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01 August 2021, Volume 42 Issue 4 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Sedimentary Characteristics of Jurassic Kalazha Formation in the Thrust Belt on the Southern Margin of Junggar Basin SI Xueqiang, YUAN Bo, PENG Bo, JI Dongsheng, GUO Huajun, TANG Xueying, DOU Yang, LI Yazhe 2021, 42 (4):  389-398.  doi: 10.7657/XJPG20210401 Abstract ( 163 )   HTML ( 5 )   PDF (23587KB) ( 59 )   Save In order to clarify the characteristics of deep reservoirs in the thrust belt on the southern margin of the Junggar basin, the markers, types, distribution and models of sedimentary facies and source directions of the Jurassic Kalazha formation were analyzed based on the data of outcrops, mud logging, trace elements and heavy minerals. The result shows that the sedimentary facies of alluvial fan and braided river delta are mainly developed in Kalaza formation. Laterally three large sedimentary systems are distributed from west to east, which are the alluvial fan-braided river delta in the middle section of the Qigu fault-fold belt, the braided river delta in the Toutunhe area in the eastern section of the Qigu fault-fold belt, and the braided river delta in the Fukang fault belt. Vertically, there are four sedimentary cycles which follow a prograding sequence. The types and planar distribution of the sedimentary facies are mainly controlled by the activities of the Tianshan orogenic belt during the late Jurassic period. Sandstone reservoirs of more than 200 m thick are developed on the three large sedimentary systems. Especially, the sandstone reservoirs in the braided river delta front are very sortable, thick and widely distributed, which match well with the deep large anticline and can be favorable exploration targets. Figures and Tables | References | Related Articles | Metrics

Formation and Evolution of Hydrothermal Karst and Hydrocarbon Distribution in Halahatang Area NING Chaozhong, LI Yong, DENG Xiaojuan, CHEN Jiaheng, WANG Xiaoming, SUN Zhao, HAN Yongquan 2021, 42 (4):  399-409.  doi: 10.7657/XJPG20210402 Abstract ( 344 )   HTML ( 9 )   PDF (15562KB) ( 145 )   Save The Ordovician carbonate reservoir in Halahatang oilfield is the primary contributor to high and stable production of Tarim Oilfield Company. However, it has been difficult to study its forming mechanism, forming period, and oil and gas distribution. Based on geophysical data, core and slice observation, analysis of geochemical and production data, etc., the characteristics of the hydrothermal karst in the Halahatang area have been studied, the forming period of the hydrothermal karst has been determined, and the controls of the active faults formed in the Hercynian movement and the strike-slip faults formed in the Caledonian movement on the distribution of the hydrothermal karst and hydrocarbon are clarified. The study results show that magmatic activities, active faults in the Hercynian movement period, and hydrocarbon accumulation in hydrothermal karst mainly occurred in the Permian, and they are similar in timing and successive in origin. There are differences between the Hercynian active faults and the Caledonian strike-slip faults in terms of mechanical properties, occurrence, scale, distribution, and controls on hydrothermal karst. Hydrocarbon can effectively accumulate in the hydrothermal karst on the strike-slip faults in the Caledonian movement period, while hydrocarbon can not or poorly accumulate in the hydrothermal karst on the active faults in the Hercynian movement period due to the influences of the openning and intermitting of faults during the hydrocarbon accumulation period. As a result, the distribution of the hydrocarbon in the Ordovician strata in the east of the Halahatang area greatly differs from that in the west. During petroleum exploration and well allocation, it is necessary to differ the Caledonian strike-slip faults from the Hercynian active faults, and then take the hydrothermal karst on the strike-slip faults as the exploration target. Figures and Tables | References | Related Articles | Metrics

