Taking the Cambrian Qiongzhusi Formation in the Ziyang-Jingyan area of the southwestern Sichuan Basin as the research object, this study investigates the reservoir characteristics, enrichment mechanism and accumulation model of new-type shale gas by comprehensively using core and thin section observation, geochemical testing, and production dynamic analysis. Two types of shales, organic-rich shale and organic-lean shale, are developed in the study area. The organic-lean shale can receive gas supply from source rock cracking in adjacent areas, possessing the foundation of multi-source hydrocarbon generation and gas supply. Multiple sets of tuffaceous shale were developed in the Qiongzhusi Formation of southern Sichuan Basin. Multi-stage volcanic-hydrothermal activities promoted the development of inorganic pores, microfractures and reservoir space. The reservoirs are characterized by high inorganic pore content, high brittle mineral content and high free gas proportion, and the ultra-deep shale presents favorable reservoir fracturing property and gas-bearing potential. Breaking the traditional understanding that shale gas only migrates over a short distance and accumulates in-situ merely in organic-rich shale, a new mixed-source enrichment model of in-situ generation + external migration charging for organic-lean shale is established. It is clarified that natural gas in the central Sichuan Basin follows a composite accumulation evolution path of "source rock cracking-in-situ generation-migration replenishment". Three types of gas reservoirs are formed successively, including the early in-situ cracked conventional gas in the Cambrian Longwangmiao Formation of the Gaoshiti-Moxi area, the middle-stage in-situ enriched shale gas in the Qiongzhusi Formation of the Ziyang area, and the mixed-source shale gas formed by in-situ generation superimposed with late migration replenishment in the Qiongzhusi Formation of the Jingyan area.
Considering the complex occurrence environment and significant compositional variation of continental shale oil, as well as the uncertainties in its mobility and producible amount, this study employs geochemical analysis and production monitoring to investigate the “component flow” phenomenon of shale oil during production from the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin. It is clarified that the miscibility of different hydrocarbon components and non-hydrocarbon substances improves the flowability of multi-component hydrocarbons and non-hydrocarbons, thereby effectively enhancing the production of shale oil. Research indicates that the “lower sweet spot” has a relatively high content of light and medium hydrocarbon components and strong formation energy compared to the “upper sweet spot” of Lucaogou Formation, resulting in higher density and viscosity of the produced crude oil, which can be regarded as evidence of “component flow” of retained hydrocarbons. The “upper sweet spot” exhibits two scenarios. In areas far from faults with good preservation conditions, the high content of light and medium components in retained hydrocarbons and a high formation pressure coefficient make component flow more likely to occur. Consequently, the produced crude oil has a higher density, and the estimated ultimate recovery (EUR) per well is also higher. In areas near faults with poor preservation conditions, although the produced crude oil has a light density, the EUR per well is relatively low, indicating that the conditions for component flow of retained hydrocarbons underground have deteriorated. The study also demonstrates that preservation conditions (preventing light hydrocarbon escape and maintaining formation energy) and production strategies (controlling production pressure differential and maintaining stable operations) are important factors in regulating the occurrence and continuity of “component flow” to maximize EUR per well. These new insights can be applied to the evaluation of economically productive “sweet spots” and provide guidance for achieving optimal EUR per well in shale oil production.
Through a systematic analysis of the physical properties of coal and gangue, including microscopic pore structure, surface wettability and mechanical strength, the mechanism of borehole wall collapse in deep coal formations was revealed. Based on this understanding, a wellbore-stabilizing drilling fluid concept was proposed, featuring high-efficiency plugging of medium and large pores and fractures + cementation and film-formation in micro and small pores and fractures + overall surface hydrophobic inhibition. An adaptive plugging agent and a cementing film-forming hydrophobic inhibitor were developed, and a cementing, wall-strengthening, film-forming, and hydrophobic drilling fluid system was established. The adaptive plugging agent consists of organic-inorganic hybrid polymer microspheres, which enables self-adaptive plugging of pores and micro-fractures in coal rock through flexible deformation, effectively preventing direct contact between the drilling fluid and medium-to-large pore-fracture systems in the formation. The cementing film-forming hydrophobic inhibitor contains strong adsorption groups and hydrophobic groups, which provides both cementing reinforcement and dense film-forming functions, significantly enhancing the overall structural strength of coal rock, greatly reducing surface hydrophilicity, and inhibiting hydration swelling of clay minerals. The developed drilling fluid system exhibits favorable rheological behavior, filtration-control performance and lubricity. It can substantially improve the compressive strength of rock samples and markedly reduce their linear expansion rate. Field application results demonstrate that the system delivers excellent anti-collapse, cuttings-carrying and lubrication performance, with outstanding wellbore stabilization effectiveness.
