Based on field geological survey, interpretation of seismic data and analysis of drilling and logging data, the evolution of geological structures, stratigraphic sedimentary filling sequence and sedimentary system around the Bogda Mountain were analyzed according to the idea of "structure controlling basin, basin controlling facies and facies controlling assemblages". The tectonic evolution of the basin around the Bogda Mountain can be divided into nine stages. The Middle-Late Permian-Middle-Late Triassic was the development stage of intracontinental rift, foreland basin and inland depression basin when lake, fan delta and braided river delta sedimentary facies developed. Early intracontinental rifting, late Permian tectonic uplift, and middle-late Triassic tectonic subsidence controlled the shape, type, subsidence rate and sedimentary system evolution of the basin. The Bogda Mountain area was the subsidence center and deposition center of the deep water lake basin in the Middle Permian with mainly deep-water deposition and local gravity flow deposition. This area had tectonic inversion in the Late Permian, when the Bogda Mountain uplifted to form a low bulge and a series of fan delta sand bodies. In the Middle-Late Triassic, subsidence occurred in the Bogda low uplift, characterized by extensive development of braided river delta deposits.

The fluid evolution and reservoir formation model of the ultra-deep gas reservoirs in the Permian Qixia Formation of the northwestern Sichuan Basin are investigated by using thin section, cathodoluminescence, inclusion temperature and U-Pb isotopic dating, combined with gas source identification plates and reservoir formation evolution profiles established based on burial history, thermal history, reservoir formation history and diagenetic evolution sequence. The fluid evolution of the marine ultra-deep gas reservoirs in the Qixia Formation has undergone two stages of dolomitization and one phase of hydrothermal action, two stages of oil and gas charging and two stages of associated burial dissolution. The diagenetic fluids include ancient seawater, atmospheric freshwater, deep hydrothermal fluid and hydrocarbon fluids. The two stages of hydrocarbon charging happened in the Late Triassic and Late Jurassic-Early Cretaceous respectively, and the Middle to Late Cretaceous is the period when the crude oil cracked massively into gas. The gas reservoirs in deep marine Permian strata of northwest Sichuan feature multiple source rocks, composite transportation, differential accumulation and late finalization. The natural gas in the Permian is mainly cracked gas from Permian marine mixed hydrocarbon source rocks, with cracked gas from crude oil in the deeper Sinian strata in local parts. The scale development of paleo-hydrocarbon reservoirs and the stable and good preservation conditions are the keys to the formation of large-scale gas reservoirs.

Temperature-triaxial permeability testing at the axial pressure of 8 MPa and confining pressure of 10 MPa, closed shale system pyrolysis experiment by electrical heating and scanning electron microscopy analysis are used to study the evolution mechanism of in-situ permeability in the direction parallel to bedding of low mature shale from Member 2 (K₂n₂) of Cretaceous Nenjiang Formation in northern Songliao Basin with mainly Type I kerogen under the effect of temperature. With the increasing temperature, the in-situ permeability presents a peak-valley-peak tendency. The lowest value of in-situ permeability occurs at 375 ℃. Under the same temperature, the in-situ permeability decreases with the increase of pore pressure. The in-situ permeability evolution of low mature shale can be divided into 5 stages: (1) From 25 ℃ to 300 ℃, thermal cracking and dehydration of clay minerals improve the permeability. However, the value of permeability is less than 0.01×10^-3 μm²; (2) From 300 ℃ to 350 ℃, organic matter pyrolysis and hydrocarbon expulsion result in mineral intergranular pores and micron pore-fractures, these pores and fractures form an interconnected pore network at limited scale, improving the permeability. But the liquid hydrocarbon, with high content of viscous asphaltene, is more difficult to move under stress and more likely to retain in pores, causing slow rise of the permeability. (3) From 350 ℃ to 375 ℃, pores are formed by organic matter pyrolysis, but the adsorption swelling of liquid hydrocarbon and additional expansion thermal stress constrained by surrounding stress compress the pore-fracture space, making liquid hydrocarbon difficult to expel and permeability reduce rapidly. (4) From 375 ℃ to 450 ℃, the interconnected pore network between different mineral particles after organic matter conversion, enlarged pores and transformation of clay minerals promote the permeability to increase constantly even under stress constraints. (5) From 450 ℃ to 500 ℃, the stable pore system and crossed fracture system in different bedding directions significantly enhance the permeability. The organic matter pyrolysis, pore-fracture structure and surrounding stress in the different stages are the key factors affecting the evolution of in-situ permeability.

Based on the logging knowledge graph of hydrocarbon-bearing formation (HBF), a Knowledge-Powered Neural Network Formation Evaluation model (KPNFE) has been proposed. It has the following functions: (1) extracting characteristic parameters describing HBF in multiple dimensions and multiple scales; (2) showing the characteristic parameter-related entities, relationships, and attributes as vectors via graph embedding technique; (3) intelligently identifying HBF; (4) seamlessly integrating expertise into the intelligent computing to establish the appraising system and ranking algorithm for potential reservoir recommendation. Taking 547 wells encountered the lower porosity and lower permeability Chang 6 Member in Jiyuan Block of Ordos Basin as objects, 80% of the wells were randomly selected as the training dataset and the remainder as the validation dataset. The KPNFE prediction results on the validation dataset had a coincidence rate of 94.43% with the expert interpretations and a coincidence rate of 84.38% for all the tested layers, which is 13 percentage points higher in accuracy and over 100 times faster than the primary conventional interpretation. In addition, a number of potential reservoirs likely to produce industrial oil were recommended. The KPNFE model effectively inherits, carries forward and improves the expert knowledge, nicely solving the robustness problem in HBF identification. The KPNFE, with good interpretability and high accuracy of computation results, is a powerful technical means for efficient and high-quality well logging re-evaluation of old wells in mature oilfields.

