Top Downloaded

Published in last 1 year| In last 2 years| In last 3 years| All| Most Downloaded in Recent Month | Most Downloaded in Recent Year|

Published in last 1 year

Please wait a minute...


For Selected: Download Citations EndNote Ris BibTeX Toggle Thumbnails

Select

Characteristics and Controlling Factors of Pore Structure in Coal-Measure Shale Reservoirs: Taking Longtan Formation in Western Guizhou as an Example LI Juhao, HE Jinxian, YANG Zhaobiao, ZHANG Xiaoli, WU Meng, MA Li, YUAN Yuan, WEN Mingzhong Xinjiang Petroleum Geology    2025, 46 (5): 521-530.   DOI: 10.7657/XJPG20250501 Abstract （431）   HTML （26）    PDF（pc） （4043KB）（179）       Knowledge map    Save Pore structure affects gas storage performance of shale and is an important parameter for evaluating shale gas resource potential. Taking the coal-measure shale of Upper Permian Longtan formation in western Guizhou as an example, micro-pores and micro-fractures were qualitatively observed using scanning electron microscopy (SEM) and classified, and the microscopic pore structure and pore size distribution were quantitatively characterized through high-pressure mercury injection and low-temperature nitrogen adsorption experiments. Combining with organic geochemical parameters and mineral composition distribution characteristics, the factors controlling the pore structures of coal-measure shale reservoirs were identified. The results show that the matrix pores in coal-measure shale of the Longtan formation can be divided into six occurrence types: residual primary intergranular pores, mineral moldic pores, clay mineral intergranular pores, intergranular pores, intragranular dissolution pores, and organic pores, and the micro-fractures are mainly extensional, shear, bedding, and diagenetic shrinkage micro-fractures. Micro-pores (especially those with diameter <5 nm) and transitional pores provide the main pore space. The pore space types are dominated by ink bottle holes and V-shaped holes, with a certain amount of parallel slits, and the connectivity between pores is relatively good. Total organic carbon content (TOC), maturity of organic matter, and mineral composition are the main factors controlling the pore structure of the coal-measure shale reservoirs of Longtan formation in western Guizhou. The single-point pore volume and specific surface area of the shale increase with the increase of TOC. The degree of thermal evolution contributes positively to the increase of micro-pore and transitional pore volume. Clay minerals have complex impacts on the pore structure. High brittleness index has a positive effect on the development of meso-pores, macro-pores and micro-fractures, being conducive to shale gas flow. Table and Figures | Reference | Related Articles | Metrics

Select

Study on CO2 Storage and CH4 Recovery Enhancement in Tight Sandstone Gas Reservoirs JIANG Yi, YANG Shenglai, BAI Haoyan, CHEN Yingli, MEI Qingyan, WANG Beidong Xinjiang Petroleum Geology    2025, 46 (5): 591-599.   DOI: 10.7657/XJPG20250509 Abstract （325）   HTML （4）    PDF（pc） （1471KB）（170）       Knowledge map    Save The CO2 storage and enhanced gas recovery (CS-EGR) technology represents a promising option for boosting production in the context of “dual carbon” goals. However, its application in tight sandstone gas reservoirs has been scarcely studied, and its field performance remains unclear. This study establishes a reservoir-scale numerical model based on a comprehensive analysis of gas-water two-phase flow mechanisms and stress sensitivity across three reservoir types. Using this model, the adaptability of CO2 injection to reservoirs, CO2 migration behaviors, CO2 trapping mechanisms, impacts of movable water on the CS-EGR process, and optimization of engineering parameters for CS-EGR are analyzed. It is indicated that CS-EGR is viable only for Class Ⅰ reservoirs, but less performed in Class Ⅱ and Class Ⅲ reservoirs. In terms of CO2 trapping mechanism, both structural trapping and residual trapping account for 95.8%, while CO2 mineralization and storage contributes 0.15%. For Class Ⅰ reservoirs, the optimal CO2 injection rate is 10,000 m3/d, the cumulative production of CH4 is 0.146×108 m3 when CO2 breaking through, and the cumulative storage of CO2 is 0.794×108 m3. Movable water significantly hinders CO2 migration and increases the risk of gas well flooding. Table and Figures | Reference | Related Articles | Metrics

Select

Mechanism and Performance of Flue Gas-Assisted Steam Flooding in Heavy Oil Reservoirs SONG Tao, LI Yiqiang, LYU Xiaolong, YAN Zhiqian, TANG Xuechen, ZI Jianqiang, LIU Zheyu Xinjiang Petroleum Geology    2025, 46 (5): 606-613.   DOI: 10.7657/XJPG20250511 Abstract （368）   HTML （4）    PDF（pc） （5201KB）（166）       Knowledge map    Save Flue gas-assisted steam flooding is an economically viable enhanced oil recovery (EOR) technology for heavy oil reservoirs. To address the complex mechanisms of synergy between flue gas injection and steam injection, and the unclear impacts of injection process and reservoir properties on development performance, experiments and numerical simulations were performed on flue gas-assisted steam flooding following conventional steam flooding. Taking a heavy oil reservoir as an example, core flooding experiments were conducted to compare oil displacement efficiencies under different injection media. A mechanistic model of flue gas-assisted steam flooding for heavy oil reservoirs was established to systematically investigate its underlying mechanism and performance. The research results show that flue gas-assisted steam flooding improves oil recovery efficiency by 5.84% compared to pure steam flooding, attributed to multiple mechanisms such as thermal viscosity reduction by steam, pressurization effect of flue gas, enhanced thermal sweep efficiency via gis-liquid Jamin effect, and oil mobilization by flue gas flow. The injected flue gas forms a gas zone at the steam chamber front, prolonging steam-oil interaction time while mitigating steam override, thereby expanding thermal sweep area. An optimal steam-to-flue gas molar ratio of 7∶3 during injection can achieve a favorable balance between enhanced oil recovery and reduced steam consumption. Slug injection generates periodic pressure differentials in the reservoir, further improving displacement efficiency over co-injection. These findings provide theoretical and practical guidance for designing flue gas-assisted steam flooding schemes in heavy oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Pore Structure and Reservoir Properties of Deep Coals: A Case Study of No.5 Coal Rock of Shanxi Formation in Southwestern Ordos Basin LUO Jing, ZHANG Lei, ZHANG Jianwu, PAN Xing, CAO Qian, LI Lei, YAN Ting, LI Teng Xinjiang Petroleum Geology    2025, 46 (5): 531-543.   DOI: 10.7657/XJPG20250502 Abstract （433）   HTML （13）    PDF（pc） （9852KB）（159）       Knowledge map    Save In order to clarify the deep coal-forming environment and its controls on the microsopic pore structure and reservoir properties of coal rocks, the deep No.5 coal rock of Shanxi formation in southwestern Ordos Basin was selected for investigating the facies, pore structure and reservoir properties of deep coal rocks through macroscopic observations, coal quality measurements, scanning electron microscope (SEM), and gas adsorption tests. The results show that the No.5 coal rock features extra-low water yield, moderate ash yield, extra-low volatile yield, and moderate-high fixed carbon content, with the average vitrinite reflectance up to 2.38%. The content of vitrinite ranges from 42.09% to 72.49%, with an average of 60.60%, and the content of inertinite reaches 27.34% averagely, while exinite is rare in the coal. Desmocollinite, telocollinite and semifusinite are the dominant sub-macerals of the coal samples. The coal-forming environment was dominated by moist forest-swamp facies, with large overlying water depth and weak hydrodynamic force. The bedding fractures, gas pores and plant tissue pores serve as the dominant reservoir space types, and a small amount of intergranular pores and clay mineral intercrystalline pores are also observed. Micropores and mesopores with pore sizes less than 22 nm are the reservoir space, and the heterogeneity of pore structure containing larger mesopores is more significant. The coal-forming environment with strong water overburden and weak flow is conducive to the development of vitrinite, which also determines that micropores are the main reservoir space of the deep coal. Under the action of gelation, the adsorption and adhesion of terrigenous detritus by coal organic matters led to strong heterogeneity of pore structure containing larger mesopores. Table and Figures | Reference | Related Articles | Metrics

Select

Dominant Geomechanical Factors Controlling the Volumetric Stimulation Effectiveness in the Shale Oil Reservoirs of the Lucaogou Formation, Jimsar Sag LIU Xiangjun, GAN Renzhong, XIONG Jian, TANG Shiqi, WAN Youwei, ZHOU Xin, LIANG Lixi, ZHANG Miao Xinjiang Petroleum Geology    2025, 46 (6): 723-733.   DOI: 10.7657/XJPG20250608 Abstract （202）   HTML （2）    PDF（pc） （2520KB）（154）       Knowledge map    Save In response to the challenges in enhancing volumetric stimulation effectiveness in the shale oil reservoirs of the Lucaogou formation in the Jimsar sag of the Junggar Basin, a systematic study was conducted. Based on the lithological assemblage characteristics and geomechanical parameters of the study area, numerical simulation was employed to analyze the propagation patterns of hydraulic fractures under different lithological assemblages. The research focused on the controlling effects of interlayer strength, in-situ stress, interface strength coefficient, displacement, and horizontal well placement on fracture propagation, and explored a differentiated optimization method for fracturing stages. The results indicate that an increase in the elastic modulus of the reservoir/barrier layers and a decrease in tensile strength both facilitate vertical fracture propagation, whereas a high horizontal stress difference significantly inhibits vertical fracture extension. A critical threshold exists for the interlayer interface strength coefficient, which directly governs fracture propagation behavior. Under this critical condition, high displacement promotes fracture penetration through barriers, while low displacement lead to fracture diversion along interfaces. Well placement exhibits a limited impact on fracture geometry, as effective vertical propagation can be achieved regardless of whether the horizontal well is placed within the reservoir or barrier layers. A nonuniform staging scheme based on geological-engineering sweet spot evaluation effectively enhances stimulation efficiency and reduces ineffective operations. This research results provide theoretical support and practical guidance for optimizing horizontal well trajectory, fracturing stage design, and treatment parameters in the shale oil development of the study area. Table and Figures | Reference | Related Articles | Metrics

Select

Main Controlling Factors and Development Practice of Shale Oil Sweet Spots in the Lucaogou Formation, Jimsar Sag, Junggar Basin JIN Zhijun, CAO Yan, ZHANG Hong, TANG Yong, QIN Zhijun, LIU Kouqi, LIANG Chenggang, LI Guanfang, HE Wenjun Xinjiang Petroleum Geology    2025, 46 (6): 647-658.   DOI: 10.7657/XJPG20250601 Abstract （254）   HTML （12）    PDF（pc） （5499KB）（128）       Knowledge map    Save The Permian Lucaogou formation in the Jimsar sag, Junggar Basin, represents one of the most significant continental shale oil plays in China. However, uncertainties remain regarding the primary geological controls of “sweet spots”, incomplete evaluation frameworks, and discontinuous distribution of productive intervals. Clarifying the formation mechanisms and identification criteria of the sweet spots is critical for advancing shale oil exploration theory and guiding efficient development. Based on core, well logging, and experimental data, this study systematically investigates the controlling factors of shale oil sweet spots in the Lucaogou formation from four dimensions (reservoir capacity, oil-bearing capacity, mobility, and fracability). The results indicate that the Lucaogou formation can be divided into upper, middle, and lower sweet-spot intervals, among which the middle interval remains largely undeveloped yet holds substantial potential. Siltstone and calcareous-felsic shale which are characterized by abundant macropores, high free hydrocarbon content, and strong mobility constitute the most favorable lithofacies. Intervals with moderate total organic carbon (TOC) content, moderate maturity, and high brittle-mineral content are more conducive to forming fracable sweet spots. A four-property coupling evaluation highlights the middle interval as a prime development target which is further validated by the high-yield performance of Well JHW85-71. This study provides a scientific foundation for sweet spot identification and development planning of shale oil in the Lucaogou formation in the Jimsar sag. Table and Figures | Reference | Related Articles | Metrics

Select

Characteristics of Ordovician Karst Reservoirs in Ma 4 Block of Hetianhe Gas Field and Its Influences on Well Productivity LI Chongyue, XU Wensheng, HAN Fuqiang, YANG Yan, ZHOU Lang, ZHANG Hu, YU Bingyue Xinjiang Petroleum Geology    2025, 46 (5): 553-559.   DOI: 10.7657/XJPG20250504 Abstract （412）   HTML （12）    PDF（pc） （3445KB）（119）       Knowledge map    Save The Ordovician carbonate reservoirs are the main development targets in the Hetianhe gas field. Taking the Ma 4 block as an example, the paleokarst characteristics were investigated based on core, thin section, logging, drilling and fluid data. The relationship between fractures and paleokarstifcaiton or filling was analyzed, the main factors controlling gas well production were evaluated, and the favorable targets for tapping the potential of the karst reservoirs were clarified. The research results show that the characteristics of fracture development in the vertical flow zone are not only related to tectonic characteristics, but also to surface karstification and filling processes. The activity of bottom water in the gas reservoir is related to the burial dissolution. Karst zonation is the main cause for the dual structure of karst reservoirs. The fracture zone is not the active water zone. The production effect of a single well mainly depends on two factors, namely burial dissolution and fracture development in the vertical flow zone. Table and Figures | Reference | Related Articles | Metrics

Select

Tectonic-Paleogeographic Restoration and Basin-Range Coupling Reappraisal of the Paleogene in Southwestern Tarim Basin GENG Feng, CAO Zicheng, WANG Arui, CAO Kai, YAO Junzhe, XU Yadong, WANG Guocan Xinjiang Petroleum Geology    2026, 47 (2): 127-136.   DOI: 10.7657/XJPG20260201 Abstract （200）   HTML （16）    PDF（pc） （1915KB）（114）       Knowledge map    Save The Paleogene strata in the southwestern Tarim Basin record the transgression-regression process of the Tarim Basin and the early Cenozoic orogenesis of the Pamir-West Kunlun orogenic belt. Thus, restoring the tectonic-paleogeographic framework of the Paleogene in the southwestern Tarim Basin is significant for understanding the paleogeographical and paleoenvironmental changes in central Asia. Based on the geological survey on the Qimugan section of the Paleogene in the southwestern Tarim Basin, together with available drilling and outcrop data, the stratigraphic framework and sedimentary sequence of the Paleogene were investigated, the tectonic-lithofacies paleogeography of the Paleogene was mapped, and the basin-range coupling process of the Paleogene was analyzed. The results show that the southwestern Tarim Basin had a higher topography in the east than in the west in the Paleogene. During the Paleocene-Late Eocene, the southwestern Tarim Basin was dominated by marine sediments in the western part, marine-continental transitional sediments in the central part, and delta sediments in the eastern part. During the Late Eocene-Oligocene, the southwestern Tarim Basin witnessed a further uplift in the southern part, together with expanded delta sediments, and a dominance of shallow lake and near-shore submarine fan sediments in the western part and of lakeside sediments in the eastern part. As a whole, the southwestern Tarim Basin fully transformed into a lacustrine depositional environment. Generally, the southwestern Tarim Basin experienced two cycles of transgression-regression during the Paleogene. After the second regression, the sea water completely retreated from the southwestern Tarim Basin. The spatio-temporal coincidence of the regression with the crustal thickening and shortening of Pamir and the global sea level drop suggests that the final regression of the Tarim Basin is probably a result of the combined effect of tectonic and climatic changes. Table and Figures | Reference | Related Articles | Metrics

Select

CO2 Injection for Flow Field Reconstruction in Jurassic Bottom Water Reservoirs， Ordos Basin ZOU Jiandong, TAN Xiqun, ZHANG Jiaosheng, LI Chao, LIU Jungang, LYU Wei, ZHAO Haifeng Xinjiang Petroleum Geology    2025, 46 (5): 560-566.   DOI: 10.7657/XJPG20250505 Abstract （321）   HTML （15）    PDF（pc） （1831KB）（107）       Knowledge map    Save Edge and bottom water are found in the Jurassic oil reservoirs in the Ordos Basin. In this kind of reservoirs, rapid water cut rise and low recovery by water flooding occur after initital production. In order to explore new methods for enhanced oil recovery in such reservoirs and find new ways to increase production by carbon sequestration in near-abandoned reservoirs, a pilot test was conducted on top CO2 injection for flow field reconstruction in the Y9 reservoir in the X1 block of Jiyuan oilfield. Through the mechanism analysis of CO2-assisted gravity drainage, multiphase and multi-component numerical simulation was performed to understand the sensitivity and adaptability of the reservoir's geological parameters, and the reservoir engineering parameters were also optimized for the test area. The results show that the residual oil in the Jurassic bottom water reservoirs after waterflooding mainly exists in three forms: thick oil ring in the zone between injection and production wells after the invasion of bottom water, thin oil ring in the zone from the outer oil-bearing edge to the oil production well due to bottom water coning and edge water intrusion, and residual oil after waterflooding. Injecting CO2 at the reservoir top is an effective way to inhibit bottom water coning. As an artificial gas cap forms and exaggerates, gas-oil contact moves downwards, and accordingly oil-water contact becomes lower, alleviating bottom water coning. The main factors affecting CO2-assisted gravity drainage include formation dip, reservoir thickness, permeability, heterogeneity, crude oil properties, and oil saturation, etc. Simulation studies and pilot tests indicate that CO2-assisted gravity drainage at the reservoir top can effectively reconstruct the flow field in waterflooding reservoirs, thereby enhancing the ultimate recovery. Table and Figures | Reference | Related Articles | Metrics

Select

Source-Reservoir Coupling and Sweet Spot Formation Mechanism of Continental Laminated Shale Oil: A Case Study of the Fengcheng Formation, Junggar Basin CAO Jian, QIN Zhijun, WEI Chao, XIANG Baoli, LIU Jin Xinjiang Petroleum Geology    2025, 46 (6): 668-683.   DOI: 10.7657/XJPG20250603 Abstract （294）   HTML （6）    PDF（pc） （20647KB）（105）       Knowledge map    Save Significant breakthroughs have been made in the exploration of continental shale oil in China. However, the strong heterogeneity and complex source-reservoir coupling in these shales have hindered the understanding of sweet spot formation mechanism. In this paper, taking the Permian Fengcheng formation in the Junggar Basin as an example, the characteristics of shale laminae and their controls on shale oil sweet spots were systematically investigated using multiple techniques such as large-area thin-section scanning, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), confocal laser scanning microscopy (CLSM), and organic geochemical analysis. The results indicate that the lacustrine shales of the Fengcheng formation are well-laminated. The laminae can be classified into six types: silt-grade felsic lamina (SFL), argillaceous-grade felsic lamina (AFL), sparry dolomitic lamina (SDL), sparry calcite lamina (SCL), spherulitic siliceous lamina (SSL), and alkaline mineral lamina (AML). Two predominant laminated shale combinations are identified, i.e., SFL + AFL, and SCL/SDL + AFL. These lamina types exhibit significant variations in source-reservoir characteristics. AFL and SSL, characterized by high organic matter (OM) contents and the presence of high-quality hydrocarbon precursors such as laminated algae and rhodophyta spores, serve as the primary hydrocarbon-generating laminae. In contrast, SFL exhibits well-developed micropores and nanopores, including quartz/feldspar intercrystallline pores and feldspar intragranular dissolved pores, with a high proportion of free oil, rendering it favorable reservoir lamina. The superimposition of multiple lamina types governs organic-inorganic interactions, reservoir space characteristics, and hydrocarbon micro-migration processes, ultimately leading to differential enrichment of shale oil across various intervals. It is noted that the SFL + AFL combination represents the optimal source-reservoir configuration, demonstrating excellent overall oil content and forming an enrichment model characterized by oil generation in argillaceous lamina and accumulation in silty lamina. This combination is identified as a favorable target for shale oil exploration and development. Table and Figures | Reference | Related Articles | Metrics

