石油实验地质

2025, 47(2): .

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Innovative exploration and post-drilling insights from H3X well in Haizhong Sag of Beibuwan Basin

JIANG Donghui, YANG Pengcheng, CHENG Xuetong, CAO Qian, YU Yongqi, NIU Huawei

2025, 47(2): 223-234. doi: 10.11781/sysydz2025020223

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The Haizhong Sag of the Beibuwan Basin has undergone decades of oil and gas exploration, but no commercial achievements have been made. Previous analysis suggested that this is primarily constrained by three key issues: indefiniteness of high-quality source rocks, unclear large-scale reservoir developing zone, and unknown profitable hydrocarbon accumulation. To achieve exploration breakthroughs in the region, key factors controlling reservoir formation were reexamined and confirmed based on basin analysis methodologies. By reconstructing the prototype basin and analyzing the characteristics of paleobathymetric, paleogeomorphology, and paleo-provenance, the study identified that the Haizhong Sag developed high-quality source rocks of the Eocene Liushagang Formation. The source-to-sink system was redefined, revealing the presence of a favorable delta-beach bar sedimentary system in the relatively flat areas of the steep slope zone of the Haizhong Sag at the distal end of the Weixinan low uplift. Guided by the exploration strategy of exploring reservoirs near major fault zones of hydrocarbon transport and reservoir development areas, the steep slope zone in the Haizhong Sag was selected as the most favorable area for future exploration. The H3X well, deployed based on this strategy, achieved production breakthrough, confirming the Haizhong Sag as a hydrocarbon-rich sag with favorable conditions for dual-source hydrocarbon supply. The oil and gas mainly originated from the deeply buried Liushagang Formation of the Haizhong Sag. Oil formed in early stage and gas formed in late stage, with two periods of accumulation. The study also confirmed that the Haizhong steep zone developed a delta-beach bar sand sedimentary system. The single layer of beach-bar sand is thin, but the accumulated thickness is large. The deep reservoirs have been significantly improved by the crack modification with better physical property. Furthermore, it clarified that the steep slope zone in the Haizhong Sag is a critical target for large-scale reserve increase in Weixi area. Two hydrocarbon accumulation systems were identified, including the upper normal-pressure structural traps as well as the lower overpressure structural and lithologic traps. The connections between sand body and fault and the development of effective reservoirs are key elements for accumulation. The high position of the Hai-3 structure is the key target for reserve expansion, while the Hai-4 structure is the priority for new breakthroughs.

Research progress, exploration process, and challenges in marine sandy hydrates

FAN Qi, FU Qiang, GUO Gang, ZHU Zhenyu, PANG Weixin, LI Qingping, ZHUO Haiteng

2025, 47(2): 235-247. doi: 10.11781/sysydz2025020235

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Natural gas hydrates are a key area of development in marine energy resources. However, the technical and economic barriers for muddy silt gas hydrate exploration in the South China Sea are high, and their resource potential remains controversial. This paper reviews the significant advancements achieved in China, the United States, and Japan over the past 20 years in the exploration of marine sandy hydrates. It discusses three primary hydrate types, i.e., muddy silt pore-filling, muddy silt fracture-filling, and sandy pore-filling hydrates, and summarizes the characteristics of sandy hydrates based on core samples, well logging, and laboratory findings. This paper presents the exploration and evaluation procedures for the "hydrate accumulation system" and discusses the challenges such as non-diagenetic reservoir evaluation, temperature-pressure variations, geomechanics, and pressure-preserved coring. Results reveal that sandy pore-filling hydrates (extendable to silt-sized particles) are currently the only hydrate type with economic value, characterized by high saturation (40% to 90%), high resistivity, strong formation strength, high quartz content (56% to 77%), and higher median particle size (approximately 56 to 87 μm). Those hydrates are typically well-sorted silty deposits in white-gray or black-gray, with a frosted texture and pore structure development. It is recommended to enhance the popularization and application of the "hydrate accumulation system" in the exploration of sandy hydrates and further address the issues in non-diagenetic reservoir evaluation, phase transitions due to temperature-pressure changes, complex geomechanical problems, and pressure-preserved coring technology. In conclusion, a reassessment of hydrate resource value is needed to provide a theoretical and scientific basis for the co-production of natural gas and gas hydrates.

Fault-cavity bodies: probable spaces for large-scale hydrocarbon migration and accumulation in non-carbonate rock areas

LUO Qun, WANG Qianjun, GUI Shiqi, HE Xiaobiao, HU Wanjing, ZHANG Yuejing, WANG Liang, CAO Xuming

