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Practices and Cognitions of Petroleum Exploration in Mesozoic,Ordos Basin LUO Anxiang, YU Jian, LIU Xianyang, JIAO Chuangyun, HAN Tianyou, CHU Meijuan Xinjiang Petroleum Geology    2022, 43 (3): 253-260.   DOI: 10.7657/XJPG20220301 Abstract （567）   HTML （31）    PDF（pc） （1437KB）（403）       Knowledge map    Save The Ordos basin is the second largest sedimentary basin in China with abundant oil and gas resources and broad exploration prospects. Typical low-permeability-tight oil reservoirs are develpoed in the Triassic Yanchang formation in the basin,which are difficult to explore. Through continously geological researches on the Mesozoic oil reservoirs in the Ordos basin over the past 50 years,some theories about hydrocarbon accumulation in Jurassic reservoir groups,in large-scale lithologic reservoirs in inland depression lake basins and in continental shales have been formed. By virtue of three strategic shifts,four conventional hydrocarbon provinces with reserves exceeding 10×108 t and a successive zone with shale oil reserves of 20×108 t have been discovered. The proven oil reserves have increased by an average of over 3×108 t per year for 10 consecutive years. Thus,Changqing oilfield in Ordos basin has become an oil and gas province with the fastest increase in reserves and production in China and contributed 12.5% of China's annual oil production,which provides a reference for the petroleum exploration in other similar basins. Table and Figures | Reference | Related Articles | Metrics

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Production Performance Analysis and Productivity Prediction of Horizontal Wells in Mahu Tight Conglomerate Reservoirs：A Case of Ma 131 Dense-Spacing 3D Development Pad CAO Wei, XIAN Chenggang, WU Baocheng, YU Huiyong, CHEN Ang, SHEN Yinghao Xinjiang Petroleum Geology    2022, 43 (4): 440-449.   DOI: 10.7657/XJPG20220409 Abstract （287）   HTML （18）    PDF（pc） （1161KB）（267）       Knowledge map    Save In order to clarify the productivity and production performance of Ma131 dense-spacing 3D development pad,the production characteristics and unstable production/productivity were predicted,a workflow for performance analysis and productivity prediction was established,and the key parameters such as equivalent formation permeability and effective fracture half-length,etc. were determined for single well productivity prediction. Oil in the target reservoir is easy to be degassed,which may be effectively alleviated by running the gas nozzle into the hole in the early stage. The use of over-sized oil nozzle in the early stage of flowback may greatly decrease the fracture volume; in this case,a pressure-managed flowback is necessary. The P50 productivity prediction results obtained from the production decline curves and the analytical model can complement each other,providing a more accurate and reasonable productivity prediction interval. The average effective fracture half-length of horizontal well in T1b3 is greater than that in T1b1 2; therefore,the well spacing can be further optimized. Table and Figures | Reference | Related Articles | Metrics

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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 （323）   HTML （537）    PDF（pc） （2522KB）（257）       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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Well Logging Evaluation of Bauxite Reservoirs in Ordos Basin LIU Die, ZHANG Haitao, YANG Xiaoming, ZHAO Taiping, KOU Xiaopan, ZHU Baoding Xinjiang Petroleum Geology    2022, 43 (3): 261-270.   DOI: 10.7657/XJPG20220302 Abstract （495）   HTML （21）    PDF（pc） （4208KB）（243）       Knowledge map    Save Bauxite gas reservoir is a kind of very rare unconventional gas reservoir recently discovered in the Ordos basin, and well logging evaluation plays an important role in its exploration and development. In the early well logging evaluation, bauxite was considered as the weathering crust caprock, but not as a reservoir, and there was no systematic well logging evaluation method suitable for the exploration and development of bauxite gas reservoirs. Based on the aluminous rocks in Taiyuan formation in the Longdong area, southwestern Ordos basin, the well logging evaluation method for bauxite gas reservoirs was studied from five aspects, that is, qualitative lithology identification, mineral composition, reservoir physical properties, quantitative calculation of gas-bearing properties and systematic summary of imaging model-pore structure characteristics. The well logging response for identifying aluminous rock formations was clarified and the aluminous rock identification chart by acoustic time-gamma ray was established. The porosity-permeability-saturation evaluation model for bauxite gas reservoirs was constructed through petrophysical experiments, and the criteria for identifying bauxite reservoir was proposed by combining micro-resistivity scanning imaging and nuclear magnetic resonance logging data. Finally, a well logging evaluation method for bauxite gas reservoirs was formed. Table and Figures | Reference | Related Articles | Metrics

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Deformation and Favorable Area Evaluation of Shunbei No.4 Strike-Slip Fault Zone in Tarim Basin LI Haiying, HAN Jun, CHEN Ping, LI Yuan, BU Xuqiang Xinjiang Petroleum Geology    2023, 44 (2): 127-135.   DOI: 10.7657/XJPG20230201 Abstract （346）   HTML （39）    PDF（pc） （7486KB）（241）       Knowledge map    Save The Shunbei No. 4 strike-slip fault zone which is located in the Shuntuoguole low uplift of the Tarim basin and extends northward to the Shaya uplift is characterized by deep burial，horizontal segmentation，vertical stratification，multi-stage activities，and complex structure. Through the interpretation of high-quality 3D seismic data from the Shunbei No. 4 strike-slip fault zone，the stratification，segmentation，staging，activity and favorable area evaluation of the fault zone were carried out. The results show that the Shunbei No. 4 strike-slip fault zone has a 4-layer structure in the Paleozoic，roughly bounded by the top of the Middle Ordovician，above which echelon faults are found and below which high-steep strike-slip faults are developed. The strike-slip fault zone is visibly segmented into the northern segment，the middle segment，and the southern segment according to the strike，showing an overall characteristic of compressed in south and extended in north. In the Paleozoic，the strike-slip fault zone successively experienced four periods of activity，namely，EpisodeⅠof the middle Caledonian，Episode Ⅲ of the middle Caledonian，late Caledonian，and Hercynian. By combining the main controlling factors (e.g. source-reservoir connectivity，reservoir size，and late adjustment) for hydrocarbon enrichment and accumulation in the Shunbei area，the favorable areas in the Shunbei No. 4 strike-slip fault zone were evaluated. Multiple favorable areas have been identified and then verified by actual drilling. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Characteristics and Sand Body Architecture of Shallow Delta Front in Ordos Basin: A Case Study of Chang 9 Member in Shiwanghe Section in Yichuan REN Yilin, ZHAO Junfeng, CHEN Jiayu, GUAN Xin, SONG Jinggan Xinjiang Petroleum Geology    2022, 43 (3): 310-319.   DOI: 10.7657/XJPG20220307 Abstract （366）   HTML （8）    PDF（pc） （5476KB）（239）       Knowledge map    Save As an important reservoir for storing oil and gas,the sand bodies in delta front are found with enormous petroleum exploration potential. However,there are few studies on architecture of sand bodies in shallow delta front through field outcrops. Guided by sedimentology and reservoir architecture theories,the outcrop observation and sampling was combined with the results of laboratory experiments and statistical analysis to clarify the sedimentary characteristics and sand body architecture of Chang 9 member in the Shiwanghe section in Yichuan,Ordos basin. The results show that during the deposition,the Chang 9 member in Shiwanghe section lied in a warm and humid environment,especially an oxidation to weak-reduction transitional freshwater environment that was not obviously stratified,and shallow delta front subfacies was mainly developed,including microfacies such as underwater distributary channel,estuary bar,sheet sand and interdistributary bay. The single sand bodies of shallow delta front in Chang 9 member in the study area can be divided into two vertical stacking styles such as non-connected and connected,and two lateral contact styles such as butted and cut-stacked. The accommodation growth rate and sediment supply rate jointly controlled by terrain slope and lake level rise/fall are important factors affecting the spatial development style of the composite sand bodies. The gentle slope allows the channels to incise weakly and present the characteristics of plane intersection. The rise of lake level and the decrease of source supply increase the ratio of accommodation growth rate to sediment supply rate,which may lead to the weakening of sand body connectivity. The architecture models of sand bodies like river-river cut stacking and river-bar cut stacking are favorable for hydrocarbon accumulation. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Connectivity of Fault-Controlled Fractured-Vuggy Reservoirs: A Case Study of Unit T in Tuofutai Area, Tahe Oilfield LI Jun, TANG Bochao, HAN Dong, LU Haitao, GENG Chunying, HUANG Mina Xinjiang Petroleum Geology    2022, 43 (5): 572-579.   DOI: 10.7657/XJPG20220509 Abstract （293）   HTML （10）    PDF（pc） （3554KB）（233）       Knowledge map    Save Fault-controlled fractured-vuggy reservoirs are extremely heterogeneous and exhibit the diversity and complexity in inter-well connectivity. Clarifying the influence of faults and karsts on reservoirs is conducive to reservoir connectivity analysis and injection-production strategy adjustment. Taking Unit T in the Tuofutai area of Tahe oilfield as an example, the development characteristics of reservoirs were systematically analyzed based on the results of seismic interpretation and the analysis of overlying water system and production performance responses. It was clarified that the reservoir development is mainly controlled by faults and surface water systems. The difference in karstification intensity leads to different characteristics of the reservoirs, which makes development wells show different production behaviors and inter-well connectivities. Based on the analysis of dynamic and static data, an inter-well connectivity model suitable for fault-controlled fractured-vuggy reservoirs was established, which can provide a basis for the adjustment of subsequent treatments. Table and Figures | Reference | Related Articles | Metrics

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Formation Mechanism and Geological Significance of Carbonate Cements in Baikouquan Formation on Northern Slope of Mahu Sag LYU Huanze, ZOU Niuniu, CAI Ningning, HUANG Yongzhi, NING Shitan, ZHU Biao Xinjiang Petroleum Geology    2022, 43 (5): 554-562.   DOI: 10.7657/XJPG20220507 Abstract （275）   HTML （12）    PDF（pc） （2281KB）（220）       Knowledge map    Save In order to further investigate the diagenetic environment, formation mechanism of carbonate cements and its influences on the physical properties of the sandy conglomerate reservoirs in the Lower Triassic Baikouquan formation on the northern slope of the Mahu sag, Junggar basin, the types, forming periods, and genesis of the carbonate cements in the study area and their effects on the reservoirs were studied through combining core observation, rock thin section identification and measurement of carbon and oxygen isotopes in carbonate cements. The results show that there are three periods of carbonate cements in the Baikouquan formation on the northern slope of the Mahu sag, that is, from early to late, micritic calcite in Period Ⅰ, ferrocalcite in Period Ⅱ, and ankerite in Period Ⅲ. δ13CPDB ranges from -47.23‰ to 3.88‰, while δ18OPDB ranges from -23.64‰ to -17.98‰. The bigger range of δ13CPDB reveals the presence of various carbon sources and the complex interaction between water and rock. The paleosalinity and paleotemperature restored from the carbon and oxygen isotope calculations show that the carbonate cements were mainly formed in freshwater environments, and partly influenced by seawater. The Baikouquan formation in Well Ma-19 is a low-porosity and low-permeability reservoir as a whole. The physical properties of the Bai 2 member are slightly better than those of the Bai 3 member, presumably indicating the presence of secondary pores. Post-drilling analysis finds that oil layers are developed in both Bai 2 member and Bai 3 member, which is basically consistent with the conclusion obtained from carbon and oxygen isotope analysis. Table and Figures | Reference | Related Articles | Metrics

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Technologies and Application of Sidetracking Horizontal Well in Existing Wells in Sulige Gas Field WANG Liqiong, WANG Zhiheng, MA Yulong, ZENG Qingxiong, ZHENG Fan Xinjiang Petroleum Geology    2022, 43 (3): 368-377.   DOI: 10.7657/XJPG20220316 Abstract （280）   HTML （7）    PDF（pc） （1058KB）（215）       Knowledge map    Save In order to improve the effective reservoir encounter rate during sidetracking drilling in existing wells,with a block in central Sulige gas field as an example,and combined with the geological characteristics and development status of the gas field,the key geological technologies for sidetracking horizontal drilling in existing wells were summarized from the aspects of optimal deployment and geosteering. On this basis,the development effect of sidetracking horizontal wells was discussed in light of drilling effect,production index,benefit evaluation,etc.,and the influence of various factors on the development effect was comprehensively analyzed. The research results show that the remaining gas mainly enriches in the areas including the rim of mid-channel bar,braided channel,and middle or bottom of the mid-channel bar in the sand belt of main channel. Based on the economic evaluation,the selection criteria for sidetracking well locations were established,that is,the lower limit of the effective thickness of recoverable beds is 4 m vertically,and the lower limit of the abundance of the remaining reserves is 0.42×108 m3/km2 on the plane. Using 3D geological model,stratigraphic dip evaluation,pilot hole information and data acquired while drilling,the horizontal-well geosteering sidetracking technology was formed,and three horizontal-section geosteering modes were provided. For 23 sidetracking horizontal wells in the study area,the average effective reservoir encounter rate is 59.7%,the average initial gas production is 2.9×104 m3,and the cumulative incremental production is 3.13×108 m3. Table and Figures | Reference | Related Articles | Metrics

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Core Experiment and Stimulation Mechanism of Unstable Waterflooding in Low Permeability Reservoirs ZHOU Jinchong, ZHANG Bin, LEI Zhengdong, SHAO Xiaoyan, GUAN Yun, CAO Renyi Xinjiang Petroleum Geology    2022, 43 (4): 491-495.   DOI: 10.7657/XJPG20220417 Abstract （300）   HTML （11）    PDF（pc） （1256KB）（214）       Knowledge map    Save According to the typical characteristics of low permeability reservoirs in Changqing oilfield, parallel core and double-layered core experiments were carried out to simulate the effect of unstable waterflooding in heterogeneous low permeability reservoirs. Due to the poor visibility of core experiments, numerical models for simulating interlayer and intralayer heterogeneous reservoirs were established, which may reveal the stimulation mechanism of unstable waterflooding according to the change of flow field. The results show that for interlayer heterogeneous reservoirs, compared with continuous waterflooding, unstable waterflooding can promote the advancement of the flooding front in the layers with lower permeability, and give full play to capillary force in oil displacement, so unstable waterflooding can significantly improve the oil recovery of the layers with lower permeability, and the pattern of short-term injection combined with long-term quit can enhance the recovery rate the most. For intralayer heterogeneous reservoirs, unstable waterflooding can generate pressure oscillations in the layers to enable the fluid percolation between the higher permeability layers and the lower permeability layers, so that the sweep efficiency of injected water in the lower permeability layers is increased and the recovery rate of the lower permeability layers is enhanced, thereby increasing the total oil recovery rate of the reservoir. Table and Figures | Reference | Related Articles | Metrics

