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.

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.

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.

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 origin of dolomite in Shahejie Formation shale of Jiyang Depression in eastern China were studied by means of petrologic identification, compositional analysis by X-ray diffraction, stable carbon and oxygen isotopic composition, and trace element and rare earth element analyses. The results show that the development of dolomite is limited in the lacustrine organic rich shale of Shahejie Formation in the study area. Three kinds of dolomite minerals can be identified: primary dolomite (D1), penecontemporaneous dolomite (D2), and ankerite (Ak). D1 has the structure of primary spherical dolomite, high magnesium and high calcium, with order degree of 0.3-0.5, and is characterized by the intracrystalline corrosion and coexistence of secondary enlargement along the outer edge. D2 has the characteristics of secondary enlargement, order degree of 0.5-0.7, high magnesium, high calcium and containing a little iron and manganese elements. Ak is characterized by high order degree of 0.7-0.9, rhombic crystal, high magnesium, high calcium and high iron. The micritic calcite belongs to primary origin on the basis of the carbon and oxygen isotopic compositions and the fractionation characteristics of rare earth elements. According to the oxygen isotopic fractionation equation between paragenetic dolomite and calcite, it is calculated that the formation temperature of dolomite in the shale is between 36.76-45.83 ℃, belonging to lacustrine low-temperature dolomite. Based on the maturation and growth mechanism of primary and penecontemporaneous dolomite crystals, a dolomite diagenetic sequence and the dolomitization process are proposed, which is corresponding to the diagenetic environment of Shahejie Formation shale in the study area.

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.

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.

Based on comprehensive analysis of cores, thin sections, logging and seismic data, the sequence stratigraphy and sedimentary evolution of the third and fourth members of Sinian Dengying Formation (Deng 3 and Deng 4 members for short) in the Gaomo area of Sichuan Basin were investigated, and the favorable zones for reservoir development in the Deng 3 Member and Deng 4 Member were predicted. (1) Two Type I and one TypeⅡsequence boundaries are identified in the Deng 3 and Deng 4 members. Based on the identified sequence boundaries, the Deng 3 and Deng 4 members can be divided into two third order sequences SQ3 and SQ4, which are well-developed, isochronal and traceable in this area; the SQ3 thins from west to the east, and the SQ4 thins from northwest to southeast. (2) The sedimentary environment from the depositional period of SQ3 to SQ4 has experienced the evolution from mixed platform to rimmed platform, and the platform rimmed system on the west side is characterized by the development of platform margin microbial mound and grain shoal assemblages. The intra-platform area is a restricted platform facies composed of a variety of dolomites, and there are local micro-geomorphic highlands of different scales and scattered intra-platform mounds and shoals. (3) The Deng 4 Member reservoirs, with obvious facies- controlled characteristic, are mainly distributed in the upper part of high-frequency upward shallow cycle and the high-stand systems tract of the third-order sequence vertically, and are more developed in the platform margin belt than in the intra-platform belt, and more developed in the Gaoshiti platform margin belt than in the west Suining platform margin belt on the plane. (4) Three types of favorable reservoir zones of Deng 4 Member have been finely delineated with 3D seismic data; among them, the mound and shoal facies zones developed in the ancient highlands of the intra-platform are the first choice for the next exploration and development of the Deng 4 Member.

Carbon dioxide storage and utilization has become an inevitable trend and choice for sustainable development under the background of global climate change and carbon neutrality. Carbon industry which is dominated by CO₂ capture, utilization and storage/ CO₂ capture and storage (CCUS/CCS) is becoming a new strategic industry under the goal of carbon neutrality. The sustainable development of carbon industry needs to learn from the experiences of global oil and gas industry development. There are three types of “carbon” in the earth system. Black carbon is the CO₂ that has not been sequestered or used and remains in the atmosphere for a long time; grey carbon is the CO₂ that has been fixed or permanently sequestered in the geological body, and blue carbon is the CO₂ that could be converted into products for human use through biological, physical, chemical and other ways. The carbon industry system covers carbon generation, carbon capture, carbon transportation, carbon utilization, carbon sequestration, carbon products, carbon finance, and other businesses. It is a revolutionary industrial field to completely eliminate “black carbon”. The development of carbon industry technical system takes carbon emission reduction, zero carbon, negative carbon and carbon economy as the connotation, and the construction of a low-cost and energy-efficient carbon industry system based on CCUS/CCS are strategic measures to achieve the goal of carbon neutrality and clean energy utilization globally. This will promote the “four 80%s” transformation of China's energy supply, namely, to 2060, the percentage of zero-carbon new energy in the energy consumption will be over 80% and the CO₂ emission will be decreased by 80% to ensure the carbon emission reduction of total 80×10⁸ t from the percentage of carbon-based fossil energy in the energy consumption of over 80%, and the percentage of CO₂ emission from energy of over 80% in 2021. The carbon industry in China is facing three challenges, large CO₂ emissions, high percentage of coal in energy consumption, and poor innovative system. Three strategic measures are proposed accordingly, including: (1) unswervingly develop carbon industrial system and ensure the achievement of carbon neutrality as scheduled by 2060; (2) vigorously develop new energy sources and promote a revolutionary transformation of China’s energy production and consumption structure; (3) accelerate the establishment of scientific and technological innovation system of the whole CO₂ industry. It is of great significance for continuously optimization of ecological environment and construction of green earth and ecological earth to develop the carbon industry system, utilize clean energy, and achieve the strategic goal of global carbon neutrality.