Select

Hydrocarbon Accumulation Mechanism and Exploration Potential of Permian Whole Petroleum System in the Jimsar Sag CHEN Xuan, LIN Lin, LIU Juntian, GONG Deyu, YANG Runze, WANG Bo, XIE An Xinjiang Petroleum Geology    2026, 47 (1): 1-10.   DOI: 10.7657/XJPG20260101 Abstract （206）   HTML （18）    PDF（pc） （6979KB）（102）       Knowledge map    Save In the Jimsar sag, petroleum exploration mainly focuses on unconventional oil reservoirs. In recent years, breakthroughs have been made in multiple strata above and below the source rocks of the Lucaogou formation and across the sag, revealing its good exploration potential and the characteristics of a whole petroleum system. Based on seismic, drilling, logging, and organic geochemistry data, the formation conditions of the whole petroleum system, and the hydrocarbon accumulation model are investigated by thoroughly dissecting known oil reservoirs. The results show that there is an orderly symbiosis between conventional and unconventional reservoirs in the Jimsar sag. Horizontally, shale oil, tight oil, and conventional sandy conglomerate oil reservoirs are developed successively from the sag area through the slope area to the structural high. Vertically, tight oil, shale oil, and conventional oil reservoirs are found successively in the Jingjingzigou formation-Lucaogou formation-Wutonggou formation sequence. The source rocks of Lucaogou formation undergone mass hydrocarbon generation and expulsion in low maturity stage, laying a material foundation for the whole petroleum system. The Lucaogou formation contains sandstone/conglomerate, mixed-rock, and shale reservoirs successively from basin margin to basin interior horizontally, and full grain sequence reservoirs of overlying Wutonggou formation and underlying Jingjingzigou formation are found vertically. A three-dimensional hydrocarbon accumulation model consisting of three horizontal zones and three vertical floors is established. Controlled by the hydrocarbon generation evolution of source rocks of the Lucaogou formation and the presence of multi-type reservoirs, the Permian strata in the Jimsar sag show characteristics of a whole petroleum system with orderly symbiosis between unconventional and conventional reservoirs. Based on the theory of the whole petroleum system and the exploration practice in the Jimsar sag, the Permian petroleum exploration in eastern Junggar Basin should focus on the sags such as Shishugou and Jinan, especially for finding tight oil and gas reservoirs in the slope or sub-source areas, structural-lithologic oil and gas reservoirs in the above-source fault-step belts and high structural positions, and shale oil reservoirs in the inner-source zones. Table and Figures | Reference | Related Articles | Metrics

Select

Identification of Fault-Karst Bodies in Permian Maokou Formation in Jingyan Area, Southwestern Sichuan Basin LI Suhua, LU Qijun, HU Hao, LI Rong, SU Chengpeng, JIANG Nengchun Xinjiang Petroleum Geology    2025, 46 (5): 544-552.   DOI: 10.7657/XJPG20250503 Abstract （294）   HTML （23）    PDF（pc） （35146KB）（99）       Knowledge map    Save The distribution of fault-controlled karst reservoirs in the Permian Maokou formation in the Jingyan area of southwestern Sichuan Basin remains unclear. A seismic identification model for faults and fault-karst bodies in the Maokou formation was established using drilling, geological, seismic and other data. The differences in seismic reflections between faults and fault-karst bodies were analyzed through forward modelling. On this basis, multi-stage superimposed faults were identified using seismic structural attributes such as coherence, maximum likelihood, dip angle and gradient structure tensor etc., and interlayer fault-karst bodies were recognized from seismic texture attributes such as entropy and energy. Then the distribution of Maokou formation fault-controlled karst reservoirs was accurately determined, and a geological development model was established. The results indicate that the study area mainly develops two types of fault-controlled karst reservoirs: multi-stage superimposed fault-karst bodies, which are observed in the southern part of the study area, and interlayer fault-karst bodies, which are developed in the eastern part of the study area. The seismic structural attributes can be used to accurately recognize high, steep and upright multi-stage superimposed fault-karst bodies that exhibit significant differences in the continuity of seismic waveforms, while the seismic texture attributes can be used to accurately represent gentle and low-angle interbedded fault-karst bodies with obvious changes in reflection amplitude energy of seismic waveforms. The predicted results are consistent with actual drilling results, and the research results can guide the future exploration deployment. Table and Figures | Reference | Related Articles | Metrics

Select

Calculation Methods and Influencing Factors of Gas Field Decline Rate FAN Youhong, LIU Zhijun, PEI Ze, REN Chaofeng Xinjiang Petroleum Geology    2025, 46 (5): 600-605.   DOI: 10.7657/XJPG20250510 Abstract （340）   HTML （3）    PDF（pc） （545KB）（95）       Knowledge map    Save Accurate evaluation of performance decline is crucial for efficient development of gas fields and ensuring stable energy supply. Production decline rate and productivity decline rate are two commonly used parameters for presenting performance decline in gas fields from different perspectives, but their definitions are different. In order to understand the physical meanings of production decline rate and productivity decline rate and clarify their inherent relationship and influencing factors, the calculation method of gas field decline rate was analyzed, and the influencing factors were identified. The results indicate that, for exponential decline, the productivity decline rate are consistent with the production decline rate, while for hyperbolic decline, the productivity decline rate is always greater than the production decline rate, and the difference between the two decline rates increases with the increase of decline index and initial decline rate, and the two rates gradually tend to be consistent with each other with the extension of production time. The concept of gas field exploitation intensity was introduced to eliminate the fluctuations in production decline rate caused by downstream gas consumption changes. A new method of production/productivity prediction was proposed. Specifically, an exponential decline model is used at the early stage of decline, and a harmonic decline model is used at the mid to late stage of decline; then, the average of the two model results is taken as the lower limit, and the result obtained from the harmonic decline model as the upper limit. The research results are of great significance to accurately analyze the decline behaviors of gas fields and scientifically formulate development plans. Table and Figures | Reference | Related Articles | Metrics

Select

Quantitative Characterization of Fractures and Vugs in Carbonate Rocks Based on Rock Surface Resistivity Measurements LI Mengfan, TANG Jun, ZHENG Chenchang, DU Guohao, WANG Caiwei Xinjiang Petroleum Geology    2025, 46 (5): 614-621.   DOI: 10.7657/XJPG20250512 Abstract （260）   HTML （5）    PDF（pc） （8629KB）（89）       Knowledge map    Save The significant heterogeneity of the carbonate reservoirs in the Sinian Dengying formation in the Sichuan Basin poses substantial challenges to interpretation of microresistivity scanning image logging for the fractured-vuggy reservoirs. To enhance the accuracy of imaging logging in evaluating fractured-vuggy carbonate reservoirs, a core surface electric field measurement device was customized based on AutoScan-Ⅱ core planar resistivity scanning experiments. Using this device, experiments on rock surface resistivity measurement and imaging were conducted to quantitatively analyze the imaging response characteristics of vugs and fractures. A calibration method for fracture-vug parameters based on rock surface resistivity distribution was established. The results show that the computed vug diameter and plane porosity increase linearly as the core-measured vug diameter and plane porosity increase, and the computed fracture width and the surface fracture ratio increase logarithmically as the core-measured fracture width and surface fracture ratio increase. The laboratory-based rock surface resistivity experiments effectively reduce the discrepancies between core measurements and imaging logging calculations, enabling precise calibration and quantitative evaluation of plane porosity of fractures and vugs. This study provides a methodological framework for improving the reliability and accuracy of imaging logging in evaluating fractured-vuggy reservoirs, and offers technical support for the evaluation and development of carbonate reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Changes in Flow Units Caused by Water Injection: A Case from Jiyuan Area of Ordos Basin HUO Ruilin, LI Airong, HOU Bindong, YIN Shuai, XIE Hongbing, LIU Meng, ZHAO Kaili Xinjiang Petroleum Geology    2025, 46 (5): 575-581.   DOI: 10.7657/XJPG20250507 Abstract （243）   HTML （3）    PDF（pc） （742KB）（88）       Knowledge map    Save Existing flow unit classification is primarily conducted under static conditions, making it difficult to reflect the dynamic changes in reservoir properties during water injection. To investigate the dynamic changes in reservoir flow units during water injection for optimizing the dynamic detection and development plans, this study takes the Yan-81 layer in the Jiyuan area of Ordos Basin as an example. The static evaluation parameter of the flow unit is defined as the flow zone index (FZI). By fitting the relationship between the cumulative water injection volume and the change in FZI (ΔFZI), the change in FZI caused by water injection is combined with the static evaluation parameter of the flow unit to form a dynamic evaluation parameter of flow units. The results show that as a standard for flow unit classification, FZI is correlated with the results of injection profile tests. Using FZI as the static evaluation parameter, the flow units are classified into three types (i.e. Ⅰ, Ⅱ, Ⅲ). By comparing the reservoir properties at various stages, it can be seen that as water injection continues, the reservoir properties are gradually improved to facilitate fluid flow. Given the same water injection rate, the increase in FZI for Type Ⅲ flow units is significantly higher than those for Type Ⅰ and Type Ⅱ, but its increase rate is lower than those of Type Ⅰ and Type Ⅱ. Table and Figures | Reference | Related Articles | Metrics

Select

Main Factors Controlling the Enrichment and High Production of Alkaline Lacustrine Shale Oil in Fengcheng Formation, Mahu Sag, Junggar Basin ZOU Yang, CHEN Wenshun, LUO Gang, CHEN Shaorong, CHEN Fangwen, HE Wenjun, LIU Xinlong, ZHU Tao Xinjiang Petroleum Geology    2025, 46 (6): 693-702.   DOI: 10.7657/XJPG20250605 Abstract （228）   HTML （2）    PDF（pc） （8028KB）（86）       Knowledge map    Save The main factors controlling the enrichment and high production of alkaline lacustrine shale oil in the Permian Fengcheng formation in the Mahu sag of Junggar Basin remain unclear, which limits theoretical understanding and efficient development. Based on the petrological, organic geochemical and physical characteristics of the Fengcheng shale oil reservoirs, the effects of source rock and reservoir lithology on shale oil enrichment in the Fengcheng formation were analyzed. Combined with the production profiles obtained from the key wells, the influences of shale oil enrichment, fractures and formation overpressure on the production of shale oil were identified. The findings are obtained in five aspects. First, in the Fengcheng shale oil reservoirs, the free hydrocarbon content increases with the increase of total organic carbon content (TOC), and the oil saturation index increases with the burial depth, indicating that the abundance, type and maturity of organic matter are the key factors determining the enrichment of shale oil. Second, siltstone exhibits the best storage space, followed by mudstone and endogenous rock, suggesting that the reservoir lithology controls the storage space and thus affects the enrichment of shale oil. Third, the enrichment is fundamental to the high production of shale oil. The shale oil production per meter from the Fengcheng reservoirs increases with the increase of TOC and feldspar mineral content. Fourth, the relationship between fracture orientation and present-day maximum horizontal principal stress direction affects the flow and production of the shale oil. Fifth, formation overpressure plays a role in retaining porosity, increasing permeability, reducing viscosity, and enhancing production/recovery of shale oil. The study clarifies the main factors controlling the enrichment and high production of shale oil in the Fengcheng formation, providing a scientific basis for further exploration and development. Table and Figures | Reference | Related Articles | Metrics

Select

Microscopic Occurrence and Production Dynamics of Shale Oil in Lucaogou Formation, Jimsar Sag, Junggar Basin LIU Jin, BAI Lei, ZHANG Baozhen, WEI Chao, LEI Haiyan, DENG Yuan, CAO Jian Xinjiang Petroleum Geology    2025, 46 (6): 684-692.   DOI: 10.7657/XJPG20250604 Abstract （220）   HTML （3）    PDF（pc） （11169KB）（83）       Knowledge map    Save Complex microscopic occurrence and unclear production dynamics of shale oil in continental saline lacustrine basins challenge the study of shale oil enrichment theory and development law. Taking the Lucaogou formation in the Jimsar sag of Junggar Basin as an example, this paper characterizes the fluid occurrence state and mobility in the shale reservoirs using the techniques such as nuclear magnetic resonance, confocal laser scanning microscopy, argon ion polishing, and scanning electron microscopy, and validates against the monitoring results of produced fluid from individual wells in the pilot test area. The results show that the microscopic occurrence of the shale oil is characterized by oil fully saturating nanopores and both oil and water coexisting in sub-micron to micron-sized pores, with light and heavy components in hydrocarbons arranged in an onionskin pattern. The natural depletion of shale oil prefers the light hydrocarbon components stored in sub-micron to micron-sized pores, where free water is involved in the fluid flow. Changes in crude oil properties and produced water during well production represent effective responses to the microscopic fluid occurrence state. Shale oil well production is featured with by long-term water production and sequential producing of light and heavy components. Table and Figures | Reference | Related Articles | Metrics

Select

Hydrocarbon Generation Simulation Experiments on Source Rocks of Different Organic Facies in Permian Fengcheng and Lucaogou Formations, Junggar Basin LIU Xiangjun, WANG Jian, RAN Yang, BAI Haifeng, LI Erting, MA Wanyun, CAO Jian, ZHOU Ni, ZHANG Yu Xinjiang Petroleum Geology    2026, 47 (2): 137-145.   DOI: 10.7657/XJPG20260202 Abstract （152）   HTML （9）    PDF（pc） （26996KB）（82）       Knowledge map    Save There are two sets of high-quality source rocks, namely the alkaline lacustrine Fengcheng formation and the saline lacustrine Lucaogou formation, in the Permian of the Junggar Basin. Due to different sedimentary environments, the two sets of source rocks show distinct hydrocarbon-generating parent materials. The hydrocarbon generation characteristics have not been correlated systematically for source rocks of different organic facies, and the gas generation capacity of lacustrine source rocks under oil expulsion conditions has not been investigated. Through the analysis on organic petrology and biomarkers of source rocks, hydrocarbon-generating parent materials such as Dunaliella-like algae, Cyanobacteria, and benthic macroalgae were found in the Fengcheng formation source rocks, and a large amount of Tasmanites were discovered in the Lucaogou formation source rocks. Combined with semi-closed thermal simulation experiments on source rocks and closed thermal simulation experiments on crude oil, it is indicated that source rocks of different organic facies are varying in hydrocarbon generation evolution patterns. Specifically, the Dunaliella-like algae source rocks are characterized by large oil yield, long oil generation window, and delayed oil generation peak, corresponding to the vitrinite reflectance (Ro) at the peak of oil generation up to 1.31%, the maximum oil yield of 836.3 mg/g, and the maximum gas yield of residual organic matter up to 312.0 mg/g. The Dunaliella-like algae + Cyanobacteria source rocks incorporate the hydrocarbon generation characteristics of both Dunaliella-like algae source rocks and Cyanobacteria source rocks, with long oil generation window, corresponding to the Ro at the peak of oil generation up to 1.15% and the maximum gas yield of residual organic matter up to 217.3 mg/g. The Cyanobacteria + benthic macroalgae source rocks exhibit early oil generation and low oil yield, corresponding to the Ro at the peak of oil generation up to 0.91% and the maximum gas yield of residual organic matter up to 292.9 mg/g. The Tasmanian algae source rocks demonstrate large oil yield and high gas-to-oil ratio (GOR), corresponding to the Ro at the peak of oil generation up to 1.09%, the maximum oil yield of 756.1 mg/g and the maximum gas yield of residual organic matter up to 330.2 mg/g. For the Fengcheng formation sapropelic source rocks, the gas yield is close to that of humic source rocks in the Junggar Basin when the Ro is 1.50%, and it increases continuously with increasing thermal maturity, indicating that the sapropelic source rocks of the Fengcheng formation still have strong gas generation capacity and gas exploration potential after oil expulsion. Table and Figures | Reference | Related Articles | Metrics

Select

Development Progress and Key Technologies for Cost-Effective Productivity of Shale Oil in Junggar Basin WEI Zhaosheng, QI Hongyan, ZHAO Jianfei, HE Jixiang, LIU Kecheng, WANG Junchao Xinjiang Petroleum Geology    2025, 46 (6): 703-711.   DOI: 10.7657/XJPG20250606 Abstract （252）   HTML （6）    PDF（pc） （1936KB）（80）       Knowledge map    Save The Junggar Basin holds abundant mixed shale oil, with total resources of 34.9×108 t booked, which is the main strategic target for Xinjiang oilfield to achieve additional reserves and production. However, the strong heterogeneity of mixed shale oil reservoirs makes sweet spot identification and evaluation challenging, limits the promotion of available technology system, and threatens the large-scale and cost-effective development. The enrichment patterns and reservoir characteristics of shale oil in the Junggar Basin, and the corresponding engineering processes/technologies are systematically analyzed in this paper. The technologies formed during the exploration and development of mixed shale oil are summarized, mainly with respect to sweet spot identification, supporting engineering, and development deployment. The differential enrichment theory of mixed shale oil is constructed, and a cost-effective shale oil productivity model integrating sweet spot identification, three-dimensional deployment, excellent fast drilling and completion, efficient fracturing, and environmental protection is established. These achievements support the construction of the first national demonstration zone for continental shale oil in China, and guide the efficient exploration and development of continental shale oil in the country. Table and Figures | Reference | Related Articles | Metrics

Select

Collaborative Optimization of Well Pattern-Fracture Network Based on Geology-Engineering Integration Simulation：A Case Study of Shale Oil in the Jimsar Sag, Junggar Basin LI Yingyan, DING Yi, LUO Gang, DING Huaiyu, TANG Huiying, HE Ge Xinjiang Petroleum Geology    2025, 46 (6): 742-753.   DOI: 10.7657/XJPG20250610 Abstract （201）   HTML （6）    PDF（pc） （8566KB）（80）       Knowledge map    Save The Jimsar Shale Oil Demonstration Area in the Junggar Basin, one of the first national continental shale oil demonstration areas in China, has entered the stage of large-scale production. Due to geographical constraints, the well placement optimization and design are indefinite. A reliable geological model is established based on the geology-engineering integration and deviation of well azimuth and operation parameters are optimized through numerical simulation. The results indicate that the platform exhibits characteristics of normal-fault stress, with the minimum horizontal principal stress of 62-72 MPa. The simulated hydraulic fracture length is about 85% of the microseismic monitoring results, and the simulated hydraulic fracture height is similar to the wellbore temperature monitoring results. As the angle between the well azimuth and the maximum horizontal principal stress direction decreases, the hydraulic fracture length increases, while the stimulated reservoir volume (SRV) decreases. Some hydraulic fractures in adjacent sections merge at the part where natural fractures are present, and the proportion of repeated stimulation and degree of heterogeneity of such fractures increase. This suggests that for wells with small angle, the fracturing section length can be extended or the number of clusters in a single section be reduced properly. It is recommended that the optimal well spacing be 200-300 m when the deviation of well azimuth does not exceed 60°, and the optimal well spacing be decreased to maintain a high oil recovery when the well azimuth deviates greater than 60°. Table and Figures | Reference | Related Articles | Metrics

Select

Genesis of Pyroclastic-Rich Sandy Conglomerate Reservoirs in the Lower-Middle Permian of Mahu-Shawan Sags LYU Houkuan, ZHANG Lei, AN Zhiyuan, KUANG Hao, DOU Fangpeng, LI Cun, PAN Lang Xinjiang Petroleum Geology    2026, 47 (1): 20-30.   DOI: 10.7657/XJPG20260103 Abstract （141）   HTML （3）    PDF（pc） （25850KB）（78）       Knowledge map    Save The genetic differences of zeolite cements lead to diverse pore space types, complex composition, and strong heterogeneity of reservoirs. To investigate their impacts on reservoir space, this study systematically compares and analyzes the types and formation mechanisms of zeolite cements, and reservoir space in the Lower-Middle Permian strata of the Mahu and Shawan sags by integrating macroscopic and microscopic approaches such as core observation, thin-section analysis, scanning electron microscopy (SEM), whole-rock X-ray diffraction (XRD), and energy-dispersive spectroscopy (EDS). The results indicate that variations in detrital composition control the types and genesis of zeolite cements: the zeolite cements in the Fengcheng and Xiazijie formations of the Mahu and Shawan sags were originated from the hydration of volcanic glass in tuff, while the zeolite cements in the Jiamuhe formation of the Zhongguai and Chepaizi bulges from the albitization of plagioclase. These genetic differences resulted in distinct reservoir space: in the Fengcheng and Xiazijie formations of the Mahu and Shawan sags, the evolution of zeolite cements involved changes in cement density and release of crystalline water, facilitating the creation of grain-edge fractures; while in the Jiamuhe formation of the Zhongguai and Chepaizi bulges, the dissolution of laumontite and calcite resulted in reservoir space dominated by dissolution pores. Table and Figures | Reference | Related Articles | Metrics

Select

Pore Genesis and Diagenetic Evolution of Shale Oil Sweet Spot Reservoirs in Lucaogou Formation, Jimsar Sag MAO Xinjun, WANG Ran, ZHENG Menglin, LI Jing, PAN Jin, WANG Tao, HUANG Liliang, CHANG Qiusheng Xinjiang Petroleum Geology    2025, 46 (6): 659-667.   DOI: 10.7657/XJPG20250602 Abstract （198）   HTML （8）    PDF（pc） （13501KB）（75）       Knowledge map    Save The shale oil sweet spot reservoirs of the Permian Lucaogou formation in the Jimsar sag of Junggar Basin are characterized by complex lithology and greatly varying physical properties, and diagenesis has played an important role in the pore evolution of these reservoirs. Using rock slice, cast thin section, scanning electron microscopy (SEM) and X-ray diffraction (XRD), this paper studies the microscopic characteristics of the pores in the reservoirs to reveal pore genesis, and variations and controlling factors of reservoir physical properties. The results indicate two types of reservoirs, i.e. sandstone reservoir and dolomite reservoir are developed in the sweet spots of Lucaogou formation in the Jimsar sag. Both reservoirs are dominated by secondary pores such as intergranular dissolution pores, intragranular dissolution pores, moldic pores and dissolution fractures, and contain the macropores with diameter >50 μm accounting for more than 50%. The sandstone reservoir and dolomite reservoir have similar physical properties, belonging to medium porosity and low-ultra-low permeability reservoirs. The average porosity and permeability of the sandstone reservoir are 13.51% and 0.81mD, respectively. The dolomite reservoir exhibits an average porosity of 12.86% and an average permeability of 2.38 mD. Both reservoirs have undergone compaction, weathering/leaching dissolution, cementation, and organic acid dissolution, and are in phase A of the middle diagenetic stage. The weathering/leaching dissolution in the epidiagenetic stage accelerated the formation of large pores like capillary pores and supercapillary pores, which are the main contributors to reservoir space. The dissolution of organic acid in the middle diagenetic stage promoted the formation of nanoscale microcapillary pores, which exerted a limited improvement on reservoir physical properties. Table and Figures | Reference | Related Articles | Metrics

