Upper Cambrian carbonates constitute an important petroleum reservoir interval in the Tabei area of the Tarim Basin, yet the relative roles of depositional facies and multistage dolomitization in reservoir development remain poorly constrained. This study integrates core observations, petrography, carbon and oxygen isotopes, Rare earth elements geochemistry, fluid-inclusion microthermometry, and in situ carbonate U-Pb geochronology to reconstruct the depositional framework, constrain dolomitization processes, and evaluate reservoir evolution. Five dolostone microfacies (MF1-MF5) were identified within tidal flat, intraplatform shoal, and platform margin shoal settings of a rimmed carbonate platform. Early seepage-reflux dolomitization mainly affected shallow-water tidal flat and shoal deposits and is characterized by fine-crystalline dolomite (MF3), preservation of residual grain and depositional fabrics (MF1-MF2), and relatively high δ18O and δ13C values. Subsequent burial dolomitization produced medium- to coarse-crystalline dolomite within MF3, characterized by subhedral to euhedral crystals, relatively depleted δ18O values, and elevated Mn contents. Localized tectono-hydrothermal dolomitization was focused along fracture-controlled fluid pathways and is recorded by saddle dolomite with depleted δ18O values, fluid-inclusion homogenization temperatures of 100–140 °C, and U-Pb ages of 472.7 ± 7.5 Ma and 469.4 ± 4.7 Ma, suggesting a possible association with Episode I of the Middle Caledonian tectonic evolution. Reservoir development was primarily inherited from moderate- to high-energy shoal deposits, whereas later dolomitization, dissolution, fracturing, and carbonate mineral precipitation locally modified the pre-existing pore system. These results emphasize depositional inheritance as the principal control on Upper Cambrian reservoir development and provide a sedimentary-diagenetic framework for evaluating analogous deeply buried carbonate reservoirs.

Natural fractures are one of the important reservoir spaces and seepage channels of continental shale reservoirs in Bonan Subsag of Jiyang Depression. The development characteristics and genetic mechanism of natural fractures directly restrict the single well productivity. By means of seismic interpretation, core and thin section observation, scanning electron microscope and XRD whole rock diffraction, the structural style, natural fracture development characteristics, main controlling factors and the influence of effective fractures on single well productivity in Bonan sag are studied. The results show that natural fractures in the lower member of Shahejie Formation can be divided into tectonic fracture fracture, diagenetic fracture and abnormal pressure fracture of organic matter evolution according to genetic types, while tectonic fracture can be divided into shear fracture, tensile fracture and bedding detachment fracture according to geological causes. The development types of natural cracks are mainly vertical shear cracks (75°~90°), the overall extension length of natural cracks is not long (5~10 cm), and the width of tensile cracks is slightly wider (0.5~1.0 mm). The fillers are mainly calcite and asphalt, and the shear joints are not filled. The main controlling factors of natural fracture formation include distance from fault, structural combination style, carbonate mineral content, organic matter content and lithofacies combination type, and the close distance from fault, fault hanging wall and fault block structural combination style lead to the development of natural fractures. The contents of carbonate minerals and organic matter are directly proportional to the development degree of natural fractures, and natural fractures in carbonate shale facies and felsic shale facies are more developed. The unfilled high-angle shear fracture and unfilled tensile fracture are the effective fractures that contribute the most to shale oil productivity, followed by unfilled bedding detachment fracture. This study is conducive to deepening the regular understanding of the formation mechanism of natural fractures in eastern continental shale oil, and providing an important basis for the exploration and development practice of fractured shale oil in Bonan Subsag and even the whole Jiyang depression.

