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Petroleum Exploration History and Enlightenment in Tarim Basin TIAN Jun Xinjiang Petroleum Geology    2021, 42 (3): 272-282.   DOI: 10.7657/XJPG20210303 Abstract （936）   HTML （41）    PDF（pc） （2661KB）（726）       Knowledge map    Save After summarizing the petroleum exploration history in the Tarim basin since 1950 from the points of major exploration areas and targets, exploration ideas, geological understandings and exploration technology and achievements, the exploration process for over 70 years in the basin can be divided into 4 stages: (1) Uphill exploration in the piedmont of the margin of the basin from 1950 to 1983; (2) Breakthrough to the cratonic area through conducting 6 times of exploration in the basin, and making many discoveries in cratonic clastic reservoirs from 1984 to 1996; (3) Great breakthrough in Kuqa piedmont area through persisting on “4 equal stresses” and strengthening technical research from 1997 to 2005; (4) Breakthroughs to subsalt thrust belts in the Kuqa foreland basin and to the fractured-vuggy carbonate rocks in ultra-deep exploration areas through focusing on three “battlefields” since 2006. As the first basin targeting ultra-deep exploration in China, it is necessary to summarize the hydrocarbon accumulation laws and exploration experiences. Due to low geothermal gradient and early-deposited effective source rocks, large-scale effective reservoirs may exist and accumulate in ultra-deep layers and large-scale hydrocarbon enrichment zones form. They are potential targets for future exploration, especially in the basin with low geothermal gradient in the central and western parts. The ultra-deep exploration practice in the Tarim basin has proved that persisting on technical research and innovation, conducting 3D seismic survey before drilling wildcat wells, and running integrated exploration and development are successful ways to make fast and large-scale exploration discoveries. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in the Northern Songliao Basin MENG Qi’an, LI Chunbai, BAI Xuefeng, ZHANG Wenjing, XUE Tao, PENG Jianliang, TANG Zhenguo Xinjiang Petroleum Geology    2021, 42 (3): 264-271.   DOI: 10.7657/XJPG20210302 Abstract （529）   HTML （23）    PDF（pc） （1691KB）（630）       Knowledge map    Save According to the exploration history in the northern Songliao basin, this paper summarizes the research results in different exploration stages and analyzes how the exploration idea in each stage changed and its role to exploring new targets. The Songliao basin went through three stages of oil and gas exploration: exploration of structural oil reservoirs (1955–1985), exploration of lithological oil reservoirs (1986–2010), and exploration of both conventional and unconventional oil and gas reservoirs (since 2011). The enlightment lies in objective geological conditions and the understanding of reservoir forming laws are the foundation for exploration deployment, sustainable theoretical innovation is the guarantee to make breakthroughs to oil and gas exploration, and technological innovation of engineering is the key to keeping steady increase of oil and gas reserves. The mature exploration areas in the basin are still primary exploration targets to discover large and medium-sized oil and gas fields in the future. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Sichuan Basin: A Case Study on Sinopec Exploration Areas HU Dongfeng, WANG Liangjun, HUANG Renchun, PAN Changlin, ZHANG Qingfeng Xinjiang Petroleum Geology    2021, 42 (3): 283-290.   DOI: 10.7657/XJPG20210304 Abstract （507）   HTML （15）    PDF（pc） （1888KB）（563）       Knowledge map    Save After systematically analyzing the petroleum geological theory and exploration results of the Sinopec exploration areas in the Sichuan basin, we divide the exploration history of the Sichuan basin into three stages: exploration for structural oil and gas reservoirs (1953-2000), exploration for lithologic gas reservoirs (2000-2010), and exploration for both conventional and unconventional oil and gas reservoirs ( from 2010 to present). Taking Puguang, Yuanba and Fuling gas fields as cases, which are three most representative large gas fields discovered by Sinopec in the Sichuan basin in recent two decades, we analyze the problems arising in the early exploration stage, summarize the theoretical innovations, changes of idea, exploration discoveries and follow-up plans. Our findings can be a reference for exploration in other areas or basins. Table and Figures | Reference | Related Articles | Metrics

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Offshore Petroleum Exploration History and Enlightenment in Beibu Gulf Basin LI Fanyi, ZHANG Houhe, LI Chunrong, ZHANG Wenzhao, HAO Jing, XU Qingmei, YAN Han Xinjiang Petroleum Geology    2021, 42 (3): 337-345.   DOI: 10.7657/XJPG20210310 Abstract （656）   HTML （9）    PDF（pc） （1700KB）（510）       Knowledge map    Save The paper analyzes the historical data of drilling, seismic survey, reserves and production, summarizes the offshore exploration achievements and targets and petroleum geology theory, then divides the offshore exploration process in the Beibu Gulf basin into three stages: (1) Early exploration stage (1960-1995). Drilling results proved that there are good source rocks and source-reservoir-cap assemblages in the Beibu Gulf basin, the basic structural characteristics was understood, and the secondary tectonic units were divided. Early exploration results laid a good foundation for further oil and gas exploration during 1980s when there was a high tide of foreign cooperation. (2) Breakthrough to the Weixinan sag and progressive exploration stage (1995-2010). The discovery and successful evaluation of a number of oilfields represented by Weizhou 12-1 firstly contributed to the cumulative proven geological reserves of oil in the Beibu Gulf basin exceeding 100 million tons. Facing the condition that the Weixinan sag is full of oil but the average size of the oilfields in the sag is relatively small, a progressive exploration strategy was put forward, which broke the bottleneck and realized the upgrading and increase of reserves. (3) Breakthrough to the Wushi sag and exploration into new areas (since 2010). The discovery and successful evaluation of a number of oilfields represented by Wushi 17-2 proved that the Wushi sag is another hydrocarbon-rich sag that has been confirmed by drilling data following the breakthrough of the Weixinan sag. This opened a new prospect in the Beibu Gulf basin. Meanwhile, the exploration to new targets such as buried-hill reservoirs led to the identification of a number of pre-Paleogene carbonate reservoirs which are potential contribution to sustainable development. Table and Figures | Reference | Related Articles | Metrics

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Progress and Enlightenment of Exploration and Development of Major Shale Oil Zones in the USA LI Qianwen, MA Xiaoxiao, GAO Bo, CHEN Xinjun Xinjiang Petroleum Geology    2021, 42 (5): 630-640.   DOI: 10.7657/XJPG20210518 Abstract （430）   HTML （29）    PDF（pc） （803KB）（439）       Knowledge map    Save We reviewed the geological features, reserves, production, drilling activities and progress of development technology in major shale oil zones in the Permian basin, the Bakken area in the Williston basin and the Eagle Ford area in the Gulf of Mexico basin, analyzed the development trend of shale oil in the USA, and summarized the experience and enlightenment from the USA, with the intent to provide a reference to the development of shale oil in China. The results show that the Permian basin has the highest reserves and production of shale oil in the USA, which is mainly produced from the Spraberry zone and the Wolfcamp zone, and they will also be of great importance in the future. In 2020, influenced by COVID-19, the amount of drilling rigs and the oil production in the three major shale oil zones mentioned above first declined and then increased, and the ultra-low oil prices drove a new round of technological innovation and cost-cutting measures to increase well production in oil companies. By referring to the experiences in shale oil exploration and development in the USA, to develop shale oil in China, priority should be given to highly matured light oil and condensate oil, and the advanced development technologies of condensate oil reservoirs in the USA should be studied and followed. Grading evaluation of sweet spot is the basis of efficient development of shale oil in the USA, and plays a particularly significant role at low oil prices. There is a long way to go to get profitable development of shale oil in China. Technological progress is the key to reducing cost and enhancing profit. Technological researches should be paid attention to in early exploration and development. Life-cycle and geological-engineering integration management is recommended. This may be a new way for efficient shale oil development and rapid cost reduction in China. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Pearl River Mouth Basin ZHANG Wenzhao, ZHANG Houhe, LI Chunrong, YAN Han, LI Fanyi, HAO Jing Xinjiang Petroleum Geology    2021, 42 (3): 346-352.   DOI: 10.7657/XJPG20210311 Abstract （552）   HTML （14）    PDF（pc） （1734KB）（432）       Knowledge map    Save Oil and gas exploration in the Pearl River Mouth basin has been going on more than 40 years. Considering the changes of exploration strategy and geological understanding, exploration workload, breakthrough and reserve growth, the exploration process can be divided into three stages: (1) Early exploration stage (1974-1984) aiming at large structures in the uplift belt; (2) Anticline exploration stage (1985-1999) focusing on middle and shallow layers in the hydrocarbon-rich sags; and (3) Composite exploration stage (since 2000) paying same attention to oil and gas, deep-water regions and deep layers. A number of innovative geological understandings, theories and technologies have been formed through exploration practices, such as differential hydrocarbon enrichment and composite accumulation theory, the late-stage hydrocarbon accumulation pattern with multi-source hydrocarbon generation and complex transformation, the recognition of deep-water fan in lowstand system tract, the comprehensive evaluation system of “source-migration-accumulation” and the reservoir forming pattern of “near-source hydrocarbon supply with multiple migration networks”. These understandings have enriched the oil and gas exploration theories, and led to continuous breakthroughs of oil and gas exploration in the Pearl River Mouth basin. Table and Figures | Reference | Related Articles | Metrics

