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2024 Vol. 46, No. 4

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2024, 46(4): 000-000.
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2024, 46(4): 00-00.
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Current research status and development trends of fault sealing
DING Wenlong, LIU Tianshun, CAO Zicheng, LI Haiying, HAN Jun, HUANG Cheng, WANG Shenghui
2024, 46(4): 647-663. doi: 10.11781/sysydz202404647
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The controlling effect of faults on hydrocarbon pool formation is mainly reflected in their impact on the processes of hydrocarbon migration, accumulation and distribution. Its essence is the problem of fault sealing. Fault sealing is typically influenced by a variety of factors, and the mechanism and the main controlling factors of fault sealing differ significantly across different layers, regions and geological periods. At present, there is no complete research system for the evaluation of fault sealing, and the accuracy of its evaluation needs to be improved. By comprehensively and systematically investigating recent research hotspots in the area of fault sealing, we summarize the mechanism of fault sealing, analyze the main controlling factors, systematically categorize the evaluation methods, and discuss the practical issues faced in fault sealing research. We also propose the development trends of future research. Fault sealing mechanisms can be divided into vertical and lateral sealing mechanisms. The former includes fault surface sealing and displacement pressure difference sealing within fault zones, while the latter includes sand and mud juxtaposition sealing, lateral sealing formed by shale smearing, and high displacement pressure sealing within fault zones. The main factors affecting fault sealing include fault development characteristics, lithology of the two fault walls, stress field environment, and diagenetic processes such as compaction, cementation, and dissolution. Different factors influence fault sealing in various ways, and fault sealing varies significantly with location and time. The research methods for fault sealing evaluation can be classified into four categories: (1) traditional geological methods: including qualitative and semi-quantitative analyses; (2) mathematical geological methods: including logistic information method, nonlinear mapping analysis, fuzzy comprehensive evaluation, grey correlation analysis, etc.; (3) numerical simulation of the tectonic stress field and calculation of parameters related to fault sealing; and (4) geochemical methods. Future research directions include fault opening and sealing mechanism and sealing evaluation of carbonate rock strata, the impact mechanism of stress and fluid coupling on fault sealing, comprehensive quantitative evaluations of fault sealing with multiple factors, the temporal and spatial evolution of fault sealing, and the assessment of fault connectivity.
Influence of sedimentary microfacies on the rock mechanics of ultra-deep reservoirs and its application: a case study of the Cretaceous formation in the BZ gas field of Kuqa Depression, Tarim Basin
WANG Zhimin, SUN Haitao, ZHANG Hui, WANG Chenguang, YIN Guoqing, XU Ke, ZHONG Dakang
2024, 46(4): 664-673. doi: 10.11781/sysydz202404664
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To optimize the identification of sweet spots with natural fracture development in ultra-deep tight sandstone reservoirs of Cretaceous in the Kuqa Depression, Tarim Basin, this study systematically analyzed the differences in rock mechanical properties across various sedimentary microfacies in the BZ gas field. Utilizing data from outcrops, rock slices, imaging logging, and other sources, a method for optimizing the rock mechanics parameter model of reservoirs was proposed, which enhanced the prediction accuracy of natural fractures within 200 m around the wellbore. Key findings of the research include: (1) In the third member of the Cretaceous Bashijiqike Formation in the BZ gas field, different sedimentary microfacies and the same microfacies at different positions had differences in rock composition and rock assemblages (including debris content, matrix content, grain size sorting, sand-to-mud ratio, and sand-mudstone combinations). These variations affected the reservoir's Poisson's ratio and Young's modulus, and different microfacies had different rock mechanical parameters. (2) The extent of fracture development differed across various sedimentary microfacies of sand bodies. Fractures were most developed in the underwater distributary channel sandstones at the fan delta front, making them more prone to fracturing compared to the interdistributary bay microfacies and distributary channel microfacies on the delta plain. (3) By further establishing three-dimensional models of different microfacies based on geometric parameters derived from outcrops, it would be feasible to optimize sedimentary microfacies models and rock mechanical parameter models around the wellbore, thereby facilitating more accurate fracture prediction.
Fracture characteristics and stress disturbance analysis for well optimization of Silurian in Shunbei area, central Tarim Basin
WANG Laiyuan, HUANG Cheng, GONG Wei, DING Wenlong, ZHAO Zhan
2024, 46(4): 674-682. doi: 10.11781/sysydz202404674
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The complex tectonic stress in the Shunbei area of the central Tarim Basin results in varied patterns of multilayered fractures. When drilling into the Silurian fracture zone and the formation pressure is lower than the drilling fluid column pressure, leakage easily occurs. To ensure efficient drilling, it is crucial to conduct an analysis of Silurian fracture characteristics and stress field disturbances to guide well design. Through enhanced interpretation and spatial analysis of Silurian faults, a comprehensive analysis of fractures was conducted in conjunction with the fault growth index. The overall characteristics of fractures in the study area included steeply dipping strike-slip faults and overlying en echelon normal faults with layered deformation. The Silurian fracture patterns primarily consist of echelon negative flower-like normal fault combinations, reflecting activity from late Caledonian to early Hercynian. The principal stress direction of the Silurian is 54° NE based on dipole array acoustic logging data from well SHZ1. By integrating three-dimensional seismic data interpretation with geological modeling and iterative boundary element numerical simulations, the current spatial distribution of stress fields, including maximum, minimum, and intermediate principal stresses, was established. The results of the stress field simulation were compared with interpretations derived from actual logging data. Due to the influence of fault occurrence and spacing, the width of stress disturbance zones varies on the plane, and stress disturbances above and below the fault plates show an asymmetric distribution. Through spatial sculpting of Silurian fractures and analysis of stress disturbances, optimal well locations and trajectories were selected to avoid areas with high fracture intensity, large dip angles, concentrated stress zones, strong energy anomaly fractures, and developed crack zones. The comprehensive analysis of Silurian fractures and stress field disturbance ensures efficient drilling and mitigates risks of significant Silurian leakage during well optimization.