Deeply buried (>7000 m) Middle Cambrian (Miaolingian) carbonate rocks in the northern Tarim Basin, China, represent a highly promising target for resource exploration. Their reservoir quality is governed by complex diagenetic processes, including multiple stages of dolomitization and subsequent dedolomitization. This study presents an integrated analysis using petrology, stable isotopes, trace elements, fluid inclusion microthermometry, and in situ U–Pb dating from seven wells. We systematically interpret the complex diagenetic history and fluid evolution of the Miaolingian carbonates. Results reveal a complete paragenetic sequence from near-surface to deep-burial diagenetic realms. Early diagenesis was dominated by marine-derived fluids in near-surface to shallow-burial realms, where supratidal and seepage–reflux dolomitization led to the formation of early dolomicrite (Md1) and grainy/microbial dolomite (Md2), along with the precipitation of dogtooth/fibrous cements (Cd1). With increasing burial depth, normal seawater influenced by geothermal circulation formed very fine- to fine-crystalline dolomite (Md3) and associated granular cements (Cd2). In the intermediate- to deep-burial realm, the diagenetic system was dominated by basinal fluids. The fabric of early dolomites was destroyed under elevated temperatures (∼110 °C) to form fine- to medium-crystalline dolomite (Md4). This was followed by cementation of euhedral (Cd3) and blocky (Cd4) dolomite cements. Late-stage diagenesis was tightly coupled with regional tectonic activity. Saddle dolomite (Sd) precipitated from high-temperature (∼139 °C), high-salinity (∼22 wt.%) tectonic–hydrothermal fluids, and some Md4 may have been altered by these fluids. U–Pb dating of early calcite cements (Cc-Ⅰ) yields an age of 459.1 ± 3.3 Ma, constraining the initial episode of the middle Caledonian Orogeny. Fluid inclusions within these cements have high temperatures (110.2–125.2 °C) and exhibit seawater-like rare earth elements and yttrium (REY) patterns, indicating a record of buried formation water. Subsequently, episodes II and III of the middle Caledonian Orogeny induced fluid mixing between Ca2+-rich formation water and meteoric water in the intermediate burial realm, causing localized dedolomitization that formed matrix calcite (Mc) and late-stage calcite cements (Cc-Ⅱ), characterized by lower homogenization temperature (Th) values (∼90–110 °C). Integration of diagenetic phases with reservoir quality reveals contrasting porosity evolution. Seepage–reflux and seawater dolomitization were the constructive processes, while supratidal, burial and hydrothermal dolomitization, and dedolomitization were predominantly destructive, occluding pore space and deteriorating reservoir quality.

The complex transport behavior of hydrocarbons in micro/nanochannels leads to inaccuracies in identifying hydrocarbon accumulation zones, as well as to hydrocarbon leakage. Hydrocarbon movement through confined channels is difficult to characterize and understand in detail because it involves complex hydrodynamic behaviors of hydrocarbon under the joint effects of various physical and chemical effects. Microfluidic platforms provide a powerful means to directly visualize and quantify these confined transport behaviors. In this work, we summarize recent theoretical and experimental advances enabled by microfluidic approaches and highlight five dominant mechanisms governing hydrocarbon transport in micro/nanochannels: (1) molecular sieving and adsorption jointly control the lower transport limit; (2) asphaltene aggregation induces pore blockage; (3) wall slip triggers ultrafast flow; (4) strong confinement shifts the hydrocarbon phase envelope; (5) wettability and roughness modulate capillary retention and flow resistance. Integrating these insights into reservoir simulation frameworks will improve the accuracy of hydrocarbon flow prediction.

The sedimentary architecture of carbonate platforms is determined by distinct paleobiological, tectonics, climatic, oceanic and environmental conditions. During the Cambrian period, a rimmed carbonate platform system developed over an area of similar to 28 x 10(4) km(2) in the Tarim Basin. However, the evolution mechanism and its predominant controlling factors remain poorly understood. The investigation utilized integrated analysis of cores, thin sections, 3-D seismic, well logging and geochemical data to explain the sequence stratigraphic framework, depositional architecture and main controlling factors. Sixteen distinct microfacies (MF1-MF16) are identified based on thin-section analysis of the five lithofacies, which could be further grouped into fourteen microfacies associations (MA1-MA14). These fourteen microfacies associations respectively represent fourteen facies belts of the five facies of the shelf, outer ramp, middle ramp, platform margin and restricted platform. Microfacies and seismic characteristics have provided the basis for establishing a sequence-stratigraphic framework. Two regionally extensive second-order sequences (CS1-CS2) are developed in the Lower-Middle Cambrian succession; CS1 incorporates five third-order sequences (Sq1-Sq5); CS2 incorporates three third-order sequences (Sq6-Sq8). The lateral migration and vertical arrangement of depositional facies resulted in a unique depositional architecture. The overall carbonate platform architecture is interpreted from 3D seismic data, integrated with the depositional facies interpretations to document the evolution of the depositional setting over time from a broad shelf (Sq1-Sq2), to a distally steepening ramp (Sq3-Sq4), to a weekly rimmed platform (Sq5), and finally to a strongly rimmed platform (Sq6-Sq8). Relative sea-level (RSL) curves were reconstructed through an integrated analysis of Fischer plots from three wells. The determined RSL curve matches closely with reconstructed paleo-water depths indicated by the distribution of microfacies types. The inferred paleo-water depths changes comprise two long-term shallow-deep-shallow trends, upon which eight intermediate-term cycles are superimposed. Microfacies also have been applied to explain the evolution of the platform in response to RSL change and other environmental factors. A major transgression occurred in the lower parts of CS1. Results demonstrate that RSL and paleo-water depth changes in the Lower-Middle Cambrian are consistent with known global sea-level changes indicated by geochemical elements. The architectural and sequence-stratigraphic evolution of the progradational rimmed carbonate platform was controlled principally by eustasy. This study is important due to the limited information on Cambrian rimmed platforms.

