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    01 February 2025, Volume 46 Issue 1 Previous Issue    Next Issue
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    OIL AND GAS EXPLORATION
    In-situ Stress Characteristics and Fracture Distribution Prediction of Different Segments in Shunbei No.4 Strike-Slip Fault Zone, Tarim Basin
    HUANG Chao, GUO Honghui, ZHANG Shenglong, ZHU Lintao, FENG Jianwei, DU He
    2025, 46 (1):  1-12.  doi: 10.7657/XJPG20250101
    Abstract ( 233 )   HTML ( 13 )   PDF (4213KB) ( 237 )   Save

    Based on the development background of the strike-slip fault zone in the Shunbei area of the Tarim Basin, the in-situ stress states, the fracture systems around faults, and the well productivity characteristics in different segments of the Shunbei No.4 strike-slip fault zone were analyzed by using geomechanical theories. According to the reservoir mechanical properties obtained through P-wave and S-wave logging and rock mechanics experiments, a 3D geomechanical model was constructed. Based on the elastoplastic theory, and by using the finite element numerical simulation method, the fracture development characteristics of the target layer controlled by the strike-slip faults were predicted. The research results show that the in-situ stress patterns vary across segments in the fault zone. The differences in structures of geological units control the in-situ stress distribution, and regions with high fracture density typically exhibit a strip-like distribution on both sides of the fault or between faults. High fracture density combined with Anderson-type Ⅰa and Ⅲ stress states is associated with wells exhibiting high yields. The in-situ stress conditions, fracture development characteristics, and key factors controlling high well productivity in different segments in the Shunbei strike-slip fault zone were clarified.

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    Mineral Features of Chlorite and Laumontite and Their Impacts on Reservoir Physical Properties: A Case Study of Lower Wuerhe Formation in Western Luliang Uplift, Junggar Basin
    NIU Jun, WANG Cong, LIANG Fei
    2025, 46 (1):  13-21.  doi: 10.7657/XJPG20250102
    Abstract ( 165 )   HTML ( 16 )   PDF (19298KB) ( 74 )   Save

    In order to enhance the understanding of mineral features of chlorite and laumontite in the lower Wuerhe formation of Permian in the western Luliang uplift, Junggar Basin, the chemical composition, occurrence states, and impacts on reservoir physical properties were studied by means of thin section, electron probe and X-ray diffraction. It is found that the chlorite has an trioctahedral crystal structure and occurs in three states: pore lining, particle coating, and pore filling. It is classified as an iron-magnesium transitional type, richer in magnesium. Fe replacing Mg mainly occurs in the octahedrons, with the Al/(Al+Mg+Fe) ratio ranging from 0.25 to 0.37. The forming of chlorite is attributed to the alteration of argillaceous rocks and the transformation of mafic rocks, with substantial material input from the hydrolytic dissolution of tuffaceous volcanic materials and the interconversion of clay minerals. Laumontite occurs in three states: crystal aggregate, filling, and replacement. The laumontite in crystal aggregate state is surrounded by numerous debris, which promotes the formation of laumontite. The laumontite in filling state coexists with chlorite, calcite and other minerals, which compete with them for material sources, partially inhibiting the formation of laumontite. The laumontite in replacement state is mainly formed by the replacement of feldspar and debris, resulting in high Si/Al ratio and good acid resistance, which allow the laumontite to be not easily dissolved. Chlorite and laumontite have dual effects on reservoir physical properties. Chlorite can significantly improve reservoir physical properties, resulting in the formation of high-quality reservoirs. In contrast, the effect of laumontite on reservoir properties is limited. With the increase of burial depth, the lower Wuerhe formation presents a variation in diagenetic environment from alkaline to weakly acidic and then to alkaline, with a relatively closed diagenetic system.

