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Exploration Progress and Potential Evaluation of Deep Oil and Gas in Turpan-Hami Exploration Area ZHI Dongming, LI Jianzhong, CHEN Xuan, YANG Fan, LIU Juntian, LIN Lin Xinjiang Petroleum Geology    2023, 44 (3): 253-264.   DOI: 10.7657/XJPG20230301 Abstract （562）   HTML （541）    PDF（pc） （2522KB）（1173）       Knowledge map    Save To realize the shift of oil and gas exploration from shallow-middle to deep strata, and from conventional to unconventional resources, and then to promote the exploration of deep oil and gas resources in the Turpan-Hami exploration area, the tectonic-lithofacies palaeogeographical evolution of Turpan-Hami basin, Santanghu basin, and Zhundong block of Junggar basin were analyzed, the characteristics and exploration potential of the petroleum systems in these basins were evaluated, the main exploration targets were determined, and the fields for strategic breakthrough were selected. In the Carboniferous-Permian period, the Turpan-Hami exploration area was a unified sedimentary basin with similar sedimentary environments and structures. In the Triassic-Jurassic period, the study area was separated into several independent foreland basins. With the tectonic-lithofacies palaeogeographical evolution, three sets of source rocks (marine-transitional facies of Carboniferous, lacustrine facies of Permian, and lacustrine-coal measure of Jurassic) were formed, contributing to three major petroleum systems. The change in exploration ideas has promoted significant progress in petroleum exploration in deep strata. Significant breakthroughs have been made in the exploration of Shiqiantan formation marine clastic oil and gas reservoirs, Permian shale oil reservoirs and conventional sandstone oil reservoirs in the Zhundong block, and the Middle-Lower Jurassic large-scale tight sandstone gas reservoirs in the Turpan-Hami basin, which enables the discovery of large-scale high-quality reserves and the orderly succession of strategic resources. Future exploration should be carried out at three levels: strategic preparation, strategic breakthrough, and strategic implementation, with a focus on 10 favorable directions. Table and Figures | Reference | Related Articles | Metrics

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A Calculation Method of Bottomhole Flowing Pressure in Coalbed Methane Wells With Double-Layer Commingled Production in Gas-Water Co-Production Stage ZHANG Peng, ZENG Xinghang, ZHENG Lihui, ZHANG Jihui, WANG Xiangchun, PENG Xiaojun Xinjiang Petroleum Geology    2023, 44 (4): 497-509.   DOI: 10.7657/XJPG20230415 Abstract （237）   HTML （3）    PDF（pc） （845KB）（1068）       Knowledge map    Save Bottomhole flowing pressure (BHFP) is a key factor determining the rational production system of coalbed methane (CBM) wells for purpose of long-term stable production. The constant mass model (CMM) is not applicable to the wells with double-layer commingled production, since it does not consider the acceleration pressure drop (APD) in the reservoir interval and the mass variation in well sections. Additionally, the BHFP in the lower reservoir is taken as a control parameter for the two intervals, which does not meet the adjustment requirements of the upper reservoirs. In this paper, the APD expression was decomposed and derived, the relationship between APD and the radial flow rate per unit length was established, and the pressure drop formula for the reservoir interval with radial inflow was derived. The reservoir was divided into multiple intervals, and the pressure drop calculation method for each interval was established. Based on the gas/water flow rates in each well section, the corresponding equations for calculating gas/water phase velocities were derived. Combining the above equations, a variable mass model (VMM) was established. The production data were input into the VMM and CMM for comparative verification. The results show that when gas and water are co-produced, the error of the VMM is 2.75%-6.58%, while the error of the CMM is 7.15%-15.18%, indicating that the VMM is more accurate. The BHFP differs significantly in the two reservoir intervals, with the maximum difference of 47.3%. Therefore, it is necessary to adjust the production system depending upon the respective BHFP of the two reservoirs. The VMM can accurately provide BHFP for each commingled interval, so it agrees more with the field conditions. It also avoids the problem of using the same BHFP for both intervals, which hinders precise adjustment of the production system. Thus, the new model provides a technical support for developing optimal production strategies and achieving high and stable production. Table and Figures | Reference | Related Articles | Metrics

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Architecture of Shallow-Water Delta Reservoir of Huagang Formation in C Oilfield，Xihu Sag HE Xianke, LOU Min, CAI Hua, LI Bingying, LIU Yinghui, HUANG Xin Xinjiang Petroleum Geology    2023, 44 (5): 517-527.   DOI: 10.7657/XJPG20230502 Abstract （284）   HTML （13）    PDF（pc） （7528KB）（873）       Knowledge map    Save In order to improve the accuracy of reservoir characterization for purpose of tapping the potential of remaining oil in the middle to late oil and gas field development stage, taking the shallow-water delta reservoir of the Huagang formation in C oilfield, Xihu sag, as an example, the reservoir architecture was investigated by using core, grain size, logging, and seismic data. The architecture patterns of composite channel sandbodies of shallow-water delta facies were established, and their spatial evolution was clarified. The results show that the H3c layer represents the upper plain-channel deposit of shallow-water-delta facies, which is dominated by vertically stacked thick sandbodies; the H3b layer represents the lower plain-channel deposit of shallow-water delta facies, in which laterally-migrated medium-thick sandbodies are developed; and the H3a layer represents the shallow-water delta-front deposit, which is featured with isolated thin sandbody. The development of vertical sandbodies was controlled by middle-term base-level cycle. As the lake level rose, the shallow-water delta in the study area formed a retrogradational sequence, and sandbodies evolved from sheet-like to isolated belt-like, resulting in deteriorating reservoir connectivity. Table and Figures | Reference | Related Articles | Metrics

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Secondary Development of Mature Oilfields in China: Current Status and Prospects FU Yarong, DOU Qinguang, LIU Ze, JIAO Lifang, JI Yuxi, YANG Yajuan, YIN Houfeng Xinjiang Petroleum Geology    2023, 44 (6): 739-750.   DOI: 10.7657/XJPG20230613 Abstract （375）   HTML （8）    PDF（pc） （792KB）（747）       Knowledge map    Save The secondary development of mature oilfields with high water cut is a revolution in the history of oilfield development and also a strategic systematic project. It plays an irreplaceable role in maintaining long-term stable oil production. From the aspects of intelligent decision-making, intelligent planning, intelligent operation, intelligent monitoring, and intelligent evaluation, and within the framework of the policies for carbon peaking and carbon neutrality, the prospects for the secondary development of mature oilfields in China were discussed. It is indicated that the secondary development of mature fields should be implemented by reconstructing underground understanding system, well pattern, and surface process, and technically by way of overall control, stratigraphic subdivision, plane reorganization, three-dimensional optimization, and deep profile control, ensuring the smooth integration of secondary development and tertiary development. Reference | Related Articles | Metrics

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Exploration Practice and Total Petroleum System in Residual Marine Sag，Eastern Junggar Basin ZHI Dongming, CHEN Xuan, YANG Runze, LIU Juntian, YU Haiyue, MA Qiang Xinjiang Petroleum Geology    2024, 45 (2): 127-138.   DOI: 10.7657/XJPG20240201 Abstract （327）   HTML （38）    PDF（pc） （6277KB）（710）       Knowledge map    Save The Shiqiantan sag in the eastern Junggar basin is a residual marine sag. In recent years, high-yield natural gas have been obtained from many wells in the Shiqiantan formation, and oil and gas shows have been observed in different strata across the sag, indicating its excellent exploration potential and characteristics as a total petroleum system. Based on seismic, drilling, logging, and organic geochemical data, the formation and evolution of the Shiqiantan sag, the conditions for the formation of the total petroleum system, and the models of hydrocarbon accumulation are studied. The results show that during the Late Carboniferous the north Tianshan oceanic crust subduction and seawater intrusion in the region led to the development of terrigenous, marine, medium- to high-quality source rocks which are now in the mature- to high-mature stage. The reservoir contains volcanic rocks in the Carboniferous strata, marine clastic rocks in the Shiqiantan formation, and continental clastic rocks in the Permian Jingou formation, in all of which hydrocarbons were accumulated. Controlled by the hydrocarbon generation and evolution in the source rocks of the Shiqiantan formation and the characteristics of multiple types of reservoirs, a distribution pattern of shale gas reservoir in the sag-tight oil and gas reservoir in the slope-conventional oil and gas reservoir in the high position is formed, showing a total petroleum system featured with orderly symbiosis of unconventional and conventional oil and gas reservoirs. According to the theory of total petroleum system, the exploration in the Shiqiantan sag should focus on tight oil and gas reservoirs in the near-source slope area, structural-lithological oil and gas reservoirs and volcanic weathering-crust oil and gas reservoirs in the above-source fault-terrace area and structural high, and marine shale gas reservoirs within the source. The Carboniferous near-source favorable lithofacies belts, piedmont thrust fault-concealed structures, intra-basin palaeouplifts, and slope areas are favorable exploration zones in northern Xinjiang. Specifically, exploration efforts should be made towards shale oil and gas reservoirs within the sag, tight sandstone oil and gas reservoirs around the sag, conventional oil and gas reservoirs in the structural highs, and volcanic weathering-crust oil and gas reservoirs in uplifted areas. Table and Figures | Reference | Related Articles | Metrics

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3D Geological Simulation of Hydraulic Fracture Propagation and Frac-Hit Prevention in Horizontal Shale Gas Wells WANG Ting, WANG Jie, JIANG Houshun, XU Hualei, YAO Ziyi, NAN Chong Xinjiang Petroleum Geology    2023, 44 (6): 720-728.   DOI: 10.7657/XJPG20230611 Abstract （372）   HTML （12）    PDF（pc） （4736KB）（683）       Knowledge map    Save In the Sichuan basin, most of horizontal shale gas wells are stimulated by subdivided fracturing with large-stage and multi-cluster. Large-scale operations at high displacement and well infilling are often associated with severe inter-well interferences, leading to a decrease in well productivity. Optimizing stimulation treatments and well completion strategies and understanding the hydraulic fracture propagation rules are crucial to reducing the risk of inter-well frac-hit. Based on a 3D geomechanical model and with consideration to reservoir heterogeneity, in-situ stress anisotropy, interaction between fractures, and fracture network distribution, hydraulic fracture propagation and frac-hit prevention were simulated for two adjacent horizontal wells. The results show that large horizontal stress difference, natural fracture density and fluid intensity, or small approach angle and cluster spacing, may induce a high risk of frac-hit. Table and Figures | Reference | Related Articles | Metrics

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Maturity Evaluation of Niutitang Formation Source Rocks in Tongren Area，Northeast Guizhou LIU Kuiyong, WU Tao, LU Shufan, PAN Yingjuan, AN Yayun Xinjiang Petroleum Geology    2023, 44 (5): 528-534.   DOI: 10.7657/XJPG20230503 Abstract （260）   HTML （16）    PDF（pc） （590KB）（613）       Knowledge map    Save To determine the exploration potential of the shale gas in the Cambrian Niutitang formation in the Tongren area, northeast Guizhou, on the basis of X-ray diffraction experiments, the maturity of the shale of Niutitang formation-Bianmachong formation from Well QTD-1 was tested by using methods of bitumen reflectance, illite crystallinity and laser Raman spectroscopy. The results show that the shale of Niutitang formation-Bianmachong formation lacks vitrinite, making its maturity difficult to be evaluated using conventional vitrinite reflectance. The shale is not evaluated satisfactorily by using the reflectance of bitumen, due to its complex genesis and the impact of bitumen heterogeneity. The illite crystallinity method can only provide a rough range of maturity, with relatively large error due to the presence of clay minerals. In contrast, the laser Raman spectroscopy method is less affected by heterogeneity and has advantages such as simple sample preparation and non-destructive testing, which proves to be a more ideal testing approach. The equivalent vitrinite reflectance of the black shale of Niutitang formation in the study area ranges from 3.41% to 3.50%, indicating a late overmature stage. Table and Figures | Reference | Related Articles | Metrics

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Development Strategies for Unconventional Oil and Gas Resources in Turpan-Hami Exploration Area XU Jun, YANG Chun, MENG Pengfei Xinjiang Petroleum Geology    2023, 44 (3): 314-320.   DOI: 10.7657/XJPG20230307 Abstract （312）   HTML （18）    PDF（pc） （671KB）（613）       Knowledge map    Save To accelerate the development and utilization of unconventional oil and gas resources in the Turpan-Hami exploration area, the current development of unconventional resources in China is reviewed. Considering the technical difficulties in development and the mature experience in domestic shale oil and tight gas development, the development strategies for unconventional oil and gas resources in the Turpan-Hami exploration area are discussed. The development strategies for unconventional oil reservoirs are proposed regarding different basins, structural units and target zones. For the Permian shale oil reservoirs in the Malang sag of Santanghu basin, multi-layer development strategy is adopted; along with the construction of the largest carbon reduction base in the eastern Xinjiang, the technology of CO2 full-chain energy replenishment + viscosity-reduction volume fracturing for shale oil is vigorously developed to continuously enhance the recovery of shale oil. For the Permian Mazhong tight oil reservoirs in the Santanghu basin, well group multi-media composite huff-and-puff is adopted to enhance the oil recovery to 15.0%. For the Permian shale oil reservoirs in the Ji 28 block in the Jimsar sag, eastern Junggar basin, based on the successful experience in the Jimsar Shale Oil Demonstration Zone, the shale oil sweet spots are classified and evaluated, their distribution characteristics are clarified, and the drilling rate of Type I + II reservoirs is improved, so as to realize the beneficial development of shale oil. For the Jurassic Sanjianfang tight gas reservoirs in the Shengbei sag of Turpan-Hami basin, pilot tests of geology-engineering integration are performed to increase the length of horizontal section and the drilling rate of reservoir sweet spots, so as to improve the production efficiency of the tight gas reservoirs in the Shengbei sag. Table and Figures | Reference | Related Articles | Metrics

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Pore Structure Characteristics and Controlling Factors of Continental Mixed Shale Reservoirs ZHOU Xinrui, WANG Xixin, LI Shaohua, ZHANG Changmin, HU Kai, YAN Chunjing, NI Xueer Xinjiang Petroleum Geology    2023, 44 (4): 411-420.   DOI: 10.7657/XJPG20230404 Abstract （323）   HTML （17）    PDF（pc） （5762KB）（603）       Knowledge map    Save Continental mixed shale reservoirs are characterized by complex lithology and varying physical properties. The pore structure characteristics and controlling factors are crucial for understanding the physical properties of such reservoirs. Through analysis of rock thin section, casting thin section, scanning electron microscopy, high-pressure mercury intrusion, constant-rate mercury intrusion, and X-ray diffraction, the lithologies of the shale oil reservoirs in the Permian Lucaogou formation in the Jimsar sag were identified, and the pore structure characteristics of different lithologies and their relationships with diagenesis were analyzed. 6 lithologies are found in the shale reservoirs of the Lucaogou formation, namely micrite dolomite, silty sandy dolomite, calcareous siltstone, calcareous mudstone, silty tuff and calcareous tuff. The silty sandy dolomite, calcareous siltstone, and silty tuff are moderately compacted, with well-developed dissolution pores which are effectively connected and have large and well-sorted pore throats, indicating good physical properties. The calcareous tuff is also moderately compacted, and mainly composed of calcite, authigenic quartz and analcite cements, indicating moderate physical properties. The micritic dolomite and calcareous mudstone are simple in composition, strongly compacted, and weakly dissolved, with small pore throats, indicating poor physical properties. Table and Figures | Reference | Related Articles | Metrics

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Formation, Preservation and Distribution of Abnormally High Pressure in Ordovician Carbonate Rocks in Northern and Central Tarim Basin DUAN Yongxian, SONG Jinpeng, HUAN Zhipeng, YANG Liangang, ZHOU Peng, LV Duanchuan, TIAN Zhihong Xinjiang Petroleum Geology    2023, 44 (4): 421-428.   DOI: 10.7657/XJPG20230405 Abstract （343）   HTML （6）    PDF（pc） （1137KB）（582）       Knowledge map    Save The Ordovician ultra-deep carbonate reservoirs in the Tarim basin are controlled by high-energy facies belts, regional unconformity surfaces, and multi-period and multi-type fault fragmentation and reforming, as a result, the distributions of internal fluid and pressure systems are extremely complex. According to the analysis, factors such as sedimentation, structure, and chemical reaction affect the formation, preservation, and distribution of abnormally high pressure in the Ordovician carbonate rocks in the northern and central Tarim basin. Thick gypsum-salt rocks delayed the thermal evolution of source rocks and blocked stress transfer, while the unconformity surfaces provided pathways for the transfer of structural stress and undercompaction pressure, and for the late hydrocarbon charging, all of which are conducive to the formation of abnormally high pressure. The later thermochemical reduction reaction of sulfate weakened the development of abnormally high pressure to a certain extent and affected the vertically distributed layers. High-quality caprocks such as thick mudstone and tight limestone are conducive to the preservation of abnormally high pressure. The abnormally high pressure is mainly distributed around hydrocarbon-generating depressions and at secondary faults far away from primary faults or with weak activity. In the northern Tarim basin, the abnormally high pressure is mainly resulted from tectonic compression and undercompaction, and it is scattered as multiple points in the Yueman and Luchang areas with complex faults. In the central Tarim basin, the abnormally high pressure due to fluid expansion is concentrated in the TZ-10 structural belt, where the reservoirs are generally small in scale and constant in volume. Table and Figures | Reference | Related Articles | Metrics

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CO2 Huff-n-Puff and Storage Test in Extra-High Water Cut Stage in Shanshan Oilfield LI Yanming, LIU Jing, ZHANG Peng, GONG Xuecheng, MA Jianhong Xinjiang Petroleum Geology    2023, 44 (3): 327-333.   DOI: 10.7657/XJPG20230309 Abstract （294）   HTML （21）    PDF（pc） （720KB）（569）       Knowledge map    Save Based on the pilot test of the CO2 huff-n-puff well group in the Shanshan oilfield, the injection-production performance and the factors influencing CO2 EOR and storage in high water cut stage in low-permeability and low-viscosity oilfields were analyzed. The results show that, in the Shanshan oilfield (medium-deep burial reservoirs), the injected CO2 stays in a supercritical state, and the characteristics of CO2 injection are similar to those of water injection, showing the problems of uneven vertical sweep and planar breakthrough. The CO2 huff-n-puff can be divided into three stages: transient gas flowback, oil enhancement, and gradual invalidation. Three huff-n-puff wells vary greatly in oil replacement rate, indicating that the EOR effect mainly affected by the degree of remaining oil enrichment. The main mechanisms of CO2 storage are dissolution and mineralization, and the simultaneous storage rate can reach as high as 95.6%. Table and Figures | Reference | Related Articles | Metrics

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Factors Influencing Water Injection Effect in Low Porosity and Low Permeability Heavy Oil Reservoirs WAN Haiqiao, WANG Sheng, LIU Xueliang Xinjiang Petroleum Geology    2023, 44 (3): 347-351.   DOI: 10.7657/XJPG20230312 Abstract （283）   HTML （20）    PDF（pc） （539KB）（566）       Knowledge map    Save Low porosity and low permeability sandy conglomerate heavy oil reservoirs in the Permian series of the Lukeqin oilfield in Turpan-Hami basin are usually fractured for recovery due to their poor physical properties, strong heterogeneity and low natural productivity. The induced fractures and reservoir heterogeneity lead to poor water injection effect. In order to solve the problems encountered in the development such as prominent areal contradiction, low efficiency, and ineffective areas, water injection is used to replenish the formation energy for increasing single-well production, but the effect in single wells is quite different. The reservoir wettability and water injection process for energy replenishment were studied through physical simulation experiments. The results show that the Permian reservoirs in the Lukeqin oilfield are water-wetting. Fracturing is conducive to the imbibition between fractures and reservoir matrix, which can effectively replenish the formation energy to improve single-well production. The faster the water is injected, the faster the formation energy can be recovered; the higher the well soaking pressure, the higher the oil increment. Combining numerical simulation and in-situ conditions, the injection parameters were optimized. As a result, the effect of water injection was good, with the effective rate reaching 88%. Table and Figures | Reference | Related Articles | Metrics