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Influences of Shale Rheology on Pore Structures of Qiongzhusi Formation in Chengkou Area, Northeastern Sichuan Basin YU Shuyan, WANG Yang, FENG Hongye, ZHU Hongjian Xinjiang Petroleum Geology    2022, 43 (5): 513-518.   DOI: 10.7657/XJPG20220502 Abstract （308）   HTML （10）    PDF（pc） （14955KB）（209）       Knowledge map    Save In order to determine the influence of natural rheology of shale on microscopic pore structure, taking the marine shale of the Lower Cambrian Qiongzhusi formation in the Chengkou area, northeastern Sichuan basin as an example, the types and characteristics of rheological structure and microscopic pore structure in the shale and their relationship were studied by using rock thin sections, focused ion beam scanning electron microscope and low temperature liquid nitrogen adsorption experiment. The microstructures of shale rheology mainly include porphyroclast system, cataclastic flow, pressolutional stylolites, microscopic fold, S-C fabric and crenulation cleavage, and the micro-nano structures include mylonite zone, micro-hybrid zone, and rotating porphyroclast. Rheological shale is dominated by nanoscale intergranular pores, and most of the primary pore structure is difficult to preserve under rheological action. Ductile rheology leads to a decrease in the number of pores, pore diameter, pore volume and pore specific surface area of shale, which reduces the storage performance of shale. Table and Figures | Reference | Related Articles | Metrics

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Influences of Cemented Natural Fractures on Propagation of Hydraulic Fractures CHENG Zhenghua, AI Chi, ZHANG Jun, YAN Maosen, TAO Feiyu, BAI Mingtao Xinjiang Petroleum Geology    2022, 43 (4): 433-439.   DOI: 10.7657/XJPG20220408 Abstract （253）   HTML （8）    PDF（pc） （2487KB）（207）       Knowledge map    Save In order to determine the role of natural fractures in the forming of hydraulic fracture network in tight sandstone reservoirs, a numerical model was established using the coupled hydraulic-mechanical-damage (HMD) model, and a fracture network model was generated in the numerical model by the Monte-Carlo method. With these models, the influences of natural fracture orientation, natural fracture strength, horizontal principal stress difference, fracturing fluid injection rate and fracturing fluid viscosity on the propagation of hydraulic fractures were analyzed. The results show that when the angle between the natural fracture and the maximum horizontal principal stress direction ranges from 30° to 60°, the induced hydraulic fractures are the most complex. The increase in natural fracture strength is not conducive to the generation of branch and steering fractures. Under the condition of low horizontal principal stress difference, the orientation of natural fractures dominates the extension of hydraulic fractures. Under the condition of high horizontal principal stress difference, stress dominates the extension of hydraulic fractures. When the horizontal principal stress difference falls between 3.0 and 4.5 MPa, the hydraulic fractures exhibit the highest complexity and the largest extension. Increasing the injection rate of fracturing fluid can promote the formation of complex hydraulic fracture network. Appropriately increasing the viscosity of fracturing fluid can promote fracture propagation, but too high viscosity can only lead to complex fractures in limited areas around the perforations. Table and Figures | Reference | Related Articles | Metrics

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Comprehensive Evaluation on Steam Chamber Location and Production Prediction of SAGD in Heavy Oil Reservoirs GUO Yunfei, LIU Huiqing, LIU Renjie, ZHENG Wei, DONG Xiaohu, WANG Wuchao Xinjiang Petroleum Geology    2022, 43 (4): 484-490.   DOI: 10.7657/XJPG20220416 Abstract （264）   HTML （5）    PDF（pc） （673KB）（204）       Knowledge map    Save Production and steam chamber location are critical for steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The existing prediction model only considers the lateral expansion of steam chamber and cannot predict the production of adjacent wells after steam chamber contact. According to the different characteristics of the steam chamber in the lateral expansion stage and the downward expansion stage, a parameter of thermal penetration depth was introduced, the flow potential function was modified, and a parabolic production prediction model was established. The results show that the production increases gradually in the initial lateral expansion stage of steam chamber, and then decreases due to the reduction of the inclination of the steam chamber interface; in the downward expansion stage of steam chamber, the production further decreases. The model analysis reveals that SAGD is more suitable for thick reservoir development, and the optimal well spacing needs to be determined depending on the oilfield conditions. The parabolic production prediction model takes the characteristics of the steam chamber into account in the downward expansion stage, and the accuracy of the model is verified by comparing with the previous experimental data. Table and Figures | Reference | Related Articles | Metrics

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Shale Oil Enrichment Mechanism and Sweet Spot Selection of Fengcheng Formation in Mahu Sag，Junggar Basin JIN Zhijun, LIANG Xinping, WANG Xiaojun, ZHU Rukai, ZHANG Yuanyuan, LIU Guoping, GAO Jiahong Xinjiang Petroleum Geology    2022, 43 (6): 631-639.   DOI: 10.7657/XJPG20220601 Abstract （360）   HTML （27）    PDF（pc） （5508KB）（199）       Knowledge map    Save The Fengcheng formation in the Mahu sag is an alkaline lake sediment，and is divided into Feng 1 member，Feng 2 member and Feng 3 member from bottom to top. In the Fengcheng formation，the lithology vertically changes rapidly，the mineral composition is complex，and the organic-rich shale source is integrated with the shale reservoir. The formation bears oil universally，but the sweet spots are scattered. The results of formation testing for single layers are not satisfied，showing an unclear production potential. According to core slices and geochemical analyses，the Fengcheng formation in the Mahu sag is dominated by lamellar silty shale intercalated with dolomite，which are mainly composed of terrigenous clastic minerals and carbonate minerals. With the variation of burial depth，the pore volume changes consistently with the variation of surface area of pores，and the pore volume is mainly contributed by macropores (pore diameter > 50 nm). The source rock is dominated by Type Ⅱ organic matter，and the vitrinite reflectance ranges from 0.85% to 1.40%，indicating a peak oil generation period. There are many shear fractures with middle to high angles in the Feng 2 member，and shear fractures with middle to high angles and structural fractures with low angles in the Feng 3 member，whose formation and development degree are controlled by lithology，mineral composition，rock mechanical properties，etc. Based on the characteristics of lithologic assemblage，reservoir property and oil-bearing property，four relatively concentrated sweet spots have been identified. When performing multi-interval formation testing and production testing in vertical wells，it is necessary to select sweet spots with good oil content and more fractures to conduct geological research and geology-engineering integration technology research，and to perform production improvement tests in horizontal wells，so as to realize comprehensive breakthrough for shale oil exploration and development in the Fengcheng formation in the study area Table and Figures | Reference | Related Articles | Metrics

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Accumulation Conditions and Exploration Direction of Lower Jurassic Tight Sandstone Gas Reservoirs in Taibei Sag CHEN Xuan, WANG Jufeng, XIAO Dongsheng, LIU Juntian, GOU Hongguang, ZHANG Hua, LIN Lin, LI Hongwei Xinjiang Petroleum Geology    2022, 43 (5): 505-512.   DOI: 10.7657/XJPG20220501 Abstract （344）   HTML （29）    PDF（pc） （3198KB）（196）       Knowledge map    Save The Turpan-Hami basin has great potential of oil and gas resources in the Lower Jurassic strata, with a large quantity of remaining resources. The discovered oil and gas reservoirs are mainly distributed in the positive structural belts around the Shengbei and Qiudong subsags in the Taibei sag, and they are primarily structural reservoirs. Less researches on the oil and gas resources in the hinterland of the subsags have been performed. Based on the dissection of known reservoirs, a systematic study was carried out on the depositional system, source rock, reservoir rock and accumulation conditions of three major hydrocarbon-rich subsags in the Taibei sag. The results show that the coal-measure source rocks are widely developed in the Shuixigou group in the Taibei sag and are in broad contact with the braided river delta sandstones, which is conducive to the formation of near-source tight sandstone gas reservoirs. There are two types of tight sandstone gas reservoirs in the Lower Jurassic, namely, trap-type and continuous-type. The hinterlands of the subsags are favorable areas for the formation of continuous-type tight sandstone gas reservoirs. Therefore, the exploration should be switched from the source-edge positive structure to the hydrocarbon-rich subsag, and from the above-source conventional oil reservoirs to the in/near-source tight sandstone gas reservoirs. The hinterlands of the Shengbei and Qiudong subsags have the conditions to form large gas reservoirs, so they are favorable areas for exploring near-source tight sandstone gas reservoirs in the lower Jurassic. Table and Figures | Reference | Related Articles | Metrics

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Sand Body Architecture of Chang 9 Member in Jiyuan Area,Ordos Basin WU Zemin, KE Xianqi, ZHANG Pan, WEN Fengqin, TONG Qiang, LIU Linyu Xinjiang Petroleum Geology    2022, 43 (3): 294-309.   DOI: 10.7657/XJPG20220306 Abstract （268）   HTML （3）    PDF（pc） （6534KB）（195）       Knowledge map    Save In order to clarify the spatial configuration of sand bodies under the dual-provenance background in Chang 9 member in Jiyuan area,Ordos basin,the sedimentary characteristics of Chang 9 member were determined by using the core,logging,test and production data. On this basis,the sand body architecture of Chang 9 member was dissected level by level to understand the development of sand bodies under the dual-provenance background and to characterize the architectural elements and their assemblage and distribution. The results reveal that there are 8 types of skeleton architectural elements in Chang 9 member,which are different from region to region: braided channel,abandoned channel and cross-bank deposits dominated by underwater distributary channel and interdistributary bay in the west; and estuary sand bar,front sheet sand and underwater natural levee in the east. On the plane,the architectural element of braided channel extends farther with continuous distribution,the architectural element of abandoned channel extends shortly with intermittent distribution,the architectural element of underwater distributary channel extends farther with discontinuous distribution,and the architectural element of estuary sand bar is usually in the side rear of the underwater distributary channel with poor continuity. Vertically,the superimposition and assemblage of the architectural elements of skeleton sand bodies become worse from bottom to top,and the architectural elements of braided river delta system in the west display better development scale and degree than those of meandering river delta system in the east. Table and Figures | Reference | Related Articles | Metrics

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Production System of Horizontal Well in Shale Oil Reservoirs of Chang 7 Member, Ordos Basin WAN Xiaolong, ZHANG Yuanli, FAN Jianming, LI Zhen, ZHANG Chao Xinjiang Petroleum Geology    2022, 43 (3): 329-334.   DOI: 10.7657/XJPG20220310 Abstract （216）   HTML （6）    PDF（pc） （3813KB）（194）       Knowledge map    Save To ensure the production of shale oil in Chang 7 member, Ordos basin, this paper discussed the production system of the horizontal well in Chang 7 member based on the theoretical research and production data. By establishing the relationship between the distance of the pressure propagation boundary from fractures induced by volume fracturing in horizontal well and the time, and assuming that the pressure propagated to the boundary does not change with time, the reasonable well soaking period is determined to be 40 d. It is considered that the high-watercut drainage stage ends when the analyzed salinity of the produced water is similar to the salinity of initial formation water, or the replacement rate of fracturing fluid in horizontal wells is greater than 60%. By quantitatively analyzing the production profile of a single section and a 100-m horizontal section in the horizontal well, the dynamic relationship was established for determining a reasonable fluid production for each stage. Table and Figures | Reference | Related Articles | Metrics

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Reservoir Benefit Classification and Development Countermeasures for Changqing Oilfield ZHOU Xiaoying, WEI Mingxia, ZHANG Yirong, LI Ting, XU Sen Xinjiang Petroleum Geology    2022, 43 (3): 320-323.   DOI: 10.7657/XJPG20220308 Abstract （280）   HTML （7）    PDF（pc） （464KB）（191）       Knowledge map    Save Influenced by the increasing reservoir types in Changqing oilfield and the low international crude oil price, clarifying the benefit categories of reservoirs and identifying the oil production limits of different types of reservoirs under different oil prices are urgent for Changqing Oilfield Company to make production and operation decisions. By combining the benefit evaluation with reservoir research, dynamic development, well production failure and comprehensive treatment, the relationship between cost or development index and benefits for different types of reservoirs was established, and the influencing factors of low-benefit wells were analyzed, providing a reference for cost-effective development of reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Inversion of Fracture Parameters and Formation Pressure for Fractured Horizontal Wells in Shale Oil Reservoir Based on Soaking Pressure WANG Fei, WU Baocheng, LIAO Kai, SHI Shanzhi, ZHANG Shicheng, LI Jianmin, SUO Jielin Xinjiang Petroleum Geology    2022, 43 (5): 624-629.   DOI: 10.7657/XJPG20220517 Abstract （349）   HTML （7）    PDF（pc） （884KB）（189）       Knowledge map    Save A fractured horizontal well in shale oil reservoir should be soaked before it is put into production. In order to quickly evaluate the effect of volume fracturing, a post-frac evaluation method based on the data of soaking pressure of shale oil reservoirs was proposed. Through numerical simulation of well soaking, the pressure diffusion and fluid migration in the stimulation area controlled by the fractured horizontal well were characterized, and a post-closure linear flow calculation model and a fracture storage control calculation model were established. Then a calculation method for inverting fracture parameters and formation pressure was formed. The results show that after pump is stopped, the stimulation area goes through 9 flow stages such as flows controlled by fractures in end section of wellbore, by fractures in the whole wellbore and by reservoir matrix, and the pressure drop derivatives appear as multiple straight-line segments with different slopes in log-log coordinates. This method has been applied to four typical shale oil horizontal wells in Jimsar sag, which proves that the data of soaking pressure can be used for the inversion of fracture parameters and formation pressure, and also verifies the applicability of the proposed method. The study results provide a reference for evaluating fracturing effect and optimizing well spacing. Table and Figures | Reference | Related Articles | Metrics

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Simulation on Fracture Propagation During Hydraulic Fracturing in Horizontal Wells in Shale Reservoirs of Fengcheng Formation，Mahu Sag YU Peirong, ZHENG Guoqing, SUN Futai, WANG Zhenlin Xinjiang Petroleum Geology    2022, 43 (6): 750-756.   DOI: 10.7657/XJPG20220613 Abstract （255）   HTML （5）    PDF（pc） （6827KB）（188）       Knowledge map    Save Hydraulic fracturing is an effective method for developing the shale reservoirs in the Permian Fengcheng formation in the Mahu sag，but the propagation characteristics of hydraulic fractures are unclear. Maye-1H，a typical horizontal well in this area，suffered from difficulties in fracturing initiation and sand addition. Thus，it is urgent to carry out hydraulic fracturing simulation to clarify the impacts of natural fractures，rock mechanical properties，and operation parameters on fracturing effect. According to the actual operation parameters such as pump pressure，fracturing fluid displacement and added sand volume in Well Maye-1H，a 2D hydraulic fracture propagation model and a 3D hydraulic fracturing model were established by using Abaqus software and Petrel software，and then numerical simulation on hydraulic fracture propagation was performed. The results show that the fracturing effect is closely related to natural fractures. The lower the tensile strength of the rock where natural fractures are developed，the easier the hydraulic fractures tend to be captured by the natural fractures. When the Young’s modulus in the fractured interval is relatively large，the hydraulic fractures formed are small in width，and most of them propagate and slip along the natural fracture trend，making it difficult to add sand. When the Young’s modulus in the fractured interval is relatively small，the hydraulic fractures formed are large in width，and they can directly pass through the natural fractures，making sand adding relatively easy. Table and Figures | Reference | Related Articles | Metrics

