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. In conjunction with a substantial 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 drawn in four aspects. First, the Gulong shales are in the stage of extensive hydrocarbon expulsion when R_o is 1.0%-1.2%, with the peak 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 clay mineral intergranular pores/fractures, dissolution pores, and organic pores make up the majority of the pore structure. During the transformation, clay minerals undergo significant intergranular pore/fracture development 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 the 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 oil 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.

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.

A fracture propagation model of radial well fracturing is established based on the finite element-meshless method. The model considers the coupling effect of fracturing fluid flow and rock matrix deformation. The fracture geometries of radial well fracturing are simulated, the induction effect of radial well on the fracture is quantitatively characterized, and the influences of azimuth, horizontal principle stress difference, and reservoir matrix permeability on the fracture geometries are revealed. The radial wells can induce the fractures to extend parallel to their axes when two radial wells in the same layer are fractured. When the radial wells are symmetrically distributed along the direction of the minimum horizontal principle stress with the azimuth greater than 15°, the extrusion effect reduces the fracture length of radial wells. When the radial wells are symmetrically distributed along the direction of the maximum horizontal principal stress, the extrusion increases the fracture length of the radial wells. The fracture geometries are controlled by the rectification of radial borehole, the extrusion between radial wells in the same layer, and the deflection of the maximum horizontal principal stress. When the radial wells are distributed along the minimum horizontal principal stress symmetrically, the fracture length induced by the radial well decreases with the increase of azimuth; in contrast, when the radial wells are distributed along the maximum horizontal principal stress symmetrically, the fracture length induced by the radial well first decreases and then increases with the increase of azimuth. The fracture length induced by the radial well decreases with the increase of horizontal principal stress difference. The increase of rock matrix permeability and pore pressure of the matrix around radial wells makes the inducing effect of the radial well on fractures increase.

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.

A smart response fluid was designed and developed to overcome the challenges of gas channeling during CO₂ flooding in low-permeability, tight oil reservoirs. The fluid is based on Gemini surfactant with self-assembly capabilities, and the tertiary amine group serves as the response component. The responsive characteristics and corresponding mechanism of the smart fluid during the interaction with CO₂/oil were studied, followed by the shear characteristics of the thickened aggregates obtained by the smart fluid responding to CO₂. The temperature and salt resistance of the smart fluid and the aggregates were evaluated, and their feasibility and effectiveness in sweep-controlling during the CO₂ flooding were confirmed. This research reveals: (1) Thickened aggregates could be assembled since the smart fluid interacted with CO₂. When the mass fraction of the smart fluid ranged from 0.05% to 2.50%, the thickening ratio changed from 9 to 246, with viscosity reaching 13 to 3100 mPa?s. As a result, the sweep efficiency in low-permeability core models could be increased in our experiments. (2) When the smart fluid (0.5% to 1.0%) was exposed to simulated oil, the oil/fluid interfacial tension decreased to the level of 1×10^?2 mN/m. Furthermore, the vesicle-like micelles in the smart fluid completely transformed into spherical micelles when the fluid was exposed to simulated oil with the saturation greater than 10%. As a result, the smart fluid could maintain low oil/fluid interfacial tension, and would not be thickened after oil exposure. (3) When the smart fluid interacted with CO₂, the aggregates showed self-healing properties in terms of shear-thinning, static-thickening, and structural integrity after several shear-static cycles. Therefore, this fluid is safe to be placed in deep reservoirs. (4) The long-term temperature and salt resistance of the smart fluid and thickened aggregates have been confirmed.

According to the theory of sequence stratigraphy based on continental transgressive-regressive (T-R) cycles, a 500 m continuous core taken from the second member of Kongdian Formation (Kong 2 Member) of Paleogene in Well G108-8 in the Cangdong Sag, Bohai Bay Basin, was tested and analyzed to clarify the high-frequency cycles of deep-water fine-grained sedimentary rocks in lacustrine basins. A logging vectorgraph in red pattern was plotted, and then a sequence stratigraphic framework with five-order high-frequency cycles was formed for the fine-grained sedimentary rocks in the Kong 2 Member. The high-frequency cycles of fine-grained sedimentary rocks were characterized by using different methods and at different scales. It is found that the fifth-order T cycles record a high content of terrigenous clastic minerals, a low paleosalinity, a relatively humid paleoclimate and a high density of laminae, while the fifth-order R cycles display a high content of carbonate minerals, a high paleosalinity, a dry paleoclimate and a low density of laminae. The changes in high-frequency cycles controlled the abundance and type of organic matter. The T cycles exhibit relatively high TOC and abundant endogenous organic matters in water in addition to terrigenous organic matters, implying a high primary productivity of lake for the generation and enrichment of shale oil.