An intelligent prediction method for fractures in tight carbonate reservoir has been established by upgrading single-well fracture identification and interwell fracture trend prediction with artificial intelligence, modifying construction of interwell fracture density model, and modeling fracture network and making fracture property equivalence. This method deeply mines fracture information in multi-source isomerous data of different scales to reduce uncertainties of fracture prediction. Based on conventional fracture indicating parameter method, a prediction method of single-well fractures has been worked out by using 3 kinds of artificial intelligence methods to improve fracture identification accuracy from 3 aspects, small sample classification, multi-scale nonlinear feature extraction, and decreasing variance of the prediction model. Fracture prediction by artificial intelligence using seismic attributes provides many details of inter-well fractures. It is combined with fault-related fracture information predicted by numerical simulation of reservoir geomechanics to improve inter-well fracture trend prediction. An interwell fracture density model for fracture network modeling is built by coupling single well fracture identification and interwell fracture trend through co-sequential simulation. By taking the tight carbonate reservoir of Oligocene-Miocene AS Formation of A Oilfield in Zagros Basin of the Middle East as an example, the proposed prediction method was applied and verified. The single-well fracture identification improves over 15% compared with the conventional fracture indication parameter method in accuracy rate, and the inter-well fracture prediction improves over 25% compared with the composite seismic attribute prediction. The established fracture network model is well consistent with the fluid production index.

As sandstone layers in thin interbedded section are difficult to identify, conventional model-driven seismic inversion and data-driven seismic methods have low precision in predicting them. To solve this problem, a model-data-driven seismic AVO (amplitude variation with offset) inversion method based on a space-variant objective function has been worked out. In this method, zero delay cross-correlation function and F norm are used to establish objective function. Based on inverse distance weighting theory, change of the objective function is controlled according to the location of the target CDP (common depth point), to change the constraint weights of training samples, initial low-frequency models, and seismic data on the inversion. Hence, the proposed method can get high resolution and high-accuracy velocity and density from inversion of small sample data, and is suitable for identifying thin interbedded sand bodies. Tests with thin interbedded geological models show that the proposed method has high inversion accuracy and resolution for small sample data, and can identify sandstone and mudstone layers of about one-30th of the dominant wavelength thick. Tests on the field data of Lishui sag show that the inversion results of the proposed method have small relative error with well-log data, and can identify thin interbedded sandstone layers of about one-15th of the dominant wavelength thick with small sample data.

Considering the Neo-Tethyan tectonic process and the resulting environmental changes, a geodynamic model of “one-way train loading” is proposed to analyze the formation and evolution mechanism of the Persian Gulf Superbasin with the most abundant hydrocarbons in the world. The Persian Gulf Superbasin has long been in a passive continental margin setting since the Late Paleozoic in the process of unidirectional subduction, forming a superior regional space of hydrocarbon accumulation. During the Jurassic-Cretaceous, the Persian Gulf Superbasin drifted slowly at low latitudes, and developed multiple superimposed source-reservoir-caprock assemblages as a combined result of several global geological events such as the Hadley Cell, the Equatorial Upwelling Current, and the Jurassic True Polar Wander. The collision during the evolution of the foreland basin since the Cenozoic led to weak destruction, which was conducive to the preservation of oil and gas. Accordingly, it is believed that the slow drifting and long retention in favorable climate zone of the landmass are the critical factors for hydrocarbon enrichment. Moreover, the prospects of hydrocarbon potential in other landmasses in the Neo-Tethyan were proposed.

