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01 February 2022, Volume 43 Issue 1 Previous Issue    Next Issue

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OIL AND GAS EXPLORATION

Micro-Pore Characteristics and Influencing Factors of Fengcheng Formation Shale in Well Maye-1 YANG Fan, MENG Xin, WANG Xianhu, YU Peirong, SHAO Guanghui, CHEN Huohong 2022, 43 (1):  1-10.  doi: 10.7657/XJPG20220101 Abstract ( 557 )   HTML ( 37 )   PDF (3132KB) ( 365 )   Save Less researches have been carried out on the microscopic pore characteristics of the Fengcheng formation shale in the Mahu sag. In order to determine the influence of pores on the occurrence and enrichment of shale oil, taking Well Maye-1 in the northwestern slope of the Mahu sag as a case, the characteristics of nano-pores and influencing factors in the continental shale were analyzed through X-ray diffraction, SEM, liquid nitrogen adsorption, high-pressure mercury intrusion, etc. The shale in the Fengcheng formation is mainly composed of felsic rock and carbonate rock. In the two kinds of rocks, the types, shapes and sizes of the pores are almost similar. There are inorganic pores, organic pores and micro-fractures, of which dissolution pores and micro-fractures are dominant. In addition, there are parallel plate-shaped fractures, wedge-shaped pores and ink-bottle-shaped pores. The pores are mainly small ones. The distribution of the pore size shows three peaks and the main peak ranges from 30 nm to 60 nm, and the pore connectivity is poor. The porosity of the felsic rock is higher than that of the carbonate rock, and macro-pores develop better in the felsic rock. So the felsic rock is more favorable for exploration. Quartz, feldspar and dolomite are controlling factors on pore development, and they have a balanced contribution to the pores of various sizes. Clay minerals are favorable for the development of micropores and small pores, but have a weaker impact on mesopores. Organic matter has a little effect on pore development. Both inorganic minerals and organic matter are favorable factors for the increase of shale porosity. Figures and Tables | References | Related Articles | Metrics

Pore Characteristics and Controlling Factors of Chang 7 Shale in Southeastern Ordos Basin CAO Shang, LI Shutong, DANG Hailong, XING Haixue, ZHANG Lixia, ZHANG Tianlong, BAI Pu 2022, 43 (1):  11-17.  doi: 10.7657/XJPG20220102 Abstract ( 370 )   HTML ( 13 )   PDF (5592KB) ( 262 )   Save In order to identify the pore characteristics of the continental shale in the seventh member of Yanchang formation (Chang 7 member) in southeastern Ordos basin, the shale cores taken from pure shale and silty laminae of Chang 7 member were analyzed for pore characteristics with the aid of experimental methods such as SEM, cast slice, gas adsorption method, and mercury intrusion, and the factors that may affect pore development were discussed. The results show that pure shale mainly contains clay mineral intergranular pores and organic pores, and silty laminae holds intergranular pores and intragranular dissolved pores. Compared with pure shale, silty laminae has mesopores-macropores with larger porosity, pore diameter and pore volume. In pure shale, the development of pores is mainly controlled by the contents of rigid particle and organic matter. In silty laminate, the controlling factors for shale pore development are mainly the preservation conditions. For instance, the enrichment of rigid particles such as quartz and feldspar is conducive to pore preservation, acidic fluid can corrode feldspar to create more pores, and liquid hydrocarbons can wrap minerals to inhibit cementation. The shale in silty laminae is superior to pure shale with respect to pore structure and physical properties. Thus, the silty laminae zones should be paid more attention in shale oil/gas exploration. Figures and Tables | References | Related Articles | Metrics