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Establishment and Application of the Optimized Evaluation System for Seismic Exploration in Junggar Basin LEI Dewen, LI Xianmin, YANG Wanxiang, YAN Jianguo, WANG Yupeng Xinjiang Petroleum Geology    2021, 42 (6): 720-725.   DOI: 10.7657/XJPG20210611 Abstract （346）   HTML （6）    PDF（pc） （63135KB）（429）       Knowledge map    Save During implementing the recent “High-Quality and Efficient Exploration” strategy, evaluation and optimization of seismic exploration have attracted extensive attention. In processing and interpretation of the seismic data from the lithologic reservoirs in Junggar basin, a “Three Lists and One Countermeasure” method and its evaluation system are put forward based on a goal-oriented integrated workflow, and remarkable results have been achieved in field application. However, this evaluation system does not cover seismic data acquisition and mainly consists of some qualitative description methods. Therefore, by taking seismic data with effective bandwidth as a key indicator, a corresponding index system of seismic acquisition is proposed, then evaluation and optimization of seismic acquisition plan are contained in the evaluation and optimization system for seismic exploration, and finally the “Three Lists and One Countermeasure V2.0” is established. The optimized seismic evaluation system has been applied in multiple projects for lithologic reservoir exploration and remarkable results have been obtained. The methods proposed in this paper can be references to evaluating and optimizing seismic exploration for lithologic reservoirs in similar areas. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Qaidam Basin WEI Xuebin, SHA Wei, SHEN Xiaoshuang, SI Dan, ZHANG Guoqing, REN Shixia, YANG Mei Xinjiang Petroleum Geology    2021, 42 (3): 302-311.   DOI: 10.7657/XJPG20210306 Abstract （586）   HTML （13）    PDF（pc） （2416KB）（426）       Knowledge map    Save This article reviews the arduous and tortuous course of oil and gas exploration in Qaidam basin from 1954 to now, which has obvious stages and complexity. From the 1950s to 1960s limited by technological means, the exploration in the basin focused on surface geological survey and exploration in the shallow strata, and more than ten oil fields such as Lenghu were discovered in shallow strata. From the 1970s to 1980s, simulated seismic exploration was carried out on a large scale, and the technology progress promoted the exploration toward the middle-deep layers and eastern part of the basin. During which, not only the Gasikule oilfield was discovered with the oil reserves of 100 million tons, but the prelude of exploring large gas fields was opened in the eastern part of the basin. In the 1990s, the exploration encountered a bottleneck, so deepening geological research and fine evaluation were performed to increase reserves and production. Entering the 21st century, the exploration has been developing in multiple domains and multiple types, and the theory and technology of oil and gas exploration and development have been advanced for the saline lacustrine basin in the Qinghai-Tibet Plateau, and sustainable breakthroughs in oil and gas exploration and rapid growth in reserves have been achieved. The whole exploration process can be divided into four stages: discovery in shallow strata, breakthrough in deep strata, persistent exploration and rapid development. The paper analyzes 5 successful cases of oil and gas field exploration, which can prove the guiding significance of the innovation of scientific and technical theories, the update of exploration ideas and the progress of exploration technology to the exploration breakthrough. Taking history as a mirror, we hope to give enlightenment to future petroleum exploration and development. Table and Figures | Reference | Related Articles | Metrics

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Proppant Migration Law in Fractures of Conglomerate Reservoirs of Wuerhe Formation in Mahu Sag CHEN Chaofeng, WANG Jia, YU Tianxi, LI Yi, ZOU Yushi, MA Xinfang, LIU Li Xinjiang Petroleum Geology    2021, 42 (5): 559-564.   DOI: 10.7657/XJPG20210507 Abstract （294）   HTML （14）    PDF（pc） （3768KB）（425）       Knowledge map    Save Fractures induced by volume fracturing stimulation to tight conglomerate reservoirs of the Wuerhe formation in Mahu sag are very complex, so that the migration and distribution laws of proppants are not clear, which seriously influences the fracturing effect. Based on 3D reconstruction of fracture shapes and considering the interaction between proppants and rough fracture surface, the influences of gravel size, gravel concentration and width attenuation of the fractures around gravels on proppant migration and distribution were investigated by using a Fluent two-phase flowing model. The results show that gravel size has obvious impacts on proppant migration, and it is negatively correlated to balanced height of proppant bank and positively correlated to balanced time of proppant bank; gravel concentration has weak impacts on proppant migration, and it is negatively correlated to balanced time and balanced height of proppant bank; width attenuation of the fractures around gravels has great influences on proppant migration, and both balanced time and balanced height of proppant bank decrease with the increase of the fracture width attenuation degree around gravels. Table and Figures | Reference | Related Articles | Metrics

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ROP Improvement and Production Enhancement for Ultra-Deep Wells Based on Geology-Engineering Integration: A Case in Kuqa Depression, Tarim Basin CAI Zhenzhong, XU Ke, ZHANG Hui, WANG Zhimin, YIN Guoqing, LIU Xinyu Xinjiang Petroleum Geology    2022, 43 (2): 206-213.   DOI: 10.7657/XJPG20220212 Abstract （386）   HTML （8）    PDF（pc） （1457KB）（404）       Knowledge map    Save The Kuqa depression in the Tarim basin is rich in oil and gas resources and has great potential for exploration. However, the geological setting in this area is complex and the target layers are generally buried deeper than 6 000 m, or even more than 8 000 m, making oil and gas exploration and development difficult. Considering the geological engineering characteristics and existing problems of ultra-deep wells in the Kuqa depression, a solution based on the concept of geology-engineering integration is proposed, and the successful practice of the first pre-salt highly-deviated well in Tarim oilfield is introduced. Research and practices show that geomechanical research is beneficial to reducing drilling complexities and increasing rate of penetration, can help select favorable reservoirs and optimize stimulation schemes, and finally support the ROP improvement and production enhancement. The geology-engineering integration is necessary for efficient development of complex oil and gas reservoirs. In this aspect, multiple disciplines will be collaborated in operations through the life cycle of each well to generate the maximum benefits and achieve overall progress from well location deployment, drilling engineering, well completion and stimulation to oil/gas production engineering, thereby facilitating the construction of large oil and gas fields. Table and Figures | Reference | Related Articles | Metrics

