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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 （317）   HTML （537）    PDF（pc） （2522KB）（256）       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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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 （259）   HTML （7）    PDF（pc） （734KB）（104）       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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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 （254）   HTML （26）    PDF（pc） （18631KB）（175）       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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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 （205）   HTML （20）    PDF（pc） （13768KB）（146）       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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Sequence Division of Shiqiantan Formation in Shiqiantan Sag on Eastern Uplift of Junggar Basin KANG Jilun, FU Guobin, HAN Cheng, LIANG Hui, MA Qiang, LIANG Guibin, CHEN Gaochao Xinjiang Petroleum Geology    2023, 44 (3): 265-276.   DOI: 10.7657/XJPG20230302 Abstract （200）   HTML （506）    PDF（pc） （27313KB）（103）       Knowledge map    Save In order to establish a standard section of the Upper Carboniferous Shiqiantan formation in the Shiqiantan sag on the eastern uplift of the Junggar basin, and to provide a basis for the division and correlation of the subsurface strata and for the oil and gas exploration in the sag, field survey was carried out. By using geological coastean, and through comprehensive analysis on lithological characteristics, sedimentary formations, contact relationships, marker beds, and paleontological fossils, the sequence division, sedimentary facies restoration, and regional stratigraphic correlation were completed for the Shiqiantan formation. The Shiqiantan formation underwent the deposition of alluvial fan (fan delta), pre-fan lake and bay lagoon, forming three transgression-retrogradation sequences. The Shiqiantan formation can be divided into three members. The lower member is composed of conglomerate and sandy conglomerate intercalated with sandstone and siltstone in the lower part, medium-fine grained conglomerate, graywacke, and interbeds of mudstone and silty mudstone in the middle part, and silty mudstone and mudstone intercalated with sandstone and siltstone in the upper part. The middle member is composed of conglomerate, pebbly sandstone and sandstone intercalated with siltstone in the lower part, and calcareous silty mudstone, mudstone, siltstone and argillaceous limestone in the upper part. The upper member is composed of conglomerate, sandstone and interbeds of siltstone and silty mudstone in the lower part, purple-brown and brick-red mudstone and argillaceous siltstone intercalated with gravel-bearing gritstone and conglomerate in the middle part, and dark grey mudstone and silty mudstone intercalated with limestone in the upper part. Macroscopically, the lower member, middle member, and the upper part of the upper member are dark grey, and the lower part of the upper member is light brown to brick-red; all members are normally graded. The dark mudstones of pre-fan swamp-bay lagoon facies are favorable source rocks, while the sandstones and conglomerates of mid-fan and fan-apex facies are reservoir rocks. The good source-reservoir assemblage suggests favorable petroleum geology conditions. 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 （194）   HTML （12）    PDF（pc） （671KB）（130）       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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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 （192）   HTML （19）    PDF（pc） （9433KB）（107）       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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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 （187）   HTML （502）    PDF（pc） （1407KB）（113）       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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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 （180）   HTML （17）    PDF（pc） （563KB）（88）       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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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 （174）   HTML （19）    PDF（pc） （5123KB）（92）       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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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 （168）   HTML （16）    PDF（pc） （671KB）（102）       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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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 （167）   HTML （20）    PDF（pc） （576KB）（99）       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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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 （164）   HTML （17）    PDF（pc） （720KB）（154）       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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Microscopic Characteristics of Fine-Grained Reservoirs in Lucaogou Formation, Santanghu Basin QIN Enpeng, ZHANG Junying, ZHANG Shengbing, LIU Juntian, ZHANG Xiaoqin, CHEN Yonghui Xinjiang Petroleum Geology    2023, 44 (3): 299-306.   DOI: 10.7657/XJPG20230305 Abstract （164）   HTML （16）    PDF（pc） （12481KB）（73）       Knowledge map    Save The fine-grained rocks in volcanic-active strata are characterized by complex composition, tight cementation, and strong heterogeneity. The concept and classification methods of fine-grained rocks were systematically reviewed. Combined with rock thin section identification, whole-rock X-ray diffraction (XRD) experiment, and scanning electron microscope-energy dispersive spectroscopy (SEM-EDS) experiment, a method for studying the microscopic characteristics of fine-grained reservoirs was established. By using this method, the petrological characteristics, and types and genesis of reservoir spaces of the fine-grained rocks in the Lucaogou formation of the Santanghu basin were analyzed. The results show that the fine-grained reservoirs in the Lucaogou formation are mainly composed of fine-grained carbonate rocks and fine-grained volcanoclastic rocks. The reservoir space is mainly contributed by fractures and pores, and the fractures are dominantly structural fractures and interbed. Fine-grained volcanoclastic rocks generally have volcanic dust solution pores, rock debris solution pores, crystal debris solution pores, and calcite vein solution pores. Micro-nanopores are relatively developed in fine-grained carbonate rocks, including dolomite intercrystalline pores, calcite intercrystalline pores, and clay mineral intercrystalline pores. The enrichment of volcanic material provides material basis for high-quality fine-grained reservoirs in volcanic-active strata, and the alternation of various laminae in fine-grained reservoirs is conducive to the formation of micropores and microfractures. 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 （157）   HTML （5）    PDF（pc） （1137KB）（172）       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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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 （157）   HTML （13）    PDF（pc） （1855KB）（118）       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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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 （154）   HTML （19）    PDF（pc） （699KB）（102）       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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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 （153）   HTML （14）    PDF（pc） （5762KB）（153）       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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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 （153）   HTML （12）    PDF（pc） （7528KB）（119）       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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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 （153）   HTML （26）    PDF（pc） （1024KB）（146）       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