Micromechanical characteristics and controlling mechanism of deep shale: a case study of well JYA in Pingqiao block, Fuling area
KONG Lingyun, SONG Guangpeng, JIANG Shu, WANG Zihang, LI Jiqing, SHI Xian
2024, 46(4): 683-697. doi: 10.11781/sysydz202404683
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The deep shale gas in the Fuling area is characterized by complex structures, high crustal stress, significant stress differences, high formation temperatures, high compaction levels, low porosity, low permeability, and complex porosity-permeability variation patterns. One reason for the significant production differences between wells is the insufficient understanding of the geomechanical features and controlling mechanisms of deep shale gas reservoirs, and the inaccurate identification of sweet spots for hydraulic fracturing. This study focuses on the marine shale of the Wufeng-Longmaxi formations in the Fuling area, investigating the micromechanical characteristics and controlling mechanisms of deep shale gas reservoirs through five series of experiments: micro rock mechanics experiments, digital speckle experiments, X-ray diffraction, total organic carbon content measurement, and scanning electron microscopy (SEM). Coupled with digital image processing technology, the changes in stress field and displacement field, and microcrack propagation processes in the Longmaxi shale under loading conditions were meticulously depicted. The deformation and fracture characteristics of the Longmaxi shale were analyzed. Experimental results indicated that the total organic carbon content in the deep shale is approximately 4.2%, with quartz content at 55.4% and clay mineral at 26.9%. The study identified five stages of microdamage evolution in deep shale: compaction, elasticity, uniform crack propagation, crack propagation failure, and brittle failure. Under the influence of brittle minerals such as quartz, and soft components such as organic matter, the microcracks in deep shale exhibit various propagation modes, including transgranular, intergranular, and laminated layer cracks. Additionally, the fracture toughness indices of the deep shale samples were calculated, with Mode Ⅰ index being 8.279 $\mathrm{MPa} \cdot \sqrt{\mathrm{m}}$ and Mode Ⅱ index being 1.243 $\mathrm{MPa} \cdot \sqrt{\mathrm{m}}$. These experimentally obtained fracture toughness indices can be applied to evaluate the brittleness of deep shale, providing guidance for deep shale fracturing modification.
Development characteristics and main controlling factors of bedding-parallel lamellated fractures in shale in 7th member of Triassic Yanchang Formation, southwestern Ordos Basin
LU Hao, ZHANG Jiaosheng, LI Chao, ZENG Lianbo, LIU Yanxiang, LÜ Wenya, LI Ruiqi
2024, 46(4): 698-709. doi: 10.11781/sysydz202404698
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Bedding-parallel lamellated fractures are widely developed in shale in the 7th member of Triassic Yanchang Formation (hereinafter referred to as Chang 7) in the southwestern Ordos Basin, which holds significant importance for sweet spot selection, fracturing operations, and development planning. In this paper, based on the surface outcrop and core observations in the Qingcheng to Huachi region of the southwestern basin, combined with analysis and testing of organic matter content, mineral composition and fabric characteristics, the developmental characteristics of bedding-parallel lamellated fractures in different lithologies in the Chang 7 shale were identified, and the main controlling factors of fracture development were analyzed. Results show that the morphology and distribution of the bedding-parallel lamellated fractures are mainly controlled by the laminates, exhibiting characteristics such as continuous flatness, wavy bending and branching due to the different characteristics of the laminae. Sandstone bedding-parallel lamellated fractures are mostly distributed along the biotite laminae, with good continuity and large aperture, and are generally unfilled. Shale bedding-parallel lamellated fractures are most developed in black shale, mostly distributed along the bedding laminates composed of organic matter layers, with a few partially or completely filled by calcite and organic matter. The aperture is smaller than that of sandstone, but the density is higher. Bedding-parallel lamellated fractures are also controlled by organic matter content, lithology, mineral composition, and laminate structure. The sandstone bedding-parallel lamellated fractures are mainly controlled by the content of biotite and the laminates formed by it. When sandstone sorting is good and biotite content is high with a layered distribution, the degree of fracture development is high. As the density of the laminates increases, the degree of development of bedding-parallel lamellated fractures also increases. Shale bedding-parallel lamellated fractures mainly develop in organic matter laminates and tuffaceous laminates, and are controlled by organic matter content and mineral components. Fracture density increases first and then decreases with the density of the layers. Fracture density in thin laminates is higher than that in thick laminates.