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Controls of Continental Shale Lithofacies on Pore Structure of Jurassic Da’anzhai Member in Central Sichuan Basin KONG Xiangye, ZENG Jianhui, LUO Qun, TAN Jie, ZHANG Rui, WANG Xin, WANG Qianyou Xinjiang Petroleum Geology    2023, 44 (4): 392-403.   DOI: 10.7657/XJPG20230402 Abstract （344）   HTML （21）    PDF（pc） （6614KB）（566）       Knowledge map    Save The hydrocarbon storage capacity of shale reservoirs depends on their complex pore structures, which vary by lithofacies of shales. In order to clarify the control of shale lithofacies on the pore structure, the lithofaices of the shales in the Da’anzhai member of Jurassic Ziliujing formation in central Sichuan basin were determined based on total organic carbon and X-ray diffraction analyses, and the pore structure characteristics of the shales were identified by means of thin section observation, and analysis on scanning electron microscopy, low-temperature nitrogen adsorption and high-pressure mercury injection. The results show that six shale lithofacies (organic-rich clayey shale, organic-moderate clayey shale, organic-poor clayey shale, organic-moderate mixed shale, organic-poor mixed shale, and organic-poor calcareous shale) are mainly developed in the Da’anzhai member, with parallel plate-like and slit-like pores dominantly. Clayey shales mainly contain clay mineral interlayer pores, organic matter pores, and fractures induced by hydrocarbon generation pressurization; mixed shale mainly contains residual intergranular pores; and calcareous shale mainly contains a small amount of dissolution pores. For all these lithofacies, the clay mineral content is positively correlated with pore volume and specific surface area, and the TOC is positively correlated with the macropore volume of organic-rich clayey shale. The organic-rich clayey shale exhibits the largest macropore volume and trimodal pore-size distribution, making it the most favorable lithofacies for shale oil storage in the Da’anzhai member in central Sichuan basin. Table and Figures | Reference | Related Articles | Metrics

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Static Connectivity Evaluation on Fault-Controlled Reservoir System in the Middle Section of Shunbei No.4 Fault Zone，Shunbei Oilfield LIU Jun, LIAO Maohui, WANG Laiyuan, GONG Wei, HUANG Chao, ZHA Ming Xinjiang Petroleum Geology    2023, 44 (4): 456-464.   DOI: 10.7657/XJPG20230410 Abstract （230）   HTML （8）    PDF（pc） （7362KB）（520）       Knowledge map    Save There are various types of reservoirs in the fault-controlled reservoir system in the Shunbei No.4 strike-slip fault zone, and the spatial positions of the reservoirs affect the connectivity of the reservoir system and restrict the production of oil wells in different locations. A method of pre-drilling evaluation on the connectivity of target reservoir system was proposed to evaluate the connectivity of fault-controlled reservoir system in the middle section of the Shunbei No.4 strike-slip fault zone. The results show that the fault-controlled reservoir system in the middle Shunbei No. 4 strike-slip fault zone can be divided into 4 compartmental units. The connectivity rates of internal caverns of the 4 compartmental units all exceed 50%, with extended high-angle fractures, large cumulative thickness of vertical caves, and strong connectivity. The favorable reservoirs in compartmental units 3 and 4 indicate high probabilities in obtaining higher production. Table and Figures | Reference | Related Articles | Metrics

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Geological Evaluation and Favorable Areas of Underground Coal Gasification in Santanghu Basin WANG Xinggang, FAN Tanguang, JIAO Lixin, DONG Zhen, CAO Zhixiong, HAN Bo Xinjiang Petroleum Geology    2023, 44 (3): 307-313.   DOI: 10.7657/XJPG20230306 Abstract （342）   HTML （14）    PDF（pc） （671KB）（514）       Knowledge map    Save Underground coal gasification (UCG) is a revolution in traditional coal mining technology, and the site selection of underground coal gasifier is a prerequisite for a successful UCG project. The geological conditions of UCG of the Jurassic Xishanyao formation in the Santanghu basin were evaluated based on the analysis of coalseam thickness, burial depth of coalseam, coal petrology and quality, geologic structure, roof lithology of coalseam and hydrogeological conditions. The results show that the Xishanyao coalseam is featured with a low coal rank, high ash and volatile matter contents, moderate dip angle and burial depth, and roof lithology consisting of mudstone, siltstone, and sandstone with underdeveloped faults, and good-quality water barriers, which provide favorable geological conditions for UCG. Furthermore, 18 indexes (e.g. structural complexity, burial depth, and coal-seam thickness and so on) for evaluating favorable areas of UCG were identified depending upon the geological characteristics of the Santanghu basin, and a multi-level mathematical model was established for evaluating UCG in the basin. According to UCG potential, the whole basin is divided into TypeⅠ, Type Ⅱ, and Type Ⅲ areas. The northern slope of Malang sag and the eastern margin of Tiaohu sag are defined as the favorable areas for UCG. Table and Figures | Reference | Related Articles | Metrics

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Research Progress and Trend of Ultra-Deep Strike-Slip Fault-Controlled Hydrocarbon Reservoirs in Tarim Basin WANG Qinghua, CAI Zhenzhong, ZHANG Yintao, WU Guanghui, XIE Zhou, WAN Xiaoguo, TANG Hao Xinjiang Petroleum Geology    2024, 45 (4): 379-386.   DOI: 10.7657/XJPG20240401 Abstract （385）   HTML （33）    PDF（pc） （4805KB）（500）       Knowledge map    Save Ultra-deep strike-slip fault-controlled hydrocarbon reservoirs have been discovered as a new frontier for exploration and development in the Tarim basin. However, the complexity of these reservoirs poses a significant challenge for profitable development, necessitating enhanced foundational geological research. The strike-slip fault-controlled hydrocarbon reservoirs are commonly characterized by strong heterogeneity, intricate reservoir and fluid distribution, significant variations in hydrocarbon production, and low recovery. The great differences in faulting, reservoir characteristics, hydrocarbon accumulation, and fluid dynamics of these reservoirs between different areas present a series of exploration and development challenges. A series of models for strike-slip fault zones of different genesis and their controls on reservoirs have been established, and the mechanisms of reservoir formation along strike-slip fault zones including combined reservoir control by microfacies, strike-slip fault and dissolution, and contiguous, differential and extensive development have been revealed. Furthermore, the strike-slip fault-controlled reservoir models with “source-fault-reservoir-caprock coupling” and “small reservoir but large field” are constructed, unveiling the mechanisms of the hydrocarbon accumulation and preservation of ultra-deep strike-slip fault-controlled reservoirs. This research breaks through the limitations in theory that weak strike-slip faults in cratonic basins are difficult to form large-scale strike-slip fault-controlled reservoirs and large oil/gas fields. Finally, the genesis of large-scale strike-slip fault systems, the differential reservoir formation mechanisms within strike-slip fault zones, and the hydrocarbon enrichment patterns in cratonic basins have been clarified. Table and Figures | Reference | Related Articles | Metrics

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Geometry of Hydraulic Fractures in Fractured Horizontal Wells in Shale Reservoirs of Jimsar Sag，Junggar Basin FANG Zheng, CHEN Mian, WANG Su, LI Jiacheng, LYU Jiaxin, YU Yanbo, JIAO Jibo Xinjiang Petroleum Geology    2024, 45 (1): 72-80.   DOI: 10.7657/XJPG20240110 Abstract （275）   HTML （10）    PDF（pc） （4519KB）（497）       Knowledge map    Save The side-view images of microseismic monitoring in horizontal wells in the shale reservoirs in the Jimsar sag of Junggar basin and in the southern Sichuan basin exhibit a phenomenon that the density and extent of the data points parallel to bedding direction are much greater than those perpendicular to the bedding direction. This phenomenon contradicts the hydraulic fracture interpretation results from conventional processing. However，there is no clear explanation for this phenomenon in terms of 3D geometry of hydraulic fractures. A method of microseismic inversion was established，and the inversion results were reconstructed to obtain 3D geometry of the fractures induced by horizontal well hydraulic fracturing in shale reservoirs. Finally，the fracture geometry and the microseismic inversion method were verified through physical simulation experiments on fracturing under true triaxial stress. The results show that the fractures from inversion primarily exhibit a geometrical pattern of one main fracture intersecting with multiple secondary fractures in three dimensional space. Combining with the results of fracturing physical simulation experiments under true triaxial stress，it is found that the hydraulic fractures are horizontally and vertically intersected. The results of acoustic emission experiments and the fracture geometry presented after true-triaxial fracturing physical simulation of outcrop samples from the Jimsar sag validate that the microseismic inversion method is reliable and the fractures induced by horizontal well hydraulic fracturing in shale reservoirs are complex. Table and Figures | Reference | Related Articles | Metrics

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Well Pattern Optimization for Fractured-Vuggy Carbonate Reservoirs in Tahe Oilfield HU Wenge, LI Xiaobo, YANG Min, LU Xinbian, LIU Xueli, LIU Hongguang Xinjiang Petroleum Geology    2023, 44 (4): 429-434.   DOI: 10.7657/XJPG20230406 Abstract （260）   HTML （9）    PDF（pc） （1767KB）（483）       Knowledge map    Save Fractured-vuggy carbonate reservoirs are characterized by large differences in reservoir scale, strong spatial discreteness, complex fracture-vug connectivity between wells, and diverse fluid flow patterns. The low control degree of fractures and vugs results in uneven producing of reserves and different water/gas flooding effects. The regular and irregular well patterns for conventional sandstone reservoirs are not applicable to fractured-vuggy carbonate reservoirs. Therefore, it is necessary to establish a well pattern construction and optimization method that matches the characteristics of fractured-vuggy carbonate reservoirs. By combining physical simulation experiments with theoretical analysis and following the idea of constructing a “three-dimensional” and “systematic” well pattern, the theoretical connotation of spatially structural well patterns is enriched, and the fundamental understanding of gravity displacement theory in the construction of spatially structural well patterns is deepened. A well pattern design method and a 6-step well pattern construction process are established, focusing on fracture-vug structures, connectivity, reserves producing, energy conditions, and injection-production structures. It is concluded that the difference in fluid density is the dominant factor of gravity displacement, the potential difference in the fracture-vug connectivity structure is the important driving force for vertical displacement, and the displacement speed difference between primary and secondary channels is the key to vertical balance and serves as an efficiency mechanism for EOR of fractured-vuggy reservoirs with spatially structural well patterns. Table and Figures | Reference | Related Articles | Metrics

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Methods for Calculating Oil Column Height in Reservoirs Controlled by Deep and Large Faults WANG Rujun, WANG Peijun, NIU Ge, WANG Huailong, ZHANG Jie, LIANG Ruihan, ZHAO Xinyue Xinjiang Petroleum Geology    2023, 44 (5): 608-612.   DOI: 10.7657/XJPG20230513 Abstract （339）   HTML （8）    PDF（pc） （586KB）（472）       Knowledge map    Save The reservoirs controlled by deep and large faults are generally thick and deep. Therefore, a well cannot penetrate completely through an entire reservoir. For calculating the oil column height in fault-controlled reservoirs, a physical model of oil column height in fault-controlled reservoir was established. On this basis, the idea of the wellbore temperature profile extrapolation method was discussed, a formula for calculating oil column height with the conversion method of oil-water column pressure coefficient was derived, and the dynamic reserves inverse method considering the cuboid drainage area and the equivalent flow resistance method considering the influence of gravity were proposed. The four methods were applied to two wells drilled into a fault-controlled reservoir in Fuman oilfield of Tarim basin. The results show that the oil column heights calculated by the four methods are consistent, and the average oil column heights of the two wells are 675.39 m and 634.60 m, respectively. Table and Figures | Reference | Related Articles | Metrics

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A New Method of Water Injection Control for Multilayered Sandstone Reservoirs: A Case of Hutubi Formation in Luliang Oilfield DANG Sisi, SUN Zhixiong, PEI Shuai, WU Congwen, MOU Lei, ZHOU Yuhui Xinjiang Petroleum Geology    2023, 44 (4): 465-471.   DOI: 10.7657/XJPG20230411 Abstract （300）   HTML （6）    PDF（pc） （1234KB）（437）       Knowledge map    Save The reservoirs with bottom water in the Luliang oilfield are characterized by multiple thin and scattered oil layers, strong interlayer heterogeneity, extra-high watercut of oil wells, and low efficiency of layered water injection. The oilfield is facing challenges such as unclear distribution of remaining oil and difficult control of water injection. In response to the current water injection status of the multilayered sandstone reservoirs in the Luliang oilfield, a new method of water injection control was established based on the interwell numerical simulation model (INSIM) and by using geological congnition, logging data and testing data. The new method helps realize a rapid simulation evaluation and injection-production parameter optimization for layered water injection in well groups with different formation coefficient ranges. This method allows for the analysis of vertical and horizontal water injection in multilayered reservoirs, and also the dynamic simulation of natural production splitting. The application to a typical well group in the L9 reservoir of the Luliang oilfield demonstrates an estimated increase in the cumulative oil production by 3.2×104 m3, a decrease in the cumulative injected water by 3.9×104 m3, and a decline in the water cut in the well block by 6.1%. Thus, the efficiency of layered water injection is improved, and the effects of production increasing and water reduction are enhanced. The method may serve as a reference for layered water injection control and potential tapping in multilayered sandstone reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Water Injection Adjustment Methods Based on Dynamic Flow Resistance SHAN Gaojun, WANG Chengxiang, WANG Zhiguo, JIANG Xueyan, GUO Junhui Xinjiang Petroleum Geology    2023, 44 (4): 435-441.   DOI: 10.7657/XJPG20230407 Abstract （282）   HTML （5）    PDF（pc） （651KB）（436）       Knowledge map    Save For the reservoirs in late development stage with ultra-high water cut, which exhibit significant difference in the oil-water two-phase flow capacity and strong dynamic reservoir heterogeneity, the injector interval subdivision method based on static parameters such as permeability and the interval water allocation method using empirical analysis are insufficient to meet the requirements of precise development of multi-layered sandstone reservoirs. Through theoretical analysis, physical simulation, and numerical modeling, the flow behaviors in the oilfields in late development stage with ultra-high water cut were further understood. A flow resistance calculation model for reservoir layers was developed, and aiming at minimizing the variation coefficient of flow resistance in single wells, a method for water injection interval optimization based on flow resistance was established. Additionally, by constructing coefficients of remaining reserves, reasonable injection-production ratio, relative water injection efficiency, and water cut rising rate for intervals, a quantitative adjustment method for water injection in the intervals with ultra-high water cut was developed. This method allows for quantitative water injection under conditions involving multiple wells, multiple layers, and complex injection-production relationships. The method was tested 237 times in wells of a typical block, with a decrease in initial water cut by 0.14%, demonstrating a satisfactory performance in both water control and oil increasement. Table and Figures | Reference | Related Articles | Metrics

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Precursor and Mechanism of Hydrocarbon Generation for Shale Oil in Lucaogou Formation, Jimsar Sag WANG Jian, LIU Jin, PAN Xiaohui, ZHANG Baozhen, LI Erting, ZHOU Xinyan Xinjiang Petroleum Geology    2024, 45 (3): 253-261.   DOI: 10.7657/XJPG20240301 Abstract （374）   HTML （30）    PDF（pc） （6824KB）（434）       Knowledge map    Save In order to clarify the differences in hydrocarbon-generating precursor and mechanism of the shale oil between the upper and lower sweet spots of the Lucaogou formation, the source rocks of the Lucaogou formation in the Jimsar sag were characterized ultra-microbiologically using field emission scanning electron microscopy, electron probe, and Fourier transform infrared spectroscopy experiments. The results show that the main hydrocarbon-generating precursor of the shale oil in the upper sweet spot is lamalginite (Microcystis), with straight-chain aliphatic series in dominance, and the main hydrocarbon-generating precursor in the lower sweet spot is telalginite (Tasmanian algae), which is rich in branched-chain aliphatic, aromatic, and sulfoxide functional groups. Due to the significantly higher activation energy required for the cleavage of long straight-chain saturated hydrocarbons than that for branched-chain hydrocarbons, as well as the lower bond energies of carbon-sulfur and carbon-nitrogen bonds, the activation energy of the precursor of the shale oil in the lower sweet spot is lower than that in the upper sweet spot. Consequently, early-stage hydrocarbon generation occurs, leading to the formation of high-density crude oil rich in non-hydrocarbon bitumen at low maturity, which is the primary reason for the relatively heavy and viscous nature of the crude oil in the lower sweet spot. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Barriers/Interlayers in Braided-River Reservoirs and Its Controls on Remaining Oil Distribution：A Case of N1gⅡ3 in Liuguanzhuang Area of Dagang Oilfield LI Hang, LI Shengli, ZHOU Lianwu, MA Shuiping, HUANG Xiaodi, HAN Bo, LI Ning Xinjiang Petroleum Geology    2024, 45 (1): 94-101.   DOI: 10.7657/XJPG20240113 Abstract （299）   HTML （11）    PDF（pc） （2302KB）（427）       Knowledge map    Save In order to clarify the controls of barriers/interlayers on the distribution of remaining oil in the braided-river reservoirs，taking the sand set Ⅱ in the third member of the Guantao formation （N1gⅡ3） in the Liuguanzhuang area of Dagang oilfield as an example，and using the data of core，testing，logging，and production performance，the criteria for quantitative identification of barriers/interlayers were established for the target interval in the study area，and the hierarchy，genesis of barriers/interlayers and their controls on remaining oil distribution were determined. In the study area，the barriers/interlayers in the target interval can be divided into 3 categories such as barriers between sand sets，interlayers between sand bodies，and interlayers within a sand body，which are developed near the architecture boundaries of the 7th-，8th-，and 9th-order sand bodies，respectively. The barriers between sand sets are dominated by floodplain mudstones and silty mudstone，with the thickness ranging from tens of centimeters to several meters. They can efficiently seal oil and gas vertically and allow the edge water to advance preferentially along the formation during development，leading to severe water flooding，and thus the remaining oil is mostly distributed in the upper parts of the complex mid-channel bars and braided channels far from water injection wells. The interlayers between sand bodies are mainly composed of fine-grained sediments in abandoned channels and gullies，with the thickness typically ranging from 0 to 2 meters. They locally hinder vertical fluid migration and laterally control the distribution of remaining oil in different sand bodies，leading to two remaining oil distribution patterns：one is controlled by abandoned channel and the other by gully. The interlayers within a sand body are primarily associated with lateral accreted and interchannel mud deposits，and fall-silt seam，with the thickness reaching tens of centimeters，leading to three remaining oil distribution patterns，which are controlled by laterally-accreted mudstone，fall-silt seam，and interchannel mudstone，respectively. Table and Figures | Reference | Related Articles | Metrics

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Controlling Factors and Models of Hydrocarbon Accumulation in Tight Oil Reservoirs of Yao 1 Member in Gulong Sag LIU Ping Xinjiang Petroleum Geology    2023, 44 (6): 635-645.   DOI: 10.7657/XJPG20230601 Abstract （268）   HTML （28）    PDF（pc） （1024KB）（413）       Knowledge map    Save Based on the seismic, geological, geochemical, and production testing data, the types and distribution patterns of the tight oil reservoirs in the first member of Yaojia formation (Yao 1 member) in the Gulong sag were analyzed, and then the controlling factors and models of hydrocarbon accumulation in these reservoirs were clarified. The results show that five types of tight oil reservoirs are developed in the Yao 1 member such as lenticular sandstone reservoir in the Gulong syncline, updipping pinch-out lithologic reservoir, fault-lithologic reservoir, fault-block reservoir, and fault-anticline reservoir at the top of the nose-like bulge. The formation of tight oil reservoirs is jointly controlled by source rock and overpressure distribution, traps, oil-source faults, and high-quality reservoir beds. The lacustrine mudstones in the first member of Qingshankou formation (Qing 1 member) serve as the material basis for tight oil reservoirs and also create abnormally-high pressure that drove oil charging into the Gulong syncline. Before extensive hydrocarbon accumulation, various traps had been formed, including structural traps and structural-lithological traps at high positions on both sides, which act as the tight oil migration destinations and favorable accumulation sites. The reversal-stage faults that opened during the main oil accumulation phase serve as the primary pathways for vertical oil migration, and high-quality distributary-channel reservoir beds are favorable for tight oil accumulation. The structural units are different in controlling factors and models of hydrocarbon accumulation. In the Gulong syncline, the hydrocarbon accumulation model is “driven by overpressure, vertical migration along faults, and enrichment in local sweet spots”. In the Xinzhan nose-like bulge, the hydrocarbon accumulation model is “first driven by overpressure then by buoyancy, vertical migration along faults, and accumulation in favorable traps”. In the Xinzhao slope, the hydrocarbon accumulation model is “driven by overpressure + buoyancy, fault-sandbody relay-migration, and accumulation in favorable reservoir beds”. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Alkaline Minerals and Logging Evaluation of Trona in Fengcheng Formation of Mahu Sag MAO Rui, ZHAO Lei, SHEN Ziming, LUO Xingping, CHEN Shanhe, FENG Cheng Xinjiang Petroleum Geology    2023, 44 (6): 667-673.   DOI: 10.7657/XJPG20230604 Abstract （285）   HTML （19）    PDF（pc） （1727KB）（411）       Knowledge map    Save The Fengcheng formation of the Mahu sag in the Junggar basin is primarily composed of alkaline lake sediments. A large number of alkaline minerals are developed near the center of the alkaline lake. As a major type in these alkaline minerals, trona is an important industrial resource worthy of development. Currently, the trona intervals are mainly qualitatively evaluated by using the crossplot method, and a quantitative evaluation method is required. Based on core analysis and thin-section identification on alkaline minerals, together with previous research findings, the alkaline minerals in the Fengcheng formation are classified into four categories: trona, shortite; huntite, and searlesite, and their physical properties and impacts on both reservoir properties and oil-bearing property are identified. The influence of trona content on logging responses is analyzed, and a predictive model for trona content is developed by using the deep-to-shallow resistivity ratio. Core data uninvolved in the modeling are used for verifying the predictive model. It is found that the trona content predicted by the model and the trona content measured in the sample are in good agreement, with an average relative error of 5.67%, meeting the requirements for precise mineral content calculations. Finally, based on the logging evaluation results of trona content from eleven wells, the distribution of trona in the Fengcheng formation is clarified. The research results may provide a theoretical and technical support for trona resource evaluation. Table and Figures | Reference | Related Articles | Metrics