In order to obtain the impact frequency of resonant coal breaking by self-excited oscillation pulsed supercritical carbon dioxide (SC-CO₂) jet, large eddy simulation was used to analyze the formation and development process of self-excited oscillation pulsed SC-CO₂ jet, the variation of jet impact frequency in the nozzle and the free flow field, and the variation of jet impact frequency at different positions in the jet axis and under different cavity lengths. The test device of jet impact frequency was developed, and experiments were performed to verify the conclusions of the numerical simulations. The results show that the frequency of the self-excited oscillation pulsed SC-CO₂ jet is different in the nozzle and the free flow field. In the nozzle, the frequency generated by the fluid disturbance is the same, and the jet frequency at the exit of the nozzle is consistent with that inside the nozzle. In the free flow field, due to the compressibility of CO₂, the pressure, velocity and other parameters of SC-CO₂ jets have obvious fluctuation patterns. This feature causes the impact frequency of the self-excited oscillation pulsed SC-CO₂ jet to decrease gradually in the axis. Changing the cavity length allows the adjustment of the jet impact frequency in the free flow field by affecting the disturbance frequency of the self-excited oscillation pulsed SC-CO₂ jet inside the nozzle.

Based on core observation, thin section examination, fluid inclusions analysis, carbon and oxygen isotopic composition analysis, and other approaches, the structural and burial evolution histories were investigated, and the diagenetic evolution process and genetic/development models were systematically discussed of the Upper Paleozoic Permian clastic rock reservoirs in the Bohai Bay Basin, East China. The Bohai Bay Basin underwent three stages of burial and two stages of uplifting in the Upper Paleozoic. Consequently, three stages of acid dissolution generated by the thermal evolution of kerogen, and two stages of meteoric freshwater leaching occurred. Dissolution in deeply buried, nearly closed diagenetic system was associated with the precipitation of authigenic clay and quartz, leading to a limited increase in storage space. Different structural uplifting-subsidence processes of tectonic zones resulted in varying diagenetic-reservoir-forming processes of the Permian clastic reservoirs. Three genetic models of reservoirs are recognized. The Model I reservoirs with pores formed in shallow strata and buried in shallow to medium strata underwent two stages of exposure to long-term open environment and two stages of meteoric freshwater leaching to enhance pores near the surface, and were shallowly buried in the late stage, exhibiting the dominance of secondary pores and the best physical properties. The Model II reservoirs with pores formed in shallow strata and preserved due to modification after deep burial experienced an early exposure-open to late burial-closed environment, where pore types were modified due to dissolution, exhibiting the dominance of numerous secondary solution pores in feldspar and the physical properties inferior to Model I. The Model III reservoirs with pores formed after being regulated after multiple periods of burial and dissolution experienced a dissolution of acidic fluids of organic origin under a near-closed to closed environment, exhibiting the dominance of intercrystalline micropores in kaolinite and the poorest physical properties. The target reservoirs lied in the waterflood area in the geological period of meteoric freshwater leaching, and are now the Model II deep reservoirs in the slope zone-depression zone. They are determined as favorable options for subsequent exploration.

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 sections 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 sections 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 sections of thin siltstone consisting of fine-grained high-density flow, fine-grained hyperpycnal flow and surge-like turbidity flow deposits, sweet sections with interbeds of mudstone and siltstone formed by fine-grained transitional flows, and sweet sections 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 shale oil reservoir and organic-rich source rock.