Research on hydrocarbon accumulation mechanism in coal-measure whole petroleum systems and coal-rock gas exploration has revealed that coal-rock gas occurs along coal-bearing strata and forms different reservoir types with distinct geological characteristics in different structural regions, and that between primary coal-rock gas reservoirs and residual coal-rock gas reservoirs (i.e., traditional shallow coalbed methane reservoirs), the gas–water relationship in the macroscopic pores and fractures of coal reservoirs gradually evolves in space, forming coal-rock gas accumulation transition zones with prominent features. Taking the coal-rock gas of the Carboniferous Benxi Formation in the central-eastern Ordos Basin, China, as an example, this study constructs the dynamic mechanism and mathematical models for the coal-rock gas accumulation transition zone by considering the dual-medium structure, stress sensitivity, and wettability variation of coal reservoirs. On this basis, the dynamic equilibrium among buoyancy, capillary force and hydrocarbon-generation expansion force is clarified. The results show that, under the geological background of uplift and reworking, the cleat fracture system and porosity–permeability properties of coal reservoirs are fundamental for the formation of the transition zone, the hydrocarbon-generation expansion force of coal rocks is an inherent determinant for the depth of the transition zone, and the spatial variation of coal rank and tectonic reworking intensity control the distribution of the transition zone. Numerical simulation results and practical exploration and development have demonstrated that, at the eastern margin of the Ordos Basin, the transition zone for medium- to high-rank coal-rock gas reservoirs in the Daning–Jixian area in the south is mainly buried at 1 300–1 800 m, while the transition zone for low- to medium-rank coal-rock gas reservoirs in the north occurs at a greater depth of 1 500–2 300 m. Through comprehensive investigation, the coal-rock gas accumulation zones at the eastern margin of the Ordos Basin are examined by hydrocarbon accumulation evolution analysis and spatial distribution prediction. Three continuous hydrocarbon accumulation evolution units are identified, i.e. deep coal-rock gas accumulation zone, coal-rock gas accumulation transition zone, and shallow coalbed methane accumulation zone. The research results deepen the understanding of accumulation mechanism and differential enrichment mechanism of coal-rock gas, and provide a theoretical basis for improving coal-rock gas classification and guiding favorable area evaluation and efficient exploration and development.
This paper proposes a multi-agent system centered on large language models to address the issues that traditional well log interpretation relies on expert experience and poses great difficulty in multi-disciplinary collaboration and constructs a digital twin architecture across three dimensions of agents, tools and environment. At the agent level, a role-based architecture is established to decompose the complex log interpretation workflow into independent subtasks, enabling structured transfer of expert knowledge. At the tool level, petrophysical formulas and machine learning algorithms are encapsulated to form a physics-data dual-path hybrid reasoning mechanism; at the environment level, a standardized digital twin space is established based on the Model Context Protocol to achieve closed-loop control of the entire workflow. Engineers can drive the system through natural language commands to complete the full log interpretation process from data loading and parameter calculation to reservoir classification, realizing end-to-end automation from raw data to interpretation conclusions. In tests on 100 field wells, the system generates key interpretation parameters that are highly consistent with expert results, exhibiting stable recognition capability for complex reservoir types. This study demonstrates that this human-machine collaborative working mode significantly enhances the standardization and efficiency of well log interpretation, providing technical reference for intelligent transformation of highly specialized industrial processes.