2025, 47(2): 248-260. doi: 10.11781/sysydz2025020248

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In carbonate rocks, it is easy to understand that fault-cavity bodies form because they dissolve easily when fluids flow along faults, creating caves. However, non-carbonate rocks are not as easily dissolved by fluids. This raises the question of whether caves still develop along faults in such areas, and if so, whether they can facilitate the migration, accumulation, and enrichment of hydrocarbons. The study aims to demonstrate the existence of large caves along faults in non-carbonate rock areas, which are key spaces for hydrocarbon migration and accumulation. Taking the Chepaizi Uplift in the western Junggar Basin as an example, the internal structures in fault rocks, the distribution and development characteristics of caves, and differential hydrocarbon migration and accumulation were studied through field investigation, core observation, drilling analysis, seismic interpretation, and physical simulation experiments. This study suggests that large cave-like geological bodies, such as fault-cavity bodies, can form along fault cores in non-carbonate rock areas. The void space, formed by the relative displacement of two fault blocks during fault activity, is defined as a fault-cavity body. It can either form as the two fault blocks move along an undulating fault plane (zone), or they separate along the dip direction of the fault. The formation of fault-cavity bodies is not related to dissolution but is instead controlled by fault surface (zone) undulations, strike or dip separation, fault occurrence, and the movement direction of two fault blocks. fault-cavity bodies can be massive in scale and are often found where strike-slip fault occurrence changes, at the intersections of different faults, or in areas of concentrated extensional or transtensional stress with significant dip separation. These fault- cavity bodies can trap hydrocarbons, forming fault-cavity type hydrocarbon reservoirs. The concept of fault-cavity bodies challenges traditional perspectives, suggesting that in extensive non-carbonate rock areas, such as clastic, volcanic or metamorphic rock areas where dissolution effect is minimal, hydrocarbon-rich, large-scale fault-related hydrocarbon reservoirs, similar to those in carbonate rock regions of the Tahe and Shunbei (Fuman) oilfields can exist.

Morphological characteristics of framboidal pyrite and their paleo-environmental significance in Longmaxi Formation of Weirong area, southern Sichuan Basin

ZHAO Guowei, DENG Mo, WANG Yuanzheng, JIANG Xiaoqiong, ZENG Huasheng, ZHANG Changjiang

2025, 47(2): 261-272. doi: 10.11781/sysydz2025020261

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The morphological characteristics of framboidal pyrite have important indicative significance for the shale sedimentary environments and shale gas enrichment. Taking the shale in the first member of the Longmaxi Formation from well WY1 in the Weirong area of southern Sichuan Basin as the study subject, argon ion scanning electron microscopic analyses and ImageJ image processing were conducted to obtain the morphological characteristics and particle sizes of framboidal pyrite and its microcrystals. By analyzing parameters such as trace elements, organic matter abundance, and gas content, the study explored the indicative role of framboidal pyrite morphology in paleo-water redox environments and shale gas enrichment. The results demonstrated that parameters such as the average particle size of framboidal pyrite, the average particle size of microcrystals, and the crystalline structures showed significant variations vertically. The average particle sizes of pyrite and its microcrystals were 4.02 μm and 0.45 μm, respectively. The particle sizes of both pyrite and its microcrystal gradually increased from bottom to top. The crystalline structure of microcrystals from the lower part was mainly truncated octahedrons, and the upper part featured truncated octahedrons, supplemented by octahedrons and truncated tetrahedrons. The roundness of microcrystals gradually decreased from bottom to top. The morphological characteristics of framboidal pyrite and its microcrystals indicated that the reducibility of the sedimentary water body in the first member of the Longmaxi Formation gradually weakened, transitioning from an euxinic and anoxic environment to a suboxic environment. This aligned well with the redox environment reflected by trace elements. Furthermore, contents of organic matter and desorbed gas showed a significant positive correlation with pyrite content, but a clear negative correlation with the particle sizes of framboidal pyrite and its microcrystals. The findings show that an euxinic and anoxic environment is favorable for the enrichment of organic matter and the generation, accumulation, and preservation of shale gas.

Fluid pressure gradient characteristics and petroleum geological significance in Shahejie Formation of Bonan Sag in Jiyang Depression

LIU Peng, MENG Tao, YAN Fatang, LI Zhongxin, SHAN Chengcheng

2025, 47(2): 273-283. doi: 10.11781/sysydz2025020273

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Fluid pressure gradient is the rate at which residual fluid pressure changes both spatially and temporally. It serves as an important parameter for indicating oil and gas migration pathways and accumulation zones, holding great geological significance. This paper focuses on the Shahejie Formation in the Bonan Sag of the Jiyang Depression. Based on drilling, logging, mud logging, seismic and geochemical analysis data, various technical methods were integrated to characterize the spatiotemporal distribution of fluid pressure gradients by mapping both paleo and present-day fluid pressures. Additionally, the controlling factors were analyzed, and their geological significance was discussed. The results show that the horizontal pressure gradient in key layers of the Bonan Sag is significantly lower than the vertical pressure gradient. High horizontal pressure gradient zones are mainly distributed in a ring-shaped pattern around the edge of the sag. There are three high vertical pressure gradient zones, forming elongated zones in a planar distribution with a broad spatial extent. High temporal pressure gradient zones at the beginning and end of the main hydrocarbon accumulation period in the Bonan Sag occur in the southwestern and northeastern regions of the sag, mainly driven by hydrocarbon generation pressurization, whereas the remaining areas exhibit relatively low values, suggesting intense hydrocarbon expulsion and pressure release. Tight lithological layers, fault systems, and the development of high-permeability reservoirs are the main controlling factors of the formation and distribution of pressure gradients. Among them, tight lithological layers control the high vertical pressure gradient zones, and fault systems control both high horizontal and low vertical pressure gradient zones. Fault order and activity influence the magnitude of temporal pressure gradients, and the development of high permeability reservoirs tends to result in high horizontal pressure gradient zones and low temporal pressure gradient zones. The magnitude of spatial pressure gradient indicates the preferred direction of oil and gas migration, while differences in temporal pressure gradients indicate the dominant accumulation zones for shale oil and conventional oil.