The conventional lithofacies and facies model of subaerial and marine pyroclastic rocks cannot reflect the characteristics of subaqueous volcanic edifice in lacustrine basins. In order to solve this problem, the lithofacies of subaqueous eruptive pyroclastic rocks is discussed and the facies model is established by taking the tuff cone of Cretaceous Huoshiling Formation in the Chaganhua area of the Changling fault depression, Songliao Basin as the research object. The results indicate that the subaqueous eruptive pyroclastic rocks in the Songliao Basin can be divided into two facies and four subfacies. The two facies are the subaqueous explosive facies and the volcanic sedimentary facies that is formed during the eruption interval. The subaqueous explosive facies can be further divided into three subfacies: gas-supported hot pyroclastic flow subfacies, water-laid density current subfacies and subaqueous fallout subfacies. The volcanic sedimentary facies consists of pyroclastic sedimentary rocks containing terrigenous clast subfacies. A typical facies model of the tuff cone that is formed by subaqueous eruptions in the Songliao Basin was established. The tuff cone is generally composed of multiple subaqueous eruption depositional units and can be divided into two facies associations: near-source facies association and far-source facies association. The complete vertical succession of one depositional unit of the near-source facies association is composed of pyroclastic sedimentary rocks containing terrigenous clast subfacies, gas-supported hot pyroclastic flow subfacies, water-laid density current subfacies and subaqueous fallout subfacies from bottom to top. The depositional unit of the far-source facies association is dominated by the subaqueous fallout subfacies and contains several thin interlayered deposits of the water-laid density current subfacies. The gas-supported hot pyroclastic flow subfacies and the pyroclastic sedimentary rocks containing terrigenous clast subfacies are favorable subaqueous eruptive facies for reservoirs in continental lacustrine basins.

The geochemical analysis and experimental simulation are comprehensively used to systematically study the hydrocarbon generation 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 saline lacustrine source rock 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 saline lacustrine source rocks 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 lacustrine basins. It generates hydrocarbons during low-maturity stage, 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.

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: exploration 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 scale-up and industrialization of CCUS in China face challenges in technology, facilities and policies. Finally, future solutions to CCUS development 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 industrial chain; deploying CCUS oil and gas + new energy clusters; improving the policy support system of CCUS; and strengthening discipline construction and personnel training, etc.

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 whole 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 whole petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a whole petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the whole 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 whole 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.

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, NW China 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.

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 pico-algae, nano-algae 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 organo-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 imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.

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.

Based on the geological and geochemical analysis of potential source rocks in different formations and the classification of crude oil types, combined with the hydrocarbon generation thermal simulation experiments, the source, genesis, and distribution of different types of oils in the Mahu large oil province of the Junggar Basin are investigated. Four sets of potential source rocks are developed in the Mahu Sag. Specifically, the source rocks of the Permian Fengcheng Formation have the highest hydrocarbon generation potential and contain mainly Types II and I organic matters, with a high oil generation capacity. In contrast, the source rocks in other formations exhibit lower hydrocarbon generation potential and contain mainly Type III organic matter, with dominant gas generation. Oils in the Mahu Sag can be classified as three types: A, B and C, which display ascending, mountainous and descending C₂₀-C₂₁-C₂₃ tricyclic terpenes abundance patterns in sequence, and gradually increasing relative content of tricyclic terpenes and sterane isomerization parameters, indicating an increasing oil maturity. Different types of oils are distributed spatially in an obviously orderly manner: Type A oil is close to the edge of the sag, Type C oil is concentrated in the center of the sag, and Type B oil lies in the slope area between Type A and Type C. The results of oil-source correlation and thermal simulation experiments show that the three types of oils come from the source rocks of the Fengcheng Formation at different thermal evolution stages. This new understanding of the differential genesis of oils in the Mahu Sag reasonably explains the source, distribution, and genetic mechanism of the three types of oils. The study results are of important guidance for the comprehensive and three-dimensional oil exploration, the identification of oil distribution in the total petroleum system, and the prediction of favorable exploration areas in the Mahu Sag.

According to the latest drilling and the analysis of the burial history, source rock evolution history and hydrocarbon accumulation history, the sub-source hydrocarbon accumulation characteristics of the Permian reservoirs in the Jinan Sag, eastern Junggar Basin, are clarified, and the hydrocarbon accumulation model of these reservoirs is established. The results are obtained in four aspects. First, the main body of the thick salified lake basin source rocks in the Lucaogou Formation has reached the mature stage with abundant resource base. Large-scale reservoirs are developed in the Jingjingzigou, Wutonggou and Lucaogou formations. Vertically, there are multiple sets of good regional seals, the source-reservoir-caprock assemblage is good, and there are three reservoir-forming assemblages: sub-source, intra-source and above-source. Second, dissolution, hydrocarbon charging and pore-preserving effect, and presence of chlorite film effectively increase the sub-source pore space. Oil charging is earlier than the time when the reservoir becomes densified, which improves the efficiency of hydrocarbon accumulation. Third, buoyancy and source-reservoir pressure difference together constitute the driving force of oil charging, and the micro-faults within the formation give the advantage of “source-reservoir lateral docking” under the source rock. Microfractures can be critical channels for efficient seepage and continuous charging of oil in different periods. Fourth, the Jingjingzigou Formation experienced three periods of oil accumulation in the Middle-Late Permian, Middle-Late Jurassic and Late Neogene, with the characteristics of long-distance migration and accumulation in early stage, mixed charging and accumulation in middle stage and short-distance migration and high-position accumulation in late stage. The discovery and theoretical understanding of the Permian reservoirs in the Jinan Sag reveal that the thrust belt has good conditions for forming large reservoirs, and it is promising for exploration. The study results are of guidance and reference significance for oil and gas exploration in the Jinan Sag and other geologically similar areas.