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    Shale Reservoir Brittleness and Its Evaluation Method
    ZHAI Yong, GUO Yaning, DING Yi, LI Yishan, CUI Yinuo, LI Bin, LIU Xiangjun
    2025, 46 (1):  22-28.  doi: 10.7657/XJPG20250103
    Abstract ( 157 )   HTML ( 11 )   PDF (1823KB) ( 124 )   Save

    Shale oil and gas resources are abundant in China, and hydraulic fracturing to stimulate reservoir is a significant way to efficiently develop these resources. Brittleness is a key parameter for reservoir stimulation and a core indicator for identifying engineering sweet spots. Taking the shale reservoir in the Dongying sag as an example, the rock mechanical properties and brittleness characteristics of the shale reservoir were analyzed through uniaxial, triaxial, and high-temperature, high-pressure (HTHP) compressive tests. Based on the rock energy balance theory and brittleness characteristics, as well as the energy evolution behaviors before and after rock failure, a new method for evaluating shale brittleness was proposed. The research results show that under uniaxial conditions, the shale exhibits significant brittle failure with multiple cracks, which is beneficial for reservoir stimulation. In HTHP conditions, the synergistic effect of temperature and confining pressure suppresses rock brittle fracture but strengthens rock ductility, leading to a significant reduction in brittleness. Based on the proposed brittleness evaluation method, the primary factors controlling shale brittleness were identified. It is found that the rock physical parameters (porosity, density, and acoustic travel time) is weakly correlated with brittleness, while mineral composition and elastic parameters are more effective in assessing brittleness. The effects of temperature and pressure cannot be ignored. The research results are conductive to identifying engineering sweet spots in shale reservoirs and provide a theoretical foundation for efficient reservoir stimulation.

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    Lower Limits of Physical and Electrical Properties of Low to Ultra-Low Permeability Gas Reservoirs
    HU Xiangyang, WU Jian, YANG Dong, ZHANG Heng, TAN Wei, YUAN Wei
    2025, 46 (1):  29-38.  doi: 10.7657/XJPG20250104
    Abstract ( 122 )   HTML ( 5 )   PDF (3825KB) ( 123 )   Save

    The low to ultra-low permeability reservoirs in the DF A and WC X/Y blocks, western South China Sea, are characterized by complex microscopic structures, making it difficult to understand the lower limits of reservoir physical and electrical properties. Through core single-phase displacement experiments under various pressure differences, and core capillary pressure-lithoelectric experiments at high temperature and high pressure, the lower limits of porosity, permeability, saturation, and resistivity of these low to ultra-low permeability gas reservoirs were examined. On this basis, the variations of the lower limits of these reservoir properties were discussed. The results show that the cores obtained from the gas reservoirs in the DF A block have the physical properties which are positively correlated with gas flow rate, and the cores from the ultra-low permeability gas reservoirs in the WC X/Y block exhibit very low gas flow rate, which couldn’t be improved significantly as the pressure difference was increased. In the presence of irreducible water, as the differential pressure for production increased, the lower limits of porosity and permeability of cores from both blocks declined gradually. As the physical properties of the reservoirs improved, the upper limit of water saturation became lower. As the reservoir physical properties improve, the cores from the DF A block demonstrated an increasing lower limit of resistivity, while the cores from the WC X/Y block reflected a decreasing lower limit. It is supposed that the reason should be attributed to different pore structures and fluid occurrence states of the reservoirs.

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    Architecture Characterization of Sandy Braided River Reservoirs: A Case Study of Guantao Formation in Western Block 7 of Gudong Oilfield
    DU Juan, YIN Yanshu, WEN Bin, REN Li, WU Wei
    2025, 46 (1):  39-47.  doi: 10.7657/XJPG20250105
    Abstract ( 169 )   HTML ( 7 )   PDF (1124KB) ( 87 )   Save

    The sublayers from N1g45 to N1g16 of the Guantao formation in western Block 7 of the Gudong oilfield are typical of braided river deposits, with complex internal sandbody architectures. A detailed analysis of the reservoir architecture is necessary to understand its impact on oil and gas development. By using the Miall’s architectural element analysis method, and constrained by modern braided river scale, the sandbody architecture was characterized. Combining dynamic and static methods, the reservoir architectures were validated, and their influences on waterflood performance and residual oil distribution were identified. The research results show that the study area exhibits sandy braided river deposits, mainly with four sedimentary architecture units: braided river channels, mid-channel bars, overbanks, and floodplains. The braided flow zone is 150-750 m wide, with a width-to-thickness ratio ranging from 47 to 74. Within the braided flow zone, there are four types of architectural patterns: braided river channel-braided river channel, mid-channel bar-mid-channel bar, braided river channel-mid-channel bar-braided river channel, and mid-channel bar-braided river channel-mid-channel bar. The mid-channel bars have average length of 250-350 m and average width of 110-140 m, with a length-to-width ratio of 2.20-2.50. The ratio of mid-channel bar area to channel area ranges from 0.36 to 0.51. The mid-channel bars typically develop 2-4 fall-silt seams with their extension ranging from 70 to 150 m, which are nearly horizontal, with interlayer dip angles between 0.9° and 2.3°. Production performance reveals that due to poor petrophysical properties at the edges of architecture units, oil and gas flows are impeded at the architectural junctions where residual oil will be enriched locally. In contrast, the main parts of the architecture units show good reservoir connectivity and development effects.

