In recent years, significant breakthroughs have been continuously achieved in the oil and gas exploration of the Permian–Triassic strata in the eastern Fukang Sag of the Junggar Basin. However, the distribution patterns of deep hydrocarbons remain unclear, the accumulation mechanisms are complex, and systematic exploration challenges persist. Based on the latest exploration results, integrated with seismic interpretation, drilling data, and geological experimental analyses, a systematic study was conducted on the characteristics of source rocks, tectonic evolution processes, types and distribution patterns of oil and gas, and accumulation mechanisms in the study area.Research indicates that the Permian–Triassic strata in the eastern Fukang Sag exhibit a composite accumulation characterized by “one source feeding multiple reservoirs, vertically stacked multi-layer systems, and planar continuity of multiple traps and diverse oil and gas reservoirs.”Vertically, centered on the high-quality source rocks of the Permian Lucaogou Formation, a multi-type hydrocarbon accumulation system has developed, encompassing the intra-source Lucaogou Formation, the near-source Upper Wuerhe Formation, and the far-source Jiucaiyuan Formation, all of which contain high-quality reservoirs. Laterally, the three sets of strata show similar distribution characteristics for their reservoir types: structural-lithologic traps dominate in uplift areas, developing = conventional reservoirs, whereas lithologic traps prevail from slope to sag areas, hosting tight reservoirs. Analysis of typical reservoirs further reveals significant differences in transport systems, reservoir types, and migration–accumulation models across different stratigraphic intervals. Guided by the newly established hydrocarbon accumulation models, the Permian Upper Wuerhe Formation and the Triassic Jiucaiyuan Formation in the central Fukang subsag were selected as key nearterm exploration targets. Remarkable breakthroughs achieved in subsequent drilling confirm the area’s strong potential as a new hundredmillion- ton-scale reserve growth zone in the Junggar Basin.

Against the backdrop of the global oil and gas industry’s transition into the unconventional era, the practices and implications of U.S. fiscal and industrial policies in facilitating the rapid development of unconventional oil and gas resources have garnered significant attention from both industrial and academic circles. Consequently, a comparative study of Chinese and American unconventional oil and gas policies has been conducted to analyze their similarities and differences, thereby proposing policy recommendations for China’s unconventional oil and gas development. Research indicates that the United States has implemented a series of substantial, long-term preferential policies for unconventional resources characterized by foresight, continuity, remarkable effectiveness, and synergistic interaction between policy and technological advancement, which served as crucial drivers for the success of the shale revolution and ultimately energy independence. While comparative analysis reveals similarities in policy contexts, objectives, support mechanisms, and market-oriented frameworks as fundamental premises, China’s unconventional oil and gas policies lack systematic integration, resulting in insufficient coordination between industrial development and policy implementation. In the unconventional gas sector, although subsidy policies have been implemented for years with notable achievements, policy continuity remains inadequate. For unconventional oil, shale oil development faces increasingly challenging reservoirs with growing technical difficulties and constrained cost-reduction potential. Among PetroChina’s three major shale oil production bases: the Changqing Oilfield is transitioning from Type I+II₁ reservoirs in the Chang-7 formation to less continuous, thinner single-layer II₂ reservoirs while expanding development into overlapping water-flooding zones; the Daqing Oilfield, while accelerating large-scale production in the Q9 reservoir and expanding exploration, is shifting toward Q1-Q8 reservoirs with rising clay content where Q2-Q3 intervals exhibit poor brittleness, limited fracture height and low estimated ultimate recovery (EUR) per well; and the Xinjiang Oilfield is transitioning from Jimsar to the more extensive, challenging, and capitalintensive Mabei Fengcheng Formation. However, policy support for shale oil remains essentially absent. Essentially, fostering unconventional oil and gas development constitutes a systematic project requiring coordinated efforts including national policy backing, local government cultivation,support from parent corporations of oilfield companies, and internal quality-efficiency enhancements by oilfield operators. Through a synergistic “four-in-one” policy linkage model, China can promote and refine its fiscal and taxation framework for unconventional resources. Looking forward,with relevant policy support, petroleum enterprises must accelerate cost-reduction and efficiency-gain initiatives in shale oil and gas development, leveraging technological innovation and managerial optimization to uphold efficient exploration and profitable development, thereby gradually diminishing policy dependence and achieving sustainable utilization of unconventional resources.