Source-to-sink pattern and sand body distribution in the first member of Permian Lower Shihezi Formation in Fuxian area, Ordos Basin

FANG Xulei, WANG Linlin, QI Rong, GAO Hui, YANG Fei, LIU Lu, SU Juan

2025, 47(2): 284-295. doi: 10.11781/sysydz2025020284

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The Fuxian area in the southeastern Ordos Basin is a crucial area for natural gas exploration in the Upper Paleozoic. The primary exploration target, the first member of the Permian Shihezi Formation (He 1 Member), is significantly influenced by complex tectonic and sedimentary processes, resulting in an unclear understanding of the source-to-sink distribution pattern and sand body distribution. Therefore, in-depth research on the sedimentary fillings, the genetic types of sand bodies, and their distribution patterns under multiple provenance systems is of significant importance for efficient natural gas exploration and large-scale storage enhancement in this region. The study employed field outcrop survey, core analysis, thin-section observation, heavy mineral analysis, and well logging data to systematically analyze the sedimentary provenance of the He 1 Member in the Fuxian area. The study summarized the genetic types, structural characteristics, and the distribution and evolution patterns of sand bodies. During the sedimentary periods, the He 1 Member in the Fuxian area primarily developed a terrigenous clastic debris filling zone in the southern region and a mixed-provenance terrigenous clastic debris filling zone in the northern and southern region. Nine lithofacies types and three lithofacies assemblages were identified within the He 1 Member, with the main sand body genetic types being braided river facies channel filling in braided rivers and channel bars. Along the provenance direction, lithofacies assemblages evolved from incision, aggradation, and lateral accretion in the southern provenance zone to lateral accretion in the mixed-provenance zone of the northern and southern region. The He 1 Member experienced a sedimentary evolution process from terrigenous coarse clastic debris sedimentation during flood periods at an initial stage to muddy sedimentation during low water periods at a later stage. In addition, the sedimentary periods of He 1-1 and He 1-3 sublayers were favorable stages for the development of braided composite channel sand bodies, especially during the sedimentary period of the He 1-1 sublayer. The dominant sand bodies were mainly developed in the southern provenance sedimentary filling area in the central and eastern Fuxian area and the primary mixed-provenance filling area in the northern Fuxian area.

Simulation and zoning evaluation of in-situ stress field within ultra-deep tight sandstone reservoirs in thrust-nappe structures of Bozi-Dabei area, Tarim Basin

XING Zimeng, LI Ruixue, DENG Hucheng, SU Hang, ZHANG Jiawei, HE Jianhua, ZHANG Hui, HU Xiaofei, MA Shunting

2025, 47(2): 296-310. doi: 10.11781/sysydz2025020296

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The Cretaceous tight sandstone reservoirs in the Bozi-Dabei area of the Tarim Basin are key targets for ultra-deep tight sandstone gas exploration and development in China. Influenced by thrust-nappe structures and salt structures, the region has formed imbricate folding structures and a series of faults with large displacements and varying dip angles, resulting in a complex and highly variable in-situ stress field that is difficult to predict, severely restricting exploration and development in the area. To clarify the stress distribution pattern, an in-situ stress field simulation method, suitable for the characteristics of thrust-nappe structures was developed. Moreover, a stress grading and zoning evaluation was conducted, combining with the geological and engineering modification characteristics of the reservoirs. Core testing, well logging, and mining field test data were used to calibrate the in-situ stress direction and magnitude for individual wells, and their distribution characteristics were analyzed. By examining the impact of in-situ stress on reservoir physical properties, brittleness, and engineering modification difficulty, stress grading evaluation standards for the study area were established. A detailed three-dimensional heterogeneous in-situ stress field model was constructed for well B1, a key development area in the Bozi-Dabei area, to clarify the stress distribution characteristics and conduct zoning evaluations. The average error rate between the numerical simulation results and single-well in-situ stress interpretations was less than 10%. In well B1, the in-situ stress direction was primarily between N170°-190°E, and the stress direction near the faults deflected along the fault strike with deflection angles ranging from 20° to 60°. The magnitude of in-situ stress increased from north to south with burial depth, with reduced in-situ stress and stress differences at the high point of the anticline and within the fault zone. The higher the fault order, the greater the disturbance range and intensity. Based on a minimum principal stress of 145 MPa and a horizontal stress difference of 34 MPa, the in-situ stress state was classified into four categories: low stress difference with low in-situ stress, high stress difference with low in-situ stress, low stress difference with high in-situ stress, and high stress difference with high in-situ stress. The low stress difference and low in-situ stress areas in well B1, which are favorable for fracturing modification, are mainly developed in the hanging wall of the faults in the Cretaceous Bashijiqike Formation (K₁bs) and the high structural deformation areas.

Characteristics and genesis of carbonate micropores in the first member of Lower Cambrian Canglangpu Formation in north and central Sichuan Basin

ZHOU Chunyu, HE Yuan, LI Zongze, ZHOU Gang, YANG Dailin, SUN Yiting, ZHANG Ya, WEN Huaguo, LIU Sibing

