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Li Guoxin, He Xinxing, Zhao Qun, Zhang Junfeng, Zhang Guosheng, Zhang Lei, Xu Wanglin, Zhang Bin, Yang Zhi Theory, technology, exploration and development progress and prospects of coal-rock gas in China China Petroleum Exploration    2025, 30 (4): 1-17.   DOI: 10.3969/j.issn.1672-7703.2025.04.001 Abstract （1095）   HTML    PDF （7026KB）（7）    Knowledge map    Save Coal-rock gas is a new type of unconventional natural gas resource. In recent years, strategic breakthrough has been achieved, which has great significance for ensuring energy security in China. The research progress in geological theories, key technologies, and current status of exploration and development of coal-rock gas are systematically discussed, and the development prospects are put forward based on resource potential analysis results. The study results show that: (1) A consensus has basically been reached in the industry on the connotation of coal-rock gas. The coal rock shows a typical dual-pore media reservoir. Coal-rock gas is composed of complex gas components and high content of free gas, which has characteristics of migration and accumulation, and good preservation conditions are required for the formation of effective gas reservoir. (2) The understanding of coal-rock gas accumulation mechanism and the theoretical framework of whole petroleum system of coal measures have primarily been established, forming a “three-field controlling” coal-rock gas accumulation mechanism, and two types of gas accumulation and enrichment models, i.e., “integration of source rock and reservoir, and box-type sealing” and “multi-source supply, and gas enrichment in reservoir at high structural parts”. (3) A series of technologies have initially been developed, such as coa-rock gas resource assessment, geological and engineering sweet spot evaluation, laboratory testing, horizontal well multi-stage fracturing, production capacity evaluation, and production optimization. In addition, technologies such as water-reducing/water-free reservoir reconstruction and stereoscopic development of multi-layer and multi-source gas in coal measures are actively being researched. These technologies have supported the cumulative proven coa-rock gas geological reserves of 5968×10 8 m 3 , and the output reaching 27×10 8 m 3 in 2024. (4) It is preliminarily estimated that the coal-rock gas geological resources exceed 38×10 12 m 3, possessing the resource foundation for achieving an annual output of 300×10 8 m 3 by 2035, which shows a new growth point in the natural gas industry. (5) Three major challenges in coal-rock gas exploration and development are pointed out, and six key theoretical and technological research directions are proposed to promote the high-quality development of coal-rock gas industry in the future. Reference | Related Articles | Metrics

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Zhi Dongming, He Wenjun, Xie An, Li Mengyao, Liu Yin, Cao Jian Recognition and enlightenments of new oil and gas exploration fields in deep formations in Junggar Basin China Petroleum Exploration    2025, 30 (3): 1-24.   DOI: 10.3969/j.issn.1672-7703.2025.03.001 Abstract （872）   HTML    PDF （22418KB）（6）    Knowledge map    Save The deep formations in petroliferous basins have become a practical field for petroleum exploration. Junggar Basin is characterized by long tectonic evolution history and complex geological settings. Based on the exploration achievements in recent years, the new exploration fields in deep formation have been predicted, which indicates that there are four new exploration fields in the deep to ultra-deep formations, including prototype marine basin oil and gas reservoirs, intra source rock unconventional oil and gas reservoirs in the Permian Fengcheng Formation in Western Depression, large-scale stratigraphic oil and gas reservoirs in hydrocarbon-rich sags, and Jurassic–Cretaceous structural oil and gas reservoirs in the southern marginal foreland thrust belt. For prototype basin oil and gas reservoirs, controlled by the scattered source rocks in multiple depo-centers in the Carboniferous, relatively independent whole petroleum system can be formed in these source kitchens. Intra source rock oil and gas reservoirs in the Permian Fengcheng Formation in Western Depression showed a hydrocarbon accumulation pattern of orderly distribution of conventional–unconventional resources. The deep formation in Pen 1 Well West–Shawan Sag is a practical field for discovering a large gas zone with resources of trillion cubic meters. In hydrocarbon-rich sags, jointly controlled by paleogeomorphology and lake level, large-scale stratigraphic traps were formed in deep formations, and the clustered oil and gas reservoirs in trough areas are favorable targets. The large-scale structural traps were formed in the Jurassic-Cretaceous in the southern marginal foreland thrust belt, and high-quality reservoirs can still be developed below 8000 m, possessing the geological conditions for forming large-scale gas reservoirs. The study shows that the petroleum exploration in Junggar Basin has entered a new stage focusing on deep formations, generally exhibiting the coexistence of conventional–unconventional oil and gas reservoirs in sequence. The high-quality source rocks and effective hydrocarbon accumulation factors provided a solid material basis and favorable conditions for deep oil and gas reservoirs in the basin. Reference | Related Articles | Metrics

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Zhang Lijuan, Su Zhou, Liu Yongfu, Zhang Yintao Exploration discovery in ultra-deep marine carbonate rocks and enlightenments, Tarim Basin China Petroleum Exploration    2025, 30 (3): 25-39.   DOI: 10.3969/j.issn.1672-7703.2025.03.002 Abstract （791）   HTML    PDF （9847KB）（8）    Knowledge map    Save Marine carbonate rocks in Tarim Basin are mainly distributed in the Early Paleozoic marine strata in cratonic zone, with a burial depth of greater than 6000 m, a large thickness, and wide distribution area. The reservoir formation and hydrocarbon accumulation mechanisms in ancient carbonate rocks are complex, so the case studies have important enlightenments for the petroleum exploration in the ultra-deep formation (≥6000 m). The arduous exploration of carbonate oil and gas resources in Tarim Basin for 40 years has been summarized, and the theory, technology and deployment ideas of major discoveries in large ultra-deep carbonate oil and gas fields have been analyzed. The field practice shows that the exploration of carbonate rocks in Tarim Basin has gone through four major stages. Through the understanding and innovation of geological theories of ultra-deep buried hill karst, reef beach karst, interlayer karst and fault controlled karst reservoirs, the formation mechanism of large-scale ultra-deep ancient carbonate rock karst reservoirs in paleo-uplift–slope–depression has been revealed, which has guided the transformation of exploration deployment ideas and major new breakthroughs; After implementing 3D high-precision seismic exploration, a series of exploration techniques dominated by quantitative fracture and cave carving and fine characterization of strike slip faults in ultra-deep carbonate reservoirs have been formed, achieving effective prediction of heterogeneous karst fractured and cavity reservoirs, and supporting the constant discoveries in ultra-deep complex carbonate rocks. The exploration theory and technical innovation of ultra-deep ancient carbonate karst reservoirs formed by exploration practice in Tarim Basin have broken through the traditional theories of “oil reservoir controlled by paleo uplift” and “dead line of oil generation” in the cratonic zone, and realized the major strategic shift from structural high part of the paleo uplift to the slope–depression zone. The experience of successful exploration in the ultra-deep ancient carbonate rocks includes the change of idea to bravely breaking the exploration forbidden zone and the integration of exploration and development. Reference | Related Articles | Metrics

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Li Cheng, Zhang Xiaohui, Shi Lichuan, Wang Zhitao, Pu Lei Main controlling factors and exploration potential of the Jurassic oil reservoirs in Ordos Basin China Petroleum Exploration    2025, 30 (3): 92-108.   DOI: 10.3969/j.issn.1672-7703.2025.03.007 Abstract （786）   HTML    PDF （14421KB）（30）    Knowledge map    Save Over the past 50 years, breakthroughs have continuously been made in the exploration of the Jurassic system in Ordos Basin. Based on early discovered oil reservoirs and exploration and appraisal wells, drilling geological data, core analysis, and seismic data have been used to finely characterize the pre Jurassic paleogeomorphology, sand bodies, and structures in the basin and analyze characteristics of fault development in the 3D seismic area, identifying the types of Jurassic oil reservoirs in the study area and controlling factors, and pointing out further exploration orientations and potential of the Jurassic system in the basin. The study results show that: (1) The pre Jurassic paleogeomorphology presented a “U+V”-shaped multi-level ancient river structure, with nine types of small units such as inter-river hill and terrace, which significantly controlled oil reservoir types; (2) The Jurassic oil reservoirs were mainly generated by source rocks in the seventh member of the Triassic Yanchang Formation, and the episodic oil charging in the Late Jurassic–Early Cretaceous laid the foundation for the wide distribution area of oil reservoirs; (3) The coupling of ancient rivers and low-amplitude nose uplift structures controlled the distribution of oil reservoir clusters, and a stereoscopic hydrocarbon accumulation pattern was formed by a three-stage fault relay transport; (4) There is still huge resource potential with a level of 100 million tons in complex fault zones in the western basin margin and the northeastern part of Jingbian slope, as well as mature areas through fine exploration. Reference | Related Articles | Metrics

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Qu Junya, Li Zhi, Yang Zi, Hou Ping, Wang Zhaoming, Li Fuheng, Xu Hailong, Kang Hailiang, Shang Fei Research on decision-making management mechanism of venture exploration projects of international oil companies and enlightenments China Petroleum Exploration    2025, 30 (3): 40-50.   DOI: 10.3969/j.issn.1672-7703.2025.03.003 Abstract （677）   HTML    PDF （2299KB）（1）    Knowledge map    Save In order to cope with challenges faced by Chinese oil enterprises in overseas risk exploration, including difficulties in acquiring high-quality assets and limitations in developing existing assets, and enhance international competitiveness, the risk exploration decision-making mechanisms of leading international oil companies are systematically analyzed. After collecting core data through expert interview and consulting research, six representative international oil companies, i.e., ExxonMobil, Eni, Shell, Equinor, TotalEenergies, and bp are optimally selected, and the decision-making management systems of three strategically balanced type enterprises, Equinor, Eni, and Shell are deeply analyzed. The study results indicate that international oil companies have established a four-stage standardized decision-making workflow (preliminary assessment and screening, in-depth study, implementation program, and operation), and three core mechanisms have been formed: (1) The full-process support has been achieved by professional team division system integrating “new venture team, exploration technical team, management team, and quality control team”; (2) The risks and returns are balanced by strategically-oriented portfolio optimization; (3) The technological collaborative innovation mechanism has been constructed, and the high-performance computing platforms and intelligent decision-making systems have been integrated to enhance decision-making efficiency. The typical case studies reveal that Equinor has shortened decision-making chains via regionally integrated organizational structures, Eni has achieved strategic goals through “dual exploration mode” and “multi-track parallel decision-making”, while Shell has optimally selected exploration targets using its play portfolio analysis framework. In terms of institutional characteristics of Chinese oil companies, a four-dimensional improvement roadmap is proposed, namely, strategic–asset portfolio synergetic optimization, standardized decision-process rebuilding, intelligent management platform development, and internal control system enhancement. These suggestions provide theoretical basis and practical reference for improving overseas oil and gas exploration decision-making and facilitating the transformation from scale-driven expansion to value-centric operation of Chinese oil companies. Reference | Related Articles | Metrics