Select

Prediction of Favorable Shale Oil and Gas Zones in the Lianggaoshan Formation of the Nanya Syncline, Eastern Sichuan Basin ZHAO Hu, YU Huan, DAI Jingyun, FENG Chenming, ZHAO Rongrong, CHEN Wei, HE Changlong, AN Hongyi Xinjiang Petroleum Geology    2026, 47 (3): 262-269.   DOI: 10.7657/XJPG20260302 Abstract （149）   HTML （10）    PDF（pc） （5583KB）（75）       Knowledge map    Save The Lower Jurassic Lianggaoshan formation in the eastern Sichuan Basin is widely developed with lacustrine shale, and multiple wells in the region have revealed good shale oil and gas shows in this formation. However, challenges remain for the resource development due to unclear spatial distribution of shale hydrocarbons, poorly defined enrichment conditions, and difficulties in identifying favorable zones. In this study, a seismic identification template for shale reservoirs in the Lianggaoshan formation was established through forward modeling. By integrating paleo-geomorphological evolution characteristics with multi-attribute seismic analysis, a workflow for shale identification and favorable zone prediction was developed for the structurally complex Nanya syncline. This provides a comprehensive approach for refined favorable zone characterization under multi-factor coupling. The results indicate that the shale reservoirs in the Lianggaoshan formation are mainly found at the top of the first member (or Liang-1 member), showing a broad spatial distribution, especially in paleo-depression zones. The favorable shale oil and gas zones at the top of Liang-1 member reflect seismic anomalies, with single-layer shale thickness of 5.0-15.0 m, total organic carbon content (TOC) of 1.1%-2.0%, and porosity of 3.0%-5.0%. The northeastern and southern parts of the study area are identified as favorable shale oil and gas zones, including Class I zones (49 km2) and Class II zones (186 km2). Table and Figures | Reference | Related Articles | Metrics

Select

Characteristics of Milankovitch Cycle of Lower Jurassic Quse Formation in Biluocuo Area, Southern Qiangtang Depression LIU Baosong, XIE Yuan, SONG Chunyan, FU Xiaodong, WEI Yunxiao, CHEN Wantao, HU Chuang, YANG Xuan, XIONG Shaoyun Xinjiang Petroleum Geology    2026, 47 (3): 253-261.   DOI: 10.7657/XJPG20260301 Abstract （140）   HTML （13）    PDF（pc） （2599KB）（73）       Knowledge map    Save The southern Qiangtang depression of the Qiangtang Basin, located in the eastern Tethys domain, has a great potential of oil and gas resources, but it has been insufficiently explored, with limited information about astronomical cycles. Cyclostratigraphy, based on the Milankovitch theory, explains the driving forces of periodic changes in astronomical orbits by extracting stratigraphic response information related to Earth’s orbital parameters from well logging curves, providing a reliable geological basis for the isochronous division and correlation of high-frequency sedimentary cycles. Using the natural gamma ray (GR) logging data from a well in the Biluocuo area of the southern Qiangtang depression, a cyclostratigraphic study was conducted on the Lower Jurassic Quse formation in this well according to the Milankovitch theory. The results show that the Quse formation exhibits significant Milankovitch cycle signals. Multiple astronomical cycles such as 405 kyr, 128 kyr, 43 kyr, and 21 kyr were identified in the Quse formation within the study area. Long and short eccentricity cycles correspond to fourth-order and fifth-order sequences, respectively. A total of 5 fourth-order sequences and 19 fifth-order sequences were identified. Accordingly, high-precision stratigraphic division and correlation were completed, and a high-frequency sequence stratigraphic framework was established for the study area. The optimal sedimentation rate was estimated to be 8.2 cm/kyr using the correlation coefficient method. Combined with trend analysis of total organic carbon (TOC) content, it is inferred that under paleoclimatic conditions controlled by astronomical cycles, there is a close relationship between TOC and astronomical cycles. Long eccentricity is a key factor controlling climate evolution and organic matter accumulation, while short eccentricity plays a local regulatory role. The research insights provide a scientific basis for future deep-time and deep-earth oil and gas exploration. Table and Figures | Reference | Related Articles | Metrics

Select

Applicability of Ball-and-Stick Model in Reservoir Pore Network Simulation DAI Jinyou, LEI Xizhen, SHEN Xiaoshu, SHI Yangyang, ZHOU Xiaofeng, ZHANG Lijuan Xinjiang Petroleum Geology    2025, 46 (5): 630-636.   DOI: 10.7657/XJPG20250514 Abstract （239）   HTML （2）    PDF（pc） （940KB）（73）       Knowledge map    Save Ball-and-stick model is widely employed in simulating pore network within reservoirs. However, given a broad range of pore scales and diversity of structural types in reservoirs, whether this model is universally applicable remains inadequately validated. Constant-rate mercury intrusion (CRMI) is one of the key methods for studying pore-throat structures. By employing the configuration theory and analytic hierarchy process (AHP), the configurations of CRMI curves were classified, the corresponding hierarchical architectures of reservoir pore systems were interpreted, and the applicability of ball-and-stick model in reservoir pore network simulation was examined. The results indicate that CRMI curves can be divided into Configuration A and B regions, corresponding to micron-scale pores and nano-scale pores, respectively. In Configuration A region, as the mercury injection pressure increases, the mercury injection saturation in pore network, pores, and throats rises monotonically, indicating a binary pore-throat structure in the micron-scale pores, with a pore/throat ratio higher than 1. Here, the ball-and-stick model is applicable. In Configuration B region, as the mercury injection pressure increases, the mercury injection saturation in pore network and throats increases monotonically, while the mercury injection saturation in pores remains constant. This suggests that nano-scale pores have no binary pore-throat structure, and are dominated by throats, with a pore/throat ratio of 1. In this region, the ball-and-stick model is inapplicable, while a capillary tube model is more suitable. The ball-and-stick model and capillary tube model can be combined to fully simulate reservoir pore networks. The poorer the reservoir physical properties, the more applicable the capillary tube model for pore network simulation. Table and Figures | Reference | Related Articles | Metrics

Select

Logging-Based Evaluation of Key Parameters of Shale Oil Reservoirs in Fengcheng Formation, Mahu Sag MAO Rui, WEI Jiamin, WANG Pan, LI Qingqing, ZHAO Lei Xinjiang Petroleum Geology    2025, 46 (6): 779-789.   DOI: 10.7657/XJPG20250614 Abstract （188）   HTML （2）    PDF（pc） （5731KB）（70）       Knowledge map    Save Based on the high-precision petrophysical experiments and the data acquired by new logging techniques, a logging-based characterization was conducted on three key parameters (lithofacies, effective porosity, and movable oil porosity) of shale oil reservoirs in the Fengcheng formation of Mahu sag, Junggar Basin. The following results are obtained. First, according to the core characteristics, FMI images, pore types, and mineral contents, the Fengcheng shale oil reservoirs are divided into felsic, dolomitic/calcareous, and clayey mixed lithofacies. The diamictite index and micro-pore index are constructed to identify lithofacies. Second, a tight reservoir analysis (TRA) experiment is performed to measure porosity of rock samples, confirming that the felsic lithofacies presents the best physical properties. Using TRA experiment results to calibrate the NMR logging data, an effective porosity characterization model with variable T2 cutoff of different lithofacies is established. Third, through comparison of multi-state T1-T2 NMR experiments, and considering the NMR logging responses, the positions of movable oil, bound oil, capillary bound water, asphalt and clay bound water of three lithofacies are revealed, and the shale oil occurrence identification chart is formed. According to the characterization results of lithofacies, effective porosity and movable oil porosity, together with the fluid production profiles of key wells, it is clarified that the interbedding of felsic lithofacies and clayey mixed lithofacies forms a favorable lithofacies combination in the Fengcheng formation. The research provides technical support for the experimental analysis of other continental shale oil reservoirs in China, and contributes a reference for shale oil reservoir evaluation. Table and Figures | Reference | Related Articles | Metrics

Select

Water Production Patterns of Fault-Fracture Gas Reservoir in Xu-2 Member in Western Sichuan Depression XU Zhongyi, GUO Yandong, BI Youyi, ZHAO Xiangyuan, SHI Haitao, LIU Lu, MI Lidong Xinjiang Petroleum Geology    2025, 46 (5): 567-574.   DOI: 10.7657/XJPG20250506 Abstract （276）   HTML （7）    PDF（pc） （2018KB）（69）       Knowledge map    Save In the western Sichuan depression of Sichuan Basin, the gas reservoir in the second member of Xujiahe formation (Xu-2 member) is a typical fault-fracture tight sandstone gas reservoir. Natural fractures are well developed in the reservoir, with a strong connectivity. The gas wells initially produce at high rates, but cannot maintain stable yield due to water invasion. To identify the causes of water production and determine the water invasion pathway, scale, and timing, gas wells were classified depending on their dynamic characteristics such as production rate and pressure. By analyzing the distribution of gas and water and the fracture characteristics of the reservoir, water invasion patterns were identified, and a numerical simulation model which can reflect these patterns was established. Based on the results of the numerical simulation, criteria for determining water invasion patterns were established, and the simulation results were verified using water analysis data from gas wells. Table and Figures | Reference | Related Articles | Metrics

Select

Development Characteristics and Controlling Factors of Paleozoic Tight Sandstone Reservoirs in Xunyi Area, Ordos Basin ZHU Yan Xinjiang Petroleum Geology    2026, 47 (2): 146-154.   DOI: 10.7657/XJPG20260203 Abstract （119）   HTML （7）    PDF（pc） （11045KB）（65）       Knowledge map    Save The reservoirs of the Paleozoic Shihezi-Taiyuan formation in the Xunyi area of the Ordos Basin are tight sandstone reservoirs featured with strong diagenesis, low porosity, low permeability, and strong heterogeneity. In this paper, through analyses of rock thin sections, cast thin sections, whole rock X-ray diffraction (XRD), scanning electron microscopy (SEM), and petrophysical properties, the Shihezi-Taiyuan formation reservoirs were systematically investigated for their development characteristics, differential evolution of components/structures during diagenesis, and controlling factors. The Shihezi-Taiyuan formation reservoirs in the Xunyi area are divided into three types: highly-plastic lithic sandstone, quartz-rich and lowly-plastic lithic sandstone, and quartz sandstone + lithic quartz sandstone. The reservoirs of Shihezi, Shanxi and Taiyuan formations exhibit an average porosity of 5.67%, 2.79% and 5.64%, and an average permeability of 1.37 mD, 0.30 mD and 0.27 mD, respectively. The pore types are mainly intergranular dissolved pores and intragranular dissolved pores, followed by primary intergranular pores and clay mineral intercrystalline pores. The interstitial materials are represented by authigenic clay minerals, as well as authigenic quartz and calcite. The research results indicate that the source for the sweet spot was mainly supplied from the southwest provenance of the study area. The dissolution of reservoirs from the Middle Jurassic to the Late Cretaceous resulted in the extensive development of secondary pores, which is a primary controlling factor of the sweet spot reservoir in Shihezi-Taiyuan formation. The reservoir protection and improvement resulted from clay minerals is a secondary factor, and it is mainly manifested by the protection of the primary pores in the reservoir by the authigenic chlorite film in the Shihezi formation, and the improvement of reservoir porosity and permeability by the intercrystalline pores formed during the transformation from smectite to illite in the mixed layer in the Shanxi formation and Taiyuan formation. Table and Figures | Reference | Related Articles | Metrics

Select

Main Controlling Factors of Tilted Oil-Water Contact of Shallow Heavy Oil Reservoirs of Qigu Formation in Block HQ1，Karamay Oilfield YAN Yonghe, LI Haibo, ZHU Aiguo, ZHANG Wuji, ZHANG Jing, LIU Gang, CHEN Yanhui, WANG Biao Xinjiang Petroleum Geology    2025, 46 (5): 582-590.   DOI: 10.7657/XJPG20250508 Abstract （280）   HTML （9）    PDF（pc） （1025KB）（64）       Knowledge map    Save In order to determine the oil-water relationship and its controlling factors in the shallow heavy oil reservoirs of the Qigu formation in Block HQ1, Karamay oilfield, the study focuses on the h-4 well area, which exhibits significant oil-water distribution complexities at the reservoir margins. Using the data of dense well pattern and test analysis, the influences of sand body distribution, hydrodynamic conditions, reservoir properties, hydrocarbon charging pressure, and tectonic activities on the oil-water contact (OWC) are identified. The h-4 well area demonstrates distinctive OWC characteristics, where the water boundary is parallel with the structural line in the east, and the water boundary obliquely intersects the structural line in the west, resulting in a tilted OWC. This tilted OWC is believed to have been resulted from the periodical fracture opening due to tectonic activities and the OWC adjustment hysteresis is caused by oil viscosity variation, indicating a coupled mechanism of tectonism and unsteady reservoir formation. The fracture opening in the western part of the study area provided oil migration pathways, facilitating oil accumulation in the Qigu formation. Subsequent fracture sealing and reactivation events led to reservoir compartmentalization, creating a OWC that is high in west and low in east. Oil biodegradation shaped a similar viscosity feature. The combined effects of tectonic activities and viscosity variations significantly retard horizontal adjustments of OWC, characterizing the reservoir as a unsteady hydrocarbon accumulation system. Table and Figures | Reference | Related Articles | Metrics

Select

Acoustic Anisotropy Correction Based on Clay Mineral Content in Shale Oil Horizontal Wells LI Yanghu, WANG Zhenlin, SHAO Huanhuan, CHEN Shanhe, TANG Fukang, LIU Caiguang, WANG Wei, ZHANG Hao Xinjiang Petroleum Geology    2025, 46 (6): 790-799.   DOI: 10.7657/XJPG20250615 Abstract （176）   HTML （0）    PDF（pc） （4408KB）（63）       Knowledge map    Save Horizontal wells are widely used in the development of shale oil reservoirs. Due to the presence of thin interlayers in and significant anisotropy of the reservoir, there is an obvious difference between the acoustic slowness measured in horizontal wells and that measured in vertical wells, which seriously affects the interpretation accuracy of horizontal wells. In this paper, the four-component rotation technique is applied to process dipole array acoustic data for correcting shear-wave anisotropy. The slow shear-wave slowness obtained by this method is difficult to be accurately extracted due to serious dispersion effect. To solve this problem, a functional relationship between shear-wave anisotropy ratio and clay mineral content is established through analyzing horizontal well logging data of typical shale oil reservoirs in different basins, and a transformation relationship between the anisotropy ratios of compressional wave and shear wave is defined by using the core experimental data of these reservoirs. In practical processing, the anisotropy ratios of compressional- and shear-waves are obtained based on the clay mineral content. By combining the fast compressional-wave and shear-wave slowness values extracted from the acoustic logging data, the measured acoustic anisotropy of horizontal well is corrected. This correction method has been used to the actual horizontal well measurements in different basins, suggesting that the corrected acoustic slowness well agrees with the measured value of adjacent vertical well. The porosity calculated by the corrected acoustic slowness is basically consistent with the porosity calculated from the density logging. The results indicate that the proposed correction method is effective, and the corrected acoustic slowness can be used for calculating reservoir and engineering evaluation parameters for shale oil. Table and Figures | Reference | Related Articles | Metrics

Select

Unbalanced Fracture Propagation Mechanism During Horizontal Well Intensive Fracturing in Shale Oil Reservoirs QI Hongyan, WANG Zhenlin, ZHENG Guoqing, YU Peirong, YANG Wangwang Xinjiang Petroleum Geology    2025, 46 (6): 734-741.   DOI: 10.7657/XJPG20250609 Abstract （201）   HTML （1）    PDF（pc） （5787KB）（63）       Knowledge map    Save In light of the geological characteristics of continental shale oil reservoirs，a numerical model for unbalanced fracture propagation during horizontal well intensive fracturing was constructed using the cohesive zone method to study the effects of cluster spacing and lamina on unbalanced propagation of multiple fractures and then elucidate the mechanism of unbalanced fracture propagation during horizontal well intensive fracturing. True triaxial physical simulation experiment was conducted on samples taken from the field outcrop of shale oil reservoirs to investigate the mechanical behaviors of multi-fracture initiation and cross-interface propagation and thereby reveal the mechanism of mechanical interaction between fractures and lamina during intensive fracturing. Comprehensive analysis indicates that the development degree of lamina in shale oil reservoirs is the key determinant of the complexity of fracture network. Increasing cluster spacing effectively enhances the connectivity of the lamina and interfaces. The difference in propagation rate among fracture clusters decreases with the increase of cluster spacing，and the central fractures are more prominently affected by stress interference when cluster spacing is small. The multiple-clustered fractures exhibit a mutually complementary propagation pattern. Reasonably controlling cluster spacing can improve the vertical extension of fractures，thereby expanding the coverage of fracture system and enhancing the fracturing efficiency in shale oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Influences of Paleo-Sedimentary Environment on Shale Oil Sweet Spots in the Fengcheng Formation, Mahu Sag, Junggar Basin CHEN Shaorong, ZHAO Yi, ZOU Yang, REN Haijiao, CHEN Fangwen, WU Junjun Xinjiang Petroleum Geology    2026, 47 (1): 46-56.   DOI: 10.7657/XJPG20260105 Abstract （150）   HTML （8）    PDF（pc） （5511KB）（60）       Knowledge map    Save The paleo-sedimentary environment of the Permian Fengcheng formation in the Mahu sag of the Junggar Basin controlled the development of shale oil sweet spots. However, such controlling mechanism in alkaline lake environment is unclear, which restricts the efficient exploration and development for shale oil. Based on the core, geochemical and logging data of the Fengcheng formation in Well MY1, the paleo-sedimentary environment parameters (e.g. paleo-water depth, paleo-climate, paleo-salinity, and paleo-redox conditions) of different qualities of source rocks, reservoirs, and source-reservoir assemblages were analyzed, and the influences of paleo-sedimentary environment on the development of shale oil sweet spots were dissected. The results show that the Class Ⅰ high quality source-reservoir assemblages of the Fengcheng formation in Well MY1 were formed in the saltwater environment with a relatively small range of paleo-water depth, relatively warm and humid paleo-climate, relatively high contents of carbonate and terrigenous clastic sediments, and relatively low paleo-salinity, and also in the environment with stronger paleo-reduction condition. An appropriate sedimentary environment provides a possibility for the flocculation and enrichment of algae organic matters featuring a high hydrocarbon yield, promotes the formation of primary productivity, and contributes organic matter preservation conditions, allowing for extensive hydrocarbon generation from organic matters with relatively low maturity. The interlayered, laminar, and pure shale-type source-reservoir assemblages respectively correspond to the Class Ⅰ, Class Ⅱ and Class Ⅲ source-reservoir assemblages in a descending order of oil expulsion efficiency. It is determined that the paleo-sedimentary environment controls the development of shale oil sweet spots in the Fengcheng formation through a three-factor (source-storage-preservation) mechanism. This research insight provides a theoretical support for shale oil exploration. Table and Figures | Reference | Related Articles | Metrics

Select

Xinjiang Petroleum Geology    2026, 47 (2): 0-0.   Abstract （52）      PDF（pc） （108176KB）（58）       Knowledge map    Save Related Articles | Metrics

Select

Xinjiang Petroleum Geology    2026, 47 (3): 0-0.   Abstract （88）      PDF（pc） （47228KB）（58）       Knowledge map    Save Related Articles | Metrics

