The upstream petroleum industry in China has achieved remarkable success. The annual crude oil production of 2×10 ⁸ t is successively achieved under difficult resources conditions, and the natural gas production has achieved rapid growth, reaching 2 200×10 ⁸m ³ in 2022. China has become the fourth largest gas producer in the world. Through exploring the exploration and development situation of oil and gas in China, this paper analyzes the theoretical and technical challenges faced by the upstream petroleum industry, and looks forward to the development prospects of domestic petroleum industry. China has realized oil-gas exploration and development in deep strata, deep water, and unconventional fields. It is predicted that China's crude oil output will be stable at 2×10 ⁸t, and natural gas production will be stable at 3 000×10 ⁸m ³ in 2035. The development of the upstream petroleum industry in China faces theoretical and technical challenges from five major fields:deep strata, deep water, unconventional resources, enhanced oil recovery (EOR) of old oil-gas fields, and carbon capture and storage(CCS) or carbon capture, utilization and storage(CCUS) projects. The future development of petroleum industry will rely more on geological theories and technological innovations in exploration of deep strata, deep water, and unconventional fields. A new generation of theories, technologies, equipment, and efficient construction teams that are suitable for deep strata, deep water, and unconventional oil-gas exploration and development are the key to achieving the high-efficiency development with low cost. The advanced technology and equipment, which are applicable for deep layer, deep water, unconventional oil and gas exploration and development, as well as EOR of old oilfields and CCS/CCUS projects, will be essential to the development of petroleum industry in the future.

Tarim Basin is characterized by vast exploration areas, large amount of oil-gas reserves, and relatively low degree of exploration. It plays a crucial role as one of the key drivers for China's domestic oil-gas reserves and production during the "14th Five-Year Plan". However, numerous world-class challenges are encountered in the exploration of Tarim Basin, such as ancient marine source rocks, ultra-deep reservoirs, the occurrence of hydrocarbons in ultra-deep reservoirs, as well as the long-term evolution of oil-gas reservoirs, which significantly limit the overall efficiency of exploration in Tarim Basin. Through an integrated approach that combines the data of outcrops, well drilling, geophysics, and testing over the past two years, this paper systematically analyzes the coupling model of key factors for the new types of hydrocarbon accumulation in new prospecting fields of Tarim Basin, as well as resource potential in the study area. The research indicates that Tarim Basin mainly developed four regional reservoir-cap combinations and hydrocarbon systems, including Cambrian pre-salt, Ordovician, and Carboniferous reservoirs in the platform area of basin, as well as the Paleozoic to Cenozoic reservoirs in the foreland area. The most important new areas and types are shown as below:the Lower Cretaceous Yageliemu Formation in Kuqa depression, the Paleozoic buried hills on the south slope of Kuqa depression, the Jurassic tight gas fault-fracture bodies in the northern tectonic belt (Dibei area) of Kuqa depression, the Carboniferous-Permian strata in the southwest Tarim Basin, the Lower Cambrian platform margin belt in platform area and the Cambrian in the west margin of Awati sag, as well as Ordovician fault-karst bodies in the platform area. The near-source oil-gas resources in the Paleozoic buried hills and the Mesozoic of Kuqa foreland basin have enormous potential. The amount of oil and gas resources can reach 2×10 ⁸t and 600× 10 ⁸m ³ in the paleo buried hills of Wensu-Jiamu area, respectively. The amount of gas and oil resources in the Cretaceous Yageliemu Formation is about 10 500×10 ⁸m ³ and 4 300×10 ⁴t, respectively. In the northern tectonic belt of Kuqa depression, the natural gas and oil resources of the Jurassic Ahe Formation possess 2.6×10 ¹²m ³ and 1.3×10 ⁸t, respectively. The Lower Cambrian pre-salt platform margin belt in the platform area contains 1.78×10 ¹²m ³ of natural gas. The gas and oil resources are 4 400×10 ⁸m ³ and 1.4×10 ⁸t in the west margin of Awati sag, respectively. The Ordovician fault-karst bodies has around 32×10 ⁸t of oil equivalent in the Fuman-Shunbei area. The insights into geological and resource potential gained from breakthroughs in exploring new fields and types of oil-gas resources can lay a solid foundation for further efficient exploration in the future.

Ordos Basin is rich in various types of natural gas resources. With the deep exploration from conventional to unconventional hydrocarbons and from shallow to deep strata, a set of natural gas reservoirs of new fields and new types are discovered in Ordos Basin. Based on exploration achievements in recent years, the paper summarizes the new types of gas reservoirs, including deep coalbed methane, Taiyuan Formation limestone gas and bauxite gas, Ordovician presalt gas, marine shale gas, and deep Proterozoic gas, and further performs an in-depth analysis from the perspectives of sedimentary-tectonic background, source-reservoir configuration, and sealing-preservation condition. By analyzing the deployment relationship of source-reservoir-cap assemblage and summarizing the differences of accumulation characteristics and various natural gas, it is believed that these gas reservoirs generally have the accumulation model of near-source, self-generation and self-reservoiring. Based on determining the enrichment characteristics of gas reservoirs, the paper evaluates the favorable exploration areas for natural gas reservoirs in various fields and clarifies their resource potentials and reserve scales. The favorable gas-bearing area of deep coal bed methane is 6.9×10 ⁴km ²; the resources are estimated to be 13.80×10 ¹²m ³, expected to achieve a reserve of trillions of cubic meters. The favorable gas bearing area of Taiyuan Formation limestone gas reservoir is 1.5×10 ⁴km ², with preliminary estimated resources of 1.6×10 ¹²m ³, and a reserve scale of 5 000×10 ⁸m ³. The exploration area of Taiyuan Formation bauxite is 7 000 km ², with natural gas resources exceeding 5 000×10 ⁸m ³. The favorable exploration area for presalt natural gas in the Member 4 of Ordovician Majiagou Formation is 2.5×10 ⁴km ², with an estimated reserve exceeding 7 000×10 ⁸m ³. The favorable gas-bearing area of Wulalik Formation marine shale is 9 000 km ²; the natural gas resources are estimated to be 1×10 ¹²m ³, and two gas abundance zones have been identified. Two favorable areas of natural gas in the deep Proterozoic are optimized, with an exploration area of 5.71×10 ⁴km ². The natural gas resources in Ordos Basin still have large exploration potential.

Junggar Basin is rich in oil-gas resources. There are three sets of major source rocks of Carboniferous System, Permian System and Jurassic System. There are diverse types of reservoirs, including volcanic rock, conglomerate, sandstone and carbonate-type mixed rock. Among them, conglomerates distributed at the edges and slopes of hydrocarbon-rich sags in the basin are the main body for increasing reserves. There are three sets of regional mudstone cap rocks distributed in the basin, which are vertically stacked with the reservoir, thus dividing the basin into a three-decker structure and forming three major petroleum systems, i.e., the Carboniferous, Permian and Jurassic petroleum system. In recent years, through innovating geological understandings, highlighting risk exploration, strengthening intensive exploration and fine exploration, and exploring the sag center and source rocks, Junggar Basin has achieved substantial achievements in the exploration of deep and ultra-deep fields. Particularly, focusing on "new areas, new fields, new strata and new types", based on previous research work, a deep analysis is performed on accumulation conditions for petroleum systems, and efforts are made to innovate the understandings of hydrocarbon accumulation, involving "whole petroleum system", "coalbed methane from other source rocks", "Carboniferous self-generation and self-reservoir and new generating hydrocarbon in paleo-reservoir". Therefore, four important new breakthroughs have been made as below:natural gas of lower assemble in the southern margin thrust belt, whole petroleum system in Fengcheng Formation in the western depression, paleo-uplift around the hydrocarbon-rich sag, and Jurassic coalbed methane in the basin. Future exploration directions and key areas are pointed out by systematically summarizing recent exploration achievements, and comprehensively analyzing the characteristics of the field. It has been clarified that the basin should adhere to the comprehensive exploration idea of "equal emphasis on both conventional and unconventional resources, collaborative development of oil and gas, and whole petroleum system" in the future, focusing on the further exploration of natural gas of the southern middle-lower assemblage, deep/ultra-deep conventional structural trap and unconventional light hydrocarbons in the western depression, and Jurassic coalbed methane.