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    Grading Evaluation of Jurassic Ultra-Deep Tight Sandstone Reservoirs in Yongjin-Zhengshacun Area, Junggar Basin
    WANG Chunwei, YANG Jun, ZHAO Dongrui, DU Huanfu, SUN Xin, WANG Yelei, MENG Fanghua
    2025, 46 (1):  48-56.  doi: 10.7657/XJPG20250106
    Abstract ( 143 )   HTML ( 6 )   PDF (5722KB) ( 138 )   Save

    The Jurassic ultra-deep sandstone reservoirs in the Yongjin-Zhengshacun area of the Junggar Basin are tight and heterogeneous, and the standards for evaluating these reservoirs and the favorable reservoir distribution are unclear, restricting oil and gas exploration and development. Based on well logging, coring, and testing data, and by using mineral analysis, nuclear magnetic resonance (NMR), capillary pressure experiments, and core displacement tests, a study was conducted on the pore structure of the Jurassic reservoirs. The lower limit of movable pore radius was determined, and a grading evaluation standard was established with movable fluid porosity as the key indicator. The results show that the reservoir space in the medium- to fine-grained lithic and feldspathic sandstones is composed of intergranular pores, secondary dissolution pores, and microfractures, with small pore radii ranging from 0.005 to 5.000 μm. After calibrating the experimental capillary pressure curves, the lower limit of movable pore radius was determined as 0.100 μm through the NMR T2 spectrum at different displacement states, and then the movable fluid porosity of oil-bearing rocks was clarified. By comprehensively considering the lithoelectric characteristics, pore type and structure, and oil-bearing property, and combining the productivity characteristics of typical wells, a grading reservoir evaluation standard for the study area was established. Based on the standard the reservoirs were classified into Class Ⅰ, Class Ⅱ, and Class Ⅲ. The evaluation provides a basis for subsequent oil and gas field development and well deployment, and offers valuable insights for the exploration and development of ultra-deep tight oil reservoirs in the study area and for reservoir evaluation in neighboring areas.

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    RESERVOIR ENGINEERING
    Identification and Productivity Prediction of High-Quality Reservoirs in the Metamorphic Buried Hills of the Bozhong 19-6 Structure
    TAN Zhongjian, GUO Kangliang, WU Liwei, ZHANG Guoqiang, LI Hongru, DENG Jinhui, BI Hongri
    2025, 46 (1):  57-63.  doi: 10.7657/XJPG20250107
    Abstract ( 142 )   HTML ( 4 )   PDF (3783KB) ( 105 )   Save

    In the Bozhong 19-6 structure, fractures serve as the primary flow channels and storage spaces in the metamorphic buried-hill reservoirs, significantly controlling the formation of high-quality reservoirs and well productivity. To accurately identify high-quality reservoirs in the Bozhong 19-6 structure and predict their productivity, fractures were quantitatively characterized using thin sections, imaging logs, and other data. Based on the division of vertical structural units within the buried-hill reservoirs, high-quality reservoirs in the target intervals were identified using conventional mud log, wireline and imaging logging data. The reservoirs were finely evaluated by introducing fracture development index and comprehensive index methods and then a comprehensive method for identifying high-quality reservoirs was established. By substituting the effective thickness and fracture parameters of the high-quality reservoir into productivity evaluation equation, the gas layer productivity of the target intervals was calculated and compared with the test results. It is found that the relative error between the predicted productivity index per meter and the actual productivity values is less than 15%, which indicates a high feasibility of this comprehensive evaluation method in identifying high-quality reservoirs in metamorphic buried hills. This study offers a guidance for oil and gas development in the metamorphic buried hills in the Bozhong 19-6 structure.