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A New Method for Characterizing Remaining Oil in High Water-Cut Reservoirs ZHAO Chenyun, DOU Songjiang, DOU Yu, LIU Chaoyang, HUANG Bo, WANG Zhenyu, LI Gang Xinjiang Petroleum Geology    2023, 44 (6): 690-695.   DOI: 10.7657/XJPG20230607 Abstract （260）   HTML （9）    PDF（pc） （1450KB）（404）       Knowledge map    Save Remaining oil aggregation is a key indicator for evaluating the recovery effect and potential of high water-cut reservoirs. In this study, the dominant reserves zones within the reservoir are determined based on remaining reserves abundance. The weights of indicators are determined with the entropy weight method by using block area, distribution density and shape index. Finally, the remaining oil aggregation is characterized. The results show that, for a reservoir under steady development, the dispersion and accumulation of remaining oil can be divided into four stages: primary dispersion, rapid separation, fluctuating accumulation and dispersion, and secondary dispersion. Utilizing these characterization indicators, an evaluation was conducted on the Nm3-4-1 layer in No.7 fault block in Block 2 of the East Dagang Development Area, Dagang oilfield. The results show that the remaining oil aggregation in Nm3-4-1 decreased steadily with the progress of development, and it starts to rise owing to injection-production structure and well pattern adjustments. Table and Figures | Reference | Related Articles | Metrics

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Distribution and Potential Tapping Strategies of Remaining Gas in Tight Sandstone Gas Reservoirs SHI Yaodong, WANG Liqiong, ZANG Yicheng, ZHANG Ji, LI Peng, LI Xu Xinjiang Petroleum Geology    2023, 44 (5): 554-561.   DOI: 10.7657/XJPG20230506 Abstract （340）   HTML （16）    PDF（pc） （1855KB）（399）       Knowledge map    Save The Su 36-11 block in the central area of Sulige gas field has been developed for 17 years, with high degrees of development and reserves producing. The strong reservoir heterogeneity in this block leads to uneven producing of reserves and complex distribution of remaining gas. Distribution determination and potential tapping of the remaining gas are crucial for maintaining stable production in the gas field. By accurately characterizing the reservoir architecture, the main factors influencing remaining gas distribution were identified, the distribution patterns of different types of remaining gas were determined, and corresponding strategies for recovering the remaining gas were proposed. The research results show that the gas-bearing sand bodies in the study area are mainly distributed in the 4th-order architecture units, such as channel bar and point bar, these sand bodies are significantly affected by various levels of flow barriers, with small overall scale, poor connectivity, width of 150-500 m and length of 300-800 m. The main NE-SW sand belt in the block has been developed the most, with low formation pressure, and the remaining gas is mainly distributed in the lower He 8 member in the northwestern part of the block. Remaining gas, whose distribution is mainly influenced by reservoir heterogeneity and uneven development, can be divided into five types: gas uncontrolled by well pattern, gas in composite sand body flow barrier, gas in secondary pay zone unexploited by horizontal well, gas in unperforated gas-bearing layer in vertical well, and gas unproduced. Four potential tapping measures were proposed, including well infilling, reperforation, sidetracking and potential tapping in exsisting wells. According to the adjusted development plan, it is predicted that stable production can be maintained for 7 years with the recovery efficiency reaching 45%. Table and Figures | Reference | Related Articles | Metrics

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Water Production Mechanism in Tight Sandstone Gas Reservoirs After Fracturing in Linxing Gas Field SHI Xuefeng, YOU Lijun, GE Yan, HU Yunting, MA Litao, WANG Yijun, GUO Sasa Xinjiang Petroleum Geology    2024, 45 (1): 81-87.   DOI: 10.7657/XJPG20240111 Abstract （253）   HTML （9）    PDF（pc） （678KB）（398）       Knowledge map    Save The tight sandstone gas reservoirs in the Linxing gas field，Ordos basin，are key targets for onshore gas development. Due to the structural complexity，reservoir physical properties，and complicated gas-water relationship，most gas wells produce water continuously after fracturing，and their water production rates are very different. Understanding the reasons for irreducible water saturation variation after fracturing is of great significance for formulating effective water control and gas recovery measures to increase well productivity. In this study，representative tight sandstone samples from the Linxing gas field were tested by using the gas displacement method to clarify how reservoir properties，production pressure difference，and fracturing fluid affect irreducible water saturation. The results show that the difference in the irreducible water saturation between matrix and fractures is 13.32%~18.36% for Class Ⅰ reservoirs，28.28%~34.19% for Class Ⅱ reservoirs，and 39.10%~48.15% for Class Ⅲ reservoirs. Hydraulic fractures can significantly improve the water flow capacity of reservoirs，and provide additional water flow pathways. The increased production pressure difference，reduced flow pressure loss and weakened hydrophilic degree are the main mechanisms leading to the weakening capacity of the reservoir in bounding water and water production of gas wells after fracturing. To control water and produce gas efficiently in tight sandstone gas reservoirs with high water cut after fracturing，measures such as controlling fracturing scale，optimizing production systems，and adjusting fracturing additive amount can be implemented，which will help delay the onset of water breakthrough in gas wells and reduce the overall water production. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Fractures and Their Controls on Yanchang Formation Reservoir in Ordos Basin XIAO Zhenglu, LU Jungang, LI Yong, ZHANG Hai, YIN Xiangdong, ZHOU Xiang Xinjiang Petroleum Geology    2023, 44 (5): 535-542.   DOI: 10.7657/XJPG20230504 Abstract （262）   HTML （13）    PDF（pc） （1050KB）（397）       Knowledge map    Save In order to determine the temporal continuity and spatial orderliness of hydrocarbon charging and accumulation in fault areas, taking the Shangzhenzi farm-Zhuanjiao area at the southern margin of the Ordos basin as an example, the relationship between fracture formation period and reservoir distribution was analyzed, and the controls of fractures on Yanchang formation reservoir was discussed. The study shows that the fractures of three periods (Yanshanian movement episode II and III, and Himalayan movement) are developed in Yanchang formation, showing varying impacts on hydrocarbon migration and accumulation. Near-source oil reservoirs captured all the hydrocarbons generated from the source rocks in immature and mature stages, which were subsequently destroyed during the Yanshanian episode III and the Himalayan movement, leading to oil migration towards the areas far away from source rocks. In the southern part of the study area, close to the Weibei uplift, fractures are well connected longitudinally and sand bodies are well developed, allowing oil enrichment primarily in reservoirs far away from source rocks. In the northern part of the study area, oil is predominantly retained in reservoirs near source rocks. Consequently, fractures and sand bodies are connected to form a transport network that plays a role in adjusting reservoirs. By virtue of multi-stage fractures, resources in reservoirs near or far away from source rocks can be complemented and integrated. Table and Figures | Reference | Related Articles | Metrics

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Diagenesis and Pore Evolution of Tight Reservoirs of Sanjianfang Formation in Shengbei Subsag ZHOU Gang, CHENG Tian, LI Jie, CHEN Anqing, LI Fuxiang, XU Hui, XU Shenglin Xinjiang Petroleum Geology    2023, 44 (3): 289-298.   DOI: 10.7657/XJPG20230304 Abstract （301）   HTML （23）    PDF（pc） （5123KB）（395）       Knowledge map    Save The Sanjianfang formation in the Shengbei subsag of the Tabei sag in the Turpan-Hami basin is rich in oil and gas resources. However, the sandstone reservoirs in this formation are tight and heterogeneous, which hinders the exploration and development of oil and gas. Based on core and thin-section observations, electron microscopy scanning, and high-pressure mercury injection tests, the diagenetic processes and pore evolution of the tight sandstone reservoirs of the Middle Jurassic Sanjianfang formation in the Shengbei subsag were studied. The results show that the tight sandstone reservoirs of the Sanjianfang formation are mainly composed of feldspathic litharenite and lithic sandstone, and dominantly contain secondary pores, with an average porosity of 6.44% and an average permeability of 0.18 mD, indicating low-porosity and low-permeability reservoirs. The diagenetic evolution process includes compaction-authigenic clay mineral cementation, chlorite-rimming cementation-phase-Ⅰ quartz enlargement and feldspar dissolution-albitization-rimmed chlorite cementation-carbonate cementation-feldspar dissolution-kaolinite illitization. The sandstone is currently in phase B of the middle diagenetic stage. The average initial porosity of the Sanjianfang formation sandstones is 34.66%. The average reduction in porosity is 14.05% due to compaction and 0.50% due to the cementation in phase A of the early diagenetic stage, 3.21% due to compaction and 0.75% due to cementation in phase B of the early diagenetic stage, 7.02% due to compaction and 4.26% due to cementation in phase A of the middle diagenetic stage, and 1.08% due to compaction and 0.75% due to cementation in phase B of the middle diagenetic stage. The dissolution process in phase A of the middle diagenetic stage is crucial to the increase in porosity, with an average increase of 3.38%. Table and Figures | Reference | Related Articles | Metrics

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Source Rock Evaluation and Oil-Source Correlation for Middle-Lower Jurassic Tight Oil in Shengbei Subsag, Turpan-Hami Basin LIU Feng, ZHAO Hongjing, JIN Ying, GAN Yingxing, ZENG Yan, WEN Wangbiao, XU Guifang Xinjiang Petroleum Geology    2023, 44 (3): 277-288.   DOI: 10.7657/XJPG20230303 Abstract （331）   HTML （508）    PDF（pc） （1407KB）（390）       Knowledge map    Save 22 oil and gas layers in the tight sandstones below the Xishanyao formation were interpreted in the risky exploration Well Qintan-1 in the Shengbei subsag, Turpan-Hami basin. It is necessary to evaluate the encountered source rocks and determine the tight oil source. The source rocks in the Xishanyao formation are non-or poor source rocks in most intervals near Well Taican-2, except the 4 700-4 900 m interval, and are moderate-good source rocks in Well Qintan-1 in the subsag. The source rocks in the Sangonghe formation are moderate to good. The organic matters in the Middle-Lower Jurassic are generally Type Ⅱ2-Ⅲ. The Xishanyao formation source rocks are mature, while the Sangonghe formation and Badaowan formation source rocks are highly mature. The carbon number of the paraffins in the soluble organic matters in source rocks distributes in a wide range, and the C27-C28-C29 αααR sterane shows a reverse “L” configuration, indicating a hybrid organic matters mainly sourced from terrestrial higher plants. The organic matter of Xishanyao formation has a low gammacerane content and a relatively high pristane-phytane ratio (Pr/Ph), corresponding to a weak oxidation-weak reduction sedimentary environment with relatively low salinity. The organic matter of Sangonghe formation and Badaowan formation have low Pr/Ph and high gammacerane content, showing a strong reduction sedimentary environment with high salinity. β-carotane is developed in the entire Sangonghe formation, and is quite abundant in some intervals, with the content equivalent to that of the main peak n-alkanes, indicating the contribution of halophilic bacteria and a reducing water environment in these intervals. According to the parameters such as C27/C29 αααR sterane, Pr/Ph, C19+20/C23+24 tricyclic terpane, C24 tetracyclic terpane/C26 tricyclic terpane, rearranged hopane and β-carotane, it can be inferred that the crude oil in the Sangonghe formation came from the source rocks of the same formation; the crude oil at the bottom of the Xishanyao formation originated from the Sangonghe formation source rocks enriched in β-carotane and underwent secondary migration, and the oil sand extracts from the upper and middle members of the Xishanyao formation are related to the source rocks in the Xishanyao formation. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation of Factors Influencing Hydraulic Fracture Propagation in Sandstone-Mudstone Interbedded Reservoirs LYU Zhao, PAN Liyan, HAO Lihua, ZOU Nana, ZOU Zhikun Xinjiang Petroleum Geology    2023, 44 (6): 729-738.   DOI: 10.7657/XJPG20230612 Abstract （291）   HTML （9）    PDF（pc） （853KB）（387）       Knowledge map    Save It is difficult to conduct hydraulic fracturing in sandstone-mudstone interbedded reservoirs. Investigating the factors influencing hydraulic fracture propagation in such reservoirs is beneficial for optimizing fracturing parameters and enhancing vertical producing degree of reservoir. The propagation of hydraulic fractures in sandstone-mudstone interbedded reservoirs is primarily influenced by rock mechanics between layers, differences in formation stress, and engineering parameters. The cohesive elements of hydraulic fracture and layer interface are embedded into ABAQUS software to analyze how the displacement and viscosity of fracturing fluid, mudstone-sandstone elastic modulus ratio, tensile strength, and formation stress difference affect vertical fracture propagation. The results show that interface fractures hinder the primary fracture propagation through beds but contribute to reducing the pressure for hydraulic fracture propagation, thereby promoting the formation of fracture network. High displacement and low viscosity of fracturing fluid can promote fracture propagation through beds and accelerate the opening of interface fractures. When the mudstone-sandstone elastic modulus ratio is less than 0.6, the mudstone barrier has a significant shielding effect, and the hydraulic fractures are primarily reverse-H-shaped and weak in prorogation through beds. When the formation stress difference is greater than the tensile strength difference between mudstone and sandstone, fractures propagate greatly in vertical direction, which can serve as a preliminary criterion for assessing the potential of hydraulic fractures to propagate through beds. Table and Figures | Reference | Related Articles | Metrics

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Models for Conductivity and Productivity of Hydraulic Fractures in Tight Oil Reservoirs in Sedimentary Rocks WANG Xiaobing, HU Yanshe, LI Sen, CHEN Min, WANG Lu, ZHU Chenyang Xinjiang Petroleum Geology    2023, 44 (4): 442-449.   DOI: 10.7657/XJPG20230408 Abstract （250）   HTML （3）    PDF（pc） （653KB）（385）       Knowledge map    Save In order to clarify the variation in the conductivity of different types of sedimentary rocks after fracturing, post-frac conductivity tests were conducted on the sedimentary rocks such as turbidite, beach-bar sandstone, and sandy conglomerate to identify the relationship between lithology and conductivity, and a conductivity model was constructed. The conductivity model was then incorporated into the primary fracture pressure control equation to obtain an analytical solution for primary fracture pressure. A semi-analytical model for predicting the productivity of multi-stage fractured horizontal wells was developed by using the distributed volume source method. The new productivity model was applied to the tight oil reservoirs in the Chaoyanggou oilfield in the periphery of Changyuan, Daqing. It is found that the calculation errors from a numerical model, a productivity model without considering lithology and the new productivity model considering lithology are 6.5%, 22.7% and 4.6%, respectively. The new model focuses on the impact of different sedimentary rock lithologies on productivity, which can improve the accuracy of productivity prediction for tight oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Experimental Study on CO2 Flooding and Storage in Chang 8 Ultra-Low Permeability Reservoir in District Huang 3，Jiyuan Oilfield CHEN Xiaodong, WANG Jin, SONG Peng, LIU Jian, YANG Weiguo, ZHANG Baojuan Xinjiang Petroleum Geology    2023, 44 (5): 592-597.   DOI: 10.7657/XJPG20230511 Abstract （244）   HTML （11）    PDF（pc） （630KB）（379）       Knowledge map    Save In order to determine CO2 flooding and storage mechanisms in the ultra-low permeability reservoir in Jiyuan oilfield, long core experiments were performed to understand the performance of enhanced oil recovery (EOR) and CO2 storage under different flooding techniques. The results show that the CO2-water alternating injection after water flooding yields the highest recovery factor, followed by CO2-water alternating flooding, while continuous CO2 injection exhibits the lowest recovery factor. CO2 breakthrough is a crucial factor influencing recovery factor, and alternating injection can suppress gas channeling. CO2 is dominantly stored in the large pores of the reservoir, and the CO2-water alternating flooding is more conducive to CO2 storage in the small pores than pure CO2 flooding. Continuous CO2 injection, CO2-water alternating flooding, CO2-water alternating injection after water flooding, and CO2 injection after water flooding exhibit a descending order in CO2 storage efficiency. Table and Figures | Reference | Related Articles | Metrics

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Experiment on Collaborative Construction of Reservoir-Type Underground Gas Storage and Natural Gas Flooding: A Case Study of Sanjianfang Formation Reservoir in Pubei Oilfield SI Bao, YAN Qian, LIU Qiang, ZHANG Yanbin, FU Chunmiao, QI Huan Xinjiang Petroleum Geology    2023, 44 (3): 321-326.   DOI: 10.7657/XJPG20230308 Abstract （351）   HTML （17）    PDF（pc） （563KB）（378）       Knowledge map    Save There are scarce researches on the prediction of collaborative underground gas storage (UGS) capacity and the timing of conversion from the collaborative construction stage to the UGS construction stage. Through core displacement experiments and overburden porosity/permeability experiments, the impacts of long-term water flooding and multiple cycles of gas flooding on UGS capacity were studied. By using the full-diameter core samples from the Sanjianfang formation in Pubei oilfield, an experiment on the whole process of UGS capacity expansion through oil production followed by collaborative UGS operation was carried out for the first time, to identify the influences of multiple cycles of gas flooding on storage capacity, time of capacity establishment, volume proportion of working gas, and recovery rate under two modes (constant-pressure production and regular production). The results show that both long-term water flooding and multiple cycles of gas flooding can improve reservoir properties and can be considered as the factors for increasing UGS capacity. As the number of injection-production cycles increases, the incremental capacity decreases and the working gas volume proportion increases under the two modes. The UGS capacity is basically established after the sixth injection-production cycle under constant-pressure production and after the tenth injection-production round under regular production, with the recovery rate not increasing further. The recovery rate under constant-pressure production is 0.34% higher than that under regular production. Table and Figures | Reference | Related Articles | Metrics

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Practice of Water Injection Development in Ultra-Deep Fault-Controlled Fractured-Vuggy Reservoirs in Shunbei Oilfield LI Xiaobo, WEI Xuegang, LIU Xueli, ZHANG Yixiao, LI Qing Xinjiang Petroleum Geology    2023, 44 (6): 702-710.   DOI: 10.7657/XJPG20230609 Abstract （273）   HTML （8）    PDF（pc） （1673KB）（375）       Knowledge map    Save The geological and development characteristics of ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield were comprehensively analyzed, and insufficient natural energy was determined to be the main reason for the rapid production decline and formation oil degassing in the weakly volatile oil reservoirs in the Shunbei No.1 fault zone. Through numerical simulation, it is clarified that water injection is the optimal development method currently. The research results show that gravity differentiation is the main mechanism of water injection in the ultra-deep fault-controlled fractured-vuggy reservoirs in Shunbei oilfield, and water injection can effectively restore formation energy. The waterflooding connectivity and energy balance capability in the fault zone’s pull-apart segments are much stronger than those in the compression segments. Water injection development of the ultra-deep fault-controlled fractured-vuggy reservoirs features rapid water channeling along fault zone and small swept area. Water injection enables good development effect, with the reservoir pressure restored by 14.78 MPa averagely, the annual decline rate of the block decreasing from 48.6% to 15.9%, and the staged cumulative oil production increased by 13.10×104 tons. Table and Figures | Reference | Related Articles | Metrics