Select

Potential of Replacement Areas for Shale Oil Development in the Lucaogou Formation, Jimsar Sag LI Qing, LUO Gang, LI Yingyan, DENG Yuan, XIAO Dianshi, XIE Xiaoquan Xinjiang Petroleum Geology    2025, 46 (6): 712-722.   DOI: 10.7657/XJPG20250607 Abstract （183）   HTML （2）    PDF（pc） （6045KB）（57）       Knowledge map    Save In the Jimsar sag, the replacement areas for shale oil development in the Lucaogou formation contain abundant resources, but exhibit small reservoir thickness and heterogeneous sweet spot distribution. Through experimental tests involving organic geochemistry, petrology, pore structure, and hydrocarbon occurrence/mobility, a comprehensive evaluation was conducted on the source rock, crude oil property, reservoir lithology, pore type, and shale oil occurrence/mobility in the replacement areas. The results show that the replacement areas have favorable source rock conditions, and have generally experienced two oil-generating peaks, with significantly lower crude oil density and viscosity and a higher proportion of light components, as compared with the primary zones. The reservoirs in the replacement areas are characterized by small thickness and fine grain size, with underdeveloped intergranular pores but relatively developed dissolution pores and intercrystalline pores, demonstrating a similar pore size range to the primary zones but smaller pore-throat radii than the latter. Both the replacement areas and primary zones hold oil in multiple types of pores, with similar shale oil occurrence patterns. The lower limit of pore size for free hydrocarbon occurrence in the replacement areas is 40-60 nm, which is smaller than that in the primary zones. Crude oil viscosity has a significant control effect on shale oil mobility. Under low viscosity conditions, the crude oil in the replacement areas is highly mobile, with a smaller cutoff than the primary zones according to the nuclear magnetic resonance (NMR) mobility interpretation. The movable oil quantity, oil saturation, pore pressure, and brittleness are the key factors affecting the productivity of the replacement areas. Based on these research insights, a sweet spot evaluation technique combining the weights of these four factors was reconstructed, revealing an accuracy of sweet spot identification in the replacement areas exceeding 80%. The research results provide theoretical support for the stable production of shale oil in the Lucaogou formation. Table and Figures | Reference | Related Articles | Metrics

Select

Genesis and Engineering Complexity Risk Assessment of Strike-Slip Faults in Lucaogou Formation, Jimsar Sag, Junggar Basin TANG Tingming, WANG Qun, YAO Juqin, CAO Yang, LIN Jiaying, CHEN Gang, ZHANG Hao, LI Wei Xinjiang Petroleum Geology    2026, 47 (3): 270-278.   DOI: 10.7657/XJPG20260303 Abstract （129）   HTML （8）    PDF（pc） （10964KB）（56）       Knowledge map    Save The Permian Lucaogou formation in the Jimsar sag of the Junggar Basin is rich in shale oil/gas resources. Horizontal well + staged fracturing is the main technique for shale oil/gas development, reserves increase, and production enhancement. During the development of horizontal wells, due to the presence of strike-slip faults, engineering complexity problems such as casing deformation, fracture interference, and lost circulation occur frequently, which seriously restrict the shale oil development progress and effect in the Jimsar sag. Considering the regional tectonic setting, this paper discusses and verifies genesis of the strike-slip faults, i.e. multi-stage compression and shear strike-slip, from three perspectives including paleotectonic stress, current stress environment, and physical simulation experiment. It highlights the development characteristics of strike-slip faults, and innovatively adopts the fault characterization method based on fault enhancement and attribute optimization to realize the characterization of strike-slip fault distribution and the establishment of fault combination patterns in the Lucaogou formation. Based on the comprehensive analysis of fault properties and current stress field direction, it is clarified that (1) the main strike-slip faults have a small angle with the maximum horizontal principal stress, and they are easily activated by fracturing to induce casing deformation; and (2) the associated extensional fractures are open fractures, which are prone to cause problems such as lost circulation and drilling through fault points. The coincidence between casing deformation points and fault positions observed in early stage reaches 84.2%. The study results provide a basis for prevention and control of engineering complexities and effectively guide the optimization of horizontal well drilling trajectory and the design of subsequent fracturing scheme. Table and Figures | Reference | Related Articles | Metrics

Select

Numerical Simulation of Strike-Slip Fault Induced Casing Deformation and Optimization of Fracturing Scheme: A Case Study of Shale Oil in Jimsar Sag LIN Jiaying, QI Hongyan, CHANG Ting, ZHANG Yunjie, ZHANG Hao, CHEN Gang, LIANG Chenggang, WEI Xiaochen Xinjiang Petroleum Geology    2025, 46 (6): 754-761.   DOI: 10.7657/XJPG20250611 Abstract （252）   HTML （5）    PDF（pc） （1910KB）（55）       Knowledge map    Save The Jimsar Shale Oil Demonstration Area in Xinjiang, China’s first national-level lacustrine shale oil demonstration area, is in the middle to late stage of development. The concentrated placement of horizontal wells and large-scale fracturing have led to fracture activation, causing casing deformation and impeding the development progress. Considering that the conventional numerical simulation of casing deformation yields results with low accuracy of multiple types of faults in strike-slip fault zones, a strike-slip fault induced casing deformation model was established and then combined with engineering practices to reveal the factors controlling the casing deformation induced by strike-slip fault. The results show that the casing deformation is mainly controlled by fracture dip, applied fluid pressure, and angle between the fracture orientation and the maximum horizontal principal stress direction. For the section of casing deformation at the risk level 1, the injected liquid volume should be reduced to 65%-70% of the original level as designed, and the temporary plugging should be advanced to the time when the injected liquid volume reaches 300 m3, so that the risk of casing deformation can be effectively mitigated. The research breaks through the limitations of traditional fracturing design in the homogenization treatment of strike-slip fault zone, and provides a theoretical basis for the prevention of casing deformation and efficient development of shale oil in complex fault systems. Table and Figures | Reference | Related Articles | Metrics

Select

Application of Seismic Frequency-Increasing Method Based on Point Complex Spectrum in Shale Oil Sweet Spot Prediction, Jimsar Sag, Junggar Basin YAO Juqin, CHEN Gang, TANG Tingming, ZHAO Chunxue, LI Wei, YU Xuefeng, YU Jianglong Xinjiang Petroleum Geology    2025, 46 (6): 773-778.   DOI: 10.7657/XJPG20250613 Abstract （159）   HTML （1）    PDF（pc） （5525KB）（55）       Knowledge map    Save Deep seismic signals exhibit serious high-frequency energy attenuation, leading to lower resolution than required level in production. Conventional frequency-increasing methods primarily operate on the amplitude spectrum of seismic signals, but cannot restore original phase spectrum, resulting in signal distortion and poor lateral continuity of events. Based on the time-frequency analysis of S transform, this paper proposes a method that directly performs spectral whitening on point complex spectrum to ensure that the phase of seismic signals remains unchanged before and after point complex spectral operation, which can effectively improve seismic data resolution while preserving signal-to-noise ratio and lateral continuity of seismic events. The conventional deconvolution method, traditional spectral whitening frequency-increasing method and point complex spectrum-based frequency-increasing method were applied to the seismic data processing of the Permian Lucaogou formation in the Jimsar sag. It is found that the point complex spectrum-based frequency-increasing method is better performed than the other two methods, and it can provide high-fidelity, amplitude-preserving, high-resolution seismic data for seismic prediction of thin sweet spots. Table and Figures | Reference | Related Articles | Metrics

Select

Evaluation of Paleoweathering Characteristics of Igneous Rock Basements LIANG Fei, NIU Jun, HE Jin Xinjiang Petroleum Geology    2025, 46 (5): 637-646.   DOI: 10.7657/XJPG20250515 Abstract （253）   HTML （7）    PDF（pc） （11331KB）（54）       Knowledge map    Save Paleoweathering crusts are of significant importance for understanding the interactions between the lithosphere and the atmosphere, as well as the rock-water reactions within weathering profiles during burial diagenesis process. This study systematically analyzed petrological, mineralogical, and geochemical characteristics of various igneous rock basements, including gabbro-diorite (GA1 basement), basaltic andesite (GA1 effusive rock interval), quartz diorite (TB8 basement), and granite (BK2/05 basement). The mobility offsets of easily migrating elements such as K, Ca, and Na were quantified using the degree of migration, and the results were cross-referenced with mineral quantitative analysis data from whole-rock X-ray diffraction (XRD) and the petrological features to clarify the burial diagenetic characteristics of the paleoweathering crust in the study area. Subsequently, based on the mineral and element contents, a quantitative correction was applied to Ca content, followed by a correction for K content. The corrected results displayed a well-defined weathering trend in the A-C-K triangular chart, validating the methodology for correction. Using the corrected parameters, the chemical index of alteration (CIA) was employed to quantify the degree of chemical weathering. Additionally, corrections for the original weathering products were performed by integrating protolith characteristics and paleoclimate features, revealing the original weathering characteristics of the paleoweathering profile. Finally, after normalization using weathering indices, the corrected weathering characteristics of each profile exhibited strong correlations with the climatic evolution trends during the Early to Middle Permian. Table and Figures | Reference | Related Articles | Metrics

Select

Characteristics and Development Model of Associated Alkaline Ore in the Shale Oil Reservoirs of the Second Member of Fengcheng Formation, Mahu Sag, Junggar Basin HUANG Liliang, ZOU Yang, YANG Yongqiang, LI Guangxing, WU Junjun, JIANG Zhenxue, LIU Xinlong Xinjiang Petroleum Geology    2026, 47 (1): 11-19.   DOI: 10.7657/XJPG20260102 Abstract （171）   HTML （9）    PDF（pc） （10657KB）（52）       Knowledge map    Save The Lower Permian Fengcheng formation in the Mahu sag of the Junggar Basin hosts alkaline ore which represents an important type of solid mineral resources. The alkaline ore has been insufficiently studied with respect to genetic mechanism and sedimentary evolution process. This paper restores the spatial distribution of alkaline ore in the Fengcheng formation in the Mahu sag through detailed core description, whole-rock X-ray diffraction(XRD) analysis, rock thin section identification, scanning electron microscopy(SEM) analysis, and geochemical analysis, and considering the geophysical characteristics, and then establishes the development model of the alkaline ore. It is found that the alkaline ore in the Fengcheng formation is predominantly composed of carbonate minerals, including trona, nahcolite, northupite, eitelite, and shortite, and it was formed with the source supply by deep volcanic hydrothermal activities. The symbiotic combination of Na-carbonate minerals are constrained by formation water salinity, and the logging responses to the minerals are characterized by high CAL, high AC, high CNL, low RT, low DEN, and low GR values, with obviously opposite trends for RLLD and RLLS. The alkaline ore is distributed in both slope and depression zones, with significant differences in macroscopic occurrence states. Based on the analysis of sedimentary facies and sequence of core samples, a model of multi-source alkaline-ore development under the alternating effects of climate fluctuation and episodic volcanic activity was established. The study results provide valuable reference for the exploration and comprehensive utilization of alkaline ore in similar lake basins. Table and Figures | Reference | Related Articles | Metrics

Select

A Logging-Based Permeability Prediction Method Based on Dual-Driven Model for Low-Permeability Gas Reservoirs: A Case Study of Dongfang Gas Field in Yinggehai Basin WU Bohan, LI Fang, TANG Di, WU Yixiong, LUO Yuhu, XIAO Dazhi, ZHANG Shunchao Xinjiang Petroleum Geology    2025, 46 (5): 622-629.   DOI: 10.7657/XJPG20250513 Abstract （341）   HTML （4）    PDF（pc） （7519KB）（50）       Knowledge map    Save Offshore low-permeability reservoirs are characterized by fine lithology, poor physical property, and strong heterogeneity, making permeability prediction highly challenging. To address this issue, a regression committee learning machine (RCLM) driven by both data and physics was developed for predicting permeability based on logging data for low-permeability reservoirs. On this basis, sweet spot evaluation and dynamic permeability prediction were conducted. The results show that compared with a simple learning machine, the RCLM not only guarantees the prediction accuracy but also achieves higher prediction stability; in comparison with conventional porosity-permeability models, the RCLM obtains superior accuracy (up to 94% within half an order of magnitude). The comprehensive logging-based sweet spot index established using logging curves and petrophysical parameters can be used to effectively identify sweet spots in reservoirs. The newly drilled wells have verified the applicability of the dynamic-static permeability transformation model, which can be used to predict well test-derived permeability during regionally progressive exploration and development. The proposed method has been successfully applied in reservoir evaluation in the Dongfang gas field of the Yinggehai Basin, demonstrating its practical value. This method may provide robust support for efficiently designing exploration and development plan for offshore gas fields. Table and Figures | Reference | Related Articles | Metrics

Select

Study on Water Invasion Pathways in the Southwest Flank of Kela-2 Gas Field Based on DAS Microseismic Inversion ZHU Songbai, WANG Shengjun, LIN Na, NIE Yanbo, FAN Qiuhai, WU Weimin, WANG Jinbing, LU Jianrong Xinjiang Petroleum Geology    2026, 47 (3): 300-306.   DOI: 10.7657/XJPG20260306 Abstract （114）   HTML （17）    PDF（pc） （2061KB）（50）       Knowledge map    Save During long-term development of the Kela-2 gas field, edge/bottom water migrated along water invasion pathways toward production wells, causing a varying degree of water breakthrough in most wells, which has adversely affected the gas field development. Currently, there is a lack of effective methods for delineating water invasion pathways. To address this limitation, a numerical model of coupled gas-water two-phase flow-stress was established to simulate the coupled flow-stress field, fault deformation, and induced microseismicity during gas field development. Based on the 3D spatial distribution of observed microseismic events, the Mahalanobis distance-based objective function was constructed to align the 3D coordinates of microseismic events recorded by distributed acoustic sensing (DAS) with those generated by the numerical simulation. Then, the objective function was minimized by iteratively adjusting the initial permeability distribution of both the matrix and fractures until a convergence was achieved. Finally, the optimal permeability distribution and the coupled gas-water two-phase flow-stress field were analyzed to identify potential water invasion pathways. The results show that, in 2015, localized segments of faults F159 and F160 began activating, exhibiting an average shear-slip rate of 1 mm/a, and an average permeability of approximately 100 D. Two active aquifers exist in the southeastern and southwestern parts of the southwest flank of the Kela-2 gas field, and they spatially coincide with the activated segments of faults F159 and F160. Edge/bottom water intruded into reservoirs through these activated segments and subsequently migrated via high-permeability channels to Wells KL205, KL2-7 and KL2-8. The edge/bottom water rose vertically at a rate of 3 m/a, and migrated horizontally at a rate of 50 m/a. Three distinct water invasion pathways have been identified in the southwest flank of the Kela-2 gas field. These findings provide valuable insights for predicting the timing and extent of water breakthrough in gas wells, designing effective water management and drainage strategies, and improving overall production efficiency. Table and Figures | Reference | Related Articles | Metrics

Select

Theory and Practice of Full-Domain CO2 Flooding WEI Zhaosheng, WANG Yanjie, LI Qing, DING Chao, LUO Gang, ZHENG Sheng, CHEN Chao, LUO Qiang, ZHANG Xuyang, TAN Long, REN Xu Xinjiang Petroleum Geology    2026, 47 (1): 81-91.   DOI: 10.7657/XJPG20260109 Abstract （142）   HTML （2）    PDF（pc） （996KB）（50）       Knowledge map    Save The Xinjiang oilfield faces the challenges such as complex reservoir type, strong reservoir heterogeneity, and low recovery efficiency. Considering the requirements for petroleum industry to meet China’s “dual carbon” goals, and through literature review, laboratory experiments, integration of key technologies, and field application in typical reservoirs, this paper proposes a theory of full-domain CO2 flooding to effectively guide the significant enhancement of oil recovery through CO2 flooding in highly heterogeneous reservoirs. A coupling mechanism between displacing medium (CO2) and reservoir characteristics across three dimensions (space domain, time domain, and fluid domain) is established to maximize the mobilization of crude oil in pores and throats of varying scales. Consequently, a series of key CO2 flooding technologies featuring full-reservoir coverage, full-scale adaptation, full-cycle optimization, and full-process integration have been formed. Field applications of the full-domain CO2 flooding theory and associated technologies in the Xinjiang oilfield have demonstrated remarkable results, with the estimated recovery enhancement by over 20%. This theory provides a new idea/approach for the efficient development of various complex reservoirs in the Xinjiang oilfield, but also lays a theoretical foundation for the significant EOR in complex reservoirs across China. It is promising, industrially and economically, for application in other oilfields. Table and Figures | Reference | Related Articles | Metrics

Select

Formation Mechanism and Controlling Factors of Natural Fractures in Xujiahe Formation, Puguang Area ZU Kewei Xinjiang Petroleum Geology    2026, 47 (2): 163-171.   DOI: 10.7657/XJPG20260205 Abstract （104）   HTML （5）    PDF（pc） （10402KB）（49）       Knowledge map    Save The formation test and production test in the Xujiahe formation in the Puguang area of the Sichuan Basin are closely related to the development of natural fractures. Based on field geological outcrop, core and imaging logging data, the types and parameters of natural fractures in the Xujiahe formation in the Puguang area are statistically analyzed. Combining with regional tectonic evolution, the formation mechanism and controlling factors of the natural fractures are evaluated. The results show that the natural fractures in the Xujiahe formation are highly efficient. Two groups of effective fractures in NW-SE and NE-SW trending are developed in the formation. The NW-SE fractures are predominant, and dominated by low-angle oblique fractures with the aperture of 10-20 μm and the permeability of 10-50 mD, acting as important flow pathways in the reservoir. The natural fractures in the Xujiahe formation formed in three periods: (1) the late Yanshanian, when conjugate shear fractures were formed in nearly N-S and NW-SE trending under the action of NW-SE compression and then highly filled; (2) the early Himalayan, when a series of NE-SW natural fractures were formed under the NW-SE compression, and these fractures are effective; and (3) the late Himalayan, when conjugate shear fractures in NE-SW and nearly N-S trending were formed due to the intense NE-SW compression, associated with NW-SE structural fractures locally. The natural fractures in the Xujiahe formation are controlled by structure, lithology, sedimentary microfacies, and rock mechanical layer thickness, among which structure is the dominant factor. Table and Figures | Reference | Related Articles | Metrics

Select

NMR Effective Porosity Spectrum Prediction and Resolution Matching Based on ReliefF and LSBoost Ensemble Tree DU Xuebiao, ZHANG Jinfeng, XIAO Dianshi, RAN Yang, LIU Yingjie, QIN Jiamin, WANG Liangzhe Xinjiang Petroleum Geology    2025, 46 (6): 762-772.   DOI: 10.7657/XJPG20250612 Abstract （173）   HTML （2）    PDF（pc） （2894KB）（49）       Knowledge map    Save Nuclear magnetic resonance (NMR) logging is a critical method for obtaining the porosity of shale oil reservoirs, but the varying vertical resolutions of different logging tools severely affect the division of oil layer thickness and the characterization of sweet spots. The spectral characteristics of different NMR effective porosity curves were analyzed through the Fourier transform. With the spectral amplitudes of the logs including microspherically focused resistivity, acoustic, neutron porosity, and P-type NMR effective porosities selected using the ReliefF algorithm as the input features for the machine learning (ML) model, and the spectral amplitude of CMR-type NMR effective porosity log as the target value, a prediction model for the spectral amplitude of NMR effective porosity was constructed using decision tree (DT) and LSBoost ensemble tree. The prediction results of different ML models were compared, showing that the LSBoost ensemble tree model is the most accurate. For purpose of resolution matching among different NMR logs, the time-frequency analysis was innovatively integrated with the resolution matching to form a method for improving the resolution of NMR effective porosity log through spectral amplitude transplantation. This method has been validated to significantly enhance the resolution of low-resolution NMR effective porosity logs. The reconstructed NMR effective porosity logs are significantly superior in oil layer thickness division, fully proving that this resolution matching method is highly promising, laying a foundation for the precise characterization of sweet spot distribution and the efficient extraction of shale oil in the Permian Luocaogou formation in the Jimsar sag of the Junggar Basin. However, this method is limited when applied in strata with high pyrite content or small thickness. Table and Figures | Reference | Related Articles | Metrics

Select

Sedimentary Evolution of the Lower-Middle Jurassic Shuixigou Group in the Turpan-Hami Basin CHEN Kairui, ZHAO Junfeng, WANG Jiangbo, WANG Gang, ZHANG Peng Xinjiang Petroleum Geology    2026, 47 (1): 31-45.   DOI: 10.7657/XJPG20260104 Abstract （145）   HTML （9）    PDF（pc） （24575KB）（48）       Knowledge map    Save The Lower-Middle Jurassic Shuixigou group in the Turpan-Hami Basin develops a fluvial-deltaic-lacustrine sedimentary system as a whole. However, the basin has undergone multiple tectonic movements, and the paleogeomorphological framework during the deposition of the Shuixigou group is believed to be the main factor controlling the evolution of this sedimentary system. Based on drilling, seismic, core and outcrop data, and combined with previous research, the sedimentary evolution of the Shuixigou group was comprehensively analyzed. The study shows that the Shuixigou group is generally thick in the north and thin in the south, and many small separated depocenters from the early stage of Early Jurassic to the Middle Jurassic migrated to the Taibei sag, forming a large and unified depocenter. The paleogeomorphology and sedimentation-provenance pattern of the Shuixigou group were shaped by the tectonic uplifting of the basin-margin mountains and the main bulges in the basin. The deposition of the Shuixigou group was mainly governed by both northern and southern provenances, as well as the sediment supply from the intra-basinal bulges. The early-formed paleo-bulges in the southern part of the basin served as the primary provenance, mainly owing to the distal deltaic system. The Bogda uplift and Buerga bulge, which rose continuously during the deposition of the Shuixigou group, were secondary provenances. The frequent fluctuation of lake level is another contributor to the distribution of the Shuixigou group sedimentary system. The early stage of lake transgression (the depositional period of the Badaowan formation) and the late stage of lake regression (the early depositional period of the Xishanyao formation), when delta plain subfacies was widely distributed within the basin, are critical coal-accumulation stages. The Sangonghe formation records the maximum lake transgression during the Early-Middle Jurassic, giving rise to the high-quality lacustrine source rocks of the Lower-Middle Jurassic Shuixigou group. Table and Figures | Reference | Related Articles | Metrics