To address the challenges of connectivity characterization, dynamic prediction efficiency, and real-time optimization in complex reservoir injection-production systems, this study proposes a physics- and deep learning-integrated intelligent injection-production modeling framework based on the graph connection element method. The method adopts the connection element method as the physical foundation and constructs a non-Euclidean graph representation to describe interwell connectivity, enabling characterization of the physical topology and dynamic interactions within the well pattern system. By incorporating an adaptive attention mechanism into a graph convolutional network and embedding time-dependent node attributes, a physics-consistent reservoir performance prediction model is developed. Furthermore, a hybrid optimization strategy integrating differential evolution and particle swarm optimization is employed to establish an intelligent optimization framework taking the economic net present value as the objective. Based on rapid prediction of injection and production behaviors, the proposed approach enables optimization of injection-production parameters and improvement of reservoir development economics. Field applications demonstrate that the proposed intelligent injection-production model based on graph connection element accurately reproduces water-cut behavior of producers and provides quantitative uncertainty estimation. It achieves rapid history matching and dynamic response forecasting for complex injection-production systems, exhibiting high accuracy and stability. It enables optimization of production strategies with NPV as the objective, demonstrating strong engineering applicability and scalability.
This paper systematically reviews the development stages and current status of key oil production engineering domains, including injection-production engineering, artificial lift, reservoir stimulation, and workover operations. The major challenges for oil production engineering are identified in four aspects: intelligent terminal equipment and process integration, extreme-environment operations, and collaborative operational constraints; AI-driven data and modeling complexities, and advanced structural and functional materials requirements; and the need for geology-engineering integration in reservoir characterization, operational efficiency and green development. Centered on multidisciplinary integration, the concept of the Oil Production Engineering Agent is introduced as a miniaturized, intelligent, and integrated hardware-software system designed for extreme downhole environments and complex conditions, incorporating power supply, communication, sensing, computation, and actuation modules to enable environmental perception, autonomous decision-making and adaptive control. The characteristics of various agent types, including those for injection-production, lift, fracturing and workover, are analyzed, with key research directions identified in miniaturized self-powered energy management, reliable communication in high-interference environments, highly integrated multi-parameter sensing with long-term drift self-calibration, and high-reliability microsystem integration manufacturing. AI-driven decision optimization remains the core feature, requiring advances in data acquisition, governance, and fusion architectures, alongside algorithmic improvements in model performance and deployment compatibility. Additionally, advanced structural and functional materials support agent construction and extreme-environment adaptability, while geology-engineering integration continues to expand the functional scope of oil production engineering.
The temperature-pressure history of the organic-rich shale in the Cretaceous Qingshankou Formation in the northern Songliao Basin was reconstructed through comprehensive analyses, including field tests, paleo-heat flow reconstruction, overpressure evolution and geochemistry. The formation and evolution process of the Gulong shale oil was reproduced, and its enrichment patterns were clarified. Influenced by tectothermal events and tectonic movements at the end of the Cretaceous Mingshui Formation deposition, the evolution of organic matter thermal maturity in the first member of Qingshankou Formation (Qing-1 Member) exhibited distinct stages, which can be divided into the Cretaceous rapid evolution stage and the Paleogene-Neogene slow evolution and stabilization stage. High paleogeotemperature drove secondary cracking of retained oil in the Qing-1 Member, forming light shale oil in the Gulong Sag. This sag experienced three phases of overpressure during the late depositional stage of the Nenjiang Formation and late depositional stage of the Mingshui Formation of the Cretaceous, and the Neogene. The first two phases were related to the oil generation peak and secondary cracking in the sag, respectively, while the third phase resulted from the inheritance of earlier overpressure, as well as sustained hydrocarbon cracking and heat-induced fluid volume expansion. Crude oil is distributed orderly in the northern Songliao Basin. Conventional oil reservoirs such as Saertu and Putaohua contain high contents of non-hydrocarbon compounds, and they are believed to have formed by hydrocarbon charging as a result of the first phase of overpressure. Tight oils in the Fuyu and Gaotaizi reservoirs, most similar to shale oil in the Qing-1 Member in terms of composition and physical properties, are characterized by high content of saturated hydrocarbons, with their hydrocarbon charging and accumulation related to the second phase of overpressure. High paleo-heat flow generated by tectothermal events is determined to be the main driving factor for the staged hydrocarbon generation of organic matter in the Qingshankou Formation. The shale of Qing-1 Member with high thermal conductivity and the Cretaceous Nenjiang shale with low thermal conductivity constitute a thermal structure with lower conducting and upper sealing. This structure has prolonged secondary cracking of hydrocarbons, widened the liquid hydrocarbon window, and helped self-sealing enrichment of the Gulong light shale oil by virtue of the third phase of overpressure.