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    Formation Heat Variation Pattern During Cyclic Steam Stimulation
    YAO Changjiang, JIA Xinfeng, SHANG Ce, LI Kehan, JIAO Binhai, GAO Fei, LIN Zhiqiang
    2025, 46 (1):  64-70.  doi: 10.7657/XJPG20250108
    Abstract ( 137 )   HTML ( 6 )   PDF (639KB) ( 59 )   Save

    Heating formation to reduce crude oil viscosity is one of the main mechanisms of cyclic steam stimulation (CSS). A dynamic heat transfer model considering both thermal convection and thermal conduction was established. Coupling temperature and pressure fields, this model was used to determine formation pressure, formation temperature, and fluid convection velocity, so that the dynamic variation of formation heat was analyzed. The research results show that, in the steam injection stage, given the same cyclic steam injection volume, higher heating rates and net heat are achieved when the injection duration is 6.0-10.0 days. In the soaking stage, when the pressure stops rising, thermal convection weakens rapidly, and formation heating rate significantly decreases, with an 88.3% drop in heating rate after 4.0 days of soaking, allowing for well production. In the production stage, thermal conduction becomes the dominant mechanism, and the formation heat increases slowly and steadily. After one cycle of CSS, 57.7% of the incremental heat is recovered with the produced fluid, while 42.3% remains in the formation. This study provides a deeper understanding of the formation heat variation during CSS, which supports the optimization of injection-production parameters and the analysis of steam heat flow.

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    Water Invasion Characteristics and Stable Production Strategies in Kelasu Ultra-Deep Gas Field, Kuqa Depression
    LIU Liwei, ZHOU Hui, YAN Bingxu, JIAO Yuwei, QU Yuanji, JIN Jiangning, PAN Yangyong
    2025, 46 (1):  71-77.  doi: 10.7657/XJPG20250109
    Abstract ( 125 )   HTML ( 8 )   PDF (18385KB) ( 48 )   Save

    The Kelasu ultra-deep gas field in the Kuqa depression of the Tarim Basin is challenged by severe water invasion, leading to rapid decline in production. Through analysis on surface seismic data and imaging logging data, the distribution patterns of faults and fractures were determined. Combining with the production performance of the gas field, three types of water invasion were identified in the Kelasu ultra-deep gas field: fault-communicated edge or bottom water, non-uniform water invasion along fractures, and occluded water invasion due to locally incomplete displacement. The former two types are dominant in the gas field. The three types differ significantly in characteristics and influence range. On one hand, the ability to communicate with edge or bottom water along the trend of second-order faults and vertically is strong, but water invasion perpendicular to the trend of faults has a minor, localized impact. On the other hand, fractures are oriented and distributed regularly, showing a feature of “zones generally and belts locally”. The differences in the internal connectivity of the gas reservoir, the order and the speed of water invasion in the gas reservoir are the external manifestations of the division and zonation of fractures, which have a global effect on water invasion in the gas reservoir. Considering the water invasion characteristics and development status of the gas field, strategies were proposed to optimize well pattern according to spatial distribution of fractures, and to strengthen researches on two supporting gas production technologies: chemical water plugging and gas injection to alleviate water lock.

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    Geological Characteristics and Development Technologies of Shale Gas Field in Anchang Area, Guizhou Province
    LIU Honglin, LU Dan, LIANG Feng, HE Xinbing, LI Gangquan, ZHAO Qun, BAI Wenhua
    2025, 46 (1):  78-87.  doi: 10.7657/XJPG20250110
    Abstract ( 120 )   HTML ( 1 )   PDF (3888KB) ( 99 )   Save