Select

Synergistic Mechanism and Displacement Efficiency of Nanomaterial-Assisted Polymer/Surfactant Flooding in High-Salinity Oil Reservoirs LIU Zheyu, FENG Yaoguo, WANG Kuibin, WANG Wenxu, GAO Wenbin, LI Yiqiang Xinjiang Petroleum Geology    2026, 47 (1): 57-63.   DOI: 10.7657/XJPG20260106 Abstract （160）   HTML （8）    PDF（pc） （10434KB）（48）       Knowledge map    Save Chemical flooding is a potential technique for enhancing oil recovery in high-salinity reservoirs. However, the high salinity impacts the viscosity of chemical system, thereby impeding the system’s effectiveness in mobility control and oil recovery improvement. This paper proposes the synergy of nanomaterials with polymer/surfactant for enhancing oil recovery in high-salinity reservoirs. The zero-dimensional nano-particle F80 and two-dimensional nano-sheet GO were compared for their effects on the viscosity and interfacial tension (IFT) of the polymer/surfactant composite system under high salinity conditions. The oil displacement mechanism of the polymer/surfactant composite system before and after the addition of nanomaterials was analyzed depending on the changes in microscopic residual oil and through core displacement experiments. It is found that F80 exhibits stronger ion-dipole interactions with cations in the formation water than GO, and it increases the viscosity of the chemical system by 1.4 times and maintains a lower oil-water IFT. In both microscopic visualization displacement and core displacement experiments, the polymer/surfactant/F80 composite system, with a high viscosity, significantly increases the flow resistance and reduces the dispersed residual oil, and enhances the oil recovery after water flooding by 20.1%, which is 5.4% higher than that of the polymer/surfactant composite system with the same mass fraction. Table and Figures | Reference | Related Articles | Metrics

Select

Characterization and Application of Original and Developed Flow Units in Tight Oil Reservoirs ZHU Rongxing, QU Hongjun, YIN Hu, SU Shuai, YANG Xiaofeng Xinjiang Petroleum Geology    2026, 47 (2): 241-252.   DOI: 10.7657/XJPG20260213 Abstract （112）   HTML （2）    PDF（pc） （4748KB）（46）       Knowledge map    Save Current research on reservoir flow units often neglects the flow unit transformation caused by development engineering factors, resulting in flow unit classification that do not match the actual development status of oilfields. To provide a flow unit classification more in line with the distribution of artificial fractures after perforation and fracturing, this paper takes the Chang 8 tight oil reservoir in the Fuxian area of the Ordos Basin as an example for investigation. Based on selected parameters (5 static parameters and 2 dynamic parameters), the Chang 8 tight oil reservoir was categorized into 4 classes of original flow units and developed flow units through cluster analysis. Combining discriminant analysis with microscopic pore structure, the classification was verified. Finally, the distribution of original and developed flow units was characterized, and the application of the flow units to reservoir development was clarified. The results show that original flow units are controlled by sedimentary microfacies, while developed flow units are controlled by engineering factors such as perforation thickness, proppant injection intensity, and water injection rate. After reservoir fracturing, the remaining oil zone gradually shifts towards lower-level flow units. Class A and B developed flow units should be developed by controlling injection pressure and optimizing perforation horizons. Re-fracturing or augmented injection should be conducted to improve development efficiency for Class C and D developed flow units. Table and Figures | Reference | Related Articles | Metrics

Select

Relationship Between Diagenesis and Hydrocarbon Accumulation in Microbial Dolomite Reservoirs of Sinian Dengying Formation in Penglai Gas Field, Central Sichuan Basin TIAN Xingwang, SUN Yiting, ZHANG Benjian, ZHOU Gang, YUAN Haifeng, MA Kui, SONG Zezhang Xinjiang Petroleum Geology    2026, 47 (2): 155-162.   DOI: 10.7657/XJPG20260204 Abstract （116）   HTML （6）    PDF（pc） （4148KB）（45）       Knowledge map    Save The microbial dolomite of the Sinian Dengying formation in the Penglai gas field, central Sichuan Basin, is an important option for achieving additional reserves and production of oil and gas in deep to ultra-deep marine carbonate rocks in the basin. However, it is challenging to identify the impacts of reservoir diagenesis and pore evolution on hydrocarbon charging in this area due to its complex history of reservoir evolution. To objectively understand the potential and direction of petroleum exploration in the Penglai gas field, based on previous research results and exploration practice, together with comprehensive analysis of core thin sections, cathodoluminescence (CL) and trace elements, the relationship between diagenesis and hydrocarbon charging in the Dengying formation in the Penglai gas field was determined. The results show that the reservoirs of the Dengying formation in the Penglai gas field have been reworked by multiple stages of various diagenetic processes, including dissolution, cementation and filling, compaction-pressure-dissolution, recrystallization, tectonic disruption, and silicification. The diagenetic evolution process of the Dengying formation in the Penglai gas field includes five stages: contemporaneous-penecontemporaneous cementation, shallow-burial early diagenesis, uplifted-exposed epidiagenesis, burial diagenesis, and deep-burial late diagenesis. Ancient oil reservoirs were developed in the second member of Dengying formation (Deng 2 member) during the Caledonian period. The diagenetic minerals records three phases of hydrocarbon charging: the first phase is the cementation of fibrous dolomite (FD) cements around grape lace-like lattice pores, which emits no light or dim light; the second phase is the replacement of algal ring and fibrous dolomites by atmospheric freshwater dolomite (AFD) cements, which emits dim light; and the third phase is the filling of silty-fine granular dolomite (GD) cements into intergranular pores, intragranular pores, and lattice pores, which emits dim to dull-red light. The reservoir of the fourth member of Dengying formation (Deng 4 member) is filled with dolomite cements of multiple stages, with the reservoir subjected to multiple phases of hydrocarbon charging, including two phases of asphalt charging: the first phase, the Caledonian, exhibits low abundance, while the second phase, the Yanshanian, shows high abundance. Table and Figures | Reference | Related Articles | Metrics

Select

NMR-Based Investigation on Microscopic Retention and Plugging During Microsphere Flooding HAN Bo, GAO Hui, LIU Yunlong, YI Ping, WANG Chen, CHENG Zhilin, LI Teng Xinjiang Petroleum Geology    2026, 47 (1): 103-110.   DOI: 10.7657/XJPG20260111 Abstract （120）   HTML （1）    PDF（pc） （1287KB）（43）       Knowledge map    Save Microsphere flooding technology can effectively address the issues of severe water channeling in high-permeability layers and difficult oil mobilizing in low-permeability layers in low-permeability reservoirs. This paper investigates the microscopic retention and plugging characteristics of microspheres by combining a parallel dual-core microsphere flooding physical simulation experiment with low-field nuclear magnetic resonance (NMR) testing, and quantitatively evaluates the microscopic plugging capacity of microspheres by defining the degree of core plugging and the plugging contributions of large and small pores. The results show that microsphere flooding can further enhance oil recovery. Microsphere injection at varying rates after water flooding enables the oil recovery of low-permeability and high-permeability cores to increase by an average of 9.47% and 5.80%, respectively. The permeabilities of the cores reduce to a varying extent after microsphere flooding, with a higher reduction in low-permeability cores than in high-permeability cores. The NMR test results indicate that the plugging degree of microspheres in low-permeability cores is greater than that in high-permeability cores. The average plugging degrees of low-permeability and high-permeability cores at different injection rates are 5.44% and 1.02%, respectively, suggesting that microspheres with a diameter of 50 nm used in the test are compatible with low-permeability cores. Additionally, the calculation results show that the plugging contribution rate of large pores is higher than that of small pores, with the latter being negative, indicating that microspheres preferentially deposit in large pores and displace the water in large pores into small pores, thereby mobilizing the fluocarbon oil in small pores. Table and Figures | Reference | Related Articles | Metrics

Select

Micro-Fault Characteristics and Their Controls on Water Invasion in Ultra-Deep Gas Reservoirs: A Case Study of the Keshen X Block, Tarim Basin JIN Jiangning, MA Xiao, QU Yuanji, NENG Yuan, ZHAO Zihan, HE Yunduo, WANG Xi’an Xinjiang Petroleum Geology    2026, 47 (3): 307-313.   DOI: 10.7657/XJPG20260307 Abstract （101）   HTML （4）    PDF（pc） （6311KB）（42）       Knowledge map    Save The Kelasu structural belt in the Kuqa depression is an important target for ultra-deep petroleum exploration and development in the Tarim Basin. The Keshen X block is an ultra-deep, high-yield gas reservoir discovered in the eastern Kelasu structural belt. With the deepening of gas reservoir development, the focus of work has shifted from clarifying the external morphology of structural traps to analyzing the complex internal trap structures. Micro-faults have been identified as the primary pathways for water invasion in the Keshen X block, and their distribution patterns and structural geometries exert significant control on reservoir productivity. This study preferentially employs the variance, coherence and curvature attributes and applies multi-attribute fusion technology to precisely characterize the distribution of micro-faults in the Keshen X block. The findings reveal that the Keshen X block, situated within a compression-strike-slip structural transition zone, exhibits distinct differences in the properties and distribution of micro-faults between its eastern and western segments. In the western segment, micro-faults predominantly trend in nearly E-W direction, have large displacement, and are formed by compression, with their strikes parallel to the direction of water invasion. In the eastern segment, micro-faults are nearly NW-SE-trending, with small displacement, and originated from strike-slip, with their strikes obliquely to the direction of water invasion at a high angle. Due to the blocking effect of fault cores in the fault zone against oblique water invasion, the Keshen X block demonstrates a pronounced contrast in water invasion intensity, i.e., weak in the east and strong in the west. Guided by these findings, a water drainage strategy has been implemented by adding two drainage wells near the main faults in the western segment. This intervention increases the reservoir’s daily water drainage volume by nearly 246%, achieving excellent results in water control and gas production optimization. Table and Figures | Reference | Related Articles | Metrics

Select

Deformation and Petroleum Significance of Strike-Slip Faults on the Northern Slope of the Leshan-Longnvsi Paleouplift WANG Xinlan, LI Zhiwu, XIE Yaoli, LIANG Hong, ZHANG Lingli, XU Baoliang, GUO Ran, CHEN Hui, YOU Liwei Xinjiang Petroleum Geology    2026, 47 (2): 172-183.   DOI: 10.7657/XJPG20260206 Abstract （111）   HTML （11）    PDF（pc） （7294KB）（40）       Knowledge map    Save Numerous strike-slip faults with small throws, complex planar configurations, and insufficient quantitative constraints on multi-phase activities are developed on the northern slope of the Leshan-Longnvsi paleouplift in the Sichuan Basin. Based on detailed interpretation of key horizons and faults using newly acquired contiguous 3D seismic data, this study investigates the changes in stratigraphic extension and thickness-domain subsidence,and analyzes the deformation characteristcs and evolutionary stages of the strike-slip faults, and their influences on hydrocarbon accumulation. The research results reveal that the strike-slip faults on the northern slope primarily trend in nearly EW and NW-SE. In cross-section, they exhibit vertical, Y-shaped, and flower structure geometries. On plan view, they display combinations such as miniature pull-apart faults, linear faults, en echelon faults, and horsetail faults. The strike-slip faults are characterized by layered and segmented structural deformation. Considering the regional tectonic setting, the strike-slip faults on the northern slope are interpreted to have undergone multistage and inherited development, with the Late Sinian-Early Cambrian and Middle-Late Permian being the primary active periods, which respectively correspond to the developmental timing of the Mianyang-Changning extensional trough and Pengxi-Wusheng subsag within the Sichuan Basin. The formation and evolution of the strike-slip faults in the study area took place across hydrocarbon generation, migration, accumulation, and destruction process, playing a controlling role in the formation of the Permian reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Distribution of Present Geothermal Field and Evaluation of Geothermal Resources in the Western Uplift of the Junggar Basin LU Hui, WANG Fei, ZHANG Yidan, WANG Junwei, ZHANG Jinlong, CHEN Lei, XIAO Bei, YANG Huang, LI Chen Xinjiang Petroleum Geology    2026, 47 (1): 92-102.   DOI: 10.7657/XJPG20260110 Abstract （130）   HTML （3）    PDF（pc） （5134KB）（39）       Knowledge map    Save Geothermal resources, as clean and stable non-carbon-based energy sources, are of great significance for China to achieve its “Dual Carbon” goals. The geothermal resources in the Junggar Basin have been insufficiently studied. This paper discusses the distribution of present geothermal field and performs the evaluation of geothermal resources in the western uplift of the Junggar Basin. Based on the high-quality, continuous temperature measurement data from 11 wells, the distribution characteristics of geothermal gradient and terrestrial heat flow were analyzed. Using the one-dimensional steady-state heat conduction equation, the planar distribution of temperature in the strata shallower than 5 000 m was revealed. On this basis, the geothermal resources of 7 sets of geothermal reservoirs (including the Carboniferous and above systems) were evaluated. The results show that, in the western uplift of the Junggar Basin, the average geothermal gradient is (21.3±3.0) ℃/km, and the average terrestrial heat flow is (43.9±6.9) mW/m2. In the Zhongguai bulge, a relatively high-temperature anomaly area, the average geothermal gradient is (23.3±2.8) ℃/km, and the average terrestrial heat flow is (47.9±5.8) mW/m2. The formation temperature at a depth of 4 000 m ranges from 78.0 ℃ to 122.9 ℃ in the western uplift, with an average of 100.7 ℃ in the Zhongguai bulge, indicating a good geothermal potential. The geothermal resources are estimated to be 411.24 EJ in the study area, with the largest quantity (132.61 EJ) endowed in the Permian, followed by the Carboniferous (121.52 EJ). The largest fluid resources are registered by the Cretaceous, reaching 19.58 EJ. This study provides key parameters for the development and utilization of geothermal resources in the western uplift and also offers a methodological reference for geothermal evaluation in other areas of the Junggar Basin. Table and Figures | Reference | Related Articles | Metrics

Select

Lithology Identification of Volcanic Rocks Based on Extra-Trees Classifier: A Case Study of the Huoshiling Formation in the Chaganhua Subsag, Changling Fault Depression, Songliao Basin WANG Yelei, CI Xinghua, DU Huanfu, HOU Wenhui, WANG Zhifeng, WANG Shunye, WANG Chunwei Xinjiang Petroleum Geology    2026, 47 (2): 222-232.   DOI: 10.7657/XJPG20260211 Abstract （96）   HTML （8）    PDF（pc） （8112KB）（38）       Knowledge map    Save Volcanic rock reservoir is one of the key exploration targets in the Changling fault depression of the Songliao Basin in recent years. The logging responses of complex volcanic lithologies are crucial to clarifying the reservoir properties (lithology, physical property, electrical property, and oil-bearing property). Based on the microscopic analysis of complex volcanic lithology, the lithology of volcanic rocks in the Huoshiling formation of the Chaganhua subsag in the Changling fault depression was calibrated through thin-section examination, whole-rock X-ray diffraction (XRD) analysis, and quantitative analysis using the RoqScan mineral auto-identification system. The conventional logging data and elemental logging data of the calibrated interval were divided into training set and test set. The training set was used to fit the target lithology, and the test set was loaded into the model calculation for prediction. Moreover, the model was employed in blind well testing. The results show that the volcanic rocks in the Huoshiling formation of the Chaganhua subsag in the Changling fault depression can be categorized into 5 classes such as volcanic lava, pyroclastic lava, pyroclastic rock, sedimentary pyroclastic rock, and pyroclastic sedimentary rock, indicating complex and varying lithologies. Six algorithms, i.e. decision tree, LightGBM, random forest, neural network, K-nearest neighbor (KNN), and extra-trees classifier (ETC), were compared for distinguishing lithology, revealing the accuracy of above 77% for all algorithms. ETC exhibits the best performance, with an accuracy up to 90%. This model has a strong generalization ability and yields an accuracy of 89% in blind well testing while correcting the results of original cutting logging. It can accurately identify and predict the lithology of volcanic rocks in the study area and provide intelligent support for subsequent volcanic oil and gas exploration and development. Table and Figures | Reference | Related Articles | Metrics

Select

Waveform Indication Inversion Constrained by a Fourth-Order Sequence Framework and Its Application in Thin Sandstone-Mudstone Interbeds MIAO He, LEI Hanyu Xinjiang Petroleum Geology    2026, 47 (3): 279-287.   DOI: 10.7657/XJPG20260304 Abstract （88）   HTML （8）    PDF（pc） （8999KB）（38）       Knowledge map    Save The sandstone reservoirs of the Yingcheng formation in the southern part of the Songliao Basin are characterized by small sand body thickness, presence of thin sandstone-mudstone interbeds, and lateral variation of lithology. The traditional third-order sequence framework is not sufficient for precisely characterizing the spatial distribution of sand bodies in such reservoirs. In strata with reflection configurations such as toplap, baselap, and truncation, the axis-crossing of sand bodies is prominent. Through dissection of the application scenarios of waveform indication inversion algorithms, a waveform indication inversion method under the constraint of a fourth-order sequence framework was proposed. By combining the layer auto-tracing algorithm with sequence stratigraphy, geologically significant layers were extracted to establish a fourth-order sequence framework as a constraint for waveform indication inversion. Compared with conventional techniques, the proposed waveform indication inversion under the constraint of a fourth-order sequence framework ensures vertical resolution, and also improves the lateral continuity of thin sand bodies. Taking the Yingcheng formation in the southern part of the Songliao Basin as an example, appropriate layer tracing algorithm and parameters were determined through forward modeling. Considering the actual third-order and fourth-order sequence boundaries identified in production wells, a fourth-order sequence framework was established and used to constrain the waveform indication inversion process. It is indicated that the inversion results can accurately represent geological phenomena, with significantly improved lateral continuity and interpretability of sand bodies. The waveform indication inversion under the constraint of a fourth-order sequence framework effectively enabled the identification of thin sand bodies in the Yingcheng formation in the southern part of the Songliao Basin. This method achieves improved reliability and continuity in predicting thin sandstone-mudstone interbeds (>10 m) and addresses the bottleneck of axis-crossing thin sand body. Table and Figures | Reference | Related Articles | Metrics

Select

Study on the Relationship Between Pore Structure and Mechanical Properties of Tight Sandstone Based on Fractal Theory FAN Qingxiong, ZHANG Chuang, ZHOU Xue, WANG Chenglong, LI Guoqing, CHENG Zhilin Xinjiang Petroleum Geology    2026, 47 (3): 350-360.   DOI: 10.7657/XJPG20260312 Abstract （64）   HTML （0）    PDF（pc） （5398KB）（37）       Knowledge map    Save The economical development of tight oil reservoirs is inseparable from successful reservoir fracturing stimulation. Understanding the relationship between reservoir rock mechanical properties and microscopic pore structure is of great significance for improving the fracturing effect of tight reservoirs. This paper investigates the tight sandstone in the seventh member of the Triassic Yanchang formation (Chang 7 member) in the Hechuan area of Yongning oilfield in the Ordos Basin as an example. Through reservoir physical property test, nuclear magnetic resonance (NMR) and high-pressure mercury intrusion (HPMI) experiments, and following the fractal theory, the pore structure characteristics were analyzed, and the comprehensive fractal dimension was calculated. Then, the comprehensive fractal dimension was used as a bridge to systematically evaluate the correlation between pore structure and mechanical parameters. The results show that the Chang 7 member tight sandstone reservoirs primarily contain intergranular pores and dissolution pores, and exhibit pore-throat structures in three types, with medium and small pore-throats in dominance. The comprehensive fractal dimension is significantly correlated with reservoir physical properties and feldspar content, and it can effectively represent the complexity and heterogeneity of the pore structure. With the increase of fractal dimension, the compressive strength, Young’s modulus, Poisson’s ratio, tensile strength and horizontal stress difference all show an upward trend. The mechanical parameter prediction model constructed based on the comprehensive fractal dimension enables the quantitative characterization of the mechanical properties of the tight sandstone in the Chang 7 member, providing important support for fracturing stimulation optimization and enhancing oil recovery from reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Feasibility Experiments and Injection/Production Optimization of Associated Gas Flooding for Enhanced Oil Recovery: A Case Study of the Chang 7 Shale Oil in the West 233 Area of the Ordos Basin CHEN Bo, LIU Shuaishuai, WANG Yijun, LENG Xiangang, LEI Qihong, LI Desheng, WANG Ning Xinjiang Petroleum Geology    2026, 47 (2): 184-191.   DOI: 10.7657/XJPG20260207 Abstract （112）   HTML （3）    PDF（pc） （757KB）（37）       Knowledge map    Save The Chang 7 reservoir in the West 233 area of the Ordos Basin is a typical sandwiched shale oil accumulation with low formation pressure coefficient, rapid production decline, and abundant associated gas. Associated gas flooding experiments were conducted on reservoir rock samples. Combined with NMR T2 spectra, the results of associated gas flooding and huff-n-puff experiments were analyzed, and the huff-n-puff efficiency under varying well spacing was simulated. The results show that the presence of bound water significantly reduces the efficiency of associated gas flooding. After displacement, the signal intensity of pores with T2>10 ms decreases significantly; the displaced oil mainly comes from large pores, while only a small part of oil in small pores is mobilized, leaving a large quantity of residual oil. Associated gas huff-n-puff can effectively improve the recovery of shale oil, with the first cycle contributing most to the recovery, the second cycle witnessing a recovery greater than 85% OOIP, the third cycle recording a recovery not exceeding 15%, and the fourth cycle remaining a recovery basically unchanged. This indicates that the oil in large pores has been mainly mobilized. With the increase of huff-n-puff cycles, the incremental oil production decreases, the oil replacement rate drops, and the increase in recovery factor slows down, gradually entering an inefficient cycle. For associated gas huff-n-puff in horizontal wells with well spacing of 200 m, the optimal associated gas injection time is 639 d, the optimal slug size is 900 m3, the optimal injection rate is 15 m3/d, the optimal shut-in time is 40 d, the optimal injection-production time per cycle is 160 d, and the optimal number of huff-n-puff cycles is 3. The optimal timing for continuous associated gas flooding is 1,200 d, and the optimal associated gas injection rate is 15 m3/d. Table and Figures | Reference | Related Articles | Metrics