2025, 47(2): 311-322. doi: 10.11781/sysydz2025020311

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Micropores with diameters under 10 μm are a current research focus in deeply buried tight reservoirs. The Lower Cambrian Canglangpu Formation in the Sichuan Basin shows considerable potential for natural gas exploration. The abundant micropores in the dolomite of the first member of Canglangpu Formation (Cang 1) serve as the main storage space for natural gas. Therefore, clarifying the development characteristics and genesis mechanisms of micropores is key to identifying favorable exploration areas. Through cast thin-section identification, scanning electron microscopy (SEM) analysis, and core computed tomography (CT) scanning, the study characterized the micropores in the dolomite of the Cang 1 member in the north and central Sichuan Basin. Additionally, the genesis mechanisms were explored considering the sedimentary environments and diagenesis processes. The oolitic dolomite samples from the Cang 1 member in the study area had an average porosity of 3.44%, with a maximum porosity of 9.44%. Cast thin-section analysis indicated poor pore development. However, SEM and CT scanning images revealed the presence of abundant micropores, demonstrating that micropores were the primary contributors to porosity in the oolitic dolomite reservoirs of the Cang 1 member. The reservoir space in the study area is dominated by intercrystalline pores extensively developed in particles. These micropores exhibit triangular or polygonal shapes, with pore diameters mainly ranging from 3 to 9 μm, and are abundant, displaying a dot-like or clustered distribution. On a macroscopic scale, the micropores outline the contours of oolites, indicating that micropores are primarily distributed within particles. The development of micropores in the dolomite of the Cang 1 member was intimately linked to the selective dissolution of oolitic beaches by meteoric freshwater due to sea-level changes in early sedimentary stages. The dolomitization at the burial stage was crucial for micropore formation. The loss of macropores was mainly influenced by compaction, pressure solution, and hydrocarbon charging from the underlying formations.

Pore structure and fractal characteristics of shale reservoirs in Jurassic Lianggaoshan Formation, northeastern Sichuan Basin

LI Qi, CHEN Ruiqian, SHANG Fei, LI Ling, BAI Xin

2025, 47(2): 323-335. doi: 10.11781/sysydz2025020323

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The Jurassic Lianggaoshan Formation in the northeastern Sichuan Basin is a key exploration target for shale oil. However, due to limited exploration in this area, the shale reservoir characteristics remain unclear. Experiments such as X-ray diffraction mineral analysis, scanning electron microscopy analysis, high-pressure mercury intrusion, and low-temperature nitrogen adsorption were conducted to systematically study the storage space types and fractal features of the Lianggaoshan Formation shale reservoir. The primary mineral composition of the Lianggaoshan Formation reservoir in the northeastern Sichuan Basin is clay minerals, with an average content of 51.57%, followed by feldspar and quartz minerals at an average of 47.11%, while carbonate minerals are scarce, averaging 2.69%. The dominant storage space types mainly include interlayer pores of clay minerals, intergranular pores between quartz and feldspar, and micro-fractures. The low-temperature nitrogen adsorption curve of the Lianggaoshan Formation shale aligns with type Ⅳ in the classification system of the International Union of Pure and Applied Chemistry, indicating slit-type pores. Based on the morphology of mercury intrusion curves and reservoir physical properties, the reservoir is divided into four types. From type Ⅰ to type Ⅳ, drainage pressure and median pressure increase, whereas maximum mercury saturation decreases, leading to enhanced reservoir heterogeneity. The "FHH"model calculations show that the pore surface fractal dimension (D_N1) is greater than the pore structure fractal dimension (D_N2), indicating that the pore surface exhibits greater complexity than the internal pore structure. The average fractal dimension D₁ of large pores, calculated using the water saturation method, averages 2.991 2, while that of small pores (D₂) averages 2.679 2. The larger pores have a fractal dimension closer to 3 and exhibit a more concentrated distribution, indicating that highly heterogeneous large pores contribute more significantly to the reservoir. Correlation analysis shows that there is a correlation between D and the contents of minerals (quartz and clay minerals) as well as pore-throat struture parameters, proving that large pores are the main contributers to the shale reservoir space in the study area. Through qualitative and quantitative analyses, this paper conducts a reservoir evaluation of the Lianggaoshan Formation shale in the northeastern Sichuan Basin, offering insights for the subsequent evaluation and selection of favorable exploration intervals in this area.

Hydrocarbon accumulation characteristics and main controlling factors of major salt-bearing basins in Central Asia

LIU Li, ZHANG Kaixun, YU Gang, YU Linjun, QIU Haihua, ZHOU Yan, GE Beiqi, NURTAEV Bakhtier, SHUKUROV Shukhrat

2025, 47(2): 336-346. doi: 10.11781/sysydz2025020336

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The Amu Darya Basin and the Pre-Caspian Basin in Central Asia hold enormous hydrocarbon resource potential and are the most representative salt-bearing basins in the region. Based on the latest petroleum geological data, this study systematically compares the structural and sedimentary evolution, petroleum geological characteristics, and hydrocarbon distribution patterns of the basins. The main factors controlling hydrocarbon distribution in salt-bearing basins are thoroughly analyzed to deepen the understanding of regional hydrocarbon accumulation patterns in Central Asia. Since the Amu Darya Basin and the Pre-Caspian Basin are oil and gas-rich basins formed under different geological backgrounds, there are obvious differences in the tectonic evolution process, sedimentary strata and oil and gas geological characteristics of the two; however, the pre-salt basins have developed high-quality source rocks formed in the same rift period and depression period, with the characteristics of huge thickness, high organic matter abundance and high degree of thermal evolution. The extensive development of salt-bearing strata in the Amu Darya Basin and the Pre-Caspian Basin controls the spatial and temporal distribution of hydrocarbons. This salt-bearing system divides the basins into two hydrocarbon accumulation systems: sub-salt and supra-salt rock sequences. Hydrocarbons are mainly concentrated in the sub-salt Callovian to Oxfordian carbonate reservoirs in the Amu Darya Basin and in the sub-salt Carboniferous to Lower Permian carbonate reservoirs in the Pre-Caspian Basin. Gypsum-salt cap rocks exhibit excellent sealing properties and, in conjunction with favorable reservoir facies in the structural positions of the paleo-uplift of the sub-salt rock sequences, provide optimal conditions for forming large oil and gas fields. Additionally, salt windows induced by deep faults, gypsum-salt pinch-out zones, and salt tectonic activities facilitate vertical migration of hydrocarbons in sub-salt source rocks, playing a crucial role in large-scale hydrocarbon accumulation in supra-salt rock sequences.