A set of method for predicting the favorable reservoir of deep shale gas based on machine learning is proposed through research of parameter correlation feature analysis principle, intelligent prediction method based on convolution neural network (CNN), and integrated fusion characterization method based on kernal principal component analysis (KPCA) nonlinear dimension reduction principle. (1) High-dimensional correlation characteristics of core and logging data are analyzed based on Pearson correlation coefficient. (2) The nonlinear dimension reduction method of KPCA is used to characterize complex high-dimensional data, so as to efficiently and accurately understand the core and logging response laws to favorable reservoirs. (3) CNN and logging data are used to train and verify the model similar to the underground reservoir. (4) CNN and seismic data are used to intelligently predict favorable reservoir parameters such as organic carbon content, gas content, brittleness and in-situ stress to effectively solve the problem of nonlinear and complex feature extraction in reservoir prediction. (5) KPCA is used to eliminate complex redundant information, mine big data characteristics of favorable reservoirs, and integrate and characterize various parameters to realize the comprehensive evaluation of reservoirs. This method has been used to predict the spatial distribution of favorable shale reservoirs in the Ordovician Wufeng Formation to Silurian Longmaxi Formation of Weirong shale gas field in Sichuan Basin. The predicted results are highly consistent with the actual core, logging, productivity data, proving that this method can provide effective support for the exploration and development of deep shale gas.

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.

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.

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

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.

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.

Aiming at the four issues of underground storage state, exploitation mechanism, crude oil flow and efficient recovery, the key theoretical and technical issues and countermeasures for effective development of Gulong shale oil are put forward. Through key exploration and research on fluid occurrence, fluid phase change, exploitation mechanism, oil start-up mechanism, flow regime/pattern, exploitation mode and enhanced oil recovery (EOR) of shale reservoirs with different storage spaces, multi-scale occurrence states of shale oil and phase behavior of fluid in nano confined space were provided, the multi-phase, multi-scale flow mode and production mechanism with hydraulic fracture-shale bedding fracture-matrix infiltration as the core was clarified, and a multi-scale flow mathematical model and recoverable reserves evaluation method were preliminarily established. The feasibility of development mode with early energy replenishment and recovery factor of 30% was discussed. Based on these, the researches of key theories and technologies for effective development of Gulong shale oil are proposed to focus on: (1) in-situ sampling and non-destructive testing of core and fluid; (2) high-temperature, high-pressure, nano-scale laboratory simulation experiment; (3) fusion of multi-scale multi-flow regime numerical simulation technology and large-scale application software; (4) waterless (CO₂) fracturing technique and the fracturing technique for increasing the vertical fracture height; (5) early energy replenishment to enhance oil recovery; (6) lifecycle technical and economic evaluation. Moreover, a series of exploitation tests should be performed on site as soon as possible to verify the theoretical understanding, optimize the exploitation mode, form supporting technologies, and provide a generalizable development model, thereby supporting and guiding the effective development and production of Gulong shale oil.

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.

Aiming at the differential distribution of overpressure in vertical and lateral directions in the foreland thrust belt in the southern margin of Junggar Basin, the study on overpressure origin identification and overpressure evolution simulation is carried out. Based on the measured formation pressure, drilling fluid density and well logging data, overpressure origin identification and overpressure evolution simulation techniques are used to analyze the vertical and lateral distribution patterns of overpressure, genetic mechanisms of overpressure in different structural belts and causes of the differential distribution of overpressure, and the controlling effects of overpressure development and evolution on the formation and distribution of oil and gas reservoirs. The research shows that overpressure occurs in multiple formations vertically in the southern Junggar foreland thrust belt, the deeper the formation, the bigger the scale of the overpressure is. Laterally, overpressure is least developed in the mountain front belt, most developed in the fold anticline belt, and relatively developed in the slope belt. The differential distribution of overpressure is mainly controlled by the differences in disequilibrium compaction and tectonic compression strengths of different belts. The vertical overpressure transmission caused by faults connecting the deep overpressured system has an important contribution to the further increase of the overpressure strength in this area. The controlling effect of overpressure development and evolution on hydrocarbon accumulation and distribution shows in the following aspects: When the strong overpressure was formed before reservoir becoming tight overpressure maintains the physical properties of deep reservoirs to some extent, expanding the exploration depth of deep and ultra-deep reservoirs; reservoirs below the Paleogene Anjihaihe Formation and Lower Cretaceous Tugulu Group overpressure mudstone cap rocks are main sites for oil and gas accumulation; under the background of overall overpressure, both overpressure strength too high or too low are not conducive to hydrocarbon enrichment and preservation, and the pressure coefficient between 1.6 and 2.1 is the best.