Global deep Earth exploration and ultra-deep oil and gas exploration (below 6 000 m) have attracted increasing attention, with a growing number of major oil and gas discoveries. This article systematically reviews the discovery history of ultra-deep oil and gas exploration since 1937, dividing it into four major stages: onshore ultra-deep exploration and local breakthrough (1937–1982), shallow- water-dominated ultra-deep exploration and sporadic discoveries (1983–1997), onshore and offshore large-scale ultra-deep discoveries (1998–2018), and onshore over-8 000-m exploration and new breakthrough (since 2019). By the end of 2025, a total of 1 348 exploratory wells with a depth of more than 6 000 m have been drilled worldwide. A total of 305 ultra-deep oil and gas fields have been discovered in 29 basins across 20 countries, with recoverable reserves equivalent to 63.21×108 t, accounting for only 0.9% of the global total reserves and indicating enormous exploration potential. The discovered reserves are highly concentrated in the Tethyan and South Gondwana petroleum realms, dominated by passive continental margin basins with a proportion of 71.25%. Reservoirs are mainly composed of Meso-Cenozoic carbonate rocks and clastic rocks. Studies show that three types of advantageous basins, including cratonic basins, passive continental margin basins and foreland basins, have their own characteristics in terms of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation. The global ultra-deep oil and gas exploration degree is extremely low, and there may exist another “golden zone” for hydrocarbon accumulation with huge resource potential. In the future, it is necessary to strengthen research on the mechanisms of hydrocarbon generation and accumulation as well as resource assessment in ultra-deep strata, and carry out integrated evaluation combining geology, engineering and intelligent technology. Internationally, efforts should be focused on new ultra-deep project evaluation and oil and gas cooperation in hydrocarbon-rich regions such as the both sides of the Atlantic, the Middle East, Central Asia-Russia and Australia. With the accelerated exploration of over-8 000-m oil and gas in China, a new peak of reserve growth is forthcoming.
Based on the post-frac core evaluation results for shale gas reservoirs in the Jiaoshiba block of the Fuling gas field, a simulation method for tensile-shear composite fracture networks in shale and a multi-scale characterization method for residual gas were developed. The types and distribution characteristics of residual shale gas were clarified, and an efficient seepage field with coordinated “artificial well pattern – induced fracture network – natural fracture network” was established. Strategies for residual gas recovery were proposed, and the expected technologies for efficient development of shale gas reservoirs were recommended. The induced fractures in shale exhibit features such as single overall morphology, clustered non-uniform distribution, branching dendritic extension and limited propped area. Residual gas can be classified into four types: gas uncontrolled by well pattern, gas insufficiently swept by inter-well fractures, gas unevenly swept by inter-layer fractures, and gas unswept between clusters. For purpose of residual gas recovery and enhanced gas recovery, an efficient seepage field with coordinated “artificial well pattern – induced fracture network – natural fracture network” can be constructed through drilling infill wells with small well-spacing, sidetracking in old wells, differential trajectory design, and precise fracturing design. Future efficient development of shale gas is expected to be achieved by improving accurate reservoir characterization, advancing coordinated 3D development technologies, iteratively optimizing technologies for enhanced shale gas recovery, and deepening the synergy between conventional and unconventional development methods. These efforts are believed to drive high-quality advancement of the shale gas development technology in China.
This study compiles and analyzes data from over 125 published field projects around the world, covering nearly 900 treated wells. Building on those detailed studies, this paper distills the most important findings into a concise, practical, and actionable framework to guide where in-situ gel treatments should be applied, how they should be designed, and how their outcomes can be evaluated. The proposed workflow guides engineers through five integrated stages: screening appropriate gel types, designing formulation and injection strategies, predicting field response, evaluating treatment performance, and conducting iterative refinement with feedback loops to adjust designs based on observed outcomes. The framework integrates empirical selection rules, statistical design ranges, tapering strategies, and machine-learning tools, to support informed decision-making. While derived from retrospective analysis of mostly successful treatments, the structured methodology offers actionable guidance for future applications and helps bridge the gap between field observations and systematic design logic. By providing a data-informed workflow supported by field evidence, this study aims to enhance the reliability, consistency, and economic value of polymer gel treatments in complex reservoir conditions.