The Tarim Basin, with its relatively low level of exploration, is one of China's largest superimposed petroliferous basins. Recent exploration advancements in the Shunbei-Shunnan area highlight the significant potential for ultra-deep marine natural gas. However, uncertainties surrounding the origin, alteration, and accumulation models of ultra-deep marine natural gas have greatly hindered future hydrocarbon exploration. This study systematically analyzes the geochemical characteristics and genesis of ultra-deep marine natural gas in the Shunbei-Shunnan area. Results indicate that the natural gas in this region comprises both primary and oil-cracking gases. Specifically, the Shunbei area's natural gas is primarily oil-associated, dominated by primary cracking gas with minor contributions from oil-cracking gas, whereas the Shunnan area's natural gas is predominantly oil-cracking gas. The maturity of marine natural gas varies, being higher near the Manjiaer Depression and relatively lower farther away. A sequential distribution of highly mature dry gas, condensate oil and gas, volatile oil, and light oil, accompanied by a gradual decrease in gas-oil ratio, is observed with increasing distance from the Manjiaer Depression. The marine natural gas in the Shunbei-Shunnan area has undergone various alterations, including cracking, thermochemical sulfate reduction, and hydrothermal fluid alteration. Hydrocarbon alteration is more pronounced in the Shunnan area than in the Shunbei area. The active period of strike-slip faults in the Shunbei-Shunnan area coincides with the major hydrocarbon generation and expulsion phases of the source rock. These strike-slip faults serve as critical conduits for hydrocarbon migration, enabling oil and gas to migrate vertically into the middle and upper Ordovician reservoirs, where they form the primary reservoir spaces for accumulation.

Based on the new data of drilling, seismic, logging, test and experiments, the key scientific problems in reservoir formation, hydrocarbon accumulation and efficient oil and gas development methods of deep and ultra-deep marine carbonate strata in the central and western superimposed basin in China have been continuously studied. (1) The fault-controlled carbonate reservoir and the ancient dolomite reservoir are two important types of reservoirs in the deep and ultra-deep marine carbonates. According to the formation origin, the large-scale fault-controlled reservoir can be further divided into three types: fracture-cavity reservoir formed by tectonic rupture, fault and fluid-controlled reservoir, and shoal and mound reservoir modified by fault and fluid. The Sinian microbial dolomites are developed in the aragonite-dolomite sea. The predominant mound-shoal facies, early dolomitization and dissolution, acidic fluid environment, anhydrite capping and overpressure are the key factors for the formation and preservation of high-quality dolomite reservoirs. (2) The organic-rich shale of the marine carbonate strata in the superimposed basins of central and western China are mainly developed in the sedimentary environments of deep-water shelf of passive continental margin and carbonate ramp. The tectonic-thermal system is the important factor controlling the hydrocarbon phase in deep and ultra-deep reservoirs, and the reformed dynamic field controls oil and gas accumulation and distribution in deep and ultra-deep marine carbonates. (3) During the development of high-sulfur gas fields such as Puguang, sulfur precipitation blocks the wellbore. The application of sulfur solvent combined with coiled tubing has a significant effect on removing sulfur blockage. The integrated technology of dual-medium modeling and numerical simulation based on sedimentary simulation can accurately characterize the spatial distribution and changes of the water invasion front. Afterward, water control strategies for the entire life cycle of gas wells are proposed, including flow rate management, water drainage and plugging. (4) In the development of ultra-deep fault-controlled fractured-cavity reservoirs, well production declines rapidly due to the permeability reduction, which is a consequence of reservoir stress-sensitivity. The rapid phase change in condensate gas reservoir and pressure decline significantly affect the recovery of condensate oil. Innovative development methods such as gravity drive through water and natural gas injection, and natural gas drive through top injection and bottom production for ultra-deep fault-controlled condensate gas reservoirs are proposed. By adopting the hierarchical geological modeling and the fluid-solid-thermal coupled numerical simulation, the accuracy of producing performance prediction in oil and gas reservoirs has been effectively improved.