To understand the reservoir property and hydrocarbon accumulation conditions of the Middle and Upper Ordovician intraplatform shoal between ultra-deep main strike-slip faults in Fuman Oilfield of the Tarim Basin, China, the main strike-slip faults in and around well FD1 in the basin were analyzed in terms of sedimentary facies, sequence stratigraphy, intraplatform shoal reservoir property, and oil and gas origins, based on drilling data. The Yingshan Formation intraplatform shoal between the main strike-slip faults is superimposed with low-order faults to form a new type of hydrocarbon play. Firstly, hydrocarbons generated from the Lower Cambrian Yuertusi Formation source rocks vertically migrated into the second member of Yingshan Formation through the main strike-slip faults, and then migrated laterally until they were accumulated. A small amount of oil from Well FD1 came from the Yuertusi Formation source rocks in the mature stage, and a large amount of gas originated from oil cracking in the ultra-deep reservoirs. Therefore, the secondary gas condensate reservoir in Well FD1 is characterized by high gas to oil ratio, dry gas (dryness coefficient being 0.970) and hybrid origin. This new type of hydrocarbon play characterized by intraplatform shoal and low-order fault suggests a prospect of continuous hydrocarbon-bearing area in Fuman Oilfield, which will expand the ultrap-deep oil and gas exploration in the oilfield.

Based on paleogeomorphology, drilling and seismic data, this paper systematically studies the structural and sedimentary evolution, source rock characteristics, reservoir characteristics and formation mechanism, hydrocarbon accumulation model and enrichment law in the Linhe Depression of the Hetao Basin, NW China. The Hetao Basin mainly experienced three stages of evolution, namely, weak extensional fault depression, strong extensional fault depression and strike-slip transformation, giving rise to four positive structural belts (Jilantai, Shabu, Nalinhu and Xinglong), which are favorable areas for oil and gas accumulation. The two main saline lacustrine source rocks, Lower Cretaceous Guyang Formation and Oligocene Linhe Formation, are characterized by high sulfur content, rich algae, early maturity, early expulsion, and wide oil generation window. The large structural transition belt in the intermountain area around the Hetao Basin controls the formation of large-scale braided river delta deposits, which are characterized by high quartz content (50%-76%), long-term shallow burial and weak compaction, low cement content, and good reservoir properties in delta front sandbody. The burial depth of the effective Paleogene reservoirs is predicted to reach 8000 m. Three hydrocarbon accumulation models, nose-uplift near sag, buried hill surrounding sag, fault nose near source rock, are constructed. The law of hydrocarbon accumulation in the Linhe Depression is finally clarified as follows: near-source around the depression is the foundation, high-quality thick reservoir is the premise, good tectonic setting and trap conditions are the key.

The existing approaches for identifying events in horizontal well fracturing are difficult, time-consuming, inaccurate, and incapable of real-time warning. Through improvement of data analysis and deep learning algorithm, together with the analysis on data and information of horizontal well fracturing in shale gas reservoirs, this paper presents a method for intelligent identification and real-time warning of diverse complex events in horizontal well fracturing. An identification model for "point" events in fracturing is established based on the Att-BiLSTM neural network, along with the broad learning system (BLS) and the BP neural network, and it realizes the intelligent identification of the start/end of fracturing, formation breakdown, instantaneous shut-in, and other events, with an accuracy of over 97%. An identification model for "phase" events in fracturing is established based on enhanced Unet++ network, and it realizes the intelligent identification of pump ball, pre-acid treatment, temporary plugging fracturing, sand plugging, and other events, with an error of less than 0.002. Moreover, a real-time prediction model for fracturing pressure is built based on the Att-BiLSTM neural network, and it realizes the real-time warning of diverse events in fracturing. The proposed method can provide an intelligent, efficient and accurate identification of events in fracturing to support the decision-making.