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Yu Jian, Shi Yunhe, Zhang Tao, Dai Xianduo, Liang Chen, Jiao Pengshuai, Du Xiaowei, Gao Xing, Zhuang Yipeng, Zhang Hui, Chen Yuhang New geological understanding and key engineering technologies for deep coal-rock gas in Ordos Basin China Petroleum Exploration    2025, 30 (4): 59-77.   DOI: 10.3969/j.issn.1672-7703.2025.04.005 Abstract （589）   HTML    PDF （11365KB）（0）    Knowledge map    Save The Carboniferous–Permian coal measure strata are widely distributed in Ordos Basin. There are abundant deep coal-rock gas resources, showing a solid material basis for large-scale capacity construction, so it is crucial to systematically understand the geological characteristics and exploration methods of deep coal-rock gas. Based on review of exploration history, and combined with well drilling, logging, and laboratory test data, the coal accumulation environment, coal quality, reservoir physical properties, and gas accumulation conditions of the Upper Paleozoic coal measure strata at the basin scale have been analyzed. By integrating with geological and engineering data from typical wells in recent years, the resource potential, enrichment patterns, and key development technologies have been summarized, and future exploration orientations have been determined. The study results show that: (1) No.8 coal seam in Benxi Formation and No.5 coal seam in Shanxi Formation are the main target layers for deep coal-rock gas exploration, which are featured by thick coal seams, consistent distribution, relatively high maturity, high vitrinite content, and high gas generation capacity; (2) The coal rock reservoirs are dominated by primary structure coal, with bimodal pattern of pore structure, well-developed micropores and cleat–fracture system, and high proportion of free gas; (3) Hydrocarbon retention rate is generally high, which is about 40% in the central basin and exceeding 50% in the eastern basin, providing a material basis for gas accumulation; (4) Three types of reservoir and cap rock combinations were formed by coal rocks and the overlying strata, including coal–mudstone, coal–limestone, and coal–sandstone, which effectively controlled the distribution of free gas and formed a favorable hydrocarbon accumulation pattern of “continuous hydrocarbon generation, integration of source rock and reservoir, and box-type sealing”; (5) Based on field practice, a series of key engineering technologies applicable for deep coal-rock gas have been developed, including differentiated geosteering, two-section wellbore structure optimization, high-displacement fracturing, and pressure-controlled production, significantly improving the drilling encounter rates, reservoir reconstruction efficiency, and single-well production capacity. The research results support the goal of deep coal-rock gas development with “accurate identification, successful drilling, and steady production”, and demonstrate the feasibility and practical value of large-scale capacity construction promoted by integration of geology and engineering. Reference | Related Articles | Metrics

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Zhou Lihong, He Xinxing, Xiong Xianyue, Li Shuguang, Ding Rong, Yan Detian, Fu Haijiao, Li Yong Scientific significance and energy strategic impact of deep coalbed methane breakthrough China Petroleum Exploration    2025, 30 (4): 18-26.   DOI: 10.3969/j.issn.1672-7703.2025.04.002 Abstract （585）   HTML    PDF （1690KB）（0）    Knowledge map    Save Based on the exploration and development practice of Daji deep coal rock gas field, the scientific value and the evolution of strategic position of coalbed methane are systematically reviewed, the strategic significance of breakthroughs in deep coalbed methane is clarified, and key technological research directions are proposed. The study results indicate that the main theoretical system of coal associated natural gas has gone through three stages of “coal derived gas–shallow coalbed methane–deep coalbed methane”. The breakthrough of deep coalbed methane has established the independent position of coalbed methane resources and enriched the theoretical system of unconventional natural gas, which has values in four aspects: (1) The exploration depth of coalbed methane has been expanded and the pattern of unconventional resources has been reshaped; (2) The “binary enrichment” mode has been proposed, enriching the theoretical understanding of unconventional oil and gas reservoir accumulation; (3) The core engineering technology system has been constructed such as large-scale volume fracturing, achieving the beneficial development of deep resources; (4) The world’s first deep coalbed methane field has been built, achieving a leading position in coalbed methane. In the future, it is still necessary to conduct research on sweet spot evaluation and high-efficiency capacity construction, high-efficiency drilling and volume fracturing, fine gas production, and intelligent gas gathering and transportation technologies, so as to build a low-cost, intelligent and green development path. The deep coalbed methane has become a new strategic replacement resource of unconventional natural gas in China, which helps to adjust energy structure and achieve the dual carbon strategic goals in China. Reference | Related Articles | Metrics

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Zhao Wenzhi, Cao Zhenglin, Huang Fuxi, Lin Shiguo, Chen Kefei, Ding Lin Hydrocarbon accumulation characteristics and development prospects of deep coal-rock gas in China China Petroleum Exploration    2025, 30 (4): 27-43.   DOI: 10.3969/j.issn.1672-7703.2025.04.003 Abstract （558）   HTML    PDF （10550KB）（0）    Knowledge map    Save Deep coal-rock gas in China generally refers to the combination of free gas and adsorbed gas stored in deep coal seams (greater than 1500 m) with favorable preservation conditions, which has similar hydrocarbon accumulation conditions to shale gas but different from shallow CBM. There are abundant deep coal-rock gas resources in China. An early understanding of its accumulation conditions and distribution characteristics is crucial for guiding and accelerating the reserve and production growth of deep coal-rock gas. Based on the study of recent exploration wells and trial production data, it is proposed that China’s onshore coal-rock gas was mainly developed in coal seams deposited in tidal flat–lagoon, lake shore swamp, and delta swamp environments, with the main storage space of micro- to nano-scale pores, cleavages and fissures. Deep coal-rock gas accumulated in reservoirs in both free and adsorbed states, with a relatively high proportion of free gas, indicating a major characteristic that distinguishes it from shallow CBM. Based on gas sources, deep coal-rock gas is classified into two types, i.e., selfgeneration and self-storage, and external-source and coal-storage, and the latter has a higher proportion of free gas content. The effective cap rocks and large burial depth are essential conditions for the formation of deep coal-rock gas reservoirs. Furthermore, two types of coal-rock gas reservoirs are classified in China, namely, medium- to high-rank coal ( R o≥1.3%) and low- to medium-rank coal ( R o<1.3%). The enrichment of coal-rock gas in medium- to high-rank coal benefits from the high gas generation potential, low formation water content, relatively stable structure, well-developed cleavages and fissures, and effective sealing conditions of main coal roof and floor. The enrichment of coal-rock gas in low- and medium-rank coal profits from the cumulative enrichment with low gas generation rate, continuous distribution of high-quality coal seams, coupling control of structure and gas sources. In addition, natural gas accumulated in adjacent tight sandstone (limestone) is also an important contributor to the low- and medium-rank coal-rock gas. China has abundant deep coal-rock gas resources, but the exploration remains in its early stage. It is expected that deep coal-rock gas production will increase rapidly in the future and reach its peak around 2040. Reference | Related Articles | Metrics

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Xie Wuren, Wang Zecheng, Luo Bing, Zheng Majia, Ma Shiyu, Chen Yana, Xin Yongguang, Yang Rongjun Hydrocarbon accumulation characteristics and exploration orientation of intra-source tight gas in Sichuan Basin China Petroleum Exploration    2025, 30 (3): 65-77.   DOI: 10.3969/j.issn.1672-7703.2025.03.005 Abstract （554）   HTML    PDF （6549KB）（1）    Knowledge map    Save With the increasing maturity of petroleum exploration in petroliferous basins in China, it is necessary to expand strategic replacement fields for oil and gas industry development. Recent exploration breakthroughs reveal that the resource potential of intra-source tight gas exceeds 1×10 12 m 3 in Sichuan Basin, emerging as a prospective new strategic replacement field. The fine core description, logging data interpretation, and geochemical analysis data of a large number of core samples have been integrated to analyze the genetic type and distribution characteristics of intra-source tight gas in Sichuan Basin, identify the hydrocarbon accumulation and enrichment laws, and clarify resource potential and future exploration orientations. The study results show that: (1) Influenced by multicyclic tectonic evolution and frequent sea–lake level fluctuations, multiple sets of high-quality thick source rocks were developed in Sichuan Basin, forming multi-type marine and continental intra-source tight gas reservoirs. (2) There are two types of source rock and reservoir assemblages of intra-source tight gas reservoirs. One is near-source gas accumulation, which is enveloped by source rocks, showing superior sealing conditions, such as tight gas in Qiongzhusi Formation and the fifth member of Xujiahe Formation; The other is source rock and reservoir integrated gas reservoir with high-pressure sealing conditions, such as marine marl tight gas in the second sub-member of the third member of Leikoupo Formation and the first member of Maokou Formation. (3) The estimated resources of the four sets of intra-source tight gas are more than 4×10 12 m 3, including tight sandstone gas in Qiongzhusi Formation, tight marl gas in Leikoupo Formation, tight marl gas in the first member of Maokou Formation, and tight sandstone gas in the fifth member of Xujiahe Formation, showing major fields for further exploration, among which Ziyang–Penglai area is the most favorable area for Qiongzhusi Formation tight gas, the southern–central Sichuan Basin is the prospective area for marine marl tight gas, and Penglai–Jinhua area is a favorable exploration area for tight gas in the fifth member of Xujiahe Formation. Reference | Related Articles | Metrics

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Pang Xiongqi, Li Caijun, Jia Chengzao, Chen Yuxuan, Li Maowen, Jiang Lin, Xiao Huiyi, Jiang Fujie, Cao Peng, Chen Dongxia, Xu Zhi, Lin Huixi, Hu Tao, Zheng Dingye, Wang Lei Prediction of the maximum depth of deep to ultra-deep resources based on the theory of whole petroleum system China Petroleum Exploration    2025, 30 (3): 126-139.   DOI: 10.3969/j.issn.1672-7703.2025.03.009 Abstract （551）   HTML    PDF （3611KB）（0）    Knowledge map    Save The deep to ultra-deep formations have abundant resources, which is currently a key field for petroleum exploration and research both domestically and internationally. The study on the maximum depth of oil and gas reservoirs has important practical significance for assessing deep oil and gas resources, deploying ultra-deep wells, and understanding exploration risks. Based on the theory of whole petroleum system (WPS), the method and process have been proposed to quantitatively predict the maximum depth of conventional, tight, and shale oil and gas reservoirs in petroliferous basins. Some cases of discovered oil and gas reservoirs and well drilling data have been studied to predict the maximum depth of oil and gas reservoirs in petroliferous basins such as Tarim, Junggar, Sichuan, Ordos, Songliao, and Bohai Bay in China. The study results show that the maximum depths of conventional, tight, and shale oil and gas reservoirs in the six major petroliferous basins are usually in the range of 800–4400 m, 5050–7990 m, and 5400–9300 m, which increase with decreasing geothermal gradient, better organic matter types, and higher oil wet property of the reservoir. With advancements in drilling technology and predictive capabilities, the scope of discovering oil and gas resources will continue to expand. In addition, the maximum depth of oil and gas reservoirs is influenced by tectonic movements in the context of in-situ geological conditions. Finally, based on the actual drilling results of shallow–medium–deep oil and gas in Tarim Basin, the predicted maximum depths of ultra-deep carbonate oil and gas reservoirs in the Cambrian–Ordovician exceed (9500±50) m and (10500±100) m, respectively. Reference | Related Articles | Metrics