Reservoir Comparison and Exploration Enlightenment of Baikouquan Formation in Northern and Western Slopes of Mahu Sag CHEN Cheng, PENG Mengyun, ZHAO Ting, WANG Jingang 2022, 43 (1):  18-25.  doi: 10.7657/XJPG20220103 Abstract ( 390 )   HTML ( 16 )   PDF (3650KB) ( 227 )   Save Major breakthroughs to oil and gas exploration have been made in the northern slope of Mahu sag, but little exploration effect has been obtained in the adjacent western slope. According to the data from cores, thin sections and scanning electron microscope, the petrological characteristics and diagenesis of the Baikouquan reservoirs in the northern and western slopes are compared and analyzed. It is found that the reservoir physical properties and controlling factors are very different, and compaction, cementation and dissolution are fundamental causes for the different reservoir physical properties. The western slope is better than the northern slope in oil and gas resources. Favorable reservoirs are distributed in the deep of the western slope, and future exploration should focus on the two wings of the fan delta and the area around Well Mazhong-1. Figures and Tables | References | Related Articles | Metrics

Differences in Microstructures Between Marine and Continental Shales and Its Influences on Shale Reservoir Fracbility WANG Yinggang, SHEN Feng, WU Jinqiao, SUN Xiao, MU Jingfu, TANG Jiren 2022, 43 (1):  26-33.  doi: 10.7657/XJPG20220104 Abstract ( 634 )   HTML ( 11 )   PDF (7036KB) ( 116 )   Save Taking the shales of the Longmaxi formation in the Sichuan basin and the Yanchang formation in the Ordos basin as examples, scanning electron microscopy, nuclear magnetic resonance, CT scanning, rock mechanics test and hydraulic fracturing experiments were carried out to investigate the differences in the shale microstructures between marine and continental facies, and then the influence of the differences on shale fracbility was analyzed, and the two kinds of shale were compared by considering fractal geometry and the theory of rock mechanics. According to the research results, the following findings are obtained: a.The continental shale (Yanchang formation) has a high content of clay minerals, accounting for about 45.3%, while the marine shale (Longmaxi formation) is dominated by brittle minerals such as quartz and feldspar, accounting for about 67.9%. b.The porosity of the marine shale is about twice that of the continental shale. c. The proportion of macropores in the marine shale is higher and the pore size distribution is wider, while mesopores and small pores in the continental shale occupy larger space, and natural fractures and beddings are developed. d.The average initial pressure of the continental shale is about 22.52% lower than that of the marine shale, mainly due to low mechanical strength caused by the high clay mineral content in the continental shale, but less effect from pore pressure. e.The major hydraulic fractures induced in the marine shale are transverse cracks that are basically symmetrical along the wellbore, while the natural fractures and beddings in the continental shale can easily capture hydraulic fractures, resulting in shear fractures perpendicular to the major fractures, and the open and connected beddings and weak surfaces are conducive to form a more complex fracture network in the continental shale. f.The three brittleness indicators of the continental shale are all lower than those of the marine shale, but the continental shale has advantages of lower initial pressure, better fracture network and better fracturing potential, so it is inaccurate to evaluate the compressibility of the continental shale by using a brittleness indicator. g.The low porosity, low permeability and high water sensitivity are not conducive to hydraulic fracturing stimulation to the continental shale reservoir. Figures and Tables | References | Related Articles | Metrics

Clay Mineral Compositions and Its Genesis in Lower Permian Fengcheng Formation of Mahu Sag, Junggar Basin ZHOU Xuelei, QI Wen, HUANG Yu, ZHANG Huquan, PAN Shuxin, WU Jia, FANG Peng 2022, 43 (1):  34-41.  doi: 10.7657/XJPG20220105 Abstract ( 437 )   HTML ( 11 )   PDF (9906KB) ( 125 )   Save In this study, X-ray diffraction (XRD) and scanning electron microscope (SEM) were used to analyze the composition characteristics and genesis of clay minerals in the source rocks of the Lower Permian Fengcheng formation of the alkaline lacustrine facies in the Mahu sag, Junggar basin. The results show that the smectite and illite/smectite mixed layer has a higher content, but the illite content is lower, showing slow illitization of smectite. Considering the depositional background of the Fengcheng formation, it is concluded that the abnormal transformation of smectite is mainly affected by the volcanic rock, climate and diagenetic fluids in the source area. The intermediate-basic volcanic rock and the dry/wet alternating climate promoted the formation of smectite, while the alkaline water with CO2-3 as the primary anion inhibited the illitization of smectite. Figures and Tables | References | Related Articles | Metrics