Physical simulation of hydrocarbon migration and accumulation in transport systems of allochthonous salt sheet development zone: a case study of Perdido Fold Belt in Burgos Basin, Gulf of Mexico

FAN Yan, XIANG Caifu, YANG Songling, PANG Lin'an, CHEN Jingtan, LI Aishan, CHEN Liang, JIANG Shanbin, SI Yongkang, YANG Minghui

2025, 47(2): 347-361. doi: 10.11781/sysydz2025020347

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The Burgos Basin is a typical salt passive continental margin basin in the western Gulf of Mexico, rich in oil and gas resources. The allochthonous salt sheet development zone in the Perdido Fold Belt of the Burgos Basin has formed an oil and gas transport system comprising the underlying structures of allochthonous salt sheets, faults, and the Paleocene to Eocene Wilcox Formation. Due to the deep-water environment and complex salt tectonics, the hydrocarbon transport characteristics and efficiency in these allochthonous salt sheet development zones remain unclear. Therefore, to reduce exploration risks, it is important to quantitatively evaluate the transport efficiency of hydrocarbon transport systems in the allochthonous salt sheet development zone of the Perdido Fold Belt and to clarify transport efficiency differences among various types of transport systems and their influencing factors. Based on seismic, well drilling, and well logging data, the hydrocarbon migration and accumulation physical simulation experiments were carried out on three types of transport systems—downdip, wavy, and updip-developed in the allochthonous salt sheet zone of the Perdido Fold Belt. The results showed that compared to the sand and mudstone at the base of the salt sheets, the Wilcox Formation exhibited higher transport efficiency in all three transport systems, serving as the primary channel for hydrocarbon migration. The transport efficiency varied during different migration periods. Specifically, the downdip system demonstrated the highest transport efficiency at the end of the Eocene, and the updip system had the highest efficiency at the end of Oligocene. During these two periods, the study area experienced strong fault activities, facilitating hydrocarbon migration. The hydrocarbon transport efficiency in the allochthonous salt sheet development zone of the Perdido Fold Belt was affected by factors such as the physical properties of transport systems, hydrocarbon migration distance, and the pressure difference between source rock and reservoir. Among these, the pressure difference is the main controlling factor, followed by the migration distance, with the physical properties of transport systems having a relatively minor effect.

Reservoir prediction of conglomerate bodies in the fourth member of Xujiahe Formation of Nanjiang area, northeastern Sichuan Basin: a probabilistic body lithofacies modeling-based reservoir prediction method combining forward and inverse modeling

LONG Tao, LIU Ming, ZHANG Yuxi, SUN Jun

2025, 47(2): 362-371. doi: 10.11781/sysydz2025020362

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The Upper Triassic Xujiahe Formation in the Nanjiang area of the piedmont belt in the northeast Sichuan Basin hosts large-scale, typical conglomerate gas-bearing reservoirs. These reservoirs remain underexplored and hold significant potential. Among them, the fourth member of the Xujiahe Formation is an important gas-bearing reservoir characterized by complex structural and lithological features, low sensitivity of geophysical parameters, and strong multi-solution, making reservoir characterization highly challenging. The distribution characteristics and patterns of favorable reservoirs remain unclear. To address this, a prediction method tailored for early-stage conglomerate reservoir exploration was developed by integrating seismic forward modeling, seismic inversion, and sequential Gaussian simulation-based lithofacies modeling. The probabilistic body lithofacies modeling-based reservoir prediction method applied seismic forward modeling to determine reservoir boundaries, seismic inversion for preliminary spatial reservoir distribution prediction, as well as well-logging and inversion collaborative modeling for refined prediction of the spatial probabilistic distribution of lithofacies, ultimately achieving precise reservoir prediction. The results showed that this prediction method used lithofacies modeling as a bridge to combine logging data with seismic inversion results, enabling quantitative prediction of reservoir thickness. The combination with seismic forward modeling further refined reservoir boundaries, significantly enhancing prediction accuracy. Applying this method to the Nanjiang area, the distribution of conglomerate reservoirs in the fourth member of the Xujiahe Formation was finely characterized. The favorable reservoirs are mainly located in the braided channels of the conglomerate facies, characterized by medium to weak amplitudes and slight amplitude downcutting on seismic profiles. Reservoir quality improves with increasing sandy content and decreasing mud and conglomerate content, resulting in weaker seismic amplitudes. The favorable reservoirs gradually thicken from north to south, exhibiting a banded distribution with thickness primarily between 15 and 30 m. This study provides a reliable geological basis for subsequent well location deployment in the target area and serves as a technical reference for reservoir prediction in similar blocks.