Jizhong depression is rich in oil-gas resources. After more than 40 years of exploration and development, it has been the main oil-gas production base and a crucial area for increasing reserves and production in Huabei oilfield. In recent years, multiple important breakthroughs have been made in new fields and new types of hydrocarbon exploration, showing good exploration prospects. However, it still faces problems such as unclear understanding of hydrocarbon accumulation conditions, as well as undetermined replacement areas and plays. Based on systematically analyzing the hydrocarbon accumulation conditions and their controlling factors in Jizhong depression, the paper summarizes the oil-gas enrichment regularities, recognizes the hydrocarbon accumulation characteristics and exploration potentials of the depression, and further points out the prospects and directions for new fields and new types of future exploration in the depression. Comprehensive assessment indicates that Jizhong depression has developed the Paleogene and Carboniferous-Permian source beds, forming two main reservoirs including marine carbonate rocks and Paleogene clastic rocks. Moreover, it has four types of hydrocarbon plays, i.e., new-generation and paleo-reservoir, self-generation and self-reservoir, lower generation and upper reservoir, paleo-generation and paleo-reservoir, constituting four types of composite hydrocarbon accumulation belts dominated by paleo-buried hills, i.e., central uplift, steep slope, slope, and trough, for which the proved rates of oil-gas resources are 45.7% and 11.0% respectively, and where the remaining hydrocarbon resources are abundant. The holistic research suggests that the five major fields of deep buried-hills and their inners, deep Paleogene layers, shale oil, deep coalbed methane, and new sags generally have good accumulation conditions, great resource potentials, and broad exploration prospects. Thirteen favorable targets, as favorable plays for natural gas exploration in Jizhong depression, have been implemented in the buried-hills and inners, such as Hexiwu buried-hill of Langgu sag, Wuqing sag, and Wen'an slope in northern Jizhong depression, with the predicted natural gas resources of 1 453×10 ⁸m ³. Twelve favorable structures, as the main plays for the exploration of deep Paleogene layers in Jizhong depression, are developed in the Liuchu-Huangfucun area of Raoyang sag, Wuqing anticline belt of Wuqing sag, Yuke-Shennan anticline belt of Shenxian sag, inner belt of Wen'an slope, Langgu sag, and steep slope of Jinxian sag, with the predicted oil resources of 2.4×10 ⁸t. The predicted trap resources of 2.3×10 ⁸t in two favorable tectonic belts in Baoding sag and the remaining natural gas resources of 836×10 ⁸m ³ in Wuqing sag demonstrate that they are realistic areas achieving exploration breakthroughs in new wellblocks of sags. The available shale oil resources in the lower submember of Member 3 of Shahejie Formation in Shulu sag and the lower submember of Member 1 of Shahejie Formation in Raoyang sag are estimated to be 9.1×10 ⁸t, and the total resources of the favorable exploration area for deep coalbed methane in the outer blet of Wen'an slope amount to 1.53×10 ¹²m ³, indicating the favorable exploration targets for strategic replacement in unconventional fields in Jizhong depression.

Hailar Basin is a Mesozoic-Cenozoic continental rift basin located on the northern border of China. After more than 60 years of continuous exploration, the main oil-bearing series has entered the mid-late stage of development. Shallow buried, large-scale, and easily-discovered structural reservoirs have been almost completely drilled and explored, it is more and more difficult to increase reserves in recent years. Through systematically reviewing the oil-gas exploration history in Hailar Basin, in combination with current exploration and development practices, it is pointed out that to exploit the less explored subsag areas and deep strata is essential to open a new situation for oil-gas exploration in Hailar Basin. The basin has great exploration potentials in four fields:shale oil in the condensed section of Nantun Formation, glutenite lithologic reservoir in Tongbomiao Formation, oil reservoir in Jurassic Tamulangou Formation, and interior reservoir in bedrocks of buried hills, of which the total oil resources are predicted to be 5.96×10 ⁸ t. The oil reservoirs in new fields and the discovered reservoirs have spatial complementarity, thus forming the petroleum system in complex rift basins that involves multiple types and multiple strata from middle-shallow to deep formations, from slope belts to subsag areas, and from conventional to unconventional fields, and displays ordered distribution and differential enrichment of oil reservoirs, and its exploration potentials can be further explored.

Over the past 30 years, significant progress has been made in the oil-gas exploration and development of Jurassic low-pressure sandstone reservoirs, Permian tuff reservoirs, and Carboniferous volcanic weathering crust reservoirs in Santanghu Basin, with the proved geological reserves of 168 ×10 ⁸t and a production capacity of crude oil of 56×10 ⁴t/a. The remaining oil-gas resources in Santanghu Basin have great potentials, but the proved unused reserves are insufficient. It is necessary to expand new fields and implement new types of oil-gas exploration and development, so as to achieve new discoveries and breakthroughs, and support stable and sustainable oil-gas production. Based on the understandings from the recent research on basin structure, source rock distribution, reservoir characteristics, as well as coal rock experiment, four new fields are proposed, i.e., southern thrust belt, shale oil in subsag areas, megaclast reservoirs at the near-source margin, and interior reservoirs in Carboniferous volcanics, with the petroleum geological resources of 0.86×10 ⁸t, 2.45×10 ⁸t, 0.69×10 ⁸t and 0.96×10 ⁸t, respectively. Also, two new types are proposed, i.e., coalbed methane in Jurassic Xishanyao Formation and tar-rich coal in Badaowan Formation, with the coalbed methane resources of 1 427×10 ⁸m ³ and tar resources of 60.1×10 ⁸t, respectively. There is great resource potentials and broad prospects for exploration and development. Based on the hydrocarbon exploration degrees, geological conditions, and development technologies, deployments and arrangements were made at three levels, i.e., strategic deployment, strategic breakthrough, and strategic preparation.

With the increase of resource exploration rate in Jianghan Basin, the difficulty in exploring conventional sandstone reservoirs is continuously enlarged. In recent years, by strengthening basic research and changing exploration ideas, the exploration breakthrough of carbonate reservoir and the effective promotion of shale oil field have been achieved. According to the exploration practice, in combination with the analysis and experiment data of drilling, testing, logging and cores, comprehensive geological research and favorable area evaluation were carried out in the study area. The research reveals the spatial distribution characteristics of lithological and lithofacies, sedimentary patterns, reservoir space types, oil-gas enrichment conditions, as well as accumulation mode. Moreover, it has been clarified that granular carbonate and mixed granular rock have good oil storage capacity, which are new types of oil reservoir for conventional exploration and development, and also the actual field for increasing reservoir and production, with a total resource of 3.7×10 ⁸t. The facies assemblage of shale mixed with micrite (dolomite) has good oil generation ability, mainly distributed in the second oil group of lower Member of Xingouzui Formation. It is expected to achieve a breakthrough in the exploration of new field of shale oil, and the resource amount is predicted to be 3.62×10 ⁸t.

Yin'gen-Ejinaqi Basin is a large sedimentary basin with a relatively low degree of oil-gas exploration in China. The exploration practice since the 13th Five-Year Plan(2016-2020) has confirmed that the Cretaceous Baiyingebi Formation is the main source rock series, and three assemblages develops in Carboniferous-Permian, Jurassic, and Cretaceous reservoirs, forming various types of oil-gas pools such as lithological and structural-lithological reservoirs, bedrock buried-hill reservoirs, and unconventional reservoirs. However, the development characteristics of source rocks, main controlling factors of hydrocarbon accumulation, and resource potentials of various sags vary due to the differences of late tectonic movements in Yin'gen-Ejinaqi Basin, thus affecting the overall cost-effective development of the basin. Based on recent exploration practices and understandings, as well as analyses of the basic accumulation conditions, this paper conducted a new round of evaluation on the resource potentials of Yin'gen-Ejinaqi Basin. The results indicate that there is great resource potentials of the Cretaceous lithological and structural reservoirs in Chagan sag, Guaizihu sag, Hari sag, and Tiancao sag, which are the main areas for oil-gas exploration and development. The Carboniferous-Permian buried-hill cave-fractured reservoirs in bed rocks in Lujing sag, Guaizihu sag, and Jigeda sag can provide favorable conditions for high production and hydrocarbon enrichment and are new types of resources for cost-effective exploration. The Cretaceous shale oil and reservoirs in Chagan sag, Guaizihu sag, and Hari sag and the Jurassic lithological reservoirs from the coal-bearing source rocks in Aoxinan sag have certain exploration potential and are new fields for further exploration. In Yin'gen-Ejinaqi Basin, the conventional oil resources amount to 14.39×10 ⁸t, the conventional gas resources amount to 451.17×10 ⁸m ³, and the unconventional shale oil resources amount to about 5.6×10 ⁸t, showing excellent exploration prospects.