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Progress and Enlightenment of EOR Field Tests in Tight Oil Reservoirs WEI Bing, ZHANG Xiang, LIU Jiang, PU Wanfen, LI Yibo, WANG Xiaochao Xinjiang Petroleum Geology    2021, 42 (4): 495-505.   DOI: 10.7657/XJPG20210415 Abstract （345）   HTML （16）    PDF（pc） （957KB）（403）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Exploration History and Enlightenment of Coalbed Methane in Baode Block YANG Xiuchun, MAO Jianshe, LIN Wenji, HAO Shuai, ZHAO Longmei, WANG Yuan, LI Li Xinjiang Petroleum Geology    2021, 42 (3): 381-388.   DOI: 10.7657/XJPG20210315 Abstract （498）   HTML （10）    PDF（pc） （1600KB）（396）       Knowledge map    Save Mainly based on the changes in geological knowledge, technological development, number of drilled wells, exploration results and gas production, this paper divides the CBM exploration process of the Baode Block into four stages: (1) Stage of foreign cooperation on exploration and evaluation: 8+9# coal seams were recovered by drainage in horizontal wells, with large water production and difficulties in drainage and pressure reduction; (2) Stage of production test and evaluation of well groups: 4+5# coal seams and 8+9# coal seams were recovered by drainage in cluster wells, with good effect of gas production by drainage; (3) Pilot test stage with integrated exploration and development: the breakthrough in high-yield was achieved through area depressurization of the optimized well pattern in oil-enriched zones; (4) Large-scale development and rolling expansion and evaluation stage: Large-scale productivity construction in favorable areas and rolling expansion exploration in complex areas have been implemented and an annual output of 5×108 m3 have been achieved. Based on the geological understanding and exploration results, this paper summarizes the origin of low-rank coalbed gas, accumulation mode, and “sweet spot” evaluation and the enlightenment to CBM exploration and production in Baode Block. The accumulation theories such as “thermogenic gas as the main source, biogenic gas as the supplement”, “hydrodynamics-controlled gas, monocline and gentle slope” are proposed, and the evaluation index system of “sweet spot” of low-rank coalbed methane enrichment is established. We hope to provide implications to the exploration of low-rank coalbed methane. Table and Figures | Reference | Related Articles | Metrics

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Practices and Cognitions of Petroleum Exploration in Mesozoic,Ordos Basin LUO Anxiang, YU Jian, LIU Xianyang, JIAO Chuangyun, HAN Tianyou, CHU Meijuan Xinjiang Petroleum Geology    2022, 43 (3): 253-260.   DOI: 10.7657/XJPG20220301 Abstract （560）   HTML （31）    PDF（pc） （1437KB）（396）       Knowledge map    Save The Ordos basin is the second largest sedimentary basin in China with abundant oil and gas resources and broad exploration prospects. Typical low-permeability-tight oil reservoirs are develpoed in the Triassic Yanchang formation in the basin,which are difficult to explore. Through continously geological researches on the Mesozoic oil reservoirs in the Ordos basin over the past 50 years,some theories about hydrocarbon accumulation in Jurassic reservoir groups,in large-scale lithologic reservoirs in inland depression lake basins and in continental shales have been formed. By virtue of three strategic shifts,four conventional hydrocarbon provinces with reserves exceeding 10×108 t and a successive zone with shale oil reserves of 20×108 t have been discovered. The proven oil reserves have increased by an average of over 3×108 t per year for 10 consecutive years. Thus,Changqing oilfield in Ordos basin has become an oil and gas province with the fastest increase in reserves and production in China and contributed 12.5% of China's annual oil production,which provides a reference for the petroleum exploration in other similar basins. Table and Figures | Reference | Related Articles | Metrics

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Development Countermeasures for Oil and Gas Industry Under the Background of “Carbon Peaking and Carbon Neutrality” CHANG Yuwen, FENG Naichao Xinjiang Petroleum Geology    2022, 43 (2): 235-240.   DOI: 10.7657/XJPG20220216 Abstract （427）   HTML （20）    PDF（pc） （701KB）（391）       Knowledge map    Save As the measures are taken against global climate issues, more than 120 countries/regions have set the goal of “carbon neutrality”. The global energy transition is progressing rapidly, and the oil companies mainly engaged in traditional oil and gas businesses are facing pressures from both multiple environmental protection regulations and carbon emission reduction. Therefore, the low-carbon transition strategy has received extensive attention. On the basis of analyzing the global energy transition under the background of “carbon peaking and carbon neutrality”, the current situation and trend of the global oil and gas development were investigated from several aspects such as supply-demand pattern, exploration and development trends, business structure, international oil prices, and geopolitics. Finally, relevant countermeasures for the development of China’s oil and gas industry were put forward: (1) take both oil and gas as the main energy sources, put more efforts in exploration and development, and attach equal importance to “unconventional and conventional resources, offshore and onshore resources, deep and shallow resources”, in order to increase reserves, stabilize oil production and enhance gas production for purpose of national energy security; (2) combine carbon emission reduction with carbon utilization, and accelerate energy conservation and emission reduction, in order to realize green and low-carbon development; (3) keep the integrated development of oil, gas, and new energy, and promote the development of new energy step by step with a clear strategy by relying on the advantages (e.g. funds, technologies and talents) of oil/gas exploration and development; (4) follow the technological innovation strategy centered on theory/technology research, key technology R&D and supporting technology applications, in order to drive the oil and gas industry to achieve green transition and high-quality development Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment of Yanchang Exploration Area in Ordos Basin HU Chunqiao, REN Laiyi, HE Yonghong, WAN Yongping, LIANG Quansheng Xinjiang Petroleum Geology    2021, 42 (3): 312-318.   DOI: 10.7657/XJPG20210307 Abstract （404）   HTML （6）    PDF（pc） （4789KB）（386）       Knowledge map    Save During the 100-year history of oil and gas exploration in Yanchang exploration area of Ordos basin, a number of major progress and breakthroughs have been made, all of which are of great significance. After analyzing the exploration history, data and important historical events, and based on the variations of oil and gas production and the development of geological theory in Yanchang exploration area, the exploration process is divided into four stages: Early exploration stage (1905-1949), sustained exploration stage (1950-1981), rapid development stage (1982-2006) and stabilizing oil production meanwhile increasing gas production stage (2007-). Additionally, this paper summarizes the theories and understandings in exploring ultra-low-extra-low permeability reservoirs, tight gas and continental shale gas in the southeastern area of the Ordos basin in recent ten years, and analyzes their important roles in the rapid increase of oil and gas reserves and production. Our findings may provide implications and references for future oil and gas exploration. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration Ideas and Discoveries in Upper Wuerhe Formation, Dongdaohaizi Sag, Junggar Basin LI Yanping, ZOU Hongliang, LI Lei, FU Jiyou, XIA Yu, XIE Junyang Xinjiang Petroleum Geology    2022, 43 (2): 127-134.   DOI: 10.7657/XJPG20220201 Abstract （506）   HTML （31）    PDF（pc） （1730KB）（385）       Knowledge map    Save Dongdaohaizi sag is one of the important hydrocarbon-generating sags in the Junggar basin. Petroleum discoveries have been made in the Jurassic and Cretaceous in the uplift around the sag and in the Permian upper Wuerhe formation within the sag. Focusing on key wells with oil and gas breakthroughs in the upper Wuerhe formation within the sag, and combining with the changes in exploration ideas and theoretical understanding, the exploration of the upper Wuerhe formation in the study area is divided into three stages, namely, source-edge fault block exploration stage, in-sag fault block exploration stage, and above-source lithologic exploration stage. The changes in exploration ideas brought about the discovery of high-yield oil and gas reservoirs in the upper Wuerhe formation on the eastern slope of the sag. Also, insights in three aspects have been gained. First, the source rocks in the Pingdiquan formation have entered the stage of light hydrocarbon generation, contributing to the near-source hydrocarbon accumulation in the upper Wuerhe formation. Second, a large-scale retrograde fan delta sedimentary system is developed in the upper Wuerhe formation, where the fan delta front facies belt superimposed by the thick layers of lowstand system tract(LST) and the thin layers of transgressive system tract(TST) serves as favorable reservoirs, with a distribution area of 3 350 km2. Third, the hydrocarbon accumulation in the upper Wuerhe formation is characterized by sand enrichment in troughs, reserves controlled by facies belts, and production controlled by pores/fractures. Petroleum discoveries are concentrated in the eastern part, while no successful drilling result has been made in the western part of the sag. With these exploration ideas and geological understanding to guide the exploration deployment, there will be new discoveries of oil and gas in the Dongdaohaizi sag. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment of Liaohe Depression in Bohai Bay Basin LI Xiaoguang, CHEN Yongcheng, LI Yujin, LAN Kuo, LI Jinghan, GONG Weiming Xinjiang Petroleum Geology    2021, 42 (3): 291-301.   DOI: 10.7657/XJPG20210305 Abstract （405）   HTML （6）    PDF（pc） （2056KB）（381）       Knowledge map    Save Based on a comprehensive review of more than 60 years of oil and gas exploration history in the Liaohe depression, this paper takes the discovery of oil and gas reserves as the main line, and fully considers the important roles of deepening theoretical understanding, improving exploration methods and applying new technologies, and divides the oil and gas exploration process in the Liaohe depression into five stages: regional reconnaissance and extensive exploration with fewer wells, local detailed prospecting and key breakthrough, exploration expanding and large-scale reserves increase, deepening onshore exploration and speeding up beach exploration, and fine exploration and stable development. Based on this, three enlightenments for oil and gas exploration are summarized: (1) The promotion of geological understanding and the application of new technologies are key factors of sustained discoveries of oil and gas reserves; (2) More attention should be paid to the study on fault development and evolution during rifted basin exploration; (3) Special types of oil and gas reservoirs are also important for oil and gas exploration in hydrocarbon-rich sags. The important roles of theoretical knowledge and exploration technologies in oil and gas exploration, and the relationship between faults and oil and gas distribution and enrichment are expounded. Oil and gas accumulation models are summarized for reservoirs inside metamorphic rock, igneous reservoirs and oil and gas reservoirs in shale, in the hope of acting as enlightenment and reference for the stereoscopic exploration of hydrocarbon-rich sags in rifted basins in the eastern China. Table and Figures | Reference | Related Articles | Metrics