    The shale gas field in Anchang area in the northern part of Guizhou province is primarily producing from the shales in the Wufeng formation to Longmaxi formation. This gas field is characterized by a source-reservoir integrated system in stable distribution and self-generation and self-storage pattern, and it is classified as a shallow mountainous shale gas field under normal pressure. From top to bottom, the gas-bearing layers show an increasing content of siliceous minerals and a decreasing content of clay minerals. The shale reservoir space primarily consists of nanometer-scale organic pores, followed by residual intergranular pores, intercrystalline pores, secondary dissolution pores, and clay mineral interlamellar pores. The gas wells generally exhibit low flowback rates upon gas breakthrough, slow production decline, and long stable production period. Considering the geological and developmental characteristics of this type of gas reservoir, it is important to enhance detailed geological modeling and fracturing design optimization, as well as to moderately expand well spacing. Given the presence of faults and strong heterogeneity, integrated geological and engineering design should be strengthened, and the 3D reservoir geological model should be iteratively optimized to establish an accurate shale gas reservoir model. In view of the large differential horizontal stress ratios and the difficulty in forming complex fracture networks, fracturing stage length and cluster spacing should be optimized, and multi-cluster fracturing and fracture diversion techniques can be implemented. For low reservoir pressure, fast decline in wellhead pressure, and low gas production, the flowback management system in the gas testing stage should be further optimized.

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    Occurrence State of Water in Ultra-Low Permeability Gas Reservoirs and Its Impact on Development of A Gas Field
    LIAO Hengjie, LOU Min, HE Xianke, DUAN Dongping, WANG Wenji, LI Yuansheng, LIU Binbin
    2025, 46 (1):  88-96.  doi: 10.7657/XJPG20250111
    Abstract ( 135 )   HTML ( 4 )   PDF (895KB) ( 76 )   Save

    Ultra-low permeability gas reservoirs are complex in gas-water contact, and differ significantly in formation water occurrence state from conventional gas reservoirs. The occurrence state of formation water and the water saturation in such reservoirs were determined through mercury intrusion experiments and relative permeability tests, and the gas-water segregation was analyzed using the trap closure height method. Logging curves were used to predict the distribution of formation water saturation in different states for a single well, and the impact of formation water on productivity was assessed. The results show that the formation water in the study area mainly consists of strongly bound water and weakly bound water, with a small amount of movable water. No distinct gas-water segregation was observed. The clay water film is a key component of strongly bound water. In fine sandstone and the sandstone with high content of carbonate cements, the saturation of weakly bound water is higher. The movable water saturation in the study area is generally less than 6%, and the initial water production is low, exerting slight impact on productivity.

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    APPLICATION OF TECHNOLOGY
    A Method for Optimizing Depth Domain Velocity Inversion
    LI Jiwei, LI Guangpeng, DU Jiajun, FENG Rongchang, DUAN Xiaoxu
    2025, 46 (1):  97-104.  doi: 10.7657/XJPG20250112
    Abstract ( 121 )   HTML ( 2 )   PDF (10898KB) ( 30 )   Save

    Seismic data from piedmont areas typically suffers from low signal-to-noise ratio (SNR), making it challenging to pick residual velocity fields and causing difficulties in iterative convergence of the depth domain velocity field to its optimal value. All these factors impede accurate migration and imaging of the seismic data from piedmont areas. By using the interpolation techniques in five-dimensional data regularization, the data from the original common midpoint (CMP) gathers prior to migration were reconstructed. By altering observation system, the bin attributes were enhanced to improve the SNR of the seismic data for iterative inversion of the pre-stack depth migration (PSDM) velocity field. To ensure the fidelity of the migrated data, the high-SNR CMP gathers obtained from data interpolation were used solely as inputs for the iterative inversion of the depth domain velocity field, while the original CMP gathers were preserved for the final PSDM imaging. This method enables fast and accurate iterative convergence of the depth domain velocity field. The actual application demonstrates that the method is highly feasible, and yields accurate final migrated velocity field through iterative updates and well-aligned reflections of migrated seismic profiles. This method provides a valuable reference for PSDM velocity modeling in the piedmont areas.