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.

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.

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.

Unconventional gas in the Sichuan Basin mainly includes shale gas and tight gas. The development of shale gas is mainly concentrated in the Ordovician Wufeng Formation-Silurian Longmaxi Formation, but has not made any significant breakthrough in the Cambrian Qiongzhusi Formation marine shale regardless of exploration efforts for years. The commercial development of tight sandstone gas is mainly concentrated in the Jurassic Shaximiao Formation, but has not been realized in the widespread and thick Triassic Xujiahe Formation. Depending on the geological characteristics of the Qiongzhusi Formation and Xujiahe Formation, the feedback of old wells was analyzed. Then, combining with the accumulation mechanisms of conventional gas and shale gas, as well as the oil/gas shows during drilling, changes in production and pressure during development, and other characteristics, it was proposed to change the exploration and development strategy from source and reservoir exploration to carrier beds exploration. With the combination of effective source rock, effective carrier beds and effective sandstone or shale as the exploration target, a model of unconventional gas accumulation and enrichment in carrier beds was built. Under the guidance of this study, two significant results have been achieved in practice. First, great breakthrough was made in exploration of the silty shale with low organic matter abundance in the Qiongzhusi Formation, which breaks the traditional approach to prospect shale gas only in organic-rich black shales and realizes a breakthrough in new areas, new layers and new types of shale gas and a transformation of exploration and development of shale gas from single-layer system, Longmaxi Formation, to multi-layer system in the Sichuan Basin. Second, exploration breakthrough and high-efficient development were realized for difficult-to-produce tight sandstone gas reserves in the Xujiahe Formation, which helps address the challenges of low production and unstable production of fracture zones in the Xujiahe Formation, promote the transformation of tight sandstone gas from reserves without production to effective production, and enhance the exploration and development potential of tight sandstone gas.

By analyzing the distribution of global oil and gas fields and the reasons why some oil and gas fields are not in production, the distribution characteristics of oil and gas remaining recoverable reserves and their year-on-year changes, the distribution characteristics of oil and gas production and their year-on-year changes, and the development potential of oil and gas to be tapped in 2021, this paper sorts out systematically the current status and characteristics of global oil and gas development, summaries the major trends of global oil and gas development, puts forward enlightenment for international oil and gas cooperation. In 2021, oil and gas fields were widely distributed, the number of non-producing oil and gas fields was large; the whole oil and gas remaining recoverable reserves declined slightly, unconventional oil and gas remaining recoverable reserves dropped significantly; the overall oil and gas production continuously increased, the outputs of key resource-host countries kept year-on-year growth; undeveloped oilfields had abundant reserves and great development potential. Combined with global oil and gas geopolitics, oil and gas industry development trends, oil and gas investment intensity, and the tracking and judgment of hotspot fields, the major trends of global oil and gas development in 2021 are summarized. On this basis, the four aspects of enlightenment and suggestions for international oil and gas cooperation and development strategies are put forward: attach great importance to the obligation of marine abandonment to ensure high-quality and long-term benefit development of offshore oil and gas; adhere to the principle of not going to dangerous and chaotic places, strengthen the concentration of oil and gas assets, and establish multi stable supply bases; based on the multi-scenario demand of natural gas, realize the transformation from integrated collaboration to full oil and gas industry chain development; increase the acquisition of high-quality large-scale assets, and pay attention to the continuous optimization of the shareholding ratio of projects at different stages.

To find out the relationship between the oil-based mud, the formation fluid and the extracted gas, we use a thermodynamic approach based on static headspace gas chromatography technique to calculate the partition coefficients of 47 kinds of light hydrocarbons compounds between nC₅ and nC₈ in two kinds of oil-based mud-air systems, and reconstruct the original formation fluid composition under thermodynamic equilibrium. The oil-based drilling mud has little effect on the formation fluid compositions in the range of nC₅-nC₈ (less than 1% for low-toxicity oil-based mud and less than 10% for oil-based mud). For most light hydrocarbon compositions, the partition coefficients obtained by vapor phase calibration and the direct quantitative methods have errors of less than 10%, and the partition coefficients obtained by direct quantitative method are more accurate. The reconstructed compositions of the two kinds of crude oil have match degrees of 91% and 89% with their real compositions, proving the feasibility and accuracy of reconstructing the composition of original formation fluid by using partition coefficients of light hydrocarbon compositions between nC₅ and nC₈.

