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 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.

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.

By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of picotype algae, microalgae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organic clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.

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.

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.

Through core observation, experimental analysis and geological analysis, the main factors controlling shale oil enrichment in the Lower Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin are clarified, and shale oil enrichment models are established. The enrichment of shale oil in the Fengcheng Formation in the Mahu Sag is controlled by the organic matter abundance and type, storage capacity, and migration amount of hydrocarbons in shale. The organic matter abundance provides the material basis for shale oil enrichment, and the shales containing Types I and II organic matters have good oil content. The storage capacity restricts shale oil enrichment. Macropores are the main space for shale oil enrichment in the Fengcheng Formation, and pore size and fracture scale directly control the degree of shale oil enrichment. The migration of hydrocarbons in shale affects shale oil enrichment. The shale that has expelled hydrocarbons has poor oil content, while the shale that has received hydrocarbons migrated from other strata has good oil content. Lithofacies reflect the hydrocarbon generation and storage capacity comprehensively. The laminated felsic shale, laminated lime-dolomitic shale and thick-layered felsic shale have good oil content, and they are favorable lithofacies for shale oil enrichment. Under the control of these factors, relative migration of hydrocarbons occurred within the Fengcheng Formation shale, which led to the differences in the process of shale oil enrichment. Accordingly, the models of shale oil enrichment in the Fengcheng Formation are established as in-situ enrichment and migration enrichment. By superimposing favorable lithofacies and controlling factors of enrichment, the sweet spots of shale oil in the Fengcheng Formation can be defined to guide the exploration and development of shale oil.

In the Jiaoshiba block of the Fuling shale gas field, the employed reserves and recovery factor by primary well pattern are low, no obvious barrier is found in the development layer series, and layered development is difficult. Based on the understanding of the main factors controlling shale gas enrichment and high production, the theory and technology of shale gas three-dimensional development, such as fine description and modeling of shale gas reservoir, optimization of three-dimensional development strategy, highly efficient drilling with dense well pattern, precision fracturing and real-time control, are discussed. Three-dimensional development refers to the application of optimal and fast drilling and volume fracturing technologies, depending upon the sedimentary characteristics, reservoir characteristics and sweet spot distribution of shale gas, to form “artificial gas reservoir” in a multidimensional space, so as to maximize the employed reserves, recovery factor and yield rate of shale gas development. In the research on shale gas three-dimensional development, the geological + engineering sweet spot description is fundamental, the collaborative optimization of natural fractures and artificial fractures is critical, and the improvement of speed and efficiency in drilling and fracturing engineering is the guarantee. Through the implementation of three-dimensional development, the overall recovery factor in the Jiaoshiba block has increased from 12.6% to 23.3%, providing an important support for the continuous and stable production of the Fuling shale gas field.

The shale oil and gas exploitation in China is technically benchmarked with the United States in terms of development philosophy, reservoir stimulation treatment, fracturing parameters, fracturing equipment and materials, oil/gas production technology, and data/achievements sharing. It is recognized that the shale oil and gas exploitation in China is weak in seven aspects: understanding of flow regimes, producing of oil/gas reserves, monitoring of complex fractures, repeated stimulation technology, oil/gas production technology, casing deformation prevention technology, and wellbore maintenance technology. Combined with the geological and engineering factors of shale oil and gas in China, the development suggestions of four projects are proposed from the macro- and micro-perspective, namely, basic innovation project, exploitation technology project, oil/gas production stabilization project, and supporting efficiency-improvement project, so as to promote the rapid, efficient, stable, green and extensive development of shale oil and gas industry chain and innovation chain and ultimately achieve the goal of “oil volume stabilizing and gas volume increasing”.