The parameters such as pore size distribution, specific surface area and pore volume of shale rock samples are analyzed by low-temperature nitrogen adsorption experiment, and then the conversion coefficient between relaxation time (T₂) and pore size is calibrated. Nuclear magnetic resonance experiments of CO₂ huff and puff in shale samples are carried out to study the effects of gas injection pressure, soaking time and fractures on the oil production characteristics of shale pores from the micro scale. The the recovery degrees of small pores (less than or equal to 50 nm) and large pores (greater than 50 nm) are quantitatively evaluated. The experimental results show that the recovery degree of crude oil in large pores increases rapidly with the increase of injection pressure under non-miscible conditions, and the effect of injection pressure rise on recovery degree of large pores decreases under miscible conditions; whether miscible or not, the recovery degree of crude oil in small pores basically maintains a linear increase with the increase of injection pressure, and the lower size limit of pores in which oil can be recovered by CO₂ decreases with the increase of gas injection pressure; with the increase of soaking time, the recovery degree of crude oil in large pores increases slowly gradually, while the recovery degree of crude oil in small pores increases faster first and then decelerates, and the best soaking time in the experiments is about 10 h; the existence of fractures can enhance the recovery degrees of crude oil in small pores and large pores noticeably.

Carbon dioxide capture, EOR-utilization and storage (CCUS-EOR) are the most practical and feasible large-scale carbon reduction technologies, and also the key technologies to greatly improve the recovery of low-permeability oil fields. This paper sorts out the main course of CCUS-EOR technological development abroad and its industrialization progress. The progress of CCUS-EOR technological research and field tests in China are summarized, the development status, problems and challenges of the entire industry chain of CO₂ capture, transportation, oil displacement, and storage are analyzed. The results show a huge potential of the large-scale application of CCUS-EOR in China in terms of carbon emission reduction and oil production increase. At present, CCUS-EOR in China is in a critical stage of development, from field pilot tests to industrialization. Aiming at the feature of continental sedimentary oil and gas reservoirs in China, and giving full play to the advantages of the abundant reserves for CO₂ flooding, huge underground storage space, surface infrastructure, and wide distribution of wellbore injection channels, by cooperating with carbon emission enterprises, critical technological research and demonstration project construction should be accelerated, including the capture of low-concentration CO₂ at low-cost and on large-scale, supercritical CO₂ long-distance transportation, greatly enhancing oil recovery and storage rate, and CO₂ large-scale and safe storage. CCUS-EOR theoretical and technical standard system should be constructed for the whole industrial chain to support and promote the industrial scale application, leading the rapid and profitable development of CCUS-EOR emerging industrial chain with innovation.

This paper summarizes the important progress in the field of oil and gas production engineering during the "Thirteenth Five-Year Plan" period, analyzes the challenges faced by the current oil and gas production engineering in terms of technological adaptability, digital construction, energy-saving and emission reduction, and points out the future development direction. During the "Thirteenth Five-Year Plan" period, major progress has been made in five major technologies, separated-layer injection, artificial lift, reservoir stimulation, gas well de-watering, and workover, which provide key technical support for continuous potential tapping of mature oilfields and profitable production of new oilfields. Under the current complex international political and economic situation, oil and gas production engineering is facing severe challenges in three aspects: technical difficulty increase in oil and gas production, insignificant improvements in digital transformation, and lack of core technical support for energy-saving and emission reduction. This paper establishes three major strategic directions and implementation paths, including oil stabilization and gas enhancement, digital transformation, and green and low-carbon development. Five key research areas are listed including fine separated-layer injection, high efficiency artificial lift, fine reservoir stimulation, long term gas well de-watering and intelligent workover, so as to provide engineering technical support for the transformation, upgrading and high-quality development of China's oil and gas industry.

Interference of thin-interbedded layers in seismic reflections has great negative impact on thin-interbedded reservoirs prediction. To deal with this, two novel methods are proposed that can predict the thin-interbedded reservoirs distribution through strata slices by suppressing the interference of adjacent layer with the help of seismic sedimentology. The plane distribution of single sand bodies in thin-interbedded reservoirs can be clarified. (1) The minimum interference frequency slicing method, uses the amplitude-frequency attribute estimated by wavelet transform to find a constant seismic frequency with the minimum influence on the stratal slice of target layer, and then an optimal slice corresponding the constant frequency mentioned above can be obtained. (2) The superimposed slicing method can calculate multiple interference coefficients of reservoir and adjacent layers of target geological body, and obtain superimposed slice by weighted stacking the multiple stratal slices of neighboring layers and target layer. The two proposed methods were used to predict the distribution of the target oil layers of 6 m thick in three sets of thin-interbedded reservoirs of Triassic Kelamayi Formation in the Fengnan area of Junggar Basin, Northwestern China. A comparison with drilling data and conventional stratal slices show that the two methods can predict the distribution of single sand bodies in thin-interbedded reservoirs more accurately.