Quantitative Characterization and Classification of Pore Structures in Chang 4+5 Member in Block Hu-154, Ordos Basin DING Qiang, CHENG Jian, YANG Bo, JIN Zixin, LIU Fei, ZHAO Ziwen, YU Jingwei 2021, 42 (4):  410-417.  doi: 10.7657/XJPG20210403 Abstract ( 292 )   HTML ( 6 )   PDF (5006KB) ( 242 )   Save In Block Hu-154 of Hujianshan oilfield in the Ordos basin, the reservoirs of Chang 4+5 member in the Triassic Yanchang formation are of low porosity and low permeability, and there are few researches on the pore structures of the reservoirs and detailed quantitative analysis, which may be the cause for the rapid production decline and less waterflooding control in this block. Based on the data of cores, slices, cast thin sections, SEM, high-pressure mercury intrusion and phase permeability experiments, quantitative characterization and classification of the pore structures have been carried out, and the plane distribution of the pore structures has been studied by combining with well logging curves in the study area. The results show that residual intergranular pores and flake-like and curved flake-like throats are dominant in the Chang 4+5 member in the study area. According to the structure, the pores can be divided into three types: (1) Type Ⅰ pores: the fractal dimension is 2.57~2.61, the average displacement pressure is 1.62 MPa and the oil production rate is over 2 t/d; (2) Type Ⅱpores: the fractal dimension is 2.61~2.66, the average displacement pressure is 2.61 MPa and the oil production rate is higher than 1~2 t/d; (3) Type Ⅲ pores: the fractal dimension is 2.66~2.71, the average displacement pressure is 3.52 MPa and the oil production rate is lower than 1 t/d. Reservoirs with Type II and III pores are distributed on a large scale, and the pore structure in the Chang (4+5)2 is better than that in the Chang (4+5)1 in the study area. Figures and Tables | References | Related Articles | Metrics

Classification and Genesis of Fine-Grained Sedimentary Rocks of Qingshankou Formation in Songliao Basin DING Cong, SUN Pingchang, WANG Chang, ZHANG Ying, ZHANG Qing 2021, 42 (4):  418-427.  doi: 10.7657/XJPG20210404 Abstract ( 109 )   HTML ( 0 )   PDF (14887KB) ( 41 )   Save The Qingshankou formation in the Songliao basin belongs to thick fine-grained sedimentary rock, and it is an important interval for shale oil and gas accumulation. The classification of the fine-grained sedimentary rocks is the key premise for exploring unconventional oil and gas. Based on field survey and systematic sampling analysis, we studied the types, sedimentary environment and geochemical characteristics of the fine-grained sedimentary rock of the Qingshankou formation in the Songliao basin. According to TOC and the contents of carbonate and terrigenous clastic minerals, the fine-grained sedimentary rocks in the study area can be classified into fine-grained terrigenous clastic rocks with extremely poor, poor, moderate and rich organic matters, and fine-grained terrigenous carbonate rocks with poor and extremely poor organic matters. The fine-grained terrigenous clastic rocks with rich and moderate organic matters and the fine-grained terrigenous carbonate rocks with poor organic matter were deposited in a semi-deep lake environment with stiller water; the fine-grained terrigenous clastic rock with poor and extremely poor organic matters and the fine-grained terrigenous carbonate rock with extremely poor organic matters were deposited in a shallow lake environment; and carbonate rock was mainly deposited in an open saline lake basin in temperate to subtropical zones. The primary type of organic matters in the fine-grained sedimentary rocks is Type Ⅱ1. The fine-grained sedimentary rocks are medium-good quality source rocks. The fine-grained terrigenous clastic rocks with rich and poor organic matters in deep formations are primary targets for shale oil and gas exploration. Figures and Tables | References | Related Articles | Metrics