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Comprehensive Determination of Oil-Water Boundary in Eastern Transitional Zone of Daqing SN Oilfield LIANG Yu, YANG Huidong, FU Xiandi, CAI Dongmei, WANG Yanhui, SUN Yanmin Xinjiang Petroleum Geology    2024, 45 (2): 213-220.   DOI: 10.7657/XJPG20240210 Abstract （244）   HTML （17）    PDF（pc） （4907KB）（369）       Knowledge map    Save In order to determine the oil-water contact in the eastern transitional zone of the Daqing SN oilfield, based on the drilling, logging, and seismic data, together with the core oil occurrence analysis and the reinterpretation of oil/water layers in existing wells, a comprehensive method for determining the oil-water boundary in the extension zone of structural reservoirs was discussed by using the techniques such as hydrocarbon detection through post-stack seismic attributes based on dual-phase medium theories and fluid identification based on pre-stack seismic waveform indication inversion. The oil-water interface in the study area exhibits the following characteristics: (1) oil patch or higher level occurs in cores; (2) oil layers or oil-water layers are extrapolated on the basis of logging interpretation; (3) in post-stack attributes, the energy ratio of low frequency to high frequency is greater than 0.85; and (4) the predicted water saturation from pre-stack inversion is less than 75%. Therefore, following the principle of “depth of oil-water contact determined by well data, boundaries of oil and water distribution determined by seismic data, and validation by well performance”, and through comprehensive analysis from point to line, plane, and then space, the final position of the oil-water interface was determined. The research results effectively guide the extention deployment and evaluation in the study area, and are referential for delineating the oil-water boundaries in similar structural reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Comparison of Petroleum Resources/Reserves Classification Systems ZHOU Liming, ZHANG Daoyong, JIANG Wenli, ZHANG Chen, ZHANG Chenshuo, ZHANG Haoze, ZHENG Yuanyuan Xinjiang Petroleum Geology    2023, 44 (6): 751-756.   DOI: 10.7657/XJPG20230614 Abstract （458）   HTML （11）    PDF（pc） （516KB）（361）       Knowledge map    Save To further understand the petroleum resources/reserves classification system and its development trend, China’s petroleum resources/reserves classification system is reviewed with respect to its development history and characteristics, and compared with the Petroleum Resources Management System (PRMS) and the United States Securities and Exchange Commission’s standard classification system. The research reveals that the three systems are significantly different in evaluation purpose, reserves definition, and evaluation approach. China’s classification system focuses on the discovered petroleum originally-in-place, emphasizes the total quantity of resources, and serves for the overall benefits and long-term planning of petroleum exploration and development. PRMS, a project-based classification system, facilitates international communication and cooperation, and considers the attributes of petroleum as both resource and asset. It centers on the remaining commercially recoverable reserves and emphasizes the commercial value of resources. The SEC standard classification system provides a benchmarking platform for petroleum companies, and ensures consistent disclosure of reserves information to the public. It also centers on remaining economically recoverable reserves, paying more attention to the attribute of petroleum as asset. These classification systems maintain their distinct features while borrowing from and integrating with each other. Table and Figures | Reference | Related Articles | Metrics

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Rock Mechanical Properties and Energy Evolution of Continental Shale Reservoirs GAN Renzhong, XIONG Jian, PENG Miao, LIU Xiangjun, LIANG Lixi, DING Yi Xinjiang Petroleum Geology    2023, 44 (4): 472-478.   DOI: 10.7657/XJPG20230412 Abstract （248）   HTML （3）    PDF（pc） （978KB）（361）       Knowledge map    Save The continental shale reservoirs in the Lucaogou formation of the Jimsar sag in the Junggar basin are lithologically composed of dolomite, argillaceous dolomite, dolomitic mudstone, dolomitic siltstone, and siltstone. The mechanical properties and energy evolution of the continental shale were investigated through laboratory mechanical experiments. The results show that there are significant differences in the rock mechanical properties of different lithologies within the shale reservoir. The compressive strengths of dolomite, dolomitic siltstone, siltstone, argillaceous dolomite and dolomitic mudstone are 112.09 MPa, 98.20 MPa, 85.98 MPa, 81.28 MPa and 58.30 MPa, respectively. With the increase of confining pressure, the brittleness of the rock samples of the continental shale reservoirs decreases and the ductility increases. The rock samples with different lithologies have different energy levels at the peak strength, indicating strong heterogeneity. Furthermore, the total energy, elastic energy and dissipated energy of the rocks with same lithologies under triaxial compression are higher than those under uniaxial compression. Table and Figures | Reference | Related Articles | Metrics

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Sensitivity Analysis of Injection-Production Parameters for CO2 Huff-n-Puff Flooding and Storage in Tight Oil Reservoirs：A Case From Typical Tight Reservoirs of Chang 7 Member，Ordos Basin DING Shuaiwei, ZHANG Meng, LI Yuanduo, XU Chuan, ZHOU Yipeng, GAO Qun, YU Hongyan Xinjiang Petroleum Geology    2024, 45 (2): 181-188.   DOI: 10.7657/XJPG20240206 Abstract （350）   HTML （15）    PDF（pc） （1331KB）（360）       Knowledge map    Save CO2 huff-n-puff in tight oil reservoirs can enhance oil recovery and store CO2. The existing researches on CO2 huff-n-puff flooding and CO2 storage in tight oil reservoirs rarely take parameters related to CO2 storage capacity as evaluation indicators. Taking typical tight reservoirs in the seventh member of Yanchang formation (Chang 7 member) in the Ordos basin as an example, through numerical simulation, six injection-production parameters (huff-n-puff timing, injection rate, injection time, soaking time, production time and huff-n-puff cycle) and three evaluation indicators (oil exchange rate, CO2 retention coefficient, and flooding-storage synthesis coefficient) were selected. Using single-factor control variable method and multi-factor orthogonal experimental design, together with range analysis method, the sensitivities of the six injection-production parameters to three evaluation indicators were analyzed. The results suggest that in the CO2 flooding-dominant stage, it is recommended to set an injection time of 30-60 d, injection rate of 0.001 0-0.003 0 PV/d, and huff-n-puff timing of less than 0.5 a; in the CO2 storage-dominant stage, it is recommended to set a production time of 30-230 d, injection rate of 0.007 5-0.010 0 PV/d, and injection time of 145-180 d; and in the synergistic optimization stage of CO2 flooding and storage, it is recommended to set an injection time of 30-65 d, huff-n-puff timing of 6 months earlier, and soaking time of 10-20 d. Table and Figures | Reference | Related Articles | Metrics

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Enhanced Oil Recovery by CO2 Huff-n-Puff in Tight Oil Reservoirs in Mazhong Block，Santanghu Basin LI Shirui, ZHAO Kai, XU Jiangwei, Murzhaty ASKUR, XU Jinlu, ZHANG Xing Xinjiang Petroleum Geology    2023, 44 (5): 572-576.   DOI: 10.7657/XJPG20230508 Abstract （293）   HTML （8）    PDF（pc） （596KB）（350）       Knowledge map    Save The tight oil reservoirs in the MZ block of the Santanghu basin are characterized by medium-high porosity, ultra-low permeability, and high oil saturation. In the initial development stage, high production rate was achieved by virtue of volume fracturing in horizontal wells, but declined greatly. In the late stage, the reserves were effectively produced through water huff-n-puff. After years of development, the effect of water huff-n-puff became worse. The current recovery percent of reserves is only 5.6%. For further enhancing the oil recovery, CO2 huff-n-puff experiments were conducted in five horizontal wells. The results show that CO2 plays a pivotal role in enhancing recovery in tight oil reservoirs through the mechanisms such as swelling, energy augmentation, viscosity reduction, light component extraction, and fluid mobility improvement. The impact of CO2 varies throughout the injection, soaking, and production stages, leading to alteration in crude oil properties. CO2 can enhance oil recovery and also demonstrate a high storage rate, offering both economic and social benefits. CO2 huff-n-puff is adaptable and promising for tight oil reservoir development. Table and Figures | Reference | Related Articles | Metrics

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Horizontal Well Infilling and Water Flooding Tracking Adjustment for Production Increase in Low Permeability Reservoirs in X Oilfield ZHOU Jiamei Xinjiang Petroleum Geology    2023, 44 (5): 577-582.   DOI: 10.7657/XJPG20230509 Abstract （234）   HTML （9）    PDF（pc） （552KB）（349）       Knowledge map    Save In X oilfield, the reservoirs exhibit poor physical properties, a small number of layers vertically, and the presence of small faults in complex distribution, which lead to poor effect of vertical well development and ineffecient displacement of the existing well pattern. Based on the successful development of pre-existing horizontal wells and infilled horizontal wells in the pilot test in 2014, a study was conducted on horizontal well infilling and tracking adjustment techniques in the areas with inefficient waterflooding by vertical wells and in the unswept areas near fault zones. Through logging-seismic combination and comprehensive dynamic-static analysis, the areas with stable reservoirs, low water-out risk, and enriched remaining oil were identified for well infilling. By optimizing the orientation and horizontal section length of horizontal wells, the fracturing density and fracture length were optimized to enhance the productivity of horizontal wells. The injection-production process was optimized by implementing the waterflooding tracking adjustment strategy of early-stage intermittent water injection and weak injection via the injector in an adjacent row + strong injection via the injector in a row apart. Following these approaches, a total of 19 infilling horizontal wells were drilled in the X oilfield in 2019, achieving a sandstone-encountered rate of 83.0%. The initial daily oil production per well reached 7.4 t, with a comprehensive water cut of 28.8%. An effective displacement system was established, resulting in an increase in the oilfield’s production rate from 0.8% to 1.5%, and improving the overall development effect of X oilfield. Table and Figures | Reference | Related Articles | Metrics

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Fluid Saturation Correction Method for Sealed Coring Wells in Thin Oil Reservoirs ZHU Yongxian, YAO Shuaiqi, ZHANG Yanbin, HAN Jifan, ZHAO Ruiming Xinjiang Petroleum Geology    2023, 44 (3): 359-364.   DOI: 10.7657/XJPG20230314 Abstract （312）   HTML （21）    PDF（pc） （576KB）（348）       Knowledge map    Save To determine the fluid saturation under the formation conditions of thin oil reservoirs in the Turpan-Hami basin, based on the data of sealed coring in the Wenmi oilfield and Shanshan oilfield, physical simulation control experiments were performed to simulate the influences of depressurized degassing and evaporation losses on core fluid saturation during coring, and then a fluid saturation correction model suitable for sealed coring of thin oil reservoirs in the Turpan-Hami basin was established. The limit of depressurized degassing loss is clarified, that is, when the initial water saturation is greater than 88% or less than 33%, the depressurized degassing loss is weak and negligible. The new model also takes into account the effects of pore volume change, extraction loss in saturation experiments, and evaporation loss under different flooding conditions on saturation measurement, effectively improving the correction accuracy. The error between the oil saturation derived from the model and that from logging interpretation is 0.17%. Table and Figures | Reference | Related Articles | Metrics

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A Data-Driven Method to Reconstruct Reservoir Flow Field FENG Gaocheng, LI Jinman, LIU Yuming, YIN Yanjun, WEI Zhiyong, ZHANG Qiang, MENG Fankun Xinjiang Petroleum Geology    2023, 44 (5): 598-607.   DOI: 10.7657/XJPG20230512 Abstract （318）   HTML （10）    PDF（pc） （4395KB）（346）       Knowledge map    Save The production stabilization and water-cut control of multilayer clastic reservoirs have always been a hot topic in oilfield development. At the medium-high water-cut development stage, oilfields usually exhibit obvious decline of production, scattered distribution of remaining oil, and prominent development conflicts between layers. For these oilfields, there is an urgent need for appropriate optimization and control methods to achieve sustained and stable production. Based on the Bayesian posterior probability method and reservoir streamline simulator, by applying a random maximum likelihood function, the history matching problem was solved and a space data set was constructed. Furthermore, by using finite-memory quasi-Newton gradient method, the data space set was inverted to predict the future. The transient flow velocity of the reservoir flow field was characterized by integrating Pollock streamline tracing method. Thus, a reservoir flow field reconstruction method based on data space inversion was proposed. This method allows real-time optimization of the reservoir injection-production parameters without the need for complex and repetitive calculations. It overcomes the limitations of traditional optimization methods in finely describing flow field evolution and fills the gap in the application of data space inversion in flow field optimization. Taking reservoir B in the Bohai oilfield as an example, the proposed method was used to reveal the mechanism of the reservoir injection-production structure optimization and intuitively demonstrate the process of reservoir flow field optimization. The field application results show that the overall water cut of the reservoir is relatively steady, the scattered remaining oil in the target flooding unit is effectively exploited, and the swept area of water flooding expands by 24.85%, indicating a remarkable flow field control effect. These digitalization efforts for reservoirs will provide valuable reference for the development and data-driven flow field control of similar medium-high water-cut oilfields. Table and Figures | Reference | Related Articles | Metrics

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Regulation of CO2 on Physical Properties of Heavy Oil Reservoir and EOR of CO2-Assisted Steam Flooding WEI Hongkun, WANG Jian, XU Tianhan, LU Yuhao, ZHOU Yaqin, WANG Junheng Xinjiang Petroleum Geology    2024, 45 (2): 221-227.   DOI: 10.7657/XJPG20240211 Abstract （269）   HTML （10）    PDF（pc） （862KB）（344）       Knowledge map    Save It is necessary to improve development efficiency of heavy oil reservoirs in the late stage of steam flooding. In this paper, considering the application of the technology of carbon capture, utilization and storage, and enhanced oil recovery （CCUS-EOR）, and taking the J6 block of Karamay oilfield as an example, four components of heavy oil were analyzed before and after CO2 treatment, and the changes in saturation pressure, expansion coefficient, viscosity, and density were tested to investigate the regulation of CO2 on physical properties of heavy oil. Parallel core physical simulation experiments were performed to understand the performance of CO2-assisted steam flooding in improving oil recovery. The results show that the viscosity of heavy oil is mainly affected by the contents of resin and asphaltene. As the volume of CO2 dissolved in heavy oil increases, the saturation pressure rises from 2.08 MPa to 11.11 MPa, and the expansion coefficient shows an upward trend, with an increase of 7.6%; meanwhile, the viscosity and density of the heavy oil decrease by 30.5% and 3.5%, respectively. This indicates that CO2 can effectively improve the physical properties of heavy oil by optimizing the expansion coefficient, viscosity, and density while increasing the saturation pressure. In addition, the application of CO2-assisted steam flooding enables the recovery of heavy oil to increase from 38.55% to 46.46% under the effect of CO2 dissolution for viscosity reduction and demulsification, representing an increase of 7.91% compared to pure steam flooding. This study provides a theoretical and experimental basis for the application of CO2-assisted steam flooding in enhancing the recovery of heavy oil, offering insights for similar heavy oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Diagenetic Evolution and Its Significance of Zeolites in Sedimentary Rocks ZUO Rusi, ZENG Xiang, CAO Zhongxiang, CAI Jingong, ZHANG Kuihua, ZHANG Guanlong Xinjiang Petroleum Geology    2023, 44 (5): 543-553.   DOI: 10.7657/XJPG20230505 Abstract （340）   HTML （19）    PDF（pc） （4982KB）（342）       Knowledge map    Save Zeolites are widely distributed in sedimentary rocks, and they are diverse in genesis and complex in evolution characteristics. Controlled by sedimentary environment and diagenetic conditions, zeolites of different genesis are formed in different diagenetic sequences, and exhibit distinct combinations, occurrences, and frameworks. Zeolites can be divided into primary zeolites, hydrothermal zeolites, volcanic-altered zeolites, and mineral-transformed zeolites. Zolite framework can be characterized by the Si/Al ratio, based on which the zeolites are categorized into high-silica and low-silica zeolites. Zeolites play a strong catalytic role in hydrocarbon generation from source rocks. High-silica zeolites have lower catalytic activity, but slower deactivation rate than low-silica zeolites, and exhibit good selectivity. Zeolite cementation and dissolution have constructive and destructive effects on reservoirs, respectively. In different diagenetic sequences, zeolites show varying impacts on reservoir properties. The transformation of clay minerals to zeolites enhances the brittleness and water sensitivity of shale. Brittleness will increase the fracability of shale reservoirs, while water sensitivity will reduce reservoir permeability. Table and Figures | Reference | Related Articles | Metrics

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Distribution Patterns and Significance of Salt in Deep Cretaceous Subsalt Reservoirs in Kuqa Depression，Tarim Basin LUO Danting, LUO Jinglan, DENG Chao, NIAN Tao, HAN Jianfa, CHENG Daojie, YUAN Long Xinjiang Petroleum Geology    2024, 45 (1): 1-12.   DOI: 10.7657/XJPG20240101 Abstract （329）   HTML （20）    PDF（pc） （2908KB）（339）       Knowledge map    Save The Cretaceous Bashijiqike formation in the Kelasu structural belt in the Kuqa depression of Tarim basin hosts a number of high- and steady-yield subsalt gas reservoirs in ultra-deep，high-temperature，and overpressure environment. For these subsalt tight sandstone reservoirs，the higher the porosity，the higher the salt content and the lower the apparent resistivity. The distribution of salt in the reservoirs not only significantly affects fluid identification but also has a noticeable impact on the reservoir physical properties. The distribution of salt in the subsalt reservoirs in the Bashijiqike formation were systematically analyzed based on the data of cores，cast thin sections，scanning electron microscopy，salt content，and conventional logs. According to the differences in salt content，resistivity，and salt source，three distribution patterns of salt in subsalt reservoirs were proposed: top source，lateral source and local sealing. For the top and lateral source patterns，the reservoir resistivity is only affected by salt content. In the reservoirs with the top source pattern，the salt content shows a vertical zonality，and the reservoir resistivity increases as the salt content decreases. In the reservoirs with the lateral source pattern，the salt content shows a lateral zonation，and the reservoir resistivity shows a trend of high to low and then to high value from the edge of structural belt towards its center. In the reservoirs with the local sealing pattern，the resistivity is influenced jointly by stress and salt content，and changes greatly because the distribution of salt content is sporadic. According to well logging responses，the reservoir is divided into intervals for each pattern. In an ideal top source pattern，the reservoir comprises a salt interval，a mudstone barrier，an interval strongly affected by saturated salt，an interval strongly affected by unsaturated salt，a transition interval affected by unsaturated salt，and a salt-unaffected interval from top to bottom. In an ideal lateral source pattern，there are several intervals affected by oversaturated salt. In an ideal local sealing pattern，the reservoir includes a salt interval，a mudstone barrier，a salt-unaffected interval with strongly compressed stress，a salt-stress hybrid affected interval，and a salt-stress unaffected interval. Table and Figures | Reference | Related Articles | Metrics

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Layered Structural Deformation Characteristics of Kuqa Foreland Thrust Belt XU Zhenping, YANG Xianzhang, NENG Yuan, DUAN Yunjiang, ZHANG Wen, HU Jianning, ZHANG Mengyang Xinjiang Petroleum Geology    2024, 45 (5): 505-515.   DOI: 10.7657/XJPG20240501 Abstract （255）   HTML （14）    PDF（pc） （5903KB）（337）       Knowledge map    Save The seismic data acquired from Kuqa foreland thrust belt is characterized by low signal-to-noise ratio and high interpretive ambiguity. By using high-resolution 3D seismic data, drilling and lab hydrocarbon analysis data, the stratigraphic assemblages of Kuqa foreland thrust belt were systematically described, the structural model was detailedly interpreted, and the hydrocarbon accumulation system was deeply analyzed. It is found that the Kuqa foreland thrust belt develops two sets of detachment layers: Paleogene and Neogene gypsum-salt rocks, and Triassic and Jurassic coal measures, all of which feature stratified detachment, vertical stacking, and multiphase deformation. Detachment folds in caprocks are found in the shallow structures, while basement-involved imbricate thrust structures are developed in deep strata. Detachment plastic deformation occured in the gypsum-salt and coal layers. Faulting occured in three phases including Caledonian, late Hercynian-Indosinian, and Yanshanian-Himalayan. The late Hercynian-Indosinian tectonics controlled the Mesozoic sedimentation, showing a north-to-south onlap thinning feature. Layered structural deformation in the Kuqa foreland thrust belt governs the stratified accumulation and migration of hydrocarbons. Hydrocarbons in the strata above the coal seam predominantly originated from the Jurassic source rocks, whereas oil and gas in the strata below the coal seam mainly came from the Triassic source rocks which contributs 60% of the hydrocarbons. A substantial quantity of hydrocarbon remains trapped in the formation below the coal layer. Table and Figures | Reference | Related Articles | Metrics