Since more than 60 year exploration and development, the Bohai oilfield has now been a super large offshore oilfield in China. This paper reviews the exploration progresses of Bohai oilfield since the 13th Five Year Plan (2016-2020), and clearly points out the key exploration fields and research directions in future based on the analysis of regional accumulation conditions. The Bohai Sea area mainly develops three sets of main source strata, i.e., Member 3 of Shahejie Formation, Member 1 of Shahejie Formation, and Member 3 of Dongying Formation. Vertically, the Cenozoic clastic reservoirs and buried-hill fractured reservoirs constitute the main productive series. Based on recognition of the special geological conditions of Bohai Sea, such as "intense Mesozoic destruction, rapid Paleogene transformation, and thick Neogene sedimentation", the paper establishes and developes multiple new petroleum geological understandings of the three major exploration fields in Bohai oilfield, including "complex metamorphic buried-hills", "Paleogene structure-lithology", and "large-scale Neogene lithology", which has achieved significant discoveries of five oilfields of 100 million tons in five years. Through the systematic analysis of source rocks, reservoir cap association, and other regional accumulation conditions in the basin, it is specified that the main potential areas for future conventional exploration fields are the buried-hill field including Liaonan belt, Liaobei belt and circum-Bozhong sag, the Palaeogene field including Liaozhong-Liaoxibei subsag belt, Shinan steep-slope belt, Bozhong southwest area and north steep-slope belt of Huanghekou sag, and the shallow Neogene field in circum-Bozhong sag. For unconventional oil-gas field, shale oil in Laizhouwan sag should be prioritized. The crude oil and natural gas in the above-mentioned conventional hydrocarbon traps are approximately estimated to be 8.7×10 ⁸t, and 1.9×10 ¹²m ³, respectively; the unconventional shale oil resource amounts to nearly 8.6×10 ⁸t in Laizhouwan sag. It is pointed out that the future oil-gas exploration in Bohai Sea needs to realize four shifts, i.e., the shift of buried hill exploration from traditional buried-hills to hidden buried-hills, the shift of Paleogene exploration from medium-deep to deep and ultra-deep strata, the shift of shallow lithology exploration from salients and slopes to sags, and the shift of exploration fields from conventional to both conventional and unconventional oil-gas. The research results can contribute to the advancement of oil-gas geological theory and technology in complex continental downfaulted basins, providing theoretical understanding and support for the stable and sustainable development of Bohai oilfield.

Pearl River Mouth Basin has still been in the stage of medium- and low-degree oil and gas exploration. In recent years, more efforts have been put on the research and evaluation of new fields in the basin and achieved a series of exploration results. We have realized new discoveries from multiple fields and types of exploration in hydrocarbon-rich depressions, i.e., the Paleogene of Wenchang A depression, Lufeng depression, Huizhou depression and Panyu 4 depression, the paleo-buried hill in Huizhou depression, as well as new depressions including Yangjiang East depression, and Kaiping depression. This has achieved large-scale reserves, thus reinforcing the reserve base for the stable development of oil fields in the east and west of South China Sea. It is clarified that the large-scale pressurization fault transitional slope zone in a fault basin indicates the main direction of exploration for large- and medium-sized oil and gas fields, thus changing the fact that no large scale reserves had been discovered in Wenchang A depression for many years. We innovatively proposed an understanding of hydrocarbon accumulation, i.e., "early fault transportation, small-scale source sink system and transformation zone controlling sand, and accumulations controlled by uplifts between depressions", guiding the discovery of the Paleogene high-yield oilfield group in the southern Lufeng sag. The establishment of exploration techniques for the fan delta-braided river delta sedimentary system has promoted the discovery of oilfield group on 10 ⁸t scale in the Palaeogene steep slope in the southwestern Huizhou depression. Deepening the research on reservoir-seal combination and petroleum entrapment in sand-rich series can contribute to the exploration and discovery of large- and medium-sized oil and gas fields in the new series of strata in Enping Formation of Panyu 4 depression. Innovatively establishing a model of diagenesis-mountain formation-reservoir formation-hydrocarbon accumulation for magmatic arcs in Mesozoic continental margins has guided the southwestern Huizhou depression to achieve a large-scale commercial breakthrough in the paleo-buried hills. The significant discovery of the oilfields group in East Yangjiang sag-North Enping sag is promoted by innovating the new mechanism of strong extension and weak strike slip controlling basin and hydrocarbons. Moreover, the innovative proposal of basin formation mechanism in the mode of "detachment-metamorphic core complex" is expected to form an oilfield group on a billion ton scale in the southern Kaiping belt. We have gradually developed new exploration fields such as Paleogene strata, buried hills, and new depressions and multiple technology series in Pearl River Mouth Basin, providing a solid technical support for the continuous increase of reserves and production in the eastern and western oilfields of South China Sea and opening up new prospects for new fields and new types of exploration. The resource evaluation results show that the remaining resources of the Paleogene system in hydrocarbon -rich depressions and buried hills in Pearl River Mouth Basin are mainly distributed in Huizhou 26 depression, Wenchang A depression, and etc. The crude oil resources are most abundant in the periphery of the Yangjiang-Yitong'ansha fault zone and the new depressions around Huizhou-Lufeng area.

As an important crude oil exploration and production area in the western South China Sea, Beibuwan Basin has the advantages of oil enrichment in multiple sags, hydrocarbon accumulation in multiple strata and multiple models. In recent years, breakthroughs have been made in new fields and new types of oil-gas exploration involving shale oil, buried hills, lithologic reservoir, deep hydrocarbon resources, and backup sags/subsags. The paper investigates the regional petroleum geological conditions, so as to make clear the regional hydrocarbon accumulation regularities of the important hydrocarbon-generating sags in Beibuwan Basin, and guide the subsequent fine exploration and development of conventional oil-gas and the new fields and new types of hydrocarbon exploration. The research shows that the multi-stage tectonic movement controlled the tectonic evolution and material filling in Beibuwan Basin. The oil shale and semi-deep lacustrine mudstone of Member 2 of the Paleogene Eocene Liushagang Formation are the most important source rocks in the basin, several sets of source rocks are developed in Member 1 and 3 of Liushagang Formation and Member 2 of Weizhou Formation, and buried-hill reservoir and clastic rock reservoir are also developed, thus forming a multi-source, multi-reservoir and multi-cap pattern. The hydrocarbon accumulation in multiple sags of Beibuwan Basin is controlled by multiple mechanisms, such as near-source primary hydrocarbon accumulation in sag, vertical accumulation in fault belt, fault-uplift belt and steep slope belt, bypass accumulation in slope area, as well as converged accumulation pattern in salient and uplift. Oil and gas are orderly distributed in multi-sags and multi-zones. The oil-gas differential accumulation controls the distribution of internal gas and external oil, deep gas and shallow oil. Moreover, there is a significant difference in the types of oil-gas reservoirs in different zones. Under the guidance of regional petroleum geological conditions and accumulation regularities, the comprehensive analysis of resource potentials, accumulation conditions and exploration and development degree indicate that shale oil, buried-hill, lithologic trap, deep hydrocarbon resources and backup sags/subsags are important new types and new fields for future exploration and development in Beibuwan Basin.

In China, Qiongdongnan Basin is the only place where large coal type gas fields have been discovered in shallow water, deep water, and ultra-deep water areas. Therefore, it is of important theoretical and practical significance to explore the geological characteristics of natural gas and new exploration fields in the basin. Based on regional geological, seismic, drilling, and geochemical testing, the paper analyzes the accumulation characteristics and exploration potentials of Qiongdongnan Basin. The results indicate that a tectonic framework of "two uplifts and two subbasins" was formed during the deposition period of Yacheng Formation in Qiongdongnan Basin. The coal-type source rocks (including coal-measure source rocks and terrestrial marine source rocks) of Yacheng Formation are the major source rocks, and the source kitchen of coal-type source rocks in the (fan) delta of the Oligocene Yacheng Formation mainly shows a bead-like distribution along the northern margin of the northern depression, the southern and northern margins of the central depression belt. The maturity of coal-type source rocks in the northern margin of the northern depression is low and has not come up to the main gas generation stage. The coal-type source rocks at the southern and northern margins of the central depression belt are mature and have entered the main gas generation stage. Coal-measure source rocks and the surrounding terrestrial marine mudstones developed in each (fan) delta are one source kitchen. As controlled by the source kitchen of the Oligocene coal-type source rocks, two large gas accumulation belts were formed at the southern and northern margins of the central depression belt. The main exploration areas for coal-type natural gas include uplifts, step-fault belts, gentle slope belts, and turbidite bodies inside sags in the gas accumulation belt, showing great exploration prospects, and the natural gas resources are expected to exceed 2×10 ¹²m ³.

Marine shale is the main sweet spot of marine shale gas reservoirs in China. The marine shale gas features complex accumulation mechanism, worse physical properties, and diverse fluid occurrence forms. The quality evaluation on marine shale gas reservoirs is important for sweet spot optimization in shale gas exploration and development, and reservoir quality is mainly evaluated by geophysical logging. This paper summarizes the geological characteristics of marine shale gas and the current problems on hydrocarbon exploration and development, introduces the pore-, core- and logging-scale petrophysical analysis technology, and also the prediction techniques of the above key parameters according to the key geological quality parameters of gas shale such as organic matter, reservoir property and gas bearing property, and the key engineering quality parameters such as brittleness index, stress difference and fracture toughness, establishes the comprehensive logging evaluation system for shale gas reservoir quality classification, i.e., sweet spot optimization, and demonstrates the technology application effect and applicability by actual examples. Finally, it points out the existing problems, and puts forward new ideas and future development trends.