Through systematic comparison of the geological characteristics, resource distribution, and exploration and development status of global marine and continental shale oil, this paper deeply analyzes the key theoretical and technical issues that restrict the development of continental shale oil in China. It points out that the basic theoretical research areas, such as the enrichment and accumulation mechanisms of shale oil with different lithological combinations, and the multi-scale and multiphase flow mechanisms in nanoscale confined spaces, are relatively underdeveloped; the accuracy of sweet spot prediction cannot effectively guide the selection of target layers and the positioning of horizontal well trajectories, and geology-engineering integration practices remain insufficient. All these factors severely restrict the large-scale utilization of shale oil resources. Focusing on the progress in the study of continental shale oil in the Songliao Basin, Ordos Basin, Junggar Basin and Bohai Bay Basin of China, this paper systematically analyzes six bottleneck issues (genetic models of fine-grained sedimentary rocks, types and distribution of hydrocarbon-generating organic matter, hydrocarbon generation-expulsion models and potential, types and performance of reservoir spaces, parameter selection and evaluation techniques for sweet spots, and productivity laws and enhanced oil recovery), summarizes progress in theoretical and technological research, and discusses examples and directions for tackling key issues. It identifies six major challenges on geological theory and engineering technology confronting the shale oil revolution in China: hydrocarbon accumulation mechanisms, sweet spot identification, seepage law, fracturing modification, drainage and production technology and recovery enhancement. To address these, the study proposes to establish a shale oil classification scheme based on source-reservoir configuration, to promote the refined development model of “geology-engineering-geology spiral integration”, and build an efficient shale oil development technology system tailored to the continental geological conditions in China, providing theoretical and technical support for achieving large-scale and beneficial development.
The large-scale deployment of carbon capture, utilization and storage (CCUS) technologies and the growing demand for low-cost gas sources provide new opportunities for the development of CO2 multicomponent gas flooding. However, the interphase mass transfer mechanisms between CO2 multicomponent gas and crude oil system remains unclear. In this work, non-equilibrium and equilibrium phase experiments, equation-of-state calculations, molecular dynamics simulations, and reservoir-scale numerical simulations were combined to investigate the phase behavior and mass transfer mechanisms of CO2 multicomponent gas and crude oil system. The results show that non-equilibrium systems exhibit spatially heterogeneous local mass transfer. CO2 demonstrates the strongest dynamic mass transfer capacity, while under the same conditions, the dynamic mass transfer effect of N2 is extremely weak. The extraction effect of CO2 multicomponent gas on hydrocarbon components in crude oil exhibits a nonlinear “critical response”. When the CO2 mole fraction reaches a critical extraction threshold of approximately 70%, the overall extraction capacity of the system increases significantly, and heavy hydrocarbon components are more sensitive to changes in CO2 concentration. As the crude oil becomes lighter, oil displacement efficiency exhibits weak dependence on the extraction of heavy components by the multicomponent gas. This study provides a theoretical basis for optimizing multicomponent gas composition and selecting low-cost gas sources, and offers a valuable guidance for the field application of CO2 multicomponent gas flooding.
This paper systematically investigates the numerical simulation model construction and methods for hot dry rock geothermal resource development. It highlights the influence law and characterization differences of multi-physics field coupling mechanism across various stages of development and utilization. The technical features and applicable scenarios of typical numerical simulation methods, as well as the application potential and advantages of emerging technologies such as intelligent algorithms in numerical simulation for hot dry rock geothermal development, are comprehensively reviewed. In addition, the functional characteristics and engineering application cases of mainstream geothermal numerical simulation software in China and abroad are summarized. On this basis, the core challenges for existing techniques are identified, and future development directions are proposed. At present, numerical simulation for hot dry rock geothermal resource development still faces several challenges, including insufficient accuracy in characterizing complex reservoir structures, incomplete representation of multi-physics field coupling mechanisms, limited cross-scale simulation capability, inadequate adaptability of software to diverse scenarios, and insufficient support from field monitoring and fundamental data. In the future, numerical simulation technologies for hot dry rock geothermal resource development should advance theoretical and technical research in full-chain integrated modeling, refined characterization of multi-physics field coupling, deep integration of intelligent algorithms with numerical simulation, and establishment of an independent and controllable software ecosystem, thereby providing theoretical and technical support for the sustainable and efficient development of hot dry rock geothermal resources in China.