The geological characteristics and production practices of major middle- and high-maturity shale oil exploration areas in China are analyzed. Combined with laboratory results, it is clear that three essential conditions, i.e. economic initial production, commercial cumulative oil production of single well, and large-scale recoverable reserves confirmed by the testing production, determine whether the continental shale oil can be put into large-scale commercial development. The quantity and quality of movable hydrocarbons are confirmed to be crucial to economic development of shale oil, and also focuses in evaluation of shale oil enrichment area/interval. The evaluation indexes of movable hydrocarbon enrichment include: (1) the material basis for forming retained hydrocarbon, including TOC>2% (preferentially 3%-4%), and type I-II₁ kerogens; (2) the mobility of retained hydrocarbon, which is closely related to the hydrocarbon composition and flow behaviors of light/heavy components, and can be evaluated from the perspectives of thermal maturity (R_o), gas-oil ratio (GOR), crude oil density, quality of hydrocarbon components, preservation conditions; and (3) the reservoir characteristics associated with the engineering reconstruction, including the main pore throat distribution zone, reservoir physical properties (including fractures), lamellation feature and diagenetic stage, etc. Accordingly, 13 evaluation indexes in three categories and their reference values are established. The evaluation indicates that the light shale oil zones in the Gulong Sag of Songliao Basin have the most favorable enrichment conditions of movable hydrocarbons, followed by light oil and black oil zones, containing 20.8×10⁸ t light oil resources in reservoirs with R_o>1.2%, pressure coefficient greater than 1.4, effective porosity greater than 6%, crude oil density less than 0.82 g/cm³, and GOR>100 m³/m³. The shale oil in the Gulong Sag can be explored and developed separately by the categories (resource sweet spot, engineering sweet spot, and tight oil sweet spot) depending on shale oil flowability. The Gulong Sag is the most promising area to achieve large-scale breakthrough and production of continental shale oil in China.

Through the study of organic matter enrichment, hydrocarbon generation and accumulation process of black shale of the Cretaceous Qingshankou Formation in the Songliao Basin, the enrichment mechanism of Gulong shale oil and the distribution of conventional-unconventional oil are revealed. The Songliao Basin is a huge interior lake basin formed in the Early Cretaceous under the control of the subduction and retreat of the western Pacific plate and the massive horizontal displacement of the Tanlu Fault Zone in Northeast China. During the deposition of the Qingshankou Formation, strong terrestrial hydrological cycle led to the lake level rise of the ancient Songliao Basin and the input of a large amount of nutrients, resulting in planktonic bacteria and algae flourish. Intermittent seawater intrusion events promoted the formation of salinization stratification and anoxic environment in the lake, which were beneficial to the enrichment of organic matters. Biomarkers analysis confirms that the biogenic organic matter of planktonic bacteria and algae modified by microorganisms plays an important role in the formation of high-quality source rocks with high oil generation capability. There are four favorable conditions for the enrichment of light shale oil in the Qingshankou Formation of the Gulong Sag, Songliao Basin: the moderate organic matter abundance and high oil potential provide sufficient material basis for oil enrichment; high degree of thermal evolution makes shale oil have high GOR and good mobility; low hydrocarbon expulsion efficiency leads to a high content of retained hydrocarbons in the source rock; and the confinement effect of intra-layer cement in the high maturity stage induces the efficient accumulation of light shale oil. The restoration of hydrocarbon accumulation process suggests that liquid hydrocarbons generated in the early (low-medium maturity) stage of the Qingshankou Formation source rocks accumulated in placanticline and slope after long-distance secondary migration, forming high-quality conventional and tight oil reservoirs. Light oil generated in the late (medium-high maturity) stage accumulated in situ, forming about 15 billion tons of Gulong shale oil resources, which finally enabled the orderly distribution of conventional-unconventional oils that are contiguous horizontally and superposed vertically within the basin, showing a complete pattern of “whole petroleum system” with conventional oil, tight oil and shale oil in sequence.

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.

To investigate the impacts of water/supercritical CO₂-rock interaction on the micro-mechanical properties of shale, a series of high temperature and high pressure immersion experiments were performed on the calcareous laminated shale samples mined from the lower submember of the third member of Paleogene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin. After that, grid nanoindentation tests were conducted to analyze the influence of immersion time, pressure, and temperature on micro-mechanical parameters. Experimental results show that the damage of shale caused by the water/supercritical CO₂-rock interaction was mainly featured by the generation of induced fractures in the clay-rich laminae. In the case of soaking with supercritical CO₂, the aperture of induced fracture was smaller. Due to the existence of induced fractures, the statistical averages of elastic modulus and the hardness both decreased. Meanwhile, compaction and stress-induced tensile fractures could be observed around the laminae. Generally, the longer the soaking time, the higher the soaking pressure and temperature, the more significant the degradation of micro-mechanical parameters is. Compared with water-rock interaction, the supercritical CO₂-rock interaction caused lower degree of mechanical damage on shale surface. Thus, supercritical CO₂ can be used as a fracturing fluid to prevent the surface softening of induced fractures in shale reservoirs.