By integrating surface geology, seismic data, resistivity profiles, and drilling data, the structural deformation characteristics of the frontier fault of thrust nappes were delineated in detail. The frontier fault of thrust nappes in northwest Scihuan Basin is a buried thrust fault with partial exposure in the Xiangshuichang-Jiangyou area, forming fault propagation folds in the hanging-wall and without presenting large-scale basin-ward displacement along the gypsum-salt layer of the Jialingjiang Formation to the Leikoupo Formation. The southwestern portion of the frontier fault of thrust nappes (southwest of Houba) forms fault bend folds with multiple ramps and flats, giving rise to the Zhongba anticline due to hanging-wall slip along the upper flat of the Jialingjiang Formation. In contrast, the northeastern portion of the frontier fault of thrust nappes (northeast of Houba) presents upward steepening geometry, leading to surface exposure of Cambrian in its hanging-wall. With the frontier fault of thrust nappes as the boundary between the Longmenshan Mountain and the Sichuan Basin, the imbricated structural belt in the hanging-wall thrusted strongly in the Indosinian orogeny and was reactivated in the Himalayan orogeny, while the piedmont buried structural belt in the footwall was formed in the Himalayan orogeny. In the footwall of the frontier fault of thrust nappes, the piedmont buried structural belt has good configuration of source rocks, reservoir rocks and cap rocks, presenting good potential to form large gas reservoirs. In comparison, the hanging-wall of the frontier fault of thrust nappes north of Chonghua has poor condition of oil/gas preservation due to the surface exposure of Triassic and deeper strata, while the fault blocks in the hanging-wall from Chonghua to Wudu, with Jurassic cover and thicker gypsum-salt layer of the Jialingjiang formation, has relative better oil/gas preservation conditions and thus potential of oil/gas accumulation. The frontier fault of thrust nappes is not only the boundary between the Longmenshan Mountain and the Sichuan Basin, but also the boundary of the oil/gas accumulation system in northwestern Sichuan Basin.

A multi-process (fracturing, shut-in and production) multi-phase flow model was derived considering the osmotic pressure, membrane effect, elastic energy and capillary force, to determine the optimal shut-in time after multi-cluster staged hydraulic fracturing in shale reservoirs for the maximum production. The accuracy of the model was verified by using production data and commercial software. Based on this model and method, a physical model was made based on the inversion of fracture parameters from fracturing pressure data, to simulate the dynamic changes of pore pressure and oil saturation during fracturing, soaking and production, examine effects of 7 factors on the optimal shut-in time, and find out the main factors affecting the optimal shut-in time through orthogonal experiments. With the increase of shut-in time, the increment of cumulative production increases rapidly first and then tended to a stable value, and the shut-in time corresponding to the inflection point of the change was the optimal shut-in time. The optimal shut-in time has a nonlinear negative correlation with matrix permeability, porosity, capillary pressure multiple and fracture length, a nonlinear positive correlation with the membrane efficiency and total volume of injected fluid, and a nearly linear positive correlation with displacement. The seven factors in descending order of influence degree on optimal shut-in time are total volume of injected fluid, capillary force multiple, matrix permeability, porosity, membrane efficiency, salinity of fracturing fluid, fracturing fluid displacement.

As the main factors affecting stable and high production and the production regularity of lacustrine shale oil are unclear, the theoretical understandings, key exploration and development technologies, development effect and production regularity of lacustrine shale oil have been analyzed and summarized based on 700 m cores taken systematically from Paleogene Kong 2 Member of 4 wells in Cangdong sag, over 100 000 analysis data and formation testing data. Three theoretical understandings on shale oil enrichment and high production have been reached: (1) High-quality shale with “three highs and one low” is the material base for shale oil enrichment. (2) Medium-slightly high thermal evolution degree is the favorable condition for shale oil enrichment. (3) Laminar felsic shale is the optimal shale layer for oil enrichment in semi-deep lake facies. Key exploration and development technologies such as shale oil enrichment layer and area evaluation and prediction, horizontal well pattern layout, shale oil reservoir fracturing, optimization of shale oil production regime have been established to support high and stable shale oil production. Under the guidance of these theoretical understandings and technologies, shale oil in Cangdong sag has achieved high and stable production, and 4 of them had the highest production of over 100 tons a day during formation testing. In particular, Well GY5-1-1L had a daily oil production of 208 m³. By April, 2022, the 28 wells combined have a stable oil production of 300-350 tons a day, and have produced 17.8×10⁴ t of oil cumulatively. It is found that the shale oil production of horizontal well declines exponentially in natural flow stage, and declines in step pattern and then tends stable in the artificial lift stage. Proportion of light hydrocarbons in produced shale oil is in positive correlation with daily oil production and decreases regularly during production test.