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Li Guoxin, Yang Yu, Song Yong, Zhang Guosheng, Guo Xuguang, Yan Weipeng, Huang Fuxi, Wang Shaoyong, Yuan Ming Major progress in oil and gas exploration during the 14 th Five–Year Plan period and future prospects of PetroChina China Petroleum Exploration    2026, 31 (1): 1-13.   DOI: 10.3969/j.issn.1672-7703.2026.01.001 Abstract （547）         Knowledge map    Save During the 14 th Five–Year Plan period, PetroChina Company Limited (hereinafter referred to as “PetroChina”) has been committed to high-quality development of oil and gas exploration, and vigorously advanced efficient exploration guided by the Seven–Year Action Plan. As a result, 30 significant results in five major fields have been achieved in domestic oil and gas exploration, including marine carbonate rocks, continental lake basin lithologic–stratigraphic traps, foreland thrust belts, shale oil and gas, and deep coal rock gas, forming nine largescale oil reserve areas and seven large-scale natural gas reserve areas by intensive exploration activities. The exploration achievements show distinct characteristics of multiple breakthroughs in various fields on the plane, simultaneous exploration of both shallow and deep formations in vertical direction, and parallel advancement of both conventional and unconventional resources. Specially, breakthroughs have been made in long-stalled fields such as the southern margin of Junggar Basin and the piedmont zone of southwestern Tarim Basin. In addition, breakthrough progress has been made in oil and gas geological theories in aspects such as marine carbonate rocks, lithologic–stratigraphic traps in continental lake basin, and coal measure whole petroleum system. Furthermore, key engineering technologies have been developed, represented by 3D seismic imaging in “double high” and “double complex” areas, efficient well drilling and completion in deep to ultra-deep formations, and geology and engineering integrated fracturing for deep coal rock gas. In response to the new situation of oil and gas exploration at home and abroad during the 15 th Five–Year Plan period and resource endowment in China, PetroChina will adhere to efficient exploration, strengthen risk exploration in key zones in the five major fields, actively prepare for strategic replacement areas and major replacement fields, focus on centralized exploration in “10 oil and 10 gas” exploration fields, and promote continuous large-scale reserve growth of conventional oil and gas and rapid development of unconventional resources, so as to consolidate the resource foundation for high-quality development. Reference | Related Articles | Metrics

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Zhang Yanming, Lin Xiaobo, Zhou Changjing, Ma Zhanguo, Xiao Yuanxiang, Gu Yonghong, Wang Lili, Hui Bo, Liu Xinjia, Liu Xiaorui Key reservoir stimulation technologies and application for deep coal-rock gas in Ordos Basin China Petroleum Exploration    2025, 30 (4): 160-170.   DOI: 10.3969/j.issn.1672-7703.2025.04.011 Abstract （529）   HTML    PDF （9928KB）（0）    Knowledge map    Save There are abundant coal rock resources in Benxi Formation coal seam No.8 in Ordos Basin, which is a realistic replacement field for increasing unconventional gas reserves and production in China. Compared with shallow coalbed methane, deep coal-rock gas has the characteristics of “tight matrix, high proportion of isolated pores, well developed cleavages and fissures, coexistence of free gas and adsorbed gas”. Therefore, the large-scale fracturing is an effective means to reduce free gas flow resistance and promote the desorption of adsorbed gas in deep coal rocks. The experiments such as triaxial mechanical compression, in-situ stress test and large physical simulation on fracture propagation have been conducted, which have identified the well-developed cleavages, mechanical properties of low Young’s modulus, high Poisson’s ratio, large longitudinal stress difference of coal rock No.8, and fracture propagation characteristics given the fracturing modes of high displacement low viscosity and low displacement high viscosity. By applying multi-parameter geology–engineering sweet spot identification method and multi-stage and multi-cluster differentiated fine fracture layout technology, the economic and large-scale fracturing technology has been formed with the core of “multi-stage and few clusters, alternating fluid injection, and combined sand addition”. The key points of the technology include: (1) Few clusters in one stage to concentrate energy at the fracture opening and initiate cleavages and fissures; (2) Alternating injection of high and low viscosity fluids to expand fracture propagation zone and increase the fracture complexity; (3) Combined sand addition to increase flow capacity, so as to achieve the effective support of multi-scale fractures. The technology has been applied to 19 wells, with an initial daily gas rate of 4.9×10 4 m 3/d, showing good gas production test results, which has provided important technical support for beneficial development of deep coal-rock gas. Reference | Related Articles | Metrics

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Xu Rongli, Bu Xiangqian, Chen Wenbin, Zhang Yanjun, Wang Guangtao, Li Changheng, Jia Xuliang, Wu Anan, Shan Shumin Research and practice of ultra-short horizontal well fracturing technology for tight oil reservoirs in Changqing Oilfield China Petroleum Exploration    2025, 30 (3): 154-164.   DOI: 10.3969/j.issn.1672-7703.2025.03.011 Abstract （511）   HTML    PDF （9213KB）（0）    Knowledge map    Save In Changqing Oilfield, tight oil production has a long history and a large scale, and it remains a key target for production capacity construction at present, accounting for 36.6% of the new production capacity. In response to the geological characteristics of tight oil reservoirs, and targeting at the goal of an optimal adaptation between well pattern and fracture network, the geology and engineering integrated research approach is applied to conduct fracturing optimization design using methods such as numerical simulation, big data analysis, and field test. As a result, the coiled tubing precise multi-stage fracturing technology for short horizontal wells has been developed, as well as key integrated technology of “optimization of fracturing timing, differential fracture design, precise fracture control, enhanced imbibition oil displacement, multi-stage fracture temporary plugging, and directional perforation”. This technical model has been applied in over 200 tight oil wells in Changqing Oilfield, significantly improving the degree of fracture control and oil production in horizontal wells. Microseismic monitoring results show that the degree of fracture control has increased from 60% to over 85%, the initial oil production of a 100-meter horizontal section has increased from 2.0 t/d to 3.4 t/d, and the single well production remains steady, with an oil production rate of 3.2 t/d in the year of reaching production capacity, showing satisfactory results as a whole. The key fracturing technology effectively supports high-efficiency development of tight oil in Ordos Basin and points out direction for further technical breakthroughs. The new insights provide references for large-scale and beneficial development of similar oilfields in China. Reference | Related Articles | Metrics

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Liu Guoyong, Zhang Yongshu, Xue Jianqin, Long Guohui, Ma Feng, Wang Bo, Wang Yongsheng, Zhang Changhao, Zhou Fei, Tian Jixian, Sun Xiujian, Wu Zhixiong Geological characteristics and exploration orientations of the Upper Carboniferous and Middle Jurassic coal rock gas in Qaidam Basin China Petroleum Exploration    2025, 30 (3): 78-91.   DOI: 10.3969/j.issn.1672-7703.2025.03.006 Abstract （494）   HTML    PDF （5688KB）（0）    Knowledge map    Save Field outcrops and drilling data reveal that the Paleozoic–Mesozoic coal rocks are widely distributed in Qaidam Basin, with certain hydrocarbon generation potential and good reservoir performance, which is a new exploration field in the basin. However, the level of research and understanding is relatively low. A systematic study on coal rocks in the Middle Jurassic Dameigou Formation and the Upper Carboniferous Keluke Formation in Qaidam Basin is conducted, including sedimentary environment, distribution, coal properties, reservoir characteristics, resource amount, and gas enrichment rules. In addition, gas resource potential in coal rocks is evaluated, and exploration deployment orientations are proposed in Qaidam Basin. The study results show that: (1) The limnic facies coal rocks in the Middle Jurassic have a single layer thickness of 2–30 m and a distribution area of 11100 km 2; The transitional facies coal rocks in the Upper Carboniferous have a single layer thickness of 1–6 m and a distribution area of 5689 km 2. (2) The coal rocks in the Middle Jurassic and the Upper Carboniferous are semi-bright to bright coals in a middle coal rank stage, all possessing gas generation capacity; TOC of coal rocks in the Middle Jurassic Dameigou Formation is 32.22%–79.50%, with an average of 62.85%, and R o is 0.77%–1.38%, with an average of 0.9%; TOC of coal rocks in the Upper Carboniferous Keluke Formation is 35.67%–98.34%, with an average of 72.40%, and R o ranges in 0.92%–1.82%, with an average of 1.57%. (3) The coal rock reservoirs are characterized by good porosity and permeability properties, and the coal cleats have a high density, showing a reticular distribution pattern and good connectivity; The matrix pores such as stomata, mold pores, dissolution pores, intercrystal pores and plant tissue pores are observed; The measured porosity of coal rocks ranges from 5.26% to 34.01%, with an average of 15.65%; The permeability is 5.11–12.60 mD, with an average of 8.91 mD. (4) Five types of gas accumulation and dispersion combinations are classified vertically in coal rocks, among which the widely distributed coal rock–mudstone and coal rock–limestone gas accumulation combinations have good sealing conditions and high peak values of total hydrocarbon gas logging shows, indicating the most favorable combinations for coal rock gas enrichment. (5) The favorable areas of the Middle Jurassic in Yuandingshan–Jiulongshan area in the northern margin of Qaidam Basin and the Upper Carboniferous in Dulan–Wulan in Delingha area are optimally selected for further strategic exploration deployment. The above understanding is expected to guide the strategic deployment of coal rock gas in Qaidam Basin, pioneer new frontiers for coal rock gas exploration, and unveil a new chapter in natural gas exploration in the basin. Reference | Related Articles | Metrics

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Zhang Ronghu, Jin Wudi, Zeng Qinglu, Yang Xianzhang, Yu Chaofeng, Song Bing, Wang Ke, Li Dong Analysis of key conditions for gas accumulation and favorable replacement fields in 10000-meter deep formations in Kuqa Depression, Tarim Basin China Petroleum Exploration    2025, 30 (3): 51-64.   DOI: 10.3969/j.issn.1672-7703.2025.03.004 Abstract （474）   HTML    PDF （7298KB）（1）    Knowledge map    Save The 10000-meter deep formation is an important field for intra source rock gas exploration in Kuqa Depression, which is a potential replacement field benefit from its large resource amount, good preservation conditions and near-source hydrocarbon charging. However, there is unclear understanding of structural traps, reservoir scale and oil and gas reservoir types. Based on geological study of deep structures, hydrocarbon generation potential evaluation, physical simulation of reservoir diagenesis and comprehensive analysis of hydrocarbon accumulation mode, the key conditions for gas accumulation in 10000-meter deep formations have been analyzed and favorable replacement fields have been optimally selected. The results show that, controlled by three detachment layers such as coal measure strata, huge thick mudstone, and Paleozoic unconformity, large fault anticlines, anticlines and fault block structures were developed in 10000-meter deep formations in Kuqa Depression, and mostly concentrated in Kelasu thrust belt. The huge thick Triassic–Lower Jurassic highly-over mature coal measures and lacustrine mudstone source rocks were developed in 10000-meter formations, with a hydrocarbon generation capacity of (1000–3000)×10 8 m 3/km 2. Jointly controlled by the large-area braided river delta plain–front huge thick sand bodies, rapidly deep burial in the late stage, ultra-high temperature and ultra-high pressure, and intense tectonic compressive stress, the large-scale fractured–porosity type reservoirs still have good physical properties at a depth of 10000 m, with a porosity of 5%–10% and a permeability of higher than 1 mD. The Triassic-Lower Jurassic regional near/intra source rock hydrocarbon accumulation combination was dominant in 10000-meter deep formation, generally forming structural-lithologic tight sandstone gas reservoirs. The Kelasu thrust belt is optimally selected as a strategic exploration zone, with an area of 4200 km 2, and gas resources of up to 1.5×10 12 m 3, and the traps below Keshen Gas Field are favorable targets. The research results provide basic understanding for gas exploration in clastic rocks with a depth of 10000 meters in China, and lay geological theoretical foundation for further discovery of large gas fields below Kela–Keshen in Kuqa foreland basin thrust belt. Reference | Related Articles | Metrics