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Genesis of Overpressure and Sealing Ability of Caprocks in Well Gaotan 1 in the Southern Margin of Junggar Basin LU Xuesong, ZHANG Fengqi, ZHAO Mengjun, ZHUO Qingong, GUI Lili, YU Zhichao, LIU Qiang Xinjiang Petroleum Geology    2021, 42 (6): 666-675.   DOI: 10.7657/XJPG20210603 Abstract （382）   HTML （18）    PDF（pc） （1440KB）（376）       Knowledge map    Save The southern margin of the Junggar basin is a typical petroliferous area with high or ultra-high pressure. To understand the oil and gas accumulation law and predict favorable exploration zones, it is important to clarify how the overpressure develops and how the oil and gas are preserved at strong overpressure. According to the overpressure characteristics and the exploration results from Well Gaotan 1, this study analyzed the overpressure causes in Well Gaotan 1, and then predicted the height of the hydrocarbon column that is dynamically closed by the hydraulic fractures in the caprock in the overpressure system. It’s found that there are multiple factors causing the overpressure in the Cretaceous Qingshuihe formation in Well Gaotan 1: tectonic compression accounts for 51.03%, pressure transmission accounts for 14.94% and undercompaction accounts for 34.03%; and the tectonic thrust and lateral compression stress during the Himalayan movement are major inducements of the abnormally high pressure in the deep formation. In the Cretaceous Qingshuihe formation in Well Gaotan 1, the mudstone caprock is thick, the displacement pressure is high and the sealing ability is strong. Therefore, hydraulic fractures in the caprock and the re-slipping of the pre-existing faults in the overpressure system dynamically control the maximum overpressure that the caprock can withstand and the maximum height of the hydrocarbon column that can be closed. The Cretaceous Qingshuihe formation and the Jurassic Toutunhe formation in Well Gaotan 1 are two independent pressure systems. The pressure coefficient of the Qingshuihe formation is 2.32, close to the critical pressure for the sliding of the pre-existing fault, so it is estimated that the maximum height of hydrocarbon column that can be dynamically closed before the burst of the caprocks is 200 m. The Middle and Upper Jurassic strata in the Gaoquan anticline are the next exploration target, the channel-delta front sandbodies may have high-quality reservoirs, and future exploration may focus on structural and lithological reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Jiuquan Basin XIANG Xin, WEI Haoyuan, WEI Deqiang, GAO Xiang, ZHAO Wei, LEI Fuping, XIE Jingyu, REN Xueyao Xinjiang Petroleum Geology    2021, 42 (3): 353-363.   DOI: 10.7657/XJPG20210312 Abstract （819）   HTML （11）    PDF（pc） （2262KB）（368）       Knowledge map    Save Petroleum exploration in Jiuquan basin started in the 1920s. Experienced the exploration process from uplift to depression, fruitful results in petroleum exploration have been achieved. The article reviews the 81-year exploration history in Jiuquan basin, sort out the main idea, technical means, significant discoveries and experience in every stage. Petroleum exploration practices show that the exploration should be foucued on geological research, guided by geological theory and geological understanding, and should be supported by exploration technology. Guided by the theories for exploration of secondary hydrocarbon-bearing structural belts, a number of anticline reservoirs have been discovered. Geology and engineering are closely integrated to form a supporting exploration technology adaptable for Qingxi oilfield, helping Qingxi oilfield make breakthroughs in exploration. After deepening geological understanding and changing exploration ideas three times, a hydrocarbon accumulation model was established for the Ying’er sag and Jiudong oilfield was discovered. New progresses have been made successively due to fine exploration in existing oil blocks after highlighting fine geological research and applying new technologies and methods. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 1-10.   DOI: 10.7657/XJPG20220101 Abstract （554）   HTML （37）    PDF（pc） （3132KB）（363）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Bohai Sea HAO Jing, ZHANG Houhe, LI Chunrong, ZHANG Wenzhao, LI Fanyi, YAN Han, XU Qingmei Xinjiang Petroleum Geology    2021, 42 (3): 328-336.   DOI: 10.7657/XJPG20210309 Abstract （532）   HTML （11）    PDF（pc） （1888KB）（343）       Knowledge map    Save The Bohai Sea has experienced more than 50 years of oil and gas exploration. Considering the breakthrough in oil and gas exploration domain, reserves growth, operation mode and other factors, the exploration process in the Bohai Sea can be divided into five stages: (1) Early exploration stage (1965-1979): it was dominated by exploration of bulges and buried hills; (2) Foreign cooperation stage (1980-1994): the exploration in this stage was targeted at the Paleogene; (3) Self-driven cooperation stage (1995-2005): its main exploration target was the Neogene; (4) 3D and multi-layer exploration stage (2006-2015); (5) Fine exploration stage (since 2016). Based on the major exploration achievements and milestone exploration events in all stages, this paper systematically summarizes the important theoretical understandings, including the theory of shallow hydrocarbon migration and accumulation, sand control principle of source-sink coupling in time and space, hydrocarbon accumulation mechanism of superimposed strike-slip fault zones, and the deep gas enrichment mechanism with “two highs and one fineness”. These new theoretical understandings further enrich and widen the oil and gas exploration theories, effectively guide the sustaining oil and gas discoveries in Bohai oilfield and have excellent application prospects. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Jizhong Depression SHEN Hua, FAN Bingda, WANG Quan, ZHANG Yiming, YANG Dexiang, GUO Huiping, WANG Mingwei Xinjiang Petroleum Geology    2021, 42 (3): 319-327.   DOI: 10.7657/XJPG20210308 Abstract （365）   HTML （5）    PDF（pc） （2055KB）（325）       Knowledge map    Save Based on a large number of literatures, this paper analyzes the exploration history in the Jizhong depression with the breakthrough of exploration understanding, transformation of exploration ideas and advancement of exploration technologies as the main line. The oil and gas exploration process of the Jizhong depression is divided into four stages：regional geological reconnaissance and exploration (1955-1972); exploration focusing on ancient buried-hill oil reservoirs (1973-1985); exploration mainly attacking the Palaeogene-Neogene structural oil reservoirs (1986-1999) and exploration of lithostratigraphic oil reservoirs and subtle buried-hill oil and gas reservoirs (2000-2019). This paper summarizes the exploration understanding, exploration ideas, exploration technologies, major exploration discoveries and reserves growth characteristics of each exploration stage. Based on which, Huabei oilfield has refined the new theoretical understanding and reservoir-forming model of buried-hill oil and gas reservoirs, and led multiple rounds of exploration and sustained discoveries in the field of buried hill through continuous innovation. The new theories of “complementarity” of oil and gas distribution and “oil accumulation in sags and troughs” effectively guide the active exploration and large-scale discoveries of lithostratigraphic oil reservoirs. The evaluation method of “play optimization-trap delineation-reservoir discovery” has effectively promoted the exploration deployment optimization of lithostratigraphic oil reservoirs. These exploration implications have deepened the understandings of oil and gas exploration and discovery in continental lacustrine fault depressions, which has important reference and guiding significance for China’s oil and gas exploration in the future. Table and Figures | Reference | Related Articles | Metrics