Stress field propagation characteristics of deep complex fault blocks based on digital speckle deformation simulation experiment
FENG Jianwei, ZHENG Chenxi, LIU Shuizhen, ZHOU Chongan, WU Wenke, SHEN Zhiyang
2024, 46(4): 710-721. doi: 10.11781/sysydz202404710
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In the process of oilfield exploration and development, the study of crustal stress plays an extremely important role in understanding the patterns of deep oil and gas migration and accumulation, enhancing reservoir fracturing efficiency and assessing drilling engineering risks. Previous studies on crustal stress have mainly focused on 2D/3D simulations, with very little research on regional structural changes and stress dynamic changes in the process of production and development. Taking block G of the Nanpu Sag of Bohai Bay Basin as an example, by creating similar geological models, setting boundary conditions, and conducting digital speckle deformation dynamic simulation experiment, the spatial propagation characteristics of stress/strain were obtained using the LOESS local regression analysis method. Combined with the classical stress wave theory, it was concluded that under the continuous action of tectonic force, the change of stress/strain at any point in the layer over time shows obvious cyclic volatility. This cyclic characteristic is more evident near the fault, with larger cyclic amplitude. Multiple reflections and transmissions occur when the stress wave passes through the fault. When numerous leftgoing waves meet rightgoing waves, the local stress and strain are concentrated, forming high-value areas. When a stress wave passes through a fault, the resulting strain causes a significant energy attenuation. Over time, the direction of stress/strain propagation is selective, always perpendicular to the direction of strong compaction and dense structure of the fault, leading to sharp energy decay after transmission. Over time, the propagation of stress/strain at any point in the formation appears as a wave cycle. However, unlike sound waves, the maximum and minimum amplitudes of the stress/strain cycle curve exhibit fluctuation characteristics along the direction of the applied force in space.
Development characteristics of structural fractures in tight sandstone reservoirs under multi-level configuration interfaces: a case study of second member of Xujiahe Formation in Western Sichuan Depression
LI Lifei, REN Qiqiang, YANG Tian, CAI Laixing, LI Zheng, CUI Rong
2024, 46(4): 722-734. doi: 10.11781/sysydz202404722
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Fractures are crucial for the high and stable production of natural gas from the tight sandstone reservoirs in the second member of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin. The development of these fractures is controlled by the configuration interfaces of sand bodies formed under different sedimentary environments. Through field outcrop surveys, core observations, logging identification, and detailed characterization of lithofacies, a classification scheme for sand body configuration interfaces was proposed for the second member of the Xujiahe Formation in the Western Sichuan Depression. These interfaces were identified and classified into second to fourth levels. The study clarified the characteristics and geological significance of fractures under different levels of configuration interfaces. These interfaces controlled the occurrence, opening degree, development degree, and storage-permeability capacities of reservoir fractures. The effective control ranges of the second and third level interfaces were 0-0.35 m and 0-3 m, respectively, while the fourth level interface had a larger control range (0-11 m). The development characteristics of fractures differed under different configuration interfaces. Specifically, fractures were underdeveloped at the second level interfaces; fairly developed at the fourth level; and most developed at the third level, primarily as low-angle dipping fractures. Fracture orientations were predominantly NNE-SSW, SEE-NWW, and SSE-NNW, with more fractures having larger openings (>0.04 mm) and larger dip angle. There was a clear positive correlation between core porosity and permeability in the fracture development under the control of the multi-level interfaces. Fractures at the third level interface had the strongest improvement effect on reservoir physical properties and made the highest contribution to oil and gas production, followed by the fourth level interface, with the second level interface being the least effective. Clarifying the control of different levels of configuration interfaces on fracture development is conducive to the effective development of tight sandstone gas reservoirs in the study area.
Development characteristics of natural fractures in horizontal wells for deep shale gas and their implications for enhanced development: a case study of Wufeng-Longmaxi formations in Luzhou area, southern Sichuan Basin
YANG Xuefeng, XIA Ziqiang, ZHAO Shengxian, HE Yuanhan, GAO Ruiqi, CAO Lieyan
2024, 46(4): 735-747. doi: 10.11781/sysydz202404735
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The analysis of natural fracture development characteristics is crucial for evaluating deep shale gas exploration and development. It provides valuable insights for assessing reservoir quality comprehensively and designing fracturing strategies differentially. This study focused on the deep shale of the Wufeng-Longmaxi formations in Luzhou area of southern Sichuan Basin (hereinafter referred to as southern Sichuan). Using core analysis, horizontal well imaging logging and seismic data, this study systematically investigated aspects such as descriptions of core natural fractures, development characteristics of horizontal well imaging logging, and the correlation between natural fractures in horizontal wells and seismically predicted fracture zones. The results show that horizontal well imaging logging can accurately identify three types of natural fractures: high-conductivity fractures, high-resistance fractures, and micro-faults. The fracture orientations identified by horizontal wells align with the direction of the current maximum horizontal principal stress, with fracture dip distribution patterns similar to those observed in vertical evaluation wells in the same structural positions. Seismically predicted fracture zones control the development of core-scale natural fractures identified through imaging logging. The influence distances of medium-intensity curvature body fracture zones, low-intensity curvature body fracture zones, and ant-track fracture zones on core-scale fractures are 110, 80, and 30-50 m, respectively. The Luzhou area's core-scale natural fractures exhibit "double-high" characteristics (high dip angle and high degree of calcite filling). The revealed correlations between the deve-lopment characteristics of core-scale natural fractures in horizontal wells, vertical well sections and seismic fracture zones serve as valuable references for the fine characterization of natural fractures, reservoir classification evaluation and differential fracturing technology testing of marine shale in southern Sichuan.