Sedimentary Characteristics of Glutenites of Sha 3 Member in Block Tuo 826, Dongying Sag MIN Wei 2021, 42 (4):  428-436.  doi: 10.7657/XJPG20210405 Abstract ( 276 )   HTML ( 6 )   PDF (1448KB) ( 180 )   Save Based on core observation, grain size analysis, thin section identification, well logging and seismic data interpretation and other methods, the sedimentary characteristics of E2s13 (the glutenites in the upper section of the Sha 3 member of the Shahejie formation) were studied in Block Tuo 826 in the northern steep slope zone of the Dongying sag in the Bohai Bay basin. The results show that although both the glutenites from the eastern and the western E2s13 are close to the parent rock, but their compositions, textures and structures are obviously different from each other due to different provenances and transport mechanisms, and as a result, their reservoir physical properties are different too. The eastern glutenite is dominated by tractive current deposits with good sorting and relatively high original porosity, and supported by grains, while the western glutenite is mainly composed of gravity flow deposits with poor sorting and relatively low original porosity, and supported by matrix. The E2s13 glutenites deposited in fan delta fronts have two sediment transport pathways (one is the eastern Z366 secondary paleo-gulley and the other is the western Z361-Z364 secondary paleo-gulley), and composite lobes with larger differences in lithology and physical properties form, which include 5 microfacies, i.e., debris flow deposit, underwater braided channel, interdistributary bay, mouth bar and sand sheet, among which the underwater braided channel and the sand sheet are developed, and the debris flow deposits are more developed in the western part of the study area. From bottom to top, the fan delta generally show a retrograding to prograding cycle. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Inter-Fracture and Inter-Section Interference Modeling for Staged and Clustered Fracturing Stimulation in Horizontal Wells: A Case Study on Reservoirs of Badaowan Formation in Wellblock Ji 7 in Changji Oilfield CHENG Ning, GUO Xuyang, WEI Pu, HUANG Lei, WANG Liang 2021, 42 (4):  437-443.  doi: 10.7657/XJPG20210406 Abstract ( 289 )   HTML ( 13 )   PDF (638KB) ( 264 )   Save In developing the reservoir of the Badaowan formation in Wellblock Ji 7 in Changji oilfield, the results of hydraulic fracturing stimulation in vertical wells are unsatisfactory, and the post-fracturing productivity is limited, so that it is necessary to apply multi-stage fracturing stimulation in horizontal wells. According to the geomechanical characteristics of the reservoir in the Badaowan formation in Wellblock Ji 7, a non-planar artificial fracture propagation model was established using the extended finite element method. By taking into account inter-fracture interference while multiple clusters of fracture propagating simultaneously and the inter-section interference during staged fracturing stimulation, the model characterizes the non-planar fracture propagation in horizontal wells drilled in the Badaowan formation in Wellblock Ji 7. The results show that the inter-fracture interference induced in a section inhibits the half-length of middle fracture clusters, but makes a wider and longer half-length of the fractures on both sides; the inter-fracture interference and the inter-cluster interference make fracture propagation non-planar, and show a certain curvature in geometrical morphology. According to comparative analysis of fracturing data and microseismic data, the modeling results are consistent with the measured data, proving that good application results have been obtained in target zones. A multi-stage fracturing test was carried out in the Badaowan formation in a horizontal well in Wellblock Ji 7. The daily post-fracturing oil production of the horizontal well was 7.8 times that of a vertical well in the same well block, indicating a significant development effect. Figures and Tables | References | Related Articles | Metrics

Occurrence Laws of Microscopic Remaining Oil in High Water-Cut Reservoirs：A Case Study on Blocks Xiaoji and Gangxi in Dagang Oilfield LI Yiqiang, ZHANG Jin, PAN Deng, YAN Yun, LIU Mingxi, CAO Han, GAO Wenbin 2021, 42 (4):  444-449.  doi: 10.7657/XJPG20210407 Abstract ( 362 )   HTML ( 6 )   PDF (5347KB) ( 268 )   Save In order to describe the microscopic distribution of remaining oil in high water-cut reservoirs during the late development stage, and guide subsequent fine development of remaining oil in blocks Xiaoji and Gangxi in Dagang oilfield, remaining oil data was observed under an ultraviolet fluorescent stereo microscope and then was processed, and finally the distribution of the remaining oil is divided into three levels, namely, weak sweep, medium sweep and strong sweep, and the occurrence states of the remaining oil are divided into five types, namely, cluster shape, pore-surface film shape, slit shape, corner shape and intergranular adsorption. In the high water-cut stage, the content of the remaining oil in different occurrence state is in the order of cluster, pore-surface film, corner, intergranular adsorption to slit shapes from high to low. After poly/surface compound flooding, remaining oil occurrences like clusters and pore-surface films are dominant. Such remaining oil could be exploited by improving rock wettability. The distribution of remaining oil in conglomerate is more complex than that in sandstone. Remaining oil in sandstone are almost distributed as clusters and intergranular adsorption, which can be exploited by controlling the fluidity of injected fluid. Figures and Tables | References | Related Articles | Metrics