In response to the lack of global quantitative research on the potential and scale prediction of CO₂ capture, utilization and storage (CCUS) in China under the background of carbon peak and carbon neutrality goals, this study predicts the future economic costs of different links of CCUS technologies and the carbon capture needs of different industries in the scenario of fossil energy continuation. Based on the CO₂ utilization and storage potential and spatial distribution in China, a cost-scale calculation model for different regions in China in 2060 is constructed to predict the whole-process economic cost and its corresponding scale potential of CCUS. The results show that a local + remote storage mode is preferred, together with a local utilization mode, to meet China's 27×10⁸ t/a CO₂ emission reduction demand under the scenario of fossil energy continuation. Specifically, about 5×10⁸ t CO₂ emission is reduced by capture utilization, and the whole-process cost is about ?1400-200 RMB/t; about 22×10⁸ t CO₂ emission is reduced by capture storage, and the whole-process cost is about 200-450 RMB/t. According to the model results, it is recommended to develop the chemical utilization industry based on P2X (Power to X, where X is raw material) technology, construct the CCUS industrial cluster, and explore a multi-party win-win cooperation mode. A scheme of national trunk pipeline network connecting areas connecting intensive emission reduction demand areas and target storage areas is suggested. The emission reduction cost of thermal power based on CCUS is calculated to be 0.16 RMB/(kW·h).

By analyzing the corrosion of phosphate completion fluid on the P110 steel at 170 °C, the high-temperature corrosion mechanism of phosphate completion fluid was revealed, and a corrosion inhibition method by membrane transformation was proposed and an efficient membrane-forming agent was selected. Scanning electron microscope (SEM) images, X-ray energy spectrum and X-ray diffraction results were used to characterize the microscopic morphology, elemental composition and phase composition of the precipitation membrane on the surface of the test piece. The effect and mechanism of corrosion inhibition by membrane transformation were clarified. The phosphate completion fluid eroded the test piece by high-temperature water vapor and its hydrolyzed products to form a membrane of iron phosphate corrosion product. By changing the corrosion reaction path, the Zn²⁺ membrane-forming agent could generate KZnPO₄ precipitation membrane with high temperature resistance, uniform thickness and tight crystal packing on the surface of the test piece, which could inhibit the corrosion of the test piece, with efficiency up to 69.63%. The Cu²⁺ membrane-forming agent electrochemically reacted with Fe to precipitate trace elemental Cu on the surface of the test piece, thus forming a protective membrane, which could inhibit metal corrosion, with efficiency up to 96.64%, but the wear resistance was poor. After combining 0.05% Cu²⁺ and 0.25% Zn²⁺, a composite protective membrane of KZnPO₄ crystal and elemental Cu was formed on the surface of the test piece. The corrosion inhibition efficiency reached 93.03%, which ensured the high corrosion inhibition efficiency and generated a precipitation membrane resistant to temperature and wear.

According to the transversely isotropic theory and weak plane criterion, and considering the mechanical damages due to stress unloading and hydration during drilling, a shale wellbore stability model with the influence of stress unloading and hydration was established using triaxial test and shear test. Then, factors influencing the wellbore stability in shale were analyzed. The results indicate that stress unloading occurs during drilling in shale. The larger the confining pressure and axial stress, the more remarkable weakening of shale strength caused by stress unloading. The stress unloading range is positively correlated with the weakening degree of shale strength. Shale with a higher development degree of bedding is more prone to damage along bedding. In this case, during stress unloading, the synergistic effect of weak structural plane and stress unloading happens, leading to a higher weakening degree of shale strength and poorer mechanical stability, which brings a higher risk of wellbore instability. Fluid tends to invade shale through bedding, promoting the shale hydration. Hydration also can weaken shale mechanical stability, causing the decline of wellbore stability. Influence of stress unloading on collapse pressure of shale mainly occurs at the early stage of drilling, while the influence of hydration on wellbore stability mainly happens at the late stage of drilling. Bedding, stress unloading and hydration jointly affect the wellbore stability in shale. The presented shale wellbore stability model with the influence of stress unloading and hydration considers the influences of the three factors. Field application demonstrates that the prediction results of the model agree with the actual drilling results, verifying the reliability of the model.