Characterization of irregular complex fractures in unconventional oil and gas reservoirs
HE Youwei, XIE Yixiang, QIAO Yu, CHEN Yulin, TANG Yong
2024, 46(4): 748-759. doi: 10.11781/sysydz202404748
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Unconventional oil and gas resources have large reserves and are difficult to develop. Reservoir fracturing is a key technical means for the development of unconventional oil and gas resources. Natural fractures and induced fractures are irregular and complex. To address the issue that existing fracture characterization methods cannot accurately depict the true shapes and width variations of fractures, a method based on unstructured PEBI grids for characterizing irregular and complex fractures was proposed. First, a natural fracture characterization process based on PEBI grids was established, allowing for accurate characterization of natural fractures in any region or a specified area. Second, a characterization and optimization method for induced fractures based on Delaunay triangulation and PEBI grids was developed, analyzing the impact of grid size and optimization iterations on fracture characterization accuracy. Third, a method for characterizing non-planar fractures using unstructured grids was established, enabling the depiction of curved fractures, making the fracture morphology and distribution more consistent with actual conditions. Fourth, a method for characterizing non-uniform fracture width was proposed, achieving fine characterization of fractures with non-uniform distribution of width and conductivity along the same fracture. Fifth, a complex fracture network characterization method coupling irregular induced fractures and irregular natural fractures in the whole area and specified regions was realized. For fracture network characterization under complex conditions such as large-scale intersections of natural and induced fractures, non-uniform fracture width distribution, and non-planar frac- tures, adjusting the number of grid optimization iterations could improve the quality of the fracture network characterization. Utilizing the advantage of PEBI grids to flexibly and accurately approximate complex fracture boundary conditions, this method enabled the rapid and accurate handling of a large number of irregular natural and induced fractures. The developed method for characterizing irregular and complex fractures helps improve the accuracy of fracture network characterization and numerical simulation calculations in unconventional oil and gas reservoirs.
Disturbance characteristics of in-situ stress field within ultra-deep tight sandstone reservoirs in thrust-nappe structures: a case study from Cretaceous reservoirs in Bozi-Dabei area, Tarim Basin
ZHANG Jiawei, LI Ruixue, DENG Hucheng, XING Zimeng, ZHANG Hui, HE Jianhua, WANG Zhimin, YANG Yuyong, SU Hang
2024, 46(4): 760-774. doi: 10.11781/sysydz202404760
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A series of large-scale north-dipping faults and imbricate folding structures have developed in the Cretaceous ultra-deep tight sandstone reservoirs in Bozi-Dabei area of Kuqa Depression of Tarim Basin under the north-to-south thrust-nappe movement in this area. This complex structural morphology results in highly variable in-situ stress fields, leading to significant differences in reservoir modification effectiveness. Therefore, it is urgent to clarify the disturbance characteristics of the in-situ stress caused by the complex structures in the study area. In this study, multiple methods were combined for the accurate interpretation of the current in-situ stress of a single well. The disturbance effects of faults, folds, and fault-fold composite structures on the in-situ stress were analyzed separately. The relevant disturbance mechanisms were identified, and a zoning map of the disturbance characte-ristics of the in-situ stress for the study area was presented. Based on these disturbance characteristics, models of in-situ stress disturbance for different structures, as well as recommendations for well deployment and trajectory, were proposed. Faults exhibit an unloading effect on the in-situ stress, leading to varying degrees of reduction in the horizontal principal stress gradient near the faults, with the maximum reduced by about 0.3 MPa/hm. Near EW-oriented faults, the regional stress direction near SN exhibits a clockwise deflection, with the maximum deflection angle reaching 60°. The disturbance range of faults with different scales is approximately 60% of the fault throw. A disturbance of the in-situ stress appears when the strata curvature exceeds 0.4 km-1. The in-situ stress is lower than the regional stress in the upper tensile disturbance zone of the folded strata, while it increases in the lower compressive disturbance zone. In the tensile disturbance zone, the maximum decrease in the horizontal principal stress gradient is approximately 0.3 MPa/hm, with the stress direction deflecting counterclockwise, reaching a maximum deflection angle of 70°. The greater the fold deformation curvature, the thicker the tensile disturbance zone, and the more significant the disturbance. Under fault-fold composite structures, the superposition of fault disturbance zones and fold tensile disturbance zones further reduces the magnitude of the in-situ stress. After offsetting the disturbance effects of both, the in-situ stress direction deviates less or does not deviate at all from the regional stress. Considering the difficulty of reservoir modification and the characteristics of tight gas enrichment, drilling should be prioritized in the overlapping areas of faults and fold tensile disturbance zones within the fault-fold composite structure zone. It is recommended that the drilling depth should not exceed the neutral plane of the folds, and the horizontal well trajectory should be designed along the EW direction.