Geochemical oil and source correlation between crude oil of well Fusha 8 and source rocks of Permian Pusige Formation in southern margin, piedmont of southwestern Tarim Basin

WANG Xiang, GE Zhushi, ZHANG Huifang, SUN Di, WANG Zhanghu, XIE Xiaomin, MENG Qiang, CHEN Guo, XIAO Qilin

2025, 47(2): 372-383. doi: 10.11781/sysydz2025020372

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To further expand the oil and gas exploration in the southern margin of the piedmont of the southwestern Tarim Basin, this study focuses on the newly discovered oil from well Fusha 8 and source rocks from wells Fusha 2 and Yang 1 in the Permian Pusige Formation of the Fusha-Keliyang structural belt. Organic geochemical oil and source correlation research was conducted. Through pyrolysis, vitrinite reflectance testing, gas chromatography (GC), GC-Mass Spectrometry (MS), and n-alkane monomer hydrocarbon isotope analysis, the geochemical characteristics of different layers of source rocks in the Permian Pusige Formation were characterized from aspects such as basic geochemical properties, molecular biomarkers, and monomer hydrocarbon carbon isotope compositions. The study revealed variations in hydrocarbon generation potential across different layers of source rocks from the Pusige Formation. Also, oil sources in well Fusha 8 were preliminarily explored. Results showed that the upper part of the upper section and the middle section of the Pusige Formation had low organic matter abundance, containing type Ⅲ organic matter, and were unlikely to serve as effective source rocks. Also, these source rocks may be contaminated by migrated hydrocarbons from the deeply buried reservoirs. The lower part of the upper section and lower section of the Pusige Formation had relatively higher organic matter abundance, featuring type Ⅱ₁ to Ⅲ organic matter in the low mature to mature stages. The lower part of the upper section of the Pusige Formation was deposited in a mildly oxidizing shallow lake environment, and the organic matter inputs were mixtures of terrestrial higher plants and aquatic organisms. Its lower section was deposited in a more reducing deep to semi-deep lake environment, with a higher content of aquatic organisms as inputs. The crude oil from the Lower Jurassic of well Fusha 8 had higher Pr/Ph, C₂₄Te/C₂₆TT, and sterane/hopane ratios and lower C₁₉-C₂₃TT/C₃₀H ratios. It was rich in C₂₉ regular steranes, fluorene, and dibenzofuran, with n-alkane monomer carbon isotope values ranging from -32.0‰ to -29.0‰. These characteristics are consistent with the biomarker and monomer hydrocarbon carbon isotope compositions of the lower part of the upper section of source rocks in the Pusige Formation, confirming a strong geochemical oil and source correlation between them.

Hydrocarbon sources and accumulation processes in intra-platform of the fourth member of Dengying Formation in northern Sichuan Basin

YANG Yi, ZHU Xiang, ZHANG Lei, XU Zuxin, DAI Lincheng

2025, 47(2): 384-394. doi: 10.11781/sysydz2025020384

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The intra-platform of the fourth member of the Dengying Formation in the Upper Sinian of the Sichuan Basin is an important area for gas exploration. To clarify the hydrocarbon accumulation and enrichment patterns and distribution characteristics in this region, a study was conducted on the hydrocarbon sources and accumulation processes based on geochemical characteristics of natural gas and bitumen, thin-section observation, and fluid inclusion analysis of the intra-platform and platform margin areas. The results indicated that: (1) Compared to the platform margin areas in the fourth member of the Dengying Formation in northern Sichuan Basin, the intra-platform exhibited higher amounts of carbon isotopes in bitumen and natural gas methane and ethane, with smaller amounts of isotopes in hydrogen. This indicated that the oil and gas in the intra-platform mainly originated from a mixed source of the Qiongzhusi Formation and Sinian hydrocarbon source rocks, with a larger contribution from the Sinian source rocks. (2) There were two phases of oil charging and two phases of natural gas charging in the oil and gas reservoirs in the intra-platform of the fourth member of the Dengying Formation in northern Sichuan Basin. The first phase of low-maturity oil charging occurred in the Late Caledonian, the second phase of large-scale crude oil charging took place from the Late Permian to the Middle Triassic, the third phase involved crude oil pyrolysis gas charging during the Middle to Late Jurassic, and the fourth phase was natural gas adjustment charging in the Cretaceous. (3) The Tongnanba area has long been located in the lower part of the paleostructure from the oil accumulation to the gas accumulation period. The crude oil and natural gas from the paleo-oil and gas reservoirs continuously adjusted and migrated towards a higher position in the front of Micang Mountain, resulting in the loss of paleo-gas reservoirs in the Tongnanba area, which now has relatively poor gas content. The Nanjiang area had a more favorable source and reservoir configuration, remaining in the higher part of the paleostructure during the main oil and gas generation periods. It continuously received natural gas charging, and the fault sealing was good, which was conducive to gas reservoir preservation and oil and gas accumulation. Therefore, the Nanjiang area in the intra-platform is the next favorable exploration zone in the fourth member of the Dengying Formation in northern Sichuan Basin.

Field tests of CO₂ huff-n-puff technology in Nanchuan normal-pressure shale gas field