To accurately evaluate the storage capacity of shale oil reservoirs under in-situ temperature and pressure conditions, we constructed a new model for determining the porosity under formation conditions, developed a HTHP shale porosity measurement system capable of operating at an overburden pressure of 70 MPa, a pore-fluid pressure of 40 MPa, and a temperature of 120 °C, and established an integrated workflow for restoring in-situ porosity in clay-rich lacustrine shale oil reservoirs. This technology system was applied to the Upper Cretaceous Gulong shale oil reservoirs in the Songliao Basin, China. The in-situ porosity in shale oil reservoirs is generally higher than that measured at normal pressure on surface. The restored porosity increases by 3.17–4.00 percentage points for ordinary shale, 1.58–1.60 percentage points for silty shale, and 1.12–1.58 percentage points for carbonates. The restored porosity increase grows regularly with burial depth, temperature, pore pressure, and pressure coefficient, reflecting the elastic dilation of clay- and organic-associated nanopores and the widening of overpressure-supported microfractures in the Gulong shales. Core depressurization was found to close these pressure-supported pores, causing conventional helium and surface nuclear magnetic resonance (NMR) measurements to systematically underestimate storage capacity, particularly in deep, clay-rich, overpressured intervals. For reserve estimation, use of ambient-condition porosity may introduce significant underestimation of original oil in place (OOIP). For the clay-rich Gulong shales, it is recommended to apply a correction factor of 3–4 percentage points to the surface-measured porosity (or surface porosity) for ordinary shale, and about 1.6 percentage points for silty shale, while only a minor correction is needed for carbonates. In-situ porosity should thus be incorporated into OOIP calculations and parameterized using clay content, total organic carbon content, pressure coefficient and burial depth. Operationally, production from clay-rich, overpressured intervals should be implemented under controlled pressure, in order to avoid elastic closure of native microfractures and preserve reservoir deliverability.
Based on the molecular structure transitions, hydrocarbon composition, and reservoir characteristics changes during coal evolution, combined with the production characteristics of coal-rock gas, the generation stages and genetic types of coal-rock gas in China are investigated. The generation of coal-rock gas can be divided into five stages: low-coal-rank biogenic gas generation stage (Ro < 0.5%), mid-coal-rank transitional gas generation stage (0.5% ≤ Ro < 0.8%), mid-coal-rank mature gas generation stage (0.8% ≤ Ro < 1.3%), mid-coal-rank high-maturity gas generation stage (1.3% ≤ Ro < 2.0%), and high-coal-rank overmature gas generation stage (Ro ≤ 2.0%). Based on the burial depth and gas origin, the gas reservoirs are divided into three types: shallow coalbed methane, deep coal-rock gas and exogenous coal-rock gas. According to the hydrocarbon generation stage of coal, deep coal-rock gas is further classified into: mid-coal-rank transitional coal-rock gas, mid-coal-rank mature coal-rock gas, mid-coal-rank high-maturity coal-rock gas, and high-coal-rank overmature coal-rock gas. During the dynamic evolution of coal from shallow to deep depths, the coal has experienced a hydrocarbon generation evolution sequence of “biogenic gas→transitional gas→wet gas→dry gas”, and a process of “primary pores→cleat development→peak organic matter pores→densification and fracturing + fracture opening” of reservoirs formation . The occurrence state gradually shifts from “dominance of adsorbed gas” to “continuous increase in free gas proportion”, and the development modes also transform from “long-term drainage and depressurization for desorption” to “high gas production upon well opening”. In addition, there is another type of coal-rock gas which is externally sourced, with the natural gas originating from underlying strata. This type of coal-rock gas corresponds to low-rank coals with reservoir development, where gas was accumulated under the control of tectonics, with high-proportion free gas and high initial production.