Study on development mechanism and variability of strike-slip fault-controlled reservoirs regulated by multi-stage structural stress: a case study of the Shunbei area, Tarim Basin
ZHANG Jibiao, DENG Shang, HAN Jun, LI Yingtao, LIU Dawei, QIU Huabiao, ZHANG Zhongpei, LIU Yuqing
2024, 46(4): 775-785. doi: 10.11781/sysydz202404775
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The Shunbei oil-and-gas field in the Tarim Basin features a typical strike-slip fault-controlled fractured-vuggy reservoir. The formation of these reservoirs is primarily influenced by fracturing related to structural stress during periods of fault activity. This contrasts with reservoir types such as matrix vugs controlled by original sedimentary facies and caves modified by karst. To study the development mechanism and distribution patterns of strike-slip fault-controlled reservoirs under the influence of multi-stage structural stress, comprehensive analysis of field observations, core samples, well logging data, seismic surveys, and drilling dynamic data was conducted to characterize the development characteristics of fault-controlled reservoirs. This included different strike-slip faults, different parts along a single strike-slip fault, and different stratigraphic levels vertically. Combined with stress field numerical modeling, multi-stage structural stress recovery was carried out to predict the main development periods and distribution patterns of fault-controlled reservoirs. Significant variations in internal stress states were observed across different segments during periods of strike-slip fault activity. Tensile stress predominated in pull-apart segments, resulting in predominantly tensile fractures, whereas compressional stress state in push-up segments led to a variety of fracture types. The fault-controlled fractures in the top of the Yijianfang Formation in the Shunbei area were mainly developed during episode Ⅲ of the Middle Caledonian period and the Late Caledonian-Early Hercynian period. Few fractures were developed during the Middle to Late Hercynian period and thereafter. Compared to the Shunbei No.1 fault, the Shunbei No.18 fault exhibited higher fracture opening degree and density with a large displacement. Strike-slip fault-controlled reservoirs exhibit a cluster-like structure. Structural differences of the reservoirs are influenced by internal stress states in different segments during fault activity. Pull-apart segments typically feature a large fault core-damage zone with more cavities and 'double-cluster' structures, whereas push-up segments display more diverse fault core-damage zones with greater separability and 'multi-cluster' structures. The stress intensity during the strike-slip fault activity controls the types and scale of reservoir spaces, with smaller fault zones dominated by fractures and larger fault zones developing extensive fault core-damage zone architectures. The scale of fault-controlled reservoirs is positively correlated with fault activity intensity. Early fault activity promotes significant fracture development, while later stages, characterized by increased burial depths, result in few newly derived fractures due to reduced rock susceptibility to fracturing.
Three-dimensional physical simulation experiments on large-scale hydraulic fracturing in multi-thin interbedded tight sandstone reservoirs
FANG Maojun, DU Xulin, BAI Yuhu, LI Hao, ZHANG Hao, ZHU Haiyan
2024, 46(4): 786-798. doi: 10.11781/sysydz202404786
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The Linxing gas field on the northeastern edge of Ordos Basin is mainly composed of multi-thin interbedded tight sandstone reservoirs. These reservoirs feature complex lithologies and low permeability, and are affected by multiple factors with unclear mechanisms, leading to difficulties in hydraulic fracturing operations and significant variability in operation outcomes. Therefore, this study designed and conducted a series of large-scale three-dimensional (3D) physical simulation experiments of hydraulic fracturing under different geological conditions, focusing on different rock components, clay contents, particle sizes, sedimentary cycles, and planar and longitudinal heterogeneities of the tight sandstone reservoirs in the Linxing gas field. According to the similarity criteria, the basic parameters of the experiments were determined by referencing the triaxial geostress, rock strength, wellbore structural parameters, and on-site fracturing operational parameters of the Permian Shihezi Formation. Based on the characteristics of the main reservoirs in typical wells of the Linxing gas field, 15 cubic rock cores were produced to account for different rock components, clay contents, particle sizes, sedimentary cycle combinations, and planar and longitudinal heterogeneity combinations. Fifteen sets of hydraulic fracturing simulation experiments were conducted, and the main controlling factors affecting the propagation of hydraulic fractures were summarized by analyzing the injection pressure curves and observing the fracture surfaces of rock samples. The results indicate that rock minerals, particle sizes, sedimentary cycles, and planar and longitudinal heterogeneities have a significant impact on fracture propagation patterns in tight reservoirs. The fracture surfaces are more prone to buckling with larger sandstone particle sizes, weaker cementation, higher clay content, and stronger planar heterogeneity, increasing the expansion pressure and difficulty in sand addition. Sedimentary cycles facilitate hydraulic fractures to propagate along the cycle planes, resulting in horizontal fractures. The difficulty of breaking through in retrograde cycle interfaces is greater than in prograde cycles. Interfaces between sand and mud layers, sand and coal layers, and natural weak sandstone surfaces are easily activated, leading to "工" or "T" shaped fractures. A combination of "工", "T", and "十" shaped fractures may occur in sand-mud multi-thin interlayers. This experimental study reveals the propagation patterns of hydraulic fractures under different geological conditions, providing insights for research in similar blocks.