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VSP Reverse Time Migration Technology and Its Imaging Effect CHEN Keyang, YANG Wei, ZHAO Haibo, WANG Cheng, ZHU Lixu, LIU Jianying, LI Xingyuan Xinjiang Petroleum Geology    2022, 43 (5): 617-623.   DOI: 10.7657/XJPG20220516 Abstract （295）   HTML （9）    PDF（pc） （3976KB）（186）       Knowledge map    Save In order to improve the precision of VSP seismic imaging, a VSP reverse time migration (RTM) operator with 16-order finite difference accuracy was constructed, and then the algorithm accuracy of VSP key links and the interchangeability of shot and receiver points were analyzed by using impulse responses to verify the accuracy of the 3D VSP RTM operator. Based on the standard theoretical model of lava dome, the imaging effects of normalized VSP RTM and conventional cross-correlation RTM were compared. It is found that VSP RTM can describe the geological body boundary and formation interface more clearly and more accurately, and can eliminate the uneven influence of folds to make energy distribution more uniform, with no well trace. The high-precision 3D VSP RTM technology was applied to the walkaway VSP data of Well L in the Songliao basin, and accurate and fine imaging of near-wellbore formations and small faults was achieved, which further verified the accuracy of the technology. The proposed VSP RTM technology can help improve the imaging accuracy of complex reservoirs around the wellbore. Table and Figures | Reference | Related Articles | Metrics

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Dominant Water Flow Channels in Block VI of North Buzachi Oilfield CHI Yungang, TANG Zhixia, WEI Jing, ZHOU Huize, ZHANG Wenhui Xinjiang Petroleum Geology    2022, 43 (4): 496-504.   DOI: 10.7657/XJPG20220418 Abstract （264）   HTML （7）    PDF（pc） （968KB）（186）       Knowledge map    Save In order to understand the development characteristics of the dominant water flow channels in the North Buzachi oilfield, the dominant water flow channels in the target layers in Block VI of the oilfield were identified by using streamlined numerical simulation technology, and the development degree and formation pattern of the dominant water flow channels were quantitatively characterized. The results show that Class Ⅰand Ⅱ channels in the study area are the water flow channels with ineffective circulation, with water flooding sweep coefficient of only 0.120-0.175. For Class I channels, the water cut at the producer is greater than 97%, and the average sweep coefficient is 0.120, with extremely serious channeling. For Class II channels, the water cut at the producer ranges from 93% to 97%, and the average sweep coefficient is 0.175, with serious channeling. The dominant water flow channels are small in number and limited in volume, but they occupy most of the water volume, which results in inefficient water injection. The number of dominant channels is inversely proportional to the distance between injector and producer. The location of the main river channel is the main area where the dominant water flow channels are formed, especially in the direction that the connection line between the injector and the producer is parallel to the sedimentary direction of the main river channel. The longer the producing time of the producer and injector, and the higher the ratio of cumulative liquid production to water injection, the higher the probability of dominant channel occurs near the wells with high daily liquid production. Furthermore, the dominant water flow channels change with the initial production time of the producer and the adjustment of injector-producer relationship. Table and Figures | Reference | Related Articles | Metrics

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Factors Influencing Shale Oil Production and Sweet Spot Evaluation of Fengcheng Formation，Mahu Sag LIU Caiguang, JI Ruixue, WANG Wei, ZHANG Rong Xinjiang Petroleum Geology    2022, 43 (6): 733-742.   DOI: 10.7657/XJPG20220611 Abstract （226）   HTML （8）    PDF（pc） （2254KB）（181）       Knowledge map    Save The Fengcheng formation in the Mahu sag is of great potential in shale oil resources. However，its characteristics such as complex lithology，diverse mineral species，thin single layer，scattered sweet spots，and variable fracture occurrence make sweet spot selection challenging，which seriously affects the exploration process. Through the studies on the qualities of source rock，reservoir and engineering，and fracturing scale，the influences of TOC，chloroform bitumen “A” content，porosity，oil saturation，free oil content，brittleness index，pore pressure，two-directional stress difference and fracture development degree on production were systematically analyzed. The results show that the shale oil production from the Fengcheng formation are mainly controlled by four factors such as free oil content，brittleness index，fracture development degree，and large-scale volume fracturing. By using the logging data from 12 wells in the study area，the correlation between production and the controlling factors was analyzed，and a sweet spot classification standard suitable for the Fengcheng formation was established. The classification standard was successfully applied to the horizontal well Maye-1H for dividing sections and clusters，and it may provide a reference for subsequent exploration deployment. Table and Figures | Reference | Related Articles | Metrics

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Production Prediction of Fractured Horizontal Wells in Tight Oil Reservoirs SONG Junqiang, LI Xiaoshan, WANG Shuo, GU Kaifang, PAN Hong, WANG Xin Xinjiang Petroleum Geology    2022, 43 (5): 580-586.   DOI: 10.7657/XJPG20220510 Abstract （287）   HTML （13）    PDF（pc） （787KB）（181）       Knowledge map    Save Regarding complex flow regime and large error in lifecycle production prediction for fractured horizontal wells in tight oil reservoirs, the stretched exponential production decline (SEPD) model dominated by transient flow and transitional flow and the exponential model dominated by boundary-dominated flow (BDF) were selected and combined based on the research on the adaptability of empirical production decline model proposed in previous studies. Given equal production and equal decline rate at nodes, a new lifecycle segmented production prediction model with BDF time as node was constructed. Furthermore, the methods for predicting BDF time based on the generalized regression neural network algorithm and for determining the parameters of piecewise function by least square fitting were established. The results show that, whether the BDF is attained, the new model realizes a better fitting than the SEPD or exponential model, and its prediction results are closer to the exponential evaluation results in the late stage of production with an error of less than 5%. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Characteristics and Connectivity of Upper Wuerhe Formation in Wellblock Ke 75, Karamay Oilfield LIU Nianzhou, LI Bo, ZHANG Yi, WU Min, WANG Quan, SU Hang Xinjiang Petroleum Geology    2022, 43 (4): 417-424.   DOI: 10.7657/XJPG20220406 Abstract （290）   HTML （13）    PDF（pc） （2524KB）（179）       Knowledge map    Save The upper Wuerhe formation in Wellblock Ke 75 in Karamay oilfield, Junggar basin has strong heterogeneity and varying connectivity between adjacent wells, and the understanding of sand body distribution in the formation is greatly different from the previous one. It is necessary to study the sedimentary facies and sand body connectivity to clarify reservoir distribution. Taking the upper Wuerhe formation in the Wellblock Ke 75 as an example, the characteristics and styles of the 4th-order architectural elements for each subfacies belt of alluvial fan controlled by both debris flow and braided channel were discussed according to the principles of sedimentology, and the sedimentary characteristics and sand body connectivity of each architectural style were analyzed. The research shows that when the electrical properties and sedimentary cycle characteristics of neighboring wells in the sheet flow zone at fan root are consistent, the sand body connectivity is good, and when the cross flow sand bodies or cross flow fine-grained sediments are developed, the sand body connectivity is poor, leading to difficulties in forming effective reservoirs. The research confirmed a Class I favorable gas reservoir area in the Wellblock Ke 75 in Karamay oilfield. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Genesis Mechanism of Wellhead Pressure Fluctuation for Well Hutan-1 WANG Quan, WANG Bin, YAN Liheng, WANG Yang, LUO Jianxin, DU Guo Xinjiang Petroleum Geology    2022, 43 (5): 587-591.   DOI: 10.7657/XJPG20220511 Abstract （259）   HTML （4）    PDF（pc） （634KB）（178）       Knowledge map    Save Well Hutan-1 is the first ultra-deep and abnormally high-pressure gas well that revealed a significant discovery in gas exploration in the middle section of Junggar basin’s southern margin. However, during the production test, the wellhead pressure of this well fluctuated greatly, making it impossible to effectively determine reservoir parameters and reasonably evaluate productivity. Based on the principle of particle bridging and plugging, and by using the gas reservoir dynamic analysis method, the variation of cyclic plugging and unplugging of the particles in fractures was investigated, and a dual-medium flow model for Well Hutan-1 was established for analyzing the characteristics and genesis mechanism of wellhead pressure fluctuation in the well. The research shows that the cyclic plugging and unplugging of the particles in fractures is the main reason for the large pressure fluctuation. With the continuous migration of the particles and unplugging in fractures, the pressure fluctuation amplitude and the skin factor gradually decrease, and the gas productivity tends to be stable. During the cyclic plugging and unplugging of the particles in fractures, the greater the fracture aperture, the greater the pressure fluctuation amplitude. Given the same fracture aperture, the proximal fractures are plugged and unplugged, resulting in a great pressure fluctuation amplitude, while the opposite is true at the distal fractures. The research provides a basis for the study of reservoir characteristics, well deployment, and productivity evaluation in the middle section of the Junggar basin’s southern margin, and provides a reference for analyzing pressure fluctuation in the same type of ultra-deep and abnormally high-pressure gas wells. 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 （257）   HTML （26）    PDF（pc） （18631KB）（176）       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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Reservoir Production Performance Optimization Algorithm Based on Numerical Simulation LEI Zexuan, XIN Xiankang, YU Gaoming, WANG Li Xinjiang Petroleum Geology    2022, 43 (5): 612-616.   DOI: 10.7657/XJPG20220515 Abstract （272）   HTML （17）    PDF（pc） （509KB）（175）       Knowledge map    Save When the conventional optimization algorithms are applied to optimized development of large scale reservoirs, the problems such as slow convergence speed, low optimization efficiency and difficult integration with field applications occur. To solve these problems, a well production performance control model was established. A global optimal solution of the model was found by using the simulated annealing genetic (SAG) algorithm and Latin hypercube sampling (LHS) algorithm. Furthermore, the convergence speed of the local solution of the model was accelerated by using the synchronous perturbation stochastic approximation (SPSA) algorithm, and a well production performance control software was developed and applied to the H block in Daqing oilfield. Compared with conventional well production systems, the best scheme of the optimized well production performance control model increases the cumulative oil production of H block by 5.68×104 m3 within 5 years, which ensures the well production performance control and optimization, and provides a new method for efficient development of large-scale oilfields. Table and Figures | Reference | Related Articles | Metrics

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Tri-Porosity and Dual-Permeability Well Test Analysis Model for Inclined Wells in Fractured-Vuggy Reservoirs JIA Ran, NIE Renshi, LIU Yong, WANG Peijun, NIU Ge, LU Cong Xinjiang Petroleum Geology    2022, 43 (5): 606-611.   DOI: 10.7657/XJPG20220514 Abstract （208）   HTML （5）    PDF（pc） （566KB）（174）       Knowledge map    Save In fractured-vuggy reservoirs, there is cross flow between the matrix, fractures and cavities, and the matrix and fractures supply fluid to the wellbore at the same time. Assuming that the reservoir is horizontal, equal in thickness, impermeable at top and bottom, and infinite laterally, a theoretical model of well test analysis for inclined wells was established. The analytical solution of the model in the Laplace space was obtained by means of Laplace transform and variable separation, and the solution of the bottom hole pressure was obtained through Stehfest inversion. Type curves controlled by model parameters for well test analysis were used for flow stage identification and curve sensitivity analysis were conducted. The tri-porosity and dual-permeability well test type curves of inclined wells reflect 8 main flow stages, including early radial flow stage, linear flow stage, cavity-to-fracture cross flow stage, cavity-to-matrix cross flow stage and the matrix-to-fracture stage, etc. The values of parameters such as inclination and fracture-reservoir permeability ratio obviously influence the characteristics of the well test type curves. 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 （159）   HTML （5）    PDF（pc） （1137KB）（174）       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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Controlling Factors and Physical Simulation Experiments on Formation and Evolution of Conjugate Strike-Slip Faults DAI Lan, WU Guanghui, CHEN Xin, ZHU Yongfeng, CHEN Siqi, LUO Xin, HU Ming Xinjiang Petroleum Geology    2023, 44 (1): 43-50.   DOI: 10.7657/XJPG20230106 Abstract （296）   HTML （12）    PDF（pc） （3055KB）（173）       Knowledge map    Save The origins of X-shaped conjugate strike-slip faults are complex. Considering the geological conditions of large X-shaped conjugate strike-slip faults in the Tabei area of the Tarim basin，7 sets of sandbox experiments with different parameters were designed to explore the controlling factors and evolution process of the X-shaped conjugate strike-slip faults. The experimental results show that conjugate strike-slip faults tends to be formed in the model with large thickness，large width and high clay content under the rapid compression on both sides. In the experiment，the fault tail propagation and the dominant development of a group of faults are obvious，while the fault linkage growth and the localization of overlapping area are weak. The formation of conjugate strike-slip faults requires three conditions: certain caprock thickness，and lack of pre-existing faults; good physical homogeneity of rocks，certain viscoplasticity，and high movement rate; and two-way compression. In the natural world and experiments，symmetrical pure shear conjugate strike-slip faults can hardly be formed，but most faults are single-shear strike-slip faults that develop as a group in dominant direction. In the Tarim basin，the conjugate strike-slip faults are also asymmetric，and they are dominantly single-shear faults in NW-SE direction; the inherited development with small displacements is the main controlling factor for the formation of large-scale conjugate strike-slip faults. 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 （118）   HTML （3）    PDF（pc） （845KB）（172）       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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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 （133）   HTML （8）    PDF（pc） （1767KB）（169）       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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Fracture-Cave System in Collapsed Underground Paleo-River With Subterranean Flow in Karst Canyon Area，Tahe Oilfield ZHANG Changjian, LYU Yanping, MA Hailong, GENG Tian, ZHANG Xiao Xinjiang Petroleum Geology    2023, 44 (1): 9-17.   DOI: 10.7657/XJPG20230102 Abstract （259）   HTML （265）    PDF（pc） （6529KB）（168）       Knowledge map    Save In order to study the development characteristics of paleokarst in the Middle-Lower Ordovician in the Tahe oilfield，by restoring the paleogeomorphology and the paleo-water system in the early Hercynian movement，the cave types in the karst canyon area were divided，and the genesis and evolution model of the collapsed fractures and caves with subterranean flow in the karst canyon area of the Tahe oilfield were established. The research results show that paleokarstification during the early Hercynian movement is found in the study area，the karst paleogeomorphology is generally high in the northeast and low in the southwest，the micro-geomorphology is mainly composed of low-amplitude karst mounds，karst peaks and depressions，and the paleo-water system is mainly composed of open channel flow，subterranean flow，underground river，and dry valley. The main water system shows a segmented structure consisting of deep incised meandering canyon in the south，canyon in the middle，and underground river-skylight in the north，and the tributary water system is a dendritic underground river network. The caves in the collapsed underground river with subterranean flow can be identified，mainly in four types，namely underground river，subterranean flow，undercurrent along river，and cave-through. The development and evolution of underground paleo-river system in the study area can be divided into free meandering flow，subterranean flow-deep incised meandering flow，and collapsed skylight subterranean flow. Table and Figures | Reference | Related Articles | Metrics