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Connectivity Characterization of Fractured-Vuggy Carbonate Reservoirs and Application WU Meilian, CHAI Xiong, ZHOU Bihui, LI Hong, YAN Nan, PENG Peng Xinjiang Petroleum Geology    2022, 43 (2): 188-193.   DOI: 10.7657/XJPG20220209 Abstract （351）   HTML （11）    PDF（pc） （5285KB）（325）       Knowledge map    Save Fractured-vuggy carbonate reservoirs are difficult to develop efficiently due to their strong heterogeneity, challenging connected unit identification, and unknown inter-well connectivity. In this paper, facies-controlled inversion and maximum likelihood attribute were used to characterize the fractured-vuggy aggregate and spatial distribution of large-scale fractures, so as to identify connected units and clarify the inter-well connection mode and the remaining oil potential. Based on dynamic data of wells, the connectivity was analyzed to verify the rationality of the connectivity characterization result obtained from static data. The technique was applied in the gas injection development of the Lungu 7-5 well group in the Lungu 7 wellblock, providing a basis for gas injection development strategy making to further improve the reservoir recovery performance. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment of Biyang Sag and Nanyang Sag in Nanxiang Basin YUAN Yuzhe, LUO Jiaqun, ZHU Yan, LIU Guilan, LI Lei, YU Mengli Xinjiang Petroleum Geology    2021, 42 (3): 364-373.   DOI: 10.7657/XJPG20210313 Abstract （723）   HTML （6）    PDF（pc） （1926KB）（321）       Knowledge map    Save The Nanxiang basin is composed of three swells and four sags. Over more than 40 years of exploration, oil and gas have been discovered in the Biyang sag and Nanyang sag, and fruitful achievements have been obtained. Mainly based on the three peaks of reserves increase in the process of exploring the Biyang sag and the Nanyang sag, this paper divides the basin exploration process into three stages: initial exploration (1970-1983), comprehensive exploration (1984-1999) and detailed exploration (since 2000). After analyzing the major achievements of each stage, it is found that oil and gas enrichment laws in the Biyang sag are more clear and the reservoir types are more representative than those in the Nanyang sag. The Biyang sag can be divided into four important oil and gas enrichment zones: Shuanghe nose-like structure, northern slope zone, southern steep slope zone and around-subsag zone. According to comprehensive analysis of geological characteristics and reservoir-forming conditions, specific exploration ideas, techniques and methods are summarized, including large updip pinch-out sandstone reservoirs in the rifted lacustrine basin, complex fault-block reservoirs in the northern slope zone, small glutenite reservoirs in the southern steep slope zone, and fault-lithologic reservoirs in the around-subsag zone. These results may enlighten future oil and gas exploration. Table and Figures | Reference | Related Articles | Metrics

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Multistage Deformation of Yingjisha Anticline in the Front of Southwestern Tarim Thrust Belt, Northwestern China YANG Geng, CHEN Zhuxin, WANG Xiaobo Xinjiang Petroleum Geology    2021, 42 (6): 656-665.   DOI: 10.7657/XJPG20210602 Abstract （443）   HTML （12）    PDF（pc） （3218KB）（320）       Knowledge map    Save In southwestern Tarim basin in the piedmont of western Kunlun Mountain, there are several thrust belts where multiple oil and gas fields have been found. Based on the fault-related fold theory and drilling and 2D seismic data, the Yingjisha anticline in the piedmont of southwestern Tarim basin is finely interpreted, where shallow detachment layers are discovered in the mudstone and gypsum mudstone of the Miocene Anju’an formation, and several shallow simple fault-bended folds are developed as well. It is concluded that the Yingjisha anticline is composed of shallow, middle-deep and deep structural intervals that are superimposed vertically. A wedge structure which contains multiple imbricate structures of thrust faults are developed in the middle-deep interval. Simple imbricate structures are in the deep interval. The growth strata and structural deformation styles indicated that the shallow structures were formed the earliest, followed by the middle-deep structures, and finally the deep structures. In short, there are multiple stages of episodic thrusts starting from the west Kunlun Mountain toward the Tarim basin, so the thrust structures in southwestern Tarim basin have undergone multiple stages of episodic activities. The structures developed in different periods are superimposed vertically, resulting in the present structural pattern. Table and Figures | Reference | Related Articles | Metrics

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Fractured Horizontal Well Test Model for Shale Gas Reservoirs With Considering Multiple Stress Sensitive Factors LU Ting, WANG Mingchuan, MA Wenli, PENG Zeyang, TIAN Lingyu, LI Wangpeng Xinjiang Petroleum Geology    2021, 42 (6): 741-748.   DOI: 10.7657/XJPG20210614 Abstract （378）   HTML （21）    PDF（pc） （36478KB）（320）       Knowledge map    Save Shale gas reservoir has multi-scale pore structures, so that shale gas flows in multiple ways including absorbing, diffusing and non-Darcy flow. Present shale gas flowing models only take the permeability and porosity of natural fractures as stress sensitivity factors, but experiments show that the diffusion coefficient is also sensitive to stress. To accurately predict and analyze shale gas reservoir and fluid parameters, it is necessary to establish a fractured horizontal well test model which should consider multi-scale pore structures and multiple gas flowing mechanisms, and it is also helpful to production performance analysis and subsequent development plan making. In this study, according to the multi-scale pore structures, and assuming that the shale gas reservoir is a dual medium with matrix and fractures, we built a fractured horizontal well test model which takes diffusion coefficient, and porosity and permeability of natural fractures as stress sensitive parameters, and analyzed the effects of fracturing scale and reservoir parameters on well test curve. The results show that fracturing parameters mainly affect early post-fracturing production, while reservoir parameters mainly affect late production. The model was applied in a typical shale reservoir block in China, and the modelling result well matched with the measured production data. It is a guiding reference to effective development of shale gas reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Incremental Proven Oil and Natural Gas Geological Reserves in China ZHOU Liming, HAN Zheng, ZHANG Daoyong, REN Jihong, FENG Zhigang, ZHANG Chenshuo Xinjiang Petroleum Geology    2022, 43 (1): 115-121.   DOI: 10.7657/XJPG20220117 Abstract （460）   HTML （21）    PDF（pc） （539KB）（309）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Characteristics of Water Breakthrough and Optimization of Production System of Oil Wells Drilled in Ultra-Deep Fault-Karst Reservoirs: A Case Study on Well Z in Shunbei Oilfield, Tarim Basin CHENG Xiaojun Xinjiang Petroleum Geology    2021, 42 (5): 554-558.   DOI: 10.7657/XJPG20210506 Abstract （307）   HTML （7）    PDF（pc） （1641KB）（307）       Knowledge map    Save In order to optimize the production system after water breakthrough in the oil wells drilled in ultra-deep fault-karst reservoirs and taking Well Z in Shunbei oilfield in Tarim basin as a case, the characteristics of reservoir geology and water breakthrough in the oil wells were analyzed through reservoir engineering method and numerical simulation. The well productivities before and after water breakthrough were compared, the water invasion rate and producing reserves were calculated, the water channeling characteristics was studied based on numerical simulation and the production system after water breakthrough was optimized. The results show that: 1) The inflow performance curve of Well Z is upturned, because the fluid flows at a higher rate after reducing the bottom hole flowing pressure or increasing the bottom hole producing pressure difference, and new fractures and caves open and more flowable channels occur, resulting in a great increase of the oil productivity in the well; 2) After water breakthrough, the daily oil production dropped sharply, and the productivity reduced dramatically; 3) The producing reserves in Well Z are about 338×104 t, bottom water invaded in January 2020 at a rate of about 0.61×104 m³/month, and by November 3, 2020, the water cone in Well Z was about 395 m from the initial oil-water contact and about 131 m from the bottom hole. According to the results, a 7 mm choke was recommended and used in Well Z. After field application, the daily oil production has increased from 96 t to 170 t and the water cut has been controlled less than 2.00%, indicating a satisfactory result. Table and Figures | Reference | Related Articles | Metrics