The solubility characteristics of sulfur in sour gas are crucial in addressing the issue of sulfur deposition and comprehending the multiphase flow behavior in high-H2S gas reservoirs. To this end, a pioneering molecular simulation method was proposed in this study to investigate the dissolution of sulfur in sour gas at the molecular scale. The solubility of sulfur in methane (CH4), carbon dioxide (CO2), hydrogen sulfide (H2S) and their mixtures were quantified. Additionally, the microscopic dissolution process of sulfur was elucidated and its differences among different gas components were highlighted. The results show that H2S is the predominant component that facilitates the dissolution of sulfur in sour gas. More specifically, the density in the central region of the sulfur phase diminishes linearly with the escalation of sulfur solubility in the H2S component. Meanwhile, the density at the edge of the sulfur phase increases linearly, and the thickness of the transition zone of the sulfur phase tends to increase initially and then remain constant. As temperature and pressure rise, the interaction energy between H2S molecules and sulfur augments, resulting in the entry of more gas molecules into the central region of the sulfur phase. Consequently, a smaller sulfur-sulfur intermolecular interaction energy ensues, leading to an increase in sulfur solubility. Similarly, the difference in solubility of sulfur among CH4, CO2, and H2S is also attributed to the variation in interaction energy between gas components and sulfur molecules. These findings hold important implications for sulfur control and treatment in high-H2S gas reservoirs.

In order to clarify the influence of liquid sulfur deposition and adsorption to high-H2S gas reservoirs, three types of natural cores with typical carbonate pore structures were selected for high-temperature and high-pressure core displacement experiments. Fine quantitative characterization of the cores in three steady states (original, after sulfur injection, and after gas flooding) was carried out using the nuclear magnetic resonance (NMR) transverse relaxation time spectrum and imaging, X-ray computer tomography (CT) of full-diameter cores, basic physical property testing, and field emission scanning electron microscopy imaging. The loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1 000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pore spaces, and causes greater damage to reservoirs with poor original pore structures. The pore structure of the three types of carbonate reservoirs shows multiple fractal characteristics. The worse the pore structure, the greater the change of internal pore distribution caused by liquid sulfur deposition and adsorption, and the stronger the heterogeneity. Liquid sulfur deposition and adsorption change the pore size distribution, pore connectivity, and heterogeneity of the rock, which further changes the physical properties of the reservoir. After sulfur injection and gas flooding, the permeability of Type I reservoirs with good physical properties decreased by 16%, and that of Types II and III reservoirs with poor physical properties decreased by 90% or more, suggesting an extremely high damage. This indicates that the worse the initial physical properties, the greater the damage of liquid sulfur deposition and adsorption. Liquid sulfur is adsorbed and deposited in different types of pore space in the forms of flocculence, cobweb, or retinitis, causing different changes in the pore structure and physical property of the reservoir.

Gas hydrates are typically found in the fine-grained sediments with low abundance and strong heterogeneity in the northern South China Sea. To date, although numerous gas hydrate reservoirs have been discovered, commercial exploitation remains highly challenging. Previous studies show that the Qiongdongnan Basin exhibits coexistence of gas hydrates, shallow gas and deep gas reservoirs. The hydrate-bound gases are a mixture of thermogenic and biogenic gas, mainly sourced from the granite buried hill reservoir, central canyon channel of the Lingshui Depression and the Yacheng Formation. In this study, we described a new development concept termed ��Three-gas Joint Development�� (TJD), to elucidate the simultaneous exploitation of these three gas reservoirs. Based on the distribution of three-gas reservoirs, three different TJD plans are proposed. If the relative distance between three-gas reservoirs does not exceeds the extension limit, a single production platform is capable of exploiting all three-gas reservoirs. A vertical well is suggested if the deep gas reservoir lies directly below the gas hydrates and shallow gas. Otherwise, multilateral well should be used to exploit different gas reservoirs with various branches in a main wellbore. However, several key issues remain unsolved. Numerical simulation of TJD should be conducted to evaluate interlayer interference and productivity. Efficient sand control and wellbore stability techniques, such as frac-packing and high-performance drilling fluids, are recommended when drilling unconsolidated sediments. Once these key technologies are overcome, TJD can provide a feasible approach for the commercial development of gas hydrates.