This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology used in the Gulong shale oil reservoirs and gives suggestions about stimulation technology development in relation to the production performance of Gulong shale oil wells. Under the control of high-density bedding fractures, fracturing in the Gulong shale results in a complex fracture morphology, yet with highly suppressed fracture height and length. Hydraulic fracturing fails to generate artificial fractures with sufficient lengths and heights, which is a main restraint on the effective stimulation in the Gulong shale oil reservoirs. In this regard, the fracturing design shall follow the strategy of “controlling near-wellbore complex fractures and maximizing the extension of main fractures”. Increasing the proportions of guar gum fracturing fluids, reducing perforation clusters within one fracturing stage, raising pump rates and appropriately exploiting stress interference are conducive to fracture propagation and lead to a considerably expanded stimulated reservoir volume (SRV). The upgraded main hydraulic fracturing technology is much more applicable to the Gulong shale oil reservoirs. It accelerates the oil production with a low flowback rate and lifts oil cut during the initial production of well groups, which both help to improve well production. It is suggested to optimize the hydraulic fracturing technology in six aspects, namely, suppressing propagation of near-wellbore microfractures, improving the pumping scheme of CO₂, managing the perforating density, enhancing multi-proppant combination, reviewing well pattern/spacing, and discreetly applying fiber-assisted injection, so as to improve the SRV, the distal fracture complexity and the long-term fracture conductivity.

The strike-slip faults and reservoirs in deep Sinian strata in the Anyue gas field of the Sichuan Basin were analyzed to identify the main controlling factors of dolomite reservoirs along the strike-slip fault zone and clarify how the strike-slip faults control the development and distribution of high-quality “sweet spot” (fractured-vuggy) reservoirs. The carbonate matrix reservoirs of the Sinian Dengying Formation are tight, with low porosity (less than 4%) and low permeability (less than 0.5×10^-3 μm²). However, the strike-slip faults and their dissolution processes increased the permeability of carbonate rock by more than 1 order of magnitude and allowed the faulting-related dissolution porosity to be more than doubled. The “sweet spot” fractured-vuggy reservoirs controlled by strike-slip faults occurred widely along the strike-slip fault zone. These reservoirs were formed at the end of the Sinian under the joint control of sedimentary microfacies, faulting and karstification. At the platform margin, the control of karstification is predominant; while high-quality reservoirs controlled by both faulting and karstification are developed with the platform, and they are different in areas, types and zones. The structures of the strike-slip fault zone controlled the differential distribution of the fracture zones and the fault-controlled “sweet spot” reservoirs, and led to wide fracture-vug zones. In conclusion, the strike-slip fault related “sweet spot” reservoirs represent a new type of targets for efficient development of resources in deep ancient carbonates. For these reservoirs, specific development strategies should be made according to the diverse and differential controls of strike-slip faults on the reservoirs.

To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratios branched fracture opening time and injection sequence of proppants in varied particle sizes. The results show that the settled proppant height increases and the placement length decreases in main fractures as the fracturing fluid diverts gradually to the branched fractures at different positions. The flow rate in branched fractures is the main factor affecting their filling. The diverion to branched fractures leads to low flow rate and poor filling of far-wellbore branched fractures. The inclined fracture wall exerts a frictional force on the proppant to slow its settlement, thus enhancing the vertical proppant distribution in the fracture. The increase of sand ratio can improve the filling of near-wellbore main fracture and far-wellbore branched fracture and also increase the settled proppant height in main fracture. Due to the limitation of fracture height, when the sand ratio increases to a certain level, the increment of fracture filling decreases. In branched fracture, the support effect is the best when it is always open (or extends continuously). In main fracture, where the proppant placement length is small, the support effect is better when it is first closed and then opened (or extends in late stage) than when it is first opened and then closed (or extends in early stage). Injection sequence of proppants in varied particle sizes can improve the placement lengths of main fracture and branched fracture. Injection of proppants in an ascending order of particle size improves the near-wellbore fracture filling, to a better extent than that in a descending order of particle size.