RESERVOIR ENGINEERING

Effect of CO2 Pre-Pad in Volume Fracturing of Conglomerate Reservoirs in Mahu Sag, Junggar Basin YI Yonggang, HUANG Kexiang, LI Jie, MOU Shanbo, YU Huiyong, MOU Jianye, ZHANG Shicheng 2022, 43 (1):  42-47.  doi: 10.7657/XJPG20220106 Abstract ( 324 )   HTML ( 8 )   PDF (16157KB) ( 117 )   Save The conglomerate reservoirs in the Mahu sag of Junggar basin are tight and the reservoir fluid has a poor flow capacity, resulting in rapid decline and unsteady production. Although the effect of CO2 pre-pad fracturing is better than that of hydraulic fracturing, no systematic study has been carried out on how CO2 affects the crude oil and reservoir rocks in Mahu sag. In this study, the displacement ability of CO2 aqueous solution, the dissolution of core minerals and the changes in core porosity and permeability are analyzed. It is found that in the Mahu conglomerate reservoirs, the crude oil displacing rate by CO2 aqueous solution is higher than that by pure CO2 or water. The Mahu conglomerate reservoir has a higher carbonate content, so CO2 aqueous solution can play a stronger dissolution role and increase the porosity and permeability of the reservoir. Experimental results show that the porosity has increased by 27% on average, and the permeability has increased by 110% on average. The injected CO2 aqueous solution prefers dissolving calcite first, then dolomite and last chlorite. Mineral dissolution mainly occurs in the first 5 days, and then becomes less after 5 days. Figures and Tables | References | Related Articles | Metrics

Characteristics of Produced Fluid From Condensate Gas Reservoirs With Oil Rings Developed by Gas-Injection Huff and Puff WANG Bin, DU Jianfen, LIU Qi, ZHANG Yi, LI Daoqing, WANG Quan 2022, 43 (1):  48-51.  doi: 10.7657/XJPG20220107 Abstract ( 280 )   HTML ( 4 )   PDF (432KB) ( 164 )   Save Gas-injection huff and puff development can improve the recovery of condensate gas reservoirs. Experiments on gas-injection huff and puff in condensate gas reservoirs generally focus on the changes in gas injection volume, gas injection rate and recovery rate, but less on the changes in the composition of the produced fluid. After establishing an indoor physical simulation method for evaluating condensate gas reservoirs with oil rings developed by gas-injection huff and puff, a gas-injection huff and puff experiment was carried out on a condensate gas reservoir with an oil ring after depletion development. The results show that, as the rounds of gas-injection huff and puff increase in the condensate gas reservoir, the content of N2+C1 decreases while the contents of C2-C4 and C5+ increase in the produced fluid, and the composition of the produced fluid changes less and less, until to almost stable after the fourth round of gas-injection huff and puff; during the gas-injection huff and puff development for the oil from the oil ring, there are more N2+C1 but less C2-C6 and C7+ in the produced fluid, and as the rounds of gas-injection huff and puff increase, N2+C1 increase obviously while C2-C6 and C7+ decrease significantly during the first several rounds, finally the composition becomes stable after 9 rounds. Figures and Tables | References | Related Articles | Metrics