By reviewing the current status of drilling fluid technologies with primary intelligence features at home and abroad, the development background and intelligent response mechanisms of drilling fluid technologies such as variable density, salt response, reversible emulsification, constant rheology, shape memory loss prevention and plugging, intelligent reservoir protection and in-situ rheology control are elaborated, current issues and future challenges are analyzed, and it is pointed out that intelligent material science, nanoscience and artificial intelligence theory are important methods for future research of intelligent drilling fluid technology of horizontal wells with more advanced intelligent features of "self-identification, self-tuning and self-adaptation". Based on the aforementioned outline and integrated with the demands from the drilling fluid technology and intelligent drilling fluid theory, three development suggestions are put forward: (1) research and develop intelligent drilling fluids responding to variable formation pressure, variable formation lithology and fluid, variable reservoir characteristics, high temperature formation and complex ground environmental protection needs; (2) establish an expert system for intelligent drilling fluid design and management; and (3) establish a real-time intelligent check and maintenance processing network.

Geological conditions and main controlling factors of gas accumulation in subsalt Ma 4 Member of Ordovician Majiagou Formation are examined based on large amounts of drilling, logging and seismic data. The new understandings on the control of paleo-uplift over facies, reservoirs and accumulations are reached: (1) During the sedimentary period of Majiagou Formation, the central paleo-uplift divided the North China Sea in central-eastern of the basin from the Qinqi Sea at southwest margin of the basin, and controlled the deposition of the thick hummocky grain beach facies dolomite on platform margin of Ma 4 Member. Under the influence of the evolution of the central paleo-uplift, the frame of two uplifts alternate with two sags was formed in the central-eastern part of the basin, dolomite of inner-platform beach facies developed in the underwater low-uplift zones, and marl developed in the low-lying areas between uplifts. (2) From the central paleo-uplift to the east margin of the basin, the dolomite in the Ma 4 Member gradually becomes thinner and turns into limestone. The lateral sealing of the limestone sedimentary facies transition zone gives rise to a large dolomite lithological trap. (3) During the late Caledonian, the basin was uplifted as a whole, and the central paleo-uplift was exposed and denuded to various degrees; high-quality Upper Paleozoic Carboniferous-Permian coal measures source rocks deposited on the paleo-uplift in an area of 60 000 km², providing large-scale hydrocarbon for the dolomite lithological traps in the underlying Ma 4 Member. (4) During the Indosinian-Yanshanian stage, the basin tilted westwards, and central paleo-uplift depressed into an efficient hydrocarbon supply window. The gas from the Upper Paleozoic source rock migrated through the high porosity and permeability dolomite in the central paleo-uplift to and accumulated in the updip high part; meanwhile, the subsalt marine source rock supplied gas through the Caledonian faults and micro-fractures as a significant supplementary. Under the guidance of the above new understandings, two favorable exploration areas in the Ma 4 Member in the central-eastern basin were sorted out. Two risk exploration wells were deployed, both revealed thick gas-bearing layer in Ma 4 Member, and one of them tapped high production gas flow. The study has brought historic breakthrough in the gas exploration of subsalt Ma 4 Member of Ordovician, and opened up a new frontier of gas exploration in the Ordos Basin.

Reflected wave seismology has the following defects: the acquisition design is based on the assumption of layered media, the signal processing suppresses weak signals such as diffracted wave and scattered wave, and the seismic wave band after the image processing is narrow. They limit the full utilization of broadband raw data. The concept of full wave seismic exploration is redefined based on the idea of balanced utilization of reflected wave, diffracted wave and scattered wave information, its characteristics and adaptive conditions are clarified. A set of key technologies suitable for full wave seismic exploration are put forward. During seismic acquisition period, it is necessary to adopt multi geometry, i.e. embed small bin, small offset and small channel interval data in conventional geometry. By discretizing of common midpoint (CMP) gathers, small offset with high coverage, the weak signals such as diffracted wave and scattered wave in the raw seismic data can be enhanced. During seismic processing, the signal and noise in the original seismic data need to be redefined at first. The effective signals of seismic data are enhanced through merging of multi-geometry data merging. By means of differential application of data with different bin sizes and different arrangement modes, different regimes of seismic waves can be effectively decomposed and imaged separately. During seismic interpretation stage, making the most of the full wave seismic data, and adopting well-seismic calibration on multi-scale and multi-dimension, the seismic attributes in multi-regimes and multi-domains are interpreted to reveal interior information of complex lithology bodies and improve the lateral resolution of non-layered reservoirs.

As formation mechanisms of plugging zone and criteria for fracture plugging remain unclear, plugging experiments and methods testing granular material mechanical properties are used to study the formation process of the plugging zone in fractured formations, analyze composition and ratios of different sizes of particles in the plugging zone, and reveal the essence and driving energy of the formation and damage of the plugging zone. New criteria for selecting lost circulation materials are proposed. The research results show that the formation of the plugging zone has undergone a process from inertial flow, elastic flow, to quasi-static flow. The plugging zone is composed of fracture mouth plugging particles, bridging particles and filling particles, and the proportion of the three types of particles is an important basis for designing drilling fluid loss control formula. The essence of the construction of the plugging zone is non-equilibrium Jamming phase transition. The response of the plugging zone particle system to pressure is driven by entropy force; the greater the entropy, the more stable the plugging zone. Lost circulation control formula optimized according to the new criteria has better plugging effect than the formula made according to conventional plugging rules and effectively improves the pressure-bearing capacity of the plugging zone. The research results provide a theoretical and technical basis for the lost circulation control of fractured formations.