The geochemical analysis and experimental simulation are comprehensively used to systematically study the hydrocarbon generation parent material, organic matter enrichment and hydrocarbon generation model of Paleogene source rock in the Western Qaidam Depression, Qaidam Basin, NW China. Three main factors result in low TOC values of source rock in the saline lake basin of the Qaidam Basin: relatively poor nutrient supply inhibits the algal bloom, too fast deposition rate causes the dilution of organic matter, and high organic matter conversion efficiency causes the low residual organic carbon. For this type of hydrogen-rich organic matter, due to the reduction of organic carbon during hydrocarbon generation, TOC needs to be restored based on maturity before evaluating organic matter abundance. The hydrocarbon generation of source rocks in the saline lake basin of the Qaidam Basin is from two parts: soluble organic matter and insoluble organic matter. The soluble organic matter is inherited from organisms and preserved in saline lake basins. It generates hydrocarbons during low-maturity evolution stages, and the formed hydrocarbons are rich in complex compounds such as NOS, and undergo secondary cracking to form light components in the later stage; the hydrocarbon generation model of insoluble organic matter conforms to the traditional “Tissot” model, with an oil generation peak corresponding to R_o of 1.0%.

The features of the unconformity, fault and tectonic inversion in the eastern Doseo Basin, Chad, were analyzed, and the genetic mechanisms and basin evolution were discussed using seismic and drilling data. The following results are obtained. First, four stratigraphic unconformities, i.e. basement (T_g), Mangara Group (T₁₀), lower Upper Cretaceous (T₅) and Cretaceous (T₄), four faulting stages, i.e. Barremian extensional faults, Aptian-Coniacian strike-slip faults, Campanian strike-slip faults, and Eocene strike-slip faults, and two tectonic inversions, i.e. Santonian and end of Cretaceous, were developed in the Doseo Basin. Second, the Doseo Basin was an early failed intracontinental passive rift basin transformed by the strike-slip movement and tectonic inversion. The initial rifting between the African and South American plates induced the nearly N-S stretching of the Doseo Basin, giving rise to the formation of the embryonic Doseo rift basin. The nearly E-W strike-slip movement of Borogop (F1) in the western section of the Central African Shear Zone resulted in the gradual cease of the near north-south rifting and long-term strike-slip transformation, forming a dextral transtension fault system with inherited activity but gradually weakened in intensity (interrupted by two tectonic inversions). This fault system was composed of the main shear (F1), R-type shear (F2-F3) and P-type shear (F4-F5) faults, with the strike-slip associated faults as branches. The strike-slip movements of F1 in Cretaceous and Eocene were controlled by the dextral shear opening of the equatorial south Atlantic and rapid expanding of the Indian Ocean, respectively. The combined function of the strike-slip movement of F1 and the convergence between Africa and Eurasia made the Doseo Basin underwent the Santonian dextral transpressional inversion characterized by intensive folding deformation leading to the echelon NE-SW and NNE-SSW nose-shaped uplifts and unconformity (T₅) on high parts of the uplifts. The convergence between Africa and Eurasia caused the intensive tectonic inversion of Doseo Basin at the end of Cretaceous manifesting as intensive uplift, denudation and folding deformation, forming the regional unconformity (T₄) and superposing a nearly E-W structural configuration on the Santonian structures. Third, the Doseo Basin experienced four evolutional stages with the features of short rifting and long depression, i.e. Barremian rifting, Aptian rifting-depression transition, Albian-Late Cretaceous depression, and Cenozoic extinction, under the control of the tectonic movements between Africa and its peripheral plates.

