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.

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.

The integration of operations and finance in oil and gas production is an important means to promote the fine management and improve the level of lean management. Taking the developed oilfields as an example, the evaluation units of profitable production have been reconstructed, and the integration of evaluation methods has been applied to conduct graded and classified cost–profitability evaluation, thus forming the business and finance integrated evaluation method system for cost–benefit of developed oilfields. The theoretical study and application practice show that the construction of evaluation units that reflect necessary financial parameters such as operating costs, depreciation and depletion, and also contain oilfield development information such as reserves, production, independent oil reservoir types and development methods is the basis for the integration of business and finance. The fine and rational evaluation methods are the key to the business and finance integrated evaluation. The accurate technical–economic indicators of evaluation units based on reasonable allocation rules are an important guarantee for the business and finance integrated evaluation. The integrated collaboration of business departments and financial departments are required for promoting the integration of business and finance. On this basis, it is necessary to make full use of the achievements of enterprise informatization, gradually solidify the evaluation units, standardize data collection and the detailed rules of evaluation methods, and continuously iterate the business and finance integrated evaluation achievements, so as to provide a scientific basis for production and operation decisions.

The accurate prediction and fine evaluation of operating costs are important means for oil enterprises to promote lean management and cost control and reduction. Taking deep and ultra-deep oil and gas fields in Western China as examples, two operating cost prediction methods have been proposed, i.e., cost component-based, and principal component model-based prediction methods, which provides robust evaluation tools and decision-making foundation for development plan design, financial budgeting, production and operation optimization, and oil and gas development strategy formulation. The study results confirm that both methods exhibit strong practicability and reliability. The cost component-based operating cost prediction method starts from the components of operating costs, focuses on cost quota, and selects common modes, common alternative modes, or deep modes for operating cost prediction based on specific situations. Two guarantee mechanisms ensuring the rational prediction results rely on the benchmarking-based cost quota auxiliary decision-making method and the understanding on the law of operating cost variation with burial depth. In addition, the rational selection and accurate definition of quotas are the key to the effective application of this method. When historical quotas are involved, a three-year historical average value is generally recommended. The principal component model-based prediction method starts with technical and economic indicators influencing operating costs, covering geological, development, and operation factors, and conducts macro-level operating cost prediction through multi-factor dimensionality reduction and regression based on historical samples. The accuracy of principal component model depends on the comprehensiveness and representativeness of historical operating cost samples.

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.

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.

Uteland Butte member in Green River Formation is a typical lacustrine shale oil formation in Uinta Basin, USA. Since 2011, exploration and development of Uteland Butte member have undergone two major shifts, i.e., from conventional targets to overpressured shale reservoirs in the central lake basin, and from conventional development method to horizontal well drilling and volume fracturing. As a result, major breakthroughs have been obtained in beneficial shale oil development, with single-well estimated ultimate recovery (EUR) reaching hundreds of thousands of barrels over the last decade. This high-efficiency development practice has challenged traditional understanding and become an important case study for continental shale oil exploration worldwide. The exploration and development breakthroughs of continental shale oil in Uteland Butte member in Uinta Basin have systematically been reviewed, and geological characteristics, enrichment control mechanisms, and engineering evolution path have been analyzed in detail. The results indicate that the high-efficiency shale oil enrichment in Uteland Butte member was jointly controlled by sedimentary facies, hydrocarbon generation, overpressure, and composite pore structures, and the coupling between complex pore structure and the abnormal overpressure system in the “integrated source rock–reservoir” was particularly critical. In terms of engineering technology, the development method has evolved from early simple fracturing of vertical wells to horizontal well drilling and “rack-style” stereoscopic development, and a comprehensive “sweet spot evaluation—well pattern optimization—staged fracturing” integrated technical system has been established. By using a stereoscopic well pattern, the “rack-style” development mode enables to accurately and synergistically produce multiple vertically superimposed thin sweet spots, providing an important reference for developing similar “thin interbedded and highly heterogeneous” continental shale oil plays in China. On this basis, a differentiated comparative analysis of typical continental shale oil basins in China has been conducted, including Junggar, Bohai Bay, and Songliao basins, which shows significant differences with Uinta Basin in terms of lithology, formation pressure, and in-situ stress. Therefore, a strategy of “tailored and differentiated reference” has been proposed, and specific technical and geological recommendations applicable to each basin have been put forward, aiming to summary the core drivers for multi-element synergic hydrocarbon accumulation, propose a differentiated reference strategy in response to the unique geological challenges of various basins in China, and provide a systematic idea for achieving beneficial oil development.