Select

Modeling Method for Fault-Controlled Reservoirs Based on Internal Filling Model and Its Application TIAN Yuan, WANG Jiale, YUE Ping, ZHAO Liming, ZHANG Ying, FAN Qingzhen, GENG Jie, MOU Yu Xinjiang Petroleum Geology    2026, 47 (1): 116-125.   DOI: 10.7657/XJPG20260113 Abstract （129）   HTML （4）    PDF（pc） （8866KB）（37）       Knowledge map    Save The complex and highly heterogeneous reservoir space in the Ordovician carbonate reservoirs in Tahe oilfield poses significant challenges to reservoir characterization and modeling. This paper proposes a modeling method for fault-controlled reservoirs based on internal filling model, enabling the construction of a high-precision model with the methodology of lithology-structure dual constraints, hierarchical modeling, and categorical integration. First, depending on the genesis of fault-controlled reservoirs and the characteristics of reservoir architectures, the reservoirs are divided into three types of structural units: vugs, pores, and fractures. Vugs and pores are delineated by using deterministic modelling with cutoff value and corrected manually to define their boundaries; combined with log-derived lithofacies, the reservoirs are identified, and the internal architecture is finely characterized by integrating deep neural network with seismic inversion data. Faults and fractures are characterized at different scales: large faults are identified through ant-tracking and coherence attributes; small-medium faults are defined by diffraction tensor ant-tracking with volume constraints; and fractures are finely described via discrete fracture network (DFN) modeling. Next, based on the coupling of genetic mechanism, storage-permeability function, and engineering application, multi-scale model integration is performed. Finally, a matrix-fracture dual-medium geological model is established. Application in a unit of the Tahe oilfield has demonstrated that the high-precision filling model yields the validated results of static reserves and production performance in good agreement with the actual production data. The proposed model can effectively support the simulations of remaining oil recovery and development adjustment, and significantly enhance the reliability of numerical simulation for such reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

An Injection Profile Log Evaluation Method Based on Distributed Temperature Sensing and Using Wellbore Temperature Recovery Data LAI Ke, SONG Hongwei, LI Ming, WANG Mingxing, QI Bo Xinjiang Petroleum Geology    2026, 47 (3): 369-377.   DOI: 10.7657/XJPG20260314 Abstract （76）   HTML （3）    PDF（pc） （4317KB）（35）       Knowledge map    Save Evaluation of injection profile for multi-layer reservoirs is vitally important for successful water injection development and effective reservoir management. It can be achieved by using distributed temperature sensing (DTS) technology, which provides reservoir information with high measuring frequency, low cost, and low risk to environment and personnel. However, conventional DTS inversion model depends heavily on steady temperature data. To improve the evaluation accuracy and efficiency, this paper proposes an injection profile log evaluation method based on DTS and using wellbore temperature recovery data. First of all, according to the multi-field coupling theory and numerical simulation, a temperature field model for injection well in multi-layer reservoirs was constructed to analyze the temperature variation in wellbore and reservoirs under different injection conditions and shut-in time. Then, an injection profile evaluation model based on the characteristic temperature recovery index was established to invert the water absorption of each layer using temperature recovery data. Moreover, the proposed model of injection profile log evaluation using wellbore temperature recovery data was validated through numerical simulation. Finally, the model was applied to the data measured by DTS and production logging tool (PLT) in two water injection wells. The application results are found consistent with the isotope interpretation, with the errors mostly below 15%, verifying the reliability and practicability of the model. The study provides theoretical support for optimizing water-injection development and reservoir dynamic monitoring. Table and Figures | Reference | Related Articles | Metrics

Select

Variations of Displacement Characteristics During the Whole Process of Waterflooding in Block WX-3 XU Yunheng, REN Bo, GENG Ziyuan, WU Jinbiao Xinjiang Petroleum Geology    2026, 47 (2): 210-221.   DOI: 10.7657/XJPG20260210 Abstract （105）   HTML （3）    PDF（pc） （8186KB）（34）       Knowledge map    Save After nearly 30 years of waterflooding development, the reservoir in Block WX-3 of Wenmi oilfield has changed in porosity, permeability and microscopic pore structure, resulting in variations of fluid flow behaviors in the reservoir. In order to further quantify the variations of flow behaviors during waterflooding in the reservoir in Block WX-3, using the experimental data of oil-water relative permeability before and after waterflooding at different watered-out levels, a mathematical model for oil-water relative permeability and a prediction model for water cut changes during the whole process of waterflooding development were constructed by virtue of waterflood analytical method and Newton iteration method. The results show that the actual water cut during production in Block WX-3 changes in a consistent pattern with the model prediction result. The main problems in the development of Block WX-3 are relatively high displacement rate in waterflooding, and the migration, expansion and blockage of clay particles caused by injected water, which alter the pore structure and wettability of the reservoir. Along with extension of water injection, the irreducible water saturation and residual oil saturation gradually increase, and the oil displacement efficiency gradually decreases. Specifically, on average, the irreducible water saturation increases by 0.067 7, the residual oil saturation increases by 0.053 1, and the oil displacement efficiency decreases by 0.142 8. Table and Figures | Reference | Related Articles | Metrics

Select

Hydrocarbon Accumulation Conditions and Exploration Directions of the Devonian in the Central Part of Western Sichuan Depression LI Shuangjian, ZHANG Lei, MA Jianfei, WU Qingjie, MENG Xianwu, DUAN Nan, SHI Lei Xinjiang Petroleum Geology    2026, 47 (4): 379-392.   DOI: 10.7657/XJPG20260401 Abstract （56）   HTML （13）    PDF（pc） （23067KB）（34）       Knowledge map    Save Influenced by the expansion of the Paleo-Tethys Ocean, the Devonian system along the western margin of the Yangtze Block presents a continuous sedimentary succession, with thickness up to several kilometers, providing favorable petroleum geological conditions. Due to complex surface structures and large burial depth of the Devonian in the Longmenshan piedmont zone of the Western Sichuan depression, this area has been insufficiently explored and studied. Moreover, there is limited research on stratigraphic distribution, reservoir development patterns, and hydrocarbon accumulation and preservation conditions of the Devonian in the deeply buried zones in the basin. Based on high-precision, contiguous 3D seismic data, this study identifies and confirms the presence of Middle-Upper Devonian high-energy facies zones. By integrating drilling and outcrop data, the fundamental hydrocarbon accumulation conditions of the Devonian in the central part of the Western Sichuan Depression are clarified, and future exploration directions are proposed. The results show that the strata in the Middle Devonian-Carboniferous in the central part of the Western Sichuan depression have a residual thickness ranging from 0 to 450 m, gradually decreasing from west to east, with a distribution area of up to 6,500 km2. The Middle-Upper Devonian is primarily an open platform to restricted platform depositional system, where high-quality reservoirs are mainly intraplatform facies and contain dissolution pores/vugs, jointly controlled by high-energy facies zones, fractures and early-stage dissolution. These high-quality reservoirs exhibit distinct medium-strong amplitude, discontinuous reflection features on seismic sections, and distribute as NE-SW-trending strips, covering an area of approximately 2,000 km2. Structural-lithologic traps in the Middle-Upper Devonian across the Western Sichuan depression, formed during the Indosinian period, show a good match with the peak hydrocarbon generation period of the Cambrian main source rocks. The overlying Triassic gypsum-salt rocks serve as a regional seal, ensuring excellent preservation conditions. Individual reservoirs can reach 100 m in thickness. These characteristics imply potential for forming large-to-medium, high-abundance gas fields. It is concluded that the Middle-Upper Devonian can be taken as a favorable target for deep-to-ultradeep marine exploration in the Sichuan Basin. Table and Figures | Reference | Related Articles | Metrics

Select

A Multi-Scale Simulation Method for Oil Mobilization Pattern of Surfactant Injection in Tight Conglomerate Reservoirs in Mahu Sag, Junggar Basin LI Qing, LIU Canhua, XIONG Qian, ZHANG Lianbin, SHENG Mao, ZHANG Jigang, LI Peiyu, SONG Zhaojie Xinjiang Petroleum Geology    2026, 47 (3): 288-299.   DOI: 10.7657/XJPG20260305 Abstract （87）   HTML （2）    PDF（pc） （9748KB）（33）       Knowledge map    Save The tight conglomerate reservoirs of the Permian upper Wuerhe formation in the Mahu sag of the Junggar Basin are strongly heterogeneous with complex pore-throat structures, resulting in large variations in surfactant huff-n-puff performance in the Jinlong 2 well block. In this study, a digital rock model was constructed, and a pore-scale lattice Boltzmann method was improved and upscaled to systematically elucidate oil displacement mechanism and oil mobilization pattern of surfactant injection. The results show that during water flooding, oil mobilization exhibits a four-stage process: initiation-expansion-breakthrough-slowdown, whereas after surfactant injection it follows a dynamic process evolving as front advancement-wettability reversal-flow enhancement-effect attenuation. The surfactant enhances the synergy between viscous driving force and capillary force, thereby stripping oil films and mobilizing oil flakes in small pores. Compared with water huff-n-puff, surfactant huff-n-puff yields more oil and less water, with an effective near-wellbore penetration depth of 14 cm. The smaller the oil/water viscosity ratio, the more uniform the pressure distribution, and the larger the swept area, indicating that an optimal surfactant formulation should be co-designed in terms of interfacial tension and wettability in accordance with reservoir conditions. The findings have provided a theoretical basis for optimizing efficient development plans for the tight conglomerate reservoirs in the Mahu sag and guided the surfactant injection in a well in the Jinlong 2 well block, recording a good performance with a cumulative incremental oil production of 7 483 t. Table and Figures | Reference | Related Articles | Metrics

Select

Segmented Quantitative Characterization of Drainage Radius of Horizontal Well Based on Reservoir Heterogeneity HUANG Zheng, LIU Yu, FAN Xiaoyi, QIN Ling, TAO Shuai, YANG Fei Xinjiang Petroleum Geology    2026, 47 (2): 233-240.   DOI: 10.7657/XJPG20260212 Abstract （106）   HTML （4）    PDF（pc） （814KB）（33）       Knowledge map    Save Steam stimulation in horizontal wells in heavy oil reservoirs fails to achieve uniform exploitation and precise potential tapping via horizontal section. Conventional methods mostly consider the horizontal section as a whole, but overlook unbalanced producing due to reservoir heterogeneity, leading to vague understanding of remaining oil distribution and indefinite direction of potential tapping. This paper presents a segmented method of calculating drainage radius of a horizontal well. This method employs acoustic time difference (AC) to characterize reservoir heterogeneity, with the difference between adjacent AC averages >15% as a threshold to segment horizontal section. Depending on the relationship among single-well recovery efficiency, sweep efficiency, and displacement efficiency, a drainage radius calculation model is constructed to determine segment-specific drainage radius, quantitatively characterize drainage area, and accurately map remaining oil distribution zones. The application of this model in the heavy oil reservoir in the Chun 10 block of Chunguang oilfield reveals that the reservoir in the block is highly heterogeneous, where the segments of horizontal section divided by AC are greatly varying in drainage radius - from 5 to 110 m in individual wells, and the recovery is extremely disproportionate along the horizontal section. Guided by remaining oil distribution patterns, target orientations are optimized, and accordingly infill wells are accurately placed to effectively avoid the drainage interference from existing wells, thereby achieving enhanced development effects. This study provides a new method for calculating drainage radius of horizontal well in heterogeneous reservoirs, which enables a simple and rapid determination of single-well drainage radius, offering a technical support for further development of heavy oil reservoirs after steam stimulation. Table and Figures | Reference | Related Articles | Metrics

Select

Design of Reasonable Injection and Production Parameters for the Yu-37 Gas Storage Considering Sand Production WANG Ping, WEI Yongsheng, GUO Yanni, TANG Shiqi, HUANG Hai, QU Zhan, WANG Liang, HE Yawen Xinjiang Petroleum Geology    2026, 47 (1): 64-73.   DOI: 10.7657/XJPG20260107 Abstract （125）   HTML （3）    PDF（pc） （956KB）（30）       Knowledge map    Save Repeated high-intensity injection and production in wells of a gas-storage lead to frequent stress changes in the reservoirs, which may trigger sand production to threaten the stable operation of the gas storage. Taking the Yu-37 gas storage in the Ordos Basin as an example, the nodal analysis method was used, together with the critical flow velocity model for proppant migration, as well as the critical sand production pressure difference model for sand production prediction and the critical erosion flow model, to define the reasonable injection and production rates of wells for ensuring the operation safety of the Yu-37 gas storage under the extreme production state. According to the calculation using the critical flow velocity model for initiation of proppant migration in the fractures, which was established through the stress analysis of the proppant in the reservoir fractures, the proppant reaches its critical flow velocity for initiation of migration when the injection and production rates are 10.89 m/s and 8.19 m/s, respectively. Three restrictive models are used to modify the nodal analysis method, the reasonable injection and production rates of Well Yu 43-1 are determined to be (1.79-6.53)×104 m3/d and (2.82-6.35)×104 m3/d, respectively. Given the safety limits, the reasonable injection and production rates of 10 wells at the Yu-37 gas storage are defined. Table and Figures | Reference | Related Articles | Metrics

Select

Mechanism and Parameter Optimization of Energy-Replenishing Fracturing for Tight Oil Reservoirs in W Oilfield CHEN Gang, YANG Shuisheng, LIU Yuqi, BAI Jiang Xinjiang Petroleum Geology    2026, 47 (3): 314-324.   DOI: 10.7657/XJPG20260308 Abstract （89）   HTML （2）    PDF（pc） （1429KB）（29）       Knowledge map    Save Due to the limitations in geological conditions and engineering technologies in W oilfield of the Ordos Basin, the development of the tight oil reservoirs in the oilfield generally demonstrates low productivity, poor production stability, insufficient injection, and unsuccessful displacement. It is necessary to modify conventional energy replenishment methods and optimize parameter design for enhanced oil recovery (EOR). In this study, a fracturing-shut-in-production whole-process simulation workflow was developed to reveal the dynamic behaviors of volume fracturing in tight oil reservoirs and analyze the influences of different factors on the performance of energy-replenishing fracturing (ERF). The numerical simulation method was used to optimize the fracturing parameter design. Finally, an innovative ERF technology featured with large fluid volume, high pump rate, low proppant ratio, and shut-in displacement was formed. The research shows that the fracturing fluid volume, matrix permeability, stimulated reservoir volume (SRV) and initial formation pressure are closely related to the effect of shut-in energy storage. The optimal parameters are obtained from the simulation as: the fracture conductivity of 10-15 D·cm, the shut-in time of 30-40 days, the pump rate of 4-6 m3/min, the fracturing fluid volume of 600-800 m3, the proppant volume of 40-55 m3, and the proppant ratio of about 15%. The proposed ERF technology has been successfully applied to tight oil reservoirs, recording an average production rate of 4.33 t/d per well, which is more than four times that (1.08 t/d) of conventional fracturing techniques. This technology addresses the problems of low initial production, rapid production decline and short steady production period in conventional treatments, and provides a reference for stable and efficient development of tight oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Enhanced Oil Recovery by Multi-Component Composite Thermal Flooding After Steam Huff and Puff in Shallow-Thin Ultra-Heavy Oil Reservoirs ZHOU Song, LIU Huiqing, PAN Yue, LUO Chen, HE Qinzhi, LI Xiang Xinjiang Petroleum Geology    2026, 47 (3): 325-334.   DOI: 10.7657/XJPG20260309 Abstract （76）   HTML （2）    PDF（pc） （6711KB）（29）       Knowledge map    Save To address the issues such as low producing degree, low well productivity, and high water cut in shallow and thin ultra-heavy oil reservoirs after multiple cycles of steam huff and puff, this study proposes the multi-component composite thermal flooding as a subsequent development strategy. Based on the geological and fluid characteristics in the study area, a three-dimensional physical simulation experiment was designed and conducted on the transition from steam huff and puff to multi-component composite thermal flooding to systematically analyze the temperature field evolution and production performance at different stages. Moreover, a numerical inversion model was employed to identify the key controlling factors of multi-component composite thermal flooding, and parameter optimization was discussed. The results indicate that the reservoir was heated in a limited area in the steam huff and puff stage, resulting in a low recovery efficiency. After transitioning to multi-component composite thermal flooding, the collaborative effect of viscosity reducer, nitrogen and steam significantly improved the recovery efficiency to 57.1%. It is found that the multi-component composite thermal flooding is influenced by the factors of steam injection rate, bottomhole steam quality, nitrogen injection volume, production-injection ratio (P/I), and viscosity reducer injection volume, in a descending order of importance. Depending on the reservoir characteristics in the study area, the optimal parameters for multi-component composite thermal flooding are determined as follows: steam injection rate of 288 t/d, bottomhole steam quality of 0.7, nitrogen injection volume of 0.6 PV, P/I of 1.2-1.3, and viscosity reducer injection volume of 0.2 PV. Table and Figures | Reference | Related Articles | Metrics

Select

Physical Property Changes and Flow Patterns in Tight Conglomeratic Sandstone Reservoirs During Waterflooding DU Zhengtong, HE Yongming, XIAO Yihang Xinjiang Petroleum Geology    2026, 47 (3): 335-340.   DOI: 10.7657/XJPG20260310 Abstract （69）   HTML （1）    PDF（pc） （664KB）（28）       Knowledge map    Save Tight conglomeratic sandstone reservoir is an important component of unconventional oil and gas resources. The tight conglomeratic sandstone reservoirs are extremely heterogeneous owing to complex sedimentary and diagenetic environments, making their exploitation very challenging. Elucidating physical property changes and flow patterns in tight conglomeratic sandstone reservoirs during waterflooding is of great significance. In this study, the effects of waterflooding on physical properties of tight conglomeratic sandstone reservoirs were identified through basic physical property test, X-ray diffraction (XRD), and Amott imbibition and unsteady state relative permeability experiments. The flow patterns in tight conglomeratic sandstone reservoirs were clarified by the experiments on stress sensitivity, start-up pressure and displacement efficiency, and then compared with the behaviors in tight sandstone reservoirs. The results show that waterflooding leads to a reduction in the content of clay minerals, altering the reservoirs from weakly hydrophilic to strongly hydrophilic, and also an increase in the permeability, mitigating the water-sensitive damage. Long-term waterflooding increases the irreducible water saturation and decreases the maximum water phase permeability, allowing the water saturation at the isoperm point to slightly increase. The stress sensitivity and start-up pressure gradient of tight conglomeratic sandstone reservoirs are higher than those of tight sandstone reservoirs. The mechanism of residual oil re-accumulation enhances the displacement efficiency during secondary and tertiary waterflooding. Table and Figures | Reference | Related Articles | Metrics