Evaluation of Injection-Production Effect of Chang 63 Ultra-Low Permeability Reservoir in Jiyuan Oilfield SU Zezhong, WU Desheng, LIU Liang, ZHU Jianhong, LIU Xiong 2021, 42 (4):  450-455.  doi: 10.7657/XJPG20210408 Abstract ( 223 )   HTML ( 5 )   PDF (576KB) ( 215 )   Save The Chang 63 reservoir in Jiyuan oilfield is an ultra-low permeability reservoir. As an effective displacement pressure system is difficult to form in the existing well pattern and the reservoir tends to be depleted, it is urgent to evaluate the injection-production effect of the existing well pattern and provide technical support for subsequent adjustment on well pattern infilling. Therefore, nine indexes for evaluating injection-production effect were selected, including reserves control degree of water flooding, pressure maintenance level, injection-production static pressure difference, flood response ratio, water breakthrough ratio, single-well productivity over two years, reserves producing degree of water flooding, sweep coefficient of water flooding, and dynamic recovery rate. Comprehensive weights were introduced to establish an injection-production effect evaluation model for well pattern in ultra-low permeability reservoirs based on unascertained measurements, helping to evaluate the injection-production effect of Chang 63 reservoir in the study area. The evaluation results show that the injection-production effect of the well pattern in this reservoir is poor, and the well pattern needs to be adjusted immediately. The evaluation results are consistent with the current production status of the reservoir, which proves the accuracy of the evaluation model, and provides a new idea or method for evaluating injection-production effect of existing well pattern in ultra-low permeability reservoirs. Figures and Tables | References | Related Articles | Metrics

Feasibility of Supercritical CO2 Huff-Puff Development of Tight Conglomerate Reservoirs PU Wanfen, WANG Yangsong, LI Longwei, GAO Haiming, SHAN Dongbai, WANG Wenke 2021, 42 (4):  456-461.  doi: 10.7657/XJPG20210409 Abstract ( 125 )   HTML ( 3 )   PDF (573KB) ( 75 )   Save CO2 huff-puff development has unique mechanisms such as dissolution, extraction and miscibility and supercritical CO2 has better injectivity, penetrability and extraction of light components. In order to further understand the feasibility of supercritical CO2 huff-puff in enhancing oil recovery of tight conglomerate, based on supercritical CO2 crude oil interaction, supercritical CO2 crude oil extraction experiment and supercritical CO2 huff-puff indoor physical simulation, oil property changes and stimulation mechanism during huff-puff process were revealed, and the recovery factors obtained with different injection parameters were determined. The results show that supercritical CO2 can effectively supplement formation energy, reduce viscosity and density of crude oil, and improve mobility of crude oil. The recovery factor was improved by 22.16% after injecting 0.50 PV of supercritical CO2; with the increase of supercritical CO2 injection rate, the recovery factor increased but the replacement ratio decreased. Compared with the single round stimulation, the recovery efficiency of the four-round huff-puff can be increased by 20%~24%. The recovery factor was 22.16% after soaking for 120 minutes, but changed little after soaking for 240 minutes. The findings demonstrate that it is feasible to enhance the recovery by implementing supercritical CO2 huff-puff development after depletion development in tight conglomerate reservoirs, which provides a reference to the development of tight conglomerate reservoirs. Figures and Tables | References | Related Articles | Metrics