The largest Precambrian gas field (Anyue gas field) in China has been discovered in the central Sichuan Basin. However, the deep ancient Ediacaran (Sinian) dolomite presents a substantial challenge due to their tightness and heterogeneity, rather than assumed large-area stratified reservoirs controlled by mound-shoal microfacies. This complicates the characterization of “sweet spot” reservoirs crucial for efficient gas exploitation. By analyzing compiled geological, geophysical and production data, this study investigates the impact of strike-slip fault on the development and distribution of high-quality “sweet spot” (fractured-vuggy) reservoirs in the Ediacaran dolomite of the Anyue gas field. The dolomite matrix reservoir exhibits low porosity (less than 4%) and low permeability (less than 0.5×10^-3 μm²). Contrarily, fractures and their dissolution processes along strike-slip fault zone significantly enhance matrix permeability by more than one order of magnitude and matrix porosity by more than one time. Widespread “sweet spot” fracture-vuggy reservoirs are found along the strike-slip fault zone, formed at the end of the Ediacaran. These fractured reservoirs are controlled by the coupling mechanisms of sedimentary microfacies, fracturing and karstification. Karstification prevails at the platform margin, while both fracturing and karstification control high-quality reservoirs in the intraplatform, resulting in reservoir diversity in terms of scale, assemblage and type. The architecture of the strike-slip fault zone governed the differential distribution of fracture zones and the fault-controlled “sweet spot” reservoirs, leading to wide fractured-vuggy reservoirs across the strike-slip fault zone. In conclusion, the intracratonic weak strike-slip fault can play a crucial role in improving tight carbonate reservoir, and the strike-slip fault-related “sweet spot” reservoir emerges as a unique and promising target for the efficient development of deep hydrocarbon resources. Tailored development strategies need to be implemented for these reservoirs, considering the diverse and differential impacts exerted by strike-slip faults on the reservoirs.

Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng-Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium-deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1-4.8 m³/t), high adsorbed gas content (2.5-2.8 m³/t), low sensitive desorption pressure (1.7-2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.

In the second member of the Upper Triassic Xujiahe Formation (T₃x₂) in the Xinchang area, western Sichuan Basin, only a low percent of reserves has been recovered, and the geological model of gas reservoir sweet spot remains unclear. Based on a large number of core, field outcrop, test and logging-seismic data, the T₃x₂ gas reservoir in the Xinchang area is examined. The concept of fault-fold-fracture body (FFFB) is proposed, and its types are recognized. The main factors controlling fracture development are identified, and the geological models of FFFB are established. FFFB refers to faults, folds and associated fractures reservoirs. According to the characteristics and genesis, FFFBs can be divided into three types: fault-fracture body, fold-fracture body, and fault-fold body. In the hanging wall of the fault, the closer to the fault, the more developed the effective fractures; the greater the fold amplitude and the closer to the fold hinge plane, the more developed the effective fractures. Two types of geological models of FFFB are established: fault-fold fracture, and matrix storage and permeability. The former can be divided into two subtypes: network fracture, and single structural fracture, and the later can be divided into three subtypes: bedding fracture, low permeability pore, and extremely low permeability pore. The process for evaluating favorable FFFB zones was formed to define favorable development targets and support the well deployment for purpose of high production. The study results provide a reference for the exploration and development of deep tight sandstone oil and gas reservoirs in China.

Based on rock mineral and geochemical analysis, microscopic observation, physical property measurement, and thin laminae separation test, etc., the characteristics of typical laminae of the Paleogene Shahejie Formation carbonate-rich shale in the Jiyang Depression were analyzed, and the organic matter abundance, reservoir properties, and oil-bearing properties of different laminae were compared. Typical shale storage-seepage structures were classified, and the mobility of oil in different types of shale storage-seepage structure was compared. The results show that the repeated superposition of mud laminae and calcite laminae are the main layer structure of carbonate-rich shales. The calcite laminae are divided into micritic calcite laminae, sparry calcite laminae and fibrous calcite vein. The mud-rich laminae are the main contributor to the organic matter abundance and porosity of shale, with the best hydrocarbon generation potential, reservoir capacity, and oil-bearing property. The micritic calcite laminae also have relatively good hydrocarbon generation potential, reservoir capacity and oil-bearing property. The sparry calcite laminae and fibrous calcite vein have good permeability and conductivity. Four types of shale storage-seepage structure are developed in the carbonate-rich shale, and the mobility of oil in each type of storage-seepage structure is in descending order: sparry calcite laminae enriched shale storage-seepage structure, mixed calcite laminae enriched shale storage-seepage structure, fibrous calcite vein enriched shale storage-seepage structure, and micritic calcite laminae enriched shale storage-seepage structure. The exploration targets of carbonate-rich shale in the Jiyang Depression Shahejie Formation are different in terms of storage-seepage structure at different thermal evolution stages.

