most important occurrence space for adsorbed gas. In addition, there is a certain movable fluid space in the macropores and micro-fractures with the movable porosity from 1.42% to 3.89%, providing the reservoir conditions to accommodate free gas. However, the relationship between gas and water saturation is quite complex and the water saturation changes greatly in deep coal reservoirs, thus directly affecting the size of the accommodation space of free gas. The research suggests that the relationship between gas and water saturation affected by the porosity and fracture structure will be a key issue that restricts the accurate prediction of highly saturated to supersaturated gas-bearing target areas in deep coal seams.

Deep coalbed methane (CBM) is a new field of hydrocarbon exploration with huge resource potential. In 2021, a great breakthrough was achieved in the exploration and development of CBM at depths greater than 2 000 m in the Daning-Jixian block on the eastern margin of Ordos Basin. The initial gas production from Well Jishen 6-7P-01 reached 10×10 ⁴m ³/d, marking the beginning of large-scale exploration and development of deep CBM in the basin. The lack of a systematic study on targeted pore characteristics has restricted the efficient development of deep CBM in the study area. Based on the test data of cores, scanning electron microscopy, full-diameter CT scans, reservoir properties, low-pressure CO ₂ adsorption, low-pressure N ₂ adsorption, and high-pressure mercury injection, the paper systematically analyzes the reservoir characteristics and pore structure of the No.8 coal seam in Taiyuan Formation of Daning-Jixian block. The results indicate that:(1) The No.8 deep coal reservoir formed in waterlogged forest and swamp with lagoon facies. Bright and semi-bright coal are mainly found in the study area, with a high organic matter thermal maturity (average R _o of 2.81%). Cleats and fractures are well developed but often filled with secondary minerals, resulting in a low effective fracture ratio. (2) The of the No.8 deep coal seam has poor reservoir properties, of which the matrix porosity ranges from 3.60% to 6.11%, averaging at 3.65%, and the matrix permeability ranges from 0.001 mD to 0.060 mD, averaging at 0.016 mD; it is classified as an ultra-low porosity and ultra-low permeability reservoir. Micropores are the dominant pore type, followed by macropores, while mesopores are poorly developed. Micropores with the specific surface area ratio exceeding 99% serve as the main storage space for adsorbed methane. (3) Compared with the No.8 mid-shallow coal reservoir and the Longmaxi Formation shale reservoir in Sichuan Basin, the No.8 deep coal reservoir has lower permeability. This is primarily due to less effective cleats and fractures, and more micropores with poor connectivity. Based on this understanding, a shift in reservoir stimulation strategies in combination with super-large-scale volume fracturing techniques have significantly increased gas production from the No.8 deep coal reservoir and effectively guided the exploration and development of deep CBM in the study area.

Deep coalbed methane (CBM) resources are abundant in Daning-Jixian block in the eastern margin of Ordos Basin, and the development practice in recent years has broken through the traditional understanding that it is difficult to develop and utilize deep CBM resources. At present, there are still a series of geological problems unsolved in the exploration and development of deep CBM, and especially the control factors of gas-bearing properties and the prediction of free gas content seriously restrict the resource evaluation and efficient development of deep CBM. Comprehensively using the geological data of CBM development and experimental testing methods, the paper compares and analyzes the differences in gas content between mid-deep coal seams (with buried depth from 1 000 m to 1 500 m) and deep coal seams (with buried depth greater than 1 500 m) in Daning-Jixian block, thus discovering the internal and external controlling factors of gas content in deep coal seams, and establishing the prediction models and vertical distribution patterns of gas content in different phases. The results show that the gas oversaturated coal reservoirs are generally detected in deep layer, of which the free gas proportion is from 17% to 43% and tends to increase with reservoir pressure. The free gas content is negatively correlated with water saturation. Before adsorption and saturation, coal reservoir pressure can promote the adsorption of methane by coal seams, while temperature and moisture can inhibit the adsorption of methane. Compared with low-rank coal, high-rank coal has stronger methane adsorption capacity, which is mainly attributed to the material composition of coal, pore structure, physical and chemical reactions between methane molecules and coal surface. Due to many limitations, the adsorbed gas content in coal seams presents a changing trend from "rapid rise to slow growth to slow decline" with the increase of buried depth, while the free gas content presents a trend from "stable rise to slow growth to being constant". Therefore, the change of total gas content in coal reservoirs with buried depth is divided into four evolution stages:rapid rise, slow rise, remaining stable and slow decline.