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Liu Yong, Zhao Shengxian, Fang Rui, Li Bo, Li Jiajun, Liu Dongchen, Liu Wenping, Nie Zhou, Zhou Luchuan, Zhu Yihui Comparative analysis of marine shale gas characteristics between Southern Sichuan Basin and the United States: implications for advancing “China’s Shale Gas Revolution” China Petroleum Exploration    2025, 30 (5): 22-38.   DOI: 10.3969/j.issn.1672-7703.2025.05.003 Abstract （445）   HTML    PDF （11353KB）（21）    Knowledge map    Save After over a decade of persistent efforts, preliminary technological iteration and sustained production growth have been obtained in shale gas exploration and development in China. However, it still faces scientific and technological challenges in realizing the large-scale and beneficial development. In order to advance the beneficial shale gas development and achieve “China’s Shale Gas Revolution”,  comparative analysis of shale gas geological characteristics and development methods between Southern Sichuan Basin and the United States has been conducted, and future development direction of shale gas in China has been clarified. The study results indicate: (1) Affected by multi-stage tectonic events, shale gas reservoirs in Southern Sichuan Basin are characterized by complex structure, great stress difference, and high reservoir heterogeneity. Despite its superior organic matter abundance (TOC) and maturity, critical parameters including porosity, permeability, and single-well controlled reserves are poorer than those in typical U.S. shale gas fields, posing inherent constraints to the large-scale and beneficial gas development. (2) Although the U.S. “horizontal drilling + volume fracturing” system offers valuable references, it is infeasible for direct replication. In response to the complex geological conditions in China, oil companies should overcome technical barriers in sweet spot delineation, ultra-long horizontal well drilling, and high-efficiency fracturing technology, and construct a technological system adapted to the native geological and engineering conditions. (3) The core factor for successful shale revolution in the U.S. lies in project-based management and day-rate contracting system, which achieves high-efficiency iteration given the high-risk conditions. In contrast, China’s traditional “relay-style” management mode severely impedes operational efficiency, so it is urgent to promote the flattened project system reform to stimulate management efficiency. Recent field practices in Southern Sichuan Basin show that the “China’s Shale Gas Revolution” is imperative for high-quality development, which demands establishing a tailored management system with operational autonomy, pursuing innovation aligned with China’s geological realities, and prioritizing geological–engineering sweet spot characterization, technological iteration, and stereoscopic development pilots to achieve a second leap in the development of shale gas industry in China. Reference | Related Articles | Metrics

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Sun Chonghao, Duan Junmao, Luo Xinsheng, Zheng Jianfeng, Shi Lei, Xiong Ran, Hu Huan, Peng Zijun Sedimentary characteristics and deposition modes of the Upper Cambrian Lower Qiulitage Formation in Xiaoerblak outcrop area, western Tabei area China Petroleum Exploration    2025, 30 (3): 109-125.   DOI: 10.3969/j.issn.1672-7703.2025.03.008 Abstract （439）   HTML    PDF （20746KB）（0）    Knowledge map    Save In Tabei area adjacent to Northern Depression and Kuqa Depression, the Upper Cambrian Lower Qiulitage Formation is characterized by dual hydrocarbon source supply and favorable geological conditions for hydrocarbon accumulation, showing significant exploration potential indicated by breakthroughs in Well Xiongtan 1. However, there is a lack of study on the fine sedimentary characteristics, microfacies distribution pattern, and deposition mode in the sequence framework, which restricts further exploration of Lower Qiulitage Formation. Through field stratigraphic survey of six sections (2334.4 m) in Xiaoerblak outcrop area, GR and carbon isotope curves measurement of two sections, and thin section observation of 555 core samples, the stratigraphy and sequence characteristics, sedimentary characteristics, and deposition modes of Lower Qiulitage Formation are systematically analyzed. The correlation of lithology, GR curve and carbon isotope curve clarifies that Lower Qiulitage Formation in the study area corresponds to SQ7 and SQ8 (absence of the top) in the platform–basin region. The main rock types include granular dolomite, clotted dolomite, stromatolitic dolomite and laminated dolomite. The restricted platform facies was dominant, which was subdivided into five subfacies and six microfacies, forming seven types of typical sedimentary sequences. Influenced by Wensu-Yaha paleo uplift, SQ7 is composed of tidal flat subfacies sediments with frequent cyclic changes of various microfacies and minor lateral variation, and a deposition mode of supratidal zone–intertidal zone–subtidal zone from paleo uplift to the basin has been established. During the deposition period of SQ8, the sedimentary subfacies transitioned from tidal flat to intra-platform beach subfacies, with significant lateral differences in the proportion of mound and beach bodies, and a deposition mode of intertidal zone–subtidal high-energy zone–intra-platform beach from paleo uplift to the basin has been established. A total of 61–74 sedimentary sequences are observed in SQ7 in the outcrop area, with high-quality reservoir–cap rock combination developed in a single sedimentary sequence, and the successive sedimentary sequences in the over-100-meter strata have the potential to form superimposed and connected lithologic oil and gas reservoirs. SQ8 is characterized by widely developed reservoirs and has the potential to form high-quality structural oil and gas reservoirs. Controlled by Wensu–Yaha paleo uplift, the mound beach facies reservoirs are widely distributed in the western Tabei area, with good physical properties. In areas with overlying tight lithology and faults connecting to source rocks, high-quality oil and gas reservoirs were easy to form, showing a favorable area for exploration. The research results provide orientations for further exploration of Lower Qiulitage Formation in Tabei area. Reference | Related Articles | Metrics

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Zhang Ruihan, Xiong Zhuohang, Zhao Chuankai, Shi Lei, Yan Liheng, Chou Peng Fracture propagation simulation and optimal design of ultra-deep and ultra-high pressure tight gas reservoirs in Hutubi area, Junggar Basin China Petroleum Exploration    2025, 30 (3): 165-178.   DOI: 10.3969/j.issn.1672-7703.2025.03.012 Abstract （420）   HTML    PDF （7632KB）（7）    Knowledge map    Save The reservoirs in HT1 well area in Hutubi area are characterized by relatively great burial depth, low porosity, low permeability and tight property. The fracture propagation law is unclear given the conditions of high temperature, high pressure and well-developed natural fractures, which poses challenges for fracturing construction. In order to solve this problem, triaxial compression tests have been conducted on core samples from the target layer under high temperature and high pressure conditions to obtain rock mechanic parameters such as elastic modulus and Poisson’s ratio. Based on geology and engineering integrated method, relevant lab test data, core observation, well logging and seismic interpretation data have been used to establish a 3D geomechanical model. Finally, constrained by the geomechanical model, the fracture propagation simulation, well construction parameter optimization design, production history fitting and prediction have been analyzed in vertical wells with natural fractures developed. The study results show that: (1) The average Young’s modulus is 37.5 GPa, and the average Poisson’s ratio is 0.25. The average maximum and minimum horizontal principal stresses are 220 MPa and 180 MPa, which are much higher than those of conventional gas reservoirs (generally less than 100 MPa). (2) By setting the length of 70 m and the interval of 150 m for small-scale natural fractures, the length of hydraulic fractures has been fitted using fracture parameter inversion method based on pump off pressure drop. (3) The simulation results indicate that the optimal construction parameters include a displacement of 8 m 3/min, perforation interval of 8–10 m, liquid volume of 910 m 3, and sand ratio of 10%–16%. (4) After fracturing and putting into operation, the duration of steady production extends by 8 years, and the cumulative gas production increases by 16.13×10 8 m 3, showing significant enhancement of fracturing results, which provides guidance for the development of similar blocks. Reference | Related Articles | Metrics

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Duan Jinbao, Xu Tianwu, Peng Jun, Wang Xuejun, Yuan Bo, Zhou Kai, Huang Lei, Zeng Chuanfu Exploration breakthroughs and implications of the Permian ultra-deep shale gas in Well Tiebei 1 L-HF, northeastern Sichuan Basin China Petroleum Exploration    2025, 30 (4): 44-58.   DOI: 10.3969/j.issn.1672-7703.2025.04.004 Abstract （416）   HTML    PDF （12818KB）（0）    Knowledge map    Save The Permian marine shale is widely distributed in (northeastern) Sichuan Basin, and the high-yield gas flow has been obtained in Well Tiebei 1 L-HF, with a daily gas rate exceeding 30×10 4 m 3 at a depth of greater than 5000 m in the northeastern basin, marking a major breakthrough in the exploration field of the ultra-deep shale gas. Based on the latest exploration results of Well Tiebei 1 L-HF, the regional sedimentary characteristics of the Permian Dalong Formation in the study area has been analyzed, and the geological characteristics of Dalong Formation shale gas has been studied. In addition, main controlling factors for shale gas enrichment and high-yield production in ultra-deep formation has been discussed, clarifying the further exploration orientation of Dalong Formation in the northeastern Sichuan Basin. The comprehensive study and evaluation show that the ultra-deep shale in the Permian Dalong Formation in the northeastern Sichuan Basin has the typical geological characteristics of “one multiplicity, three highs and one medium”, namely the development of multiple shale facies types, high TOC, high gas content, high brittleness and medium porosity. The reservoir space of Dalong Formation ultra-deep shale is dominated by nanoscale organic pores and microfractures, and the coupling distribution of “organic pores + microfractures” significantly enhances physical properties and fracability of ultra-deep shale gas reservoir. The main controlling factors for the enrichment and high-yield production of ultradeep shale gas have been identified, that is, the development of contiguous carbon-rich lithofacies is the foundation, the coupling control of organic pores and microfractures over reservoir is the key, and favorable preservation conditions (ultra-high pressure sealing) are the external manifestation of gas enrichment. By adopting seismic imaging technology for the sub-salt steep structures and reservoir stimulation method of “175 MPa equipment for enhanced net pressure, multi-size grading strong proppants, and high-viscosity/high pumping rate for transverse fracture penetration”, it has achieved an 100% drilling rate of sweet spots and large-scale effective reconstruction of ultra-deep shale gas reservoir. This breakthrough marks that the shale gas exploration in China has stepped into the field of ultra-deep formation. It further confirms that there are abundant shale gas resources in ultra-deep formations in Sichuan Basin, which is an important replacement field for natural gas exploration and development in China. Reference | Related Articles | Metrics

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Deng Ze, Zhao Qun, Li Cong, Ma Limin, Zhang Lei, Ding Rong, Fei Shixiang, Huang Daojun, Huang Jinxiu, Wang Shuhui, Zhang Xianmin Study and application of active pressure-control production method for coal-rock gas wells China Petroleum Exploration    2025, 30 (6): 185-200.   DOI: 10.3969/j.issn.1672-7703.2025.06.013 Abstract （400）   HTML       Knowledge map    Save Compared with shallow–middle coal seams, deep coal reservoirs exhibit significant differences in gas–water occurrence, production mechanism, and engineering response. In the in-situ high-pressure deep formations, free gas mainly flows through continuous media. The variations in reservoir pressure and bottom-hole flowing pressure directly influence gas–water distribution, migration driving force, and production capacity change law. Therefore, a rational pressure-control regime enhances gas flow and production capacity. Based on the control of pressure evolution on coal-rock gas migration mechanism, an active pressure release and production control method centered on differentiated bottom-hole pressure regulation has been proposed. By establishing a critical fracturing fluid pressure difference model, criteria for iso-flow and iso-pressure point recognition, and a dynamic gas–water ratio identification model, this approach reveals the fluid migration characteristics and pressure difference control rules across different production stages, and forms a staged bottom-hole pressure control system, that is, “safe open flow–steady water drainage–coordinated gas production–enhanced and steady gas production”, achieving dynamic matching of pressure system with flow mechanism and desorption kinetics in the whole production process. Numerical simulations of typical coal-rock wells in the eastern margin of Ordos Basin confirm that the active pressure-control strategy enables to gradually release and effectively utilize reservoir energy, achieving a “multi-peak” growth of gas production profile, with the predicted recovery factor increased by approximately 8.9% compared with non-production-control regime. Field tests further demonstrate that the staged and graded pressure release effectively slows the pressure decline, mitigates rapid gas–water ratio increase, maintains two-phase flow balance, and gradually releases production capacity, significantly enhancing single-well capacity and steady-production duration. The study results provide a theoretical basis and engineering guidance for high-efficiency development of coal-rock gas in Ordos Basin. Reference | Related Articles | Metrics