Production Behaviors of Condensate Oil From Gas Reservoirs in Southestern Sulige Gas Field, Ordos Basin GUAN Wei, LIU Chiyang, LI Han, WEN Yuanchao, YANG Qingsong, WANG Tao 2022, 43 (1):  52-58.  doi: 10.7657/XJPG20220108 Abstract ( 309 )   HTML ( 8 )   PDF (634KB) ( 208 )   Save The Permian gas reservoirs in the southeastern area of Sulige gas field in the Ordos basin are wet gas reservoirs developed from coal-measure source rocks. No condensate oil is produced just from the reservoir during development. However, when natural gas enters the wellbore and experiences the decreases in both temperature and pressure to below the critical values, condensate oil would appear. In order to increase the production of condensate oil associated with natural gas, the full-component analysis results of natural gas sampling and production data are used to analyze the geological conditions for reservoir forming and the factors such as temperature, pressure and gas production in the process of development. It’s found that the condensate oil production is influenced by the stable balance separation time and the liquid carrying capacity. After analyzing the geological and production conditions, controlling factors on the production of condensate oil are compared, and according to the changes of gas production, the production of condensate oil can be predicted block by block. The result provides basis for updating the gas reservoir development plan in the study area. Figures and Tables | References | Related Articles | Metrics

EOR of CO2 Flooding in Low-Permeability Sandy Conglomerate Reservoirs LI Yan, ZHANG Di, FAN Xiaoyi, ZHANG Jintong, YANG Ruisha, YE Huan 2022, 43 (1):  59-65.  doi: 10.7657/XJPG20220109 Abstract ( 344 )   HTML ( 13 )   PDF (2398KB) ( 283 )   Save The low-permeability sandy conglomerate reservoirs of Benbutu oilfield in Yanqi basin was developed by water flooding in the early stage. While along with water flooding, the reservoirs were seriously damaged, it was even harder to inject water into the reservoirs and the recovery rate stayed in a low level, therefore, it is urgent to switch flooding agent to further improve the recovery rate. In order to determine the feasibility of CO2 injection in the low-permeability sandy conglomerate reservoirs in Benbutu oilfield to enhance oil recovery, indoor experimental researches were carried out. The research results show that the crude oil in the formation of the study area has good swellability, is easily miscible with the injected CO2, and the viscosity of the crude oil is easy to be reduced. The minimum miscible pressure of the reservoirs is about 25 MPa, and near-miscible flooding can be achieved under the current formation pressure. The oil displacement efficiency of CO2 flooding is relatively high, which can dramatically improve recovery rate. The CO2 flooding plan was optimized with numerical simulation, in which a five-spot well pattern and a continuous gas injection method were adopted, and the oil recovery is expected to increase by about 13.37% and the oil diplacement ratio of CO2 injection will be about 0.33 t/t. The numerical simulation results provide a theoretical basis for the next field application. Figures and Tables | References | Related Articles | Metrics

Producing of Edge and Bottom Water Invasion Front and Risk Assessment on Injection and Production of Hutubi UGS LIAO Wei, LIU Guoliang, LI Xinlu, ZHANG Yunxin, ZHENG Qiang, LU Ye 2022, 43 (1):  66-71.  doi: 10.7657/XJPG20220110 Abstract ( 363 )   HTML ( 5 )   PDF (624KB) ( 238 )   Save Injection and production of a UGS (underground gas storage) with edge and bottom water is likely forcing gas-water contact to move, so it is necessary to assess the migration of water invasion front and the injection-production risk since it is very important for recovering the storage capacity and improving the peak shaving ability of injection and production wells. Taking the Hutubi UGS as a case, we evaluated the feasibility of recovering the gas/water front of the UGS with edge and bottom water, simulated the position of gas front by tracer numerical simulation technology, and enhanced the flow capacity of the reservoir by multiple cycles of gas flooding. Then an indicator system evaluating dynamic and static parameters that affect the water invasion in injection and production wells was established, and the risks of water breakthrough were evaluated in 30 injection and production wells in Hutubi UGS. It is found that there are only 3 wells with high water invasion risk in the study area, which are located in the western water invasion area. Finally, an early water invasion warning mechanism was proposed. The mechanism aims to monitor the production performance, record real-time production parameters such as water production, water-gas ratio, Cl- content in produced water and wellhead pressure of the wells with medium–high water invasion risks, and adjust and optimize the injection and production rates and gas volumes, and as a result, control the advancing speed of the gas/water front. Figures and Tables | References | Related Articles | Metrics