To achieve the goals of carbon peaking and carbon neutrality under the backgrounds of poor resource endowments, weak theoretical basis and other factors, the development of China’s coalbed methane industry faces many bottlenecks and challenges. This paper systematically analyzes the coalbed methane resources, key technologies and progress, exploration effect and production performance in China and abroad. The main problems are summarized as low exploration degree, low technical adaptability, low return on investment and small development scale. This study suggests that the coalbed methane industry in China should follow the “two-step” (short-term and long-term) development strategy. The short-term action before 2030, can be divided into two stages: (1) From the present to 2025, to achieve new breakthroughs in theory and technology, and accomplish the target of annual production of 10 billion cubic meters; (2) From 2025 to 2030, to form the technologies suitable for most geological conditions, further expand the industry scale, and achieve an annual output of 30 billion cubic meters, improving the proportion of coalbed methane in the total natural gas production. The long-term action after 2030 is to gradually realize an annual production of 100 billion cubic meters. The strategic countermeasure to achieve the above goals is to adhere to “technology+management dual wheel drive”, realize the synchronous progress of technology and management, and promote the high-quality development of the coalbed methane industry. Technically, the efforts will focus on fine and effective development of coalbed methane in the medium to shallow layers of mature fields, effective development of coalbed methane in new fields, extensive and beneficial development of deep coalbed methane, three-dimensional comingled development of coalbed methane, applying new technologies such as coalbed methane displacement by carbon dioxide, microwave heating and stimulation technology, ultrasonic stimulation, high-temperature heat injection stimulation, rock breaking by high-energy laser. In terms of management, the efforts will focus on coordinative innovation of resource, technology, talent, policy and investment, with technological innovation as the core, to realize an all-round and integrated management and promote the development of coalbed methane industry at a high level.

Distribution characteristics, organic matter development characteristics, gas-bearing characteristics, reservoir characteristics and preservation conditions of the Shahezi Formation shale of Lower Cretaceous in the Lishu fault depression, Songliao Basin are analyzed using organic geochemical, whole rock, and SEM analysis data, and CO₂ and N₂ adsorption and high pressure mercury injection experiment data in combination with the tectonic and sedimentation evolution of the region to reveal the geological conditions for enrichment and resource potential of continental shale gas. The organic-rich shale in the Lower Cretaceous of the Lishu fault depression is mainly developed in the lower sub-member of the second member of Shahezi Formation (K₁sh₂¹), and is thick and stable in distribution. The shale has high TOC, mainly types II₁ and II₂ organic matter, and is in mature to over mature stage. The volcanic activity, salinization and reduction water environment are conducive to formation of the organic-rich shale. The shale reservoirs have mainly clay mineral intergranular pores, organic matter pores, carbonate mineral dissolution pores and foliated microfractures as storage space. The pores are in the mesopore range of 10-50 nm, and the microfractures are mostly 5-10 μm wide. Massive argillaceous rocks of lowland and highstand domains are deposited above and below the gas-bearing shale separately in the lower sub-member of the K₁sh₂¹ Fm., act as the natural roof and floor in the process of shale gas accumulation and preservation, and control the shale gas enrichment. Based on the above understandings, the first shale gas exploration well in Shahezi Formation was drilled in the Lishu fault depression of Songliao Basin. After fracturing, the well tested a daily gas production of 7.6×10⁴ m³, marking a breakthrough in continental shale gas exploration in Shahezi Formation of Lishu fault depression in Songliao Basin. The exploration practice has reference significance for the exploration of continental shale gas in Lower Cretaceous of Songliao Basin and its periphery.

Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. The large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology.

By examining structures, sediments, reservoirs and accumulation assemblages in the Deyang-Anyue rift and its surrounding area, four new understandings are obtained. First, during the initiation period of Deyang-Anyue rift, multiple groups of faults developed in the rift due to the effect of tensile force, bringing about multiple mound and shoal belts controlled by horsts in the second member of Dengying Formation; in the development stage of the rift, the boundary faults of the rift controlled the development of mound and shoal belts at the platform margin in the fourth member of Dengying Formation; during the shrinkage period of the rift, platform margin grain shoals of Canglangpu Formation developed in the rift margin. Second, four sets of large-scale mound and shoal reservoirs in the second member of Dengying Formation, the fourth member of Dengying Formation, Canglangpu Formation and Longwangmiao Formation overlap with several sets of source rocks such as Qiongzhusi Formation source rocks and Dengying Formation argillaceous limestone or dolomite developed inside and outside the rift, forming good source-reservoir-cap rock combinations; the sealing of tight rock layers in the lateral and updip direction results in the formation model of large lithologic gas reservoirs of oil pool before gas, continuous charging and independent preservation of each gas reservoir. Third, six favorable exploration zones of large-scale lithologic gas reservoirs have been sorted out through comprehensive evaluation, namely, mound and shoal complex controlled by horsts in the northern part of the rift in the second member of Dengying Formation, isolated karst mound and shoal complex of the fourth member of Dengying Formation in the south of the rift, the superimposed area of multi-stage platform margin mounds and shoals of the second and fourth members of Dengying Formation and Canglangpu Formation in the north slope area, the platform margin mounds and shoals of the second and fourth members of Dengying Formation in the west side of the rift, the platform margin mound and shoal bodies of the fourth member of Dengying Formation in the south slope area, etc. Fourth, Well Pengtan-1 drilled on the mound and shoal complex controlled by horsts of the second member of Dengying Formation in the rift and Well Jiaotan-1 drilled on the platform margin mound and shoal complex of the North Slope have obtained high-yield gas flows in multiple target layers, marking the discovery of a new gas province with reserves of (2-3)×10¹² m³. This has proved the huge exploration potential of large lithologic gas reservoir group related to intracratonic rift.