The Ordos Basin is rich in deep coalbed methane resources, the development of which is helpful to increase the reserve and production of oil and gas and achieve the goals of carbon peaking and carbon neutrality. Focusing on the key problem of predicting free gas content in deep coal seams, the paper proposes a new free gas content prediction model based on the validation and evaluation of the existing free gas content prediction model, when relying on pressure-retaining coring data from the eastern margin of the basin at the depth from 1 911.60 m to 1 924.84 m. The results show that the gas content of 9 pressure-retaining sealed coring samples is ranged from 4.22 m ³/t to 16.35 m ³/t; the free gas content is ranged from 1.24 m ³/t to 2.56 m ³/t, accounting for 11.00% to 36.17% of the total gas content. The difference in gas content is obviously affected by ash content, and the samples with high ash content and high density tend to have low gas content, characterized by oversaturation in the middle coal seam and undersaturation in the upper and lower coal seams. Comprehensively considering the methane gas density, water saturation and porosity of the reservoirs under certain temperature and pressure conditions, in combination with the pore space occupied by adsorbed methane, a prediction model of free gas content in deep coal seams has been constructed based on the effect of adsorption swelling. As predicted using the model, the free gas content is ranging from 1.29 m ³/t to 2.69 m ³/t, accounting for 10.01% to 38.54% of the total gas content, and the gas content ratio (actual gas content/theoretical maximum gas adsorption capacity) is within the range of 33.86% to 148.26%, which is highly consistent with the measured gas content in the pressure-retaining coring samples. In addition, the correlation model can be used to evaluate the gas content in deep coal seams, thus providing theoretical support for the accurate prediction and quantitative drainage and production of deep coalbed methane resources.

The deep coalbed methane (CBM) resources are abundant in Ordos Basin, and three difficulties in seismic technology are encountered in CBM exploration and development, including low signal-to-noise ratio of loess mountain data, thin thickness and rapid lateral changes of coal seams, and high requirements for sweet spot prediction accuracy. To realize the large-scale high-efficiency development of deep CBM, in recent years, significant advances have been made in the integrated technology of seismic acquisition, data processing and interpretation as well as seismic geology and engineering for deep target CBM reservoirs in the eastern margin of Ordos Basin. The application of "wide azimuth, broadband, and high-density" seismic acquisition technique and "high fidelity, high resolution" data processing technology in loess mountain area provides a high-quality data for seismic exploration of deep CBM. As a result, the main frequency of target layer for CBM seismic exploration can reach up to 40 Hz, and the frequency band can be broadened by more than 10 Hz, thus steadily improving the imaging accuracy. The fine structure interpretation and reservoir evaluation technologies have laid a solid foundation for the location of dual CBM sweet spots. The predicted thickness of coal seam is 5 m and the coincidence rate between the predicted and measured values of fractures can reach 79%. The application of seismic geology and engineering integrated technology has realized the effective extension of seismic exploration to geological development, increased the drilling encounter rate of coal seams to more than 97%, and the output of horizontal wells has reached 100 000 cubic meters, providing strong support for the efficient production of CBM in the study area.

Significant breakthroughs have been made in precursor experiments for the exploration and development of deep coalbed methane, showing good prospect for development. However, deep coalbed methane has relatively high buried depth with strong heterogeneity. Lots of geological and engineering factors may affect the development results, and reasonable development countermeasures are still not determined. This paper is a case study of No. 8 coal seam in Ordos Basin, and analyzes its accumulation laws and development characteristics. The results show that No.8 coal seam has high maturity, stable distribution in the whole basin, and huge hydrocarbon generation potential; the average volume proportions of micropores, mesopores, macropores, and microfractures in deep coal reservoirs are 78.0%, 6.8%, 2.1% and 13.1%, respectively, as being a typical multiple pore-fracture system with superior hydrocarbon accumulation conditions; deep coalbed methane is located below the critical depth, characterized with a small-scale structural uplift, relatively tight reservoirs, undeveloped faults, weak hydrodynamic forces, and better preservation conditions. There is a high content of deep coalbed methane in the study area, which coexists with adsorbed gas and free gas. The coal structure is generally well developed, which is more conducive to reservoir stimulation by hydraulic fracturing. The production of gas wells quickly increases at early stag, characterized with high early production and rapid decline; according to desorption laws, the whole process can be divided into three development stages:free gas production, stable production, and decline. To address the challenges faced in the exploitation of deep coalbed methane, based on the experiences obtained during the development of tight gas and shale gas, four targeted suggestions are proposed:(1) initially applying 3D seismic technique; (2) establishing a reservoir geomechanical model; (3) building an industrialized large-scale well cluster construction mode; (4) keep doing precursor experiments. Finally, taking the Daning-Jixian block as an example, the understandings obtained from the precursor experiments have been summarized, will provide reference for further development of deep coalbed methane.