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Water Invasion Characteristics and Residual Gas Distribution in Fractured-Porous Carbonate Reservoirs XIE Peng, CHEN Pengyu, ZHAO Hailong, Xu Jianting Xinjiang Petroleum Geology    2023, 44 (5): 583-591.   DOI: 10.7657/XJPG20230510 Abstract （305）   HTML （14）    PDF（pc） （1507KB）（333）       Knowledge map    Save Water channeling often occurs in gas wells during the production of fractured-porous carbonate gas reservoirs with edge/bottom water. A simulation experiment on water invasion mechanism was performed by using a visualized microscopic model and under the formation conditions simulated by the high-temperature high-pressure online nuclear magnetic resonance detection system, to study the distribution of residual gas. The distribution of intrusive water was characterized by the T2 spectrum obtained from pulse sequence testing. The results show that the pore-throat ratio, coordination number, and fracture width have significant impacts on water invasion and residual gas distribution. In porous reservoirs, invasion water first enters large pores and then small pores. In fractured-porous reservoirs, where the distribution of fractures has an influence on the water invasion mode, intrusive water enters the fractures and then the medium-large pores. In water-invaded porous reservoirs, 37.7% of the residual gas exists in small pores, and 62.3% in large pores. In water-invaded fractured-porous reservoirs, a little residual gas is in fractures, 4.8%-26.8% of the residual gas in small pores (where the residual gas is difficult to recover), and 94.7%-69.2% in medium-large pores. The residual gas saturation index was evaluated with the water invasion proportion in medium-large pores as an objective function, and the main controlling factors include fracture penetration degree, water volume ratio, fracture width and gas production rate. The well trajectory should be optimized in the fracture zones and kept away from the fractures that communicate with edge/bottom water. Furthermore, well production rate should be optimized to delay water breakthrough. After water breakthrough in gas wells, the gas production rate should be appropriately reduced to drive intrusive water into medium-large pores and reduce residual gas in the medium-large pores, thus enhancing the gas recovery. Table and Figures | Reference | Related Articles | Metrics

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Thermal Evolution History of Shale in Da’anzhai Member and Its Petroleum Geological Significance in Central Sichuan Basin JIANG Qijun, LI Yong, XIAO Zhenglu, LU Jungang, QIN Chunyu, ZHANG Shaomin Xinjiang Petroleum Geology    2024, 45 (3): 262-270.   DOI: 10.7657/XJPG20240302 Abstract （298）   HTML （321）    PDF（pc） （821KB）（331）       Knowledge map    Save The Da’anzhai member of the Lower Jurassic Ziliujing formation is the most favorable layer for the development of continental shale oil in the Sichuan basin, and has huge potential in shale oil exploration. However, there is a lack of systematic research on the thermal evolution history of this formation. Using the simulation system for petroliferous basins, the differences in the thermal evolution and hydrocarbon generation of the shales in Da’anzhai member between the northern part and the central part of the central Sichuan basin were comparatively analyzed, and their impacts on shale oil enrichment were discussed. The thermal evolution degree of the shale of Da’anzhai member in the study area gradually increases from southwest to northeast, and the shale can be divided into a highly matured zone and a matured zone on the plane. The highly matured zone is located in the northern part of the study area, with vitrinite reflectance ranging from 1.3% to 1.7%, mainly developing Type Ⅲ organic matter. The early oil generation occured in the early Late Jurassic, and the oil generation peaked at the end of Late Jurassic, experiencing two phases of hydrocarbon generation. The matured zone is located in the central to southern parts of the study area, with vitrinite reflectance ranging from 0.9% to 1.3%, mainly developing Type Ⅱ1-Ⅱ2 organic matter. The sedimentary thickness of the Jurassic is relatively small, the early oil generation occured at the end of the Late Jurassic and reached the peak in the Early Cretaceous, with only one period of hydrocarbon generation. Compared with the northern area, a large set of organic-rich shales deposited in the central area, which provieded a solid material basis for shale oil in the Da’anzhai member. However, the tectonic uplift and stratum erosion since the Paleogene posed a certain destructive effect on the preservation of oil and gas in this area. Table and Figures | Reference | Related Articles | Metrics

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Seismic Identification of Strike-Slip Fault Damage Zones Based on Structure Tensor Analysis: A Case Study of Ultra-Deep Carbonate Rocks in Fuman Oilfield WANG Rujun, SUN Chong, YUAN Jingyi, LIU Ruidong, WANG Xuan, MA Yinglong, WANG Xupeng Xinjiang Petroleum Geology    2024, 45 (4): 475-482.   DOI: 10.7657/XJPG20240412 Abstract （199）   HTML （7）    PDF（pc） （4592KB）（329）       Knowledge map    Save Abundant hydrocarbon resources have been discovered in the ultra-deep Ordovician carbonate strike-slip fault damage zones of the Tarim basin. However, these zones cannot be accurately characterized due to the low resolution of seismic data obtained from the ultra-deep layers, thereby restricting the efficient evaluation and target selection of the strike-slip fault-controlled hydrocarbon reservoirs. According to the seismic responses of the strike-slip fault damage zones in the Fuman oilfield, and based on the structure-oriented filtering, the eigenvalues and eigenvectors were calculated by using the structure tensor method, and the projection energy along the fault direction was enhanced by selecting appropriate time windows and stacking vertical thicknesses, which accentuates the strike-slip fault damage zones, enabling a clearer delineation of their boundaries and intensities. The results show that this method provides a clearer depiction of strike-slip fault distribution, allows for the identification of smaller-scale faults, and effectively delineates the width and intensity of ultra-deep carbonate strike-slip fault damage zones, which can be used to evaluate the development degree of the strike-slip fault damage zones. This method can be employed in trap evaluation, well placement, trajectory design, and well monitoring, which will improve drilling success rates and individual well productivity. Table and Figures | Reference | Related Articles | Metrics

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Shale Gas Accumulation Characteristics of Wufeng Formation-Longmaxi Formation in Luzhou Area LIU Honglin, WANG Huaichang, LI Xiaobo Xinjiang Petroleum Geology    2024, 45 (1): 19-26.   DOI: 10.7657/XJPG20240103 Abstract （281）   HTML （16）    PDF（pc） （3755KB）（326）       Knowledge map    Save To find favorable areas for shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area of the Sichuan basin，fluid inclusion detection，shale micropore observation，and gas bubble-pore evolution simulation were performed. On this basis，the tectonic burial process and the hydrocarbon generation and thermal evolution process in the Luzhou area were investigated，and the characteristics and patterns of shale gas accumulation in the Luzhou area were summarized. The results show that the Wufeng formation-Longmaxi formation in the Luzhou area has a set of thick organic-rich shales. During the Permian to Early Triassic，oil was generated from the shale which then experienced two tectonic uplift events during the Middle Triassic and the Yanshanian-Himalayan movement. The gentle uplifting of the formation in the Middle Triassic did not induce extensive hydrocarbon loss，while the uplifting during the Yanshanian-Himalayan movement was later than that of the structure in the southeastern part of Sichuan basin，with a small magnitude，which was favorable for shale gas preservation. The organic pores in the shales were developed as a result of the fact that the uplifting with short duration and low intensity in the Middle Triassic did not cause massive hydrocarbon expulsion，leaving a large quantity of liquid hydrocarbons in the reservoirs and allowing well preservation of organic pores during the Late Triassic to Middle Cretaceous，when liquid hydrocarbons were cracked to gas along with deep burial，and the strata were universally under overpressure. Although the Triassic uplifting in the Luzhou area was short-lived and of low intensity，the simulation results suggest that it led to crude oil thickening and gas pore formation，which was beneficial for shale gas accumulation. The uplifting in the Indosinian period resulted in crude oil thickening，facilitating shale gas accumulation. The late strata uplifting together with a short period of shale gas loss，developed low-angle bedding fractures，and fewer vertical fractures all contribute to the formation of overpressured shale gas accumulation zones in the Luzhou area. The proposed patterns of shale gas accumulation in the Wufeng formation-Longmaxi formation in the Luzhou area are of great reference significance in guiding oil and gas exploration for similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Stimulation Capability of Low-Medium Maturity Shale Oil Reservoir During In-Situ Conversion WEI Zijian, SHENG Jiaping, ZHANG Xiao Xinjiang Petroleum Geology    2023, 44 (4): 485-496.   DOI: 10.7657/XJPG20230414 Abstract （320）   HTML （3）    PDF（pc） （6584KB）（323）       Knowledge map    Save In China, the abundant low-medium maturity shale oil resources present a huge potential for in-situ conversion. To evaluate the stimulation capability of low-medium maturity shale oil reservoir during in-situ conversion, in-situ heating experiments were conducted on the typical low-medium maturity shales from Chang 7 member of Yanchang formation in Ordos basin and Lucaogou formation of Jimsar sag in Junggar basin. By using techniques such as nuclear magnetic resonance testing, vertical optical microscopy observation, computerized tomography scanning, and pulse decay gas permeability measurement, the dynamic changes in nano-scale pores, thermal fractures, porosity and permeability under high-temperature and high-pressure conditions during in-situ conversion were monitored in a real-time manner. The kerogen pyrolysis-induced fractures and the hydrocarbon generation pressurization effect are key factors for significantly improving the microstructure and reservoir properties. Once the temperature exceeds the threshold (400°C), the extension, density, complexity and connectivity of fractures within the shale significantly increase due to kerogen pyrolysis and thermal expansion of hydrocarbons. Secondary pores with diameters ranging from 2 to 50 nm become dominant in the pore structure. Under in-situ stress, the porosities of the two types of shale can be increased by 3.65 and 2.73 times, respectively, while the permeability can be increased by 624.09 and 418.37 times, respectively. Permeability is more stress-sensitive in the high-temperature stage than in the low-temperature stage. Shale reservoir with lower in-situ stress and higher kerogen content exhibit higher stimulation capability and higher thermal fracturing and thermal permeability enhancement capabilities during in-situ conversion. Table and Figures | Reference | Related Articles | Metrics

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Seismic Frequency Enhancement Processing Based on Multi-Layer Residual Network and Its Application to Identification of Thin Reservoirs ZHANG Wenqi, LI Chunlei Xinjiang Petroleum Geology    2024, 45 (1): 102-108.   DOI: 10.7657/XJPG20240114 Abstract （236）   HTML （10）    PDF（pc） （4839KB）（321）       Knowledge map    Save The seismic frequency enhancement processing method based on multi-layer residual network combines high-frequency well logging information with seismic data through an intelligent network. This method effectively improves vertical resolution while maintaining lateral continuity，facilitating the identification of thin reservoir beds. In the AMH area，the seismic data processed by conventional techniques enable only the identification of carbonates thicker than 30 m，but not of thinner beds. The seismic frequency enhancement processing method based on multi-layer residual network was proposed for application in this area. First，a training was performed using the multi-layer residual network，a deep learning network，with the near-wellbore seismic amplitudes as training data and the relative wave impedance data from well logging as training labels. Thus，a predictive model for relative wave impedance curve was obtained. By using seismic data as input，the deep network training model was solved to obtain a relative wave impedance data cube，and then a data cube of reflection coefficient corresponding to the frequency-enhanced seismic data cube was obtained. After analyzing the geological conditions of the target area，appropriate wide-frequency wavelet was extracted after calibration，and then convolved with the reflection coefficient cube，so that a frequency-enhanced seismic data cube was obtained. Reservoir inversion was performed using the frequency-enhanced seismic data cube. The inversion results are of high resolution vertically，well matching the main target beds，and can be identifiable and traceable laterally. Ultimately，the identification of thin beds in the AMH area was realized through the application of high-resolution seismic inversion results. The seismic frequency enhancement processing based on multi-layer residual network together with the corresponding high-resolution model inversion can identify beds thicker than 10 m in the AMH area. This method effectively addresses the problem of infeasible thin bed identification using low-resolution seismic data，and improves the accuracy in predicting thin beds. It is referential for identifying similar thin beds. Table and Figures | Reference | Related Articles | Metrics

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Development Characteristics and Potential Tapping Strategies of Massive Sandstone Reservoirs With Bottom Water in Tahe Oilfield LIU Lina, CAO Fei, LIU Xueli, TAN Tao, ZHENG Xiaojie, LIU Rui Xinjiang Petroleum Geology    2023, 44 (4): 450-455.   DOI: 10.7657/XJPG20230409 Abstract （362）   HTML （8）    PDF（pc） （734KB）（318）       Knowledge map    Save The massive sandstone reservoirs with bottom water in the Tahe oilfield are characterized by relatively thin oil layers. After oil wells are put into production, water breakthrough, water-cut rise, and production decline occur rapidly, posing challenges for stable production. Through the analysis of reservoir development characteristics, the water-cut rise patterns of wells were classified, and the remaining oil distribution and its influencing factors were determined. The results indicate that the main factors affecting the distribution of remaining oil in bottom-water reservoirs are structure, interlayer, reservoir heterogeneity and development methods. Based on the distribution of remaining oil in bottom-water reservoirs in the high water-cut period, effective potential tapping strategies were proposed to improve development efficiency, including flow adjustment by controlling fluid, natural gas flooding, and CO2 flooding. Numerical simulations and field practices have demonstrated satisfactory results of these strategies, which provide valuable references for the development of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of Functional Mathematical Model for Production Cycle of Oil and Gas Reservoirs MEN Haiwen, ZHANG Jing, WEI Haijun, ZHAO Yang, GAO Wenjun Xinjiang Petroleum Geology    2023, 44 (3): 365-374.   DOI: 10.7657/XJPG20230315 Abstract （237）   HTML （19）    PDF（pc） （699KB）（312）       Knowledge map    Save The mathematical models for production cycle of oil and gas reservoirs were reviewed systematically. On this basis, the generalized functional production decline formula was introduced to replace the decline function in the generalized whole-process mathematical model for production cycle, and it is no longer necessary to determine the decline function according to the driving type and flow characteristics of the oil and gas reservoirs. Meanwhile, considering that the generalized whole-process mathematical model for production cycle can be integrated, the expressions of its increasing function items were summarized to form three types of increasing function expressions. When the composite time and undetermined parameters take different values, the new generalized whole-process mathematical model for production cycle can not only be converted into the basic mathematical models for various production cycles, but also form other new mathematical models for production cycle, possessing the general formula and extensibility in the whole-process mathematical model for production cycle. In order to reduce the difficulty in solving the undetermined parameters, five simplest and most common methods for solving the composite time formula and functional mathematical model for production cycle are given. The satisfactory application results verify that the new model is worthy of promotion in other oil and gas reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Geological Sweet Spots for Shale Oil in Fengcheng Formation in Well Maye-1, Mahu Sag LI Na, LI Hui, LIU Hong, CHEN Fangwen, YANG Sen, ZOU Yang Xinjiang Petroleum Geology    2024, 45 (3): 271-278.   DOI: 10.7657/XJPG20240303 Abstract （281）   HTML （9）    PDF（pc） （940KB）（308）       Knowledge map    Save The Fengcheng formation in the Mahu sag is a typical alkaline lacustrine deposit characterized by mixed provenance, complex lithology, overall oil possibility, and scattered sweet spots. To efficiently explore and develop the shale oil, it is necessary to optimize geological sweet spots for the shale oil. Based on the results of high-pressure mercury injection and rock pyrolysis experiments, the reservoir and shale oil mobility of the Fengcheng formation in Well Maye-1 were evaluated, a model for optimizing geological sweet spots for the shale oil was constructed, and the vertical distribution of geological sweet spots for the shale oil was assessed. The results show that porosity, total organic carbon content, brittle mineral content, and difference between free hydrocarbon content and 100 times of total organic carbon content are parameters for respectively evaluating the reservoir performance, oil-bearing property, brittleness, and shale oil mobility of the Fengcheng formation. A model for optimizing geological sweet spots for the shale oil was constructed by using these four parameters, with sweet spot factors for Class Ⅰ, Ⅱ, and Ⅲ shale oil geological sweet spots in Well Maye-1 being greater than 0.282 3, ranging from 0.011 1 to 0.282 3, and less than 0.011 1, respectively. Class Ⅰ shale oil geological sweet spots in the Fengcheng formation in Well Maye-1 are mainly distributed in the upper part of the second member of Fengcheng formation and in the third member of Fengcheng formation, with lithology dominated by mudstone and dolomitic mudstone. Table and Figures | Reference | Related Articles | Metrics

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NMR Logging-Based Productivity Analysis and Sweet Spot Evaluation for Shale Oil QIN Jianhua, LI Yingyan, DU Gefeng, ZHOU Yang, DENG Yuan, PENG Shouchang, XIAO Dianshi Xinjiang Petroleum Geology    2024, 45 (3): 317-326.   DOI: 10.7657/XJPG20240308 Abstract （294）   HTML （9）    PDF（pc） （1650KB）（296）       Knowledge map    Save Shale oil horizontal wells in the Lucaogou formation within the Jimsar sag vary greatly in productivity, with notable differences in water production rate. Main factors controlling this phenomenon remain unclear. Moreover, the existing sweet spot classification criteria fail to meet the requirements for fine development of shale oil in this area, and the interpretation of oil saturation and mobility based on the cutoff values from nuclear magnetic resonance (NMR) logging cannot realize precise identification of shale oil sweet spots. In this paper, based on the results of NMR logging and laboratory NMR testing, and through frequency division processing, NMR logging-based pore structure characterization by fluids, and elastic oil displacement simulation, the distribution of different types of fluids in shale oil reservoirs was characterized detailedly. The pore sizes for oil/water occurrence were delineated, and a model for evaluating movable oil amount was established to quantitatively characterize the fluid occurrence, pore size distribution, movable oil quantity, and other parameters. By integrating single-well testing and production data, the factors controlling horizontal well productivity were elucidated. The results show that horizontal well productivity is much more correlated to the large-pore light oil proportion (LOP) and movable oil porosity (MOP) than to porosity, oil saturation, NMR MOP and other parameters. The water influence index reflects the extent of formation water’s impact on shale oil flow, and given the same MOP, a smaller water influence index corresponds to a higher productivity and a lower water cut of a horizontal well. Based on large-pore LOP, water influence index and MOP, the shale oil sweet spots are classified into Class Ⅰ, Class Ⅱ and Class Ⅲ, with rapid decline in daily oil production and significant rise in water cut, which can serve as the basis for finely evaluating shale oil sweet spots in the Lucaogou formation. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of Rock Mechanical Parameter Profile to Tight Reservoirs in Yongjin Oilfield GAI Shanshan, WANG Zizhen, LIU Haojie, ZHANG Wensheng, YU Wenzheng, YANG Chongxiang, WANG Yuping Xinjiang Petroleum Geology    2024, 45 (3): 362-370.   DOI: 10.7657/XJPG20240314 Abstract （261）   HTML （10）    PDF（pc） （3814KB）（296）       Knowledge map    Save In order to study the fracability evaluation method for low-permeability tight reservoirs, experiments were conducted on six core samples from Well Y301 and Well Y3 in the Yongjin oilfield, Shawan sag, Junggar basin, and the parameters such as rock mineral composition, porosity, stress-strain curves, P-wave velocity, and S-wave velocity were obtained. The experiment results agreed well with logging data, and an empirical rock mechanical model was established for the study area. Meanwhile, based on the equivalent medium model, a new model considering mineral composition and pore structure characteristics was developed for calculating rock brittleness index. Then, a method for constructing the rock mechanical parameter profile of low-permeability tight reservoirs based on logging data was established and applied in Well Y301. The application results show that the Qigu formation in Well Y301 has good fracability, which lays a foundation for the comprehensive evaluation of fracability of tight sandstone reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Mechanical Mechanism of Karst Cave Collapse in Carbonate Reservoirs ZHANG Jiyue, KANG Zhihong, CHEN Huaxin, KANG Zhijiang Xinjiang Petroleum Geology    2023, 44 (5): 618-625.   DOI: 10.7657/XJPG20230515 Abstract （292）   HTML （8）    PDF（pc） （2016KB）（295）       Knowledge map    Save To determine the collapse mechanism of karst caves in carbonate reservoirs, through stress field simulation, and based on orthogonal two-dimensional sections of the karst caves, a two-dimensional mechanical model was established to simulate the stress distribution characteristics of the carbonate karst caves under negative pressure. By multiple linear regression on controlling variables, a karst cave collapse model coupling with the stress function of the critical fracture point was constructed to predict the relationships among cave collapse and stress, depth and width. It is found that the most important factors influencing cave rock burst and collapse are overlying formation pressure, reservoir compressive strength and flexural strength. For two caves superimposed vertically, when their vertical distance is less than 0.3 times the cave radius, the partition between the two caves breaks, leading to the cave connection. During the collapse and rupture, the cave height changes obviously, while the width changes slightly. Table and Figures | Reference | Related Articles | Metrics