Mesozoic marine shale oil was found in the Qiangtang Basin by a large number of hydrocarbon geological surveys and shallow drilling sampling. Based on systematic observation and experimental analysis of outcrop and core samples, the deposition and development conditions and characteristics of marine shale are revealed, the geochemical and reservoir characteristics of marine shale are evaluated, and the layers of marine shale oil in the Mesozoic are determined. The following geological understandings are obtained. First, there are two sets of marine organic-rich shales, the Lower Jurassic Quse Formation and the Upper Triassic Bagong Formation, in the Qiangtang Basin. They are mainly composed of laminated shale with massive mudstone. The laminated organic-rich shale of the Quse Formation is located in the lower part of the stratum, with a thickness of 50-75 m, and mainly distributed in southern Qiangtang Basin and the central-west of northern Qiangtang Basin. The laminated organic-rich shale of the Bagong Formation is located in the middle of the stratum, with a thickness of 250-350 m, and distributed in both northern and southern Qiangtang Basin. Second, the two sets of laminated organic-rich shales develop foliation, and various types of micropores and microfractures. The average content of brittle minerals is 70%, implying a high fracturability. The average porosity is 5.89%, indicating good reservoir physical properties to the level of moderate-good shale oil reservoirs. Third, the organic-rich shale of the Quse Formation contains organic matters of types II₁ and II₂, with the average TOC of 8.34%, the average content of chloroform bitumen 'A' of 0.66%, the average residual hydrocarbon generation potential (S₁+S₂) of 29.93 mg/g, and the R_o value of 0.9%-1.3%, meeting the standard of high-quality source rock. The organic-rich shale of the Bagong Formation contains mixed organic matters, with the TOC of 0.65%-3.10% and the R_o value of 1.17%-1.59%, meeting the standard of moderate source rock. Fourth, four shallow wells (depth of 50-250 m) with oil shows have been found in the organic shales at 50-90 m in the lower part of the Bagong Formation and 30-75 m in the middle part of the Quse Formation. The crude oil contains a high content of saturated hydrocarbon. Analysis and testing of outcrop and shallow well samples confirm the presence of marine shale oil in the Bagong Formation and the Quse Formation. Good shale oil intervals in the Bagong Formation are observed in layers 18-20 in the lower part of the section, where the shales with (S₀+S₁) higher than 1 mg/g are 206.7 m thick, with the maximum and average (S₀+S₁) of 1.92 mg/g and 1.81 mg/g, respectively. Good shale oil intervals in the Quse Formation are found in layers 4-8 in the lower part of the section, where the shales with (S₀+S₁) higher than 1 mg/g are 58.8 m thick, with the maximum and average (S₀+S₁) of 6.46 mg/g and 2.23 mg/g, respectively.

A self-designed full-diameter core experimental facility was used to evaluate the flow heterogeneity of bedding fractures at four radial directions under different closure pressures and injection rates, using full-diameter cores retaining original natural bedding fractures. The distribution morphology of bedding surface affects the conductivity of bedding fractures, and the flow capacity of bedding fractures in four radial directions varies greatly with the closure pressure and injection rate. The rougher the fracture surface, the greater the flow capacity varies with the closure pressure. For unsupported bedding fractures, the mean percentage error (MPE) of the conductivity in four radial directions increase gradually with the increase of the closure pressure. This phenomenon is especially prominent in deep rock samples. It is indicated that the flow heterogeneity of bedding fractures tends to increase with the closure pressure. When proppant is placed in the fracture, at a low closure pressure, due to the combined effects of self-support of rough fracture surface, proppant instability and uneven proppant placement, the flow heterogeneity is greater than that when proppant is not placed at the same closure pressure; however, with the increase of the closure pressure, the proppant becomes compact and stable, and the flow heterogeneity is mitigated gradually.