A novel type curve is presented for oil recovery factor prediction suitable for gas flooding by innovatively introducing the equivalent water-gas cut to replace the water cut, comprehensively considering the impact of three-phase flow (oil, gas, water), and deriving the theoretical equations of gas flooding type curve based on Tong’s type curve. The equivalent water-gas cut is the ratio of the cumulative underground volume of gas and water production to the total underground volume of produced fluids. Field production data and the numerical simulation results are used to demonstrate the feasibility of the new type curve and verify the accuracy of the prediction results with field cases. The new type curve is suitable for oil recovery factor prediction of both water flooding and gas flooding. When a reservoir has no gas injected or produced, the gas phase can be ignored and only the oil and water phases need to be considered, in this case, this gas flooding type curve returns to the Tong’s type curve, which can evaluate the oil recovery factor of water flooding. For reservoirs with equivalent water-gas cuts of 60%-80%, the regression method of the new type curve works well in predicting the oil recovery factor. For reservoirs with equivalent water-gas cuts higher than 80%, both the regression and assignment methods of the new type curve can accurately predict the oil recovery factor of gas flooding.

The development history of carbon capture, utilization and storage for enhanced oil recovery (CCUS-EOR) in China is comprehensively reviewed, which consists of three stages: research and exploration, field test and industrial application. The breakthrough understanding of CO₂ flooding mechanism and field practice in recent years and the corresponding supporting technical achievements of CCUS-EOR project are systematically described. The future development prospects are also pointed out. After nearly 60 years of exploration, the theory of CO₂ flooding and storage suitable for continental sedimentary reservoirs in China has been innovatively developed. It is suggested that C₇-C₁₅ are also important components affecting miscibility of CO₂ and crude oil. The mechanism of rapid recovery of formation energy by CO₂ and significant improvement of block productivity and recovery factor has been verified in field tests. The CCUS-EOR reservoir engineering design technology for continental sedimentary reservoir is established. The technology of reservoir engineering parameter design and well spacing optimization has been developed, which focuses on maintaining miscibility to improve oil displacement efficiency and uniform displacement to improve sweep efficiency. The technology of CO₂ capture, injection and production process, whole-system anticorrosion, storage monitoring and other whole-process supporting technologies have been initially formed. In order to realize the efficient utilization and permanent storage of CO₂, it is necessary to take the oil reservoir in the oil-water transition zone into consideration, realize the large-scale CO₂ flooding and storage in the area from single reservoir to the overall structural control system. The oil reservoir in the oil-water transition zone is developed by stable gravity flooding of injecting CO₂ from structural highs. The research on the storage technology such as the conversion of residual oil and CO₂ into methane need to be carried out.

Based on the practice of oil and gas exploration and the analysis of shallow lithologic reservoirs, combined with the allocation relationship and enrichment law of oil and gas accumulation factors, main controlling factors and models of hydrocarbon accumulation of large lithologic reservoirs in shallow strata around the Bozhong sag are summarized, and favorable exploration areas are proposed. The coupling of the four factors of “ridge-fault-sand-zone” is crucial for the hydrocarbon enrichment in the shallow lithologic reservoirs. The convergence intensity of deep convergence ridges is the basis for shallow oil and gas enrichment, the activity intensity of large fault cutting ridges and the thickness of cap rocks control the vertical migration ability of oil and gas, the coupling degree of large sand bodies and fault cutting ridges control large-scale oil and gas filling, the fault sealing ability of structural stress concentration zones affects the enrichment degree of lithologic oil and gas reservoirs. Three enrichment models including uplift convergence type, steep slope sand convergence type and depression uplift convergence type are established through the case study of lithologic reservoirs in shallow strata around the Bozhong sag.

Aiming at the technology of hydraulic fracturing assisted oil displacement which combines hydraulic fracturing, seepage and oil displacement, an experimental system of energy storage and flowback in fracturing assisted oil displacement process has been developed and used to simulate the mechanism of percolation, energy storage, oil displacement and flowback of chemical agents in the whole process. The research shows that in hydraulic fracturing assisted oil displacement, the chemical agent could be directly pushed to the deeper area of the low and medium permeability reservoirs, avoiding the viscosity loss and adhesion retention of chemical agents near the pay zone; in addition, this technology could effectively enlarge the swept volume, improve the oil displacement efficiency, replenish formation energy, gather and exploit the scattered residual oil. For the reservoir with higher permeability, this measure takes effect fast, so to lower cost, and the high pressure hydraulic fracturing assisted oil displacement could be adopted directly. For the reservoir with lower permeability which is difficult to absorb water, hydraulic fracturing assisted oil displacement with surfactant should be adopted to reduce flow resistance of the reservoir and improve the water absorption capacity and development effect of the reservoir. The degree of formation energy deficit was the main factor affecting the effective swept range of chemical agents. Moreover, the larger the formation energy deficit was, the further the seepage distance of chemical agents was, accordingly, the larger the effective swept volume was, and the greater the increase of oil recovery was. Formation energy enhancement was the most important contribution to enhanced oil recovery (EOR), which was the key to EOR by the technology of hydraulic fracturing assisted oil displacement.