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Self-Emulsification and Waterflooding Characteristics of Heavy Oil Reservoirs in Wellblock Ji-7 LIU Yanhong, WAN Wensheng, LUO Hongcheng, LI Chen, ZHANG Wu, MA Baojun Xinjiang Petroleum Geology    2021, 42 (6): 696-701.   DOI: 10.7657/XJPG20210607 Abstract （720）   HTML （12）    PDF（pc） （593KB）（300）       Knowledge map    Save With self-emulsification function, the heavy oil reservoir in Wellblock Ji-7 is different from light oil reservoirs and conventional heavy oil reservoirs in waterflooding behaviors at normal temperature, and the waterflooding efficiency is higher in the reservoir. After analyzing the cause of the self-emulsification and the characteristics of emulsion in Wellblock Ji-7, the waterflooding behaviors are defined and it is considered that the main reason for a long-term steady water cut in the middle water-cut period in Wellblock Ji-7 is that the water-to-oil ratio is close to 1 due to the self-emulsification of water-in-oil emulsion. It is further proposed that stabilizing the water-to-oil ratio is one of the most effective measures for waterflooding development in heavy oil reservoirs, and keeping the water-to-oil ratio around 1 can maximize the recovery of heavy oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Applicability of Nitrogen Foam in Developing Shallow-Thin Ultra-Heavy Oil Reservoirs CHANG Taile, YANG Yuanliang, GAO Zhiwei, HU Chunyu, ZHENG Xiaoqiang, ZHANG Meng, YUAN Yiping Xinjiang Petroleum Geology    2021, 42 (6): 690-695.   DOI: 10.7657/XJPG20210606 Abstract （356）   HTML （9）    PDF（pc） （555KB）（298）       Knowledge map    Save Located in the Neogene Shawan formation in the central Block Pai 601 and southern Block Pai 6 of Chunfeng oilfield, the ultra-heavy oil reservoirs are characterized by shallow burial, thin pays, low original formation pressure and high crude oil viscosity. A compound method integrating horizontal well, viscosity reducer, steam with nitrogen is usually used to develop these reservoirs. After several cycles of huff and puff development, the formation pressure dropped, edge and bottom water broke through the oil-water contact and coned upward, resulting in a longer water drainage period, higher cumulative water production, and a shorter effective production period, and consequently relatively low ultimate oil recovery. Therefore, a steam huff and puff test assisted by nitrogen foam was carried out, and indoor experiments and numerical simulation techniques were used to analyze and compare foam applicability and optimize injection parameters and process. Field test results show that after applying steam huff and puff assisted by nitrogen foam in the blocks with edge and bottom water intrusion, the average water drainage period in the oil well was shortened by 8.3 days, the water cut decreased by 32.2% and the cumulative oil production increased by 2 606.0 t. In the blocks after several cycles of huff and puff, injecting nitrogen foam reduced the water cut by 8.6% and increased the cumulative oil production by 1 668.0 t, indicating that nitrogen foam can effectively increase formation energy, block large pore channels, adjust steam absorption profile and play a key role in improving the ultimate oil recovery. Table and Figures | Reference | Related Articles | Metrics

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Fracability Evaluation of Conglomerate Reservoirs in Baikouquan Formation in Ma-131 Well Block CAI Wenjun, FENG Yongcun, YAN Wei, JIANG Qingping, MENG Xianglong, LIU Kai Xinjiang Petroleum Geology    2022, 43 (2): 194-199.   DOI: 10.7657/XJPG20220210 Abstract （305）   HTML （7）    PDF（pc） （5972KB）（293）       Knowledge map    Save For developing the tight conglomerate reservoirs in the Baikouquan formation in Mahu oilfield with small well-spacing, it is urgent to establish an appropriate fracability evaluation model. Based on the optimal parameters such as elastic modulus, Poisson’s ratio and minimum in-situ stress, and combined with the core, logging and seismic data, the 3D geomechanical modeling was carried out for Ma-131 well block. The spatial distribution of the fracability index (0.38-0.91) of the reservoir in the study area was determined. Coupling with the microseismic fracture monitoring and production data from 12 horizontal wells, it is found that the calculated fractability index is consistent with the fracture propagation direction and scale, and the actual production performance of the wells. The research results may provide a basis for developing the conglomerate reservoirs in the study area. Table and Figures | Reference | Related Articles | Metrics

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Lower Limits of Pore Throat Radius for Movable Fluids in Shale Reservoirs of Lucaogou Formation in Jimsar Sag TANG Hongjiao, LIANG Baoxing, LIU Weizhou, LIU Huan, SHI Feng, LAN Shangtao, WANG Qixiang Xinjiang Petroleum Geology    2021, 42 (5): 612-616.   DOI: 10.7657/XJPG20210515 Abstract （218）   HTML （10）    PDF（pc） （499KB）（291）       Knowledge map    Save To get sufficient theoretical and experimental data for determining the lower limits of pore throat radius for movable fluids in shale reservoirs, core NMR, centrifugal, flowing and high-pressure mercury intrusion experiments were carried out on the physical characteristics of shale oil. Based on bridging theory and boundary layer theory, and combining macroscopic and microscopic analysis results, a method for determining the lower limits of pore throat radius in shale reservoirs was established. It is concluded that the lower limits of pore throat radius in the shale reservoirs of the Permian Lucaogou formation in Jimsar sag is 50 nm; the pore throats with the radius ranging from 50 nm to 500 nm are the primary contributors to movable fluids, and the contribution of the pore throats with the radius larger than 500 nm to movable fluids is less than 10%. Table and Figures | Reference | Related Articles | Metrics

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EOR of CO2 Flooding in Low-Permeability Sandy Conglomerate Reservoirs LI Yan, ZHANG Di, FAN Xiaoyi, ZHANG Jintong, YANG Ruisha, YE Huan Xinjiang Petroleum Geology    2022, 43 (1): 59-65.   DOI: 10.7657/XJPG20220109 Abstract （343）   HTML （13）    PDF（pc） （2398KB）（282）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment of Changqing Oilfield in Ordos Basin ZHANG Caili, LIU Xinshe, YANG Yajuan, YU Jian, HAN Tianyou, ZHANG Yan Xinjiang Petroleum Geology    2021, 42 (3): 253-263.   DOI: 10.7657/XJPG20210301 Abstract （293）   HTML （6）    PDF（pc） （4351KB）（278）       Knowledge map    Save This paper systematically analyzes the geological theories of hydrocarbon accumulation and summarizes the exploration achievements made by Changqing oilfield in the Ordos basin. The exploration process in the Ordos basin can be divided into five stages: (1) Oil and gas exploration for the structures in the basin and its surroundings from 1907 to 1969; (2) Oil exploration in the Jurassic paleogeomorphology from 1970 to 1979; (3) Oil and gas exploration in the Triassic delta and Ordovician karst paleogeomorphology from 1980 to 1999; (4) Oil and gas exploration for large lithological reservoirs from 2000 to 2012; (5) Exploration of tight and unconventional oil and gas since 2013. During more than 50 years of exploration practices, a number of innovative geological cognitions and theories have been developed, such as hydrocarbon accumulation in Jurassic paleogeomorphic oil reservoir groups, hydrocarbon accumulation in large delta reservoirs in continental lacustrine basin, shale oil accumulation in terrestrial freshwater lake basin, gas accumulation in tight sandstone, gas accumulation in karst paleogeomorphy and hydrocarbon accumulation in multiple series in the eastern Ordos basin, which promoted sustainable breakthroughs to oil and gas exploration in the Ordos basin. Table and Figures | Reference | Related Articles | Metrics