Drowned carbonate platforms on passive margins present a paradox, because their great growth potential exceeds the typical rates of passive margin subsidence and any relative sea-level rise driven by long-term processes in the geologic record. In this study, manned submersible observations, sampling, and high-resolution acoustic data were used to investigate a drowned isolated carbonate platform cropping out at a water depth of 536–800 m in the northern South China Sea. Based on the results, the Early Miocene strata of the platform are grouped into three units (AU1, AU2, and AU3) that formed on the fault-created topography. The fault-created topography served as a template for the onset of the carbonate platform deposition and as a pedestal for the localization of backstepped platforms in response to accommodation space variations, primarily driven by rapid subsidence and eustatic rises during the Early Miocene. The Middle Miocene strata of the platform are grouped into four units (AU4, PU1, PU2, and PU3), exhibiting a general switch from dominantly aggrading to dominantly prograding platform margins, in tandem with the cessation of faulting. The biostratigraphy and established seismic–stratigraphic correlations indicate that the carbonate platform was submerged during the late Middle Miocene. The banktop consists of a heterozoan carbonate factory dominated by large benthic foraminifera and coralline algae. This facies was deposited during a time interval when summer monsoon-induced upwelling triggered heterozoan factory turnover in other carbonate platforms in the region, such as at well XK-1 (Xuande Platform). The asymmetric backstepping of the platform margins demonstrates that summer monsoon-driven currents influenced the platform drowning. Therefore, summer monsoon-induced upwelling was a major factor influencing platform drowning during the late Middle Miocene. Platform growth did not persist due to the high subsidence rate throughout the Late Miocene. This study provides new insights into the drowning mechanism of a Miocene carbonate platform in the northern South China Sea and a new seismic analog for other ancient, isolated platforms worldwide.

Ultra-deeply buried (>5000 m) marine carbonate reservoirs have gradually become important exploration tar-gets. This research focuses on providing an understanding of the basic elements of the ultra-deeply buried Middle Triassic Leikoupo marine carbonate petroleum system within the Western Sichuan Depression, China. Comprehensive analyses of organic geochemistry, natural gas, and C-H-He-Ne-Ar isotope compositions suggest that the reservoir is charged with compound gases from four source rock units including the Permian Longtan, Middle Triassic Leikoupo, Late Triassic Maantang and Xiaotangzi formations. Approximately a 50-m thick outcrop and 100-m length of drilling cores were examined in detail, and 108 samples were collected from six different exploration wells in order to conduct petrographic and petrophysical analyses. Thin-section and scanning electron microscope (SEM) observations, helium porosity and permeability measurements, mercury injection capillary pressure (MICP) analysis, and wire-line logging (5500-6900 m) indicate that the reservoir lithologies include argillaceous algal limestones, dolograinstones, crystalline dolostones, and microbially-derived stromatolitic and thrombolitic dolostones. Reservoir properties exhibit extreme heterogeneity due to different paleogeographic environmental controls and mutual interactions between constructive (e.g., epigenetic paleo-karstification, burial dissolution, structural movement, pressure-solution and dolomitization) and destructive (e.g., physical/chemical compaction, cementation, infilling, recrystallization, and replacement) diagenetic pro-cesses. An unconformity-related epigenetic karstification zone was identified in the uppermost fourth member of the Leikoupo Formation, which has developed secondary solution-enhanced pores, vugs, and holes that resulted in higher porosity (1.8-14.2%) and permeability (0.2-7.7 mD). The homogeneity and tightness of the reservoir increases with depth below the unconformity, and it is characterized by primary intergranular and intra-crystalline pores, solution pores, fractures, stylolites, and micropores with a lower helium porosity (0.6-4.1%) and permeability (0.003-125.2 mD). Regional seals consist of the Late Triassic Xujiahe Formation, comprised of-300 m of mudstones that are overlain by-5000-m thick of Jurassic to Quaternary continental argillaceous overburden rocks. Effective traps are dominated by a combination of structural-stratigraphic types. Paleo-reservoir crude oil cracking, wet-gases, and dry-gases from three successive hydrocarbon generation processes supplied the sufficient hydrocarbon resources. The homogenization temperatures of the hydrocarbon-associated aqueous fluid inclusions range from 98 to 130 degrees C and 130-171 degrees C, which suggests hydrocarbon charging occurred between 220-170 Ma and 130-90 Ma, respectively. One-dimensional basin evolution models combined with structural geologic and seismic profiles across wells PZ1-XQS1-CK1-XCS1-TS1 show that hydrocarbon migration and entrapment mainly occurred via the unconformity and interconnected fault-fracture networks with migration and charging driven by formation overpressure, abnormal fluid flow pressure, and buoyancy forces during the Indosinian and Yanshanian orogenies, with experiencing additional transformation occurring during the Himalayan orogeny. The predicted estimated reserves reached-300 x 109 m3. The results provide excellent scientific implications for similar sedimentary basin studies, it is believed that abundant analogous deeply buried marine carbonate hydrocarbon resources yet to be discovered in China and elsewhere worldwide in the near future.