Combining low salinity water (LSW) with surfactants has an enormous potential for enhancing oil recovery processes. However, there is no consensus about the mechanisms involved, in addition to the fact that several studies have been conducted in model systems, while experiments with rocks and reservoir fluids are scarce. This study presents a core-flooding experiment of LSW injection, with and without surfactant, using the core and heavy oil samples obtained from a sandstone reservoir in southeastern Mexico. The effluents and the crude oil obtained at each stage were analyzed. The study was complemented by tomographic analysis. The results revealed that LSW injection and hybrid process with surfactants obtained an increase of 11.4 percentage points in recovery factor. Various phenomena were caused by LSW flooding, such as changes in wettability and pH, ion exchange, mineral dissolution, detachment of fines and modification of the hydrocarbon profile. In the surfactant flooding, the reduction of interfacial tension and alteration of wettability were the main mechanisms involved. The findings of this work also showed that the conditions believed to be necessary for enhanced oil recovery with LSW, such as the presence of kaolinite or high acid number oil, are not relevant.

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.

The geological characteristics and production practices of the 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 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.

This paper establishes a 3D multi-well pad fracturing numerical model coupled with fracture propagation and proppant migration based on the displacement discontinuity method and Eulerian-Eulerian frameworks, and the fracture propagation and proppant distribution during multi-well fracturing are investigated by taking the actual multi-well pad parameters as an example. Fracture initiation and propagation during multi-well pad fracturing are jointly affected by a variety of stress interference mechanisms such as inter-cluster, inter-stage, and inter-well, and the fracture extension is unbalanced among clusters, asymmetric on both wings, and dipping at heels. Due to the significant influence of fracture morphology and width on the migration capacity of proppant in the fracture, proppant is mainly placed in the area near the wellbore with large fracture width, while a high-concentration sandwash may easily occur in the area with narrow fracture width as a result of quick bridging. On the whole, the proppant placement range is limited. Increasing the well-spacing can reduce the stress interference of adjacent wells and promote the uniform distribution of fractures and proppant on both wings. The maximum stimulated reservoir volume or multi-fracture uniform propagation can be achieved by optimizing the well spacing. Although reducing the perforation-cluster spacing also can improve the stimulated reservoir area, a too low cluster spacing is not conducive to effectively increasing the propped fracture area. Since increasing the stage time lag is beneficial to reduce inter-stage stress interference, zipper fracturing produces more uniform fracture propagation and proppant distribution.

To study the fluid dynamic response mechanism under the working condition of water injection well borehole, based on the microelement analysis of fluid mechanics and the classical theory of hydrodynamics, a fluid microelement pressure-flow rate relationship model is built to derive and solve the dynamic distribution of fluid pressure and flow rate in the space of well borehole. Combined with the production data of a typical deviated well in China, numerical simulations and analyses are carried out to analyze the dynamic distribution of wellbore pressure at different injection pressures and injection volumes, the delayed and attenuated characteristics of fluid transmission in tube, and the dynamic distribution of wellbore pressure amplitude under the fluctuation of wellhead pressure. The pressure loss along the wellbore has nothing to do with the absolute pressure, and the design of the coding and decoding scheme for wave code communication doesn’t need to consider the absolute pressure during injecting. When the injection pressure is constant, the higher the injection flow rate at the wellhead, the larger the pressure loss along the wellbore. The fluid wave signal delay amplitude mainly depends on the length of the wellbore. The smaller the tubing diameter, the larger the fluid wave signal attenuation amplitude. The higher the target wave code amplitude (differential pressure identification root mean square) generated at the same well depth, the greater the wellhead pressure wave amplitude required to overcome the wellbore pressure loss.

On the basis of sorting out current understanding of solid bitumen (SB) in shales and taking organic-rich shales in the first member of the Cretaceous Qingshankou Formation in the Songliao Basin as an example, the definition, classification, occurrence and evolution path of SB are systemtically studied, and the indicative significance of SB reflectance (R_ob) on maturity and its influence on the development of reservoir space are discussed and summarized. The results show that the difference of primary maceral types is primarily responsible for the different evolution paths of SB. Most of the pre-oil bitumen is in-situ SB with only a small amount being of migrated SB, while most of the post-oil bitumen and pyrobitumen are migrated SB. From the immature to early oil maturity stage, bituminite, vitrinite, and inertinite can be distinguished from SB based on their optical characteristics under reflected light, and alginite can be differentiated from SB by their fluorescence characteristics. Under scanning electron microscope, in-situ SB and migrated SB can be effectively identified. R_ob increases linearly with increasing vitrinite reflectance (R_o), as a result of a decrease of aliphatic structure and the enhancement of aromatization of SB. Within the oil window three types of secondary pores may develop in SB, including modified mineral pores, devolatilization cracks and bubble holes. At a high maturity stage spongy pores may develop in pyrobitumen. Scanning electron microscopy combined with in-situ SEM-Raman spectroscopy can further reveal the structral information of different types of SB, thus providing crucial data for understanding for understanding OM migration paths, dynamics, and distances at micro-scale.