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.

This paper investigates the deposition of asphaltenes in the porous medium of the studied field in Russia and predicts production profiles based on uncertainty evaluation. This problem can be solved by dynamic modeling, during which production profiles are estimated in two scenarios: with and without the activation of the asphaltene option. Calculations are carried out for two development scenarios: field operation under natural depletion and water injection into the aquifer as a reservoir pressure maintenance system. A full-scale compositional reservoir simulation model of the Russian oilfield was created. Within a dynamic simulation, the asphaltene option was activated and the asphaltene behavior in oil and porous medium was tuned according to our own special laboratory experiments. The model was also matched to production historical data, and a pattern model was prepared using the full-scale simulation model. Technological and the asphaltene option parameters were used in sensitivity and an uncertainty evaluation. Furthermore, probable production profiles within a forecast period were estimated. The sensitivity analysis of the pattern model to input parameters of the asphaltene option allowed determining the following heavy-hitters on the objective function: the molar weight of dissolved asphaltenes as a function of pressure, the asphaltene dissociation rate, the asphaltene adsorption coefficient and the critical velocity of oil movement in the reservoir. Under the natural depletion scenario, our simulations show a significant decrease in reservoir pressure and the formation of drawdown cones leading to asphaltene deposition in the bottom-hole area of production wells, decreasing their productivity. Water injection generally allows us to significantly reduce the volume of asphaltene phase transitions and has a positive effect on cumulative oil production. Injecting water into aquifer can keep the formation pressure long above the pressure for asphaltene precipitation, preventing the asphaltene deposition resulted from interaction of oil and water, so this way has higher oil production.

The history and results of petroleum exploration in the Santos Basin, Brazil are reviewed. The regularity of hydrocarbon enrichment and the key exploration technologies are summarized and analyzed using the seismic, gravity, magnetic and drilling data. It is proposed that the Santos Basin had a structural pattern of two uplifts and three depressions and the Aram-Uirapuru uplift belt controlled the hydrocarbon accumulation. It is believed that the main hydrocarbon source kitchen in the rift period controlled the hydrocarbon-enriched zones, paleo-structures controlled the scale and quality of lacustrine carbonate reservoirs, and continuous thick salt rocks controlled the hydrocarbon formation and preservation. The process and mechanism of reservoirs being transformed by CO₂ charging were revealed. Five key exploration technologies were developed, including the variable-velocity mapping for layer-controlled facies-controlled pre-salt structures, the prediction of lacustrine carbonate reservoirs, the prediction of intrusive/effusive rock distribution, the detection of hydrocarbons in lacustrine carbonates, and the logging identification of supercritical CO₂ fluid. These theoretical recognitions and exploration technologies have contributed to the discovery of deep-water super-large reservoirs under CNODC projects in Brazil, and will guide the further exploration of deep-water large reservoirs in the Santos Basin and other similar regions.

Based on the contemporary strategy of PetroChina and the “Super Basin Thinking” initiative, we analyze the petroleum system and remaining oil and gas resource distribution, the Super Basin development scheme in the Sichuan Basin with the aim of unlocking its full resource potential. We conclude that, (1) The three-stage evolution of the Sichuan Basin has resulted in the superimposed distribution of hydrocarbon systems dominated by natural gas. The prospecting Nanhua-rift stage gas system is potentially to be found in the ultra-deep part of the basin. The marine-cratonic stage gas system is distributed in the Sinian to Mid-Triassic formations, mainly conventional gas and shale gas resources. The foreland-basin stage tight sand gas and shale oil resources are found in the Upper Triassic-Jurassic formations. The distribution laws of conventional and unconventional resources are different in each system. (2) To ensure larger scale hydrocarbon exploration and production, technologies regarding deep to ultra-deep carbonate conventional gas, tight-sand gas, and shale oil are necessarily to be advanced. (3) In order to achieve the full hydrocarbon potential of the Sichuan Basin, pertinent exploration strategies are expected to be proposed with regard to each hydrocarbon system respectively, government and policy supports ought to be strengthened, and new cooperative pattern should be established. Introducing the “Super Basin Thinking” provides references and guidelines for further deployment of hydrocarbon exploration and production in the Sichuan Basin and other developed basins.