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Oil-Bearing Properties and Hydrocarbon Occurrence States of Fengcheng Formation Shale in Well Maye-1，Mahu Sag QIAN Menhui, WANG Xulong, LI Maowen, LI Zhiming, LENG Junying, SUN Zhongliang Xinjiang Petroleum Geology    2022, 43 (6): 693-703.   DOI: 10.7657/XJPG20220607 Abstract （238）   HTML （2）    PDF（pc） （4169KB）（166）       Knowledge map    Save The oil-bearing properties and hydrocarbon occurrence states of shale are crucial to evaluating and selecting shale oil sweet spots. Through the analysis such as rock pyrolysis, multi-temperature-gradient pyrolysis and X-ray diffraction, the oil-bearing properties and hydrocarbon occurrence states of the shale in the Lower Permian Fengcheng formation in Well Maye-1, Mahu Sag, were investigated, and then the optimal sweet spot intervals for shale oil in the Fengcheng formation were defined. The results show that the Fengcheng formation shale in Mahu sag is mainly composed of three lithofacies associations. The quality of source rocks is the best in the Feng 2 member, partially moderate in the Feng 1 member, and poor in the Feng 3 member. The macerals of organic matter in the rocks are mainly vitrinite and inertinite, indicative of a mature stage, showing a good material basis for shale oil accumulation. Vertically, the Fengcheng formation shale can be divided into 6 sweet spot intervals with good oil-bearing properties. The lamellar felsic shale intervals at the top and in the middle of the Feng 2 member have the best oil-bearing property, and contain hydrocarbons mainly in free state, where free oil accounts for more than 80% of the total oil content and mainly occurs in intergranular pores and bedding fractures continuously, suggesting a good oil-bearing foundation and a good prospect of movable resource. The research results provide a theoretical basis and technical support for subsequent exploration and development of the shale oil in the Fengcheng formation Table and Figures | Reference | Related Articles | Metrics

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Seismic Prediction Method of Geological and Engineering Shale Oil Sweet Spots and Its Application in Fengcheng Formation of Mahu Sag YU Jianglong, CHEN Gang, WU Junjun, LI Wei, YANG Sen, TANG Tingming Xinjiang Petroleum Geology    2022, 43 (6): 757-766.   DOI: 10.7657/XJPG20220614 Abstract （252）   HTML （5）    PDF（pc） （3687KB）（165）       Knowledge map    Save In order to further accelerate the exploration and development for shale oil in the Lower Permian Fengcheng formation in the Mahu sag，Junggar basin，sweet spots of shale oil should be identified. Considering that lithology is the main factor controlling geological sweet spots，and brittleness index and horizontal principal stress difference are the main factors controlling engineering sweet spots，seismic methods of predicting geological and engineering sweet spots were established on the basis of prestack simultaneous inversion. In terms of geological sweet spots，by using core，experiment，drilling and logging data，the dominant lithology for shale oil sweet spots was identified to be dolomitic siltstone，the elastic parameters sensitive to the dominant lithology were selected，and the distribution of dolomitic siltstone was predicted by using prestack isimultaneous nversion and lithofacies probability analysis techniques. In terms of engineering sweet spots，using the Young’s modulus and Poisson’s ratio obtained from prestack simultaneous inversion，cubes of brittleness index and in-situ stress for the study area were obtained through the Rickman brittleness index method and a combined spring model. The predicted results are consistent with the actual drilling results，which confirms the accuracy of the prediction of geological and engineering sweet spots. The proposed methods can provide references for shale oil exploration and development in other areas. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Quantitative Prediction of Structural Fractures in Lei4 Member Reservoir in Pengzhou Area, Western Sichuan Basin XIE Qiang, LI Gao, PENG Hongli, HE Long, GONG Hanbo Xinjiang Petroleum Geology    2022, 43 (5): 519-525.   DOI: 10.7657/XJPG20220503 Abstract （245）   HTML （6）    PDF（pc） （3677KB）（165）       Knowledge map    Save Structural fractures are found in the Lei4 member reservoir in Pengzhou area, western Sichuan basin. However, their distribution characteristics are unclear, which seriously affects the efficient development of natural gas in the Lei4 member. Through outcrop, core and rock thin section observations, the development characteristics of the structural fractures in the reservoir were described. The tectonic stress field during the Himalayan movement was simulated with the finite element method. Based on the rock failure criterion and elastic strain energy, the development of the structural fractures in the Lei4 member reservoir was predicted. The results show that the structural fractures in the Lei4 member reservoir are dominantly shear fractures with the extension ranging from 10 m to 70 m and the density of 5-10 fractures/m, mainly trending in NE-SW, NW-SE, nearly S-N and nearly E-W. Most of the fractures generated during the Himalayan movement are not filled. The minimum horizontal principal stress, maximum horizontal principal stress and differential stress of the Lei4 member during the Himalayan movement were 72.30-106.50 MPa, 126.00-183.47 MPa and 48.51-92.46 MPa, respectively. The predicted structural fracture density in the fault zone of the study area is far more than 15 fractures per meter, mainly 5-11 fractures/m in the Lei4 member. The fracture density in the high part of the anticline is lower than that in the two flanks, indicating that the distribution of fractures in the study area is controlled by both fault and structural position. The relative error between the predicted and measured structural fracture densities is 4.2%-10.7%, suggesting reliable predicted results, which provide a geological basis for the exploration and development of carbonate gas reservoirs in the Lei4 member in Pengzhou area. Table and Figures | Reference | Related Articles | Metrics

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Influencing Factors and Prediction Methods for Production of Tight Oil Reservoir in Pingbei Oilfield HU Xinling, WANG Jian, PAN Lin Xinjiang Petroleum Geology    2022, 43 (3): 346-353.   DOI: 10.7657/XJPG20220313 Abstract （291）   HTML （6）    PDF（pc） （599KB）（163）       Knowledge map    Save Compared with conventional oil reservoirs, tight oil reservoirs have poor physical properties and low permeability, and wells drilled in these reservoirs need to be fractured for more production. Due to the geological features and special development techniques, there are many factors affecting the production of these reservoirs, and the simple analogy method commonly used on site for production prediction cannot meet the actual needs. In order to solve this problem, taking the tight oil reservoir in Pingbei oilfield of Ordos basin as the research object and based on the Darcy equation, the main influencing factors for production were quantitatively described through grey theoretical analysis. Moreover, a mathematical model was established by using the multiple regression method, and applied to predict the production of new wells in order to verify the reliability of the model. Production prediction by using the multidisciplinary method that combines the grey theory and multiple regression is more scientific and accurate than by using traditional methods, and it can provide a reference for the development of similar oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of a Combined Production Decline Prediction Model for Tight Sandstone Gas Well LI Xiaofeng, XU Wen, LIU Pengcheng, YUE Jun Xinjiang Petroleum Geology    2022, 43 (3): 324-328.   DOI: 10.7657/XJPG20220309 Abstract （269）   HTML （5）    PDF（pc） （602KB）（162）       Knowledge map    Save The Permian fluvial sandstone gas reservoirs in the Sulige gas field are tight and contain effective sand bodies that are mostly isolated or banded. After gas wells are put into production, reservoir fluid stays consistently in an unsteady flow state, and it is late to reach the boundary-dominated flow state. In this case, the traditional Arps production decline analysis method is not sufficient for field application. This paper analyzed the causes for the poor adaptability of the Arps production decline analysis method. On this basis, the variation law of the decline exponent of wells in tight gas reservoirs was identified by numerical simulation, and the relationship between the decline exponent and the flow period of fluid in gas wells was clarified. Finally, it was proposed to use the channel linear flow model to predict the production in the unsteady flow period and the Arps model to predict the production in the boundary-dominated flow period. For the gas wells in the unsteady flow period, the critical point time to attain boundary-dominated flow is determined by the theoretical formula; in the boundary-dominated flow period, the time of inflection point deviating from the linear flow is the critical point time. The field application shows that the proposed combined production decline model is accurate and effective in predicting the decline characteristics and indicators of gas wells. Table and Figures | Reference | Related Articles | Metrics

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Upper Limit of Water Saturation for Profitable Development of Tight Sandstone Gas Reservoirs in Sulige Gas Field XIAO Feng, YUE Jun, LI Zhichao, LIU Lili, ZHANG Ji, FAN Jiwu, ZHANG Tao Xinjiang Petroleum Geology    2022, 43 (3): 335-340.   DOI: 10.7657/XJPG20220311 Abstract （267）   HTML （2）    PDF（pc） （634KB）（161）       Knowledge map    Save In the Sulige gas field, tight sandstone gas reservoirs present a high water saturation. The water cut increases rapidly after the gas wells are put into production. With the increase of water cut, the production of gas wells declines greatly or even stops. Based on the analysis of production performance of water-producing gas wells, the relationships between the water saturation and the cumulative gas production and recovery rate of the gas wells were established. Combined with the single well investment and natural gas price, the minimum cumulative gas production required to recoup the investment in a gas well was determined, and accordingly the upper limit of reservoir water saturation was determined. Furthermore, taking the minimum cumulative gas production of gas wells as the standard, and considering the reservoir water saturation and reservoir thickness, the quantitative indicators for the logging interpretation of gas layers, gas-water layers and gas-bearing water layers were determined. The results show that the upper limit of water saturation of tight sandstone reservoirs in the central part of Sulige gas field is 48.2%, and when the economic minimum cumulative gas production in the life cycle of a gas well reaches 1 260×104 m3, the gas well is profitable. Table and Figures | Reference | Related Articles | Metrics

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Reasonable Productivity Optimization Methods and Application in Ultra-Deep Fault-Controlled Fractured-Vuggy Reservoirs GU Hao, KANG Zhijiang, SHANG Genhua, ZHANG Dongli, LI Hongkai, HUANG Xiaote Xinjiang Petroleum Geology    2023, 44 (1): 64-69.   DOI: 10.7657/XJPG20230109 Abstract （230）   HTML （4）    PDF（pc） （2699KB）（161）       Knowledge map    Save In this paper，the geological and development characteristics in the FQ oilfield in the Tarim basin were analyzed，and then the productivity test method，nozzle flow method and reservoir numerical simulation method were developed to optimize the reasonable productivity in ultra-deep fault-controlled fractured-vuggy reservoirs. The results show that the primary oil recovery of ultra-deep fault-controlled fractured-vuggy reservoirs can be divided into early stage，middle stage and late stage，which differ greatly in development characteristics. The ultra-deep fault-controlled fractured-vuggy reservoirs in the FQ oilfield exhibit four types of productivity test curves: convex，linear，upturned and stepped. For wells showing the convex curves，the productivity at the inflection of the curves is the reasonable productivity. For wells showing the linear and upturned curves，the maximum test productivity is the reasonable productivity，but the nozzle testing productivity needs to be continuously expanded until the inflection of the curves appears. For wells following the stepped curves，the maximum test productivity after reaching the step will be the reasonable productivity. When the well productivity is optimized by the nozzle flow method，the productivity at the inflection of the nozzle flow curves is the reasonable productivity. The reservoir numerical simulation method is suitable for optimizing the well productivity in the middle and late stages of primary oil recovery，that is，the reasonable productivity is determined by optimizing the key indicators such as water breakthrough time，cumulative oil production，and recovery rate. 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 （169）   HTML （17）    PDF（pc） （720KB）（160）       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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Method for Calculating Single-Well Producing Geological Reserves and Single-Well Technically Recoverable Reserves in Tight Sandstone Gas Reservoirs: A Case of Carboniferous-Permian Gas Reservoirs in Yanchang Gas Field, Ordos Basin CHEN Zhanjun, REN Zhanli Xinjiang Petroleum Geology    2022, 43 (3): 360-367.   DOI: 10.7657/XJPG20220315 Abstract （304）   HTML （12）    PDF（pc） （711KB）（159）       Knowledge map    Save The Carboniferous-Permian sandstone gas reservoirs in the Ordos basin are tight, with obvious different gas saturations from part to part of the reservoir unit, complex gas-bearing pattern, non-uniform reservoir pressure systems, and highly heterogeneous distribution of reserves as a whole. This paper compared the geological and development characteristics between Carboniferous-Permian tight sandstone gas reservoirs and the conventional sandstone gas reservoirs in Yanchang gas field in Ordos basin. It is found that there is a threshold pressure gradient during the development of the Carboniferous-Permian tight sandstone gas reservoirs, and the single-well produced geological reserves and the single-well reserves producing radius increase with the decrease of the bottom hole pressure. When the abandonment pressure is reached, the single-well produced geological reserves and the single-well reserves producing radius reach the maximum values. Accordingly, by analyzing the distribution of reserves during the development of tight sandstone gas reservoirs, the material balance equation under the condition of threshold pressure gradient was established, and the relationship between cumulative production and bottom hole pressure was obtained. Furthermore, two methods for calculating the threshold pressure gradient were analyzed. On this basis, the method for calculating the single-well producing geological reserves and the single-well technically recoverable reserves in tight sandstone gas reservoirs was proposed, which provides a theoretical basis for the optimization of well pattern to develop tight sandstone gas reservoirs. The theoretical calculation method has been improved to form a simplified method for calculating single-well producing geological reserves, which is referential for well pattern deployment in undeveloped blocks. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Genesis of Condensate Reservoirs of Lianggaoshan Formation in Fuling Area, Southeastern Sichuan Basin LI Mingyang, LI Chengyin, QU Dapeng Xinjiang Petroleum Geology    2022, 43 (4): 387-395.   DOI: 10.7657/XJPG20220402 Abstract （302）   HTML （14）    PDF（pc） （1211KB）（159）       Knowledge map    Save In the condensate gas reservoirs of the Lower Jurassic Lianggaoshan formation in the Fuling area, southeastern Sichuan basin, the fluid properties are complex and the gas-oil ratios from multi-well testing differ greatly. In this paper, the basic characteristics of oil and gas were clarified by using the data such as crude oil chromatography-mass spectrometry, gas composition, carbon isotopes and fluid inclusions. The gas reservoir properties and phase states were determined with the empirical calculation method for gas compositions and through the experiments simulating PVT fluid phase state. On this basis, the genesis and forming process of condensate gas reservoirs were discussed. The results show that the gas reservoirs in the Lianggaoshan formation are mainly condensate gas reservoirs without oil rings, where hydrocarbons are mainly primary condensate oil and gas generated from Type Ⅱ2 kerogens in the mature stage, and cracking gas is found locally. The thermal evolution degree of source rocks and the differences in the present temperature and pressure conditions of formation are the main contributors to different reservoir properties. The superimposed areas of the relatively deep-burial areas during the hydrocarbon accumulation period on the areas with relatively high pressure at present are favorable targets for future exploration. 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 （154）   HTML （14）    PDF（pc） （5762KB）（159）       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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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 （134）   HTML （4）    PDF（pc） （1234KB）（159）       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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Candidate Well Selection Criteria for Potential Tapping of Existing Wells in Gas Reservoirs of Penglaizhen Formation in Xinchang Gas Field, Western Sichuan Basin LU Yu, LI Zhongping, LI Huaji, LUO Changchuan, LUO Bin Xinjiang Petroleum Geology    2022, 43 (5): 592-599.   DOI: 10.7657/XJPG20220512 Abstract （209）   HTML （7）    PDF（pc） （3077KB）（158）       Knowledge map    Save The main gas reservoirs in the Xinchang gas field in western Sichuan basin have entered the middle to late stage of development, and potential tapping of the existing wells is an important means to maintain the effective development of the gas field. As high-quality reservoirs are further recovered, the original criteria of candidate well selection for tapping potential are no longer applicable to the current development situation; instead, it is urgent to establish new criteria for well/layer selection aiming at recovering the hard-to-produce reserves. The potential tapping effect of typical wells in the Penglaizhen formation of Xinchang gas field was evaluated, and the reservoir quality and reserves recovery of the target interval were analyzed. Combining with the single-well production performance, the candidate well selection criteria suitable for the current development characteristics of the study area were established. The results show that the potential tapping effect is affected by multiple factors such as well logging, seismic response and adjacent well producing, which should be comprehensively considered to reduce the failure risk in potential tapping. When candidate wells are selected in the same favorable zone or the same fracture strike, the lower limit of well spacing to a neighbouring well is 350 m, and the upper limit of cumulative gas production from a single layer of a neighbouring well with the well spacing of 350 m is 0.20×108 m3. Commingled production from multiple layers with secondary favorable microfacies is more applicable in the middle to late development stages, which is beneficial for the successful potential tapping. Table and Figures | Reference | Related Articles | Metrics