Taking continental lake basin shales of the Yanchang Formation in the Ordos Basin and the Qingshankou Formation in the Songliao Basin as research objects, the characteristics and origins of different types of silica in the shales have been studied by means of core observation, thin section identification, cathodoluminescence, X-ray diffraction analysis, scanning electron microscope (SEM), electron probe and rock pyrolysis. The results shows that the origins of silica include felsic mineral dissolution, tuffite devitrification, clay mineral transformation and siliceous mineral metasomatism. The silica formed by feldspar dissolution commonly appears as spots and veins, with low degree of crystallization, and is largely aqueous opal mineral, with an average SiO₂ content of 67.2%. Silica formed by devitrification of tuffite mainly occurs in two forms, amorphous silica and authigenic quartz with better crystal shape. The authigenic silica formed during the transformation of clay minerals is embedded in the clay minerals in the form of micron-scale plates and small flakes, or mixed with clay minerals in a dispersed state. The authigenic quartz formed by siliceous mineral metasomatism is in better angular crystal shape, and has an average SiO₂ content of 87%. The authigenic siliceous mineral content is positively correlated with the content of terrigenous felsic minerals. The pressure solution of felsic minerals is the main source of authigenic siliceous minerals, followed by the transformation of clay minerals, and the organic matter has some boost on the formation of authigenic silica. The authigenic siliceous materials of different origins have different geological characteristics and occurrence states from terrigenous quartz, which would affect the storage performance, seepage capacity and fracturing effect of continental shale. In particular, although the organic-rich shale has high silica content, different from terrigenous quartz, authigenic silica in this kind of shale mostly floats and disperse in clay minerals, which would have negative effect on the formation of complex fractures in fracturing, fracture support ability after fracturing, and formation of effective seepage channels. Therefore, calculating the brittleness index of shale intervals only based on the composition of brittle minerals cannot accurately characterize mechanical characteristics of continental shale oil reservoirs, and also would affect comprehensive evaluation and selection of continental shale oil “sweet spots”.

Shale gas wells frequently suffer from liquid loading and insufficient formation pressure in the late stage of production. To address this issue, an intelligent production optimization method for low pressure and low productivity shale gas well is proposed. Based on the artificial intelligence algorithms, this method realizes automatic production and monitoring of gas well. The method can forecast the production performance of a single well by using the long short-term memory neural network and then guide gas well production accordingly, to fulfill liquid loading warning and automatic intermittent production. Combined with adjustable nozzle, the method can keep production and pressure of gas wells stable automatically, extend normal production time of shale gas wells, enhance automatic level of well sites, and reach the goal of refined production management by making production regime for each well. Field tests show that wells with production regime optimized by this method increased 15% in estimated ultimate reserve (EUR). Compared with the development mode of drainage after depletion recovery, this method is more economical and can increase and stabilize production effectively, so it has a bright application prospect.

Through analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potential of oil and gas fields with production capacity not built and to be built, this paper presents the situation and trend of global oil and gas development in 2022. It is found that, in 2022, oil and gas fields are widely distributed worldwide, and upstream production activities continue to recover; the oil and gas reserves decrease slightly year on year, and the oil and gas reserves in sea areas increase significantly; the oil and gas production increases continuously, and the key resource countries make a significant contribution in oil and gas production growth; and the oil and gas fields with production capacity not built and to be built hold abundant reserves, and their development potential will be gradually released with the economic benefits increase. Further analysis is conducted from the perspectives of global oil and gas resources continuity, geopolitical risks, potential of international cooperation, and upgrade of unconventional oil and gas technology. Finally, in view of core business domains and strategies under the new situation, the Chinese oil companies are recommended to: (1) keep a foothold in onshore conventional oil and gas development by virtue of their comparative advantages and learning from other's experience in cooperation; (2) carry out pilot tests on development adjustment, and deepen the international cooperation in enhanced oil/gas recovery; (3) improve the oil and gas operation capabilities in sea areas to transform from follower as minority shareholder to joint venture and then to independent operations; and (4) seek appropriate ways for shale oil/gas development to reduce the dependence on foreign oil and gas.