This paper systematically reviews the trend of carbon dioxide capture, utilization and storage (CCUS) industry in the world and China, presents the CCUS projects, clusters, technologies and strategies/policies, and analyzes the CCUS challenges and countermeasures in China based on the comparison of CCUS industrial development at home and abroad. The global CCUS development has experienced three stages: early stage, policy driven stage, and dual-drive stage. Currently, the active large-scale CCUS projects around the world focus on enhanced oil recovery (EOR) and are expanding into storage in saline aquifers. The CCUS industry of China has evolved in three stages: exploration, pilot test, and industrialization. In the current critical period of transition from field test to industrialization, China's CCUS projects are EOR-dominated. By comparing the industrial development of CCUS in China and abroad, it is found that the extension and industrialization of CCUS in China face challenges in technology, facilities and policies. Finally, future solutions to CCUS in China are proposed as follows: strengthening the top-level design and planning of CCUS; developing high-efficiency and low-cost CCUS technologies throughout the whole industry chain; deploying CCUS oil and gas + new energy clusters; improving the policy support system of CCUS; and strengthening discipline construction and personnel training, etc.

A quantitative evaluation model that integrates kerogen adsorption and clay pore adsorption of shale oil was proposed, and the evaluation charts of adsorption-swelling capacity of kerogen (M_k) and adsorbed oil capacity of clay minerals (M_c) were established, taking the 1st member of Cretaceous Qingshankou Formation in the northern Songliao Basin as an example. The model and charts were derived from swelling oil experiments performed on naturally evolved kerogens and adsorbed oil experiments on clays (separated from shale core samples). They were constructed on the basis of clarifying the control law of kerogen maturity evolution on its adsorption-swelling capacity, and considering the effect of both the clay pore surface area that occupied by adsorbed oil and formation temperature. The results are obtained in four aspects: (1) For the Qing 1 Member shale, with the increase of maturity, M_k decreases. Given R_o of 0.83%-1.65%, M_k is about 50-250 mg/g. (2) The clay in shale adsorbs asphaltene. M_c is 0.63 mg/m², and about 15% of the clay pore surface is occupied by adsorbed oil. (3) In the low to medium maturity stages, the shale oil adsorption is controlled by organic matter. When R_o>1.3%, the shale oil adsorption capacity is contributed by clay pores. (4) The oil adsorption capacity evaluated on the surface at room temperature is 8%-22% (avg. 15%) higher than that is held in the formations. The proposed evaluation model reveals the occurrence mechanisms of shale oils with different maturities, and provides a new insight for estimating the reserves of shale oil under formation temperature conditions.

The essence of energy system transition is the “energy revolution”. The development of the “resource-dominated” energy system with fossil energy as the mainstay has promoted human progress, but it has also triggered energy crisis and ecological environment crisis, which is not compatible with the new demands of the new round of scientific and technological revolution, industrial transformation, and sustainable human development. It is in urgent need to research and develop a new-type energy system in the context of carbon neutrality. In the framework of “technique-dominated” new green and intelligent energy system with “three new” of new energy, new power and new energy storage as the mainstay, the “super energy basin” concepts with the Ordos Basin as a representative will reshape the concept and model of future energy exploration and development. In view of the “six inequalities” in global energy and the resource conditions of “abundant coal, insufficient oil and gas and infinite new energy” in China, it is suggested to deeply boost “China energy revolution”, sticking to the six principles of independent energy production, green energy supply, secure energy reserve, efficient energy consumption, intelligent energy management, economical energy cost; enhance “energy scientific and technological innovation” by implementing technique-dominated “four major science and technology innovation projects”, namely, clean coal project, oil production stabilization and gas production increasing project, new energy acceleration project, and green-intelligent energy project; implement “energy transition” by accelerating the green-dominated “four-modernization development”, namely, fossil energy cleaning, large-scale new energy, coordinated centralized energy distribution, intelligent multi-energy management, so as to promote the exchange of “two 80%s” in China’s energy structure and construct the new green and intelligent energy system.