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Architectures of and Remaining Oil Potential Tapping in Heavy Oil Reservoirs of Panyu Oilfield Group TU Yi, DAI Jianwen, YANG Jiao, WANG Yahui, WANG Hua, TANG Zhonghao, LI Qi Xinjiang Petroleum Geology    2024, 45 (2): 189-198.   DOI: 10.7657/XJPG20240207 Abstract （221）   HTML （42）    PDF（pc） （1918KB）（293）       Knowledge map    Save Due to the low oil recovery percent of reserves, developed barriers/interlayers, and difficult remaining oil prediction in the heavy oil reservoirs in the Panyu oilfield group, it is urgent to improve the accuracy of reservoir architecture analysis and prediction. Based on geological, seismic and logging data, together with GR return rate and big data statistical technologies, the 3rd-, 4th-, and 5th-order architecture boundaries in the reservoirs were identified, the distribution patterns of interlayers were studied, the internal structure of reservoir architecture units and the distribution of interlayers were quantitatively characterized, the main controlling factors and occurrence patterns of the remaining oil were analyzed, and the control of architecture boundary on remaining oil was clarified. The results show that the 3rd-order oblique progradational interlayers in the reservoirs can slow down vertical fluid flow, and the 4th-order superimposed horizontal interlayers can prevent vertical fluid channeling. The energy and direction of remaining oil migration are mainly constrained by the 3rd- and 4th-order interlayers and the rhythm differences. Ten ineffective and inefficient wells were sidetracked, which revealed an initial cumulative oil production of 680.00 m3/d, five times that before sidetracking. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation of Grid-Like Fragmented Structure of Fault-Karst Reservoirs in Southern Tuoputai Block ZHANG Rujie, YUE Ping, ZHANG Ying, LI Xiaobo, HUANG Nan, ZHAO Liming, FAN Qingzhen Xinjiang Petroleum Geology    2024, 45 (1): 58-64.   DOI: 10.7657/XJPG20240108 Abstract （209）   HTML （2）    PDF（pc） （3074KB）（281）       Knowledge map    Save The fault-karst reservoirs in the southern Tuoputai block of the Tahe oilfield exhibit a high initial production capacity，but a sharply declining production in the late development stage due to serious water flood and rapid water breakthrough occurred in many wells. There is no efficient simulation method for this phenomenon. Based on the karst features，seismic characteristics，actual well-reservoir configuration，and three-zone structure of fault-karst reservoirs，a grid-like fragmented structure of the fault-karst reservoirs was proposed. Accordingly，by combining the automatic fault extraction (AFE) technology with the ant body attributes，the fracture indicator was derived for characterizing the grid-like fragmented reservoir. Tensor attributes were used for characterizing the karst-vug reservoir，and a dual-porosity compositional model was established for numerical simulation. The results indicate that the grid-like fragmented structure serves as the primary flow channel in fault-karst reservoirs. The fracture indicator is better applicable to characterize the grid-like fragmented structure than AFE and maximum likelihood，and it is highly compatible with tensor attributes in water source zone but poorly compatible in other areas. Compared to single-porosity model，the dual-porosity model based on the grid-like fragmented structure can offer higher matching accuracy and better reflect the production performance of the fault-karst reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Influencing Factors of Natural Gas Gravity Drainage in Sanjianfang Formation Reservoir of Pubei Oilfield XIAO Zhipeng, QI Huan, ZHANG Yizhen, LI Yiqiang, YAO Shuaiqi, LIU Tong Xinjiang Petroleum Geology    2023, 44 (3): 334-340.   DOI: 10.7657/XJPG20230310 Abstract （239）   HTML （16）    PDF（pc） （3886KB）（279）       Knowledge map    Save To explore the feasibility of natural gas gravity drainage in the Pubei oilfield of the Turpan-Hami basin, the oil displacement characteristics under different operation parameters were clarified. By way of high-pressure physical property analysis, slim tube test, CT scanning imaging, and full-diameter core displacement experiments, the variations of the high-pressure physical properties of the fluids in the Middle Jurassic Sanjianfang formation reservoir before and after the flooding in the Pubei oilfield were analyzed, the minimum miscible pressure of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline under current reservoir conditions was calculated, the fluid distribution characteristics and the changes in oil saturation along the core under different displacement methods were compared, and the influences of injection rate, injection pressure, and rock dip angle on natural gas gravity drainage were clarified. The results show that after flooding there are increases in both crude oil density and saturation pressure, an unconspicuous change in viscosity, and significantly decrease contents of C2-C6 contents in the crude oil. The minimum miscibility pressures of the gas in the Shanshan-Urumqi Gas Pipeline and the West-East Gas Pipeline with oil are 48.2 MPa and 49.5 MPa, respectively, both higher than the minimum miscibility pressure of the original oil and gas. Compared with the performance after water flooding, the natural gas gravity drainage reveals very different oil saturations along the core: the oil saturation at the high position of the core is significantly lower than that at the low position, indicating that the natural gas gravity drainage is more effective in displacing the crude oil at the high position. Low injection rate, high displacement pressure, and large dip angle are all beneficial to improving the oil recovery of natural gas gravity drainage. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Dominant Flowing Channels and Throat Volume of Multi-Layer Sandstone Reservoirs in Liuzan Oilfield CAO Tongfeng, GAO Donghua, LI Zhandong, WANG Tianyang, JIANG Feng Xinjiang Petroleum Geology    2024, 45 (1): 53-57.   DOI: 10.7657/XJPG20240107 Abstract （184）   HTML （5）    PDF（pc） （1018KB）（278）       Knowledge map    Save For continental reservoirs with strong heterogeneity，long-term water injection may create dominant flowing channels，which will cause rapid water breakthrough in oil wells，thereby reducing the displacement efficiency and resulting in poor development results. Taking the Paleogene Oligocene Shahejie formation of Liuzan oilfield as an example，the litho-electric logging responses，reservoir heterogeneity，injection-production performance，and reservoir pore characteristics were analyzed，the characteristics of dominant flowing channels in the multi-layer sandstone reservoirs of the oilfield were described，and the conditions for the formation of dominant flowing channels in this area were determined. A calculation method for the throat volume of dominant flowing channels was established. With this method，the amount of profile control agent used in the subsequent operations was clarified to effectively plug the channels. The research results provide a technical support for subsequent oil production stabilization and water control in oilfields. Table and Figures | Reference | Related Articles | Metrics

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Dynamic Reserves Calculation Method for Fault-Controlled Carbonate Reservoirs GENG Jie, YUE Ping, YANG Wenming, YANG Bo, ZHAO Bin, ZHANG Rujie Xinjiang Petroleum Geology    2024, 45 (4): 499-504.   DOI: 10.7657/XJPG20240415 Abstract （258）   HTML （11）    PDF（pc） （960KB）（278）       Knowledge map    Save Fault-controlled carbonate reservoirs are highly heterogeneous, with interweaving development of pores, fractures, and vugs of various sizes. For this kind of reservoirs, the dynamic reserves calculated using conventional material balance methods may be larger than the static reserves. By incorporating water-oil ratio and considering rock compressibility coefficients for different pore-fracture-vug media, a comprehensive compressibility coefficient suitable for the fault-controlled reservoirs was derived. On this basis, a new flow material balance equation was established for the fault-karst reservoir, and its accuracy and applicability were verified using numerical simulation. The research results show that the dynamic reserves calculated by the new equation have an error of only 0.1099% with the static reserves obtained from numerical simulation, confirming the new equation’s reliability and accuracy. In the Halahatang area, the relative error between the dynamic reserves calculated using the new equation and the static reserves derived from geological modeling for multiple wells ranged from -4.82% to -0.15%, which is significantly lower than that calculated using the conventional material balance equation. The results obtained from the new equation are closer to actual conditions, making it more suitable for calculating the reserves of the fault-controlled carbonate reservoirs in the Halahatang area. Table and Figures | Reference | Related Articles | Metrics

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A Production Formula for Fractured Vertical Wells LI Chuanliang, PANG Yanming, ZHOU Yongbing, ZHAN Jianfei, ZANG Wei, LU Huimin, ZHU Suyang Xinjiang Petroleum Geology    2023, 44 (6): 683-689.   DOI: 10.7657/XJPG20230606 Abstract （259）   HTML （10）    PDF（pc） （639KB）（270）       Knowledge map    Save Fluid flow in the reservoir is no longer merely linear or radial after fracturing, instead, the flow field becomes complex and cannot be directly solved using analytical methods. In order to derive a production formula for fractured vertical wells, the complex flow field in the reservoir was decomposed into three simple flow patterns: outer radial flow, middle linear flow, and fracture linear flow. Each of these flow patterns was separately solved, and by applying the principles of fluid-electric similarity and equivalent flow resistance method, a production formula for fractured vertical wells was analytically derived. This formula can be used to calculate and predict the production of fractured vertical wells, and also to determine the fracture length and fracturing effect. Table and Figures | Reference | Related Articles | Metrics

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Segmented Structural Characteristics and Growth Mechanism of Transtensional Strike-Slip Fault Zone in Tazhong Uplift BAI Bingchen, WU Guanghui, MA Bingshan, ZHAO Xingxing, TANG Hao, SHEN Chunguang, WANG Xupeng Xinjiang Petroleum Geology    2024, 45 (4): 409-416.   DOI: 10.7657/XJPG20240404 Abstract （212）   HTML （9）    PDF（pc） （5426KB）（267）       Knowledge map    Save In the Tarim basin, transpressional strike-slip faults are developed under oblique compression in the Ordovician carbonate rocks, but a series of transtensional strike-slip faults have been discovered in the Tazhong uplift, significantly controlling the hydrocarbon accumulation. Using the 3D seismic data from the western Tazhong uplift, as well as the attributes such as coherence and curvature, the kinematic parameters of the strike-slip faults were statistically analyzed. Through structural analysis of the strike-slip faults, the FⅡ21 strike-slip fault zone in the Tazhong uplift was optimally selected for segmented modeling, and its growth mechanism was investigated. The results show that the FⅡ21 strike-slip fault zone is segmented horizontally and stratified vertically. Various structural forms such as linear, en echelon, horsetail, wingtip, braided, and overlapping structures are found at the top of the Ordovician carbonates. The characteristics of altitude differences of the fault zone reveal segmentation and tail-end expansion as the growth mechanisms, elucidating its role as a transform fault that regulates the reverse contraction deformation on either side of the strike-slip fault zone, and clarifying its evolution process including stages of en echelon fracturing, growth and linkage, and reactivation. Table and Figures | Reference | Related Articles | Metrics

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Thermally Recovered Reservoir Management and EOR for a Multi-Layered Sandstone Oilfield LYU Xiaoguang, LI Wei Xinjiang Petroleum Geology    2024, 45 (1): 65-71.   DOI: 10.7657/XJPG20240109 Abstract （214）   HTML （8）    PDF（pc） （674KB）（266）       Knowledge map    Save This paper presents the characteristics and development history of the multi-layered sandstone heavy oil reservoirs in the Kern River field，USA，and specifically discusses the practices of thermally recovered reservoir management and enhanced oil recovery (EOR). The Kern River field is a monocline reservoir of hydrodynamic trap. In the late stage of steam flooding，the practices such as C/O spectral logging，4D time-lapse dynamic surveillance during thermal recovery，injector-producer performance monitoring，isolated single-channel sandbody identification and tracking，and full-field 3D geological modeling and numerical simulation lay a basis for identifying remaining oil and enhancing oil recovery. Artificial intelligence，steam-foam flooding，and layered steam injection through dual-tubing completion are proved technologies for expanding the swept volume of steam flooding. Infill drilling，horizontal well drilling，and horizontal sidetracking in shallow oil reservoirs provide additional opportunities for significantly increasing the recoverable reserves. These technologies enable the production of horizontal well to be more than three times that of adjacent vertical wells. To exploit “cold reservoirs” near the oil-water contact in the downdip zone of the reservoir，water producers are drilled in the downdip aquifer zone to release reservoir pressure，allowing the remaining oil in this zone to be effectively swept by steam. Table and Figures | Reference | Related Articles | Metrics

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Oil-Water Two-Phase Flow Behaviors in Fracture-Cavity Carbonate Reservoirs With Fluid-Solid Coupling LIU Qiang, LI Jing, LI Ting, ZHENG Mingjun, XU Mengjia, WANG Xuan, WU Mingyang Xinjiang Petroleum Geology    2024, 45 (4): 451-459.   DOI: 10.7657/XJPG20240409 Abstract （191）   HTML （10）    PDF（pc） （4788KB）（265）       Knowledge map    Save To enhance the recovery of fracture-cavity carbonate reservoirs and investigate the oil-water two-phase flow behaviors under fluid-solid coupling effect, a Darcy-Stokes two-phase flow model was established based on the fluid flow patterns in different media. According to the principles of effective stress and the generalized Hooke’s law, an oil-water two-phase Darcy-Stokes coupled mathematical model suitable for fracture-cavity carbonate reservoirs was developed. Macroscopic and microscopic simulations of oil-water two-phase flows were conducted for carbonate reservoirs with and without fluid-solid coupling effect. The results show a significant difference in oil-water two-phase flow behaviors within the matrix zones of reservoirs with and without fluid-solid coupling effect, but a small difference within cavities. Water injection rate greatly influences oil-water flows in fracture-cavity carbonate reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Adaptability Evaluation of Gas Huff-n-Puff in Heavy Oil Reservoirs in Tuha Exploration Area XIA Zhengchun, ZHAO Jian, LIU Feng, QIN Enpeng, CAI Bijin, WANG Qi Xinjiang Petroleum Geology    2023, 44 (3): 341-346.   DOI: 10.7657/XJPG20230311 Abstract （291）   HTML （13）    PDF（pc） （539KB）（265）       Knowledge map    Save The performance of gas huff-n-puff in heavy oil reservoirs in the Tuha exploration area are declining. Gas huff-n-puff experiments were conducted by using PVT analysis technology to simulate high-temperature and high-pressure environment in the heavy oil reservoirs. CO2, natural gas, and nitrogen were injected respectively into the reservoirs, and then evaluated for adaptability in terms of viscosity reduction, swelling effect, foamy oil range, and residual heavy oil properties. The results show that CO2 huff-n-puff is best performed in viscosity reduction, swelling, and foamy oil range, but the injected CO2 has a significant impact on the residual heavy oil properties by increasing the residual heavy oil viscosity and decreasing the gas dissolution capacity, which is not conducive to multiple rounds of gas huff-n-puff. The natural gas huff-n-puff effect is slightly inferior to that of CO2 huff-n-puff, while the nitrogen huff-n-puff exhibits the worst performance but has a little impact on residual heavy oil properties. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Perforation in CBM Horizontal Wells in Southern Qinshui Basin LI Kexin, ZHANG Cong, LI Jun, LIU Chunchun, YANG Ruiqiang, ZHANG Wuchang, LI Shaonan, REN Zhijian Xinjiang Petroleum Geology    2024, 45 (5): 581-589.   DOI: 10.7657/XJPG20240510 Abstract （220）   HTML （5）    PDF（pc） （766KB）（258）       Knowledge map    Save To enhance the fracturing performance of coalbed methane (CBM) horizontal wells in the Qinshui basin, by analyzing the data of distributed optical fiber monitoring of water and gas production profiles, mud log, and well logging, the key factors influencing the fracturing performance were identified. These factors include coal quality, coal structure, drilling position, and perforation method. The middle to upper part of coal seam No. 3 in the Qinshui basin, characterized by low GR values, high coal quality, and intact coal structure, is identified as the optimal interval for fracturing stimulation. Based on the double GR curves, the drilling position of horizontal wellbore trajectory in the coal seam can be accurately determined, aiding in the selection of optimal fracturing interval and perforation method. When the drilling position is located in the middle part of the coal seam, conventional perforation method can be efficient. When the drilling position approaches the roof or is beyond the seam, downward directional perforation is preferred to effectively stimulate the high-quality upper part of the coal seam. When the drilling position is near the lower dirt band, upward directional perforation is advisable to target the high-quality middle part of the coal seam. Field application to 46 horizontal wells demonstrated that the single well production exceeded 2.5×104 m3/d and was stabilized at 2×104 m3/d, and the reservoir fracturing efficiency increased by 10% to 50%, recording a satisfactory development effect of the horizontal wells. Table and Figures | Reference | Related Articles | Metrics

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Pore Throat Structures and Fluid Occurrences of Reservoirs in Fengcheng Formation, Mahu Sag ZHU Yue, WU Shunwei, DENG Yusen, LIU Lin, LEI Xianghui, NIU Youmu Xinjiang Petroleum Geology    2024, 45 (3): 286-295.   DOI: 10.7657/XJPG20240305 Abstract （235）   HTML （13）    PDF（pc） （4537KB）（256）       Knowledge map    Save In order to reveal and compare the microstructures of sandstone and shale reservoirs, and the fluid occurrences within different sizes of pores in the Fengcheng formation of the Mahu sag, the experiments including high-pressure mercury intrusion (HPMI), nuclear magnetic resonance (NMR), and large-view splicing SEM were conducted to quantitatively characterize the pore throat size and fluid occurrence characteristics of the two types of reservoirs. The NMR experimental results and the HPMI experimental results before and after extraction of the original samples and the pressurized oil-saturated sample were compared to reveal the distributions of bound and movable fluids within pores of different sizes. The results indicate that sandstone and shale do not differ significantly in the sizes of pores and throats, which are dominantly 0.01-10.00 μm in pore diameter and <10.00 nm in throat radius, respectively, indicative of mesopores and fine throats. Shale has slightly larger pore diameters but smaller throat radii than sandstone. Shale mainly develops tubular pores such as intercrystalline pores and honeycomb-like dissolution pores. Sandstone has an equal distribution of tubular and spherical pores, with the proportion of spherical pores such as intergranular pores and intergranular dissolution pores increasing as the pore size increases. Fluid occurrence and mobility are controlled by multiple factors such as mineral composition and pore size. The oil-wet properties of organic matter, dolomite and pyrite, and the strong capillary confinement of intergranular pores in clay minerals, reduce the mobility of shale oil, and the movable fluids are mainly distributed in mesopores-macropores with diameters greater than 300 nm. Combining the reservoir physical properties and movable fluid distribution, it is determined that the favorable shale oil block in the study area is the Ma 51X well block, both shale and sandstone in the well block are favorable targets for development. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of Generalized Characteristic Curves of Gas-Water Miscible Flooding JIA Rui, YUAN Quan, TANG Xin, LYU Qiqi, GAO Wenjun Xinjiang Petroleum Geology    2023, 44 (5): 562-571.   DOI: 10.7657/XJPG20230507 Abstract （232）   HTML （16）    PDF（pc） （769KB）（254）       Knowledge map    Save Considering the limited methods for evaluating reservoir development performance using gas-water miscible flooding characteristic curves, a concept of underground water-gas cut was introduced. By analogy with the generalized mathematical model of water cut variation in water flooding reservoirs, generalized gas-water miscible flooding characteristic curves and the corresponding generalized mathematical models of underground gas-water cut variation were established. The generalized gas-water miscible flooding characteristic curve is a Type A water-alternating-gas (WAG) injection characteristic curve when n=0 and m=0, and a Type B WAG injection characteristic curve when n=1 and m=0. By varying the values of n and m, the generalized gas-water miscible flooding characteristic curve can be transformed into S-shaped, convex, S-convex, S-concave, and concave gas-water miscible flooding characteristic curves. For purpose of field application, a general formula for the generalized gas-water miscible flooding characteristic curve and solution method for the corresponding mathematical model combining underground gas-water cut variation were provided. The application to the evaluation of the development performance of WAG injection in the reservoir of Sanjianfang formation in Pubei oilfield, and of gas cap gas + edge water displacement in S31 reservoir in Jinzhou oilfield shows a high fitting accuracy. This method can be a reference for other reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Well Location Optimization and Potential Tapping Strategy for Reservoirs With Narrow Oil Ring and Gas Cap in JZ-X Oilfield, Bohai Bay Basin YUE Baolin, MENG Zhiqiang, FANG Na, ZHENG Yang, QU Zhaozhao, WANG Shuanglong Xinjiang Petroleum Geology    2024, 45 (1): 88-93.   DOI: 10.7657/XJPG20240112 Abstract （215）   HTML （7）    PDF（pc） （2148KB）（249）       Knowledge map    Save The development of the reservoirs with narrow oil ring, gas cap, and bottom water is often challenged by water coning, gas channeling, and complex remaining oil distribution. This paper discusses the well location optimization and potential tapping strategy for horizontal well development in the Bohai Bay basin. In the basic well pattern arrangement stage, in plane, horizontal wells are arranged perpendicular to the structural lines and penetrating multiple layers for enhancing the recovery of reserves, and the separated-layer production string with intelligent sliding sleeve is equipped to alleviate inter-layer contradiction; vertically, horizontal wells are arranged parallel to the fluid interface and at 1/3 of the oil column height from the water-oil contact for gas channeling prevention and water control. In the comprehensive adjustment stage, according to the numerical reservoir simulation, the remaining oil is enriched in inter-well retention zone in plane in the middle-late development stage, and is vertically enriched in the upper part of the reservoir due to the subsequent dominance of water drive in the late stage. Comparing the oil increment indexes under the schemes of inter-well sidetracking, gas reinjection into the gas cap, and barrier water injection, the former two schemes are preferred for tapping the potential remaining oil. Ineffective and inefficient wells are sidetracked to the zones at high positions between wells, with the expected net oil increment of 3.4×104-4.2×104 m3 per well. For gas reinjection into the gas cap, existing gas production wells are converted for gas reinjection to replenish the energy of the gas cap, so as to displace the remaining oil in the upper part of horizontal wells and enhancing the oil recovery, with the expected net oil increment of 5.2×104 m3 per well. Table and Figures | Reference | Related Articles | Metrics