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Yang Chen, Shi Jianchao, hen Xiaodong, Jing Wenping, Zhang Baojuan, Xie Qichao, Shi Jian Genesis of low-resistivity oil reservoir in the eighth member of Yanchang Formation and research and application of artificial intelligence oil–water identification method in the middle section of the western margin of Ordos Basin China Petroleum Exploration    2025, 30 (5): 173-186.   DOI: 10.3969/j.issn.1672-7703.2025.05.013 Abstract （393）   HTML    PDF （17853KB）（0）    Knowledge map    Save In Huanjiang–Hongde–Yanwu area in the western margin of Ordos Basin, oil reservoirs were widely developed in the eighth member of the Mesozoic Yanchang Formation (Chang 8 member), with huge reserve amount, which is a favorable replacement resource for further exploration and increasing reserves in the region. However, the electrical resistivity of Chang 8 member oil reservoir generally ranges in 3–15 Ω·m, and the resistivity ratio between oil layer and water layer is lower than 2, showing low contrast ratio, and leading to great difficulty in oil layer identification. The conventional logging interpretation method has a low accuracy, which is unable to meet the needs of high-efficiency reserve increase and capacity construction. Based on a large amount of well drilling, core data, 3D seismic data, and comparative analysis of logging curves, the genesis of Chang 8 member low-resistivity oil reservoir has been studied from the perspectives of structural evolution and mineralization characteristics. The study results indicate that Chang 8 member low-resistivity oil reservoir in the western margin of Ordos Basin was mainly caused by high salinity of formation water and high saturation of bound water. By using an artificial neural network model and variables of six key logging parameters, two sensitive parameters have been introduced, i.e., Q Rw and PC 1, and a machine learning model has been established to prepare a cross plot between them, obtaining good distinguishment results among oil layer, oil–water layer, and water layer, with an accuracy of reservoir fluid type recognition improved to 88.9%. Reference | Related Articles | Metrics

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Li Guoxin, He Xinxing, Zhao Qun, Zhang Junfeng, Zhang Guosheng, Zhang Lei, Xu Wanglin, Zhang Bin, Yang Zhi Geological characteristics, depositional environment, and differential reservoir storage capacity of laminated shale in Huanghua Depression, Bohai Bay Basin China Petroleum Exploration    2025, 30 (5): 1-16.   DOI: 10.3969/j.issn.1672-7703.2025.05.001 Abstract （384）   HTML    PDF （13828KB）（23）    Knowledge map    Save The development of laminae is one of the typical characteristics of continental shale in faulted lake basins in eastern China. Three sets of shale layers were developed in the second member of the Paleogene Kongdian Formation (Kong 2 member), the third member of Shahejie Formation (Sha 3 member) and the first member of Shahejie Formation (Sha 1 member) in Huanghua Depression, Bohai Bay Basin, which were deposited in different sedimentary environments, thus forming different laminae units. The oil-bearing property, reservoir storage capacity and fracability vary, which restricts the exploration and development achievements of shale oil. Based on core samples, wireline logging and mud logging data of three sets of shale layers in Huanghua Depression, basic geochemical and rock mineral analysis has been conducted, and multi-scale fine characterization on various types of shale laminae has been implemented by comprehensively using technical measures such as AMICSCAN mineral scanning, high resolution scanning electron microscopy, energy spectrum elements, micro-CT scanning, and true triaxial hydraulic fracturing simulation, clarifying the depositional environment, reservoir storage capacity, flow capacity and fracability of different types of laminated shale. The study results show that Kong 2 member shale is mainly composed of felsic shale, as well as mixed shale and a small amount of limy-dolomitic shale; Sha 3 member shale is dominated by mixed shale, with felsic shale; Sha 1 member shale is mainly mixed shale, with a small amount of limy-dolomitic shale and felsic shale. The felsic laminae are mainly observed in Kong 2 member shale, with a small amount of limy-dolomitic laminae and clay laminae. The limy-dolomitic laminae and clay laminae are dominant in Sha 3 member shale, with a small amount of felsic laminae. While the dolomitic laminae are dominant in Sha 1 member shale, with a small amount of felsic laminae and clay laminae. The clay laminae generally have high organic matter content, and are responsible for hydrocarbon generation in the microscopic source rock–reservoir system, which lays a foundation for shale oil enrichment. The felsic laminae and limy-dolomitic laminae usually have high storage capacity, serving as the reservoir part in the microscopic source rock–reservoir system, providing reservoir and storage space for shale oil. Compared with layered and massive shale, shale reservoirs with high-frequency lamination have larger specific surface area, larger area for hydrocarbon charging, better pore connectivity, and an overpressure state due to the constant hydrocarbon generation and pressurization. In addition, the micron-scale dissolution pores of feldspar and dolomitic minerals were formed by organic acids in the process of hydrocarbon generation, which improved physical properties of shale reservoirs. The physical fracturing simulation experiments show that the laminated felsic shale has the best fracturing effect, followed by the laminated mixed shale, while the massive limy-dolomitic shale has the poorest fracturing results. Reference | Related Articles | Metrics

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Liang Shunjun, Wo Yukai, Sun Fu, Diao Yongbo, Wu Furong, Zhang Xiong, Liu Dingjin, Peng Cai, Li Jinzhi, Dong Tongwu, Bai Luofei, You Liwei Analysis of the main controlling factors for well–seismic depth error accuracy and discussion on new quantitative indicators: a case study of oil and gas exploration in Sichuan Basin China Petroleum Exploration    2025, 30 (3): 140-153.   DOI: 10.3969/j.issn.1672-7703.2025.03.010 Abstract （380）   HTML    PDF （10954KB）（0）    Knowledge map    Save According to the “Technical Specification of Seismic Data Interpretation” (GB/T 33684-2017), oilfield companies use the accuracy of well–seismic depth errors as an important indicator for assessing the precision of seismic interpreted structure results. There are two problems during the implementation process. Firstly, the absolute error and relative error accuracies are artificially specified in the national standard, lacking certain theoretical basis and technical support, which has a low operability in actual practice; Secondly, oilfield companies have established corresponding enterprise standards, with the continuously higher accuracy requirements of well seismic–depth errors far exceeding the vertical seismic resolution. Based on the practice of oil and gas exploration in Sichuan Basin, four main controlling factors that affect well–seismic depth errors are deeply analyzed, including (1) migrated imaging methods; (2) velocity errors in variable-speed depth conversion; (3) horizon calibration; and (4) vertical resolution of seismic exploration. The absolute error of well–seismic depth is related to the magnitude of the longitudinal resolution wavelength λ in seismic exploration. Therefore, based on the wavelength theory of vertical resolution in seismic exploration, and targeted at various exploration stages (exploration, appraisal, development, and fine development) of oil fields, different fractional values of seismic wavelength ( λn and Kλn) can be taken as important reference indicators for the absolute and relative errors of well–seismic depth, which is operable in practice and can be used as a reference for oil field managers to assess the accuracy of seismic interpreted structure results. Reference | Related Articles | Metrics

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Huang Hongxing, Shi Juntai, Chen Guohui, Wang Feng, Tao Ziqiang, Liu Ying, Zhu Wentao, Li Xiaogang, Zhao Haoyang, Chang Yihang, Lin Haikun, He Rui Characteristics of gangues in deep No.8 coal seam and their relationship with production capacity in Daning–Jixian block, Ordos Basin China Petroleum Exploration    2025, 30 (4): 108-119.   DOI: 10.3969/j.issn.1672-7703.2025.04.008 Abstract （365）   HTML    PDF （13734KB）（0）    Knowledge map    Save The deep No.8 coal seam in Daning–Jixian block in the eastern Ordos Basin demonstrates promising exploration potential. However, there is unclear understanding of the distribution characteristics and influence mechanisms on production capacity of the well-developed coal gangues. The high-precision identification and characterization of gangues in No.8 coal seam have been conducted by full-diameter spiral CT scanning for core section from eight wells in the study area, as well as coal rock laboratory data such as proximate analysis, pore structure, and mineral composition. Furthermore, a comprehensive evaluation has been performed on the development characteristics of gangues and their relationship with gas content, reservoir sensitivity, and production capacity. The results indicate that gangues in No.8 coal seam are extensively distributed in Daning–Jixian block, with a thickness proportion of approximately 25.16% in individual wells, a density of about 2.3 layers/m, a single-layer thickness of 0.02–1.57 m (generally <1 m), and the cumulative thickness of 0.20–2.66 m. The gangues are featured by low carbon content, low proportion of micropores, and poor adsorption performance, resulting in weaker gas generation and adsorption capacity compared to coal seams. The average clay mineral content in gangues is 61.61%, dominated by illite/montmorillonite mixed-layer minerals, kaolinite, and illite, which are prone to water and velocity sensitivity, adversely affecting the stability and effectiveness of post-fracturing flow pathways. It shows distinctly negative correlation between gangue content, average thickness, maximum single-layer thickness, and daily gas production. The study concludes that the gangues not only reduce the overall organic content of coal seams but also enhance reservoir heterogeneity and sensitivity, ultimately reducing well production capacity. These findings provide a scientific basis for optimizing hydraulic fracturing design and rational drainage strategy of deep coalbed methane in Daning–Jixian block. Reference | Related Articles | Metrics

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Liu Chang, Zhu Rukai, Li Binhui, Zhang Jinyou, Zhang Jingya, Bai Bin Microscopic differential distribution characteristics and accumulation mechanism of Gulong shale oil in Qingshankou Formation in the deep lake area, Songliao Basin China Petroleum Exploration    2025, 30 (5): 87-100.   DOI: 10.3969/j.issn.1672-7703.2025.05.007 Abstract （360）   HTML    PDF （12066KB）（0）    Knowledge map    Save Qingshankou Formation shale oil in Gulong Sag in the northern part of Songliao Basin (referred to as Gulong shale oil) exhibits distinct microscopic migration and differential accumulation characteristics, which affect the distribution and enrichment of retained movable hydrocarbons. The geochemical characteristics of washing oil products and pore structure of sealed and pressurized core sequences from key wells in deep lake area have been systematically tested to clarify the micro distribution characteristics of hydrocarbons and reveal the migration and accumulation mechanism of Gulong shale oil. The study results suggest that Gulong shale in the deep lake area has a grain size of smaller than 63 μm, and four lithofacies are subdivided, i.e., layered clayey shale, laminated mixed shale, laminated felsic shale, and layered calcareous shale. Based on the ranking of shale retention hydrocarbon content, the layered clayey shale with high TOC (>2%) has a high total hydrocarbon content (2.8–13.7 mg/g), and the movable hydrocarbon (2.8–12.5 mg/g) mainly occurs in intercrystal pores of clay minerals smaller than 32 nm. The laminated mixed and felsic shale with medium–high TOC (>1%) has a total hydrocarbon content of 3.8–7.3 mg/g, and the movable hydrocarbon (2.7–6.4 mg/g) mainly occurs in pores with diameters smaller than 8 nm and larger than 64 nm in the mixed laminae. The laminated felsic shale with low TOC (<1%) contains only a small amount of movable hydrocarbon (3.1–4.6 mg/g), mainly occurring in pores with a diameter greater than 64 nm and only a small amount in pores less than 8 nm. The distribution of organic matter laminae and later diagenesis are the key factors for the differential hydrocarbon distribution and accumulation. The organic matters were enriched in clayey laminae, and the generated hydrocarbon was preferentially retained in situ in organic matter pores and clay intercrystal pores. Part of the movable hydrocarbon migrated to felsic laminae or carbonate mineral laminae within source rocks. In areas with strong dissolution and well-developed pores, the movable hydrocarbon migrated on a large scale. While in areas with strong clay and carbonate rock cementation and undeveloped pores, the migration amount of movable hydrocarbon was small. Based on the movable hydrocarbon distribution and accumulation mechanism of Gulong shale oil, it can be further clarified that the high-TOC layered clayey shale has a high oil content but small pore size, which is a resource sweet spot, but the low-TOC laminated felsic shale has a low movable oil content; The medium-high TOC laminated mixed shale and felsic shale have a high movable oil content, large pore size and good fracability, which is the resource and engineering dual sweet spot. Reference | Related Articles | Metrics

