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01 April 2026, Volume 47 Issue 2 Previous Issue   

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OIL AND GAS EXPLORATION

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 2026, 47 (2):  127-136.  doi: 10.7657/XJPG20260201 Abstract ( 27 )   HTML ( 1 )   PDF (1915KB) ( 14 )   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. Figures and Tables | References | Related Articles | Metrics

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 2026, 47 (2):  137-145.  doi: 10.7657/XJPG20260202 Abstract ( 19 )   HTML ( 4 )   PDF (26996KB) ( 16 )   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. Figures and Tables | References | Related Articles | Metrics

Development Characteristics and Controlling Factors of Paleozoic Tight Sandstone Reservoirs in Xunyi Area, Ordos Basin ZHU Yan 2026, 47 (2):  146-154.  doi: 10.7657/XJPG20260203 Abstract ( 13 )   HTML ( 1 )   PDF (11045KB) ( 1 )   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. Figures and Tables | References | Related Articles | Metrics

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 2026, 47 (2):  155-162.  doi: 10.7657/XJPG20260204 Abstract ( 13 )   HTML ( 1 )   PDF (4148KB) ( 2 )   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. Figures and Tables | References | Related Articles | Metrics

Formation Mechanism and Controlling Factors of Natural Fractures in Xujiahe Formation, Puguang Area ZU Kewei 2026, 47 (2):  163-171.  doi: 10.7657/XJPG20260205 Abstract ( 16 )   HTML ( 2 )   PDF (10402KB) ( 4 )   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. Figures and Tables | References | Related Articles | Metrics

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 2026, 47 (2):  172-183.  doi: 10.7657/XJPG20260206 Abstract ( 11 )   HTML ( 1 )   PDF (7294KB) ( 3 )   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. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

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 2026, 47 (2):  184-191.  doi: 10.7657/XJPG20260207 Abstract ( 14 )   HTML ( 2 )   PDF (757KB) ( 2 )   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. Figures and Tables | References | Related Articles | Metrics

Influence of Hydraulic Fracture Morphology on the Producing Degree of CBM Reservoir LI Wenjie, WANG Hu, WU Yunli, ZHONG Jie, ZHANG Tao, ZHAO Zhihong 2026, 47 (2):  192-200.  doi: 10.7657/XJPG20260208 Abstract ( 14 )   HTML ( 1 )   PDF (2685KB) ( 4 )   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. Figures and Tables | References | Related Articles | Metrics

Development Characteristics of Fractured Horizontal Wells in Spatiotemporally Heterogeneous Shale Volatile Oil Reservoirs JIANG Liwu, DIWU Pengxiang, CHENG Chunjie, LIU Jinju 2026, 47 (2):  201-209.  doi: 10.7657/XJPG20260209 Abstract ( 22 )   HTML ( 4 )   PDF (950KB) ( 3 )   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. Figures and Tables | References | Related Articles | Metrics

Variations of Displacement Characteristics During the Whole Process of Waterflooding in Block WX-3 XU Yunheng, REN Bo, GENG Ziyuan, WU Jinbiao 2026, 47 (2):  210-221.  doi: 10.7657/XJPG20260210 Abstract ( 13 )   HTML ( 1 )   PDF (8186KB) ( 4 )   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. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

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 2026, 47 (2):  222-232.  doi: 10.7657/XJPG20260211 Abstract ( 13 )   HTML ( 1 )   PDF (8112KB) ( 2 )   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. Figures and Tables | References | Related Articles | Metrics

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 2026, 47 (2):  233-240.  doi: 10.7657/XJPG20260212 Abstract ( 15 )   HTML ( 1 )   PDF (814KB) ( 0 )   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. Figures and Tables | References | Related Articles | Metrics

Characterization and Application of Original and Developed Flow Units in Tight Oil Reservoirs ZHU Rongxing, QU Hongjun, YIN Hu, SU Shuai, YANG Xiaofeng 2026, 47 (2):  241-252.  doi: 10.7657/XJPG20260213 Abstract ( 11 )   HTML ( 1 )   PDF (4748KB) ( 2 )   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. Figures and Tables | References | Related Articles | Metrics