In order to understand the mechanism of air flooding shale oil, an online physical simulation method for enhanced shale oil recovery by air injection was established by integrating CT scanning and nuclear magnetic resonance (NMR). The development effect of shale oil by air flooding under different depletion pressures, the micro-production characteristics of pore throats with different sizes and the mechanism of shale oil recovery by air flooding were analyzed. The effects of air oxygen content, permeability, gas injection pressure, and fractures on the air flooding effect in shale and crude oil production in pores with different sizes were analyzed. The recovery of shale oil can be greatly improved by injecting air into the depleted shale reservoir, but the oil displacement efficiency and the production degree of different levels of pore throats vary with the injection timing. The higher the air oxygen content and the stronger the low-temperature oxidation, the higher the production degree of pores with different sizes and the higher the shale oil recovery. The higher the permeability and the better the pore throat connectivity, the stronger the fluid flow capacity and the higher the shale oil recovery. As the injection pressure increases, the lower limit of the production degree of pore throats decreases, but gas channeling may occur to cause a premature breakthrough; as a result, the recovery increases and then decreases. Fractures can effectively increase the contact area between gas and crude oil, and increase the air sweep coefficient and matrix oil drainage area by supplying oil to fractures through the matrix, which means that a proper fracturing before air injection can help to improve the oil displacement effect under a reasonable production pressure difference.

Based on structural distribution and fault characteristics of the Luzhou block, southern Sichuan Basin, as well as microseismic, well logging and in-situ stress data, the casing deformation behaviors of deep shale gas wells are summarized, and the casing deformation mechanism and influencing factors are identified. Then, the risk assessment chart of casing deformation is plotted, and the measures for preventing and controlling casing deformation are proposed. Fracturing-activated fault slip is a main factor causing the casing deformation in deep shale gas wells in the Luzhou block. In the working area, the approximate fracture angle is primarily 10°-50°, accounting for 65.34%, and the critical pore pressure increment for fault-activation is 6.05-9.71 MPa. The casing deformation caused by geological factors can be prevented/controlled by avoiding the faults at risk and deploying wells in areas with low value of stress factor. The casing deformation caused by engineering factors can be prevented/controlled by: (1) keeping wells avoid faults with risks of activation and slippage, or deploying wells in areas far from the faulting center if such avoidance is impossible; (2) optimizing the wellbore parameters, for example, adjusting the wellbore orientation to reduce the shear force on casing to a certain extent and thus mitigate the casing deformation; (3) optimizing the casing program to ensure that the curvature radius of the curved section of horizontal well is greater than 200 m while the drilling rate of high-quality reservoirs is not impaired; (4) optimizing the fracturing parameters, for example, increasing the evasive distance, lowering the single-operation pressure, and increasing the stage length, which can help effectively reduce the risk of casing deformation.

Based on outcrop, seismic and drilling data, the main regional unconformities in the Sichuan Basin and their controls on hydrocarbon accumulation were systematically studied. Three findings are obtained. First, six regional stratigraphic unconformities are mainly developed in the Sichuan Basin, from the bottom up, which are between pre-Sinian and Sinian, between Sinian and Cambrian, between pre-Permian and Permian, between middle and upper Permian, between middle and upper Triassic, and between Triassic and Jurassic. Especially, 16 of 21 conventional (and tight) gas fields discovered are believed to have formed in relation to regional unconformities. Second, regional unconformity mainly controls hydrocarbon accumulation from five aspects: (1) The porosity and permeability of reservoirs under the unconformity are improved through weathering crust karstification to form large-scale karst reservoirs; (2) Good source-reservoir-caprock assemblage can form near the unconformity, which provides a basis for forming large gas field; (3) Regional unconformity may lead to stratigraphic pinch-out and rugged ancient landform, giving rise to a large area of stratigraphic and lithologic trap groups; (4) Regional unconformity provides a dominant channel for lateral migration of oil and gas; and (5) Regional unconformity is conducive to large-scale accumulation of oil and gas. Third, the areas related to regional unconformities are the exploration focus of large gas fields in the Sichuan Basin. The pre-Sinian is found with source rocks, reservoir rocks and other favorable conditions for the formation of large gas fields, and presents a large exploration potential. Thus, it is expected to be an important strategic replacement.