Shale gas is a clean and efficient unconventional natural gas resource. In the past decade, In the past 10 years, China has made breakthroughs in Marine shale gas exploration, which has played an important role in ensuring national energy security, and China has become the second largest shale gas producer in the world. Compared with foreign countries, China's marine shale gas resources are widely distributed in Sichuan and Chongqing mountainous areas, and seismic exploration techniques have achieved rapid development under the incentives of both poor natural conditions and urgent resource demand. This paper focuses on the technical challenges of marine shale gas seismic exploration under complex conditions of mountainous and subsurface structure in China, investigates and analyzes the current status of marine shale gas seismic exploration techniques, and clarifies the goal of technological development to improve the drilling rate of horizontal wells through efficient and economic acquisition, high-precision seismic imaging, and shale gas reservoir interpretation. The paper systematically summarizes the key technologies for marine shale gas seismic exploration in China, mainly introduces the key technologies attracting much attention from the industry, such as node acquisition, anisotropic depth migration, rapid imaging while drilling, and geomechanical parameter prediction, and further analyzes their application effects. Finally, the main problems and development directions faced by China's marine shale gas seismic exploration technology are proposed. It is required to accelerate the research and development of high-end independent seismic acquisition and processing technology considering complex geological conditions in China, build a solid petrophysical foundation, deepen the integration of geology and engineering, improve the popularization and application of artificial intelligence technology in the field of shale gas geophysics, and promote the efficient utilization of deep and ambient pressure shale gas resources.

It is the foreland basin that has the most abundant oil and gas resources in the whole world, and the foreland thrust belt located on its active limb has become an important replacement area for achieving exploration breakthroughs and increasing reserves. In China, the development of seismic exploration techniques for oil and gas in the foreland thrust belts has gone through four stages of conventional 2D, large wide-line combination 2D, conventional 3D, and wide azimuth high-density 3D seismic technologies. The key techniques of seismic exploration for oil and gas in the foreland thrust belt of China are expounded from three aspects, i.e., the seismic acquisition, optimization and design technology for prestack depth migration imaging, seismic data processing technology and seismic data interpretation technology for complex tectonic zones. The paper introduces the main exploration achievements in the Kuche subbasin in Tarim Basin and the southern edge of Junggar Basin, which are of great significance for promoting the formation and application of key supporting techniques in the foreland thrust belt. For the challenges faced in the exploration of foreland thrust belts, such as complex surface and subsurface geological conditions (dual complexity), severe tectonic deformation, and poor seismic data quality, it is still necessary to explore and develop in the directions of artificial intelligence and geophysical exploration technology, deep to ultra deep layers, stratigraphic-lithologic reservoirs and unconventional oil and gas reservoirs, comprehensive geophysical services, as well as interdisciplinary integrated collaborative work.

After more than 10 years of theoretical innovation and engineering practice in shale gas fracturing, supporting the scale cost-effective development of marine shale gas, China has established a theoretical and technical system for marine shale gas fracturing in the middle and shallow layers (< 3 500 m). The technically recoverable resources of deep (3 500-4 500 m) and ultra deep (> 4 500 m) shale gas in China account for 56.63% of the total recoverable shale gas reserve. To achieve efficient gas exploitation is essential for the development of the shale gas industry and guarantee of oil and gas security. The recoverable resources of deep (3 500-4 500 m) and ultra deep (> 4 500 m) shale gas in Sichuan Basin and its periphery account for 65.8% of the total reserve, making the most important contribution to the efficient development of shale gas and the construction of "Daqing Gas Base". Based on the preliminary exploration and practical understanding of deep and ultra deep shale gas fracturing in China and according to the 10 characteristics of deep and ultra deep shale gas fracturing, this paper analyzes six basic problems or challenges that are derived from above situation and urgently need to be solved. Further, the paper proposes five key theories and methods that urgently need to be innovated, points out 10 development directions for deep and ultra deep shale gas fracturing, and emphasizes that China's shale gas development should focus on both deep and shallow layers and continue to improve large-scale production and EOR in the middle and shallow layers. There are both opportunities and challenges in advancing into the new fields of exploration in deep and ultra deep layers to achieve efficient development. It is still necessary to continuously enhance the research, and accelerate the establishment of China's fracturing theory and technology system for deep and ultra deep shale gas.

Deep and ultra-deep oil and gas are important replacement resources for increasing reserve and production in China. Therefore, to achieve safe and fast drilling and completion of deep and ultra-deep wells is of great significance for the efficient development of deep and ultra-deep oil and gas resources. By reviewing the development history of deep and ultra-deep wells in China, the paper summarizes and compares the current development status, advance and application of key technologies for deep and ultra-deep well drilling and completion, and further points out the development direction based on the current main problems. Moreover, a comparison has been made on key drilling equipment for well drilling and completion in deep and ultra-deep wells, wellbore structure optimization and expansion, drilling speeding-up, drilling fluid, cementing, downhole measurement and control technology, and key technical performance indicators of oil testing and completion technology and its application status in China and other countries. Then it is pointed out that technical gaps mainly occur as the result of resistance to high temperature and pressure, as well as high stability. Further, an analysis is performed on the latest progress and application of high-end equipment, cutting-edge tools and core additives, including the automatic drilling rigs for deep drilling that can support China to achieve the normalization of 8 000-meter ultra-deep drilling on land, with the drilling capacity of 9 000 meters and drilling depth range extending towards 10 000 meters, wellbore structure optimization, controlled pressure drilling (MPD), efficient PDC bits, high-temperature resistant and ultra-high density oil-based drilling fluids, efficient plugging, high strength and toughness cement slurry, automatic cementing, high temperature resistant acid fracturing, coiled tubing equipment for deep and ultra-deep operation. In view of ultra-high temperature, ultra-high pressure, complex geo-stress and multi pressure systems in ultra-deep layer which pose a great challenge to safe and efficient drilling and completion, the paper proposes that the further research should focus on optimization and expansion of wellbore structure, high temperature and high pressure resistant downhole tools and instruments, ultra-high temperature resistant downhole fluids, efficient rock-breaking and speed-up tools for ultra-deep drilling, ultra-high temperature and pressure resistant testing and completion tools, ultra-high temperature resistant and low damage acid fracturing fluid, digital intelligent drilling and completion equipment and technology, so as to accelerate the breakthrough and iterative upgrade in key technologies and equipment, support and safeguard the efficient exploration and development of deep and ultra deep oil and gas resources.

CO ₂ capture, oil-flooding and storage (CCUS-EOR project) can achieve carbon sequestration while improving oil recovery, which is of great significance for ensuring national energy security and achieving the "dual carbon" goals. By reviewing the foreign and domestic development history of CCUS-EOR project, the paper systematically elaborates the technological progress and engineering practice status in terms of CO ₂ capture, oil-flooding and storage, and points out the next development direction of CCUS-EOR project. For CO ₂ capture technology, this paper analyzes the principles, technical characteristics, and application scenarios of pre-combustion, post-combustion, oxygen-rich combustion, and other new carbon capture technologies, and points out that high capture costs and insufficient technological innovation are the main issues restricting the commercialization process of CO ₂ capture technology. Moreover, an in-depth analysis is performed on the technological development trend of CO ₂ oil-flooding and storage from immiscible flooding, miscible flooding to high-pressure miscible flooding in China. The development concept of CO ₂ high-pressure miscible flooding and storage in terrestrial sedimentary reservoirs has been innovatively developed with a focus on improving the phase mixing of crude oil and expanding sweep efficiency, thus forming the reservoir engineering design technology for CO ₂ oil-flooding and storage, which involves well pattern and spacing optimization, water-gas alternation, injection-production coupling, and chemical sealing. Additionally, relevant supporting technologies such as long-distance pipeline transportation, efficient injection and safety monitoring are also formed. In response to the challenges and major technical demands faced during CCUS-EOR project development in China, it is proposed to vigorously develop efficient and low-energy CO ₂ capture technologies for low concentration gas sources, key supporting technologies for collaborative optimization of CO ₂ oil-flooding and storage, as well as optimization technologies for matching CO ₂ emission sources with sources and sinks in petroliferous basin, and provide breakthrough direction for the construction of a CCUS full chain industrial cluster system, thus providing support for achieving the large-scale commercial application of CCUS-EOR project.