GAO Yuqiao, ZHENG Yongwang, ZHANG Lina, REN Jianhua, ZHANG Yaozu, FANG Dazhi

2025, 47(2): 395-405. doi: 10.11781/sysydz2025020395

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Abstract:
Due to the high proportion of adsorbed methane and weak formation energy, the recovery rate of normal-pressure shale gas reservoirs is generally less than 30%. SINOPEC took the lead in conducting CO₂ huff-n-puff field tests in the Nanchuan normal-pressure shale gas field in the Sichuan Basin, verifying the feasibility of CO₂ injection for enhanced recovery of marine shale gas. To promote this technology, a comprehensive study was carried out on the Nanchuan normal-pressure shale gas field, involving laboratory experiments, numerical simulations, and dynamic huff-n-puff analysis. The study analyzed the CO₂ competitive adsorption differences in different shale reservoirs, explored the CO₂ huff-n-puff characteristics in the field, and clarified the synergistic effects of CO₂ huff-n-puff to enhance shale gas recovery (ESGR) technology through multi-mechanisms of energy enhancement, displacement, and water-unlocking, aiming to guide well selection and program optimization. Using techniques such as electron microscope scanning, well logging interpretation, and isothermal adsorption experiments, the study revealed that the CO₂ competitive adsorption capacity of normal-pressure shale reservoirs in the Upper Ordovician Wufeng and the Lower Silurian Longmaxi formations of the Nanchuan area increased with decreased burial depth and formation pressure, and with increased porosity, TOC, and clay mineral content. The adsorption capacity of supercritical CO₂ was found to be 6 to 7 times higher than that of CH₄. After CO₂ huff-n-puff operations in shale gas wells, the daily gas production increased by 3.5 to 6.5 times, and the recovery rate increased by 1.9% to 3.1%. Based on pressure monitoring during the injection and soaking stages of two wells over three rounds of CO₂ injection, CO₂ mainly concentrated in the near-well micro-fractures. The diffusion distance, generally not exceeding 70 m, was related to formation pressure and the conductivity of fracture network. The process of CO₂ huff-n-puff can be divided into three stages: early rapid CO₂ flowback, early production increase, and mid- to late-stage stable production. The production increase mechanisms include early energy enhancement and supplementation, mid-stage expansion and expulsion assistance + water lock removal, and late-stage adsorption displacement + desorption promotion by partial pressure. The main influencing factors for increased huff-n-puff production are the degree of reservoir modification and recovery. Wells with poor fracturing effects in medium and deep layers had a higher gas exchange rate during the early and middle stages of CO₂ huff-n-puff, while wells with high recovery rates in shallow layers had a higher cumulative gas increase in the middle and late stages. Based on numerical simulations, it is recommended to prioritize wells with strong adsorption capacity, a recovery rate of 20% to 30%, poor liquid carrying capacity, and a shut-in pressure as close to 7 MPa as possible for field pilot tests. In the low-pressure and low-yield stage, small-scale multiple rounds of CO₂ huff-n-puff can be carried out in medium-deep wells for energy enhancement and expulsion assistance, while large-scale CO₂ huff-n-puff can be conducted in shallow wells to replenish formation energy and achieve enhanced recovery through adsorption displacement.

Optimization design of geothermal field development schemes based on hydraulic, thermal and chemical coupled numerical simulation: a case study of karst thermal reservoir in Xiong'an New Area, Hebei Province

LIU Jian, CAO Qiang, REN Xiaoqing, LU Xingchen, LIU Yiming, YANG Baolin

2025, 47(2): 406-416. doi: 10.11781/sysydz2025020406

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Abstract:
For the optimization design of geothermal resource development schemes in karst thermal reservoirs of the Xiong'an New Area, Hebei Province, a hydraulic, thermal and chemical multi-field coupled numerical simulation was conducted on the geothermal field's extraction status based on a three-dimensional geological model. The influence of key parameters such as extraction duration, extraction and recharge flow rates, well spacing, recharge temperature, and recharge rate on the effectiveness of geothermal field development was discussed using sensitivity analysis. The results showed that the extension of the extraction time of geothermal wells led to temperature decline and thermal breakthrough. In the current development scenario, the temperature of some geothermal wells in Xiongxian and Rongcheng areas could decrease by up to 4 ℃ over a 100-year extraction cycle. Reducing extraction flow rates and increasing well spacing could effectively delay thermal breakthrough and ensure the longevity of geothermal fields. In Xiongxian area, it was recommended that the well spacing should be kept from 500 to 600 m. The recharge temperature had little effect on the overall temperature field of the geothermal field, but reducing the recharge temperature could improve thermal utilization. The recharge rate had a significant impact on groundwater levels. A 100% recharge rate could maintain water level stability, while a 90% recharge rate could lead to a continuous decline in groundwater levels. In general, reasonable adjustment of the extraction cycle, extraction and recharge flow rates, well spacing, and recharge strategy can effectively extend the service life of geothermal fields and improve resource utilization efficiency.

Quantitative study on contribution of dynamic imbibition to oil production during fracturing and huff-n-puff in tight reservoirs

LIU Hongxian, BAI Lei, LUO Qiang, LIU Tongjing, SUN Jiangfei, LIU Jiaxing

2025, 47(2): 417-425. doi: 10.11781/sysydz2025020417

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Abstract:
Fracturing and huff-n-puff in tight reservoirs is a dynamic imbibition process, where crude oil recovery is enhanced mainly through two mechanisms: differential pressure displacement and spontaneous imbibition. However, the contribution rate of these two mechanisms to the quantification of overall oil recovery remains unclear. To address this, a quantitative analysis was conducted on the contribution of dynamic imbibition mechanisms during fracturing and huff-n-puff oil recovery in tight conglomerate reservoirs. Laboratory physical simulation experiments were carried out using natural tight conglomerate reservoir cores, utilizing a high-temperature and high-pressure multi-functional core displacement system and a high-temperature and high-pressure online displacement nuclear magnetic resonance imaging system. Firstly, experiments were conducted on the imbibition characteristics of different types of fracturing oil displacement agents, and the agents with superior imbibition effects were screened out. Secondly, based on evaluations of fracturing and huff-n-puff oil recovery, the most effective fracturing oil displacement agent was identified. Finally, through analyzing factors influencing oil recovery, a quantitative assessment of the production enhancement mechanisms of dynamic imbibition in fracturing and huff-n-puff oil recovery was carried out. The experimental results showed that both surfactants and flow control agents exhibited strong imbibition effects, with flow control agents more effective in enhancing fracturing and huff-n-puff oil recovery. Furthermore, the contribution of imbibition and displacement on oil recovery during the dynamic imbibition process showed opposite patterns. The main research conclusions are as follows. Imbibition dominates as the primary oil recovery mechanism when the fracturing oil displacement agent exhibits a strong ability to reduce interfacial tension and alter wettability. Otherwise, displacement becomes the dominant mechanism. Both surfactants and flow control agents demonstrate good imbibition performance. However, surfactants are less sensitive to huff-n-puff cycles, while flow control agents are more sensitive. Shut-in time is the key factor affecting the contribution rate of imbibition or displacement. However, the contribution rate of displacement remains consistently higher than that of imbibition.