Variations of Physical Properties of Shale Oil in Jimsar Sag, Junggar Basin YAO Zhenhua, QIN Jianhua, GAO Yang, CHEN Chao, LIU Zhenping, ZHANG Xiaogong 2022, 43 (1):  72-78.  doi: 10.7657/XJPG20220111 Abstract ( 357 )   HTML ( 11 )   PDF (691KB) ( 275 )   Save Shale reservoirs of the Permian Lucaogou formation in the Jimsar sag, Junggar basin are highly heterogeneous, so that the production of horizontal wells after volumetric fracturing stimulation declines rapidly. The oil recovery is predicted to be low by depletion development and the properties of the produced oil are very complex. After analyzing the physical properties and occurrence of the crude oil, and the physical properties of the produced fluid, and combining with the producing modes of reserves and the distribution of remaining oil, the physical properties and distribution of the shale oil are characterized in terms of pores, reservoirs and wellbore. The oil in large pores is lighter and uneasily adsorbs to the pore wall, whereas the oil in small pores is heavier and easily adsorbs to the pore wall due to more heavy components in it. The viscosity of the crude oil produced alternatively from the reservoirs with different physical properties has been changing, which can be classified into four types such as unobvious change, slight decrease, significant decrease and slight increase. The crude oil produced from the lower sweet spot interval is heavier and easy to emulsify. The viscosity of the emulsion increases sharply when the water cut is greater than 30%, so the water cut may be the primary cause for the emulsification of the crude oil. CO2 huff and puff may be effective to produce the adsorbed crude oil that cannot be displaced through depletion development. In high water-cut period, injecting surfactants may help reduce the viscosity and elasticity of emulsified crude oil and improve the oil recovery. Figures and Tables | References | Related Articles | Metrics

APPLICATION OF TECHNOLOGY

Determination and Application of Welge Equation for Reservoirs After Water Breakthrough GAO Wenjun, TIE Qi, ZHENG Wei, TANG Xin 2022, 43 (1):  79-84.  doi: 10.7657/XJPG20220112 Abstract ( 325 )   HTML ( 10 )   PDF (814KB) ( 252 )   Save This paper reviews the establishment and development process of the Welge equation, and derives the Welge equation for oil wells after water breakthrough according to the finding that the water cut at the outlet of an oil well drilled in homogeneous reservoirs is numerically equal to that of this oil well after water breakthrough. Using this equation, the mutual conversion between water drive curves and oil-water two-phase flow characteristics can be realized. Taking Iraj Ersaghi’s watercut variation law, Maximov-Tong Xianzhang’s water drive characteristic curve and Efros’s experimental results as examples, the formation process and applicable conditions of them are discussed, and the classical theories and methods of water flooding are further understood. The result provides a reference for evaluating water flooding reservoirs. Figures and Tables | References | Related Articles | Metrics