Taking the Lower Permian Fengcheng Formation shale in Mahu Sag of Junggar Basin as an example, core observation, test analysis, geological analysis and numerical simulation were applied to identify the shale oil micro-migration phenomenon. The hydrocarbon micro-migration in shale oil was quantitatively evaluated and verified by a self-created hydrocarbon expulsion potential method, and the petroleum geological significance of shale oil micro-migration evaluation was determined. Results show that significant micro-migration can be recognized between the organic-rich lamina and organic-poor lamina. The organic-rich lamina has strong hydrocarbon generation ability. The heavy components of hydrocarbon preferentially retained by kerogen swelling or adsorption, while the light components of hydrocarbon were migrated and accumulated to the interbedded felsic or carbonate organic-poor laminae as free oil. 69% of the Fengcheng Formation shale samples in Well MY1 exhibit hydrocarbon charging phenomenon, while 31% of those exhibit hydrocarbon expulsion phenomenon. The reliability of the micro-migration evaluation results was verified by combining the group components based on the geochromatography effect, two-dimension nuclear magnetic resonance analysis, and the geochemical behavior of inorganic manganese elements in the process of hydrocarbon migration. Micro-migration is a bridge connecting the hydrocarbon accumulation elements in shale formations, which reflects the whole process of shale oil generation, expulsion and accumulation, and controls the content and composition of shale oil. The identification and evaluation of shale oil micro-migration will provide new perspectives for dynamically differential enrichment mechanism of shale oil and establishing a “multi-peak model in oil generation” of shale.

In 2022, the risk exploration well Chongtan1(CT1) in the Sichuan Basin revealed commercial oil and gas flow during test in a new zone - the marl of the second submember of the third member of Leikoupo Formation (Lei-3²) of Middle Triassic, recording a significant discovery. However, the hydrocarbon accumulation in marl remains unclear, which restricts the selection and deployment of exploration area. Focusing on Well CT1, the hydrocarbon accumulation characteristics of Lei-3² marl are analyzed to clarify the potential zones for exploration. The following findings are obtained. First, according to the geochemical analysis of petroleum and source rocks, oil and gas in the Lei-3² marl of Well CT1 are originated from the same marl. The marl acts as both source rock and reservoir rock. Second, the Lei-3² marl in central Sichuan Basin is of lagoonal facies, with a thickness of 40-130 m, an area of about 40 000 km², a hydrocarbon generation intensity of (4-12)×10⁸ m³/km², and an estimated quantity of generated hydrocarbons of 25×10¹² m³. Third, the lagoonal marl reservoirs are widely distributed in central Sichuan Basin. Typically, in Xichong-Yilong, Ziyang-Jianyang and Moxi South, the reservoirs are 20-60 m thick and cover an area of 7500 km². Fourth, hydrocarbons in the lagoonal marl are generated and stored in the Lei-3² marl, which means that marl serves as both source rock and reservoir rock. They represent a new type of unconventional resource, which is worthy of exploring. Fifth, based on the interpretation of 2D and 3D seismic data from central Sichuan Basin, Xichong and Suining are defined as favorable prospects with estimated resources of (2000-3000)×10⁸ m³.

This work systematically reviews the complex mechanisms of CO₂-water-rock interactions, microscopic simulations of reactive transport (dissolution, precipitation and precipitation migration) in porous media, and microscopic simulations of CO₂-water-rock system. The work points out the key issues in current research and provides suggestions for future research. After injection of CO₂ into underground reservoirs, not only conventional pressure-driven flow and mass transfer processes occur, but also special physicochemical phenomena like dissolution, precipitation, and precipitation migration. The coupling of these processes causes complex changes in permeability and porosity parameters of the porous media. Pore-scale microscopic flow simulations can provide detailed information within the three-dimensional pore and throat space and explicitly observe changes in the fluid-solid interfaces of porous media during reactions. At present, the research has limitations in the decoupling of complex mechanisms, characterization of differential multi-mineral reactions, precipitation generation mechanisms and characterization (crystal nucleation and mineral detachment), simulation methods for precipitation-fluid interaction, and coupling mechanisms of multiple physicochemical processes. In future studies, it is essential to innovate experimental methods to decouple “dissolution-precipitation-precipitation migration” processes, improve the accuracy of experimental testing of minerals geochemical reaction-related parameters, build reliable characterization of various precipitation types, establish precipitation-fluid interaction simulation methods, coordinate the boundary conditions of different physicochemical processes, and, finally, achieve coupled flow simulation of “dissolution-precipitation-precipitation migration” within CO₂-water-rock systems.