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Liu Zhongbao, Shen Zhenhuan, Li Peng, Shen Baojian, Liu Yali, Ma Xiaoxiao, Tao Jia, Li Pei, Qian Menhui, Zhang Wentao, Ge Xiaotong, Wu Zhoufan Lithofacies and reservoir pore characteristics of continental shale oil and influencing factors China Petroleum Exploration    2025, 30 (5): 68-86.   DOI: 10.3969/j.issn.1672-7703.2025.05.006 Abstract （349）   HTML    PDF （21524KB）（0）    Knowledge map    Save Significant progress has been made in the exploration and development of continental shale oil in China, which has become a major field for increasing oil reserves and production. In order to investigate continental shale lithofacies and reservoir pore development characteristics and their influencing factors, two main types of shale have been studied and compared, including the mixed shale in the Lower sub-member of the third member of Shahejie Formation (Lower Sha 3 sub-member) in Bonan subsag in Jiyang Depression and the second member of Funing Formation (Fu 2 member) in Gaoyou Sag in Subei Basin, as well as the matrix shale in Dongyuemiao member and the second member of Lianggaoshan Formation (Liang 2 member) in Fuxing area in Sichuan Basin. Based on core observation and description, multiple experimental and testing techniques such as bulk rock mineral X-ray diffraction, thin section, micro area XRF, high-pressure mercury injection–low-temperature nitrogen adsorption joint measurement, micro CT, argon ion polishing scanning electron microscopy, and overburden porosity have been used to comprehensively characterize and analyze the lithofacies and reservoir pores of continental shale, and identify influencing factors for reservoir pore development. The study results indicate that multi-component and multi-scale sedimentary structures were developed in continental shale. Controlled by the alternating input of terrestrial and endogenous materials, the sedimentary structure combination types and lithofacies types of mixed shale are more abundant and diverse than the matrix shale. In Bonan subsag, the lithofacies is mainly composed of layered carbonate mixed shale, layered felsic mixed shale, laminated carbonate shale, and massive carbonate shale. In Gaoyou Sag, it is mainly composed of laminated felsic mixed shale, laminated carbonate shale, layered felsic shale, and massive clayey mixed shale. In Fuxing area, it is mainly composed of massive clayey shale, laminated shell carbonate shale, or laminated felsic shale. Based on the differences in pore carriers, the pore classification scheme for continental shale oil reservoirs has been established, proposing that pores can be formed in various inorganic minerals and organic matter components in continental shale, with the most favorable pore carriers of carbonate minerals and clay minerals. In Bonan subsag, pores are dominated by carbonate mineral pores. In Gaoyou Sag, they are mainly carbonate mineral pores and felsic mineral pores. In Fuxing area, pores are mainly clay mineral pores and carbonate mineral pores. The high-quality lithofacies was the foundation for pore development, and differences in mineral composition, structure, and sedimentary structures all affected the degree of pore development. The pores were well developed in massive clayey (mixed) shale and laminated carbonate (mixed) shale, fairly developed in laminated (layered) felsic (mixed) shale, but poorly developed in massive carbonate (mixed) shale; The diagenetic type and evolutionary sequence were key factors controlling the formation and preservation of reservoir pores. The rigid mineral particles were stacked in layers or locally mixed to form anti compaction support structures, which were beneficial for pore preservation, while the common pore increasing process included clay mineral transformation and carbonate mineral dissolution. In Bonan subsag and Gaoyou Sag, inorganic pores in mixed shale were mainly controlled by compaction, recrystallization, and dissolution, but there were basically no organic matter pores; In Fuxing area, the inorganic pores of matrix shale were controlled by compaction, clay mineral transformation, and shell calcite dissolution, and organic matter pores were developed in bitumenite. Reference | Related Articles | Metrics

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Nie Zhihong, Wang Dezhi, Xiong Xianyue, Ji Liang, Zhou Changhui, Deng Yonghong, Wang Wei, Song Yinan, Huang Yangyang, Gao Xicheng, Xu Chengchao, Xing Xuejie High-efficiency development strategy and engineering practice of deep coal-rock gas by clustered vertical–deviated wells: a case study of Yichuan well area in Daning–Jixian block China Petroleum Exploration    2025, 30 (4): 120-140.   DOI: 10.3969/j.issn.1672-7703.2025.04.009 Abstract （348）   HTML    PDF （5351KB）（0）    Knowledge map    Save The development of deep coal-rock gas using clustered vertical–deviated wells faces challenges such as unclear controlling factors for production capacity, and significant differences in single-well production, which restrict the high-efficiency utilization of deep coal-rock gas resources in areas with multi-set thin coal rocks developed. In order to enhance the single-well production, a total of 105 clustered vertical–deviated wells in Daning–Jixian block has been studied to systematically identify the controlling factors for production capacity. Through single-factor analysis, law of production capacity control of 11 geological and engineering parameters has been clarified, among which resource abundance and reservoir fracability are the geological foundation for high-yield production. Furthermore, multivariate linear regression analysis and decision tree model have been combined to identify four engineering controlling factors, i.e., total sand volume, construction pressure, well shut-in period, and post-fracturing assisted fluid flowback volume. On this basis, a cultivation pathway for high-yield wells has been established following the strategy of “deployment optimization–intense reservoir reconstruction–damage control–efficiency enhancement”, and the high-efficiency well development technology system has been developed, centered on collaborative geological and engineering sweet spot zone selection, large-scale volume fracturing and reservoir reconstruction, post-fracturing rapid flowback for filtration control, and multi-source energy coupling assisted drainage and pressure release. In addition, the supporting engineering organization strategies have been proposed, including advanced artificial lifting operation, staged surface engineering construction, and multi-process coordinated execution, forming a lifecycle high-efficiency development mode for clustered vertical–deviated wells. This technology system has been applied to Yichuan well area, obtaining significant achievements, with the average single-well gas rate increased from 0.8×10 4 m 3/d to 1.8×10 4 m 3/d, EUR reaching up to 2000×10 4 m 3, significantly improved reservoir pressure release efficiency, and constantly enhanced steady production capacity. The study results provide systematic technical support for the high-efficiency development of deep rock gas in Yichuan well area and offer a reference path and practical basis for large-scale application of the technology system in similar blocks. Reference | Related Articles | Metrics

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Li Mingrui, Xiao Dongsheng, Ma Qiang, Kang Jilun, Li Shilin, Zhang Wei, Wang Lilong Hydrocarbon accumulation characteristics and exploration orientation of the Permian–Triassic composite petroleum system in the eastern Fukang Sag, Junggar Basin China Petroleum Exploration    2025, 30 (6): 1-12.   DOI: 10.3969/j.issn.1672-7703.2025.06.001 Abstract （344）   HTML       Knowledge map    Save In recent years, significant breakthroughs have successively been achieved in the petroleum exploration of the Permian–Triassic in the eastern Fukang Sag, Junggar Basin. However, the distribution pattern of deep oil and gas remains unclear, and the accumulation mechanism is complex, leading to a series of exploration challenges. Based on the latest exploration achievements, and integrated with seismic interpretation, drilling data, and geological experimental analysis, a systematic study has been conducted on source rock characteristics, tectonic evolution history, oil and gas reservoir type and distribution pattern, and hydrocarbon accumulation mechanisms in the study area. The study results indicate that the Permian–Triassic in the eastern Fukang Sag exhibits a composite hydrocarbon accumulation pattern characterized by “one set of source rock and multi-set reservoirs, vertical superposition of multiple layers, and planar continuity of multiple traps and diverse oil and gas reservoirs”. Vertically, centered on the high-quality source rocks in the Permian Lucaogou Formation, a multi-type hydrocarbon accumulation system was developed in high-quality reservoirs in the intra-source Lucaogou Formation, near-source Upper Wuerhe Formation, and far-source Jiucaiyuan Formation. Laterally, the three sets of oil and gas reservoirs show similar distribution characteristics, generally including conventional oil and gas reservoirs in structural–lithologic traps in bulge zone, and tight oil and gas reservoirs in lithologic traps in slope–sag zone. The detailed analysis of typical oil and gas reservoirs further reveals that there are significant differences in transport system, reservoir type, and migration–accumulation mode across different layers. Guided by the newly established hydrocarbon accumulation mode, the Permian Upper Wuerhe Formation and the Triassic Jiucaiyuan Formation in Fuzhong subsag have optimally been selected as key exploration targets, and remarkable breakthroughs have been achieved in subsequent drilling operations, confirming promising prospects of large-scale reserve growth in Junggar Basin with a level of 100 million tons. Reference | Related Articles | Metrics

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Liu Baolei, Zhang Xinyi Research progress in oil and gas production forecast method and technology China Petroleum Exploration    2025, 30 (5): 128-144.   DOI: 10.3969/j.issn.1672-7703.2025.05.010 Abstract （340）   HTML    PDF （4499KB）（2）    Knowledge map    Save Oil and gas production forecast is a critical technical approach for optimizing development strategy and enhancing recovery factor of oil and gas fields. The theoretical system of oil and gas production decline has systematically been reviewed, and a comparative evaluation between conventional empirical models and analytical methods has been conducted in terms of their theoretical foundations, applicability, and limitations. In addition, innovative application of machine learning in production forecast of complex reservoirs has been discussed in detail. The analysis results show that: (1) Traditional methods show robustness for conventional reservoirs but exhibit constrained application performance in unconventional oil and gas reservoirs due to strong heterogeneity and nonlinear multiphase flow; (2) The data-driven models demonstrate superior prediction performance for unconventional reservoirs through automated feature extraction and spatiotemporal correlation modeling; (3) The physical-informed hybrid models effectively integrate data-driven advantages with physical mechanisms, delivering enhanced reliability in complex conditions and long-term production forecast. The study concludes that artificial intelligence significantly improves prediction accuracy and reliability in oil and gas production forecast, with machine learning and deep learning offering novel technical support for complex reservoir development. However, challenges persist in engineering applications, particularly in real-time computation and model interpretability, where further interdisciplinary research is needed on artificial intelligence and oil and gas domain to promote intelligent and high-quality development of the oil and gas industry. Reference | Related Articles | Metrics

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Gao Min, Zhang Zhongmin, Wang Tong, Wu Gaokui, Cao Zhe, Shi Danni Characteristics of deep structures, identification of paleo uplifts and exploration significance in Persian Gulf Basin China Petroleum Exploration    2025, 30 (5): 56-67.   DOI: 10.3969/j.issn.1672-7703.2025.05.005 Abstract （337）   HTML    PDF （10228KB）（0）    Knowledge map    Save The deep paleo uplifts in Persian Gulf Basin controlled the development of giant low-amplitude anticlines, which further controlled the formation of world-class large oil and gas fields. It is urgent to delineate the distribution of deep paleo uplifts and faults, and analyze their control over oil and gas distribution. Based on the wavelet analysis of high precision EGM free air gravity data, 36 paleo uplifts have been identified in Central Arabian, Rub’ al-Khali and Zagros sub-basins, which are classified into three stages based on their formation and evolution processes, i.e., Precambrian, Late Devonian–Early Carboniferous, and Miocene–Pliocene. The first and second stages of paleo uplifts controlled the development of the Precambrian–Devonian anticlinal traps, the Devonian truncated unconformity–lithologic traps, and the Periman–Cretaceous anticlinal traps. While the third stage of paleo uplifts controlled the development of the Miocene–Pliocene drape anticlinal traps. By combining with the configuration relationship of hydrocarbon accumulation conditions in Persian Gulf Basin, favorable exploration areas have been predicted, including 16 oil and gas reservoirs in the Paleozoic, 26 oil and gas reservoirs in the Jurassic and 16 oil and gas reservoirs in the Cretaceous. This study provides reference for deep oil and gas exploration in Persian Gulf and similar basins. Reference | Related Articles | Metrics