Based on the measurements of petrological, petrophysical and elastic properties of the samples of different sedimentary facies in the fourth member of Sinian Dengying Formation (Deng 4 Member) in the Sichuan Basin, the diagenetic processes of reservoirs of different sedimentary facies and their controls on the petrophysical properties were discussed. The results show that cracks and mineral composition jointly control the petrophysical properties, and both are significantly influenced by sedimentary environment and diagenesis. The microbial dolomite of mound-shoal facies mainly experienced multi-stage dolomitization, penecontemporaneous dissolution, tectonic rupture and hydrothermal/organic acid dissolution processes, giving rise to cracks and dissolved pores. The grannular dolomite of inter-mound-shoal bottomland or dolomitic lagoon facies mainly underwent mechanical compaction, burial dolomitization and tectonic-hydrothermal action, creating cracks and intercrystalline pores. The diagenesis related to crack development increases the pressure- and saturation-dependent effects of samples, leading to significant decrease in the compressional wave impedance and Poisson's ratio. Dolomitization changes the properties of mineral particles, resulting in a Poisson's ratio close to dolomite. The muddy, siliceous and calcareous sediments in the low-energy environment lead to the decrease of impedance and the differential change of Poisson's ratio (significantly increased or decreased). The samples with both cracks and dissolved pores show high P-wave velocity dispersion characteristics, and the P-wave velocity dispersion of samples with only fractures or pores is the lowest.

According to the variable toe-to-heel well spacing, combined with the dislocation theory, discrete lattice method, and finite-element-method (FEM) based fluid-solid coupling, an integrated geological-engineering method of volume fracturing for fan-shaped well pattern is proposed considering the geomechanical modeling, induced stress calculation, hydraulic fracturing simulation, and post-frac productivity evaluation. Besides, we propose the differential fracturing design for the conventional productivity-area and the potential production area for fan-shaped horizontal wells. After the fracturing of the conventional production area for H1 fan-shaped well platform, the research shows that the maximum reduction of the horizontal principal stress difference in the potential productivity-area is 0.2 MPa, which cannot cause the stress reversal, but this reduction is still conducive to the lateral propagation of hydraulic fractures. According to the optimized fracturing design, in zone-I of the potential production area, only Well 2 is fractured, with a cluster spacing of 30 m and an injection rate of 12 m³/min per stage; in zone-II, Well 2 is fractured before Well 3, with a cluster spacing of 30 m and an injection rate of 12 m³/min per stage. The swept area of the pore pressure drop in the potential production area is small, showing that the reservoir is not well developed. The hydraulic fracturing in the toe area can be improved by, for example, properly densifying the fractures and adjusting the fracture distribution, in order to enhance the swept volume and increase the reservoir utilization.

Considering the characteristics of carbonate reservoirs in the Middle East, a low-viscosity microemulsion acid that can be prepared on site and has an appropriate retardation ability was developed. It was compared with four conventional acid systems (hydrochloric acid, gelled acid, emulsified acid and surfactant acid) through experiments of rotating disk, multistage acid fracturing and core flooding with CT scanning. The micro-etching characteristics and conductivity of fracture surfaces were clarified, and the variation of saturation field during water invasion and flowback of spent acid and the recovery of oil phase relative permeability were quantitatively evaluated. The study shows that the addition of negatively charged agent to the oil core of microemulsion acid can enhance its adsorption capacity on the limestone surface and significantly reduce the H⁺ mass transfer rate. Moreover, the negatively charged oil core is immiscible with the Ca^{2 +} salt, so that the microemulsion acid can keep an overall structure not be damaged by Ca^{2 +} salt generated during reaction, with adjustable adsorption capacity and stable microemulsion structure. With high vertical permeability along the fracture walls, the microemulsion acid can penetrate into deep fracture wall to form network etching, which helps greatly improve the permeability of reservoirs around the fractures and keep a high conductivity under a high closure pressure. The spent microemulsion acid is miscible with crude oil to form microemulsion. The microemulsion, oil and water are in a nearly miscible state, with basically no water block and low flowback resistance, the flowback of spent acid and the relative permeability of oil are recovered to a high degree.

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.