The integration of business and finance in oil and gas production is an important means to promote refined management and improve the level of lean management. To this end, taking the classified evaluation of cost - effectiveness of developed oilfields as an example, starting from the reconstruction of the evaluation unit of profitable production, through the integration of profitable production evaluation methods, the evaluation of profitable production and the classified evaluation of profitable production and cost are carried out, thus forming an evaluation method system for the integration of business and finance in the cost - effectiveness of developed oilfields. Theoretical research and application practice show that constructing an evaluation unit that can reflect necessary financial parameters such as operating costs, depreciation and depletion, and also contain oilfield development information such as reserves, production, independent reservoir types and development methods is the basis for the integration of business and finance. The refinement and rationalization of evaluation methods are the key to the evaluation of the integration of business and finance. The accurate acquisition of the technical - economic indicators of the evaluation unit based on reasonable allocation rules is an important guarantee for the evaluation of the integration of business and finance. Promoting the integration of business and finance requires the integrated collaboration of business departments and financial departments. On this basis, it is necessary to make full use of the achievements of enterprise informatization, gradually solidify the evaluation unit, standardize data collection and the detailed rules of evaluation methods, and continuously iterate on the achievements of the integration of business and finance, so as to provide a scientific basis for production and operation decision - making.

Accurate prediction and refined assessment of operating costs constitute a significant tool for petroleum enterprises to advance lean management and cost control. To this end, targeting deep and ultra-deep oil and gas fields in Western China, we propose two operating cost prediction methods: Cost Component-Based Operating Cost Prediction Method & Principal Component Model-Based Prediction Method. These approaches provide robust evaluation tools and decision-making foundations for development plan design, financial budgeting, operational optimization, and strategic formulation in oil and gas development. Studies confirm both methods exhibit strong practicability and reliability. Cost composition-based operating cost forecasting method starts from the components of operating costs, focuses on cost norms, and selects common modes, common alternative modes, or deep modes for operating cost forecasting according to specific situations. The benchmarking-based cost norm auxiliary decision-making method and the research on the regularity between operating costs and burial depth are two types of guarantee mechanisms to ensure the rationality of the cost composition-based operating cost forecasting results. The reasonable selection and accurate definition of norms are the key to the effective application of this method. When historical norms are involved, it is generally recommended to use the three-year historical average. The Principal Component Modelbased forecasting method for operating costs begins with techno-economic indicators—covering geological, developmental, and operational factors—that influence these costs. It conducts macro-level operating cost predictions through multi-factor dimensionality reduction and regression based on historical samples. The comprehensiveness and representativeness of historical operating cost samples are critical determinants of the model’s accuracy.

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. Italy’s Eni Group has innovatively developed the “Dual Exploration Model,” leveraging its deepwater technical advantages to achieve early value realization through equity sales after exploration discoveries,successfully establishing a closed-loop system of “discovery-monetization-rediscovery.” This paper systematically reviews the model’s connotation,execution status, and implementation essentials, analyzing case studies from Mozambique, Egypt, and C?te d’Ivoire to reveal its path of achieving low-cost discoveries and efficient development through technology-driven approaches, capital optimization, and strategic synergy.Research shows that the “Dual Exploration Model” features: low cost and major discoveries as the foundation, high equity and fast monetization as the essence, and retaining operator status and risk diversification as safeguards. The main implementation process consists of three stages (block acquisition, independent exploration, and self-recycling) with 10 detailed steps. It is suitable for low oil price periods but requires specific resource, pipeline, policy, capital, and technical conditions. Currently, it still faces numerous challenges including resource scarcity, external market environment, and internal technical capabilities. Based on the current status of PetroChina’s overseas oil and gas assets, this paper proposes recommendations such as establishing full-lifecycle assessment systems and equity management matrices for existing projects and forming a new business philosophy of “sustainable monetization” for new project acquisitions.