In 2021, a great breakthrough has been made in discovery of crude oil in the risk exploration well, i.e., Well Gulashou-1, in deep water area of Santos Basin in South America; a daily production of thousands of tons of high-yield oil flows was obtained in the drill stem testing, thus determining a super large oil reservoir in the Alam block in Brazil and confirming its potential for large-scale commercial development. To better understand this major breakthrough, the tectonic-sedimentary environment, accumulation conditions and reservoir characteristics of Well Gulashao-1 were analyzed in detail based on the analysis of regional geological background, in combination with the exploration history. The results show as follows. (1) Alam block is located in the Alam-Uirapuru uplift belt of Santos Basin, facing with Lula oilfield in the Lula-Sugar uplift belt across a lake, and the both has a similar tectonic-sedimentary background. The large paleo-uplift in the center of the basin provides favorable conditions for carbonate sedimentation. (2) Alam block is adjacent to the main hydrocarbon generating sag with abundant oil sources. (3) The inherited paleo-uplift controls the contiguous distribution of lacustrine carbonate reservoirs. (4) Salt rocks, post-salt calcilutites and mudstones have formed multiple effective seals on the oil reservoir. (5) The pre-salt anticlinal trap is developed on a large scale, demonstrating a favorable migration direction of oil and gas. (6) The pool in Well Gulashao-1 is an overpressure reservoir, which produces medium crude oil with low CO ₂ and H ₂S contents. The successful drilling of Well Gulashao-1 is a major breakthrough of oil exploration expanding from the pre-salt core area to the periphery in Santos Basin of Brazil. It is a major success achieved by PetroChina Company Limited (PetroChina) in adhering to overseas risk exploration and also a successful practice of overseas cooperation for deepwater oil and gas exploration in PetroChina. It is of guiding significance to the pre-salt oil and gas exploration in Santos Basin of Brazil and the development strategy of deepwater oil and gas business in PetroChina.

A number of wells in Qiudong subsag of Taibei sag of Tuha Basin have obtained high-yield oil and gas flow in Sangonghe Formation of the Middle-Lower Jurassic Shuixigou Group, showing a good hydrocarbon exploration prospect of the deep intra-source tight sandstone in the subsag area. To make clear the petroleum geological conditions of tight sandstone from Shuixigou Group in Qiudong subsag and comprehensively evaluate the exploration prospects of Shuixigou Group in Tuha Basin, based on the drilling knowledge obtained from new boreholes, this paper systematically summarizes the favorable accumulation conditions of Qiudong subsag, and points out the next exploration direction. (1)Qiudong subsag suffered from multiple tectonic movements and developed three tectonic zones, namely southern slope, central subsag, and northern slope. Among them, the central subsag was tectonically stable, which was conducive to hydrocarbon preservation in the multi-stage superimposed basin. (2)Shuixigou Group in Qiudong subsag developed two sets of coal-measure source rocks in Badaowan Formation and Xishanyao Formation respectively, as well as lacustrine argillaceous source rocks in Sangonghe Formation. The dominant kerogen types were Ⅱ ₂—Ⅲ and in mature evolution stage. (3)Shuixigou Group in Qiudong subsag developed bidirectional braided river delta sedimentary system to the south and north. The sand-bodies in the subsag area developed well and effective reservoirs developed even below 5 000 m under the control of such factors as favorable facies, dissolution, overpressure, and fractures. (4)By comprehensively analyzing the exploration potential of tight sandstone gas from Shuixigou Group in Taibei sag, it showed that the superposition of large coal-measure source rocks and braided river delta front sand-bodies were developed in all three subsags (Shengbei subsag, Qiudong subsag and Xiaocaohu subsag). Five main fan bodies, namely Pudong, Hongbei, Lingbei, Qiudong, and Gebei, can be selected from Sangonghe Formation with the favorable exploration area of 1 090 km ², evaluated natural gas resource of 5.29×10 ¹²m ³, and petroleum resource of 5.2×10 ⁸t. The great resource potential shows that the sag area in Tuha Basin has a good exploration prospect.

At present, it is considered that the accumulation of tight oil is characterized by source-reservoir integration or large-scale near-source distribution. However, the exploration practice indicates that the sweet spots near high-quality source rocks in continental tight oil areas in China generally contain no oil or even produce a large amount of water. Therefore, it is necessary to re-recognize the sweet spots where tight oil is enriched. Based on systematically summarizing the classification scheme and geneses of the existing source-reservoir interlayer, as well as a large amount of core observations, the source-reservoir interlayer is divided into three types, i.e., argillaceous interlayer, tight sandstone with argillaceous laminae, and sand-shale transition section, of which the physical properties, distribution and logging response characteristics are described separately. The study suggests that the tight oil accumulation is mainly driven by the expansive force generated as a result of the hydrocarbon generation pressurization of source rock. When the charging resistance is greater than the expansive force, it is not conducive to oil-gas accumulation. Quantitative characterization shows that the thickness, transverse continuity and fracture development of source-reservoir interlayer jointly control the charging resistance and affect the barrier capacity of source-reservoir interlayer. Based on this, four pool-controlling modes for tight oil enrichment in the source-reservoir interlayer are established as follows. (1)When the thickness of the source-reservoir interlayer is smaller than the effective barrier thickness, the oil and gas will break through the barrier and continue to migrate. (2)When the extension radius of the source-reservoir interlayer is smaller than the radius of the affected area, the oil and gas can break through from the edge area and form a radial oil-gas accumulation zone. (3)When the thickness of the source-reservoir interval is greater than the effective barrier thickness and the extension radius is greater than the radius of the affected area, oil and gas migration can be effectively blocked, resulting in the phenomenon of "sand without oil" in local areas. (4)When cracks are developed in the source-reservoir interlayer, the barrier capacity will be reduced, making it easier for oil and gas to break through. In conclusion, these research results and understandings are expected to improve the theoretical basis of continental tight oil in China and provide theoretical guidance for the exploration and development of continental tight oil in China.

Small and middle sized karst fractures and vugs in the Lower-Middle Ordovician epikarst zone in the main area of Tahe oilfield are important succeeded fields for oil-gas exploitation. It is vital to intelligently identify epikarst zones and determine the development laws of fractures and vugs. Through the integrated utilization of three-dimensional seismic data, imaging logging, conventional logging, core and thin section data, the artificial intelligence identification method for bottom interface of epikarst zone was established to describe the structural characteristics and patterns of epikarst fractures and vugs at different scales, the main controlling factors for the development of epikarst zones were explored, the geological model of epikarst fracture-vug development was summarized, and the favorable development sites for such reservoirs were pointed out. The results show as follows. (1)The self-similarity coefficient method and dynamic time sequence matching method can realize the intelligent identification of bottom interface in epikarst zone and overcome interference of subjective factors. (2)The epikarst zone in the main area of Tahe oilfield is 4.5 m to 62.5 m in thickness, with an average of 24.0 m. The epikarst zones of the main area demonstrate 5 different structural styles of karst fractures and vugs, dominated by high-angle solution expansion cracks, and caves and dissolution pores can be observed in partial areas. (3)Multi-attribute combination based on "Thin Likelihood attribute analysis+50 Hz frequency division+diffraction wave separation imaging" can effectively predict small and medium-sized fractures and vugs. (4)Different levels of karst paleogeomorphology, karst drainage system as well as faults and fractures jointly controlled the development of fractures and vugs in epikarst zone. The development models of epikarst fractures and vugs controlled by third-level karst landform and coupling gullies with faults and fractures were established separately. (5)The gentle slope and the core of karst residual hills in the karst plateau area are the most favorable for the development of epikarst fractures and vugs, followed by the gullies with developed faults and fractures in some areas. These zones have good development potential.

The light oil from Gulong shale is widely distributed, with favorable components and temperature-pressure conditions for miscibility with CO ₂. Pre-fracturing with CO ₂ injection and huff-and-puff can offer significant potential to enhance oil recovery. However, there is a lack of sufficient understanding of the high-pressure phase behavior of Gulong shale oil. Based on the equation of state and two-phase equilibrium theory, through verifying the results of constant mass expansion experiment and slim tube experiment for shale oil, the paper establishes a thermodynamic oil-CO ₂ two-phase equilibrium model considering the nano-confinement effect, and also a calculation method for the minimum miscibility pressure based on the two-phase equilibrium model. This paper is a case study of Gulong shale oils in Well Guye 2HC and Well Guye 9HC, and elucidates the interphase mass transfer behavior of Gulong shale oil and CO ₂, which is influenced by the factors such as maturity, oil/CO ₂ ratio, pressure, and nano-confinement effect. The results show that with an increase in CO ₂ mole fraction, the saturation pressure of Well Guye 2HC and Well Guye 9HC shale oils gradually decreases. Under reservoir temperature and pressure conditions, both Well Guye 2HC and Well Guye 9HC shale oils can be miscible with CO ₂. Under the same amount of CO ₂ injection, Well Guye 2HC shale oil exhibits a higher molecular weight and viscosity with a greater drop, and a lower saturation pressure and expansion coefficient with a smaller variation than Well Guye 9HC shale oil. The multilevel contact process of CO ₂ injection shows that the dissolution capacity and extraction effect of CO ₂ are similar in both Well Guye 2HC and Well Guye 9HC shale oils. After sufficient contact, C ₁-C ₆ components in the oil phase of Well Guye 2HC and Well Guye 9HC shale oils at the far end opposite to injection gas front are all extracted into the gas phase, and the mole fractions of CO ₂ in the oil phase increase to 86.63 % and 87.35 %, respectively. The presence of nano-confinement effect reduces the compositional differences between oil and gas inside nanopores, leading to a decrease in the interfacial tension and minimum miscibility pressure, which is beneficial to the mutual dissolution and miscibility between CO ₂ and shale oil. The impact of the nano-confinement effect on Well Guye 2HC and Well Guye 9HC shale oils is not significantly different. When the pore radius decreases from 100 nm to 10 nm, the minimum miscibility pressure of Well Guye 2HC and Well Guye 9HC shale oils with CO ₂ is decreased by 20.90 % and 21.31 %, respectively. Understanding the phase behavior of fluids in shale oil reservoirs can provide a theoretical guidance for the optimization of CO ₂ injection development.