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Geochemical Characteristics and Paleoenvironment of Toutunhe Formation-Qingshuihe Formation in Qigu Fault-Fold Belt WANG Yaru, ZHANG Changmin, JI Dongsheng, ZHU Rui, FU Wenjun, WANG Zeyu, LIU Jiale Xinjiang Petroleum Geology    2022, 43 (5): 563-571.   DOI: 10.7657/XJPG20220508 Abstract （266）   HTML （5）    PDF（pc） （994KB）（157）       Knowledge map    Save In order to determine the geochemical characteristics and paleoenvironment of the Toutunhe formation-Qingshuihe formation in the Qigu fault-fold belt of Junggar basin, the element analysis was carried out using the X-ray fluorescence spectrometer. Such elements as vanadium (V), chromium (Cr), nickel (Ni), cobalt (Co), strontium (Sr), zirconium (Zr) and gallium (Ga), which are sensitive to the depositional environment, were selected to systematically analyze the characteristics of paleo-oxidation-reduction conditions, paleosalinity, paleo-water depth, and paleoclimate in the study area. The results show that the Toutunhe formation-Qingshuihe formation in the study area was deposited in an oxidation environment, and occasionally in short-term weak oxidation-weak reduction environment. Sensitive elements (e.g. Ga and Sr) and Sr/Ba value indicate that the Toutunhe formation-Kalazha formation was dominantly deposited in a freshwater environment, and possibly a short-term brackish water environment locally, and the Qingshuihe formation exhibits relatively frequent paleosalinity fluctuation and was deposited in an alternating environment of saltwater and freshwater. According to the Co estimation, the water depth of the Toutunhe formation-Qingshuihe formation rangef from 2.05 to 74.20 m, and fluctuated greatly during the depositional period. The climate changed from warm and humid to arid and hot during the deposition of the Toutunhe formation-Kalazha formation, and shifted to warm and humid during the deposition of the Qingshuihe formation. Table and Figures | Reference | Related Articles | Metrics

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Production Mechanism of Mud and Sand in Ordovician Carbonate Reservoirs in Halahatang Oilfield, Tarim Basin BAI Xiaofei, ZHOU Bo, DONG Changyin, WANG Fangzhi, LIU Xiao, GAN Lingyun, REN Jinming Xinjiang Petroleum Geology    2022, 43 (4): 456-462.   DOI: 10.7657/XJPG20220411 Abstract （204）   HTML （3）    PDF（pc） （1732KB）（156）       Knowledge map    Save In order to clarify the mechanism of wellbore instability in the Ordovician reservoirs of Halahatang oilfield, the rock, sand particle size and mineral composition of washed-out sand samples were mainly analyzed. It is found that wellbore instability in the Ordovician carbonate reservoirs in the study area occurs in two modes: (1) collapse of wellbore in the upper unplugged non-producing horizon (Tumuxiuke formation), that is, macroscopic instability, which results in collapsed rock blocks; and (2) production of sand carried by the fluids from key producing horizons, that is, microscopic instability, which causes the wellbore blockage by sand and mud generated from the cracking of fracture fillings and the exfoliated fine-grained components from micro-convex. The main controlling factors of wellbore instability were analyzed with the grey relational method, indicating that reservoir burial depth, wellbore diameter, water cut and wellbore azimuth are the main factors affecting wellbore instability. The wellbore diameter, wellbore azimuth and production system can be optimized to prevent and control the production of mud and sand. Table and Figures | Reference | Related Articles | Metrics

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Lithofacies Paleogeography and Petroleum Exploration of Fengcheng Formation in Western Central Depression of Junggar Basin HE Haiqing, TANG Yong, ZOU Zhiwen, GUO Huajun, XU Yang, LI Yazhe Xinjiang Petroleum Geology    2022, 43 (6): 640-653.   DOI: 10.7657/XJPG20220602 Abstract （298）   HTML （16）    PDF（pc） （18669KB）（154）       Knowledge map    Save In order to evaluate the petroleum exploration prospects of the Fengcheng formation in the western Central depression of the Junggar basin, the lithology assemblage and sedimentary facies of the Fengcheng formation were studied by means of analyzing the trace element, core, rock thin section, paleomorphology, logging facies and seismic facies of the formation. The results show that the Fengcheng formation in the study area is fan delta-alkaline lake deposition which formed in an arid-semi-arid climate, foreland tectonic setting and geological environment with periodic changes in water salinity and water depth. From the edge to the center of the Central depression, basin-marginal fan-delta clastic rocks, outer-slope front dolomites, slope-highland volcanic rocks, low-uplift dolomitic calcareous beach-bar peperites, and the central lake-basin alkali rocks are found in sequence. According to the sedimentary characteristics, an evolution model for the fan delta-alkali lake deposition was established for the Fengcheng formation. Based on the sedimentary facies, lithofacies and petroleum exploration status, the Fengcheng formation in the study area can be divided into 5 areas such as conventional hydrocarbon area in basin-margin ultra-denudation belt, tight hydrocarbon area in outer-slope front, shale oil/gas area in lake basin, conventional hydrocarbon area in low-uplift dolomitic calcareous beach-bar and conventional hydrocarbon area in highland volcanic rocks. The favorable exploration area with the depth less than 7 000 m reaches 1.2×104 km2, with hydrocarbon reserves of more than one billion tons, which demonstrates huge exploration potential of the total petroleum system of the Fengcheng formation in the study area Table and Figures | Reference | Related Articles | Metrics

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Spatial Distribution of Architectures of Braided River Reservoirs in He 8 Member, Sulige Gas Field LIU Jinku, HU Yang, WU Yi Xinjiang Petroleum Geology    2023, 44 (2): 144-150.   DOI: 10.7657/XJPG20230203 Abstract （243）   HTML （21）    PDF（pc） （4557KB）（154）       Knowledge map    Save In order to determine the spatial distribution of the architectures of the multi-stage superimposed braided-river tight sandstone reservoirs in the He 8 member, Sulige gas field, by using well logging and core data and referring to modern rivers, the architecture division scheme of the braided river reservoirs in the study area was determined, and the reservoir architecture units were dissected hierarchically. Through the joint simulation based on pixel and target methods, a 3D architecture model of the braided river reservoir including multi-level architecture units was established to finely depict the spatial distribution of different reservoir architectures. The reservoirs in the He 8 member formed due to the vertical or lateral cutting and stacking of multi-phase sand bodies of braided channel. The mid-channel bar of a single braided belt appears in form of lens. The interior of mid-channel bar is separated by discontinuous fall-siltseam, and the braided channels are distributed around the mid-channel bar. According to the 3D architecture model, the reservoir can be divided into different hierarchical architectures, among which the favorable reservoir interval is He 84 sublayer which is mainly distributed in two major braided belts extending north-south in the east and west of the study area, and high-quality sand bodies are distributed in a lenticular shape inside the braided belt. The research results were applied to horizontal well deployment and geosteering drilling, and the drilling results show a high coincidence rate with model predictions. Table and Figures | Reference | Related Articles | Metrics

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Formation Pressure Estimation Method Based on Dynamic Effective Stress Coefficient ZHOU Yunqiu, HE Xilei, LIN Kai, QIN Siping, ZHANG Chenqiang, LIU Zongjie Xinjiang Petroleum Geology    2023, 44 (2): 245-251.   DOI: 10.7657/XJPG20230216 Abstract （234）   HTML （20）    PDF（pc） （649KB）（152）       Knowledge map    Save Formation pressure which can reflect porosity，compaction，and fluid occurrence of underground rock formation is very important for discovering effective reservoirs. Regarding the status that the effective stress coefficient is set as 1 for simplification when calculating formation pressure，the dynamic effective stress coefficient considering pore structure parameters is calculated based on a unified rock skeleton model and the Gassmann equation，formation pressure and pressure coefficient are estimated by using the conventional Eaton method，and the accuracy of formation pressure estimation is improved. Taking carbonate and sandstone reservoirs as examples，the estimated formation pressures show anomalies in water layers，dry layers，and gas layers. Compared with the results obtained from the conventional Eaton method，the proposed method provides a more accurate estimate of formation pressure，thus facilitating a more reliable discovery of effective reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Development and Application of Velocity Modeling Method Based on Double Square Root Operator Alifjian REHMTULY, PAN Long, LI Xianmin, LIN Juan, MA Jingjing, DOU Qiangfeng Xinjiang Petroleum Geology    2023, 44 (1): 119-124.   DOI: 10.7657/XJPG20230117 Abstract （212）   HTML （9）    PDF（pc） （4411KB）（149）       Knowledge map    Save The southern margin of the Junggar Basin is a mountainous area with severe surface fluctuations. The conventional seismic processing method cannot meet the needs of the assumptions of the processing method due to the actual geological structure of the surface and deep layers，resulting in an unsatisfactory imaging effect and a large error between the interpreted depth and the measured drilling depth. In order to improve the quality of seismic data processing in the area，a seismic data processing method based on rugged datum was explored by using the velocity modeling with double square root operator. The method can reduce the distortion of wave field caused by the horizontal datum correction of the common midpoint (CMP) gather and provide a velocity field similar to the real observation surface for pre-stack migration，thus realizing the efficient integration of the time-domain datum and the depth-domain datum. The actual application of the new method show good seismic data processing results，with accurate migration imaging homing，satisfactory focusing，and significantly reduced error between the depth obtained from seismic interpretation and the depth measured by drilling. The new method provides a reference for seismic data processing in similar mountainous areas. 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 （156）   HTML （27）    PDF（pc） （1024KB）（148）       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 and Formation Mechanism of Traps in K1g1 Reservoir in Changshaling Structural Zone, Jiuquan Basin WEI Jun, YAN Baonian, DU Wenbo, ZHOU Xiaofeng, ZHOU Zaihua, LI Tiefeng, XIE Jingyu Xinjiang Petroleum Geology    2022, 43 (4): 379-386.   DOI: 10.7657/XJPG20220401 Abstract （312）   HTML （21）    PDF（pc） （7073KB）（147）       Knowledge map    Save With the meanings such as core observation, casting thin section identification and scanning electron microscope imaging, and based on the analysis of sandstone in light of petrological characteristics, diagenesis, pore types and dissolution fluid sources, the trap formation mechanism was investigated. The results show that the traps in the sandstone reservoir of the first member of the Cretaceous Xiagou formation (K1g1) in the Changshaling structural zone, Jiuquan basin, are diagenetic traps, the reservoir space is dominated by secondary pores, and the barrier is tight sandstone cemented by calcite in the early diagenetic stage. Atmospheric fresh water carrying smectite particles infiltrates through faults and dissolves the calcite cements and feldspar particles in tight sandstone, creating secondary intergranular pores and intragranular pores and clay-rich reservoir forms. The tight sandstone which is far from faults and has non-contact with atmospheric fresh water becomes the barrier. The traps are elongated and distributed along the fault trend, with the characteristics of “large sand bodies and small traps”. For the K1g1 sandstone reservoir, the diagenetic traps controlled by faults should be preferentially explored and wells should be deployed in the areas close to faults. 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 （207）   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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Sedimentary Characteristics and Controlling Factors of Hyperpycnal Flow in Triassic Depressed Lake Basin，Northern Tarim Basin ZHONG Mihong, TANG Wu Xinjiang Petroleum Geology    2023, 44 (1): 1-8.   DOI: 10.7657/XJPG20230101 Abstract （280）   HTML （282）    PDF（pc） （2830KB）（145）       Knowledge map    Save Previous studies on hyperpycnal flow mainly focused on modern marine environment and paid little attention to sedimentary characteristics and controlling factors of hyperpycnal flow in ancient continental depressed lake basins. In this paper，taking Tabei area as an example，the hyperpycnal flow deposits of the Triassic TⅡ oil member are analyzed by using core，drilling，logging and 3D seismic data. The results show that during the deposition of lacustrine transgressive system tract (TST) - highstand systems tract (HST)，the TⅡ oil member in the study area developed two typical hyperpycnal flow sedimentary sequences，and each sequence is a compound of a basal coarsening-upward unit and a top fining-upward unit，with climbing ripples and ripple cross lamination. In one sequence，an erosive surface is developed between the two units，while in the other sequence，the two sedimentary units present a trend of gradual change，reflecting different flooding energy. The hyperpycnal flow in the study area mainly comes from two directions such as southwest and northeast，among which the hyperpycnal flow from southwest is the dominant with wide distribution，long extending distance and vertical superimposition of hyperpycnal flow deposits of multiple periods. The hyperpycnal flow in the study area has the characteristics of flood gravity flow，and its formation is closely related to flooding and controlled by multiple factors such as climate，tectonic activities，lake level，and provenance. 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 （148）   HTML （4）    PDF（pc） （792KB）（145）       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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Changes and Significance of Biomarkers in Thermal Evolution of Fengcheng Formation Source Rocks in Northwestern Margin of Junggar Basin JIANG Wenlong, Ablimit·YIMING , BIAN Baoli, WANG Tao, REN Haijiao, HAN Yang Xinjiang Petroleum Geology    2022, 43 (6): 684-692.   DOI: 10.7657/XJPG20220606 Abstract （234）   HTML （6）    PDF（pc） （1167KB）（143）       Knowledge map    Save A thermal simulation experiment in a closed system was conducted on the cores of argillaceous source rocks in the Permian Fengcheng formation of the Mahu sag in the northwestern margin of the Junggar basin. Taking the thermal simulation temperature as a scale，the evolution characteristics and applicable ranges of the biomarkers in different stages of maturity were analyzed in light of the parameters for identifying typical biomarkers in the Fengcheng formation source rocks，which includes Pr/Ph，Pr/nC17，absolute content of β-carotane，distribution patterns of C20，C21 and C23 tricyclic terpenes，and ratio of pregnane to regular sterane. On this basis，it is expected to more accurately identify the high-matured oil and gas from the Fengcheng formation in the northwestern margin of the Junggar basin by comparing with the crude oil in the West Pen-1 sag. The results show that，in addition to the distribution patterns of C20，C21 and C23 tricyclic terpenes，the typical oil-source correlation parameters of the Fengcheng formation such as Pr/Ph，Pr/nC17，and absolute content of β-carotane are greatly affected by maturity and cannot be used to identify the source of high-matured condensate oil and gas. By considering the maturity in the process of oil-source correlation and combined with the newly established carbon isotope chart of normal alkane monomers for the Fengcheng formation source rocks，the controversial high-mature condensate oil from Well Pen-5 in the West Pen-1 sag was analyzed. It is speculated that the condensate oil from Well Pen-5 mainly came from the Fengcheng formation source rocks. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Hydrocarbon Generation Potential of Chang 9 Source Rocks on Yishaan Slope, Ordos Basin LUO Lirong, LI Jianfeng, YANG Weiwei, MA Jun, LI Huan, WU Kai Xinjiang Petroleum Geology    2022, 43 (3): 278-284.   DOI: 10.7657/XJPG20220304 Abstract （320）   HTML （7）    PDF（pc） （746KB）（143）       Knowledge map    Save A number of favorable oil-bearing areas have been discovered in the lower assemblage adjacent to the Chang 9 source rocks on Yishaan slope, Ordos basin. In order to promote the petroleum exploration of the lower assemblage in this area, it is urgent to deepen the research on the characteristics and hydrocarbon generation potential of the Chang 9 source rocks. The distribution of the Chang 9 source rocks were analyzed using well logging, mud logging and core data. The geochemical characteristics and hydrocarbon generation potential of the Chang 9 source rocks were studied by various methods such as rock pyrolysis analysis, total organic carbon analysis, kerogen maceral analysis, and biomarker analysis by saturated hydrocarbon gas chromatography-mass spectrometry. The results show that the Chang 91 source rocks are distributed in Wuqi, Jingbian, Zhidan, Ansai and other areas, with the maximum thickness of over 20 m, and the Chang 92 source rocks are mainly developed in Ganquan-Luochuan area, with the maximum thickness of over 12 m. The Chang 9 source rocks hold a high abundance of organic matters that were originated from lower aquatic organisms and terrestrial higher plants. With Type Ⅰ and Ⅱ1 organic matters in dominance, which are in the mature stage, the Chang 9 source rocks exhibit high hydrocarbon conversion rate and especially strong hydrocarbon generation capability in Zhidan-Ansai area. The Chang 9 source rocks are mostly good and locally high-quality rocks with strong hydrocarbon generation and expulsion capacities, which provides a material basis for hydrocarbon accumulation in the lower assemblage of Yanchang formation on Yishaan slope. Table and Figures | Reference | Related Articles | Metrics