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Productivity Evaluation of Condensate Gas Wells With Water and High Condensate Oil Content in Shunbei Oil and Gas Field LI Dongmei Xinjiang Petroleum Geology    2023, 44 (6): 696-701.   DOI: 10.7657/XJPG20230608 Abstract （251）   HTML （9）    PDF（pc） （567KB）（248）       Knowledge map    Save The wells drilled in the fault-karst condensate gas reservoirs in Shunbei oil and gas field of Tarim basin exhibits significant formation pressure fluctuations, making conventional well testing interpretation methods based on constant formation pressure inapplicable. Additionally, due to the presence of water and high contents of condensate oil in gas wells, the evaluation results of open flow rates of the wells deviate significantly. Based on systematic well testing data that are corrected with elastic productivity in the well testing stage, this paper presents a productivity evaluation method for the condensate gas wells with water and high content of condensate oil. The field application validates that this evaluation method is applicable for assessing the open flow rate of condensate gas wells in the Shunbei oil and gas field to provide a quantitative understanding on the productivity of condensate gas wells with water and high content of condensate oil in Shunbei area. Table and Figures | Reference | Related Articles | Metrics

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Origin of Crude Oil From Coal Mine of Yan’an Formation in Huangling-Tongchuan Area，Ordos Basin KONG Lingyin, LI Jianfeng, WU Kai, MA Jun Xinjiang Petroleum Geology    2024, 45 (1): 35-46.   DOI: 10.7657/XJPG20240105 Abstract （237）   HTML （9）    PDF（pc） （1020KB）（248）       Knowledge map    Save To clarify the geochemical characteristics and origin of the crude oil from the coal mine in Yan’an formation in Huangling-Tongchuan area，southeastern Ordos basin，a comparative study was conducted on the biomarker compositions and carbon isotope distribution of n-alkane monomers in extracts from crude oil，coal，and mudstone in the study area using gas chromatography，chromatography-mass spectrometry，and isotope mass spectrometry techniques. The oil from coal mine is characterized by equilibration of pristane and phytane，high sesquiterpene content，relatively high Ts/Tm and C29Ts/C29 norhopane ratios，relatively low ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and 22S/(22S+22R) for C31 homohopane and C32 homohopane，“V”-shaped distribution of ααα-20R regular sterane，and relatively light carbon isotopic values of crude oil and n-alkane monomers. The extracts from the Jurassic coal-bearing source rocks exhibit high Pr/Ph ratio，low sesquiterpene content，low Ts/Tm and C29Ts/C29 norhopane ratios，relatively high ratios of C30 moretane/C30 hopance，C30 norhopane/C30 hopance，and high 22S/(22S+22R) values for C31 homohopane and C32 homohopane，inverted “L”-shaped distribution of ααα-20R regular sterane，and relatively heavy carbon isotopic values of crude oil and n-alkane monomers. The characteristics of crude oil significantly differ from those of the potential coal-bearing source rocks，which is consistent with the deep lacustrine source rocks and the generated hydrocarbons of Chang 7 member in the basin. The coal of the Jurassic Yan’an formation is at a low maturity stage，and it is incapable of expelling liquid hydrocarbons，since the generated liquid hydrocarbons cannot even fully meet its adsorption needs. The crude oils in the Cuijiagou Coal Mine in Tongchuan and the Diantou Coal Mine in Huangling are both originated from the source rocks of the underlying Chang 7 member. Table and Figures | Reference | Related Articles | Metrics

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Layered Modeling Algorithms and Cases for Different Reservoir Development Stages ZUO Yi, SONG Jing, SHI Zhuoli, QIAO Jingxuan, ZU Xiuran, ZHENG Jie Xinjiang Petroleum Geology    2024, 45 (1): 118-125.   DOI: 10.7657/XJPG20240116 Abstract （305）   HTML （6）    PDF（pc） （1695KB）（248）       Knowledge map    Save The simulation methods and model precision adopted for layered modeling in 3D geological modeling vary with reservoir characteristics and research purposes at different development stages. From the perspective of 3D geological modeling，the reservoir development can be divided into three stages: reservoir evaluation，new block development，and existing block adjustment. The layered modeling algorithms were analyzed and selected for the 5th fault block in Gangdong district 2. It is proposed that the Kriging algorithm should be used for modeling at the reservoir evaluation stage，with a grid resolution of 100 m × 100 m × 5.0 m；the Kriging or Global B-spline algorithm should be used for modeling at the new block development stage，with a grid resolution of 50 m × 50 m × 1.5 m；and the Local B-spline or Converging average algorithm should be used for modeling at the existing block adjustment stage，with a grid resolution of 10 m × 10 m × 0.5 m. This modeling approach can provide results in more coincidence with actual geological conditions and can meet requirements for reservoir research at each stage. Table and Figures | Reference | Related Articles | Metrics

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Experimental Study on Water Invasion in Full-Diameter Cores From Fractured Carbonate Reservoirs HU Yong, LE Ping, GUO Chunqiu, CHEN Pengyu, XIAO Yun, QU Simin, WANG Xin Xinjiang Petroleum Geology    2023, 44 (4): 479-484.   DOI: 10.7657/XJPG20230413 Abstract （234）   HTML （3）    PDF（pc） （789KB）（248）       Knowledge map    Save Faults and fractures are developed in the marine carbonate gas reservoirs on the right bank of the Amu Darya basin. Water is active locally, which leads to severe water invasion during development. Through high-temperature and high-pressure displacement experiments on full-diameter core samples from complex fractured reservoirs, the influences of fracture permeability, fracture penetration degree and water volume multiple on water invasion in gas reservoirs were analyzed. The water invasion patterns in different fractured core samples were investigated by considering the dynamic changes in the water-gas ratio (WGR). The results indicate that as the fracture penetration degree, fracture permeability, and water volume multiple increase, the slope of the WGR curve under the corresponding water invasion pattern increases, suggesting more severe water invasion and channeling. The areas with incomplete fracture penetration can effectively restrain any sudden water invasion. Accordingly, the characteristics of water invasion patterns were further analyzed by using the water invasion diagnosis curves, and the index chart for diagnosis of water invasion in the study area was optimized. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Tilted Oil-Water Contact of Heavy Oil Reservoir in Shawan Formation, Chunfeng Oilfield, Junggar Basin ZHANG Deyao Xinjiang Petroleum Geology    2024, 45 (2): 205-212.   DOI: 10.7657/XJPG20240209 Abstract （190）   HTML （23）    PDF（pc） （3330KB）（238）       Knowledge map    Save The oil-water relationship of the heavy oil reservoir in the first member of the Neogene Shawan formation （Sha 1 member） in Chunfeng oilfield is complex and cannot be explained from the traditional viewpoint of oil-water contact （OWC）, which affects the exploration and development process of the oilfield. Taking the P601-20 block with prominent contradiction in oil-water relationship as an example, researches on seismic-geology and pool-forming dynamics were conducted, and combining with the reservoir performance during development, the oil-water relationship of the heavy oil reservoir in Sha 1 member and its genesis were analyzed. It is found that the complex oil-water relationship in this oilfield is caused by the presence of a tilted OWC in the reservoir which is a structural-lithological reservoir with bottom/edge water. In terms of reservoir physical property, fault, formation pressure, tectonic movement, etc., the presence of the tilted OWC should be attributed to the adjustment of the reservoir due to tectonic movements, and the crude oil densification and flat strata intensified the lag of OWC adjustment. This reservoir can be classified as an unsteady oil and gas reservoir. Table and Figures | Reference | Related Articles | Metrics

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Identification of Fluid in Highly Saline Tight Reservoirs of Fengcheng Formation in Maxi Slope Area MAO Rui, BAI Yu, WANG Pan, HUANG Zhiqiang Xinjiang Petroleum Geology    2024, 45 (3): 279-285.   DOI: 10.7657/XJPG20240304 Abstract （193）   HTML （6）    PDF（pc） （2125KB）（238）       Knowledge map    Save The Permian Fengcheng formation in the Maxi slope area of the Junggar basin is characterized by highly saline tight reservoirs deposited in alkaline lakes, and the relationship between oil and water in these reservoirs is complicated, which leads to difficulties in fluid identification. A thermal neutron macroscopic capture cross-section of the highly saline formation was constructed by using lithoscanner logging data, and an oil-sensitive factor was constructed by using the difference between the thermal neutron macroscopic capture cross-section from logging and the thermal neutron macroscopic capture cross-section of the brine-saturated formation. Furthermore, a salinity-sensitive factor was constructed by using the ratio of chlorine element relative yield to total porosity. Then, a fluid identification chart was established by intersecting the oil-sensitive factor with the salinity-sensitive factor. The actual application shows that this fluid identification chart can accurately assess reservoir fluid properties and provide a basis for selecting formation test layers. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2025, 46 (1): 1-12.   DOI: 10.7657/XJPG20250101 Abstract （233）   HTML （13）    PDF（pc） （4213KB）（237）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Facies-Controlled Geostatistical Inversion Method Based on Low-Frequency Model Optimization and Its Application SHI Nan, LIU Yuan, LENG Yue, WEN Yihua, PAN Haifeng, SUN Bo, WANG Bing Xinjiang Petroleum Geology    2023, 44 (3): 375-382.   DOI: 10.7657/XJPG20230316 Abstract （398）   HTML （25）    PDF（pc） （9433KB）（235）       Knowledge map    Save The oil and gas reservoirs in the Qiketai formation of Middle Jurassic in the Pubei area of Taibei sag, Turpan-Hami basin, are controlled by lithology. Early exploration confirmed that there are thin oil-bearing sand layers with the thickness of 6-15 m at the bottom of the Qiketai formation. It is difficult for conventional inversion methods to predict these sand layers and these methods often yield large errors due to the limitations of the frequency band of seismic data. In order to improve inversion accuracy, a facies-controlled geostatistical inversion method based on low-frequency model optimization was proposed. Combined with the characteristics of large structural relief and greatly varying sedimentary facies in the study area, the low-frequency model was established by combining the compaction trend correction method and the seismic attribute constraint method to obtain the deterministic inversion results. On this basis, a facies-controlled model was established for facies-controlled geostatistical inversion, thus enabling the identification of thin sand layers in the study area. This method effectively complements the low-frequency information missed in seismic signals, and improves the longitudinal resolution of the inversion results. By using this method, a thin sand layer with the thickness of 7 m can be identified, and the inversion result is basically consistent with the actual thickness of sand body, which confirms the effectiveness of this method in predicting thin sand layers in Pubei area. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation of One-Hole Multi-Target Staged Fracturing in Fractured-Vuggy Reservoirs GENG Yudi, LIU Lijun, WANG Lijing, GUO Tiankui Xinjiang Petroleum Geology    2023, 44 (6): 711-719.   DOI: 10.7657/XJPG20230610 Abstract （271）   HTML （10）    PDF（pc） （3598KB）（233）       Knowledge map    Save Based on the discrete fractured-vuggy reservoir model, an oil-water two-phase flow model and a numerical simulation method considering matrix-fracture flow and vug free flow were established to analyze the performance of one-hole multi-target staged fracturing in fractured-vuggy reservoirs, and the impacts of natural fracture development degree, bottom water, and number of fracturing clusters on the fracturing performance were identified. The results show that, in the absence of bottom water, the natural fracture development degree only affects production rate but has a minor impact on the ultimate oil recovery; and in the presence of bottom water, the bottom water rising along natural fractures displaces the crude oil in cavities, leading to an increase in oil production with the increase of natural fracture density. Vug size and hydraulic fractures significantly affect the productivity of fractured-vuggy reservoirs. When natural fractures are highly developed, the difference between the performance of fracturing by single cluster in one stage and by multiple clusters in one stage decreases significantly, indicating that a single cluster hydraulic fracture can effectively control the entire sweet spot area in the fractured-vuggy reservoir. Table and Figures | Reference | Related Articles | Metrics

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Multilayer Superimposition Patterns of Strike-Slip Fault Zones and Their Petroleum Geological Significance in Platform Area, Tarim Basin YANG Haijun, NENG Yuan, SHAO Longfei, XIE Zhou, KANG Pengfei, YUAN Jingyi, FU Yonghong Xinjiang Petroleum Geology    2024, 45 (4): 387-400.   DOI: 10.7657/XJPG20240402 Abstract （210）   HTML （16）    PDF（pc） （33226KB）（233）       Knowledge map    Save In recent years, with the progress of oil and gas exploration in the Tarim basin, large-scale strike-slip fault systems have been discovered in the Paleozoic strata of the platform area in the basin and a new type of fault-karst reservoir has been identified. Due to multiple tectonic movements in the basin, these strike-slip faults exhibit multilayer structures featured with multiple phase superimposition. Based on high-quality 3D seismic data, drilling data, and petroleum geological data, the multilayer superimposition of large-scale strike-slip faults in the basin and its controls over hydrocarbon accumulation were investigated. The research results show that the strike-slip fault zones in the platform area of the Tarim basin primarily develop five structural layers in the Paleozoic: Lower Cambrian pre-salt structural layer, Middle Cambrian salt structural layer, Upper Cambrian-Middle Ordovician carbonate structural layer, Upper Ordovician-Carboniferous clastic structural layer, and Permian magmatite structural layer. Affected by multiple tectonic movements and strike-slip fault activities, these layers exhibit characteristics of banded spatial distribution, vertical superposition, and differential superimposition. The superimposition patterns can be broadly categorized into four types: connection, overlapping, inverse superimposition, and inverse reformation. These superimposition patterns have significant impacts on hydrocarbon accumulation, and three types of reservoirs such as TypeⅠ (Ordovician carbonate reservoirs), Type Ⅱ (Ordovician carbonate, Silurian clastic, and Permian magmatite reservoirs), and Type Ⅲ (Cambrian pre-salt dolomite reservoirs) are formed. Table and Figures | Reference | Related Articles | Metrics

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Natural Gas Enrichment in Carbonate Gas Reservoirs of Taiyuan Formation in Yishaan Slope，Ordos Basin LI Yanrong, LI Jing, SU Wenjie, SHI Lei, SUN Rui, ZHU Yushuang Xinjiang Petroleum Geology    2023, 44 (5): 509-516.   DOI: 10.7657/XJPG20230501 Abstract （374）   HTML （28）    PDF（pc） （18631KB）（226）       Knowledge map    Save To determine the distribution of the carbonate gas reservoirs in Permian Taiyuan formation in Yishaan slope of the Ordos basin, based on the data of drilling, well testing, logging, and formation testing, the carbonate gas reservoirs in Taiyuan formation were analyzed using field outcrops, core samples, thin sections, electron microscopy scanning, high-pressure mercury intrusion, and fluid inclusion temperature measurements, and then sedimentary microfacies, petrographic characteristics, physical properties, pore structures, and fracture distribution were studied of the reservoir. The results indicate that the carbonate gas reservoirs in Taiyuan formation are low-porosity and low-permeability lithological gas reservoirs. Favorable plays control the reservoir distribution and gas enrichment. The gas reservoirs `are mainly distributed in the bioherm and bioclastic shoal microfacies zones. Bioherms are found in the eastern part of the study area, including Jiaxian, Zizhou, and Qingjian, while bioclastic shoals are developed in the western part of the study area, including Hengshan, Jingbian, and Pingqiao, exhibiting an obvious zoning of facies from west to east. The carbonate rocks in Taiyuan formation consist of micritic bioclastic limestone and algal-bounded limestone, in which biogenic pores, intercrystalline pores, dissolution pores, and microcracks serve as accommondation. Fractures play a crucial role in migration of oil and gas, and their development contributes significantly to the natural gas enrichment in the reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Genesis of M55 Reservoirs in Daniudi Gas Field, Ordos Basin GAO Jingyun, DING Xiaoqi, QI Zhuangzhuang, TIAN Yinyu Xinjiang Petroleum Geology    2023, 44 (4): 404-410.   DOI: 10.7657/XJPG20230403 Abstract （277）   HTML （15）    PDF（pc） （5975KB）（224）       Knowledge map    Save A set of vug-type karst reservoirs is developed below the weathering crust of the Majiagou formation in the Daniudi gas field of Ordos basin, which are the main reservoirs of the Paleozoic super-large gas fields. The disturbed-facies karst reservoirs with fractures are found stably at the bottom of the fifth submember of the fifth member of Majiagou formation (M55) and contain gas universally. The genesis of these reservoirs remains unknown, leading to difficulties in oil and gas exploration and development. Based on the analysis on field outcrop and core data, the genesis of the M55 reservoirs was analyzed. Disturbed facies and well-developed fractures are clearly observed from the outcrops, and show a line-porphyritic pattern on the image logging. Most of the fractures are filled by calcite of two periods. The disturbed facies found at the bottom of M55 are mainly distributed in the fault zones of the central and western parts of the study area, with obvious gas logging anomalies and good exploration prospects. Abundant fractures in $\text{M5}^{1}_{6}$ promote the strong karstification of fresh water laterally, forming accommodation spaces. The overburden pressure makes the brittle limestone at the bottom of M55 evolve to disturbed reservoir. Table and Figures | Reference | Related Articles | Metrics

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Breakthrough and Implication of Oil and Gas Exploration in Permian Upper Wuerhe Formation in Fukang Sag, Junggar Basin LIU Chaowei, LI Hui, WANG Zesheng, WANG Qiuyu, XIE Zhiyi, HUANG Zhiqiang, ZHANG Rong Xinjiang Petroleum Geology    2024, 45 (2): 139-150.   DOI: 10.7657/XJPG20240202 Abstract （270）   HTML （23）    PDF（pc） （9344KB）（219）       Knowledge map    Save The confirmation of 100-million-ton reserves in the Permian upper Wuerhe formation in the Kangtan-1 well area of Fukang sag, Junggar basin, demonstrates the excellent hydrocarbon accumulation conditions and huge exploration potential of the deep layers in the sag. Summarizing the exploration experience and theoretical understanding of the upper Wuerhe formation in the Fukang sag will be significant to guide the exploration of clastic reservoirs in other hydrocarbon-rich sags. Using the data of drilling, reservoir rock thin section, porosity-permeability analysis and formation testing, a systematic analysis was conducted on the exploration breakthrough of the upper Wuerhe formation in the Fukang sag. It is indicated that the oil and gas in the uplift and slope zones around the Fukang sag are mainly products of source rocks in the early maturity stage, and the hydrocarbons generated in the high maturity stage of source rocks are mainly found in the sag area. Controlled by the paleogeomorphology during deposition, retrogradational sand bodies in lowstand systems tract （LST） were developed in the upper Wuerhe formation in the Fukang sag, forming superimposed continuous large-scale reservoirs in the paleo-trough area. Overpressure is commonly found in the sag, which is conducive to the preservation of primary pores in deeply buried sandstones and also to the formation of microfractures, enhancing the permeability of reservoirs and making the deep reservoirs more effective. The upper Wuerhe formation in the Fukang sag has large exploration potential for achieving reserves increment due to the late-stage charging of hydrocarbons generated from highly mature sources rocks in the Lucaogou formation, the large-scale retrograditional sedimentation, and the pore preservation and permeability increasement caused by overpressure. Table and Figures | Reference | Related Articles | Metrics