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Variations of Physical Properties of Shale Oil in Jimsar Sag, Junggar Basin YAO Zhenhua, QIN Jianhua, GAO Yang, CHEN Chao, LIU Zhenping, ZHANG Xiaogong Xinjiang Petroleum Geology    2022, 43 (1): 72-78.   DOI: 10.7657/XJPG20220111 Abstract （355）   HTML （11）    PDF（pc） （691KB）（272）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Natural Energy Partition in Offshore Thin Heavy Oil Reservoirs With Edge Water XIE Mingying, YAN Zhenghe, WEI Xihui, WU Liulei, ZHANG Yu Xinjiang Petroleum Geology    2021, 42 (5): 579-583.   DOI: 10.7657/XJPG20210510 Abstract （212）   HTML （3）    PDF（pc） （498KB）（268）       Knowledge map    Save The E heavy oil reservoir with edge water in eastern South China Sea has thin pay zones, gentle structures and a large oil-bearing area. The regional energy is insufficient and the production capacity can’t support oilfield development at a high rate, so it is urgent to update the development model. Numerical simulation was carried out on the influence of controlling factors on oil well performance and reservoir pressure, and the extreme distance from an oil well to the edge water was estimated when natural energy supply is sufficient, then the zones with sufficient energy and insufficient energy were determined, and finally natural energy partition charts for different water multiples were established after analyzing the controlling factors and grey correlation. The research results indicate that: (1) The higher the reservoir permeability, the higher the oil mobility, the thicker the pay zone, the greater the water multiples and the lower the fluid recovery rate, and the larger the sufficient energy zone range; (2) The natural energy boundary in the E reservoir, namely the extreme distance between an oil well and the edge water, is 922 m, which is consistent with the regional production performance. The findings above have proved that the charts are reliable and can be a reference to developing similar oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 444-449.   DOI: 10.7657/XJPG20210407 Abstract （362）   HTML （6）    PDF（pc） （5347KB）（267）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Petroleum Exploration History and Enlightenment in Hailar Basin LI Chunbai Xinjiang Petroleum Geology    2021, 42 (3): 374-380.   DOI: 10.7657/XJPG20210314 Abstract （427）   HTML （6）    PDF（pc） （1645KB）（264）       Knowledge map    Save After looking back the oil and gas exploration history and summarizing the geological understanding, engineering technology and important exploration results in the Hailar basin since the 1950s, the exploration process of the Hailar basin can be divided into four stages, namely regional exploration for oil and gas discovery, structural reservoir exploration for breakthrough, fault-block reservoir and lithologic reservoir exploration for reserves increase, and multi-type reservoir exploration for further expansion. Many years of exploration practice proves the following conclusions: (1) Every innovation in understanding and every change in thinking bring new portunities to exploration; (2) Breakthrough to key seismic technologies can effectively improve geophysical imaging quality and lay a foundation for deepening understanding of complex structural zones in complex faulted basins; (3) The prototype basin controls the formation and evolution of source rocks, and the structural belts in sags control the migration and enrichment of oil and gas, so that the optimal selection of major sags and the clear understanding of reservoir forming controlled by faults and structures are the basis and key points guiding exploration; (4) Understanding oil and gas enrichment laws in subsag-slope zones allows the changes of exploration ideas and expansion in exploration field and space; (5) The innovation in the understanding of geological theory is fundamental for widening exploration field and making sustainable discoveries, and it is also helpful to broaden our mind and encourage innovation in future exploration. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 11-17.   DOI: 10.7657/XJPG20220102 Abstract （369）   HTML （13）    PDF（pc） （5592KB）（261）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Injection-Production Optimization of Carbonate Oil Reservoirs Based on a Well Connectivity Model LEI Sheng, ZHOU Yuhui, WANG Ning, Saierjiang AHATI, ZHENG Qiang, SHENG Guanglong Xinjiang Petroleum Geology    2021, 42 (5): 584-591.   DOI: 10.7657/XJPG20210511 Abstract （302）   HTML （13）    PDF（pc） （636KB）（260）       Knowledge map    Save Carbonate oil reservoirs are very heterogeneous, so that injected water is easy to advance through high-permeability channels, and results in water channeling or flooding, and consequently fast rising water cut and low development effeciency in production wells. Based on the principle of well connectivity, and considering the geological features and development performance of fractured-vuggy carbonate oil reservoirs, parameters of well connectivity (conductivity and connected volume) were quantitatively characterized, then a vertical multi-layer well connectivity model was established, and parameters such as plane splitting coefficient and utilization rate of injected water were estimated for each layer of the oil reservoirs, and finally by using automatic history matching method and production optimization algorithm, real-time optimization and prediction of production performance of oil and water wells were realized. Field application has proved that the yearly incremental oil production is 1.1×104 m3 by using this method and good effect has been obtained. The method has important guiding significance for efficient development of similar oil reservoirs. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 437-443.   DOI: 10.7657/XJPG20210406 Abstract （289）   HTML （13）    PDF（pc） （638KB）（260）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Production Performance Analysis and Productivity Prediction of Horizontal Wells in Mahu Tight Conglomerate Reservoirs：A Case of Ma 131 Dense-Spacing 3D Development Pad CAO Wei, XIAN Chenggang, WU Baocheng, YU Huiyong, CHEN Ang, SHEN Yinghao Xinjiang Petroleum Geology    2022, 43 (4): 440-449.   DOI: 10.7657/XJPG20220409 Abstract （278）   HTML （18）    PDF（pc） （1161KB）（260）       Knowledge map    Save In order to clarify the productivity and production performance of Ma131 dense-spacing 3D development pad,the production characteristics and unstable production/productivity were predicted,a workflow for performance analysis and productivity prediction was established,and the key parameters such as equivalent formation permeability and effective fracture half-length,etc. were determined for single well productivity prediction. Oil in the target reservoir is easy to be degassed,which may be effectively alleviated by running the gas nozzle into the hole in the early stage. The use of over-sized oil nozzle in the early stage of flowback may greatly decrease the fracture volume; in this case,a pressure-managed flowback is necessary. The P50 productivity prediction results obtained from the production decline curves and the analytical model can complement each other,providing a more accurate and reasonable productivity prediction interval. The average effective fracture half-length of horizontal well in T1b3 is greater than that in T1b1 2; therefore,the well spacing can be further optimized. Table and Figures | Reference | Related Articles | Metrics