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Reservoir Characteristics and Controlling Factors of Shan 1 Member in Qingyang Gas Field, Ordos Basin DUAN Zhiqiang, XIA Hui, WANG Long, GAO Wei, FAN Qianqian, SHI Wei Xinjiang Petroleum Geology    2022, 43 (3): 285-293.   DOI: 10.7657/XJPG20220305 Abstract （329）   HTML （8）    PDF（pc） （6467KB）（140）       Knowledge map    Save In the Qingyang gas field, Ordos basin, which is a typical tight sandstone gas field, the major pay zone is the first member of the Permian Shanxi formation. Its sedimentary sand bodies change rapidly with small thickness, making the prediction of reservoir distribution difficult, which restricts the productivity construction of the gas field. In this paper, sedimentary sand body characterization and thin layer prediction were carried out using logging-seismic combination, the main factors controlling reservoir development were discussed, and favorable reservoir distribution areas were identified. The results show that the paleogeomorphology and paleo-flow direction jointly controlled the distribution of delta sand bodies, the underwater distributary channel sand bodies with developed dissolution facies are the most favorable reservoirs, and the local micro-amplitude nose uplift structure is the natural gas enrichment area. Based on the factors such as sand body distribution, reservoir physical properties, diagenesis and structural characteristics, a set of standards for classifying reservoirs in the study area was established, by which two Type I reservoir enrichment areas were defined in the southern and central parts of the study area. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Calcareous Sandy Conglomerate of Baikouquan Formation in Well XIA72 Fault Block, Mabei Oilfield WU Shunwei, XIA Xueling, ZHU Shijie Xinjiang Petroleum Geology    2022, 43 (4): 404-409.   DOI: 10.7657/XJPG20220404 Abstract （244）   HTML （4）    PDF（pc） （1627KB）（140）       Knowledge map    Save Calcareous sandy conglomerate was encountered in multiple wells in the oil layers of the Lower Triassic Baikouquan formation in Well XIA72 fault block, MA131 well block, Mabei oilfield, gas logging result shows that the total hydrocarbon content is low, and the physical and oil-bearing properties of reservoirs are poor, which affects the oil layer drilling rate and the later horizontal well deployment. According to the core, logging and seismic data, the genesis, identification and distribution of calcareous sandy conglomerate in the Baikouquan formation, Well XIA72 fault block were discussed. The results show that the calcareous cement in the calcareous sandy conglomerate in the study area was formed in the late diagenetic stage, and it has a destructive effect on the reservoir. The distribution of the calcareous sandy conglomerate is mainly controlled by sedimentary facies and early faults, with the logging responses characterized by high resistivity, high density and low interval transit time, which are reflected as “bright spots” on the seismic section. The distribution of the calcareous sandy conglomerate in the study area was predicted by means of the maximum likelihood system, root mean square amplitude and maximum amplitude, among which the last one can accurately reflect the distribution. The calcareous sandy conglomerate in the study area is found in massive distribution controlled by sedimentary microfacies and NW trending banded distribution controlled by faults. According to the prediction results, the deployment of 27 horizontal wells was optimized. Table and Figures | Reference | Related Articles | Metrics

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Total Petroleum System and Inner-Source Natural Gas Exploration in Permian Strata of Junggar Basin TANG Yong, LEI Dewen, CAO Jian, LIU Yin, HUANG Liliang, LI Hui Xinjiang Petroleum Geology    2022, 43 (6): 654-662.   DOI: 10.7657/XJPG20220603 Abstract （265）   HTML （8）    PDF（pc） （15608KB）（140）       Knowledge map    Save In order to further expand the petroleum exploration and enrich the basic theory and understanding on petroleum geology in Junggar basin，based on the exploration practices in recent years，the characteristics of present petroleum exploration and its trend are summarized，and the total petroleum system in Permian strata and the conditions for large-scale accumulation of unconventional natural gas in inner-source deep strata are described. The results show that the middle and lower reservoir assemblages have become the major exploration targets，deep strata have the conditions for oil and gas accumulation，the source rock controls the distribution of oil and gas，and a distribution pattern with orderly coexistence of conventional and unconventional reservoirs is established. The continuous hydrocarbon supply from high-quality Permian source rocks is the premise for the formation of the total petroleum system，and two sets of oil and gas accumulation systems are found inside source and outside source. Various inner-source reservoirs are developed in the Permian strata，which have great potential for natural gas exploration，especially unconventional natural gas. The understanding not only broadens the petroleum exploration area in Junggar basin，but provides theoretical and practical support for construction of a large oil and gas field. Moreover，it is of great significance for further improving the theory of total petroleum system. Deep inner-source unconventional oil and gas are becoming an important frontier for future exploration in hydrocarbon-rich sags. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Identification of Zeolite-Bearing Tight Sandy Conglomerate Reservoirs in Wuerhe Formation，Mahu Sag QIN Zhijun, CAO Yingchang, MAO Rui, ZHANG Hao, FENG Cheng Xinjiang Petroleum Geology    2023, 44 (2): 136-143.   DOI: 10.7657/XJPG20230202 Abstract （265）   HTML （22）    PDF（pc） （5390KB）（140）       Knowledge map    Save Zeolite is found in the tight sandy conglomerate reservoirs of the Permian Wuerhe formation in the Mahu sag, Junggar basin, leading to great difficulties in oil-bearing property evaluation and productivity estimation for the tight sandy conglomerate reservoirs due to their abnormal reservoir physical properties. The experiments by using casting thin sections and scanning electron microscope were carried out to analyze the geological characteristics of zeolite, including the occurrence, symbiotic relationship with other minerals, and diagenetic sequence of zeolite cement. Through the analysis of core and logging data, it is clear that the zeolite-bearing tight sandy conglomerate reservoirs show the logging responses featured with low density, high neutron porosity and high acoustic slowness. By intersecting the difference between neutron logging porosity and density logging porosity with the difference between neutron logging porosity and acoustic slowness porosity, the chart for identifying the sandy conglomerate reservoirs containing zeolites was established. Based on the normalized tri-porosity logging parameters, a model for quantitatively predicting zeolite content was built. By comparing the zeolite content from core analysis with the content predicted by the model, it is confirmed that the prediction accuracy of the model is high. Based on the identification results of the zeolite-bearing tight sandy conglomerate reservoirs in 132 wells, the development zones of tight sandy conglomerate reservoirs containing zeolites in the Wuerhe formation in the study area were determined. The dissolution of zeolites can create a lot of accommodations for hydrocarbon accumulation. The study results provide reliable guidance for predicting favorable areas of tight sandy conglomerate reservoirs in the study area. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Genesis of Calcareous Interlayers in Underwater Distributary Channel Sandbodies in Chang 8 Reservoir，Ganquan Oilfield CUI Yaoke, DU Guichao, WANG Fengqin, WANG Cong’e, CHEN Yiyang, WANG Ying, HUANG Xingyu Xinjiang Petroleum Geology    2023, 44 (2): 161-168.   DOI: 10.7657/XJPG20230205 Abstract （277）   HTML （23）    PDF（pc） （5199KB）（140）       Knowledge map    Save The study on calcareous interlayers is of great significance to well pattern deployment in the early stage of oilfield development and to the increase of reserves and production in the late stage. By means of core observation，well logging data analysis，casting thin section and SEM observation，the lithology，electrical properties，distribution，and genesis of calcareous interlayers in the eighth member of Yanchang formation (Chang 8 member) in the Ganquan oilfield and the influence of such calcareous interlayers on reservoir heterogeneity were systematically studied. The results show that the calcareous interlayers were developed under the control of underwater distributary channel microfacies，mainly at the top and bottom of sand bodies. The calcareous interlayers exhibit the geological characteristics of high stability and large thickness，and the logging response characteristics of low gamma，low acoustic slowness and high resistivity. The development of the calcareous interlayers was mainly controlled by calcite cementation of two periods. The calcite cementation of the first period was related to the supersaturated precipitation of calcite in the syndiagenetic stage，during which the dissolution of crustal biological residues，Ca2+ and $CO_{3}^{2-}$ carried by rivers，and the dissolution of CO2 from the atmosphere provided materials for calcite cementation. The calcite cementation of the second period was the porous cementation in the Phase B of the middle diagenetic stage，and the residual Ca2+ and $CO_{3}^{2-}$ in the original formation fluids，the dissolution of unstable components，and Ca2+ and $CO_{3}^{2-}$ precipitated from mineral transformation provided materials for calcareous cementation. The development of calcareous interlayers enhanced the intralayer heterogeneity of sandbodies，leading to poor vertical sandbody connectivity and complex oil-water relationships. During the water flooding of the reservoir，calcareous interlayers obliquely intersect with the adjacent non-permeable interlayers，forming effective barriers and remaining-oil enriching areas locally. Table and Figures | Reference | Related Articles | Metrics

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Differences and Genesis of Upper Wuerhe Formation Reservoirs in Mahu Sag and Shawan Sag KUANG Hao, ZHOU Runchi, WANG Junmin, LIU Hao, TAN Xianfeng, CAI Xinyong, XIAO Zhenxing Xinjiang Petroleum Geology    2023, 44 (1): 18-24.   DOI: 10.7657/XJPG20230103 Abstract （294）   HTML （263）    PDF（pc） （4617KB）（139）       Knowledge map    Save By means of thin section observation，scanning electron microscope (SEM) analysis，X-ray diffraction (XRD) analysis of clay minerals，and cathodoluminescence experiment，the diagenesis of the Upper Permian upper Wuerhe formation in the Mahu and Shawan sags in the Junggar basin were analyzed and compared，and the types of diagenetic products and pore evolution process were clarified. Compaction，carbonate mineral cementation and zeolite cementation are the main factors controlling the differences in reservoir physical properties in the study area. The compaction in the Mahu sag is relatively weak，while the dissolution in the Shawan sag is relatively strong. There are differences in diagenesis and pore evolution of sand bodies in the two sags. The reservoirs in the Mahu sag are dominated by feldspar particles and dissolved tuff debris pores，and the reservoirs in the Shawan sag are dominated by feldspar particles，dissolved tuff debris pores，and dissolved zeolite pores. There are a few primary pores developed in the reservoirs in both Mahu sag and Shawan sag. The differences between the reservoirs in the two sags are mainly caused by the different properties of diagenetic fluids and rock components. Specifically，the rock components represent the main cause for the differences in pore structure characteristics in the sandy conglomerate reservoirs in the Mahu sag and the Shawan sag. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary System of Permian Fengcheng Formation in Hashan Area in Northwestern Margin of Junggar Basin YU Hongzhou, WANG Yue, ZHOU Jian, XUE Yan Xinjiang Petroleum Geology    2022, 43 (4): 396-403.   DOI: 10.7657/XJPG20220403 Abstract （319）   HTML （13）    PDF（pc） （12519KB）（137）       Knowledge map    Save The Fengcheng formation in the Hashan area in the northwestern margin of Junggar basin experienced strong tectonic deformation and structural displacement. There are few studies on the sedimentary system of the Fengcheng formation, which restricts the oil and gas exploration in this area. The 3D seismic, drilling, logging and core data in the Hashan area were systematically analyzed, and the structural evolution of the Fengcheng formation in different parts of the Hashan area was investigated, so that the original stratigraphic position of the Fengcheng formation was restored, the sedimentary facies types were analyzed and compared, and finally the original sedimentary system of the Fengcheng formation in this area was restored. The results show that in the Hashan area the tectonic compression strength gradually weakens from west to east, and the shortened distances of the Lower Permian from the Early Permian to the present in the western, central and eastern parts due to the compression are 33.0-40.0 km, 25.0-30.0 km and 15.0-20.0 km, respectively. Three types of sedimentary facies such as fan delta, beach bar and lake are developed and volcanic rocks of a certain scale are found in the Fengcheng formation. During the deposition of Feng 1 member, large-scale fan deltas and shore-shallow lakes were developed in the northern part of the Hashan area, semi-deep to deep lakes and beach bars in a small range in the central-western part, and volcanic rocks in the central-eastern part. During the deposition of Feng 2 member, the sedimentary range of semi-deep to deep lakes expanded significantly, thick layers of dolomitic mudstone was developed, and the distribution range of fan-delta sandy conglomerate and volcanic rocks decreased. During the deposition of Feng 3 member, the provenance supply capacity was enhanced, large-scale contiguous fan-delta sandy conglomerate was developed in the northern and western parts and semi-deep to deep lakes and beach bars were found locally. 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 （147）   HTML （7）    PDF（pc） （586KB）（137）       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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Experimental Correction of Dual Lateral Reservoir Resistivity After High Salinity Drilling Fluid Invasion MU Liwei, WANG Gang, LUO Xingping, FAN Haitao, LIN Shijun, WANG Guohui Xinjiang Petroleum Geology    2022, 43 (4): 474-478.   DOI: 10.7657/XJPG20220414 Abstract （184）   HTML （6）    PDF（pc） （570KB）（136）       Knowledge map    Save In order to eliminate the influences of high salinity drilling fluid invasion on dual lateral resistivity, it is necessary to restore the real resistivity of formation. By analyzing the factors influencing rock electric experiment, the electrode system and measuring technology were improved to make the resistivity of the rock sample from impermeable layers consistent with the double lateral resistivity. Under the conditions of high temperature and high pressure, the rock electric parameters were measured with the semi-permeable baffle plate gas flooding method, and then the drilling fluid invasion was simulated by displacing the oil in rock samples with high salinity drilling fluid. Finally, the relationship between rock sample resistivity and logging resistivity was established and a correction method for logging resistivity based on experiment was formed. The application of the method in multiple wells in the hinterland of Junggar basin shows that the gas saturation calculated with the corrected resistivity is more reasonable. The method provides an effective means for logging response analysis and reservoir evaluation. Table and Figures | Reference | Related Articles | Metrics