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Genesis and Identification of Low Resistivity of Oil Layers in Badaowan Formation on Southern Slope of Zhongguai Bulge, Junggar Basin LI Fengling, FANG Xinxin, ZHANG Zhen, MA Sijie, LIU Rongjun Xinjiang Petroleum Geology    2024, 45 (5): 541-551.   DOI: 10.7657/XJPG20240505 Abstract （238）   HTML （15）    PDF（pc） （4996KB）（213）       Knowledge map    Save Compared to other low-resistivity oil layers, the low-resistivity oil layers in the Lower Jurassic Badaowan formation on the southern slope of the Zhongguai bulge in the Junggar basin are characterized by early hydrocarbon accumulation, deep burial, large grain size, and low mud content, showing a unique low-resistivity genesis. Based on a comprehensive analysis on the genetic mechanisms of typical low-resistivity oil layers globally, together with the data of drilling, logging, well testing, and core analysis in the study area, the main controlling factors of the low-resistivity oil layers in the Badaowan formation were investigated from various perspectives including tectonics, sedimentation, diagenesis, reservoir characteristics, and hydrocarbon accumulation conditions. It is found that low resistivity of the oil layers in the study area is jointly controlled by macroscopic and microscopic factors. In a macroscopic setting with low tectonic amplitude and weak hydrodynamic sedimentation, low oil-water differentiation degree, high formation water salinity, and low tuff debris content are the main controlling factors for low resistivity, while low saturation of bound water is a secondary controlling factor. Accordingly, a chart illustrating the relationship between formation resistivity and oil/gas indicator coefficient was established, which matches the formation/production testing data in the study area by 92.9%. The study results provide a basis for identifying low-resistivity oil layers in the Badaowan formation on the southern slope of the Zhongguai bulge. Table and Figures | Reference | Related Articles | Metrics

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Optimized Laboratory Experiment on Interlayer Interference in Heterogeneous Reservoirs WANG Jie, LI Hongyu, LYU Dongliang, QIAN Chuanchuan, ZHOU Qunmao Xinjiang Petroleum Geology    2024, 45 (2): 199-204.   DOI: 10.7657/XJPG20240208 Abstract （227）   HTML （10）    PDF（pc） （869KB）（212）       Knowledge map    Save During the development of multi-layer heterogeneous reservoirs through commingled injection and production, interference between layers occurs due to various factors such as reservoir lithology, petrophysical properties, formation pressure, and fluid properties. The previous laboratory experiments on parallel displacement failed to effectively simulate fluid exchange between layers during the commingled production of multiple layers, and the physical meaning of the defined interference coefficient does not align with the flow process in water injection development. In this paper, an experimental model of series-parallel combined displacement was established to simulate the variation of lithology within the reservoir layers. The oil production, water cut, and recovery rate of cores with different permeabilities in the experiments were investigated to verify and re-understand the interference coefficient. The results show that interlayer interference is essentially a phenomenon that the variation of flow resistance of reservoir layers with time leads to alteration in flow distribution within the layers. Reservoir heterogeneity is identified as a key factor in forming dominant flow channels during commingled production. The research results provide a reference for designing interlayer interference experiments and developing heterogeneous reservoirs rationally and efficiently. Table and Figures | Reference | Related Articles | Metrics

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Simultaneous CO2 Huff-n-Puff Test in Highly Sensitive Reservoirs in Upper Wuerhe Formation, Mahu Sag SONG Ping, CUI Chenguang, ZHANG Jigang, LIU Kai, DENG Zhenlong, TAN Long, YU Xike Xinjiang Petroleum Geology    2024, 45 (3): 355-361.   DOI: 10.7657/XJPG20240313 Abstract （200）   HTML （4）    PDF（pc） （2185KB）（208）       Knowledge map    Save In order to explore the post-fracturing EOR technologies for efficient development of highly sensitive tight conglomerate oil reservoirs in horizontal wells in the Mahu sag, a simultaneous CO2 huff-n-puff test was carried out in the Mahu 1 well block. The results show that simultaneous CO2 huff-n-puff can enhance oil recovery of highly sensitive tight conglomerate reservoirs, and its oil displacement mechanisms mainly include extraction, miscibility, competitive adsorption, and expansive displacement. Fracture communication is the main cause of gas channeling. Through field regulation and control, synchronous soaking of well groups and gas channeling wells was achieved, ensuring the field implementation effect. Soaked by fracturing fluid, the clay minerals in the tested well group hydrate and expand, causing pore throat blockage, which affects CO2 swept range and results in a low interim oil exchange ratio. The simultaneous CO2 huff-n-puff test achieved favorable stimulation effects, with an interim oil increment of 3,983 tons and an oil exchange ratio of 0.36 in the tested well group. This test provides technical ideas and field experience for horizontal wells in enhancing oil recovery of highly sensitive tight conglomerate reservoirs after fracturing. Table and Figures | Reference | Related Articles | Metrics

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Dynamic Model and Sensitivity Analysis of High-Pressure Water Injection for Capacity Expansion of Fractured-Vuggy Reservoirs ZHANG Rujie, CHEN Lixin, YUE Ping, XIAO Yun, WANG Xia, LYU Yuan, YANG Wenming Xinjiang Petroleum Geology    2024, 45 (4): 460-469.   DOI: 10.7657/XJPG20240410 Abstract （190）   HTML （9）    PDF（pc） （964KB）（206）       Knowledge map    Save High-pressure water injection for capacity expansion is an effective method to enhance the recovery of fractured-vuggy reservoirs. However，the injection-production process during high-pressure water injection remains unclear. In this paper，three modes of high-pressure water injection for capacity expansion were proposed. Based on a dynamic model of high-pressure water injection for capacity expansion，the impacts of sensitivity parameters on the injection-production process during high-pressure water injection were simulated. The three modes of high-pressure water injection for capacity expansion were analyzed using actual wells drilled in the fractured-vuggy reservoirs in Halahatang oilfield. The high-pressure water injection for capacity expansion conforms to three modes：far-end low-energy，flow barrier，and near-end small reservoir. All three modes can realize effective production of far-end reservoirs to improve recovery efficiency. Flow barrier mode has the optimal EOR effect. The size of the near-end reservoir affects the time at which the water-injection indicator curve inflects，and the size of the far-end reservoir influences the difficulty degree of water injection after the water-injection indicator curve inflects. The fluid exchange index in the water injection process is greater than that in the production process，which indicates that the high-pressure water injection for capacity expansion is effective. The smaller the fracture closure pressure and stress sensitivity coefficient，the earlier the water-injection indicator curve inflects，and the higher the cumulative liquid production. Table and Figures | Reference | Related Articles | Metrics

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Main Controlling Factors of Shale Oil and Gas Enrichment in Chang 7 Member， Southeastern Ordos Basin SONG Haiqiang, LIU Huiqing, WANG Jing, SI Shanghua, YANG Xiao Xinjiang Petroleum Geology    2024, 45 (1): 27-34.   DOI: 10.7657/XJPG20240104 Abstract （234）   HTML （7）    PDF（pc） （728KB）（205）       Knowledge map    Save In order to clarify the main controlling factors of shale oil and gas enrichment，the degree and mechanisms of shale oil and gas enrichment in the Chang 7 member in southeastern Ordos basin were analyzed using the data of drilling，logging，and core. Desorbed shale gas content is positively correlated with the total organic carbon content (TOC) of source rocks，the organic matter content controls the total content of shale oil and gas，and abundant pores are developed in organic matter，and shale oil and gas exist in both adsorbed and free states in these organic pores. The pore structure and porosity of the reservoir affect the content and occurrence state of shale oil and gas. Adsorbed oil and gas mainly exist in micropores，while free oil and gas in mesopores and macropores. The content of free gas in mesopores is higher than that in macropores，and the larger the porosity，the higher the absolute content of oil and gas in shale. The configuration between sandstone interlayers and organic-rich shale controls the enrichment positions of shale oil and gas. Based on the distribution of siltstone，fine sandstone and shale in the reservoir，the shale oil and gas in Chang 7 member can be classified into two types：near-source and in-source. The in-source shale oil and gas can be further divided into hydrocarbons from sandstone interbedded with shale，shale intercalated with sandstone，and pure shale. Sand bodies underlying the organic-rich shale and lenticular sand bodies exhibit the best potential of oil and gas，followed by sand bodies overlying the organic-rich shale or those tongue-shaped or finger-shaped ones in contact with shale. Table and Figures | Reference | Related Articles | Metrics

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A Logging-Based Method for Calculating Water Saturation in Continental Shale Reservoirs: A Case Study of Lianggaoshan Formation in Fuxing Block, Southeastern Sichuan Basin CHENG Li, YAN Wei, LI Na Xinjiang Petroleum Geology    2024, 45 (3): 371-377.   DOI: 10.7657/XJPG20240315 Abstract （203）   HTML （5）    PDF（pc） （717KB）（203）       Knowledge map    Save Continental shale reservoirs are characterized by low porosity, ultra-low permeability, high clay mineral content, rapid mineral composition variation, and strong formation heterogeneity. Therefore, the water saturation calculated with Archie formula or conventional mathematical statistical models often introduces large errors. To improve the calculation accuracy of water saturation in continental shale reservoirs, taking the shale from Lower Jurassic Lianggaoshan formation in the Fuxing block of southeastern Sichuan basin as an example, the limitations of existing methods for calculating water saturation were analyzed, and the feasibility of applying the composite wave impedance reconstructed from the combination of P wave and S wave in array acoustic logging and logging density to calculate water saturation was demonstrated. Based on this analysis, a method for calculating water saturation in continental shale reservoirs was proposed. This method considers the influence of rock minerals and effectively avoids the limitations of electrical logging and non-electrical logging, and finally improving applicability. The application of this method has yielded favorable results in multiple wells in the shale reservoirs of Lianggaoshan formation, southeastern Sichuan basin, with calculated water saturation closely matching those from core analysis, and absolute errors ranging from 1.3% to 2.2%, meeting the requirements for well logging evaluation. Table and Figures | Reference | Related Articles | Metrics

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Microscopic Oil Mobility in Tight Conglomerate Reservoirs Under Different Development Modes, Mahu Sag WAN Tao, ZHANG Jing, DONG Yan Xinjiang Petroleum Geology    2024, 45 (3): 327-333.   DOI: 10.7657/XJPG20240309 Abstract （248）   HTML （5）    PDF（pc） （2794KB）（189）       Knowledge map    Save In order to evaluate the oil mobility in the tight sandy conglomerate reservoirs of the Triassic Baikouquan formation in the Mahu sag, the distribution characteristics of movable oil in typical rock samples from Type Ⅰ and Type Ⅱ reservoirs were compared through imbibition, centrifugation, and huff-n-puff tests. For the low-permeability conglomerate reservoirs in the Mahu sag, the imbibition oil recovery is related to the pore structure of the rock. The higher the proportion of small pores, the better the imbibition effect. After 144 hours of oil displacement by imbibition, the recovery rate can reach 30.9%, but the oil displacement process is slow, with low utilization of large pores. Under reservoir pressure of 40 MPa and reservoir temperature, during three cycles of CO2 huff-n-puff process, the recovery percent of each round increase, with the highest increase observed in the first cycle, reaching an oil exchange ratio of 27%. As the huff-n-puff cycle increases, the increment in recovery percent gradually decreases, and the oil exchange ratio of N2 huff-n-puff in the first cycle is 15%. Therefore, CO2 huff-n-puff has the best development effect. Table and Figures | Reference | Related Articles | Metrics

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Study on Water Flooding With Self-Emulsification in Heavy Oil Reservoirs SHI Lanxiang, TANG Wenjun, ZHOU You, WANG Bojun Xinjiang Petroleum Geology    2024, 45 (2): 228-234.   DOI: 10.7657/XJPG20240212 Abstract （233）   HTML （5）    PDF（pc） （1281KB）（187）       Knowledge map    Save Influenced by crude oil properties, water flooding with self-emulsification in heavy oil reservoirs is different from conventional water flooding, and the conventional theories for light oil water flooding are not applicable to heavy oil reservoirs. Taking a heavy oil reservoir with self-emulsification water flooding and the reservoir fluid parameters in China as cases, the water flooding with heavy oil self-emulsification was studied through laboratory experiments and numerical simulations to clarify key mechanisms and main influencing factors. The new numerical simulation method reveals that the stable displacement stage of the self-emulsification water flooding is a quasi-piston oil displacement pattern. The development process can be divided into four stages, namely pure oil, transition, plateau and rapid WOR increase. Permeability ratio and crude oil viscosity are the main factors affecting the water cut in self-emulsification water flooding, followed by permeability and water injection rate. Table and Figures | Reference | Related Articles | Metrics

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Enhanced Recovery in Middle and Late Stages of Depletion Development of Condensate Gas Reservoirs With Oil Ring HUANG Zhaoting, LI Chuntao, WANG Bin, QIAO Xia, FU Ying, YAN Bingxu Xinjiang Petroleum Geology    2024, 45 (4): 470-474.   DOI: 10.7657/XJPG20240411 Abstract （236）   HTML （10）    PDF（pc） （549KB）（186）       Knowledge map    Save The depletion development of Y5 condensate gas reservoir in the Tarim basin encounters the challenges such as rapid decline in both reservoir pressure and well productivity, gradual decrease in produced gas-oil ratio, increase in condensate oil density and viscosity, and fast downgrading of development performance. Combining performance analysis and reservoir fluid component evaluation, the Y5 condensate gas reservoir was redefined as a layered condensate gas reservoir with oil ring and edge water and the thickness of the oil ring was determined through numerical simulation. To improve the development performance and enhance the condensate oil/gas recovery, a systematic investigation was conducted on the mechanism of enhanced recovery in the middle and late stages of depletion development of the condensate gas reservoir with oil ring. It is found that optimizing the well pattern and implementing cyclic gas injection can significantly improve oil and gas recovery. Gravity-assisted gas drive is recommended, with CO2 being the optimal injection medium, followed by reservoir gas. Based on reservoir type and enhanced recovery mechanism, a scheme of cyclic gas injection for enhancing the recovery of Y5 condensate gas reservoir was developed, with an expected oil recovery 29.96% higher than that of depletion development alone. Under this scheme, a cumulative gas volume of 0.19×108 m3 was injected, the reservoir pressure restored by 4.31 MPa, and the well productivity increased by 3.09 times compared to that before the scheme was implemented. The research results provide valuable reference for enhancing recovery in the middle and late development stages of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Fracture Characteristics and Seismic Prediction of Z4 Metamorphic Buried-Hill Reservoir DING Sheng, LIU Jinhua, SHANG Yamin, PENG Pai, FU Jinxiang Xinjiang Petroleum Geology    2024, 45 (5): 516-521.   DOI: 10.7657/XJPG20240502 Abstract （243）   HTML （7）    PDF（pc） （3488KB）（182）       Knowledge map    Save Seismic prediction of fractures is the foundation of fractured reservoir evaluation. Metamorphic buried-hill reservoirs exhibit diverse fracture types, significant variations in fracture development at different reservoir parts, and difficulties in describing fracture heterogeneity. The Z4 metamorphic buried-hill reservoir was investigated for its fracture characteristics and seismic prediction. The development of fractures in the Z4 reservoir has layering characteristics and can be divided into four sections such as weathered-semi-filled fractures at the top, highly developed net-like fractures in the upper part, moderately developed low-angle fractures in the middle part, and poorly developed high-angle fractures at the bottom. A comprehensive fracture prediction technique was proposed, which integrates multi-scale general spectral decomposition, dip-oriented eigenvalue coherent processing, and iterative ant analysis. The fracture orientations and development revealed by cores were compared with the results of seismic prediction, suggesting a high consistency. It is believed that the multi-approach comprehensive fracture seismic prediction technology proposed in this study has high accuracy. Table and Figures | Reference | Related Articles | Metrics

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Application of Logging Data Wavelet Transform and Pseudo-Imaging to Fine Division of Deep Barrier/Interlayer SHAO Cairui, WANG Meng, CHANG Lunjie, WANG Kaiyu, ZHANG Fuming, WANG Chao Xinjiang Petroleum Geology    2024, 45 (5): 611-621.   DOI: 10.7657/XJPG20240514 Abstract （182）   HTML （6）    PDF（pc） （1474KB）（180）       Knowledge map    Save Barrier/interlayer is a key factor that significantly affects fluid flow and controls the distribution of oil and water, and it serves as a crucial evidence for understanding the distribution of remaining oil. Barrier/interlayer in deep strata is difficult to identify due to the high coring cost, large depth error in logging data, low resolution of conventional logging curves, and ambiguous signals from thin interbeds. Through core analysis of key wells, the logging curves sensitive to barrier/interlayer and their response characteristics were identified. By employing wavelet decomposition and reconstruction, the conventional sensitive logging curves were processed with high resolution, which reduced the smoothing effect of adjacent layers and highlighted the logging response characteristics of thin layer interfaces, making thin layer identification resolution enhanced by nearly 100%. By integrating the vector pattern of formation dip and pseudo-imaging characteristics of barrier/interlayer, a method for identifying and dividing deep barrier/interlayer was established. Actual applications demonstrate that this method allows for precise identification of barrier/interlayer, with a much higher capability than conventional methods. This method yields an accuracy of layer correlation between wells increased by 38%, elucidating the issue of inclined oil-water contact and providing remaining oil distribution. Table and Figures | Reference | Related Articles | Metrics

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Diagenetic Facies Division of Chang 8 Tight Sandstone Reservoirs in Eastern HQ Block，Longdong Area PENG Xiaoyong, LIU Guoli, WANG Bing, WEI Tao, REN Lijian, WANG Wei, REN Jiangli Xinjiang Petroleum Geology    2023, 44 (4): 383-391.   DOI: 10.7657/XJPG20230401 Abstract （323）   HTML （24）    PDF（pc） （13768KB）（180）       Knowledge map    Save To determine the diagenetic facies and their evolution patterns of the Chang 8 tight sandstone reservoir in the eastern part of the HQ block in the Longdong area of the Ordos basin, the diagenetic facies and logging facies of the cores from individual sand layers were divided by using the data of cast thin section, rock property, coring, and logging. Then, the diagenetic facies of the Chang 8 reservoir were classified with the dominant facies method, the favorable diagenetic facies for oil and gas exploration were determined, and the distribution zones of favorable diagenetic facies were predicted. Considering the diagenetic influences, the diagenetic facies of target layers can be classified into five categories: facies of residual intergranular pores and feldspar dissolution, facies of chlorite-cemented residual intergranular pores, strongly chlorite-illite cementation facies, authigenic carbonate cementation facies, and clay matrix compaction facies. The facies of residual intergranular pores and feldspar dissolution is the most favorable for hydrocarbon accumulation in the study area. Generally, the favorable diagenetic facies distribute as strips with good continuity and in large areas. The central and east-central parts of the study area are the main development zones for favorable diagenetic facies belts. Table and Figures | Reference | Related Articles | Metrics

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Shale Lithology Identification Based on Improved Random Forest Algorithm：A Case of Lucaogou Formation in Junggar Basin QIN Zhijun, CAO Yingchang, FENG Cheng Xinjiang Petroleum Geology    2024, 45 (5): 595-603.   DOI: 10.7657/XJPG20240512 Abstract （212）   HTML （5）    PDF（pc） （6023KB）（178）       Knowledge map    Save In the application of reservoir lithology identification, the efficiency, accuracy and effective information integration ability of machine learning algorithm have been fully verified, especially in unconventional reservoirs with strong heterogeneity such as shale. Based on the optimal selection of parameters such as natural gamma, T2 geometric mean, structural index, skeleton density index, density, and deep lateral resistivity, and using a random forest algorithm combined with recursive feature elimination (RF-RFE), major lithologies of the shale reservoirs in the Middle Permian Lucaogou formation in the Junggar basin were identified. Lithology prediction was conducted on the same dataset using conventional RF and support vector machine (SVM) algorithms, and the results were compared with those obtained from thin-section identifications. It is found that RF-RFE yields better results with only half of the logging parameters, and the parameters defined by optimal selection help reduce the algorithm’s running time. Thus, the use of RF-RFE algorithm can realize optimal selection of characteristic logging parameters, more accurate identification of shale lithology, and reduction of running time. The algorithm provides a new approach for complex lithology identification and multi-parameter selection. Table and Figures | Reference | Related Articles | Metrics