Select

Effects of Acid Pretreatment and Acid Volume on Fracture Propagation in Tight Limestone DOU Liangbin, WANG Ruxu, CHENG Xuebin, QUAN Shanshan, SHI Yang, ZHANG Jie, CHEN Zhiwen, CHEN Jingyang Xinjiang Petroleum Geology    2026, 47 (3): 341-349.   DOI: 10.7657/XJPG20260311 Abstract （60）   HTML （2）    PDF（pc） （2685KB）（28）       Knowledge map    Save In the Ordos Basin, the tight limestone reservoirs of the Taiyuan formation are highly heterogeneous, with poor pore-throat sorting and connectivity. Conventional fracturing techniques used in previous treatments were limited and yielded unsatisfactory results in these fracture-underdeveloped reservoirs. Appropriate acid injection can enhance fracture complexity and stimulated reservoir volume (SRV). However, excessive acid injection may cause a ‘big belly’ near the wellbore, where acid reaction and dissolution restrict fracture growth during subsequent treatment, reducing the overall SRV. True triaxial hydraulic fracturing experiments were performed on the samples from the Taiyuan formation limestone outcrop. The open-hole sections of the samples were acid-pretreated before fracturing, and the effects of acid volume on fracture complexity and morphology were analyzed. The results indicate that, for hard rocks with low porosity, low permeability, and low confining pressure, the best acidizing performance is achieved at the acid-to-fracturing fluid ratio of 0.2-0.34, while the acidizing effect weakens and the risk increases in treatment when the acid-to-fracturing fluid ratio is higher than 0.2-0.34. Acid stimulation is not recommended for formations with high permeability, presence of abundant natural fractures, and high content of ferrierous dolomite. By optimizing the acid volume, it is possible to efficiently generate a complex fracture network that helps significantly enhance both the SRV and ultimate production. Table and Figures | Reference | Related Articles | Metrics

Select

Evaluation of Preservation Conditions Based on Deep Marine Shale Gas Formation Pressure Calculation: A Case Study of Wulalike Formation Shale Gas in the Western Ordos Basin ZHANG Haitao, XU Peiyu, KOU Xiaopan, GUO Xiaokai, LIU Die, LIU Yubai, TIAN Lili, CHEN Zhen Xinjiang Petroleum Geology    2026, 47 (3): 361-368.   DOI: 10.7657/XJPG20260313 Abstract （71）   HTML （1）    PDF（pc） （874KB）（28）       Knowledge map    Save Preservation conditions represent a key factor controlling shale gas enrichment and high production, and formation pressure coefficient is one of the core parameters for evaluating shale gas preservation conditions and selecting favorable exploration zones. This study investigates the marine shale gas in the Wulalike formation in the western Ordos Basin. By integrating data from gas testing and formation pressure measurements, an applicability analysis was conducted on formation pressure calculation methods. Additionally, a preservation condition evaluation index was established, along with a quantitative classification standard for reservoir preservation conditions, to enable a comprehensive evaluation of preservation conditions in the study area. The results show that the Eaton method performs well in calculating normal and undercompacted formation pressures at shallow to medium depths, but fails to account for formation unloading effects. The current formation pressure in the Wulalike shale gas reservoirs is primarily influenced by tectonic uplift, erosion, and hydrocarbon generation, and the Bowers unloading curve shows a superior applicability. The formation pressure coefficient in the study area mainly ranges between 0.8 and 1.2, exhibiting a logarithmic positive correlation with tested daily shale gas production. This coefficient serves as a critical indicator for evaluating shale gas preservation conditions. The shale gas preservation conditions of the Wulalike formation in the western Ordos Basin are generally superior in the east and inferior in the west, and strong in the north and weak in the south. The research insights provide valuable reference for identifying favorable shale gas exploration zones in the study area. Table and Figures | Reference | Related Articles | Metrics

Select

Pseudo Threshold Pressure Gradient Model for Shallow Heavy Oil Reservoirs in Xinjiang Oilfield Under the Heat-Hydrocarbon Synergy LI Qihang, YAN Yonghe, Muhetar , WANG Zhizhang, LI Yiqiang, CHEN Wenhao, YUAN Chaoye Xinjiang Petroleum Geology    2026, 47 (1): 74-80.   DOI: 10.7657/XJPG20260108 Abstract （127）   HTML （3）    PDF（pc） （734KB）（28）       Knowledge map    Save The high-temperature steam huff-and-puff in the J230 block of Xinjiang oilfield has led to an increased viscosity in residual heavy oil in the formation, significant differences in threshold pressure, and severe fluid channeling. Adding light hydrocarbon solvent can effectively reduce heavy oil threshold pressure gradient. In this paper, viscosity-temperature and rheological tests were conducted to compare the viscosity-temperature curves and rheological properties of heavy oil before and after the addition of light hydrocarbon solvent, and flow experiments were performed to clarify the relationship between the mobility of heavy oil and the pseudo threshold pressure gradient. Finally, a pseudo threshold pressure gradient model for solvent-assisted steam flooding was established. The study shows that the synergy between viscosity reduction by heat and viscosity reduction by light hydrocarbon solvent （or heat-hydrocarbon synergy in brief） allows for an improved performance. Light hydrocarbon solvent can modify the flow capacity of heavy oil. Adding 5%（mass fraction） light hydrocarbon solvent at 40℃ yields a pseudo threshold pressure gradient of heavy oil comparable to that at 70℃. Addition of light hydrocarbon solvent can reduce the quantity of immovable heavy oil. As shown in the pseudo threshold pressure gradient diagram, when the mass fraction of light hydrocarbon solvent added is 0.5%, 2.0%, and 5.0%, the quantity of immovable heavy oil is reduced by 39.13%, 70.56%, and 87.14%, respectively. Addition of the light hydrocarbon solvent can reduce steam consumption, thereby effectively lowering the pseudo threshold pressure of heavy oil, and thus suppressing fluid channeling. Table and Figures | Reference | Related Articles | Metrics

Select

Influence of Hydraulic Fracture Morphology on the Producing Degree of CBM Reservoir LI Wenjie, WANG Hu, WU Yunli, ZHONG Jie, ZHANG Tao, ZHAO Zhihong Xinjiang Petroleum Geology    2026, 47 (2): 192-200.   DOI: 10.7657/XJPG20260208 Abstract （104）   HTML （3）    PDF（pc） （2685KB）（24）       Knowledge map    Save To investigate the multi-scale and complex strain-coupled seepage characteristics of coalbed methane (CBM) reservoirs after fracturing, a numerical model for gas reservoirs was established based on finite volume method (FVM). Using the embedded discrete fracture method (EDFM), the fracture system was characterized, coupling with the permeability under matrix creep, desorption swelling, and cleat compression, and considering the nonhomogeneous permeability distribution. The model was validated on production data and then used to identify the influence of hydraulic fracture morphology on the producing degree of CBM reservoirs. The results show that hydraulic fracturing increases the drainage area, enhancing the producing degree and accelerating the overall desorption rate of coal seams. The fracture network formed near the wellbore provides a high-permeability pathway system. Especially in low- to medium-rank coal seams, the ultimate volume fracturing technology significantly increases the production capacity of a single well and prolongs its production period. Table and Figures | Reference | Related Articles | Metrics

Select

Development Characteristics of Fractured Horizontal Wells in Spatiotemporally Heterogeneous Shale Volatile Oil Reservoirs JIANG Liwu, DIWU Pengxiang, CHENG Chunjie, LIU Jinju Xinjiang Petroleum Geology    2026, 47 (2): 201-209.   DOI: 10.7657/XJPG20260209 Abstract （136）   HTML （6）    PDF（pc） （950KB）（24）       Knowledge map    Save Shale volatile oil reservoirs are characterized by small pore throat sizes and complex fluid properties, which compromises the accuracy in predicting reservoir development performance. Conventional prediction methods usually yield the results that are inaccurate or inconsistent with field conditions, since they only take into account a single factor or a few factors. Currently, the main controlling mechanisms in fractured horizontal well development of shale volatile oil reservoirs remain unclear. In this paper, a numerical simulation model based on discrete fracture network (DFN) was built to clarify the influences of multiple mechanisms, including nanopore confinement effect, and spatiotemporal heterogeneity of reservoirs. It is found that the pore throat size controls the development effectiveness mainly by influencing reservoir permeability, and its resulting fluid confinement effect has a relatively small impact on development. The stress-sensitive effect is an adverse factor for the development of shale volatile oil reservoirs. Fractures with high conductivity are conducive to the development of such reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Calculation Method of Critical Edge-Water Distance During Steam Huff and Puff for Preventing Water Invasion ZHENG Wenqian, GENG Zhigang, GE Taotao, SONG Jianfang Xinjiang Petroleum Geology    2026, 47 (1): 111-115.   DOI: 10.7657/XJPG20260112 Abstract （112）   HTML （2）    PDF（pc） （719KB）（21）       Knowledge map    Save For edge-water heavy oil reservoirs, the critical edge-water distance during steam huff and puff is vital for the placement of new wells and the development adjustment of existing wells. When a well for steam huff and puff is placed at a distance less than the critical edge-water distance, edge-water invasion may easily occur, resulting in poor development effect of heavy oil reservoirs. In this paper, the formation after steam huff and puff is divided into a thermally swept zone and a cold zone, and a characterization method of flow field parameters after steam huff and puff is determined. The comprehensive mobility of the thermally swept zone is equivalent to the comprehensive mobility of the cold zone by transforming the length of the thermally swept zone. On this basis, the calculation method of critical edge-water distance during steam huff and puff in heavy oil reservoirs is established considering the start-up pressure gradient of heavy oil, together with the mirror reflection and the potential superposition theory. The results show that the relationship curve between the critical edge-water distance and the permeability is plotted to guide the placement of new wells, effectively preventing edge-water invasion, and the relationship curve between the cumulative liquid production and the cumulative steam injection volume under different edge-water distances is provided to support the optimization of the cyclic steam injection volume in existing wells. Field application in Well A demonstrated that the critical edge-water distance was reduced from 180 m in the first cycle to 150 m in the second cycle, effectively preventing edge-water invasion. By optimizing the cyclic steam injection volume, the steam huff and puff recovery has been increased by 3.1%. Table and Figures | Reference | Related Articles | Metrics

Select

An Injection Profile Log Evaluation Method Based on Distributed Temperature Sensing and Using Wellbore Temperature Recovery Data LAI Ke , SONG Hongwei, LI Ming, WANG Mingxing, QI Bo Xinjiang Petroleum Geology    Accepted: 10 April 2026 Online available: 09 April 2026

Select

Xinjiang Petroleum Geology    2026, 47 (1): 0-0.   Abstract （35）      PDF（pc） （55086KB）（18）       Knowledge map    Save Related Articles | Metrics

Select

Analysis of Seismic Imaging Characteristics of Volcanic Rocks and Underlying Strata Based on Physical Models: A Case Study of Chaganhua Subsag, Southern Songliao Basin MIAO He, LI Ning, XING Tingdong, TIAN Jun Xinjiang Petroleum Geology    2026, 47 (4): 515-524.   DOI: 10.7657/XJPG20260416 Abstract （35）   HTML （4）    PDF（pc） （11013KB）（14）       Knowledge map    Save In the southern Songliao Basin, deep strata experienced intense volcanic activity during faulting period. Volcanic rocks act as the critical hydrocarbon reservoir rocks, but they interfere the seismic imaging of underlying strata. It is very important to study the impact of volcanic rocks on seismic imaging of underlying strata. Based on the typical characteristics and elastic parameters of the volcanic rocks in two eruption cycles and the overlying and underlying rocks in the Chaganhua subsag of the Changling fault depression, physical models were built by scaling down, and seismic acquisition and image processing were performed. On this basis, the impacts of the volcanic rocks on the seismic imaging of the underlying strata were analyzed. The results show that equivalent velocity and density models for volcanic rock formations can be constructed using mixed materials with mica powder and epoxy resin as cementing agents to simulate volcanic rock with high wave impedance and high hardness, together with different proportions of organic crystals to simulate different facies zones. These physical models yield the errors of P-wave velocity less than 2%. It is found that the volcanic rocks of Lower Cretaceous Yingcheng formation have great impacts on the well-seismic calibration of the underlying strata, the thickness of the volcanic rocks and the thickness of the underlying clastic rocks jointly affect the well-seismic calibration of the volcanic rocks of the Lower Cretaceous Huoshiling formation, and the seismic imaging-derived velocity in the volcanic rock area is smaller than the actual velocity of the strata. Based on the research results from the physical models, and considering the data of existing wells and previously acquired insights on the thickness and distribution of the volcanic rocks and clastic rocks, grid tomographic velocity modeling was conducted to iteratively optimize the velocity model, improving the compatibility between actual seismic data and synthetic seismogram. This study provides reference for seismic imaging in volcanic rock areas in other regions around the world. Table and Figures | Reference | Related Articles | Metrics

Select

Patterns and Genetic Mechanisms of Spatial Differentiation of Crude Oil Physical Properties in the Mabei Area, Junggar Basin REN Haijiao, LI Guangxing, ZHAO Yi, HE Wenjun, YU Shuang, YANG Sen, LI Na, LI Hui, ZHU Tao Xinjiang Petroleum Geology    2026, 47 (4): 393-403.   DOI: 10.7657/XJPG20260402 Abstract （43）   HTML （6）    PDF（pc） （2282KB）（13）       Knowledge map    Save The Mabei area in the Mahu sag of the Junggar Basin has yielded significant hydrocarbon discoveries in multiple strata, including the Carboniferous, Permian, and Triassic. However, physical properties of crude oil vary spatially and stratigraphically, and the genetic mechanism underlying this differentiation represents a critical geological factor constraining hydrocarbon exploration. In this study, analyses on total hydrocarbon chromatography and biomarker were systematically performed. Based on the differential distribution of crude oil physical properties, the genetic mechanism of spatial differentiation was investigated, and an oil accumulation model for the Mabei area was established. The results show that the chemical composition of crude oil is the fundamental cause of physical property variations. Differences in depositional environment and thermal maturity of source rocks give rise to variations in chemical composition. In addition, multi-stage charging, mixing, and biodegradation further complicate the physical properties of crude oil. The Triassic crude oil in the sag and slope zones features low density, low viscosity, high wax content, and a high freezing point. It has a high proportion of saturated hydrocarbons and a low content of isomeric branched alkanes, indicative of predominantly high-mature oil. This oil was sourced from the high-maturity source rocks of the Fengcheng formation in the sag, migrated upward along faults, and accumulated in shallow reservoirs. The Permian crude oil in the slope zones and the conventional crude oil in the fault zones is characterized by high density, high viscosity, low wax content, and low freezing point. These oils have low saturated hydrocarbon content but abundant isomeric branched alkanes, and are dominated by mature oil, with a minor proportion of high-mature oil. Specifically, the mature oil originated from the source rocks of the Fengcheng formation in the fault and slope zones, forming reservoirs through vertical near-source migration or in-situ accumulation. The high-mature oil, which occurs only in the fault zones, is interpreted to have been sourced from both the Fengcheng and Jiamuhe formations, with lateral migration as the primary transport mechanism. The shallow heavy oil in the fault zones, buried at depths of less than 1,500 m, has a high freezing point and was mostly subjected to biodegradation. Table and Figures | Reference | Related Articles | Metrics

Select

Xinjiang Petroleum Geology    2026, 47 (4): 0-0.   Abstract （24）      PDF（pc） （93935KB）（11）       Knowledge map    Save Related Articles | Metrics

Select

A Technique for Identifying and Quantitatively Characterizing Dominant Flow Channels Based On Ensemble Kalman Filter TIAN Jinjie, WANG Chengsheng, CHEN Weiyu, HU Xue, YIN Yanjun, WANG Jinlin, CHEN Shijia, FANG Yueyue, ZHANG Yanhui Xinjiang Petroleum Geology    2026, 47 (4): 459-465.   DOI: 10.7657/XJPG20260409 Abstract （23）   HTML （1）    PDF（pc） （1692KB）（10）       Knowledge map    Save Identification of dominant flow channels is a critical step in oilfield development. Conventional studies on interwell dominant flow channels require data that are difficult to acquire, in addition to complex operations and high costs. Moreover, conventional numerical simulation methods employ grid-based complex geological models which feature burdensome data loading and long computation cycle. To quickly identify dominant flow channels, an interwell connectivity inversion model was established based on a capacitance resistance model for production (CRMP), and the injection-production data transmission relationship was constructed using connectivity coefficient and time constant. The ensemble Kalman filter (EnKF) was used as an optimization algorithm for automatic history match of production data, enabling quantitative characterization of interwell connectivity. The average permeability between wells and oil saturation at well points were calculated using the principle of hydroelectric similarity principle, fractional flow equation, and relative permeability curve. An oil saturation field map was plotted to characterize the dynamic production process of oilfield. The standard for dividing dominant flow channels was developed using the K-means algorithm, and multidimensional clustering analysis was conducted on connectivity coefficient and production data to achieve intelligent identification of dominant flow channels. Finally, the proposed model was applied to actual oil reservoirs. In this application, the noise effects of data and the model were considered, and multiple sets of parameters were updated simultaneously through data assimilation during the model training. The average value was taken as the optimal solution, thereby avoiding the ambiguity in results. The results indicate that the CRMP- and EnKF-based model accurately delineates the spatial distribution of dominant flow channels, and also reduces the uncertainty of reservoir parameter inversion. Actual reservoir applications demonstrate basically identical oil saturation fields inverted by CRMP and obtained by numerical simulation. The effects of data update and parameter convergence are significant, and the obtained connectivity coefficient agrees well with the tracer results, reaching 83%. The findings prove that the proposed technique is of great significance for decision-making in future waterflooding, profile control and well selection in oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Macrolithotype Identification and Sedimentary Environment Analysis of Coal Seam No. 8 in Benxi Formation, Ningqing Block, Western Ordos Basin CHEN Zhaobing, NIU Senkai, YUAN Bochao, ZHANG Yufei, XU Wanglin, LIU Feng, LIU Hanlin, CHEN Qing Xinjiang Petroleum Geology    2026, 47 (4): 404-415.   DOI: 10.7657/XJPG20260403 Abstract （50）   HTML （5）    PDF（pc） （3976KB）（10）       Knowledge map    Save In the eastern Ordos Basin, the coal seam No. 8 in the Carboniferous Benxi formation has been extensively developed for coal-rock gas. In the Ningqing block of the western Ordos Basin, however, the coal seams are typically thin, compositionally complex, and sedimentologically intricate, which has hindered their exploration and development. Using microscopic experiments such as proximate analysis, maceral analysis, and elemental analysis in combination with elemental logging and conventional logging data, this study analyzed the coupling relationships between measured data and sensitive logs. Subsequently, the macrolithotype and log-based identification criteria for the coal seam No. 8 in the Benxi formation in the Ningqing block were established. On this basis, sensitive elemental analysis was performed to reconstruct the coal-forming paleoenvironment, and maceral analysis was conducted to define a coal facies calibration index. The sedimentary facies distribution of the coal seam No. 8 was finely characterized, and the corresponding sedimentary facies model was constructed. Proximate analysis results indicate that, for the coal seam No. 8 in the Benxi formation of the Ningqing block, the fixed carbon and ash contents exhibit the strongest coupling with the density (DEN) log. In terms of macrolithotype, semi-dull coal is dominant, followed by semi-bright and dull coal, with bright coal being underdeveloped. Both total sulfur and inorganic sulfur contents exhibit a decrease-increase-decrease-increase cyclic pattern, indicating four sea-level fluctuations during the depositional period. Paleoenvironmental analysis based on elemental logging data indicates that the target interval was deposited in an environment alternating between weakly oxidizing and weakly reducing conditions, with primarily freshwater to brackish water and in a warm, humid paleoclimate, and recorded typical marine-continental transitional facies. Coal facies classification criteria were established based on macrolithotype, industrial components, and lithofacies associations. Accordingly, the facies of the coal seam No. 8 in the study area are categorized into three types: shallowly inundated herbaceous marsh and wetland herbaceous marsh dominantly under continental conditions in the central-northern region, and open-water swamp dominantly under marine conditions in the southern region. Moreover, a sedimentary facies model for the coal seam No. 8 in the Ningqing block was established. The research findings provide a basis for the exploration of coal-rock gas in the western Ordos Basin. Table and Figures | Reference | Related Articles | Metrics

Select

Study on the Impact of Natural Zeolites on Reservoir Development by Simulating Parameters of Synthetic Zeolites PAN Lang, JIA Chunming, KUANG Hao, YU Haitao, LYU Houkuan, XIA Fang, LI Gege Xinjiang Petroleum Geology    2026, 47 (4): 435-442.   DOI: 10.7657/XJPG20260406 Abstract （24）   HTML （2）    PDF（pc） （9836KB）（9）       Knowledge map    Save Due to complex geological conditions and technical limitations, the migration of metal cations, changes of energy and other processes during the diagenesis of zeolite cement in deep reservoirs are difficult to quantify. Previous studies have compared the genesis of natural and synthetic zeolites, but most have focused on a single type; therefore, systematic comparisons on the genetic conditions among different zeolite types remain lacking. This study examines the Permian volcaniclastic-rich sandy conglomerate reservoirs in the Shawan sag of the Junggar Basin. Using microscopic methods such as thin section observation, scanning electron microscopy (SEM), and energy-dispersive spectroscopy (EDS), natural and synthetic zeolites of the same type were compared for their compositional and structural characteristics. The formation processes of natural and synthetic zeolites were compared based on the genetic conditions of synthetic zeolites. The paper preliminarily revealed the diagenetic conditions of natural zeolite and identified the genetic mechanisms and abnormal growth processes of zeolite cements, as well as the controlling factors for different zeolite phases. The results show that natural and synthetic zeolites are similar in formation temperature, pH value, and Si/Al ratio, and are also highly similar in chemical composition, crystal morphology, and structure. Furthermore, the dissolution of volcanic glass increases the concentration of OH- ions, which in turn raises the salinity and alkalinity of pore water, promoting the formation and abnormal growth of zeolite cement and controlling the formation of different zeolite phases. Zeolite transformation is mainly influenced by the compositional differences of volcanic materials and the dissolution of volcanic glass. Table and Figures | Reference | Related Articles | Metrics