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Factors Influencing Productivity of Horizontal Wells With CO2 Inter-Fracture Flooding XIAO Hanmin, LUO Yongcheng, ZHAO Xinli, ZHANG Haiqin, LIU Xuewei Xinjiang Petroleum Geology    2022, 43 (4): 479-483.   DOI: 10.7657/XJPG20220415 Abstract （220）   HTML （7）    PDF（pc） （1922KB）（136）       Knowledge map    Save When tight oil reservoirs are developed by depletion mode, oil production declines rapidly. In order to explore a more effective development technique, a CO2 inter-fracture flooding model for horizontal well was established using the CMG-GEM software to simulate how the factors such as CO2 injection volume, injection pressure, reservoir temperature, fracture spacing and fracture length affect horizontal well productivity. The results show that CO2 inter-fracture flooding in a horizontal well can greatly increase the CO2 swept area, fully exploit the remaining oil, and improve the development effect. When the injection pressure is 25 MPa, the CO2 injection volume is close to and not more than 10×104 m3. The peak production rate rises with the increase of injection pressure, fracture spacing and fracture half-length. The peak production rate at the reservoir temperature of 80°C is higher than that at other temperatures; however, the higher the reservoir temperature, the less time will be needed to reach the peak daily production rate. Table and Figures | Reference | Related Articles | Metrics

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EOR Mechanism of Compound Gas Injection After Multiple Cycles of Oxygen-Reduced Air Huff and Puff in Heavy Oil Reservoirs GUO Xiaozhe, ZHAO Jian, GAO Wanglai, PU Yanan, LI Chenggeer, GAO Neng Xinjiang Petroleum Geology    2022, 43 (4): 450-455.   DOI: 10.7657/XJPG20220410 Abstract （243）   HTML （5）    PDF（pc） （557KB）（134）       Knowledge map    Save For heavy oil reservoirs, the enhanced oil recovery (EOR) mechanism of injecting different gases or compound of gases after multiple cycles of oxygen-reduced air huff and puff following water flooding is unclear. In this paper, experiments were conducted with one-dimensional and three-dimensional physical models, and numerical simulations were performed on well pair model and inverted five-spot well pattern model. Based on the comparative analysis on production and components of oil recovered in different cycles of huff and puff and flow process research, the oil displacement and washing mechanisms during huff and puff with three gases, i.e. oxygen-reduced air, CO2 and natural gas, in heavy oil reservoirs were discussed. The results show that the EOR mechanism of oxygen-reduced air huff and puff is dominated by water plugging, and the water front may readily break through after multiple cycles of operation and then fail quickly. The huff and puff with CO2 slug followed by oxygen-reduced air plays a synergy of water plugging and remaining oil displacement. The huff and puff with oxygen-reduced air injection followed by natural gas dissolves the heavy components of the oil in near-wellbore area, achieving multiple effects of increasing energy, reducing viscosity and dredging pores. EOR mechanisms of huff and puff with three gases and their compound have been clarified through the experiments and numerical simulations on 10 cycles of huff and puff, and have been verified by field wells. The conclusions are of guiding significance for enhancing oil recovery by gas huff and puff in similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Production Profile of Horizontal Wells in Strongly Heterogeneous Tight Gas Reservoirs in Sulige Gas Field FAN Jiwu, XU Zhenping, LIU Lili, ZHANG Juan Xinjiang Petroleum Geology    2022, 43 (3): 341-345.   DOI: 10.7657/XJPG20220312 Abstract （275）   HTML （7）    PDF（pc） （1499KB）（134）       Knowledge map    Save In order to determine the productivity of each fracturing section of a horizontal well after staged fracturing in the Sulige gas field, the production profile of horizontal wells and its influencing factors such as reservoir heterogeneity, flow characteristic, multistage fracturing technique and production pressure difference were analyzed. It is found that physical properties of reservoirs and development degree of effective sand bodies are the main factors controlling gas well productivity, and they have greater effect than the flow dominant term at the heel and toe of the horizontal well in an ideal model. The increase in production pressure difference aggravates the difference in gas production rate among fracturing sections in strongly heterogeneous reservoirs. The uneven distribution of induced fractures leads to different gas productivities of perforation clusters in the same fracturing section. Therefore, for multi-stage fractured horizontal wells, technical countermeasures such as optimization of perforation sections, differential stimulation of horizontal sections, and uniform fracture propagation by temporary plugging were proposed so as to improve the development effect of tight gas reservoirs. 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 （196）   HTML （12）    PDF（pc） （671KB）（133）       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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Characterization of Hydraulic Fractures in Tight Conglomerate Reservoirs in Baikouquan Formation，Mabei Slope LI Xiangyang, JI Hancheng, BIAN Tengfei, CHEN Liang, CHEN Liang, GUO Xinshu, LI Mengkai Xinjiang Petroleum Geology    2023, 44 (2): 178-183.   DOI: 10.7657/XJPG20230207 Abstract （223）   HTML （20）    PDF（pc） （1833KB）（133）       Knowledge map    Save Hydraulic fracturing is a main technique for developing oil and gas in tight conglomerate reservoirs. Currently，hydraulic fractures are mainly studied by means of physical experiments and numerical simulation. The study results can provide a theoretical basis for optimization of development plans，but they are not verified with field data，bringing great uncertainties to the design of stimulation measures. In order to describe the shape of hydraulic fractures for confirming the effective stimulation in tight conglomerate reservoirs，a coring well was drilled on the north slope of Mahu sag for obtaining hydraulic fractures. Based on the observation and analysis of the tight conglomerate cores，the shape，occurrence，and density of hydraulic fractures were characterized by using the core，image logging and CT scanning data. It is found that the tight conglomerate is characterized by large grain size，poor sorting，grain support，and strong heterogeneity. A total of 335 hydraulic fractures were identified in the core with the length of 323 m. Principal fractures propagate in the direction perpendicular to the wellbore; branch fractures are few and nearly perpendicular to the main fractures; crushed zones and asymmetrical double-wing fractures are observed in some intervals. The fractures propagate in two modes: gravel bypassing and gravel penetrating，which are formed due to tension and shear action，respectively，and are thus classified as tensional fractures and shear fractures. The tensional fractures and shear fractures are consistent in occurrence，both with a high dip angle close to 90° and a nearly south-north trending. The density of shear fractures is generally greater than that of tensional fractures. 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 （132）   HTML （13）    PDF（pc） （1727KB）（133）       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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Plugging Mechanism and Plugging Removal Technology for Unconsolidated Sandstone Gas Reservoirs in Sebei Gas Field LIAO Li, OU Baoming, CHEN Jun, WU Cheng, JIANG Qi, NI Yong, ZHAO Yu Xinjiang Petroleum Geology    2023, 44 (1): 100-104.   DOI: 10.7657/XJPG20230114 Abstract （223）   HTML （6）    PDF（pc） （545KB）（132）       Knowledge map    Save The Sebei gas field，a major natural gas producing area in the Qaidam basin，is characterized by multiple layers，easy sand production，and gas reservoirs with edge water. With the progress of the gas field development，reservoir plugging due to the factors such as water blocking damage，clay mineral hydration swelling and migration，and increased volume of the fluid entering wellbore occurs frequently in gas wells，which seriously affects well productivity. In the Sebei gas field，the unconsolidated sandstone gas reservoirs have high shale content and are suffering intensified water production. Through simulation experiment，it is determined that the influencing factor of reservoir plugging is clay mineral content. In order to protect the reservoirs，by selecting proper and economical plugging removal fluids，a chemical plugging removal technology has been developed for unconsolidated sandstone gas reservoirs in the Sebei gas field. Field application shows that this plugging removal technology is featured with fast operation，high efficiency and long validity，showing a good performance and application prospect. Table and Figures | Reference | Related Articles | Metrics

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Experimental Evaluation on Microsphere-Natural Gas Flooding in Buried-Hill Reservoirs CHEN Shijie, SUN Lei, PAN Yi, WANG Yajuan, LIN Youjian, CHEN Fenjun Xinjiang Petroleum Geology    2022, 43 (4): 468-473.   DOI: 10.7657/XJPG20220413 Abstract （209）   HTML （3）    PDF（pc） （761KB）（131）       Knowledge map    Save During the development of fractured buried-hill reservoirs which are highly heterogeneous, fingering and channeling occur frequently; therefore, blocking high permeability channels such as fractures and large pores is an effective measure to improve oil recovery of these reservoirs. Through laboratory experiments on flowing in the cores from the B1 buried-hill reservoir, the plugging effect of microspheres on both fractures and large pores in the cores was evaluated, and the effectiveness of microsphere-natural gas flooding to improve the recovery of remaining oil was discussed. The results show that the oil displacement efficiency of water flooding or natural gas flooding is inapparent. When microsphere flooding is adopted, the microspheres significantly increase the resistance coefficient and injection pressure due to their expansion and plugging after entering the core. The microsphere size directly affects the plugging effect. If the microsphere size is too small, good plugging effect cannot be achieved; if the microsphere size is too large, microsphere injection is difficult. The expansion, plugging, unplugging, deformation plugging of the injected microspheres and the dissolution of the injected natural gas are synergic to effectively inhibit the fingering and channeling of displacing fluid during the development of fractured buried-hill reservoirs. Therefore, microsphere-natural gas flooding can greatly improve the recovery degree of remaining oil. Table and Figures | Reference | Related Articles | Metrics

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Optimization of Key Fracturing Parameters for Profitable Development of Horizontal Wells in Mahu Conglomerate Reservoirs ZHANG Jing, HU Dandan, QIN Jianhua, WANG Yingwei, TANG Huiying Xinjiang Petroleum Geology    2023, 44 (2): 184-194.   DOI: 10.7657/XJPG20230208 Abstract （267）   HTML （16）    PDF（pc） （1343KB）（131）       Knowledge map    Save In the process of transforming the Mahu conglomerate reservoirs in the Junggar basin from large-scale development to profitable development，it is particularly important to select reasonable fracturing parameters under the premise of considering economic benefits. In order to realize the optimization of key fracturing parameters for the Mahu conglomerate reservoirs，an equivalent KGD fracture propagation model was established to realize the rapid estimation of fracture shape. By using the heuristic particle swarm optimization algorithm and taking the rate of return as the objective function，a combined optimization on fracturing scale, cluster number and displacement was carried out for pay zones in the Mahu conglomerate reservoirs. The optimization results show that with the increase of the iteration number，the high-cost development plan finally converges to a combined optimization plan with the best comprehensive development effect，thus enabling the optimization of fracturing parameters for Ma 131 block. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation on Upgrading and Dilation of SAGD Ultra-Heavy Oil Reservoirs With High Heterogeneity MENG Xiangbing, SUN Xinge, LUO Chihui, MA Hong, WANG Qing Xinjiang Petroleum Geology    2023, 44 (2): 210-216.   DOI: 10.7657/XJPG20230211 Abstract （190）   HTML （16）    PDF（pc） （3508KB）（131）       Knowledge map    Save The ultra-heavy oil reservoirs in Fengcheng oilfield of Xinjiang belong to continental braided river deposits，with high heterogeneity. The SAGD well group in the oilfield has problems such as long preheating period and uneven development of steam chambers. The initial reservoir dilation test can significantly improve steam injection capacity and shorten preheating period，but lacks the whole-process rock mechanics coupling analysis on reservoir dilation，which is not conducive to the optimal design of the parameters for SAGD reservoir upgrading and dilation. Based on laboratory experiments such as rock triaxial compression test，the rock mechanical parameters of highly heterogeneous reservoirs were obtained，and a numerical model of SAGD dilation and thermal production for dual horizontal wells coupled with rock mechanics was established to analyze the factors influencing reservoir upgrading and dilation. Through the hierarchical and segmented dilation simulation for the highly heterogeneous reservoirs，it is clear that the reservoir upgrading and dilation should include five stages，that is，wellbore pore-pressure pretreatment stage，stress dilation stage of steam injector and its branches，large-volume dilation stage of steam injector and its branches，steam injector and producer connection stage，and above-injector large-volume dilation stage. An upgrading and dilation strategy represented by segmental dilation of fishbone well was formed for highly heterogeneous reservoirs. Field application has shown that the proposed reservoir upgrading and dilation technology is suitable for highly heterogeneous reservoirs. The technology can shorten the preheating period by 50% and increase the oil production rate by 20%. It provides a reference for the optimal design of parameters for SAGD upgrading and dilation in highly heterogeneous reservoirs. 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 （142）   HTML （12）    PDF（pc） （590KB）（131）       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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Main Controlling Factors and Gas Enrichment Area Selection of Ma55 Gas Reservoir in Eastern Sulige Gas Field BAI Hui, YANG Tebo, HOU Kefeng, MA Zhixin, FENG Min Xinjiang Petroleum Geology    2022, 43 (3): 271-277.   DOI: 10.7657/XJPG20220303 Abstract （372）   HTML （15）    PDF（pc） （5950KB）（130）       Knowledge map    Save In order to improve the drilling rate of pay zones in the Ma55 gas reservoir in eastern Sulige gas field, Ordos basin, using the drilling, logging, core and gas production testing data, and analyzing the main factors controlling pay zones such as sedimentary microfacies, diagenesis and paleotopography, the distribution law of dolomite in the Ma55 gas reservoir was clarified. Moreover, the reservoirs were comprehensively classified and evaluated, and the favorable gas enrichment areas in the Ma55 gas reservoir were selected. The research results show that the pay zones in the Ma55 reservoir are distributed as “lens” in local areas, with poor continuity. The most favorable reservoir rocks are granular dolomite and coarse powder crystalline dolomite, and the main storage space consists of intergranular pores, intergranular dissolved pores and structural fractures. Sedimentary facies and diagenesis are the main controlling factors of the Ma55 reservoir, and the grain beach is the most favorable sedimentary microfacies of the Ma55 dolomite. The pay zones are mainly controlled by quasi-contemporaneous dolomitization and buried dolomite diagenesis. The paleoslope on the relatively high position is a favorable area for the development of the Ma55 gas reservoir. Table and Figures | Reference | Related Articles | Metrics