The hydraulic fracturing assisted oil displacement (HFAD) technique, which is based on large-scale hydraulic fracturing, has been applied to the old oilfields with extra high water cut, achieving a remarkable effect of enhanced oil recovery (EOR). To further clarify the impact of HFAD technique on the oil displacement efficiency of HFAD agents, the paper investigates the adsorption loss of HFAD agents on the porous media surface under high pressure. Firstly, by carrying out dynamic adsorption experiments under ordinary pressure and high pressure conditions, changes in the dynamic adsorption capacity of HFAD agents on the core surface during HFAD process were compared and analyzed. In combination with conventional mercury injection experiment and scanning electron microscope (SEM)test, the mechanism of reduced absorption under high pressure was clarified. Then the impact of high-pressure reduced adsorption on enhanced oil recovery by HFAD technique was confirmed by the physical simulation experiment of reverse hydraulic fracturing-assisted oil displacement. Research shows that the dynamic adsorption capacity of HFAD agents on the core surface is decreased with the increase of the displacement pressure difference. When the displacement pressure differences are 0.5 MPa, 1.0 MPa and 1.5 MPa, the dynamic saturated adsorption capacity of HFAD agents on the core surface is decreased by 40.67 %, 62.17 % and 72.38 %, respectively, as compared with that under the displacement pressure difference of 0.1 MPa. At a high pressure, the core pore structure is changed, i.e., the average pore radius and seepage velocity are increased, fluid seepage resistance is decreased, and the dynamic saturated adsorption capacity of HFAD agents on core surface is reduced. Additionally, the oil displacement efficiency of HFAD agents can be improved by reduced absorption under high pressure, which is 1.96 times higher than that under ordinary pressure. In conclusion, high displacement pressure in the HFAD process can effectively reduce the dynamic adsorption capacity of HFAD agents in reservoirs, thus improving the oil displacement efficiency. The research results are of important guiding significance for further EOR in the field application stage of HFAD technique.

Aiming at the defect that professional gas hydrate reservoir numerical simulator fails to accurately characterize mass and heat transfer laws in the matrix and reservoir stimulation areas. By adding PEBI unstructured grid division module and mass and the heat transfer calculation module for matrix and reservoir stimulation area in Tough+Hydrate software, a breakthrough is made in the numerical simulation of depressurization exploitation of natural gas hydrate reservoir assisted by reservoir stimulation. Firstly, the matrix and reservoir stimulation areas are modeled respectively, and the mass and heat transfer laws between the matrix and reservoir stimulation areas are characterized based on discrete fracture theory, thus establishing the numerical simulation method for depressurization exploitation of natural gas hydrate reservoir assisted by reservoir stimulation. Then, taking the reservoir stimulation by hydraulic fracturing as an example, the paper investigates the variation law of productivity and physical field during depressurization exploitation of natural gas hydrate reservoir assisted by hydraulic fracturing during trial production in Shenhu sea area of the South China Sea, and analyzes the influencing factors of productivity. Research results show that hydraulic fracturing can greatly accelerate the output rate and depressurization rate for gas-water mobile phase, so as to make full use of the reservoir heat and pressure to promote hydrate dissociation in the hybrid layer and hydrate layer. Compared with the case of no fracturing, the peak gas production and long-term cumulative gas production can increase up to 198.7 % and 108.1 % after hydrofracturing, respectively. However, being subject to the large consumption of heat, the hydrate dissociation rate and gas production will decrease significantly in the later stage of depressurization exploitation, and a large amount of undissociated hydrates still remain in the hydrate layer after depressurization. Fracture conductivity, fracture number and half length will have a great impact on gas productivity. The higher gas productivity after depressurization exploitation is attributed to the stronger fracture conductivity, the larger amount of fractures, and the larger half length.

In view of the problem that existing polymer tackifiers have the defect of viscosity reduction at high temperature and cannot effectively regulate the high-temperature rheological properties of solid-free water-based drilling fluid, acrylamide (AM)/new thermo-sensitive monomer (MVC)/sodium 2-acrylamido-2-methylpropane sulfonate (NaAMPS)comb-type thermo-sensitive polymer (TSP-Comb)was prepared by free radical micellar polymerization. The molecular structure and weight-average molecular weight of TSP-Comb were characterized and measured by infrared spectroscopy, nuclear magnetic hydrogen spectroscopy and gel permeation chromatography. The thermal stability and microstructure of TSP-Comb molecular chain were measured by thermo gravimetric analysis (TGA)and environmental SEM, respectively. The temperature response characteristics of TSP-Comb was studied using rheometer and visible spectrophotometer, and the regulation effect of TSP-Comb on the high-temperature rheological properties of solid-free water-based drilling fluid was also studied. The results show that TSP-Comb solution has excellent high-temperature thickening property within the temperature range of 90 ℃ to 180 ℃ and higher phase transition temperature (higher than 60 ℃). Compared with linear thermo-sensitive polymers, TSP-Comb has been significantly improved in terms of high-temperature rheological stability and phase transition temperature. The high-temperature thickening property of TSP-Comb helps improve the high-temperature rheological properties of solid-free drilling fluid. The change rate of rheological parameters such as apparent viscosity, plastic viscosity and dynamic shear force of solid-free drilling fluid based on TSP-Comb was lower than 25 % within a wide temperature range of 90 ℃ to 180 ℃, and TSP-Comb has significantly improved the high-temperature rheological stability of solid-free drilling fluid, providing a new method for regulating the high-temperature rheological properties of solid-free water-based drilling fluid.

Since the discovery of Lucaogou Formation shale oil in Jimusar sag of Junggar Basin, it has third-level reserves of 4.3×10 ⁸t through ten years of exploration and development. In 2020, Jimusar sag became a national development demonstration zone of continental shale oil with an oil production of 60×10 ⁴t. A series of theoretical innovation and technological breakthroughs have been achieved in terms of geological theory of shale oil accumulation in Jimusar sag, supporting exploration and development technologies, and benefits management. The research results show as follows. Jimusar sag is a vast lake basin under the stable tectonic setting, where multi-component peperite with rich organic matters has been deposited, with the thickness of 275 m. The integrated distribution of thin source-reservoir interbeds plays an important role in the enrichment and preservation of shale oil. Due to high source-reservoir ratio (4.5:1), high organic matter abundance (3.24 %) and sedimentary environment of saline lake, the maturity of crude oil in the sag has been improved, and the vitrinite reflectance R _o is up to 1.05 %. Overpressure commonly exists in tsag with an average pressure coefficient of 1.36. The charging efficiency and oil enrichment degree are enhanced as a result of the source-reservoir pressure difference, indicating the formation of reservoirs with high oil saturation and high pressure coefficient. The current exploration and development technologies of shale oil in Jimusar sag are basically established. The geological understanding has been improved by the fine three-dimensional seismic technique of broadband excitation and combination of logging and seismic acquisition. The fine characterization of shale oil "sweet spots" and classified evaluation provide the bases for hydrocarbon development and deployment. The drilling ratio for "gold targets" can provide a basis for high and stable production of horizontal wells. The complex fracture networks are effective means for the efficient development of shale oil. The reasonable drainage and production system is beneficial to fully expand the production capacity of horizontal wells. The market-based cost reduction is key to the benefit development of shale oil in Jimusar sag. The technology, management and benefit of shale oil in Jimusar sag lead the way in China, and provide references and demonstration for the efficient exploration and development of continental shale oil in China.