Application and discussion of multi-factor sensitivity analysis in value assessment of areas with low exploration level

FENG Yongtai, ZHAO Linjie, WANG Baohua, LI Longlong, DUAN Tiejun

2025, 47(2): 426-432. doi: 10.11781/sysydz2025020426

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Abstract:
With the full implementation of competitive mining rights policies in China, the oil and gas exploration and production market has been fully open, but most of the exploration blocks currently being offered are located in areas with low exploration level. Due to the lack of data and limited understanding in these areas, major oil companies face challenges in evaluating, selecting, and bidding during the process of obtaining mining rights. Against this background, it is particularly crucial for those companies to quickly and effectively assess the value of areas with low exploration level to gain a strategic advantage in block acquisition. This study takes into account the risks in oil and gas exploration, including geological complexity, exploration limitations, development uncertainties, and economic fluctuations. Based on the internationally recognized expected monetary value (EMV) method, the study employed multi-factor sensitivity analysis to identify the key sensitive factors affecting block value assessment. A multiple regression equation was established between the expected revenue per unit of geological resources and the main controlling factors, thereby enabling an effective assessment of the value of areas with low exploration level. The method has been applied to a conventional karstic-fault oil reservoir block in the northern Tarim Basin. This method comprehensively considers geological, exploration, development, and economic risks in oil and gas exploration. Through quantitative multi-factor sensitivity analysis, it determines the key controlling factors and establishes an analogy model. It provides a scientific basis for defining the parameter systems in analogy methods, enabling objective and rapid assessment of expected revenue in areas with low exploration level. It offers strong support for bidding decisions on blocks on offer.

Issues in shale oil core porosity measurement

ZHANG Jinqing, TAO Guoliang, HUANG Dai, LUO Cuijuan, LIU Lingbo, YANG Yunfeng

2025, 47(2): 433-440. doi: 10.11781/sysydz2025020433

Abstract(28) HTML (13) PDF(3)

Abstract:
The primary methods for shale porosity measurement are the fluid invasion method and the electron/X-ray radiation methods. Among them, radiation methods, due to certain limitations, are currently not widely applied. Since shale pore structures have nanometer-scale characteristics, helium gas, with its small molecular size, stable chemical properties, and excellent permeability, has become the most commonly used fluid medium for shale porosity measurement. The penetration of helium gas into shale is influenced by core sample size and pore connectivity. Bulk samples require a long time for pressure equilibrium due to their complex pore tortuosity, while grain samples exhibit improved nanopore connectivity in shale with more pore space detected, making the measurement more accurate and reliable. This study aims to determine the sample with the optimal particle size and explore the impact of solvent extraction on porosity under the complex interaction mechanisms of soluble organic matter, organic solvent, and nanopores in shale oil cores. Recent progress in shale porosity measurement is systematically reviewed, focusing on sample size and solvent extraction, and experimental analyses of the shale oil core porosity in the Cretaceous Qingshankou Formation in Songliao Basin are conducted. The research indicates that the combination of bulk sample apparent density with grain helium porosity achieves the best measurement result for shale oil core porosity. It is recommended to use samples with particle sizes that cover 3 to 4 orders of magnitude larger than the main pore diameter to ensure both sample representativeness and experimental efficiency. It isn't recommended to perform solvent extraction on shale oil cores and use low-temperature vacuum drying to remove soluble organic matter in pores, thereby improving the accuracy of porosity measurements.

Main controlling factors on oblique extensional deformations in multiphase rift basins: insights from analogue experiments

WANG Qi, SUN Yonghe, GONG Lei, WANG Yougong, CHANG Deshuang, ZHANG Wanfu

2025, 47(2): 441-450. doi: 10.11781/sysydz2025020441

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Abstract:
In order to investigate the influence of pre-existing faults and their angle (α) with different extension directions on oblique extension deformation and sag structure in multiphase rift basins, three sets of analogue experiments were designed based on the similarity theory, including oblique extensional physical simulation experiments with different angles (α), and two sets of physical simulation experiments of oblique extensional and strike-slip deformations. The experiment results showed that: (1) In multiphase rift basins, the angles between the extension direction and pre-existing faults controlled the ratio between the strike-slip component and the dip-slip components, affecting the sag structure. As the angle increased, the dip-slip component and the width of the sag increased. Conversely, when the angle decreased, the sag width decreased. (2) Affected by the distribution of pre-existing faults, the reactivation style of pre-existing faults differed at different evolutionary stages. During the oblique extensional and strike-slip deformation, when the distance between the pre-existing strike-slip fault and the boundary fault was large, the sag showed a single-fault half-graben characteristic. When the distance between them was small, the strike-slip fault also controlled subsidence, and the sag presented a double-fault graben structure. (3) Sag depth and the amplitude of the compression and shear folds controlled by the reactivation of pre-existing boundary faults with multi-directional extension were also influenced by the distance between the faults. As the distance between the pre-existing boundary faults and strike-slip faults increased, the depth of the sag in the extensional-shear zone gradually increased, and the amplitude of the folds in the compressional-shear zone gradually increased. Conversely, the sag depth and fold amplitude decreased.

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