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Lithology Identification for Diamictite Based on Lithology Scan Logging: A Case Study on Fengcheng Formation, Mahu Sag MAO Rui, SHEN Ziming, ZHANG Hao, CHEN Shanhe, FAN Haitao Xinjiang Petroleum Geology    2022, 43 (6): 743-749.   DOI: 10.7657/XJPG20220612 Abstract （230）   HTML （3）    PDF（pc） （1100KB）（130）       Knowledge map    Save Hydrocarbon-rich continental diamictite developed in the Permian Fengcheng formation of Mahu sag, Junggar basin is characterized by varieties of minerals and rapid variation of lithology. Conventional logging cannot be used to effectively identify the lithology of diamictite. By using lithology scan logging, the mass fractions of the main elements in the formation are obtained, and the mineral mass fraction is then calculated according to the relationship between mineral-sensitive elements and minerals. The diamictite index is constructed by using the ratio of felsic mineral content to carbonate mineral content, and the shale index is constructed by using the difference between neutron porosity and nuclear magnetic resonance total porosity. Then the lithology identification chart for the diamictite in the Fengcheng formation is formed by intersecting the diamictite index and the shale index. The results show that the calculation of mineral content is accurate with the average relative error of only 6.5%, and the lithology interpretation exhibits a coincidence rate of 90.9%, which meets the needs of logging evaluation. The proposed method provides a reference for logging lithology identification of diamictite shale 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 （155）   HTML （9）    PDF（pc） （516KB）（129）       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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Stratification and Segmentation Characteristics and Tectonic Evolution of Shunbei No.5 Strike-Slip Fault Zone in Tarim Basin CHEN Ping, NENG Yuan, WU Xian, HUANG Cheng, WANG Laiyuan, GUO Man Xinjiang Petroleum Geology    2023, 44 (1): 33-42.   DOI: 10.7657/XJPG20230105 Abstract （245）   HTML （11）    PDF（pc） （18034KB）（128）       Knowledge map    Save The ultra-deep fault-karst reservoirs in the Tarim basin are mainly distributed along strike-slip fault zones，and the oil and gas exploration effects are poor in the areas far away from fault zones，that is，the activity scale of strike-slip fault zones control the scale of hydrocarbon accumulation. The Shunbei No.5 strike-slip fault zone is a super-large strike-slip fault zone，which is characterized by deep burial，complex internal structure，and evident stratification and segmentation. Based on high-quality 3D seismic data，the geometry，kinematics and dynamics of the Shunbei No.5 strike-slip fault zone were systematically analyzed. It is recognized that the Shunbei No.5 strike-slip fault zone is evidently layered (including 5 structural layers)，and also segmented，with the southern and northern segments having different kinematic characteristics. The southern segment has experienced 5 stages of evolution，and the northern segment has experienced 4 stages of evolution. Table and Figures | Reference | Related Articles | Metrics

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Development Characteristics of Solution-Gas Drive in Fault-Karst Reservoirs in Shunbei-1 Block LIU Xueli, TAN Tao, CHEN Yong, XIE Hui, ZHU Suyang, WU Haoqiang, XIANG Dongliu Xinjiang Petroleum Geology    2023, 44 (2): 195-202.   DOI: 10.7657/XJPG20230209 Abstract （211）   HTML （17）    PDF（pc） （2422KB）（124）       Knowledge map    Save In order to confirm whether there is solution-gas drive in the fault-karst reservoirs in the Shunbei-1 block, reservoir numerical simulation was performed to characterize the solution-gas drive in the fault-karst reservoirs. Based on the reservoir engineering method, the solution-gas-drive characteristics of the fault-karst reservoirs in the Shunbei-1 block were analyzed. The study shows that due to the large thickness of the fault-karst reservoirs in the study area, component gravity differentiation occurs simultaneously near the bottom of the well and at the top of the reservoir, leaving a large amount of solution-gas unproduced and forming a secondary gas cap. Under the action of the elastic energy of solution-gas, the decline of bottomhole flow pressure slows down, and the dynamic reserves of a single well increase to a certain extent. This process is accompanied by the decline in oil-phase driving index. With the further development of solution-gas drive, the secondary gas cap invades the bottom of the well, resulting in a rapid decline of oil production. Therefore, during the depletion development of the fault-karst reservoirs in the Shunbei-1 block, the solution-gas drive can be used to a certain extent together with development under pressure. Table and Figures | Reference | Related Articles | Metrics

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Architecture and Prediction of Clastic Reservoirs in Offshore Oilfields With Sparse Well Pattern: A Case Study on L14 Oilfield in Lufeng Sag in Pearl River Mouth Basin DAI Jianwen, ZHANG Wei, WANG Hua, YANG Jiao, TU Yi, LI Qi Xinjiang Petroleum Geology    2022, 43 (5): 526-536.   DOI: 10.7657/XJPG20220504 Abstract （251）   HTML （5）    PDF（pc） （4172KB）（124）       Knowledge map    Save Offshore oilfields are characterized by large well spacing, sparse well pattern, and strong reservoir heterogeneity. Taking the 5th member of Wenchang formation (Wen 5 member) of Paleogene in L14 oilfield, Lufeng sag, Pearl River Mouth basin, as an example, a method for characterizing the architectures of continental braided river delta reservoirs based on “hierarchy constraint, subdivided dissection, pattern fitting, logging-seismic cross-feedback and multidimensional coordination” was proposed. By using frequency-dividing RGB fusion technology, the architecture units of the reservoirs were characterized. On the basis of reservoir architecture division, high-quality reservoirs were predicted. The results show that the third-order architecture unit in the study area is composite distributary bar, and the fourth-order architecture unit is composed of distributary bar, distributary channel and braided channel. The fourth-order architecture unit is found with three vertical stacking styles and two lateral splicing styles. The rock mineral components and architecture units play a leading role on physical properties. In the Wen 5 member, Class Ⅰ reservoirs are dominant and mostly distributed in distributary bars; Class Ⅱ reservoirs are mainly distributed in the outer edge of Class Ⅰ reservoirs, with poor continuity; and Class Ⅲ reservoirs are often associated with Class II reservoirs, with the poorest continuity. From the center to the outer edge of the distributary bar, and then to the distributary channel and braided channel between the distributary bars, the reservoir quality gradually decreases. Table and Figures | Reference | Related Articles | Metrics

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Semi-Analytical Model and Flow Characteristics of Asymmetrically Fractured Off-Center Vertical Wells in Tight Gas Reservoirs WANG Yufeng, JI Anzhao, ZHANG Guangsheng, CHEN Zhanjun Xinjiang Petroleum Geology    2022, 43 (4): 425-432.   DOI: 10.7657/XJPG20220407 Abstract （224）   HTML （5）    PDF（pc） （696KB）（123）       Knowledge map    Save To understand the flow regime of asymmetrically fractured off-center vertical wells in tight gas reservoirs,a mathematical model for asymmetrically fractured off-center vertical wells was established according to the mass conservation equation. The bottom-hole pseudo pressure of off-center vertical well in Laplace space was obtained by using Laplace transform and numerical discretization. The time-space distribution of pressure and production were determined by using the Stehfest numerical inversion method,and the impacts of fracture angle,dimensionless fracture conductivity and eccentric distance on bottom-hole pseudo pressure and production were discussed. With the help of Saphir well test interpretation software,the numerical model of gas well was built and the numerical calculation for discretization was performed. The calculated results were compared with the semi-analytical solution to verify the mathematical model. Furthermore,according to the variation characteristics of the dimensionless bottom-hole pseudo pressure,the fluid flow in asymmetrically fractured off-center vertical wells was divided into six stages: bilinear flow stage in reservoir and fracture,linear flow stage in reservoir,elliptical flow stage in fracture,plane radial flow stage,near-fracture boundary-dominated flow stage,and circular closed boundary-dominated flow stage. Table and Figures | Reference | Related Articles | Metrics

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Evaluation on Adaptability of Horizontal Well Development to Multi-Layer Tight Sandstone Gas Reservoirs LIU Jiaojiao, WANG Delong, LIU Qian, TANG Jing Xinjiang Petroleum Geology    2022, 43 (3): 354-359.   DOI: 10.7657/XJPG20220314 Abstract （282）   HTML （5）    PDF（pc） （962KB）（122）       Knowledge map    Save For multi-layer gas reservoirs in the Shenmu gas field, improper selection of geological targets for horizontal well development may lead to the problems such as poor economic benefits and unrecovered reserves. The development scale and stacking patterns of sand bodies in these multi-layer gas reservoirs were investigated, and the single-layer, double-layer and multi-layer gas reservoir models were established by adopting the concept of reserves concentration. Taking the horizontal well stimulation ratio as the basis for economic benefit evaluation, the reservoir limit of horizontal well development in multi-layer reservoirs was evaluated. The research shows that large-scale composite effective reservoirs are locally developed in the Lower Permian Taiyuan formation and the second member of the Lower Permian Shanxi formation in the Shenmu gas field, with an effective thickness of 6.0-9.0 m and a length of 1 600-3 200 m. These intervals satisfy the optimal reservoir conditions for horizontal well development, namely the reserves concentration greater than 75% and the permeability ratio of the dominant layer to the secondary producing layer ranging from 0.8 to 3.9. Table and Figures | Reference | Related Articles | Metrics

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Factors Influencing Effective Storage Capacity of Abnormally-High-Pressure Water-Containing Condensate Gas Reservoirs FAN Jiawei, WU Zangyuan, YU Song, ZHOU Daiyu, YAN Gengping, WANG Chao Xinjiang Petroleum Geology    2022, 43 (4): 463-467.   DOI: 10.7657/XJPG20220412 Abstract （260）   HTML （4）    PDF（pc） （561KB）（121）       Knowledge map    Save As a key parameter, the effective storage capacity of a UGS affects the function, peaking capability, parameters and design of the UGS, so its accurate evaluation is very important. When converting an abnormally-high-pressure water-containing condensate gas reservoir into a UGS, factors such as abnormally high pressure, water intrusion and reverse condensate affect the storage capacity. Considering abnormally high pressure, the upper limit of the pressure for the UGS is designed to be 58.00 MPa, which is much lower than the original formation pressure. The difference of the gas volume coefficient results in the difference of the storage capacity of the UGS. During the injection-production process, water flows back and forth in the UGS, which dramatically affects the utilization of reservoir space. In the alternative production-injection process, when the formation pressure is lower than the dew point pressure, separated condensate oil has a certain influence on the storage capacity. In response to this problem, an improved dual model integrating material balance and numerical simulation was established. Based on the dynamic reserves of gas reservoirs, factors such as abnormal high pressure, reverse condensation, water intrusion were quantitatively analyzed, and a set of methods for evaluating the capacity of the UGS were developed. The set of methods was applied for constructing the Lunnan-59 Carboniferous UGS. The effective storage capacity of the UGS was accurately evaluated. This lays a foundation for the research on the parameters of the UGS, and ensures the successful construction of the Lunnan-59 Carboniferous UGS. 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 （160）   HTML （13）    PDF（pc） （1855KB）（120）       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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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 （154）   HTML （12）    PDF（pc） （7528KB）（120）       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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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 （148）   HTML （17）    PDF（pc） （6614KB）（119）       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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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 （142）   HTML （17）    PDF（pc） （539KB）（118）       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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Water-Gas Ratio and Early Warning of Water Invasion in Unconsolidated Sandstone Gas Reservoirs in Sebei Gas Field，Qaidam Basin CHAI Xiaoying, WANG Yan, LIU Junfeng, CHEN Fenjun, YANG Huijie, TAN Zhiwei Xinjiang Petroleum Geology    2023, 44 (1): 51-57.   DOI: 10.7657/XJPG20230107 Abstract （250）   HTML （5）    PDF（pc） （614KB）（118）       Knowledge map    Save The Sebei gas field in the Qaidam basin is an anticline-type shallow unconsolidated sandstone gas field driven by weak edge water，and is exploited by depletion. According to water-gas ratio (WGR)，the production process in the gas field can be divided into four stages: low water-cut steady production stage，initial water invasion stage，edge water breakthrough stage，and strong water invasion stage. The occurrence of water invasion can be accurately monitored based on WGR. The edge water breakthrough stage can be used as a time window for predicting the large-scale water invasion of edge water，so as to adjust the development plan and extend the steady production period. The strong water invasion stage with high water cut corresponds to a long production period，so it is an important stage for enhanced oil recovery while producing with water. 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 （113）   HTML （7）    PDF（pc） （1450KB）（118）       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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Hydrocarbon Accumulation Mechanism of Total Petroleum System in Permian Fengcheng Formation，Mahu Sag HE Wenjun, SONG Yong, TANG Shiqi, YOU Xincai, BAI Yu, ZHAO Yi Xinjiang Petroleum Geology    2022, 43 (6): 663-673.   DOI: 10.7657/XJPG20220604 Abstract （262）   HTML （9）    PDF（pc） （10902KB）（117）       Knowledge map    Save The exploration practice in the Fengcheng formation in the Mahu sag，western Junggar basin，has revealed the orderly coexistence of conventional and unconventional hydrocarbons. By finely dissecting the characteristics of the total petroleum system in the Fengcheng formation in the Mahu sag，and combining with the macro-and micro-analysis and production data of the reservoirs，the hydrocarbon accumulation mechanism of the total petroleum system was analyzed. The results show that conventional oil，tight oil and shale oil accumulate in an orderly pattern in the total petroleum system，which essentially complies with the hydrocarbon accumulation pattern of “source-reservoir coupling” and “dynamic sealing” of oil and gas. In the early diagenesis stage，the present tight reservoirs and shale reservoirs were conventional reservoirs with medium-large pore throats，where hydrocarbons accumulated because of buoyancy. In the middle-later diagenesis stage，the medium-large pore throats gradually evolved to micro-to nano-pore throats，the buoyancy was weakened，and the capillary force was strengthened. The hydrocarbon in the reservoir adjacent to or integrated with the source rocks underwent primary or micro migration continuously until the source-reservoir pressure difference resulted from hydrocarbon generation and expulsion and the capillary force originated from micro-to nano-pore throats reached a dynamic equilibrium，forming a “self-sealing” continuous unconventional oil and gas accumulation. The capillary force in the present conventional reservoirs is far less than the buoyancy，so “external sealing”is needed for hydrocarbon accumulation in traps. Generally，the hydrocarbon accumulation in the Fengcheng formation is represented by the space-time evolution of the pore throat structure in the reservoir and the dynamic coupling of source rock and reservoir on hydrocarbon generation-expulsion-migration-accumulation. Table and Figures | Reference | Related Articles | Metrics

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Comprehensive Identification of Fractured-Vuggy Reservoirs in Tahe Oilfield WU Bo, YANG Wendong, LYU Jing, LUO Junlan Xinjiang Petroleum Geology    2023, 44 (2): 238-244.   DOI: 10.7657/XJPG20230215 Abstract （222）   HTML （24）    PDF（pc） （1223KB）（116）       Knowledge map    Save In order to realize the identification of the connected fractured-vuggy structures in the Tahe oilfield，based on the seismic interpretation results of large-scale reservoirs，together with the drilling，logging，testing，tracer and other data，the reservoir types in near-well and inter-well areas were identified. By identifying the reservoirs with static and dynamic monitoring methods，the characteristic parameters of the dynamic methods for identifying reservoirs in fractured-vuggy units were determined to improve the reliability of the identification. Depending upon the types of reservoirs identified with static and dynamic methods，the connected fractured-vuggy structures were constructed according to their in spatial position relationship. The application in the identification of single-well fractured-vuggy structures in the X unit reveals that the proposed comprehensive method is more reliable in identification of fractured-vuggy structure than a single static or dynamic method. 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 （134）   HTML （16）    PDF（pc） （3886KB）（116）       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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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 （147）   HTML （4）    PDF（pc） （651KB）（116）       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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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 （145）   HTML （11）    PDF（pc） （5975KB）（115）       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