Fire Front Prediction and Injection-Production Parameter Optimization for Block Gao 3618, Liaohe Oilfield JIANG Yi, YU Gaoming, XIN Xiankang, WANG Lixuan, ZHANG Fengfeng, CHEN Minggui 2021, 42 (4):  462-468.  doi: 10.7657/XJPG20210410 Abstract ( 289 )   HTML ( 11 )   PDF (654KB) ( 174 )   Save Affected by factors such as reservoir heterogeneity, well interference and pore blockage, the fire front advances unevenly, and results in unsatisfactory fire flooding development of the Block Gao 3618 in Gaosheng heavy oil reservoir of Liaohe oilfield. Therefore, physical experiments on simulating fire flooding process were carried out to understand the temperature limit of crude oil in different oxidation stages, kinetic parameters were revised using the Arrhenius equation, and a well connectivity model was established on the basic well pattern to quantitatively characterize the connectivity between injection and production wells. The rationality of the connectivity model was verified through high-temperature gas tracer simulation. The physical experiments and the model were joined together to characterize the moving trajectory of the fire front, making the fitting accuracy increase to 85%. After optimizing the injection-production parameters based on numerical simulation, the fire front was controlled, gas channeling was slowed down, the fire flooding sweep coefficient was increased and the oil recovery was enhanced. For example, the initial gas injection rate is 10,000 m3/d for Well I5-0151C2 and Well I51-156, and 10,500 m3/d for Well I5-0158C. Supposing that the monthly increase of gas injection is 3,000 m3/d, and horizontal wells produces at a fixed rate of 100 m3/d, the fire front can advance evenly after parameter optimization, the sweep coefficient can increase by 8.74%, and the recovery can increase by 6.37%. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Occurrence Characteristics of Movable Fluids in Unconsolidated Sandstone Reservoir of Toutunhe Formation in Santai Oilfield ZHANG Tong 2021, 42 (4):  469-474.  doi: 10.7657/XJPG20210411 Abstract ( 390 )   HTML ( 4 )   PDF (3041KB) ( 192 )   Save The unconsolidated sandstone reservoir in the Toutunhe formation of Santai oilfield, Junggar basin is characterized by complex pore structures, strong heterogeneity and large difference in fluid distribution. In order to clarify the occurrence characteristics of the movable fluid in the unconsolidated sandstone reservoir, typical core samples were taken from the unconsolidated sandstone reservoir, and tested on their NMR (nuclear magnetic resonance) T2 spectra before and after centrifugation, and the T2 cut-offs and saturation of the movable fluid in the reservoir were evaluated quantitatively. The results show that the pore structures in the reservoir of Tou 2 member are complex, and the pore throats are thin and poorly connected; and the T2 spectra has proved the saturation of the movable fluid ranging from 80.42% to 82.57%, with an average of 81.39%, the porosity of the movable fluid ranges from 13.91% to 17.98%, with an average of 15.88%, and the T2 cut-offs is from 1.86 to 4.64 ms, with an average of 3.06 ms. The movable fluid mainly occupy larger pores, while the bound fluid is mainly distributed in smaller pores. The best centrifugal force to the core sample is 1.02 MPa. In the samples No. 4 and No. 7 with poorly developed large pores, the saturation of the movable fluid in larger pores differs greatly from that in smaller pores after four times of centrifugation. As for the sample No. 5 with well developed large pores, increasing centrifugal force can significantly increase the saturation of the movable fluid. And when the centrifugal force is close to 1.02 MPa, which is the optimal centrifugal force, there is almost no difference in the contribution of different pores to the parameters of the movable fluid. Figures and Tables | References | Related Articles | Metrics