Characteristics and main controlling factors of structural fracture development in deep buried hill reservoirs of basement metamorphic rocks: a case study of B block, Bohai Bay Basin
SHI Ning, LIU Jingshou, ZHANG Guanjie, CHENG Qi, ZHANG Lei, LIU Wenchao
2024, 46(4): 799-811. doi: 10.11781/sysydz202404799
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Structural fractures are pivotal in enhancing the physical properties of buried hill reservoirs within basement metamorphic rocks, thereby increasing oil and gas productivity. However, there is limited comprehensive, multi-scale investigations into the development characteristics and main controlling factors of such fractures. Taking B block in the Bohai Bay Basin as a case study, this research systematically synthesized thin-section, core, and imaging logging data to delineate the characteristics of structural fractures in buried hill reservoirs within basement metamorphic rocks. This study identified the principal controlling factors and revealed the influencing factors and development patterns of these fractures. The study area mainly developed shear fractures, followed by tensile fractures, with lesser occurrences of oblique and vertical fractures. The fractures exhibited a high overall filling degree, primarily filled with mud followed by carbonate. Four groups of structural fractures in near-EW, NE-SW, NW-SE and NNW-SSE directions were identified. Among them, the near-EW fractures were more developed, indicating that the strong compressive environment during the early stage of Indosinian was crucial for widespread fracture development. The development of structural fractures in the study area was mainly controlled by rock mechanics properties, tectonic activity, weathering processes, reservoir physical properties, and lithology. The effectiveness of structural fractures was mainly controlled by factors including the angle between the maximum horizontal principal stress direction and the orientation of structural fractures, tectonic movement, fracture filling and dissolution. Vertically, the influence of weathering decreased with depth in buried hill reservoirs, with local development of dissolution pores along faults in the internal zones. Rocks with different mechanical properties showed different degrees of fracture development. Rocks with higher brittleness index exhibited higher degree of fracture development. Laterally, the line density of structural fractures in the core of the anticlines was greater than that in the flanks, providing favorable conditions for the development of structural fractures when reservoir porosity and permeability were within suitable ranges.
Fracture development characteristics and their influence on water invasion of ultra-deep tight sandstone reservoirs in Keshen gas reservoir of Kuqa Depression, Tarim Basin
XU Xiaotong, ZENG Lianbo, DONG Shaoqun, DIWU Pengxiang, LI Haiming, Liu Jianzhong, HAN Gaosong, XU Hui, JI Chunqiu
2024, 46(4): 812-822. doi: 10.11781/sysydz202404812
Abstract(79) HTML (54) PDF-CN(17)
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Natural fractures are crucial factors influencing productivity and water invasion in the ultra-deep tight sandstone gas wells of the Keshen gas reservoir in the Kuqa Depression, Tarim Basin. Research on fractures is significant for understanding water invasion patterns and formulating effective water control strategies. This study investigated the development characteristics, distribution patterns, and water invasion characteristics of effective fractures using core samples, thin sections, conventional logging, imaging logging, production data, and well testing, as well as the influence of different fracture networks on water invasion. High-angle and nearly vertical shear fractures are the main fracture types. Vertically, the first member of Bashijiqike Formation (K1bs1) is predo-minantly characterized by completely filled fractures, which are ineffective fractures. Conversely, the second and third members of Bashijiqike Formation (K1bs2 and K1bs3) are mostly characterized by partially filled and unfilled fractures, which are effective fractures. Horizontally, the NNW-SSE striking effective fractures are concentrated in the western part of the gas reservoir and have larger average apertures. The eastern part has relatively deve-loped nearly E-W and NWW-SEE striking effective fractures with smaller average apertures. The more deve-loped and the larger the aperture of the effective fractures, the lower the initial water production from gas wells, with more production of condensate water. From production onset to water breakthrough, formation water is produced in various forms: sealed water, condensate water, movable water and pure formation water. The development stage, aperture and orientation of effective fractures are important factors affecting heterogeneous water invasion. Dense, highly effective fracture networks that are nearly parallel to the orientation of water invasion will accelerate the water invasion speed, resulting in significant water production and severely reducing gas well productivity. Integrating the development characteristics of effective fractures with individual well water invasion dynamics reveals three types of water invasion: rapid channeling along faults or dense fractures, slow coning along sparse fractures and slow uplift and invasion of edge-bottom water.
Factors affecting the mechanical properties of tight sandstone and their patterns of variation in Cretaceous Bashijiqike Formation of Kuqa Depression in Tarim Basin
XU Ke, JU Wei, ZHANG Hui, LIANG Yan, YIN Guoqing, WANG Zhimin, XU Haoran, ZHANG Wei, LIANG Jingrui
2024, 46(4): 823-832. doi: 10.11781/sysydz202404823
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To clarify the mechanical characteristics of tight sandstone in the Cretaceous Bashijiqike Formation of Kuqa Depression in Tarim Basin, and address field issues in deep and ultra-deep oil and gas exploration and development, triaxial compression experiments were used to quantitatively study the patterns of changes in rock mechanical properties influenced by confining pressure, fluid, and loading rate, with a preliminary analysis of their causes. The results showed that the maximum principal stress difference and elastic modulus of the sandstone samples increased significantly with confining pressure. The micro-reason was that the increase in confining pressure reduced the distance between particles inside the rock, enhancing the rock's cohesion and making particle dispersion less likely. Sandstone samples exhibited a progression from brittleness under low confining pressure to brittle-ductile transformation, and to ductile deformation under high confining pressure. Compared with dry sandstone samples, the reduction in the elastic modulus of samples soaked in pure water, 150 g/L solution, 250 g/L solution, and 350 g/L solution were 67.71%, 61.45%, 64.69%, and 57.32%, respectively, with pure water soaking causing the greatest reduction. Increasing fluid salinity could mitigate the weakening trend in rock mechanical parameters. Crystallization on crystal surfaces and changes in the electric double layer thickness were important controlling factors for these patterns. At lower loading rates, the values for maximum principal stress difference, elastic modulus, and Poisson's ratio of the sandstone samples were smaller, but they increased faster with increasing loading rates. When the loading rate reached a certain critical value (around 0.05 mm/min in this experiment), the rate of increase in rock mechanical parameters slowed down.