Given the stringent requirements for friction reducers in terms of long-distance friction reduction, efficient proppant transport, temperature resistance and viscosity enhancement in deep oil and gas reservoir fracturing development, an aqueous two-phase high-viscosity friction reducer ANSD-PADA suitable for deep reservoir fracturing was prepared by introducing nanomaterial ANSD and through the aqueous two-phase polymerization. Its mechanisms of temperature resistance, viscosity enhancement, and friction reduction were explored by means of fluorescence spectroscopy, microscopic morphology observation, nanomechanical testing and other analytical methods, and field tests were also carried out. The introduction of hydrophobic monomer N-(3-dimethylaminopropyl) methacrylamide enables PADA (a self-synthesized hydrophobic terpolymer) molecules to entangle, associate and self-assemble into a honeycomb-like network structure under the combined effects of van der Waals forces, electrostatic repulsion and hydrophobic interaction. This structure further increases the hydrodynamic volume, thereby significantly improving the viscosity-enhancing performance of the product. ANSD fills the pores of the polymer network structure, effectively strengthening the network skeleton and association junctions, and remarkably improving the temperature resistance of the system. The friction reducer retains a friction reduction rate of 73.36% at 130 °C, with a temperature resistance up to 150 °C, and it has demonstrated encouraging results in the pilot site at Well XX-HF targeting deep shale oil reservoirs on the northern slope zone of the Gaoyou Sag, Subei Basin, China.
Coal-measure whole petroleum system is generally featured by dual-source multi-reservoir coupling, coexistence of three dynamic fields controlling hydrocarbon accumulation, and sequential accumulation of deep coal-rock gas (shale gas), proximal tight sandstone gas (fractured tight gas), distal tight gas/conventional natural gas, and shallow coalbed methane. To reveal the common geological characteristics of coal-measure WPS in the Jurassic coal-bearing basins in Northwest China, this paper analyzes the geological characteristics of coal-measure WPSs in Kuqa Depression of Tarim Basin and Thrust Belt of Southern Junggar Basin, such as structure and hydrocarbon accumulation. It is pointed out that the Jurassic whole petroleum system of coal measures in northwestern China is significantly different from that of the Carboniferous–Permian in North China. Four types of source-reservoir coupling accumulation models are mainly developed in the Jurassic of Northwest China, including structural-type shallow to deep conventional gas outside the source, structural-type deep to ultra-deep tight gas outside the source, near-source/in-source tight gas, and self-generating and self-preserving coal-rock gas. It is indicated that the Jurassic strata in Northwest China belong to the giant continental sedimentary region on the passive continental margin of Neo-Tethys Ocean, including six subsidence zones, and containing coal measures and coal rocks that are consistent in the region but distinct from basin to basin. Thus, this region stands as the largest Mesozoic coal-measure area and a giant natural gas accumulation area in China. Resource assessment demonstrates that the Jurassic coal-measure WPS in Northwest China holds natural gas resources up to 30×1012 m3, in which merely 11% has been proved, and coal-rock gas accounts for 17×1012 m3, possessing a tremendous exploration potential. Deep and ultra-deep tight gas and coal-rock gas in Kuqa Depression and Southwestern Depression of Tarim Basin, southern margin of Junggar Basin, northern margin of Qaidam Basin, and Taipei Sag of Turpan-Hami Basin will serve as key natural gas exploration targets in the future.
Under the guidance of the whole petroleum system (WPS) concept, the Jurassic coal-measure source rocks, source-reservoir- caprock conditions, and configurations of various hydrocarbon accumulations in the Junggar Basin were systematically investigated to reveal the hydrocarbon accumulation characteristics and exploration targets of the Jurassic coal-measure WPS. The following research insights are obtained. First, the coal rocks of the Jurassic Badaowan and Xishanyao formations, together with the mudstones of the Sangonghe Formation, constitute a unified source kitchen characterized by large thickness, high thermal evolution degree and sustained gas-generation capability. This kitchen provides an ample source for the orderly accumulation of conventional oil and gas, coal-rock gas and tight sandstone gas. Second, multi-phase fluvial–deltaic sedimentation has developed thick conventional sandstones, tight sandstones, and coal rocks as diverse types of reservoirs in the basin, offering various storage spaces for hydrocarbon accumulation, while regionally extensive thick mudstones ensure effective sealing of deep gas reservoirs. Third, within the unified petroleum accumulation, system, multi-phase detachment and superimposed structures control hydrocarbon migration pathways and accumulation units, resulting in a orderly distribution of reservoirs from structural highs to deep sags. Specifically, at the southern margin, deep conventional natural gas and deep coal-rock gas are endowed in the central segment, while oil and gas coexist in the eastern and western segments; in the basin hinterland, coal-rock gas generated from old strata and stored in young strata is confirmed in the Dinan–Baijiahai area, while coal-rock gas generated and stored in the same set of strata is discovered in the Qigu area; in the slope and structurally complex zones, tight sandstone gas of the Badaowan Formation is found.