Heterogeneous Compound Flooding Technology for Medium-High Permeability Consolidated Reservoir After Polymer Flooding ZHANG Zhuo, WANG Zhengxin, XUE Guoqin, LI Yan, LIU Yanhua, WANG Xi 2021, 42 (4):  475-479.  doi: 10.7657/XJPG20210412 Abstract ( 232 )   HTML ( 1 )   PDF (1371KB) ( 185 )   Save The Ⅳ1-3 layers in Eocene Hetaoyuan formation in Shuanghe oilfield are characterized by high temperature and medium-high permeability. At present, the layers have entered a development stage with ultra-high water cut after polymer flooding, and it is necessary to further improve the recovery. Heterogeneous compound flooding system can effectively expand swept volume, improve oil displacement efficiency, adjust production and injection profiles, control water production and increase oil production. We studied the long-term thermal stability of the system based on viscoelasticity and interfacial activity. Using a single core, we investigated the injectability and moving style of the heterogeneous compound system in reservoir. Through a parallel core displacement experiment, we evaluated the oil displacement effect of the system. The research results show that the heterogeneous compound flooding system is viscoelastic and its elasticity is dominant. The viscosity of the heterogeneous compound flooding system is 58%~197% higher than a conventional polymer flooding system, and the elastic modulus of the former is 67%~227% higher than the latter. The interfacial tension of the heterogeneous compound flooding system is at the magnitude of 10 -3 mN/m, so it is good at displacing oil. In addition, the heterogeneous compound flooding system can keep thermal stability for a long time. For example, after 180 days of aging, the retention rates of the viscosity and the elastic modulus exceed 100%, and the interfacial tension is still at the magnitude of 10-3 mN/m. The system has good injectivity, which can further increase the recovery by 16.93% after high-strength polymer flooding. The system moves in reservoirs in ways of migrating, accumulating, plugging, and deforming to move. By displacing the residual oil bound by the capillary force in less permeable zones, the heterogeneous compound flooding system can significantly reduce oil saturation. This research expands the application of the heterogeneous compound flooding from unconsolidated oil reservoirs at low temperature, and with high porosity and high permeability to consolidated reservoirs at high temperature, and with medium to high permeability. Figures and Tables | References | Related Articles | Metrics

Experiments on Controlling Gas Channeling in Low-Permeability Reservoirs by Enhanced CO2 Foam System With Nano-Microspheres ZHAO Yunhai, WANG Jian, HUANG Weihao, ZHANG Liwei, PENG Qilin, DU Hong 2021, 42 (4):  480-486.  doi: 10.7657/XJPG20210413 Abstract ( 230 )   HTML ( 5 )   PDF (554KB) ( 186 )   Save The development of the gas-injection pilot area with small well spacing in Block Hei-46 in Jilin oilfield has entered its middle to late stage characterized by serious water channeling and gas channeling. An enhanced CO2 foam system with nanosphere particles which is composed of three phases, namely gas, liquid and solid has been tested on controlling gas channeling. The experiment results show that the optimal composition of the enhanced CO2 foam system with nano-microsphere particles includes 0.10% FA-1, 0.50% FA-2 and 0.10% M-1 (mass fraction); at different temperature and salinity the performance of the enhanced CO2 foam system is much better than a conventional CO2 foam, and the resistance factor of the former is increased by 20.03%; when the permeability difference of parallel cores is 5.80, the profile improvement rate of the enhanced foam system is 14.29% higher than that of the conventional CO2 foam; when the permeability difference of parallel cores is 4.34, the final recovery factor is 79.97%, and the enhanced CO2 foam system can increase the recovery by 15.53% based on conventional gas flooding. Figures and Tables | References | Related Articles | Metrics