Numerical Simulation on Polymer Flooding Recovery of Conglomerate Reservoirs: Horizontal Fractures in Arched Wells After Multi-Stage Fraturing WU Haoqiang, PENG Xiaolong, ZHU Suyang, FENG Ning, ZHANG Si, YE Zeyu 2022, 43 (1):  85-91.  doi: 10.7657/XJPG20220113 Abstract ( 280 )   HTML ( 4 )   PDF (1651KB) ( 194 )   Save Conglomerate reservoirs are generally very heterogeneous, so it is easy to induce large channels during water flooding, resulting in low flooding efficiency, rapid water cut rise and unfavorable development effect. For shallow conglomerate reservoirs which are variable in lithofacies and poor in reservoir continuity, to improve the recovery of polymer flooding, horizontal fractures can be induced through multiple-stage fracturing in arched wells. Based on the geological model of the northwestern block of District Qidong-1 in Karamay oilfield, production history matching was performed for the high water-cut conglomerate reservoirs. Then we set up an injection-production well pattern composed of vertical wells and extended-reach arched wells with horizontal fractures induced by multi-stage fracturing stimulation in the area with enriched remaining oil, and conducted numerical simulation on how to enhance the recovery. The results show that the optimal polymer injecting intensity in the study area is about 0.05 PV/a; the sweep coefficient of an angular injection well pattern is higher than that of an edge injection well pattern; and the polymer flooding effect is the best when horizontal fractures are induced in the upper interval of an arched well. An arched well can make full use of horizontal fractures to improve fluid flow near the wellbore, and it can boost the effect of polymer in profile controlling. The two mechanisms complement each other and can effectively improve the advancement of flooding front, and enhance the recovery of shallow conglomerate reservoirs. Figures and Tables | References | Related Articles | Metrics

Parameters of Connected Conducting Model and Its Application in Dolomite Reservoir Evaluation XIE Fang, CAI Deyang, LIU Ruilin, ZHANG Chengsen, FENG Cheng 2022, 43 (1):  92-101.  doi: 10.7657/XJPG20220114 Abstract ( 254 )   HTML ( 7 )   PDF (8750KB) ( 102 )   Save Based on reservoir physical properties and the data of rock electricity, CT scan, nuclear magnetic resonance and thin slices, a method for determining the parameters of a connected conducting model is proposed for studying dolomite reservoirs, including the critical water-filled porosity, critical water saturation and critical conductivity index. Then the calculated critical water saturation is compared with the T2 cut-off value, permeability, CT scan photos and thin slice analysis results, the critical conductivity index is compared with the cementation index, and the physical meanings of critical water saturation, critical water-filled porosity and critical conductivity index are discussed. The theoretical saturation curves from connected conduction is compared with the theoretical saturation curves from Archie’s formula, and the difference between them is discussed. Finally, according to the determined parameters of the connected conducting model, the water saturations of the dolomite reservoir in two wells are calculated using the connected conductance formula and the calculated results are consistent with formation test results. Figures and Tables | References | Related Articles | Metrics

Mid-Late Development of Reservoirs With Narrow Oil Ring, Gas Cap and Edge Water YUE Baolin, ZHU Xiaolin, LIU Bin, CHEN Cunliang, WANG Shuanglong 2022, 43 (1):  102-106.  doi: 10.7657/XJPG20220115 Abstract ( 249 )   HTML ( 4 )   PDF (656KB) ( 181 )   Save The X sandstone reservoir in Jinzhou has a large gas cap, narrow oil ring and strong edge water. After entering its middle to late development stage, the reservoir faces the problems such as rapid formation pressure drop, severe gas channeling and difficult potential tapping, so it is urgent to optimize the development methods. Following the principles of geometric similarity, physical property similarity and production performance similarity, we optimized the profile model of the reservoir, and validated the feasibility of a barrier water injection scheme through 2D visualized physical simulation experiments. Then we proposed a barrier water injection scheme with horizontal wells in a parallel well pattern by combining with numerical simulation, and demonstrated the technical requirements for implementing the scheme. Considering the reservoir complexity, development risks, severe gas channeling, uneven vertical displacement and the ultimate goal for significant stimulation effects, a well group was selected for pilot test to improve the understanding of barrier water injection performance. The result provides a reference to the development of similar reservoirs. Figures and Tables | References | Related Articles | Metrics