It is traditionally considered that shale gas reservoirs do not contain or contain little hydrogen sulfide (H ₂S). However, low to extra-high content of H ₂S has been detected in 9 shale gas reservoirs in the ten years of exploration and development practice, and high to extra-high content of H ₂S are often found in calcareous shale gas reservoirs. According to the sequential order of H ₂S formation time, "natural geological process" and "anthropogenic cause" are regarded as two major causes for the occurrence of H ₂S in shale play. The former focuses on demonstrating the residue or migration of primary H ₂S in gas reservoirs as a result of the natural geological processes, while the latter emphasizes that the introduction of microorganisms and chemical substances by field operations (such as drilling, hydraulic fracturing) can result in the formation and emergence of secondary H ₂S after multiple processes under the complex downhole conditions. The proposal of "anthropogenic cause" has shed new light on the occurrence of H ₂S in shale gas reservoirs, but has not received much attention till now. Meanwhile, the mutually exclusive and complementary relationships between "natural geological process" and "anthropogenic cause" have not yet been clarified. Furthermore, the research of evaluating the primary supply capacity of H ₂S in shale gas reservoirs shall be carried out in the future. Meanwhile, it is required to deeply explore and establish the genesis identification criteria and output prediction system of epigenetic H ₂S based on field production data, so as to deepen the understanding of the genetic mechanism of H ₂S in shale gas reservoirs, thus providing a theoretical support for subsequent exploration and development of shale gas.

Since establishing the Da’an circulation block in western Chongqing in June 2021, Zhejiang oilfield has been making every effort to increase and accelerate the exploration and evaluation of deep shale gas, as well as implementation work, and constantly deepen geological understanding and improve engineering technology. Thus, industrial breakthroughs have been achieved in the production tests of multiple wells, and the Da’an deep shale gas field was discovered in western Chongqing. Through systematically introducing the exploration and discovery process of the Da’an block in western Chongqing in the past two years, the paper comprehensively analyzes the geological accumulation conditions in terms of regional geological characteristics, sedimentary lithofacies, organic geochemistry, pores and fractures, physical properties, gas-bearing properties, fracture characteristics, geological and mechanical properties of rock, as well as high-quality reservoir distribution characteristics, and also summarizes the key techniques for the exploration and development of deep shale gas in Da’an block, which have been formed through practice and innovation. Da’an block was the depocenter of the Upper Yangtze foreland basin at the northern foot of the Jiangnan-Xuefeng Caledonian orogenic belt during the sedimentary period of the submember 1 of Member 1 of Wufeng-Longmaxi formations. The high-quality shale layer in the lower section was of deep-water shelf facies, and the strong reduction and anaerobic environment provided good source and reservoir conditions. As a result, the organic carbon-rich siliceous shale was developed; this block possesses excellent organic geochemical indicators, well-developed micro-reservoir space, good physical properties, good self-sealing property of shale, and high gas-bearing properties, indicating an overpressure continuous shale gas reservoir with over-matured dry gas. Based on the good conditions of shale roof and floor and the deformation of comb-shaped fold structure, an enrichment and accumulation model has been built for the deep shale gas (burial depth of 3 500-4 500 m) in western Chongqing based on the characteristics of "narrow steep anticlinal faults as the barrier bed and contiguous widely-distributed gentle synclines, hydrocarbon enrichment and high production in tectonic transition belt and low-amplitude anticline structure", reflecting the theoretical connotation of enrichment, accumulation and occurrence of mountainous shale gas under the mode of "multi-field synergy, multi-element coupling, multi-factor superposition". Through practical exploration, five comprehensive evaluation methods and technologies have been developed for the exploration and development of deep shale gas in Da’an block, including the fine identification and stability evaluation technology of multi-scale natural fractures, the integrated evaluation and design technology for the full life cycle of well platforms, the matching technology of safe, excellent and fast drilling under high temperature, the segmented volume fracturing 2.0 technology for horizontal wells that focuses on increasing reserves and production under the control of dense crushed fractures while preventing casing deformation, and the fine pressure control and flowback technology for deep shale gas based on continuous monitoring of high-frequency pressure and dynamic evaluation optimization of artificial gas reservoirs. The exploration and discovery of Da’an deep shale gas field the western Chongqing has further promoted the rapid development of deep-ultra deep marine shale gas in China.

Early low-mature oil is formed by specific organic parent materials with low activation energy for hydrocarbon generation under low temperature and early mature conditions [vitrinite reflectance ( R _o)of 0.3 % to 0.6 % , geothermal temperature of 60 ℃ to 100 ℃]. It has higher maturity and better oil quality than immature oil, and is easy to form commercial oil reservoirs and natural industrial capacity. This type of oil was discovered early in China, but there is less understanding of its hydrocarbon generation mechanism and reservoir potential. In recent years, the Exploration and Development Research Institute of PetroChina Huabei Oilfield Company has been exploring early low-mature oil and obtained high-yield oil flows and large-scale cost-effective reserves in the middle-shallow strata of Dongying Formation of Baoding sag in Jizhong depression, thus achieving a breakthrough in traditional cognition. The research on the hydrocarbon generation mechanism, including the organic geochemical analysis of crude oil and source rocks, analysis of hydrocarbon inclusions in reservoirs, and thermal simulation experiments of hydrocarbon generation and expulsion in Baoding sag, reveals that under the environment of strong-reduced saline water bodies and high geothermal field, the bacteria and algae with low activation energy and soluble organic matter in the organic-rich strata of the lower submember of Member 1 of Shahejie Formation have generated large amounts of early low-mature oil by biochemical action and low-temperature thermocatalysis in the late diagenesis stage, with the oil rate of 190 mg/g and oil expulsion of 86 mg/g, respectively. They account for 46.4 % and 37.3 % of the oil generation and expulsion of kerogens in source rocks during the peak stage of oil generation ( R _o of 0.8 % to 1.3 % , geothermal temperature over 120 ℃), providing sufficient oil sources for the formation of early low-mature oil reservoirs. The early generated oil completed the migration and accumulation process from source to reservoir by fault networks and sand bodies, showing a regularity of near source enrichment.

The water produced from coalbed methane (CBM)wells contains rich information on geology and productivity, which can reveal the geochemical characteristics and main controlling factors of produced water and make clear the evolution path of produced water and its inherent link with production capacity, thus helping understand the heterogeneity of production capacity and provide a basis for the optimization of development programs. In recent years, significant breakthroughs have been made in the CBM exploration and development in Zhijin block of western Guizhou Province, providing a technical demonstration for the CBM development multiple thin coal seams in South China. However, there are still a number of problems, including great variability in produced water quality, high uncertainty in production capacity, and unclear control factors for gas production. In this study, hydrogeochemical tests were performed on the water produced from CBM in Zhijin block of western Guizhou Province, which aims to explore the hydrochemical characteristics, evolution path and its significance in judging productivity. The quality of the produced water can be divided into Na-HCO ₃ and Na-Cl types; the total dissolved solid (TDS)of the former ranges from 944 mg/L to 2 681 mg/L, and that of the latter ranges from 3 603 mg/L to 8 800 mg/L. According to the scale of TDS, the five clusters of samples show the successively increasing degree of groundwater retention. Desulphidation, cation exchange adsorption, and concentrating action are the main factors controlling the hydrochemical characteristics and evolution of produced water. The produced water is of Ca-SO ₄ type with low TDS (<200 mg/L)under oxidation conditions, Na-HCO ₃ type with medium TDS (900-3 000 mg/L)dominated by desulphidation and cation exchange adsorption under reduction conditions, and Na-Cl type with high TDS (3 500-9 000 mg/L)dominated by concentrating action under high retention rate. The evolution process of produced water can be divided into reduction stage and retention stage, and the produced water (TDS>3 000 mg/L)in the retention stage corresponds to high-yield wells. High-yield wells can be effectively identified by extracting key hydrochemical indicators and their critical values for identification of CBM production capacity, and analyzing the concentrations of characteristic ions such as Cl ^-, Na ⁺ and Sr ²⁺; the desulphidation coefficient γSO ₄ ^2-/γCl ^- can be used to effectively identify low-yield wells. The CBM wells in Zhijin block of western Guizhou Province should be located in groundwater retention areas with high TDS, high Cl ^- and low SO ₄ ^2-, instead of strong groundwater runoff zones. The axial part of Zhucang sub-syncline is a favorable area for deployment of CBM wells. Hydrodynamic interference and its resulted low pressure reduction efficiency are still the key factors restricting the multi-seam co-production capacity of vertical and directional wells. In conclusion, these findings can serve as a foundation for the efficient CBM development and produced water treatment in Zhijin block.

This study aims to quantitatively characterize the relative contribution of pore types to the micro-nano pore space of Paleozoic marine shale in Sichuan Basin. Based on petrological analysis, geochemical analysis, low-temperature nitrogen adsorption experiment and field emission scanning electron microscopy observation, comparison and analysis were performed on the pore types and structure of marine shale in different thermal evolution stages. Combined with the total organic carbon (TOC) content and mineral composition of shale, the geometric parameters of shale pores were extracted by means of image analysis based on machine learning, and then the pore surface area and pore volume of different types of pores in marine shale at different evolution stages were quantitatively calculated. The results show that with the increase of maturity, the average pore size of marine shale in Sichuan Basin is decreased, while the pore surface area, pore volume, surface fractal dimensions, and structure fractal dimension are increased. In the low-mature marine shale of the Upper Permian Dalong Formation, the mineral-related pores were the most developed, providing 70 % of pore surface area and 73 % of pore volume. The mature marine shale of the Silurian Longmaxi Formation was dominated by clay mineral pores, which provided 63 % of pore surface area and 58 % of pore volume. In the high-mature and over-mature shale of Longmaxi Formation, organic pores contributed to 68 % of pore surface area and 52 % of pore volume. The pore evolution of marine shale in Sichuan Basin is jointly influenced by diagenesis and hydrocarbon generation process. It is of important significance to clarify the dominant pore types of marine shale at different thermal evolution stages, thus providing theoretical guidance for the efficient development of shale oil and gas.