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Qin Yanqun, Xiao Kunye, Chen Zhongmin, Yuan Shengqiang, Wang Li, Ou Yafei, Yang Yu, Zhou Hongpu Execution, implementation essentials and insights of Eni’s“Dual Exploration Model” China Petroleum Exploration    2025, 30 (6): 58-69.   DOI: 10.3969/j.issn.1672-7703.2025.06.005 Abstract （316）   HTML       Knowledge map    Save Under the dual pressures of global energy transition and low oil price cycles, major oil and gas companies worldwide face survival challenges, including shrinking exploration investments and tight cash flows. By innovatively developing a “Dual Exploration Model”, Italy’s Eni Group has leveraged its technical advantages in deep-water fields and achieved early value realization through equity sales after exploration discoveries, successfully establishing a closed-loop system of “discovery–monetization–rediscovery”. The connotation, execution status, and implementation essentials of the model have systematically been reviewed, and typical case studies from Mozambique, Egypt, and C?te d’Ivoire have been analyzed to reveal its path of achieving low-cost discoveries and high-efficiency development through technology-driven approaches, capital optimization, and strategic coordination. The study results show that the “Dual Exploration Model” is featured by the foundation of low cost and major discoveries, essence of high equity and fast monetization, and guarantee of retaining operator status and risk diversification. The main implementation process consists of three stages (block acquisition, independent exploration, and self-recycling) and 10 detailed steps. It is applicable for low oil price periods but requires specific resource, pipeline, policy, capital, and technical conditions. Currently, it still faces numerous challenges including scarce resources, external market environment, and internal technical capabilities. Based on the current status of CNPC’s overseas oil and gas assets, it is proposed that full-lifecycle assessment systems and equity management matrices should be established for current projects and a new business philosophy of “sustainable monetization” should be formed when acquiring new projects. Reference | Related Articles | Metrics

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Han Yaqin, Mao Junli, Wang Qiaohong, Du Jindu, Gao Yang, Wang Weiming, Li Wenbo Analysis of the impact of the new mineral resources law on oil and gas mining rights holders China Petroleum Exploration    2025, 30 (5): 17-21.   DOI: 10.3969/j.issn.1672-7703.2025.05.002 Abstract （315）   HTML    PDF （1076KB）（21）    Knowledge map    Save The newly revised “Mineral Resources Law of the People’s Republic of China” in 2024 (hereinafter referred to as the “New Mineral Resources Law”) has made systematic and reconstructive modifications to the approach of mineral resources management, which has established a whole-chain management system of mineral resources including mining rights, mineral resource exploration and exploitation, ecological restoration of mining areas, mineral resource reserves and emergency, and supervision and administration. Based on a systematic review of the legal provisions related to oil and gas in the New Mineral Resources Law, the content of the provisions has been interpreted from five aspects, i.e., the special protection system for strategic mineral resources, the management model of mining rights transfer registration and administrative licensing, key systems for mining rights management, policy support for exploration and exploitation, and the fulfillment of mining rights holders’ obligations. Meanwhile, the impact of these systems mentioned above on oil and gas mining rights holders has been analyzed. After investigation and data analysis, it is proposed that under the New Mineral Resources Law, oil and gas mining rights holders should implement the special protection system for strategic mineral resources, timely transform the management ideas of oil and gas mining rights transfer, registration, and licensing, properly grasp the key systems of oil and gas management, utilize the supporting policies for oil and gas exploration and exploitation, fulfill the obligations of oil and gas mining rights holders, and promptly offer countermeasures and suggestions for the promulgation of the mineral resources law and regulations. Reference | Related Articles | Metrics

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Zheng Yiqiong, Ruan Conghui, Liu Bin, Zheng Bin, Liu Haiying Comparative study of unconventional oil and gas policies between China and the United States and implications and suggestions China Petroleum Exploration    2025, 30 (6): 13-28.   DOI: 10.3969/j.issn.1672-7703.2025.06.002 Abstract （307）   HTML       Knowledge map    Save At present, against the backdrop of global oil and gas development entering the unconventional era, the practice and insights of the United States’ fiscal, tax, and industrial policies for unconventional oil and gas, which have facilitated its rapid development, have attracted considerable attention from both industry and academia. As a result, a comparative study of unconventional oil and gas policies between China and the United States has been conducted to analyze their similarities and differences, and policy suggestions for the development of unconventional oil and gas in China have been proposed. The study results indicate that the United States has implemented a series of preferential policies for unconventional oil and gas that are substantial in scope and long-lasting in duration. These policies are characterized by forward-looking nature, sustainability, significant effectiveness, and synergistic relationship with technological advancements, serving as a key driver behind the success of the U.S. shale revolution and even its energy independence. The comparison of unconventional oil and gas policies between China and the United States shows similarities in terms of policy background, objectives, supporting routes, and the reliance on market mechanisms as a policy prerequisite. In contrast, China’s unconventional oil and gas policies lack systematic coordination, and the development of unconventional oil and gas industry is unable to seamlessly align with policy implementation. In terms of unconventional gas, although subsidy policies have been in place for many years and remarkable results have been achieved, policy continuity remains insufficient. Regarding unconventional oil, the current targets for shale oil development are increasingly deteriorated in quality, leading to greater technical difficulties and cost reduction challenges. However, policies for shale oil development are basically absent. In reality, supporting policies for unconventional oil and gas development are a systematic project, and policy design and implementation require national policy support, cultivation by local governments, assistance from their parent groups, and quality and efficiency improvement by the oil and gas field companies themselves. Through a “four-in-one” integrated policy linkage development model, the fiscal and tax policy system for unconventional oil and gas in China can be promoted and refined. Reference | Related Articles | Metrics

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Liu Honglin, Wang Huaichang, Huang Daojun, Zhao Qun, Li Xiaobo Vesicle genesis and characteristics of gas accumulation and enrichment in deep coal rock reservoirs in Ordos Basin China Petroleum Exploration    2025, 30 (4): 92-107.   DOI: 10.3969/j.issn.1672-7703.2025.04.007 Abstract （306）   HTML    PDF （9887KB）（0）    Knowledge map    Save The deep coal rocks are widely distributed in Ordos Basin, showing a major replacement field for natural gas exploration and development. However, with the increasing burial depth, the temperature, field stress and hydrogeological conditions of deep formations vary greatly, resulting in great differences in gas accumulation law between deep coal rocks and shallow coal rocks. Regarding the particularity of gas accumulation in deep coal rocks, there are insufficient studies on pore structural characteristics and genesis, gas accumulation types and enrichment characteristics. The experimental analysis on coal rock marcels and scanning electron microscopy have been conducted. The results show that No.8 coal seam in Benxi Formation was mainly deposited in lagoon–tidal flat sedimentary environments, with a thickness of 8–22 m in the northeast and 2–6 m in the southwest, a high vitrinite content of 78.5% on an average, and an increasing maturity from northeast to southwest. The porosity of deep coal reservoir ranges in 3.65%–5.84%. The formation of vesicles was controlled the type of coal swamps, and it was affected by formation water vaporization and rapid hydrocarbon generation of coal rocks. There are multiple types of coal-rock gas reservoirs in deep formations, such as microstructural gas reservoir and anticlinal gas reservoir. The gas content of coal rocks increases from northeast to southwest, with a critical point at a depth of about 2000 m. The gas content distribution of coal rocks was affected by coal-forming swamp facies zones. The gas content of coal rocks with a silty mudstone roof is better than those with limestone and sandstone roofs. In addition, it is proposed that a geological evaluation system for deep coal-rock gas with the core of pore development, a geophysical prediction technology with the core of pore development zone and gas enrichment zone, and a horizontal well fracturing design and targeted production technology for vesicle developed reservoir should be researched and developed, so as to accelerate the beneficial development of deep coal-rock gas. Reference | Related Articles | Metrics

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Zhang Hong Research progress of the Ediacaran fibrous dolomite in China China Petroleum Exploration    2025, 30 (5): 112-127.   DOI: 10.3969/j.issn.1672-7703.2025.05.009 Abstract （304）   HTML    PDF （15581KB）（0）    Knowledge map    Save The Ediacaran represented a key period of paleo ocean and paleoclimate evolution, and the extensively developed fibrous dolomites provided important evidences for reconstructing the oceanic chemical characteristics in this stage. The genetic types and discrimination criteria of fibrous dolomite have been discussed, focusing on the distribution, genetic mechanism, and paleo environmental significance of the Ediacaran fibrous dolomite in China. Multidimensional properties such as petrological characteristics, crystallographic properties, and geochemical composition are important criteria for identifying the dolomite genesis. The primary fibrous dolomites are typically characterized by fibrous structure, and length-slow optical properties, with well-developed growth girdles. While the secondary metasomatic fibrous dolomites commonly show acicular, botryoidal patterns or square terminations, with length-fast optical properties, but underdeveloped growth girdle. In addition, trace element content to some extent provides indicative significance in distinguishing genetic types of dolomites. Multiple types of fibrous dolomites have been identified in the Ediacaran base (first member of Doushantuo Formation) and top (second and fourth members of Dengying Formation) in Yangtze Plate, as well as in the upper Qigebulake Formation in Tarim Basin, including bladed dolomite, fascicular–length-fast dolomite, radial–length-fast dolomite, fascicular–length-slow dolomite and radial–length-slow dolomite. The former three types were mainly generated by secondary metasomatism of aragonite or high magnesium calcite, while fascicular–length-slow dolomite and radial–length-slow dolomite were more likely to be primary dolomites directly precipitated from paleo seawater or marine pore water. In the Ediacaran, seawater was featured by high Mg/Ca ratio, elevated alkalinity and low sulfate concentration, promoting the precipitation of fibrous aragonite and high magnesium calcite precursors. Evaporation further increased the Mg/Ca ratio, while metabolism of sulfate reducing bacteria in hypoxic environments released Mg2+ and increased pH and alkalinity, which effectively overcame precipitation barriers, thereby facilitating the nucleation of primary fibrous dolomites. In summary, the Ediacaran fibrous dolomites in China generally recorded critical geochemical signatures of contemporaneous seawater or marine pore water, and in some cases reflected the involvement of hydrothermal fluids. Their geochemical information effectively reveal the redox state, provenance, and temporal–spatial evolution of the Ediacaran ocean, offering critical geological evidence for reconstructing the Precambrian oceanic chemical system and assessing its environmental constraints on early life evolution. Reference | Related Articles | Metrics