In Northern Songliao Basin, the high-quality shale in Qingshankou Formation was mainly developed in Gulong and Sanzhao sags. Major strategic breakthroughs in shale oil have been achieved in Gulong Sag. However, there is a lack of systematic study on oil enrichment geological conditions, main controlling factors, and exploration potential of shale with relatively low maturity in Sanzhao Sag. Based on achievements in risk exploration wells, a comprehensive study has been conducted on sedimentary paleogeomorphology, paleoenvironment, reservoir lithofacies, and reservoir evaluation parameters, and shale oil enrichment geological characteristics in Sanzhao Sag have been discussed in detail by comparing with those in Gulong Sag. The results indicate that: (1) In the context of a transgressive environment, Sanzhao Sag was featured by saline and brackish–saline water environments, as well as high paleo-productivity given the semi-humid to humid climates and anoxic environment; (2) Three types of shale oil reservoirs were developed in Qingshankou Formation in Sanzhao Sag, i.e., organic-rich laminar shale, laminated shale, and thin siltstone interlayered shale, all of which had excellent reservoir storage capacity and high oil content; (3) The total area of ClassⅠ favorable zone of the three types of shale oil exceeds 3000 km², in which Sanzhao Sag hosts a unique ClassⅠ favorable zone of laminar type shale oil, with enormous resource amount. The study results confirm that Sanzhao Sag is the shale oil replacement zone after Qijia-Gulong sags, and provide significant guidance and reference for sweet spot prediction and large-scale shale oil exploration in 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 potentials 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.

In recent years, Huagang Formation in the central inversion structural belt in Xihu Sag is a major exploration target in the East China Sea Basin. However, due to the influence of multi-stage tectonic activities and diagenesis, the reservoirs exhibit strong heterogeneity, and the genesis of high-quality reservoirs remains unclear. Taking structure “B” as an example, and integrating with core observation, mineral composition analysis, scanning electron microscopy, high-pressure mercury injection, and imaging logging data, reservoir stress distribution, fracture development characteristics, and the tectono-diagenetic reservoir-controlling mechanisms have systematically been analyzed. 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 developed, and the middle zone is characterized by intense stress disturbance and diffuse fracture orientations, while the deep zone is governed by compressive–shear stress, with concentrated and large-angle fractures developed. There are significant differences in stress concentration, fracture connectivity, and diagenetic fluid activity in different structural positions (fault core, fractured zone, and host zone). Considering the combined effects of tectonic stress and diagenesis, Huagang Formation reservoirs are classified into six types of tectono-diagenetic facies, and their planar distribution characteristics have been clarified. These facies alternate spatially among the fault core, fractured zone, and host zone, with high-quality reservoirs predominantly developed in strong dissolution facies zones characterized by high fracture connectivity and open diagenetic system. Overall, reservoir heterogeneity in the study area was controlled by multi-scale coupling of tectonic stress, fracture system, and diagenetic process, and a reservoir-controlling model of “stress-dominant–fluid-driving–facies zone differentiation” was proposed based on tectono-diagenetic facies analysis. The study 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 Mianyang–Guang’an shallow continental shelf and its periphery. However, the gas geochemical characteristics and gas-bearing properties in different reef beach bodies vary greatly, and the genesis/origin and main source rocks of different gas reservoirs remain unclear, as well as the gas enrichment law and accumulation pattern, restricting the evaluation of favorable traps and exploration deployment. Based on laboratory analysis and experimental data such as natural gas composition, carbon isotopes, hydrogen isotopes, nitrogen isotopes, reservoir bitumen and source rocks, a systematic study has been conducted on the genesis of natural gas and the mixing ratio of mixed gases. Combined with geological study results, a gas accumulation model for Changxing Formation gas reservoir has been established. The study results show that: (1) The natural gas in Changxing Formation is mainly composed of hydrocarbon gases with a dryness coefficient of greater than 0.98, generally showing crude oil cracking gas, with medium–high H₂S content in local areas. (2) Three sets of source rocks were deposited in the study area, namely the Upper Permian Longtan Formation/Wujiaping Formation TypeⅡ1–Ⅲ, the Lower Paleozoic Qiongzhusi Formation TypeⅠ, and Longmaxi Formation TypeⅠ–Ⅱ1 source rocks. The geochemical differences in Changxing Formation natural gas are related to the development degree of main source rocks and the stratigraphic horizon cut by source-connecting faults. Natural gas generated by the Upper Permian source rock has heavy carbon isotopes, with δ¹³C₂ values generally heavier than -28.0‰. When mixed with gas generated by the Lower Paleozoic source rocks, carbon isotopes of the mixed gas become lighter, with a contribution ratio of 53.9%–77.0% of the Lower Paleozoic gas estimated by the end-member gas δ¹³C₂ values. (3) Three types of gas accumulation patterns have been identified for Changxing Formation gas reservoirs, i.e., single-source, dual-source, and triple-source hydrocarbon supply patterns, and the main source rocks for various accumulation patterns have been clarified. The results indicate that in the area where the Upper Permian Longtan Formation/Wujiaping Formation served as source rocks, the superposition of large-scale beach facies reservoirs and current structures shows favorable exploration zone. In the area where there is a mixture of the Lower Paleozoic hydrocarbon source, the effective matching of source-connecting faults and large-scale beach facies reservoirs leads to an overall higher degree of oil and gas enrichment. This research provides geological basis for further exploration deployment decisions in Sichuan Basin.