Fluorescent thin section is an important tool to study the properties, distribution characteristics and pore structure of crude oil in reservoirs. However, the data of fluorescent thin section is mainly processed by hand, so that the analysis efficiency is low and easily affected by human factors. This paper proposes an unsupervised automatic segmentation method based on convolution neural network(CNN). Firstly, fluorescent colors generated by different components under the excitation of ultraviolet light source were listed and used to establish fluorescent color chart and standard color system map, thus determining the division standard. Later, after extracting the advanced semantic features of fluorescent images by CNN, feature fusion was achieved through similarity and continuity constraints, and the space distance and angle of fluorescence spectrum was calculated to determine the similarity classification. Finally, the automatic division and quantitative analysis of particles, pores, oily asphalt, colloidal asphalt, and asphaltene in fluorescent images was completed. The experiment of fluorescence thin section images demonstrates that this approach does not rely on a substantial quantity of labeled samples and generally exhibits a low average error, thereby satisfying the practical production demands.

Midium-high mature continental shale oil is a major substituted field in oil and gas exploration and development, but facing some challenges such as multi-lithology interaction and low degree of longitudinal reformation. How to fully activate longitudinal production zone is the key to achieve volume fracturing and obtain high and stable production of shale oil. For this reason, a novel idea of cross-layer fracturing in radial wells was proposed, which aims to guide longitudinal multi-layer fracture initiation by penetrating the interlayer and lithologic interface through radial borehole, thus solving the problem of limited fracture height. In order to determine the feasibility of above idea, a true tri-axial cross-layer fracturing experiment was conducted. By means of CT scanning and 3D fracture reconstruction technology, the paper clarifies the characteristics of fracture initiation and penetration induced by radial well, and analyzes the influence law of vertical stress difference, displacement and radial well length on the fracture initiation and penetration. The results indicate that the radial well has the ability of guiding fracture propagation and promoting longitudinal fracture penetration, which can effectively reduce the difficulty of fracture penetration through layers and increase the longitudinal fracture propagation height. With the increase of vertical stress difference, the effect of fracture propagation induced by radial well is enhanced, and the fracture initiation changes from cross-layer cracking mode to simultaneous multi-layer cracking mode, crossing the lithology interface. The fracture is dominated by low-strength layers under low displacement, and increasing displacement is conducive to longitudinal fracture propagation across layers. With the increase of radial length, the wellbore has the enhanced ability of inducing fractures to cross the layer interface. The key findings are expected to provide solutions to the limitation of longitudinal fracture propagation height in continental shale oil reservoirs.

Flue gas, used as an additive, can enhance the efficiency of steam flooding for heavy oil. To investigate the enhanced oil recovery mechanism of flue gas in collaboration with different phases of steam, and promote the large-scale application of flue gas in oil fields, the influence of flue gas on steam/hot water oil displacement characteristics was systematically studied by regulating 1D experimental parameters. Later, 2D visualization experiments were conducted to explore the impact of flue gas on the expansion law of steam chamber and oil displacement and production performance, the effect of which was verified by the field experiment of flue gas-assisted steam huff and puff. The results show that flue gas can significantly improve the efficiency of steam flooding. When the steam is in a liquid state, the liquid phase of flue gas is transformed into gas and liquid phases, improving the microscopic sweep efficiency; as the temperature rises, the synergistic effect of flue gas becomes stronger. When the steam is in a vapor state, flue gas can improve the dryness of steam, and significantly increase the contact degree between steam and heavy oil, as well as the thermal utilization efficiency. However, as the temperature rises, the oil displacement effect achieved by flue gas diminishes. The advantageous region where flue gas plays a dominant role is at the vapor-liquid phase boundary, and the oil displacement efficiency can increase up to 24.2 % . Flue gas promotes the development of the middle and lower parts of the steam chamber during steam flooding, resulting in a 17.4 % increase in the sweep coefficient of steam chamber and a 25.4 % increase in oil recovery. In field applications for over 25 well times, the average oil production is increased by 120 t per cycle, and the oil-to-steam ratio is increased by 0.1. In typical wells, the oil production is increased by 775 t per cycle, and the oil-to-steam ratio is increased from 0.3 to 0.9.

Accurate prediction of annular pressure drop provides the foundation for precisely controlling bottom hole pressure and effectively preventing complex downhole incidents such as wellbore leakage, overflow, and even blowout. The conventional prediction method of annular pressure drop is usually based on circular wellbores, without considering the influence of irregular borehole shapes. Owing to the heterogeneity of mechanical rock parameters and in-situ stress, elliptical wellbores are easily formed. Based on fluid dynamics, a numerical model for the pressure drop of power-law fluid in laminar helical flow in elliptical wellbores was established, and was further verified by fluid mechanics simulation results and experimental data. Using the numerical model, the influencing factors of flow pressure drop were analyzed to clarify the effects of different parameters on flow pressure drop. A dimensionless pressure gradient fitting model was established by the least square method. The results show that the numerical model has an error within ±5 % when compared with simulation and measured results. The pressure gradient increases linearly with the increase of fluid viscosity coefficient, increases exponentially with the increase of flow behavior index and the ratio of inner and outer diameters, and increases logarithmically with the increase of average axial velocity; however, it decreases exponentially with an increase in the ratio of major and minor axes of the ellipse and the inner tube rotational speed. The dimensionless pressure gradient shows little variation with the change of fluid viscosity coefficient. The fitting model has an error of only ±5 % when compared to the numerical model. The applicable parameter ranges are as follows:0.8 m/s≤ v _x≤1.4 m/s, 40 r/min≤ ω≤120 r/min, 0.5≤ K _d≤0.8, 1.0≤ η≤1.2 and 0.5≤ n≤0.8. The dimensionless pressure gradient fitting model established for concentric annular laminar helical flow in elliptical wellbore enables accurate and convenient prediction of flow pressure drop, thus laying a theoretical foundation for the fundamental study of wellbore hydraulics.

Sichuan Basin has abundant oil-gas resources. Several hydrocarbon accumulation systems develop vertically from marine to terrestrial facies. In recent years, significant oil-gas exploration achievements have made in multiple strata of the West Sichuan gas field. To deepen the understanding of hydrocarbon enrichment regularities, guide the exploration and development practice, and further expand achievements in oil-gas production, this paper reviews the exploration and development history of the West Sichuan gas field and systematically analyzes the hydrocarbon accumulation conditions. The results show as follows. There are many sets of high-quality source rocks in western Sichuan depression, which provide sufficient material conditions. The development of tidal flat dolomite pore reservoir in the Member 4 of Middle Triassic Leikoupo Formation in western Sichuan area can expand marine exploration field from high-energy reef-beach and karst to confined platform tidal-flat dolomites, and enrich the types of marine oil-gas exploration. The superposed high-energy sandbodies widely developed at mouth bar and underwater distributary channel in the Member 2 of Upper Triassic Xujiahe Formation form a complete source-reservoir assemblage with inner source rocks or underlying Xiaotangzi Formation source rocks. The high-energy sandbodies widely developed at fan delta and braided river delta underwater distributary channels in Shaximiao Formation form a complete source-reservoir assemblage with source rocks of the Member 5 of Xujiahe Formation.The direct and relay through-source faults developed from Permian to Triassic Leikoupo Formation, the network micro-faults and fractures developed in Leikoupo Formation, the fault-fracture-sandbody transport system developed in Xujiahe Formation, and the fault-sandbody transport system developed in Shaximiao Formation in western Sichuan area are all efficient oil-gas transport systems, which ensure the efficient migration and accumulation of natural gas. The fine techniques of ultra-deep tidal-flat thin interbedded reservoir prediction are established, and the techniques of thin reservoir prediction and middle-small fracture space characterization for the Member 2 of Xujiahe Formation are formed, thus achieving fine reservoir characterization and supporting the implementation of horizontal wells. The development goals of high yield with fewer wells and effective use of reserves have been realized through well-matched development plan and research on drilling and completion technology. In western Sichuan area, the development and production of tidal-flat dolomite gas reservoirs in the ultra-deep complex structural belt, the efficient development of Xujiahe Formation, and the exploration breakthrough of Shaximiao Formation tight sandstone promote the process of exploration and development as well as the innovations of method and technology in relevant fields.