The isolated Carboniferous carbonate platform in the southern margin of Pre-Caspian Basin is an important exploration target in the Caspian Sea area, Kazakhstan. Taking the representative K oil reservoir as the study object, thin sections, geochemical, logging, and geological data have been comprehensively used to evaluate the characteristics and oil and gas geological significance of the Carboniferous Visean–Bashkirian bitumen bearing carbonate reservoirs. The study results show that the distribution of bitumen was controlled by the open fracture system in high-energy platform margin and tectonic–diagenetic processes, while it was basically absent in the isolated pores in the platform zone. In response to the problem of overestimation of logging interpreted porosity caused by bitumen enrichment, a multi mineral quantitative inversion model constrained by bitumen physical phase has innovatively been constructed, in which bitumen is quantitatively characterized as a solid organic mineral component, achieving accurate calculation of bitumen content and significantly improving the accuracy of porosity interpretation (reducing average error by 20%). The geochemical indicators (T_max of 452–461 ℃, I_H<130 mg/g (HC/TOC)) indicate that bitumen was a product of high-temperature thermal cracking and possible TSR alteration, and its genesis might be related to local thermal anomalies in the context of regional tectonic–thermal events in the Hercynian period. The Bashkirian high abundance bitumen zone is a sign of the residual oil reservoir after cracking, which is mainly distributed in the high porosity and high permeability zone in the platform margin. The bottom boundary of bitumen occurrence reveals that the ancient oil-water contact is deeper than the current value, and the storage space system below the Visean oil reservoir unit indicates the potential preservation zone of deep primary oil reservoirs. This study elucidates the indicative significance of bitumen on the location of paleo oil reservoirs and reservoir heterogeneity, providing new ideas for fine evaluation of bitumen bearing carbonate reservoirs and petroleum exploration in deep formations.

The Uteland Butte Member is a representative lacustrine shale oil play within the Green River Formation of the Uinta Basin, USA. Since 2011, exploration and development of the Uteland Butte Member have undergone two significant shifts: from conventional targets to overpressured shale reservoirs in the lacustrine basin center, and from conventional drilling to horizontal wells combined with volumetric fracturing. These transitions led to a major breakthrough in economic development, with single-well estimated ultimate recovery (EUR) reaching hundreds of thousands of barrels over the last decade. This high-efficiency development challenged traditional perceptions and has become a crucial case study for continental shale oil exploration worldwide.This study systematically reviews the exploration and development breakthroughs in the continental shale oil of the Uteland Butte Member in the Uinta Basin, USA. It specifically analyzes its geological characteristics, enrichment control mechanisms, and engineering evolution pathways. The results indicate that the high-efficiency enrichment of this member is a synergistic outcome of multiple factors, including deposition, hydrocarbon generation, overpressure, and complex pore structures. The coupling between the “source-reservoir integration” complex pore structure and the abnormal overpressure system is particularly critical. In terms of engineering technology, the play evolved from early vertical wells with simple fracturing to horizontal wells and “rack-style” three-dimensional development. This led to the establishment of a comprehensive, integrated technical system for “sweet spot evaluation—well-pattern optimization—staged fracturing.” The “rack-style” development model accurately and synergistically taps into multiple vertically stacked thin-bed sweet spots using a three-dimensional well pattern, providing a crucial reference for developing similar “thin interbedded, highly heterogeneous” continental shale oil plays in China. Based on these findings, this paper conducts a differentiated comparative analysis for typical Chinese continental shale oil basins, including Junggar (Jimsar), Jiyang, and Songliao. We found significant differences between these Chinese basins and the Uinta Basin in aspects such as lithology, formation pressure, and in-situ stress. Therefore, we propose a strategy of “tailored and differentiated reference,” offering specific technical and geological recommendations applicable to each basin. This paper aims to distill the core drivers of multi-factor synergy for reservoir formation and, by addressing the unique geological challenges of different Chinese basins, propose a differentiated reference strategy to provide a systematic framework for achieving economic development.