Reservoir Damage Mechanism for Upper Wuerhe Formation in Southern Mahu Area, Junggar Basin ZHOU Wei, SHEN Xiulun, KOU Gen, WEI Yun, JIANG Guancheng, YANG Lili, ZHANG Yuankai 2022, 43 (1):  107-114.  doi: 10.7657/XJPG20220116 Abstract ( 331 )   HTML ( 6 )   PDF (16052KB) ( 219 )   Save The core of the conglomerate reservoir from upper Wuerhe formation of Permian is very easy to break after immersed in fluids, so that it is difficult to evaluate how gel-breaking fracturing fluid damages the reservoir, and it is impossible to determine the factors controlling reservoir damage in the southern Mahu area, Junggar basin. This study used X-ray Micro-CT technology to scan core samples and reconstructed the three-dimensional pore structure, and then characterized the pore changes on different sections by the ball-stick model and the threshold segmentation method. The results show that, after the reservoir was damaged by gel-breaking fracturing fluid, the average pore radius, average throat radius, average throat length, average pore-to-throat ratio, porosity and permeability were reduced by 42.1%, 32.7%, 19.1%, 45.3%, 7.7% and 33.8%, respectively. After fractured by gel-breaking fracturing fluid, the reservoir was damaged, resulting in reduced porosity and permeability, especially a significant change in permeability. Swelling montmorillonite in the clay minerals and particle migration are the factors that can cause damage to the reservoir, and the interaction between gel-breaking fracturing fluid and the reservoir is the primary factor causing reservoir damage. Figures and Tables | References | Related Articles | Metrics

REVIEW

Characteristics of Incremental Proven Oil and Natural Gas Geological Reserves in China ZHOU Liming, HAN Zheng, ZHANG Daoyong, REN Jihong, FENG Zhigang, ZHANG Chenshuo 2022, 43 (1):  115-121.  doi: 10.7657/XJPG20220117 Abstract ( 462 )   HTML ( 21 )   PDF (539KB) ( 314 )   Save In order to understand the growth trend of proven oil and natural gas geological reserves in China, this paper analyzes the distribution and change of the incremental proven oil and natural gas geological reserves discovered from 2010 to 2019 in China. The results show that the incremental proven oil reserves are mainly distributed in the areas such as Ordos basin, Bohai Bay basin, and Junggar basin, and accumulated in the middle-shallow to middle-deep formations in these basins; the incremental proven natural gas reserves are mainly distributed in the areas such as Ordos basin, Sichuan basin, Tarim basin, and East China Sea Shelf basin, and accumulated in middle-deep to ultra-deep formations; the quality of the incremental oil and gas reserves become worse, the abundance goes lower and the burial depth is deeper and deeper; and incremental proven oil and gas reserves are mainly preserved in lithologic oil and gas reservoirs, unconventional oil and gas reservoirs and deep oil and gas reservoirs. Figures and Tables | References | Related Articles | Metrics

OIL AND GAS GEOLOGY ABROAD

Selection of Wells for Profile Control and Water Plugging in Late High-Water Cut Stage in KS Oilfield WANG Guifang, WANG Shuoliang, XU Xuejian, LEI Yan, KANG Bo 2022, 43 (1):  122-126.  doi: 10.7657/XJPG20220118 Abstract ( 299 )   HTML ( 9 )   PDF (529KB) ( 191 )   Save In the late high-water cut stage in KS oilfield, profile control in water injection wells is a common measure to stabilize oil production while controlling water production. However, it is difficult to decide index limits and quantify weight values when selecting water wells. This study screened single-well, interwell and static indicators that can accurately reflect the characteristics of water channeling, developed a new kernel function based on polynomial kernel function, radial basis kernel function and Sigmoid kernel function, and optimized the fuzzy clustering method to improve the accuracy of fitting and prediction. Then a special fuzzy clustering method was proposed for selecting wells for profile control in the late high water-cut stage in KS oilfield. It can improve the recognition rates of sample set and detected set for selected wells. The new decision-making method for selecting wells for profile control has been applied to KS oilfield, and 3 wells were selected from 22 water wells for profile control. Significant oil increasing and water reducing effects have been achieved. Figures and Tables | References | Related Articles | Metrics