Select

Well-Seismic Integrated Prediction of High-Pressure Brine Layer and Pore Pressure in the Shengjinkou Formation of Huxi Anticline, Junggar Basin LI Jianguo, ZOU Lingzhan, XU Xinniu, RUAN Biao, HUANG Hong, YIN Hongcheng, XI Chuanming, XU Xiaolong Xinjiang Petroleum Geology    2026, 47 (4): 443-450.   DOI: 10.7657/XJPG20260407 Abstract （27）   HTML （1）    PDF（pc） （7367KB）（9）       Knowledge map    Save High-pressure brine layers were encountered while drilling in the Shengjinkou formation of the Huxi anticline, Junggar Basin. The coexistence of kicks and lost circulation restricted drilling rate. Therefore, it is necessary to accurately predict the 3D distribution and pore pressure of these high-pressure brine layers. This study adopts well-seismic integration and “point-to-volume” prediction approach based on drilling, mud logging, well logging, and seismic data. The genesis of high-pressure brine layers was analyzed using seismic and structural characteristics at well sites. The pore pressure was predicted based on the correlation between pore pressure equivalent density and seismic trace integral interval attributes. The results show that the high-pressure brine layers in the Shengjinkou formation of the Huxi anticline originate from water-bearing fault-fracture bodies sealed by tight layers, and their distribution correlates with the distance from faults. Low pore pressure zones in the high-pressure brine layers occur at the edges of fault damage zones, where water invasion risk is low. In contrast, high pore pressure zones are located in the fault-fracture areas and the central parts of fault damage zones, where water invasion risk is high. These findings provide a basis for decision-making in risk identification, prevention and control, precise pressure control, and pressure reduction via drainage. Table and Figures | Reference | Related Articles | Metrics

Select

Prediction of Favorable Zones in Low-Permeability Reservoirs Based on Classification of Diagenetic Facies：A Case Study of the Yan-9 Member in the H65 Block，Ordos Basin LIU Ting, WEI Tao, DUAN Xiaochen, CHEN Yulongzhuo, WU Dezhi, ZHU Yushuang Xinjiang Petroleum Geology    2026, 47 (4): 416-424.   DOI: 10.7657/XJPG20260404 Abstract （29）   HTML （2）    PDF（pc） （16294KB）（8）       Knowledge map    Save There is a close relationship between diagenetic facies and distribution of high-quality reservoirs. Logging interpretation of diagenetic facies is crucial for predicting favorable zones in low-porosity and low-permeability reservoirs. The diagenetic facies were classified after analyzing the data of cast thin sections, scanning electron microscopy (SEM), high-pressure mercury intrusion (HPMI), and physical property tests. Using logging data, the diagenetic facies were classified across the study area from the prospective of coring wells, full hole of individual wells, and target intervals by integrating the Fisher discriminant method with the dominant facies method. On this basis, the favorable zones were predicted. The results show that the ninth member of the Lower Jurassic Yan’an formation (Yan-9 member) in the H65 block of the southern Tianhuan depression, is represented by low-porosity and low-permeability, fine-pore and fine-throat reservoirs. These reservoirs are dominated by lithic quartz sandstone, with low cement content. The storage space is mostly composed of feldspar dissolved pores-intergranular pores, with uneven distribution of pore throats and poor connectivity. In the diagenetic transformation stage, compaction led to a significant reduction in porosity, by a rate up to 44.57%, thus being the main destructive factor. In contrast, dissolution improved the porosity only by 3.01%, suggesting a limited contribution to the optimization of pore throat connectivity and the expansion of storage space. Six types of diagenetic facies are identified in the study area, including intergranular pore facies, feldspar dissolved pore-intergranular pore facies, feldspar dissolved pore facies, kaolinite cementation facies, carbonate cementation facies, and mechanical compaction facies. Based on the classification of diagenetic facies by using the Fisher discriminant method across the study area, it is believed that the central and central-southern parts of the study area hold favorable conditions of diagenetic facies for oil and gas accumulation, and thus can be considered as the targets for subsequent exploration. The results demonstrate that the Fisher discriminant method is highly accurate in classifying diagenetic facies, thereby facilitating the prediction of favorable zones in low permeability reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

NMR-Based Insights into Displacement Characteristics and Mechanisms of High-Pressure Waterflooding in Low-Permeability Reservoirs WU Jiqiang, HUANG Shijun, ZHANG Shuang, WANG Yang Xinjiang Petroleum Geology    2026, 47 (4): 472-480.   DOI: 10.7657/XJPG20260411 Abstract （28）   HTML （2）    PDF（pc） （1736KB）（8）       Knowledge map    Save Understanding the displacement characteristics and mechanisms of high-pressure waterflooding is critical to improving oil recovery in low-permeability reservoirs. In this study, laboratory experiments were conducted on core samples from typical low-permeability reservoirs. The experiments were performed using T2 spectra and T1-T2 two-dimensional NMR techniques under different injection parameters and displacement modes, in order to quantitatively evaluate the mobilization of crude oil and occurrence of residual oil in pores of various scales. Moreover, two-dimensional NMR analysis was performed to further reveal the oil-water distribution across pore sizes and its evolution during displacement. The results demonstrate that oil recovery has been improved significantly-by up to 14.38% and 8.05%, respectively-under elevated injection pressure and rate, primarily due to enhanced mobilization of oil in macropores. An additional recovery of 10.94% was achieved when high-pressure waterflooding was applied after imbibition, further mobilizing residual oil in macropores. These results identify injection pressure and rate as the dominant parameters governing the recovery enhancement by waterflooding in low-permeability reservoirs. It is recommended to combine high-pressure waterflooding with high-rate water injection, along with the coupling of soak imbibition and high-pressure waterflooding. This treatment is expected to effectively reduce residual oil saturation and improve oil recovery. The study provides theoretical support to the optimization of waterflooding process in low-permeability reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Machine Learning-Based Prediction Model of Bottomhole Flowing Pressure in Condensate Oil and Gas Wells LIU Tianyu, ZHAO Haiyong, WU Lili, MA Li Xinjiang Petroleum Geology    2026, 47 (4): 481-487.   DOI: 10.7657/XJPG20260412 Abstract （32）   HTML （2）    PDF（pc） （1564KB）（7）       Knowledge map    Save During production of condensate gas, there is a gas-to-liquid phase transition along with temperature and pressure changes in wellbores. This phenomenon results in low accuracy of conventional bottomhole flowing pressure (BHFP) calculation methods such as empirical formula and the modified H-B algorithm. To address this problem, a BHFP prediction model based on machine learning (ML) algorithms including BP neural network and LightGBM was proposed. Using 1,536 measured datasets from 24 wells, followed by normalization, noise removal, and correlation analysis, the modified H-B algorithm, BP neural network, and LightGBM algorithm were employed for modeling. The results show that the histogram-based splitting and feature binding techniques of LightGBM can significantly reduce the computational complexity and improve the fitting accuracy, with the correlation coefficient up to 0.9893, and the mean absolute error (MAE) of 86.5% lower than the modified H-B algorithm. A quantitative analysis was conducted on the main factors controlling BHFP prediction, suggesting gas production as the most prominent factor. Based on the accurate fitting of BHFP, the proposed model was extended to condensate gas wells without pressure-measurement conditions, and it accurately identified two production wells at high-risk pressure points of retrograde condensation. Specifically, for Well A6, the production regime was adjusted by increasing the wellhead tubing pressure by 2.73 MPa, which ultimately led to an increase in the daily gas production by more than 2,000 m3/d, and in the gas productivity index by 31.6%. This performance validated the effectiveness of the proposed model in identifying high-risk wells and guiding optimization of production regime. It is concluded that the ML-based BHFP prediction model can efficiently quantify the multiphase flow behaviors in wellbores, providing reliable technical support for adjusting the production regime of condensate gas reservoirs and controlling retrograde condensation pollution. Table and Figures | Reference | Related Articles | Metrics

Select

Random Forest-Based Quantitative Evaluation Method for Reservoir Heterogeneity: A Case Study of Ngs4 and Ngs5 Reservoirs of Upper Guantao Formation in Chengbei 84 Well Area SUN Tingbin, WANG Ling, WANG Kaipeng, LI Ensheng, LIU Changhui, WANG Zichuan, ZHAO Rongqi Xinjiang Petroleum Geology    2026, 47 (4): 496-505.   DOI: 10.7657/XJPG20260414 Abstract （29）   HTML （2）    PDF（pc） （1695KB）（7）       Knowledge map    Save The sand groups 4 and 5 of the upper Guantao formation (Ngs4 and Ngs5) in the Chengdao oilfield, Bohai Bay Basin, represent meandering river deposits, and exhibit rapid reservoir sedimentary facies transition. Reservoirs in the upper Guantao formation are found with pronounced interlayer and planar heterogeneities. Based on two dimensions of reservoir quality and spatial distribution, four evaluation index systems comprising basic parameters, intralayer heterogeneity parameters, interlayer heterogeneity parameters, and planar heterogeneity parameters respectively were established. Employing the Random Forest algorithm, the importance of each parameter to heterogeneity was quantified. Subsequently, basic composite index and intralayer/interlayer/planar heterogeneity composite indexes were calculated, a formula for calculating reservoir heterogeneity composite index was designed, and the reservoir heterogeneity composite index was yielded. The results indicate that a higher heterogeneity composite index reflects a weaker reservoir heterogeneity. Table and Figures | Reference | Related Articles | Metrics

Select

Combined Huff-and-Puff With Oxygen-Reduced Air and Nano-Sized Oil Displacement Agent for Horizontal Well Depletion-Drive Development in Ultra-Low Permeability Reservoirs LI Gang, MENG Baofeng, JIA Zhiwei Xinjiang Petroleum Geology    2026, 47 (4): 466-471.   DOI: 10.7657/XJPG20260410 Abstract （26）   HTML （1）    PDF（pc） （1572KB）（5）       Knowledge map    Save CO2 huff-and-puff is considered as the most promising and effective enhanced oil recovery technique for depletion-drive development of ultra-low permeability reservoirs. Nonetheless, due to the limitations such as injection modes, gas costs, and safety/environmental concerns, it is urgent to find new huff-and-puff strategies for horizontal well depletion-drive development of these reservoirs. The alternating injection of nano-sized oil displacement agent and oxygen-reduced air not only leverages the oil displacement mechanisms of nanoparticles and gas, but also generates a distinctive synergistic effect. In this study, laboratory experiments were conducted to evaluate the oil displacement mechanisms of oxygen-reduced air and nano-sized oil displacement agent, and molecular simulation was employed at the microscopic level to investigate the synergistic effect of the combined huff-and-puff with oxygen-reduced air and nano-sized oil displacement agent. Then, reservoir engineering methods and numerical simulations were adopted to optimize key parameters including huff-and-puff timing, injection volume, injection rate, and soaking time. Finally, field tests were performed at horizontal wells C-H1 and D-H2 in the Z area. The tests revealed a cumulative incremental oil production of 4,526.7 tons and an input-output ratio exceeding 1∶2.5, demonstrating satisfactory huff-and-puff and displacement performance. The proposed combined huff-and-puff with oxygen-reduced air and nano-sized oil displacement agent provides a practical guidance for late-stage energy replenishment in horizontal well depletion-drive development of ultra-low permeability reservoirs. Table and Figures | Reference | Related Articles | Metrics

Select

Stratigraphic Boundaries in the Mesozoic Volcanic Rocks in the Bohai Bay Basin: Types and Influence on Reservoirs WANG Liying, WANG Jiage, HUANG Feifei, WANG Fang Xinjiang Petroleum Geology    2026, 47 (4): 425-434.   DOI: 10.7657/XJPG20260405 Abstract （24）   HTML （2）    PDF（pc） （15742KB）（5）       Knowledge map    Save Volcanic rock reservoirs are complex in distribution, and especially the relationship between volcanic rock stratigraphic boundary and reservoir distribution remains unclear. Based on the data of field volcanic edifice sections, drilling, logging, elements, and thin sections, the stratigraphic boundaries in the Mesozoic volcanic rocks in the Bohai Bay Basin were identified, and their types and characteristics were clarified, and the influence of these stratigraphic boundaries on reservoirs was investigated. The results indicate that long-term, medium-term, and short-term exposed stratigraphic boundaries associated with eruptive unconformity are identified in the Mesozoic volcanic rocks in the Bohai Bay Basin. The long-term exposed stratigraphic boundaries reflect obvious angular unconformities in seismic data. In contrast, the medium-term and short-term ones exhibit remarkable signatures on electrical and elemental logs due to the presence of sedimentary interlayers and thin weathering crusts. These signatures are mainly manifested in decreased resistivity, lower density, increased acoustic travel time, and higher neutron porosity near the stratigraphic boundaries, as well as gradual increases in contents of elements such as Ca, Ti, Fe, Mg, P, and Mn. The stratigraphic boundaries exert differential control on volcanic rock reservoirs. Specifically, the long-term exposed stratigraphic boundaries control the weathering crust reservoirs (mostly 150-300 m thick) at the top of buried hills; below the medium-term exposed stratigraphic boundaries, intra-buried-hill reservoirs with thickness of 30-50 m are found; and beneath the short-term exposed stratigraphic boundaries, there are intra-buried-hill reservoirs, with thickness of 10 m or up to 50 m individually. A model of reservoir development controlled by 3 stratigraphic boundaries was established. It is recognized that the volcanic rock reservoir exhibit a multi-layered stacking architecture. The study provides a basis for the shift of exploration from weathering crust at the top of buried hills to reservoirs within buried hills. Table and Figures | Reference | Related Articles | Metrics

Select

Quantitative Interpretation of Gas Saturation in Paleozoic Gas Reservoirs in the Ordos Basin: Taking Well A Area in the Southeastern Yishaan Slope as an Example CHEN Zhanjun, REN Zhanli, GAO Xiaoping, LIU Baoping, YU Chunyong, HAO Qianqian, WANG Fuyuan Xinjiang Petroleum Geology    2026, 47 (4): 451-458.   DOI: 10.7657/XJPG20260408 Abstract （25）   HTML （1）    PDF（pc） （1771KB）（5）       Knowledge map    Save To enhance the quantitative interpretation accuracy of fluid saturation in the Paleozoic tight sandstone gas reservoirs in the Ordos Basin, the physical and electric properties of the reservoir were analyzed, indicating a feasibility to interpret porosity, water saturation and gas saturation in sequence. The Archie formula was re-derived to obtain an equation to represent water-bearing porosity and resistivity, and the in-situ resistivity of formation water was defined, without the necessity to perform litho-electric experiments and formation water resistivity tests. On the basis of the above theory, taking the Well A area in the southeastern Yishaan slope as an example, a quantitative interpretation approach of reservoir fluid was established. Firstly, the existing basic data acquisition process and the main error causes were analyzed, and the data with the minimum fluid loss were selected as the basic data for interpreting water-bearing porosity. Then, the crossplot of water-bearing porosity and resistivity was established, and the water-bearing porosity interpretation equation was formed. Finally, according to the porosity interpretation equation and the water-bearing porosity interpretation equation, the gas saturation of reservoirs in the Well A area was quantitatively interpreted. It is found that the obtained gas saturation is highly consistent with the production results, and is 95.14% coincident with the single-layer gas test results. Compared with the results from Archie formula, the proposed interpretation approach exhibits lower technical requirements for experiments, and achieves improvements in both accuracy and resolution. This research enriches the theory for quantitative interpretation of tight sandstone gas reservoirs in the Ordos Basin, and provides reference for quantitative interpretation of tight sandstone gas reservoirs in other areas. Table and Figures | Reference | Related Articles | Metrics

Select

A 3D Quantitative Characterization Method for Fragmentation Degree of Deep Fault- Controlled Reservoirs: A Case Study of the Yijianfang-Yingshan Formation in the Shunbei Area XIA Yang, XIANG Jian, JIN Yan, CHEN Xiuping, ZHAO Zhen, HAN Zhengbo Xinjiang Petroleum Geology    2026, 47 (4): 506-514.   DOI: 10.7657/XJPG20260415 Abstract （24）   HTML （2）    PDF（pc） （4495KB）（4）       Knowledge map    Save Deep drilling in the Shunbei area is confronted with a complex geological environment where reservoirs are controlled by strike-slip fault zones. In addition, the strata in this area are highly fragmented, posing a significant risk of deep wellbore instability. However, no quantitative method is currently available to characterize the fragmentation degree, leaving the instability mechanism unclear. This paper presents a 3D quantitative method to characterize the degree of fragmentation in deep strata based on seismic data, as demonstrated by a case study of the Ordovician Yijianfang-Yingshan formation in the Shunbei area. First, an index for the degree of rock mass fragmentation was established using acoustic wave dynamics. Second, wave impedance inversion was performed on seismic data that had been processed by Gaussian filtering and normalization. Third, fault identification results from 3D seismic data were transformed into threshold-type weight function to constrain the fragmentation degree index. Finally, 3D seismic imaging technology was integrated with the time-depth relationship, together with well location, inclination, and azimuth data, to achieve spatial matching between the 3D wellbore trajectory and fragmented zones. The fragmentation degree index was then validated through laboratory experiments and individual-well logging data. The proposed method was further validated by comparison with fault identification models including edge detection and ant tracking. The predicted rock-mass fragmentation profile matches the borehole enlargement log with an agreement rate of 89% for actual wells in the Shunbei area. This method provides a reference for predicting the degree of fragmentation in deep strata. Table and Figures | Reference | Related Articles | Metrics

Select

Tight Sandstone Reservoir Prediction Based on 2D Seismic Probabilistic Deduction with Step-by-Step Constraints WANG Yong, JIA Xiurong, ZHU Yan, JIN Yunyun, XIONG Jian, XIE Chun’an, LI Hengquan, GUO Juncan Xinjiang Petroleum Geology    2026, 47 (4): 488-495.   DOI: 10.7657/XJPG20260413 Abstract （28）   HTML （2）    PDF（pc） （7989KB）（2）       Knowledge map    Save Tight sandstone of the Carboniferous Taiyuan formation in the Xunyi area represents a favorable exploration target in the southern Ordos Basin. However, it exhibits rapid variation in lithofacies and is sheltered by both the overlying continental coal rocks and the underlying marine carbonate rocks with strong reflection events, which challenge reservoir prediction. In the eastern Xunyi area covered by 2D seismic survey, seismic attribute analysis and inversion on 2D lines were often used in previous prediction of reservoir distribution, These techniques suffered from problems such as multiple solutions and low accuracy. This paper proposes a probabilistic deduction method with step-by-step constraints to predict tight sandstone reservoirs in 2D seismic areas. First, a layer-flattening procedure was applied to identify layer-thickening zones and favorable sedimentary facies zones for tight sandstones, thus setting the first-level constraint. Then, under the regional sedimentary framework, structure models of different lithologic associations were established using actual drilling data, and the seismic reflection probability type for the sandstone development area was simulated by forward modeling. Accordingly, the favorable area for tight sandstone development was determined according to the seismic response characteristics of sandstone in the favorable sedimentary facies zones. In this way, the second-level constraint was created. Finally, the wave impedance inversion was performed based on well log constraint to define sweetspots in the sandstone, achieving the third-level constraint. This three-level sandbody control approach for predicting tight sandstone reservoirs by probabilistic deduction with step-by-step constraints achieves improvements in precision (from 15 m to 10 m) and prediction coincidence (from 40% to 75%). The newly deployed exploration well encountered a tight sandstone layer of 24 m thick, recording effective support to the exploration in marine-continental transitional tight sandstone gas reservoir. Table and Figures | Reference | Related Articles | Metrics

Select

Molecular Simulation Study and Influencing Factor Analysis of Shale Gas Adsorption HU Shuyong, DONG Qi, GUO Jingjing Xinjiang Petroleum Geology    Accepted: 08 May 2026

Select

Numerical Simulation of Acid Fracturing and Analysis on Factors Influencing Fracture#br# Propagation in Deep Dolomite Reservoirs of the Tabei Area #br# YAO Wenjiea, b, ZHAO Haifenga, b, LUO Jielunb, LI Yunfu Xinjiang Petroleum Geology    Accepted: 28 July 2026