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Bai Tong, Chen Guowen, Liu Kang, He Yan, Li Xiang, Yang Qingning, Jiang Kaiyue Progradation characteristics of Yanchang Formation and petroleum exploration significance in the southwestern margin of Ordos Basin China Petroleum Exploration    2025, 30 (5): 101-111.   DOI: 10.3969/j.issn.1672-7703.2025.05.008 Abstract （299）   HTML    PDF （11239KB）（0）    Knowledge map    Save In the southwestern margin of Ordos Basin, progradation seismic reflection features of Yanchang Formation are extensively observed in 3D seismic profile. By comprehensively using geological data such as well drilling, logging, and core section, well–seismic data has been combined to conduct stratigraphic correlation and division, and analyze the sedimentary evolution of progradation layer, sand body distribution, and oil and gas distribution laws. The following understanding has been obtained: (1) Multi-stage progradation reflection features are observed in the seventh–third members of Yanchang Formation in the southwestern basin margin, which generally reflect the progradation characteristics of water regression and sand progradation. The deposition units are stacked in a tangential oblique pattern towards the lake basin center. After reconstructing a stratigraphic framework of Yanchang Formation, the traditional method of “isopachous” stratigraphic correlation has been changed; (2) The distribution characteristics of the two types of sand bodies in the southwestern basin margin were mainly controlled by the basin bottom shape. The comprehensive study of logging, seismic, and sedimentary facies shows that the upper and lower sections of the progradation layer in Yanchang Formation respectively controlled the distribution of delta front and gravity flow sand bodies, among which the gravity flow sand bodies are favorable reservoir types for large-scale exploration and development; (3) Based on the “two-wide and one-high” seismic information, the distribution of multi-stage deep-water gravity flow sand bodies in the progradation layer has been finely characterized, effectively identifying the distribution range of high-quality reservoirs, and determining that the slope foot sand-rich belt is a favorable area for increasing tight oil reserves on a large scale. The reservoir prediction method based on seismic progradation reflection structure analysis has important guiding significance for the exploration and development of tight oil with similar deep-water sedimentary backgrounds in China. Reference | Related Articles | Metrics

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Lin Xiaobo, Zhang Yanming, Ma Zhanguo, Xiao Yuanxiang, Su Yubin, Gu Yonghong, Wang Lili, Liu Xinjia, Zhao Bochao, Yan Zhichen Research on CO 2 Volume Fracturing and Process Parameter Optimization in Tight Sandstone Reservoirs China Petroleum Exploration    2025, 30 (5): 145-160.   DOI: 10.3969/j.issn.1672-7703.2025.05.011 Abstract （294）   HTML    PDF （6973KB）（0）    Knowledge map    Save There are a series of problems of tight sandstone reservoirs in Ordos Basin, such as poor physical properties, large burial depth, high clay mineral content, and great difficulty in post-fracturing backflow. CO 2 fracturing has advantages such as reducing rock fracture pressure, reducing fluid loss and promoting backflow, which is a targeted measure for reservoirs with poor physical properties, high clay content and low pressure coefficient. Therefore, based on the true triaxial simulation of tight sandstone fracturing reconstruction process with three different injection methods, i.e., CO 2 prepad, CO 2 foam injection, and CO 2 associated injection, the variation law of core fracture pressure and fracture distribution characteristics of tight sandstone reservoirs have been analyzed through similarity criterion, and the difference in core fracturing results has been compared. In addition, Petrel geological–fracturing integrated platform has been applied to conduct numerical simulation of reservoir fracture propagation with different CO 2 injection modes. The quantitative experimental analysis results show that the ranking of fracturing effects is as follows: hydraulic fracturing for rock breaking > CO 2 foam > CO 2 associated injection > CO 2 prepad. Compared with hydraulic fractures, fracture network is the most complex by using CO 2 prepad fracturing, followed by CO 2 foam, and it is the poorest by CO 2 associated injection, which is consistent with numerical simulation results. Furthermore, the variation law of reservoir fracture network parameters with fracturing operation parameters given the different injection methods has been clarified, and a fracturing parameter optimization plate has been prepared. The new understanding provides operational guidance and suggestions for the beneficial development of tight sandstone reservoirs. Reference | Related Articles | Metrics

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Fan Zhili, Shi Juntai, Wang Chunqi, Hao Pengling, Wang Yuchuan, Wang Tao, Wang Xiaodong, Dai Haoxiang, Yang Bo, Cao Jingtian Experimental study of permeability stress sensitivity and velocity sensitivity of deep coal seams in Linxing–Shenfu block, Ordos Basin China Petroleum Exploration    2025, 30 (4): 141-159.   DOI: 10.3969/j.issn.1672-7703.2025.04.010 Abstract （289）   HTML    PDF （4649KB）（1）    Knowledge map    Save In recent years, major breakthroughs have been achieved in deep coalbed methane (CBM) development. However, gas production varies significantly among deep CBM wells across various blocks and even in various well areas in the same block. One of the reasons lies in the differences in permeability changes of deep coal reservoirs in different blocks, while the permeability stress sensitivity and velocity sensitivity properties remain unclear. The full-diameter coal core plugs taken from deep formations in Linxing-Shenfu block have been used to conduct porosity–permeability measurements, stress sensitivity experiments, and velocity sensitivity experiments, obtaining permeabilities under different effective stresses and flow velocities. Based on the measured stress sensitivity data, the applicability of exponential, power-law, and logarithmic stress sensitivity models has been compared and evaluated, which enables to select the optimal permeability stress sensitivity model and establish a new standard for stress sensitivity evaluation. Additionally, the measured velocity sensitivity data has been applied to determine the parameters of permeability velocity sensitivity model, revealing the deep coal permeability velocity sensitivity property in Linxing-Shenfu block. The study results indicate that: (1) The deep coal seams in Linxing-Shenfu block exhibit typical characteristics of low porosity and low permeability, with the porosity range of 3.9%–9.1% (average of 6.5%) and gas permeability under low pressure of 0.9–2.1 mD (average of 1.63 mD). (2) The dynamic permeability changes with pressure follow an exponential trend, with the stress sensitivity index of 0.33–0.52 MPa -1. Based on the new stress sensitivity evaluation criteria (which classify stress sensitivity into six levels—none, weak, moderately weak, moderately strong, strong, and extremely strong using stress sensitivity boundaries of 0.01 MPa -1, 0.08 MPa -1,0.15 MPa -1, 0.23 MPa -1, and 0.45 MPa -1), the stress sensitivity degree of deep coal seams is classified as strong or extremely strong, so special consideration should be given to stress sensitivity effects in the process of optimization design of production regimes. (3) As the fluid flow rate increases, permeability decreases sharply initially and then declines slowly. The fitted critical plugging velocity ( v cr2) ranges in 0.01–0.11 m/d, the maximum damage degree ( D v,max) is 0.81–0.96, and the damage rate index ( n) is 0.40–1.05. Furthermore, the lower the original coal permeability, the lower the critical plugging velocity, the higher the maximum damage degree, and the smaller the damage rate index. The research findings provide a theoretical basis for production capacity evaluation and production regime design of deep CBM wells. Reference | Related Articles | Metrics

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He Wenjun, Pan Jin, Liu Chaowei, Wang Qiuyu, Li Hui, Chen Mengna, Li Peng, Wang Ning Geological characteristics and accumulation mode of the Jurassic deep coal-rock gas in Junggar Basin China Petroleum Exploration    2025, 30 (4): 78-91.   DOI: 10.3969/j.issn.1672-7703.2025.04.006 Abstract （279）   HTML    PDF （10616KB）（0）    Knowledge map    Save The Jurassic coal measures were well developed in Junggar Basin, which served as both good source rock and reservoir. A Well CT1H was drilled in Baijiahai Bulge, and high-yield gas flow was obtained in the Jurassic Xishanyao Formation coal rock reservoir, breaking through the traditional depth forbidden zone for CBM exploration and development at a depth greater than 2000 m, which indicated a new type of natural gas resource for increasing reserves and production on a large scale. Based on the exploration results of the Jurassic coal-rock gas in Junggar Basin, and combined with experimental methods such as casting thin section, scanning electron microscope, and nuclear magnetic resonance, a systematic study has been conducted on the geological characteristics and hydrocarbon accumulation pattern of deep coal-rock gas, and the future exploration orientation has been clarified. The study results show that two sets of main coal rocks, namely, coal rock No.2 in Xishanyao Formation and coal rock No.5 in Badaowan Formation, were developed in Junggar Basin. Xishanyao Formation coal rocks in the basin hinterland are characterized by low rank and primary structure, an average porosity of 17.25%, and poor gas generation capacity, while those in the southern basin margin are composed of medium-rank coal, with good connectivity of pores and a high proportion of free gas. Badaowan Formation coal rocks are characterized by medium rank and primary structure, with an average reservoir porosity of 3.12% and a proportion of adsorption gas of 89.75%. There are three main types of hydrocarbon accumulation patterns of the Jurassic deep coal-rock gas in the basin, i.e., allogenetic structural type, authigenic stratigraphic type, and authigenic structural type. The comprehensive study of geological conditions and gas accumulation control factors indicates that the favorable exploration area of deep coal-rock gas is 2385 km 2, and the predicted coal-rock gas resources are 4260×10 8 m 3 in Junggar Basin. The future exploration orientation of coal-rock gas includes Xishanyao Formation and Badaowan Formation in Dinan–Baijiahai area in the hinterland basin and Xishanyao Formation in the southern margin of the basin. Reference | Related Articles | Metrics

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Zhao Zhe, Fan Liyong, Huang Zhengliang, Cheng Dangxing, Hu Jianling, Chu Meijuan, Yan Wei, Hu Xinyou, Mao Zhiqi, Cao Jingjingi, Tian Lianjie Progress in oil and gas exploration during the 14 th Five–Year Plan period and future exploration orientations in Ordos Basin#br# China Petroleum Exploration    2026, 31 (1): 64-79.   DOI: 10.3969/j.issn.1672-7703.2026.01.006 Abstract （264）         Knowledge map    Save The conventional oil and gas exploration and development have dominated in Ordos Basin for a long time. With the increasing exploration level, it has gradually shifted to intra-source exploration. However, in response to the long-term demands for steady oil and gas production, exploration faces significant challenges. The major exploration progress, achievements, and key geological understanding of hydrocarbon accumulation in Ordos Basin since the 14 th Five–Year Plan period have systematically been reviewed: (1) Effective source rocks were developed in the Mesozoic, Upper Paleozoic, and deep formations in Ordos Basin. Among them, the Mesozoic and Upper Paleozoic source rocks have highly been proved, which served as the main source rocks for exploration. In addition, two sets of low-abundance source rocks were developed in the Ordovician, and both had large-scale hydrocarbon generation potential, in which Wulalik Formation source rock had a large thickness and continuous distribution, while the Ordovician inter-salt layer had a thin individual layer thickness but huge cumulative thickness. (2) Besides the strong hydrocarbon generation capacity, the innovative understanding has been formed that the three major stratigraphic sequences had favorable reservoir physical properties, marking a concept transformation from a simple source rock to a source rock–reservoir integrated system, and the intra-source or near-source accumulation was more conducive to gas enrichment. (3) Based on the exploration level and source rock proven degree, future exploration will be conducted in two tiers. The first tier focuses on the realistic exploration fields, including the Mesozoic shale oil, Upper Paleozoic coal rock gas, and western marginal Qingshimao tight gas; The second tier includes the replacement exploration fields such as the lower combination in the Mesozoic Yanchang Formation, Upper Paleozoic transitional facies shale gas, Ordovician inter-salt layer, Ordovician in the western basin, and Cambrian–Mesoproterozoic–Neoproterozoic. In the exploration practice, it is essential to deepen fundamental geological study and innovate hydrocarbon accumulation theory in new fields, while strengthening 3D seismic deployment, enhancing exploration supporting technologies, and optimizing reservoir stimulation techniques, so as to promote the large-scale reserve increase in realistic exploration fields and achieve breakthroughs in new formations and fields, providing resource guarantees for long-term steady oil and gas production in Ordos Basin. Reference | Related Articles | Metrics