The high-quality mud shale of the Qingshankou Formation in the northern Songliao Basin is primarily developed in the Gulong and Sanzhao Sags. Major strategic breakthroughs in shale oil have been achieved in the Gulong Sag. However, systematic studies on whether the Sanzhao Sag, with relatively low shale maturity, possesses favorable geological conditions for shale oil accumulation, controlling accumulation factors, and exploration potential remain scarce. This study, based on breakthroughs from risk exploration well drilling to provide a comprehensive analysis of the sedimentary paleogeomorphology, paleoenvironment, reservoir lithofacies, and reservoir evaluation parameters in the region. It focuses on comparing the shale oil enrichment geological characteristics of the Sanzhao Sag with those of the Gulong Sag.The results indicate: (1) under a transgressive environment, the Sanzhao Sag features saline and semi-saline water conditions, exhibiting high paleo-productivity under semi-humid to humid climates and anoxic environments; (2) the Qingshankou Formation in the Sanzhao Sag contains three types of reservoir facies: high organic laminar shale, laminated shale, and thinly interbedded siltstone-shale, all of which exhibit excellent reservoir properties and high oil content; (3) the total area of favorable I-type zones for shale oil exceeds 3,000 square kilometers, with the Sanzhao Sag hosting a unique favorable I-type zone for laminated shale -type shale oil, containing substantial resources.The findings suggest that the Sanzhao Sag is poised to become the next shale oil replacement zone after the Qijia-Gulong Sags, offering valuable guidance for predicting and exploring sweet spots in shale oil within the basin.

In Linhe Depression, Hetao Basin, high-yield oil flows with a daily rate of 100–1000 t/d have been achieved in deep to ultra-deep sandstone reservoirs in the Paleogene Linhe Formation in multiple exploration wells. Specially, the open flow oil and gas rates of 1285.77 m³/d and 1.07×10⁴ m³/d were tested at a depth of 6500 m in Well Hetan 101, which was the first high-yield well with an oil rate level of 1000 t/d in the ultra-deep clastic rocks in faulted lake basin in China, and also the highest oil flow well in the ultra-deep clastic rocks, with the main reservoir space of primary intergranular pores, greatly breaking through the lower depth limit of oil and gas exploration in conventional primary porosity type sandstone reservoirs. Based on thin sections, core samples, well drilling, logging, and a large amount of rock mineral laboratory test data, a comprehensive study of reservoir formation mode and lower exploration depth limit of effective primary porosity type sandstone reservoirs in the deep to ultra-deep formations has been conducted. The study results show that the high-quality reservoirs in Linhe Formation are mainly composed of high composition and high structural maturity quartz rich clastic sandstones. The reservoir space is dominated by primary intergranular pores with characteristics of large pores and coarse throats. The reservoir formation and evolution were controlled by four fields, including static rock compaction dynamic field, thermal compaction dynamic field, fluid salinity field, and fluid pressure field. The evolution of high-quality reservoirs experienced four diagenetic stages, namely early constant burial depth increase–rapid pore reduction, early–middle stage long-term slow burial depth increase–slow pore reduction, middle–late stage rapid burial depth increase–weak compaction pore reduction, and late stage continuous burial depth increase–hydrocarbon charging for pressurization and pore preservation, and the porosity of ultra-deep high-quality reservoirs before hydrocarbon charging reached up to 20%–30%. Furthermore, a power function relationship model between time temperature index TTI and porosity has been established, which indicates that thick sandstone (greater than 1 m) with low interstitial material content in the trough area is effective reservoir, the lower porosity limit of effective conventional reservoir is 8.5%, and the lower depth limit of effective reservoir reaches 9200 m, greatly expanding the lower depth limit of oil and gas exploration in deep to ultra-deep primary porosity type sandstone reservoirs.

The Huagang Formation in the central inversion belt of the Xihu Sag has been an important target for oil and gas exploration in the East China Sea Basin in recent years. However, due to the influence of multiphase tectonic activity and diagenesis, the reservoirs exhibit strong heterogeneity, and the genesis of high-quality reservoirs remains unclear. Taking Structure “B” as an example, this study integrates core observations, mineral composition analysis, scanning electron microscopy, high-pressure mercury intrusion, and imaging logging data to systematically analyze reservoir stress distribution, fracture development characteristics, and the tectono-diagenetic reservoir-controlling mechanism. The tectonic stress in the study area displays a distinct three-segment zonation: the shallow zone is dominated by extensional stress with regularly oriented fractures; the middle zone is characterized by intense stress disturbance and diffuse fracture orientations; and the deep zone is governed by compressive–shear stress, with concentrated fractures of large dip angles. Different structural positions (fault core, damage zone, and host rock) show significant differences in stress concentration, fracture connectivity, and diagenetic fluid activity. Considering the combined effects of tectonic stress and diagenesis, the Huagang Formation reservoirs are classified into six types of tectono-diagenetic facies, and their planar distribution characteristics are clarified. These facies alternate spatially among the fault core, damage zone, and host rock, with high-quality reservoirs predominantly developed in strongly dissolved facies zones characterized by high fracture connectivity and an open diagenetic system. Overall, reservoir heterogeneity in the study area results from the multi-scale coupling of tectonic stress, fracture systems, and diagenetic processes, and the tectono-diagenetic facies reveal a “stress-dominated – fluid-driven – facies belt differentiation” reservoircontrolling model. The results provide a geological basis for high-quality reservoir prediction and zonal evaluation in strike-slip fault zones.