The geological conditions and processes of fine-grained gravity flow sedimentation in continental lacustrine basins in China are analyzed to construct the model of fine-grained gravity flow sedimentation in lacustrine basin, reveal the development laws of fine-grained deposits and source-reservoir, and identify the sweet spot intervals of shale oil. The results show that fine-grained gravity flow is one of the important sedimentary processes in deep lake environment, and it can transport fine-grained clasts and organic matter in shallow water to deep lake, forming sweet spot intervals and high-quality source rocks of shale oil. Fine-grained gravity flow deposits in deep waters of lacustrine basins in China are mainly fine-grained high-density flow, fine-grained turbidity flow (including surge-like turbidity flow and fine-grained hyperpycnal flow), fine-grained viscous flow (including fine-grained debris flow and mud flow), and fine-grained transitional flow deposits. The distribution of fine-grained gravity flow deposits in the warm and humid unbalanced lacustrine basins are controlled by lake-level fluctuation, flooding events, and lakebed paleogeomorphology. During the lake-level rise, fine-grained hyperpycnal flow caused by flooding formed fine-grained channel-levee-lobe system in the flat area of the deep lake. During the lake-level fall, the sublacustrine fan system represented by unconfined channel was developed in the flexural slope breaks and sedimentary slopes of depressed lacustrine basins, and in the steep slopes of faulted lacustrine basins; the sublacustrine fan system with confined or unconfined channel was developed on the gentle slopes and in axial direction of faulted lacustrine basins, with fine-grained gravity flow deposits possibly existing in the lower fan. Within the fourth-order sequences, transgression might lead to organic-rich shale and fine-grained hyperpycnal flow deposits, while regression might cause fine-grained high-density flow, surge-like turbidity flow, fine-grained debris flow, mud flow, and fine-grained transitional flow deposits. Since the Permian, in the shale strata of lacustrine basins in China, multiple transgression-regression cycles of fourth-order sequences have formed multiple source-reservoir assemblages. Diverse fine-grained gravity flow sedimentation processes have created sweet spot intervals of thin siltstone consisting of fine-grained high-density flow, fine-grained hyperpycnal flow and surge-like turbidity flow deposits, sweet spot intervals with interbeds of mudstone and siltstone formed by fine-grained transitional flows, and sweet spot intervals of shale containing silty and muddy clasts and with horizontal bedding formed by fine-grained debris flow and mud flow. The model of fine-grained gravity flow sedimentation in lacustrine basin is significant for the scientific evaluation of sweet spot shale oil reservoir and organic-rich source rock.

Based on analyses of characteristics, hydrocarbon charging history and geological conditions for the formation of Sinian-Cambrian reservoirs in the north slope area of central Sichuan paleo-uplift, the natural gas origin, accumulation evolution, accumulation pattern and formation conditions of large lithologic gas reservoirs have been investigated. Through comprehensive analyses of natural gas composition, carbon and hydrogen isotopic compositions, fluid inclusions, reservoir bitumen, and geological conditions such as lithofacies paleogeography and beach body characterization, it is concluded that: (1) The natural gas in the Sinian-Cambrian of the north slope area is mainly oil cracking gas, and different contribution ratios of multiple sets of source rocks lead to different geochemical characteristics of natural gas in different reservoirs. (2) Although the both Sinian and Cambrian gas reservoirs in this area are lithologic gas reservoirs under monocline background, the former has normal-pressure and the latter has high-pressure. There are three types of source-reservoir-caprock combinations: single source with lower generation and upper reservoir, double sources with lower generation and upper reservoir or with side source and lateral reservoir, double sources with lower generation and upper reservoir or with upper generation and lower reservoir. The Permian-Triassic is the main generation period of oil, Early-Middle Jurassic is the main generation period of oil cracking gas and wet gas, and Late Jurassic-Cretaceous is the main generation period of dry gas. (3) The Sinian-Cambrian system of the north slope area has two favorable conditions for formation of large lithologic gas reservoirs, one is that the large scale beach facies reservoirs are located in the range of ancient oil reservoirs or near the source rocks, which is conducive to the "in-situ" large-scale accumulation of cracked gas in the paleo-oil reservoirs, the other is that the large scale mound-shoal complex reservoirs and sealing layers of inter beach tight zones match effectively to form large lithologic traps under the slope background. The research results confirm that the north slope area has large multi-layer lithologic gas reservoirs with more than one trillion cubic meters of natural gas resources and great exploration potential.

Aiming at the simulation of multi-phase flow in the wellbore during the processes of gas kick and well killing of complex-structure wells (e.g., directional wells, extended reach wells, etc.), a database including 3561 groups of experimental data from 32 different data sources is established. Considering the effects of fluid viscosity, pipe size, interfacial tension, fluid density, pipe inclination and other factors on multi-phase flow parameters, a new gas-liquid two-phase drift flow relation suitable for the full flow pattern and full dip range is established. The distribution coefficient and gas drift velocity models with a pipe inclination range of -90°-90° are established by means of theoretical analysis and data-driven. Compared with three existing models, the proposed models have the highest prediction accuracy and most stable performance. Using a well killing case with the backpressure method in the field, the applicability of the proposed model under the flow conditions with a pipe inclination range of -90°-80° is verified. The errors of the calculated shut in casing pressure, initial back casing pressure, casing pressure when adjusting the displacement are 2.58%, 3.43%, 5.35%, respectively. The calculated results of the model are in good agreement with the field backpressure data.

This paper analyzes the differences in geological and development characteristics between continental shale oil in China and marine shale oil in North America, reviews the evaluation methods and technological progress of the continental shale oil development in China, and points out the existing problems and development directions of the continental shale oil development. The research progress of development evaluation technologies such as favorable lithofacies identification, reservoir characterization, mobility evaluation, fracability evaluation, productivity evaluation and geological-mathematical modeling integration are introduced. The efficient exploration and development of continental shale oil in China are faced with many problems, such as weak basic theoretical research, imperfect exploration and development technology system, big gap in engineering technology between China and other countries, and high development cost. Three key research issues must be studied in the future: (1) forming differentiated development technologies of continental shale oil through geological and engineering integrated research; (2) strengthening the application of big data and artificial intelligence to improve the accuracy of development evaluation; (3) tackling enhanced shale oil recovery technology and research effective development method, so as to improve the development effect and benefit.