Numerical simulation of mesoscopic deformation and failure for glutenite in Triassic Baikouquan Formation, Junggar Basin
HUANG Liuke, LIU Rui, HE Rui, MA Junxiu, TAN Peng, WANG Can
2024, 46(4): 833-844. doi: 10.11781/sysydz202404833
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Abstract:
The Triassic Baikouquan Formation glutenite in the Junggar Basin of western China is rich in tight oil resources. Due to the presence of gravels with varying composition and strength in the glutenite, the mechanical characteristics of the glutenite are significantly affected by the shape, size, and physical properties of the gravels, which in turn affects the fracture complexity and fracturing reconstruction effectiveness of the glutenite reservoirs. In view of this, a method for generating random irregular polygonal gravels was established based on the reservoir characteristics of Baikouquan Formation, Junggar Basin. A mechanical numerical model of the glutenite was created based on particle discrete element method to study the influence mechanism of typical gravel content and distribu-tion on the meso-mechanical characteristics of glutenite. The results show that low-strength gravels have a weak shielding effect on fracture propagation, with most cracks exhibiting a "penetrating gravel" pattern. In contrast, high-strength gravels exhibit a stronger shielding effect, leading to more "bypass gravel" fracture patterns. With increased confining pressure, the compressive strength of the rock significantly increases, along with peak strain energy and slip energy, both showing a linear increase with strain energy being particularly pronounced. In glutenite reservoirs with different gravel combinations, there is a strong linear relationship between the number of shear microcracks and the confining pressure. The glutenite reservoirs with high confining pressure and high-strength gravels exhibit more obvious plastic and ductile characteristics, along with evident secondary failure phenomena. With the decrease of low-strength gravels or the increase of high-strength gravels, the elastic modulus of the glutenite increases, enhancing its resistance to deformation. However, the influence of confining pressure on the elastic modulus of glutenite is minimal across different gravel combinations. The formation and development of macroscopic failure zones in glutenite are largely controlled by the internal meso-structure and are greatly affected by confining pressure and gravel type (mechanical strength).
Development characteristics and controlling factors of fractures in deep-buried tight oil reservoirs of the 3rd member of Paleogene Hetaoyuan Formation in southeast An'peng area, Nanxiang Basin
HUANG Zheng, ZHOU Yongqiang, HE Zixiao, LI Ming, YANG Tao, WANG Su, LI Qiang, ZHAO Ying, YIN Shuai
2024, 46(4): 845-854. doi: 10.11781/sysydz202404845
Abstract(55) HTML (27) PDF-CN(11)
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To elucidate the development patterns and influencing factors of natural fractures in deep-buried tight oil reservoirs, a comprehensive evaluation was conducted using a large amount of core samples, thin section, physical property data, imaging and conventional logging, water injection pressure testing and other data. The focus was on the tight oil reservoirs within the Ⅱ-Ⅵ oil layers of the third member of the Paleogene Hetaoyuan Formation in the southeastern An'peng area of the Biyang Depression, Nanxiang Basin. These oil formations, deposited in fan-delta front environment, are characterized by a high content of rock debris, indicating proximal deposition. A strong positive correlation between reservoir porosity and permeability was observed. Among the various sandstone lithologies, fractures predominantly developed in fine sandstone, followed by siltstone, while gravelly sandstone generally lacked fractures. High-angle and vertical fractures were predominant, constituting 87.8% of the total, while low-angle oblique and horizontal fractures accounted for 7.3% and 4.9%, respectively. The main controlling factors for fracture development in these tight reservoirs included lithology, depositional microfacies, and local structures. Thin and fine-grained single or composite sand bodies typically had more deve-loped fractures, particularly in front channel, channel flank, mouth bar, and outer edge of distal bars. Conversely, fractures were less developed in sheet sands or delta front microfacies. Moreover, fractures primarily formed at structural inflection points, predominantly at the tops and wings of forward structures and were primarily oriented along the WE and NE directions, followed by the NW direction. These fractures predominantly formed during the Neogene depression period (late Himalayan). Fractures significantly influence water channeling in tight oil reservoirs, necessitating enhanced dynamic and static monitoring of the degree, extent, and orientation of fracture development.