Based on the seismic, logging, drilling and other data, the distribution, structural types and mound-shoal hydrocarbon accumulation characteristics of platform margins of the Sinian Dengying Formation in the Deyang-Anyue Rift and its periphery were analyzed. Four types of platform margins are developed in the Dengying Formation, i.e., single-stage fault-controlled platform margin, multi-stage fault-controlled platform margin, gentle slope platform margin, and overlapping platform margin. In the Gaoshiti West-Weiyuan East area, single-stage fault controlled platform margins are developed in the Deng 2 Member, which trend in nearly NEE direction and are shielded by faults and mudstones, forming fault-controlled-lithologic traps. In the Lezhi-Penglai area, independent and multi-stage fault controlled platform margins are developed in the Deng 2 Member, which trend in NE direction and are controlled by synsedimentary faults; the mound-shoal complexes are aggraded and built on the hanging walls of the faults, and they are shielded by tight intertidal belts and the Lower Cambrian source rocks in multiple directions, forming fault-controlled-lithologic and other composite traps. In the Weiyuan-Ziyang area, gentle slope platform margins are developed in the Deng 2 Member, which trend in NW direction; the mound-shoal complexes are mostly thin interbeds as continuous bands and shielded by tight intertidal belts in the updip direction, forming lithologic traps. In the Gaoshiti-Moxi-Yanting area, overlapping platform margins are developed in the Deng 2 and Deng 4 members; the mound-shoal complexes are aggraded and overlaid to create platform margin buildup with a huge thickness and sealed by tight intertidal belts and the Lower Cambrian mudstones in the updip direction, forming large-scale lithologic traps on the north slope of the Central Sichuan Paleouplift. To summarize, the mound-shoal complexes on the platform margins in the Dengying Formation in the Penglai-Zhongjiang area, Moxi North-Yanting area and Weiyuan-Ziyang area are large in scale, with estimated resources of 1.58×10¹² m³, and they will be the key targets for the future exploration of the Dengying Formation in the Sichuan Basin.

Based on the results of drilling, tests and simulation experiments, the shales of the Cretaceous Qingshankou Formation in the Gulong Sag of the Songliao Basin are discussed with respect to hydrocarbon generation evolution, shale oil occurrence, and pore/fracture evolution mechanism. Combined with a large amount of oil testing and production data, the Gulong shale oil enrichment layers are evaluated and the production behaviors and decline law are analyzed. The results are obtained in four aspects. First, the Gulong shales enter into a stage of extensive hydrocarbon expulsion when R_o is 1.0%-1.2%, with the highest hydrocarbon expulsion efficiency of 49.5% approximately. In the low-medium maturity stage, shale oil migrates from kerogen to rocks and organic pores/fractures. In the medium-high maturity stage, shale oil transforms from adsorbed state to free state. Second, the pore structure is mainly composed of clay mineral intergranular pores/fractures, dissolution pores, and organic pores. During the transformation of clay minerals, a large number of intergranular pores/fractures are formed between the minerals such as illite and illite/smectite mixed layer. A network of pores/fractures is formed by organic matter cracking. Third, free hydrocarbon content, effective porosity, total porosity, and brittle mineral content are the core indicators for evaluation of shale oil enrichment layers. Class-I layers are defined as free hydrocarbon content equal or greater than 6.0 mg/g, effective porosity equal or greater than 3.5%, total porosity equal or greater than 8.0%, and brittle mineral content equal or greater than 50%. It is believed that the favourable layers are Q2-Q3 and Q8-Q9. Fourth, the horizontal wells in the core area of the light oil zone exhibit a high cumulative production in the first year, and present a hyperbolic production decline pattern, with the decline index of 0.85-0.95, the first-year decline rate of 14.5%-26.5%, and the single-well estimated ultimate recovery (EUR) greater than 2.0×10⁴ t. In practical exploration and production, more efforts will be devoted to the clarification of hydrocarbon generation and expulsion mechanisms, accurate testing of porosity and hydrocarbon content/phase of shale under formation conditions, precise delineation of the boundary of enrichment area, relationship between mechanical properties and stimulated reservoir volume, and enhanced oil recovery, in order to improve the EUR and achieve a large-scale, efficient development of shale oil.