In recent years, significant breakthroughs have been made in the exploration of the Upper Permian Changxing Formation in the Mianyang-Guang’an shallow-water shelf and its adjacent areas. However, the geochemical characteristics and gas-bearing properties of different reef-shoal bodies vary greatly, the genesis and main source rocks of different gas reservoirs remain unclear, and the laws of oil and gas enrichment and the accumulation models are not yet well understood. These factors have restricted the evaluation of favorable traps and the deployment of exploration. Based on the analysis and experimental data of natural gas composition, carbon isotopes, hydrogen isotopes, nitrogen isotopes, reservoir bitumen and source rocks, a systematic study was conducted on the origin of natural gas and the mixing ratio of mixed gases. Combined with geological research results, a gas accumulation model for the Changxing Formation was established. The research results show that: The study results show that: (1) The natural gas in the Changxing Formation is mainly composed of hydrocarbon gases with a dryness coefficient greater than 0.9841, and it is mainly pyrolysis gas from crude oil, with some being medium to high H₂S gas reservoirs. (2) In the study area, three sets of source rocks of two types, namely the Upper Permian Longtan Formation/Wujiaping Formation Type II₁-III and the Lower Paleozoic Qiongzhusi Formation and Longmaxi Formation Type I-II₁, are mainly developed. The geochemical differences of natural gas in the Changxing Formation are related to the development degree of the main source rocks and the stratigraphic level of the source-cutting faults. Natural gas from the Upper Permian source rocks has heavy carbon isotopes, with δ¹³C₂ values mainly heavier than -28.0‰. When Lower Paleozoic source rocks are mixed in, the carbon isotopes of the mixed gas become lighter. The contribution ratio of Lower Paleozoic source rocks estimated by the end-member gas δ¹³C₂ values is 53.9% - 77.0%. (3) The Changxing Formation gas reservoirs have three types of accumulation patterns：single-source，dual-source and triple-source hydrocarbon supply pattern. The main source rocks and their distribution for different accumulation patterns were clarified. It is believed that in the area where the source rocks are from the Upper Permian Longtan Formation/Wujiaping Formation, the superimposition of large-scale beach facies reservoirs and the current structure is a favorable exploration zone. In the area where there is a mixture of Lower Paleozoic sources, the effective matching of source-cutting faults and large-scale beach facies reservoirs leads to a higher overall degree of oil and gas enrichment，which can provide geological basis for the next exploration deployment decisions in Sichuan Basin.

The Qixia Formation gas reservoir in the Shuangyushi structure, the first large-scale gas reservoir discovered in the Longmenshan foothill belt, is characterized by extremely developed faults and complex structural patterns, where structural features are a key factor influencing reservoir development. Considering that the structure in this area is jointly controlled by multi - stage tectonic movements and multi - detachment layers, while the existing studies have insufficient discussion on the controlling effect of the multi - detachment system, this paper adopts a progressive technical route of “physical simulation - numerical simulation - geological verification”. By designing models with different properties and thicknesses of detachment layers, the controlling mechanism of multi - detachment layers on structural deformation is revealed. Combined with actual drilling data, the simulation results are verified to guide the development and deployment of the gas reservoir. The results show that: ① Three sets of detachment systems are developed in the Shuangyushi area, namely the Cambrian (deep main detachment layer), Triassic (shallow main detachment layer), and Silurian (local secondary detachment layer). The “upper-lower double detachment” combination is the key to forming the thrust imbricate - steep fold structure in this area; ② The properties of detachment layers significantly affect structural styles: weak detachment layers tend to form continuous imbricate thrust structures, while strong detachment layers enhance the deformation complexity of overlying strata and weaken the continuity of imbricate structures; ③ The thickness of detachment layers controls structural evolution: thin detachment layers are characterized by “fold-dominated, fault-secondary”, mediumthick detachment layers form compartmental box folds - imbricate fan structures, and thick detachment layers develop “detachment layerdominated” giant fold - thrust systems, with thick plastic detachment layers having better sealing performance; ④ Based on the differences in structural styles, development models are proposed: the “sparse well pattern + high - angle well” model for the pop - up structure area, the “long horizontal section horizontal well (deployed at the high point)” model for the monocline anticline area, and the “high - angle well + horizontal well combination” model for the faulted anticline area. The research results clarify the structural formation mechanism under the control of multi - detachment layers and provide theoretical support and technical reference for the exploration and development of similar gas reservoirs in the Longmenshan piedmont belt.