Prediction of fracture distribution in the Lower Jurassic Da'anzhai Member on the eastern slope of the Western Sichuan Depression, Sichuan Basin
XIE Runcheng, DENG Kun, ZHOU Guoxiao, LUO Ziwei, DENG Meizhou, LI Siyuan, MA Tingting
2024, 46(4): 855-867. doi: 10.11781/sysydz202404855
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The Da'anzhai Member of the Lower Jurassic on the eastern slope of the Western Sichuan Depression in the Sichuan Basin is a main target for the development of tight oil and gas. Fractures are essential for achieving high production in the Da'anzhai Member reservoirs. Due to their complex lithology, traditional methods for fracture prediction and evaluation have limited applicability and low prediction accuracy. Based on core fracture investigations and thin-section identification data, combined with geological statistics and numerical simulations, the lithological characteristics of various reservoirs were clarified, and the fracture development characteristics in the Da'anzhai Member were revealed. Considering both the fracture foundation and external fracturing forces, three fracture evaluation factors were proposed and constructed to predict and evaluate the planar distribution of fractures in each sub-member by distinguishing lithology and sub-members. The results showed that: (1) The Da'anzhai Member reservoirs had complex lithologies with interbedded (shell) limestone, sandstone, and shale. (2) Fully filled fractures were mainly developed, and (shell) limestone exhibited mainly structural fractures, while sandstone and shale mainly showed interlayer fractures with dissolution features on the fracture surfaces, which was beneficial for enhancing oil and gas flow. (3) Three fracture evaluation factors were proposed and constructed, which included lithologic thickness, tectonic deformation intensity, and fracture rupture intensity. A quantitative model for comprehensive prediction and evaluation of fractures was established to predict and evaluate the planar distribution of fractures in each sub-member comprehensively. The predicted fracture density aligned well with the fracture development index identified in individual wells, indicating the reliability of the prediction results. This method for fracture planar distribution prediction and evaluation offers a reference for similar oil and gas reservoirs.
Geomechanics modeling of ultra-deep fault-controlled carbonate reservoirs and its application in development
CAI Zhenzhong, ZHANG Hui, XU Ke, YIN Guoqing, WANG Zhimin, WANG Haiying, QIAN Ziwei, ZHANG Yu
2024, 46(4): 868-879. doi: 10.11781/sysydz202404868
Abstract(77) HTML (47) PDF-CN(19)
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To enhance the development efficiency of ultra-deep fault-controlled carbonate reservoirs, large-scale rock mechanical experiments were conducted to reveal the deformation and connectivity mechanisms of high-angle to near-vertical fault surfaces. Based on the mechanical and flow coupling principles of high-pressure water injection production, geomechanical modeling was employed to clarify the current in-situ stress field and fault activity distribution patterns in fault-controlled carbonate reservoirs. Significant differences were found in fault activities in different directions and in the connectivity of fracture and cavity bodies in different parts. The development effects of different wellbore trajectories were then analyzed, and an integrated geological and engineering working method was proposed to scientifically guide the design of wellbore trajectories and the optimization of water injection schemes. The results show: ① Large-scale fractured bodies and high-angle fracture systems in strike-slip fault deformation are key factors affecting reservoir quality. High-pressure water injection can activate existing fractures on one hand, and on the other hand, it can extend and expand based on existing fractures, even generating new fractures, promoting the interconnection of fault-controlled fracture and cavity bodies in both vertical and horizontal directions; ② During the high-pressure water injection process, coupling changes between mechanics and flow occur inside the fault body, improving the seepage environment, and increasing oil and gas recovery rate through cyclic lifting; ③ According to the shape and the occurrence of the fault body, and the dynamic shear deformation connectivity of the fault surface, the best well point and well trajectory for directional wells can be selected, and the water injection scheme can be optimized; ④ In the fault-controlled oil reservoir test area of Tarim Basin, the recovery rate was increased by 5% through high-pressure water injection. This method provides a good theoretical basis and technical support for the efficient development of ultra-deep fault-controlled reservoirs.
Quantitative division method of geomechanical strata and its applications in exploration and development of oil and gas in ultra-deep layers
JU Wei, ZHANG Hui, XU Ke, NING Weike, XIANG Ru
2024, 46(4): 880-888. doi: 10.11781/sysydz202404880
Abstract(177) HTML (72) PDF-CN(36)
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Efficient exploration and development of ultra-deep oil and gas reservoirs are key objectives in current global energy geological research. The concept of "geomechanical strata and oil and gas exploration and development" represents a cutting-edge research area internationally. Establishing an effective method for dividing geomechanical layers holds both theoretical and practical significance for the efficient exploration and economical development of ultra-deep oil and gas reservoirs. Currently, the state of in-situ stress affects the effectiveness of natural fractures, while the development and distribution of fractures impact the mechanical properties of rocks, which influence the the distribution of in-situ stress. However, the existing "rock mechanical stratigraphy theory" fails to comprehensively cover the coupling relationships among these three factors. In response, this study introduced a method for the quantitative division of geomechanical strata based on six parameters: minimum horizontal principal stress, difference in horizontal stress, elastic modulus, angle between the current dominant stress orientation and the natural fracture orientation, natural fracture density, and stress concentration factor. An analysis of well W in the Dabei area of the Kelasu structural belt, Kuqa Depression, Tarim Basin, demonstrated that the target layers at the Cretaceous Bashijiqike Formation exhibited strong vertical geomechanical heterogeneity. The geomechanical strata of the reservoir correlated well with the development sections of the gas layers. Therefore, with the results of geomechanical strata division, it is possible to guide the optimization of sweet spots in ultra-deep oil and gas reservoirs.
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