Qixia Formation gas reservoir in Shuangyushi structure is the first large-scale marine carbonate gas reservoir discovered in Longmenshan piedmont belt, with faults extremely well developed and complex structural patterns, and structural features are a key factor influencing gas reservoir development. The structures in this area were jointly controlled by multi-stage tectonic movements and multiple detachment layers, while there was insufficient discussion on the controlling effects of multi detachment system in previous studies. A progressive technical route of “physical simulation–numerical simulation–geological verification” has been adopted, and various models with different properties and thicknesses of detachment layers have been designed to reveal the controlling mechanism of multi detachment layers on structural deformation, then the accuracy of the simulation results was verified by actual drilling data. By analyzing the geological characteristics of different structural styles, awe can further optimize the deployment of gas reservoir development. The results show that: (1) Three sets of detachment systems were developed in Shuangyushi area, namely the Cambrian (deep main detachment layer), Triassic (shallow main detachment layer), and Silurian (secondary detachment layer). The “upper–lower double detachment” combination was the key to forming the thrust imbricate–steep fold structure in this area. (2) The properties of detachment layers significantly affected structural styles. For example, the weak detachment layers tended to form continuous imbricate thrust structures, while strong detachment layers enhanced the deformation complexity of overlying strata and weakened the continuity of imbricate structures. (3) The thickness of detachment layers controlled structural evolution. Thin detachment layers are characterized by “fold dominant, and secondary faults”. The medium-thick detachment layers formed ejective box folds–imbricate fan structures, and the thick detachment layers developed “detachment layer dominated” giant fold–thrust systems, with better sealing performance of thick plastic detachment layers. (4) Based on the differences in structural styles, differentiated gas reservoir development models have been proposed, that is, “sparse well pattern + high-angle deviated well” model for the pop-up structural zone, “long horizontal well (at the high point)” model for the monoclinal anticline zone, and “high-angle deviated well + horizontal well combination” model for the faulted anticline zone. The research results have clarified the structural formation mechanism under the control of multiple detachment layers, which provides theoretical support and technical reference for the exploration and development of similar gas reservoirs in Longmenshan piedmont belt.

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.

In Gegangji area, Dongpu Sag, the distribution of high-quality source rocks in Shahejie Formation exhibits extremely strong heterogeneity, making it difficult for conventional logging methods to accurately identify and predict, which significantly hinders effective oil and gas exploration in the subsag area. By integrating geochemical data with logging response characteristics, and employing a random forest algorithm, a high-precision TOC prediction model has been developed, achieving effective prediction of total organic carbon (TOC) content of source rocks in the context of highly heterogeneous geological conditions, which reveals the distribution pattern of high-quality thin source rocks and their controlling effect on hydrocarbon accumulation. The study results indicate that the high-quality source rocks in the study area are mainly composed of gray black shale, with high organic matter abundance, and favorable kerogen types, but thin single-layer thickness, rapid vertical and lateral variations, and complex logging response, leading to insufficient identification accuracy of traditional methods. The random forest algorithm significantly improves the prediction capability for heterogeneous organic matter distribution in complex lithological associations by integrating multi-type logging parameters. The prediction results show that high-quality source rocks are mainly distributed at the base lower sub-member of the third member (Es₃^l) and the middle-upper part of the upper sub-member of the fourth member of Shahejie Formation (Es₄^u) in the study area. Moreover, their thickness gradually increases from west to east and from south to north in the near-subsag to deep-subsag areas. The distribution of high-quality source rocks had a clear control on hydrocarbon accumulation, demonstrating typical characteristics of “near-source rock hydrocarbon accumulation”. The high-yield oil and gas layers as well as hydrocarbon-bearing intervals are all located near high-quality source rocks, and the degree of hydrocarbon enrichment is closely related to source rock thickness. This research provides an important geological basis for oil and gas exploration planning in the subsag area in Dongpu Sag.