Compared with shallow and medium-depth coal seams, deep coal reservoirs exhibit significant differences in gas–water occurrence, production mechanisms, and engineering responses. Under in situ high-pressure conditions, free gas primarily flows as a continuous medium, and variations in reservoir pressure and bottom-hole flowing pressure directly influence gas–water distribution, migration driving forces, and production evolution. Proper pressure management enhances gas production via matrix and fracture flow. Based on the control of coalbed methane (CBM) migration mechanisms by pressure evolution, an active depressurization and production control method centered on differentiated bottom-hole pressure regulation is proposed. This approach incorporates a critical fracturing fluid pressure model, criteria for iso-flow and iso-pressure points, and a dynamic gas–water ratio identification model, revealing the fluid migration characteristics and pressure-differential control rules across different production stages. A staged bottom-hole pressure management system—“safe flow initiation–stable dewatering–coordinated gas production–enhanced output and stable production”—is established, achieving dynamic coupling of pressure, flow mechanisms, and desorption kinetics throughout the production process. Numerical simulations based on typical CBM wells on the eastern margin of the Ordos Basin indicate that the active pressure-control strategy enables graded energy release and effective utilization of reservoir energy, producing a “multi-peak” daily gas production profile and improving predicted recovery by approximately 8.9% compared with uncontrolled conditions. Field tests further demonstrate that staged and graded depressurization effectively slows the pressure decline, mitigates rapid gas–water ratio increases, maintains two-phase flow balance, and gradually releases production capacity, significantly enhancing single-well output and production stability. These results provide a theoretical basis and practical guidance for the efficient development of CBM in deep coal-rock gas reservoirs of the Ordos Basin.

The high-quality source rocks in the Shahejie Formation of the Gegangji area, Dongpu Sag, exhibit extremely strong distribution heterogeneity. Conventional logging methods struggle to accurately identify and predict their spatial distribution, which significantly hinders the effectiveness of oil and gas exploration in the sag zone. In response, this study integrates geochemical data with logging response characteristics and employs a random forest algorithm to develop a high-precision TOC prediction model. This model achieves effective prediction of total organic carbon (TOC) content in highly heterogeneous geological conditions, revealing the distribution patterns of thinlayer high-quality source rocks and their controlling effect on hydrocarbon accumulation. The results indicate that the high-quality source rocks in the study area are predominantly gray-black shales with high organic matter abundance and favorable kerogen types. However, their thin single-layer thickness, rapid vertical and lateral variations, and complex logging responses lead to insufficient identification accuracy using traditional methods. The random forest algorithm significantly improves the prediction capability of heterogeneous organic matter distribution in complex lithological associations by integrating multiple types of logging parameters. Prediction results show that high-quality source rocks in the study area are mainly distributed at the bottom of the lower sub-member of the third member of the Shahejie Formation (Es₃^l) and the middle-upper part of the upper sub-member of the fourth member (Es₄^u). Moreover, their thickness gradually increases from west to east and from south to north in the near-sag to deep-sag areas. The distribution of high-quality source rocks exhibits a clear controlling effect on hydrocarbon accumulation, demonstrating typical“near-source accumulation”characteristics. High-yield oil and gas reservoirs as well as hydrocarbon-bearing intervals are all located near high-quality source rocks, and the degree of hydrocarbon enrichment is closely related to the thickness of these rocks. This research provides an important geological basis for oil and gas exploration planning in the sag zone of the Dongpu Sag.