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 the oil and gas exploration practice in the Songliao Basin, combined with the latest exploration and development data such as seismic, well logging and geochemistry, the basic geological conditions, oil and gas types and distribution characteristics, reservoir-forming dynamics, source-reservoir relationship and hydrocarbon accumulation model of the total petroleum system in shallow and medium strata in the northern part of Songliao Basin are systematically studied. The shallow-medium strata in northern Songliao Basin have the conditions for the formation of total petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a total petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the total petroleum system are correlated with each other in terms of depositional system, lithologic association and physical property changes, and they, to a certain extent, have created the spatial framework with orderly symbiosis of shallow-medium conventional oil reservoirs, tight oil reservoirs and shale oil reservoirs in northern Songliao Basin. Vertically, the resources are endowed as conventional oil above source, shale oil/tight oil within source, and tight oil below source. Horizontally, conventional oil, tight oil, interlayer-type shale oil, and pure shale-type shale oil are developed in an orderly way, from the margin of the basin to the center of the depression. Three hydrocarbon accumulation models are recognized for the total petroleum system in northern Songliao Basin, namely, buoyancy-driven charging of conventional oil above source, retention of shale oil within source, and pressure differential-driven charging of tight oil below source.

Aiming at the scientific problem that only part of dolomite acts as dolomite reservoir, this paper takes the multiple dolomite-bearing formations in the Tarim, Sichuan and Ordos basins as the study object, by means of mineral petrological analysis and geochemical methods including carbonate clumped isotope, U-Pb isotopic dating, etc., to rebuild the dolomitization pathway and evaluate its effects on reservoir formation. On the basis of detailed rock thin section observation, five dolomitic structural components are identified, including original fabric-retained dolomite (microbial and/or micrite structure), buried metasomatic dolomite I (subhedral-euhedral fine, medium and coarse crystalline structure), buried metasomatic dolomite II (allotriomorphic-subhedral fine, medium and coarse crystalline structure), buried precipitation dolomite and coarse crystalline saddle dolomite. Among them, the first three exist in the form of rocks, the latter two occur as dolomite minerals filling in pores and fractures. The corresponding petrological and geochemical identification templates for them are established. Based on the identification of the five dolomitic structural components, six dolomitization pathways for three types of reservoirs (preserved dolomite, reworked dolomite and limestone buried dolomitization) are distinguished. The initial porosity of the original rock before dolomitization and the dolomitization pathway are the main factors controlling the development of dolomite reservoirs. The preserved dolomite and reworked dolomite types have the most favorable dolomitization pathway for reservoir formation, and are large scale and controlled by sedimentary facies in development and distribution, making them the first choices for oil and gas exploration in deep carbonate formations.

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.

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.

This paper systematically presents the established technologies and field applications with respect to research and engineering practice of CO₂ capture, enhanced oil recovery (EOR), and storage technology in Jilin Oilfield, NE China, and depicts the available series of supporting technologies across the industry chain. Through simulation calculation + pilot test + field application, the adaptability of the technology for capturing CO₂ with different concentrations in oilfields was confirmed. The low energy-consumption, activated N-methyl diethanolamine (MDEA) decarburization technology based on a new activator was developed, and the operation mode of CO₂ gas-phase transportation through trunk pipeline network, supercritical injection at wellhead, and produced gas-liquid separated transportation was established. According to different gas source conditions, liquid, supercritical phase, high-pressure dense phase pressurization technologies and facilities were applied to form the downhole injection processes (e.g. gas-tight tubing and coiled tubing) and supporting anti-corrosion and anti-blocking techniques. In the practice of oil displacement, the oil recovery technologies (e.g. conical water-alternating-gas injection, CO₂ foam flooding, and high gas-oil ratio CO₂ flooding) and produced fluid processing technologies were developed. Through numerical simulation and field tests, three kinds of CO₂ cyclic injection technologies (i.e. direct injection, injection after separation and purification, and hybrid injection) were formed, and a 10×10⁴ m³/d cyclic injection station was constructed to achieve "zero emission" of associated gas. The CO₂ storage safety monitoring technology of carbon flux, fluid composition and carbon isotopic composition was formed. The whole-process anti-corrosion technology with anticorrosive agents supplemented by anticorrosive materials was established. An integrated demonstration area of CO₂ capture, flooding and storage with high efficiency and low energy-consumption has been built, with a cumulative oil increment of 32×10⁴ t and a CO₂ storage volume of 250×10⁴ t.