地层硫沉积对高含硫气藏采收率及开发中后期稳产具有重要影响.文中通过梳理高含硫气藏天然气中硫溶解度、流体相态平衡、地层硫沉积伤害等方面的研究进展,提出了高含硫气藏地层硫沉积研究的重要手段,即开展不同温压条件下高含硫气体的相态及微观流动室内实验,并与分子模拟、数值模拟方法相结合,分析地层硫沉积机理及规律.未来应着重加强三方面的基础研究:结合硫溶解度实验,采用分子模拟方法开展分子尺度下的硫溶解行为研究,揭示硫溶解机理;进一步开展高温高压条件下多硫化氢和硫组分变化实验,建立考虑化学反应和热力学平衡的气-水-液态硫三相相平衡模型;加强固态硫伤害及气-水-液态硫三相渗流实验研究,采用分子模拟方法获取各流体组分间多相流动力学行为参数,联合介观尺度多相流模拟方法,模拟多孔介质中气-水-液态硫三相渗流规律.在此基础上,进一步开展储层硫沉积预测数值模拟和硫防治技术研究,为我国以普光、元坝为代表的高含硫气田防硫、控硫、治硫对策制订提供依据.

在"双碳"目标下,油气行业面临着保障能源供应和绿色低碳发展的双重使命.分析全球能源转型大势下油气行业面对的新趋势和面临的新要求,提出"双碳"目标下我国油气产业发展路径.一是坚定不移持续加大勘探开发,确保国家核心油气需求供给安全;二是加大油气生产过程节能减碳改造,努力实现绿色低碳发展;三是推动油气传统能源与风光等新能源协同发展,实现油气能源与新能源融合互促;四是积极拓展共生伴生资源,打造新的业务增长极;五是大力发展碳捕获、利用与封存(Carbon Capture,Utilization and Storage,CCUS)负碳产业,发挥其在落实"双碳"目标中的兜底作用.

中国石化西南油气分公司2017年在四川盆地东南缘林滩场完钻的探井林页1井,证实林滩场构造在奥陶纪末—早志留世处于深水陆棚有利相带,页岩气形成条件较好.为进一步落实该区勘探开发潜力,实现五峰组-龙马溪组页岩气的商业突破,对林滩场进行区域构造和沉积特征分析.在大量基础地质实验数据分析的基础上,优选总有机碳(TOC)含量、有效孔隙度(POR)和含气量(GAS)作为地质甜点评价参数,脆性指数(BI)和水平主应力差作为工程甜点评价参数,地层倾角、断裂影响和地层压力作为保存条件评价参数.利用叠前反演求取地震弹性参数(纵横波速度比、密度和泊松比),通过岩心样品测试分析数据、储层地质岩性特征以及储层岩石物理分析,建立储层评价参数与地震弹性参数之间的定量关系,根据定量关系利用叠前反演CRP道集内岩性信息的AVO特征,对各项页岩储层评价参数进行平面预测,最终优选出林滩场页岩气有利目标区.应用地质-测井-地球物理一体化方法对页岩储层甜点区做出精准平面预测,对实现川东南盆缘复杂构造区页岩气勘探开发一体化具有重要的指导意义.