Study on Meso-Structures and Flow Characteristics of Oil Sands in Qigu Formation of Fengcheng Oilfield PANG Huiwen, JIN Yan, GAO Yanfang, WANG Qiqi 2021, 42 (4):  487-494.  doi: 10.7657/XJPG20210414 Abstract ( 285 )   HTML ( 4 )   PDF (8607KB) ( 103 )   Save In order to clarify the meso-structures and flow characteristics of oil sands in the Jurassic Qigu formation in Fengcheng oilfield, a three-medium image segmenting method suitable for oil sands was proposed by using micron CT grayscale images and conventional image segmenting method. Using the new method, digital oil sand cores were obtained from physical experiments, and finally a pore network model was built. The research shows that when constructing digital oil sand cores, it is necessary to propose a three-medium image segmenting method suitable for oil sands on the basis of the binary image segmenting method for porous media, to distinguish the particles, asphaltenes and pores in oil sands. Only when the side length of the representative volume unit of a digital core is greater than 3.0 mm, it can truly reflect the meso-structures of oil sands. The contact between particle and asphaltene in the oil sands of the Jurassic Qigu formation in Fengcheng oilfield are divided into three types: particle contact, cementing contact and suspending contact. Furthermore, the oil sands are strongly heterogenous and anisotropic, and asphaltene as a part of framework or as pore fluid, its absolute permeability is about 2 orders of magnitude higher than the effective permeability. As a result, the phase state of the asphaltene significantly affects the meso-structures of the oil sands. Figures and Tables | References | Related Articles | Metrics

REVIEW

Progress and Enlightenment of EOR Field Tests in Tight Oil Reservoirs WEI Bing, ZHANG Xiang, LIU Jiang, PU Wanfen, LI Yibo, WANG Xiaochao 2021, 42 (4):  495-505.  doi: 10.7657/XJPG20210415 Abstract ( 347 )   HTML ( 16 )   PDF (957KB) ( 410 )   Save This paper reviews field test cases for enhancing oil recovery in tight oil reservoirs at home and abroad in recent years, analyzes the effects of various development methods, and points out the problems arising out of and the enlightenment obtained from the field tests. According to the results of field tests at home and abroad, we conclude that gas injection (CO2 and natural gas) is a popular development method at present; most pilot tests are successful with the oil recovery improved by 3% to 30%; the laboratory models are too ideal and quite different from or even contrary to the field test results; fracture interference and channeling result in uneven energy spread, which is the fundamental cause for the failure of some pilot tests. Therefore, how to balance “utilization and treatment” of fractures, clarify the “ substantial” exchange mechanism between tight matrix and fractures, and guide and optimize laboratory research through field experience are key issues to resolve in tight oil development in China. In addition, it is necessary to further optimize the methods for tight oil resource evaluation, increase policy support to oil and gas industry and promote the leapfrog development of the theory and technology for enhancing tight oil recovery. Figures and Tables | References | Related Articles | Metrics

OIL AND GAS GEOLOGY ABROAD

Pore Throat Structure and Fractal Characteristics of Tight Sandstone Reservoirs: A Case Study of Upper Montney Formation in Block A in Western Canada Sedimentary Basin Huang Yiming, Richard COLLIER 2021, 42 (4):  506-513.  doi: 10.7657/XJPG20210416 Abstract ( 268 )   HTML ( 4 )   PDF (7333KB) ( 136 )   Save In order to further characterize the structure and fractal characteristics of different pore throats in tight sandstone reservoirs, the tight sandstone samples from Upper Montney formation in Block A of western Canada sedimentary basin are studied by using cast thin section, SEM and high pressure mercury injection analyses. The results show that the pore types of the reservoir in the study area mainly include dissolution pore, primary residual intergranular pore and intercrystal micropore, and a small number of microfractures are noted. Most of the pore throat radius of the reservoir is less than 0.30 μm, showing a curve with multiple peaks, and the effective storage space is mainly composed of nano- and submicron- pores. The tight sandstones in the study area can be divided into Type Ⅰ, Type Ⅱ and Type Ⅲ with the corresponding average overall fractal dimensions of 2.31, 2.46 and 2.63, respectively. The Type I samples have relatively good physical properties and relatively weak heterogeneity. The fractal characteristics of pore throats with different sizes are different. The fractal dimension of the submicron pore throats is higher than that of nano pore throats, indicating a stronger heterogeneity of the submicron pore throats. The fractal dimension of pore throats is related to pore throat structure, and the development of different pore throats in tight sandstone reservoirs results in different heterogeneity of pore throats. Figures and Tables | References | Related Articles | Metrics