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    Experimental Study on Oil Displacement Efficiency by Different Fluids in Low-Permeability Sandstone Reservoirs
    CHEN Chao, YAN Xiaolong, LUO Xiaojing, ZHEN Yanming
    2025, 46 (1):  105-113.  doi: 10.7657/XJPG20250113
    Abstract ( 126 )   HTML ( 2 )   PDF (1769KB) ( 80 )   Save

    In the middle-late stage of waterflood development in low-permeability sandstone reservoirs in the eastern margin of the Junggar Basin, the development performance deteriorates, and the water cut increases, necessitating new effective development techniques. Different fluids were selected for oil displacement efficiency experiments. Using long cores and under simulated formation conditions, oil displacement experiments were performed for waterflooding and gas flooding with N?, CH?, and CO? after waterflooding till achieving the current recovery efficiency of the reservoir. Nuclear magnetic resonance scanning and oil-containing pore size inversion were conducted on cores before and after injection of different fluids. The results show that CO? flooding can increase the recovery factor by 21.58%. The fluids rank as CO?, CH?, H?O, and N? in a descending order of oil displacement efficiency and producing degree. N? flooding primarily recovers oil from larger pores, with the lower limit of pore size being 170.9 nm. CH? flooding primarily mobilizes oil from medium to large pores, with the lower limit of pore size being 48.7 nm. CO? flooding can extract oil from pores of all sizes, with the lower limit of pore size being 27.8 nm, the lowest level among the processes tested. A CO? flooding pilot test zone was established in the oilfield. After CO? injection, the liquid production increased, the water cut decreased, and the oil production improved, suggesting good field application.

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    Laboratory Experiments and Field Tests of CO2 Near-Miscible Flooding for Medium-Viscosity Oil in NJH Block, Santanghu Oilfield
    ZHANG Qi, ZHU Yongxian, HAN Tianhui
    2025, 46 (1):  114-120.  doi: 10.7657/XJPG20250114
    Abstract ( 107 )   HTML ( 2 )   PDF (655KB) ( 55 )   Save

    The NJH block of the Santanghu oilfield features sandstone reservoirs containing medium-viscosity oil, with crude oil viscosity of 20.8 mPa·s. The reservoir is at medium water cut stage, with a predicted waterflood recovery factor of 22.70%, leaving a limited potential for further enhanced oil recovery. To figure out an applicable enhanced oil recovery (EOR) technique, laboratory experiments and field test were conducted on CO2 near-miscible flooding for medium-viscosity oil to understand the mass transfer patterns and EOR mechanisms of this technique, thereby determining its feasibility. The research results show that the front of the CO2 flooding mainly plays a swelling effect, and the rear exerts a stronger extraction effect than the front. Reducing the viscosity and improving the remaining oil displacement efficiency are the main stimulation mechanisms. The viscosity of surface crude oil reduced by 55%, the content of C2-C15 components increased by 18.3%, and the displacement efficiency improved by 4.6 times. Permeability ratio is found to be the primary factor influencing swept volume, with a permeability ratio of 6, leading to a recovery factor of only 13.84% in low-permeability layers. During the field test, the cumulative injected gas volume is 2.66×104 t, cumulative oil production is 0.78×104 t, and oil exchange ratio is 0.29, confirming a promising application of CO2 near-miscible flooding for medium-viscosity oil.

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    Effectiveness Evaluation of Tight Sandstone Reservoirs Based on NMR Logging
    MU Qian, LI Gaoren, ZHANG Wenjing, CHI Ruiqiang
    2025, 46 (1):  121-126.  doi: 10.7657/XJPG20250115
    Abstract ( 150 )   HTML ( 5 )   PDF (786KB) ( 78 )   Save

    In the Zhijing-Ansai area of the Ordos Basin, the reservoirs in the 8th and 9th members of the Upper Triassic Yanchang formation (Chang 8 and Chang 9 members) are tight, with complex pore structure and unclear vertical distribution of effective reservoirs. A method for evaluating the effectiveness of the tight sandstone reservoirs was proposed based on nuclear magnetic resonance (NMR) logging data and mercury injection data of rock samples. For wells with NMR logging data, the proportions of macropores, mesopores, and micropores can be directly obtained from the NMR data, and an NMR logging-based three-pore component index can be constructed. For wells without NMR logging data, the pore throat radius index can be established by using the relationship between NMR transverse relaxation time and pore throat radius. Both the NMR logging-based three-pore component index and the pore throat radius index can quantitatively characterize the pore structure of tight sandstone reservoirs. Integrating with analysis of formation test data, it is found that single-well liquid production index per meter is positively correlated with pore structure. Thus, an effectiveness evaluation standard for tight sandstone reservoirs was established. The application of this standard to the Chang 8 and Chang 9 members in the Zhijing-Ansai area demonstrates excellent results, with significantly improved accuracy of well logging interpretation.

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