The Weirong shale gas field, located within a low-steep structural belt in southern Sichuan Basin, China, is characterized by gentle structural deformation. Production results have shown that inter-well interference, also known as fracture channeling, affects the productivity of shale gas wells by facilitating fluid flow between wells along pre-existing natural fractures. In this study, we used core observational data, scanning electron microscopy, and image logging analysis to determine the type, intensity, occurrence, and genetic mechanism of the natural fractures in the Upper Ordovician Wufeng-Silurian Longmaxi Formation. Attributes such as seismic coherence, AFE (fault-enhanced attribute), dip, and curvature were utilized to predict the macro and meso fault-fractures in the study area. We modeled the micro fault-fractures using the seismic and tracking algorithm to characterize the faults at multiple scales in the Weirong shale gas field, and then completed a comprehensive evaluation of the overall fracture development patterns with respect to the fracture channeling of neighboring shale gas wells. Results indicate that both horizontal and vertical structural fractures have been developed in the shale reservoir of the Wufeng-Longmaxi Formation in the Weirong shale gas field, although the horizontal fractures heavily outnumber the inclined ones. While a few high-conductivity macro and meso fractures display a NE-SW strike, abundant micro-faults have NE-SW and NWW-SEE strikes. Due to the pre-existing basement faults, stress fields and micro-amplitude structure, the NWW-SEE-trending micro fault-fractures are more active than those oriented in the NE-SW direction. Based on field observations, we conclude that regions with well-developed natural fault-fracture networks are more likely to have experienced fracture channeling between or within the platforms of well groups; and the NWW-SEE-trending micro fault-fractures generate more inter-well interference than the NE-SW-trending ones. Predicting the distribution and understanding the origin of the micro fault-fractures make it possible to prevent or mitigate the effects of fracture channeling during the drilling and artificial stimulation of shale gas wells.

In this review on the exploration and development process of the Shunbei ultra-deep carbonate oil and gas field in the Tarim Basin, the progress of exploration and development technologies during the National 13th Five-Year Plan of China has been summarized systematically, giving important guidance for the exploration and development of ultra-deep marine carbonate reservoirs in China and abroad. Through analyzing the primary geological factors of "hydrocarbon generation-reservoir formation-hydrocarbon accumulation" of ancient and superposed basin comprehensively and dynamically, we point out that because the Lower Cambrian Yuertusi Formation high-quality source rocks have been located in a low-temperature environment for a long time, they were capable of generating hydrocarbon continuously in late stage, providing ideal geological conditions for massive liquid hydrocarbon accumulation in ultra-deep layers. In addition, strike-slip faults developed in tectonically stable areas have strong control on reservoir formation and hydrocarbon accumulation in this region. With these understandings, the exploration focus shifted from the two paleo-uplifts located in the north and the south to the Shuntuoguole lower uplift located in between and achieved major hydrocarbon discoveries. Through continuing improvement of seismic exploration technologies for ultra-deep carbonates in desert, integrated technologies including seismic acquisition in ultra-deep carbonates, seismic imaging of strike-slip faults and the associated cavity-fracture systems, detailed structural interpretation of strike-slip faults, characterization and quantitative description of fault-controlled cavities and fractures, description of fault-controlled traps and target optimization have been established. Geology-engineering integration including well trajectory optimization, high efficiency drilling, completion and reservoir reformation technologies has provided important support for exploration and development of the Shunbei oil and gas field.

氦气是一种重要的战略稀缺资源,通常与天然气伴生.中国目前仅发现塔里木盆地和田河气田一例特大型富氦气田.本文报道了鄂尔多斯盆地东胜气田新的实例,该气田为首例致密砂岩型特大富氦气田.鄂尔多斯盆地东胜气田92个天然气样品中氦气相对含量数据统计分析表明,该气田天然气中氦气平均含量为0.133%,其中有65个样品氦气含量不小于0.1%,占比70.7%.按照东胜气田探明天然气储量折算,探明氦气地质储量约1.96×108m3,为我国首个特大致密砂岩型富氦天然气藏.结合东胜气田5个天然气样品中氦气同位素组成分布区间为3.03×10-8～3.44×10-8,认为该气田氦气为典型壳源成因,氦气源为基底富含铀、钍的花岗质基岩.富氦天然气成藏受到区域构造活动控制,沟通基底的断裂开启使得源岩中氦气释放,沿断裂进入上覆地层与常规烃类气体混合聚集成藏.结合鄂尔多斯盆地构造背景以及氦源岩分布特征,该盆地北部与中部深层可能是氦气富集主要区域,具勘探潜力.