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Genesis and Coupling Relationship of Fractures in Shale Reservoir of Lucaogou Formation in Jimsar Sag, Junggar Basin LIANG Chenggang, XIE Jianyong, CHEN Yiwei, LIU Juanli, HE Yongqing, ZHAO Jun, WANG Wei, WANG Liangzhe Xinjiang Petroleum Geology    2021, 42 (5): 521-528.   DOI: 10.7657/XJPG20210502 Abstract （284）   HTML （17）    PDF（pc） （10928KB）（255）       Knowledge map    Save According to the data of outcrops, cores and thin sections of the shale reservoir of the Lucaogou formation in the Jimsar sag, Junggar basin, and considering the imaging logging data, physical simulation of oil and gas migration and triaxial rock fracturing experiment etc., we studied the genesis and coupling relationship of fractures in the shale reservoir in micro and macro scales based on the stress-strain curve. The results show that: (1) The mutual coupling of bedding fractures and structural fractures can greatly improve the physical properties of the shale reservoir; (2) Bedding fractures and structural fractures are influenced by each other during their devlopment. When the rock with bedding fractures is compressed in the direction vertical to the bedding plane, multi-stage fractures are likely to appear and form a fracture system with interlaced bedding fractures and structural fractures; when the rock is compressed in the direction parallel to the bedding plane, a fracture system with less stages may occur, which is mainly composed of bedding fractures; (3) The parallel coupling of structural fractures and bedding fractures has no significant impact on the permeability of the shale reservoir, while their vertical coupling can significantly increase the permeability of the shale reservoir. Table and Figures | Reference | Related Articles | Metrics

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Evaluation on Injection-Production Connectivity of Low-Permeability Reservoirs Based on Tracer Monitoring and Numerical Simulation LI Ning, YANG Lin, ZHENG Xiaomin, ZHANG Jinhai, LIU Yichen, MA Jiong Xinjiang Petroleum Geology    2021, 42 (6): 735-740.   DOI: 10.7657/XJPG20210613 Abstract （356）   HTML （12）    PDF（pc） （1418KB）（255）       Knowledge map    Save As a typical oilfield developing low-permeability reservoirs in China, Changqing oilfield has huge resources of tight oil and gas. However, strong reservoir heterogeneity, poor injection-production connectivity and low oil recovery make it urgent to describe the reservoir development units in details to improve the development effects of well groups at medium-high water cut stage. Taking well group Q011-35 as a case, this study evaluated the waterflooding development effect of the well group based on the contact types of the target Chang 61 sand bodies and the results of tracer monitoring and reservoir numerical simulation. It is concluded that the well group Q011-35 is strongly heterogeneous. Laterally, there are high-permeability zones in the northwest and southwest, while vertically, Chang $6^2_1$ is flooded more completely than Chang $6^1_1$, and the remaining oil in Chang $6^1_1$ is richer, indicating reservoir connectivity and injection-production relationship are controlling factors on the distribution of remaining oil. The combination of tracer monitoring and reservoir numerical simulation eliminates the limitations caused by a single method in evaluating interwell connectivity, therefore the results are more accurate and reasonable. The conclusion is a reference to fine evaluation on waterflooding development effect of low-permeability reservoirs and taking effective measures for potential tapping of remaining oil. Table and Figures | Reference | Related Articles | Metrics

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Exploration Progress and Potential Evaluation of Deep Oil and Gas in Turpan-Hami Exploration Area ZHI Dongming, LI Jianzhong, CHEN Xuan, YANG Fan, LIU Juntian, LIN Lin Xinjiang Petroleum Geology    2023, 44 (3): 253-264.   DOI: 10.7657/XJPG20230301 Abstract （316）   HTML （537）    PDF（pc） （2522KB）（254）       Knowledge map    Save To realize the shift of oil and gas exploration from shallow-middle to deep strata, and from conventional to unconventional resources, and then to promote the exploration of deep oil and gas resources in the Turpan-Hami exploration area, the tectonic-lithofacies palaeogeographical evolution of Turpan-Hami basin, Santanghu basin, and Zhundong block of Junggar basin were analyzed, the characteristics and exploration potential of the petroleum systems in these basins were evaluated, the main exploration targets were determined, and the fields for strategic breakthrough were selected. In the Carboniferous-Permian period, the Turpan-Hami exploration area was a unified sedimentary basin with similar sedimentary environments and structures. In the Triassic-Jurassic period, the study area was separated into several independent foreland basins. With the tectonic-lithofacies palaeogeographical evolution, three sets of source rocks (marine-transitional facies of Carboniferous, lacustrine facies of Permian, and lacustrine-coal measure of Jurassic) were formed, contributing to three major petroleum systems. The change in exploration ideas has promoted significant progress in petroleum exploration in deep strata. Significant breakthroughs have been made in the exploration of Shiqiantan formation marine clastic oil and gas reservoirs, Permian shale oil reservoirs and conventional sandstone oil reservoirs in the Zhundong block, and the Middle-Lower Jurassic large-scale tight sandstone gas reservoirs in the Turpan-Hami basin, which enables the discovery of large-scale high-quality reserves and the orderly succession of strategic resources. Future exploration should be carried out at three levels: strategic preparation, strategic breakthrough, and strategic implementation, with a focus on 10 favorable directions. Table and Figures | Reference | Related Articles | Metrics

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Development Characteristics and Model of Cili Longwang Karst Cave in Hunan Province XU Xinyu, CHEN Qinghua, JI Dongsheng, CUI Youwei Xinjiang Petroleum Geology    2022, 43 (2): 145-152.   DOI: 10.7657/XJPG20220203 Abstract （415）   HTML （10）    PDF（pc） （1966KB）（249）       Knowledge map    Save To study the development characteristics and model of the Longwang Cave in the Cili area of Hunan province, a 3D model is constructed by using manual survey and 3D laser scanning technology to characterize the structure of the karst cave. The Longwang Cave can be divided into three sections. The western section is NEE-SWW trending and filled with chemical cements. The middle section is NNE-SSW trending and filled with collapsed cements. The eastern section is nearly EW trending, and filled with chemical cements and flowing water deposits. As for the filling degree, the middle section shows the highest, the western section is higher, and the eastern section is the lowest. Controlled by a NEE-SWW trending fracture zone, the Longwang Cave is a typical fracture-controlled karst cave which has undergone four development stages. First, a NEE-SWW fracture zone was formed along the Sanguansi syncline. Then the rock was dissolved along the fracture zone by karst water from west to east, and an initial karst cave formed. Second, the initial karst cave was dislocated by NNW-SSE trending strike-slip thrust faults and then differential dissolution occured, that is, the western section was dissolved to a higher degree than the middle and eastern sections. Third, due to different numbers and scales of fractures, differential dissolution made the carst caves in the western section further expand, and the karst caves in the eastern section gradually connected together. The dissolution of the western section was higher than that of the eastern section. Finally, the middle section inherited the previous dissolution characteristics, so it is weaker than the eastern and western sections in dissolution. After the four stages above, the Longwang Cave shows its present structure. Table and Figures | Reference | Related Articles | Metrics

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Determination and Application of Welge Equation for Reservoirs After Water Breakthrough GAO Wenjun, TIE Qi, ZHENG Wei, TANG Xin Xinjiang Petroleum Geology    2022, 43 (1): 79-84.   DOI: 10.7657/XJPG20220112 Abstract （322）   HTML （10）    PDF（pc） （814KB）（248）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Numerical Simulation on Fracture Propagation in Conglomerate in Mahu Sag LIU Pengyu, JIANG Qingping, SHEN Yinghao, ZHAO Tingfeng, GE Hongkui, ZHOU Dong Xinjiang Petroleum Geology    2022, 43 (2): 227-234.   DOI: 10.7657/XJPG20220215 Abstract （295）   HTML （7）    PDF（pc） （4324KB）（244）       Knowledge map    Save For the conglomerate in the Mahu sag, the law and controlling factors of fracture propagation are unclear. A numerical simulation model for conglomerate was constructed to analyze the law of fracture propagation in conglomerate with different material properties under different loading modes. The results show that the higher the gravel content, the lower the cementation strength and the greater the relative strength of gravel to matrix, the more complex the fractures created in the conglomerate. Influenced by loading mode, the most complex fractures are created in the conglomerate under the combined action of tensile and shear loads. The attracting and shielding effects of gravel on conglomerate fractures promote the formation of complex fracture network in the conglomerate. Table and Figures | Reference | Related Articles | Metrics

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Application of Thin Reservoir Prediction Technology Based on Frequency Domain in Coal Measure Strata FENG Xinpeng, WANG Tao, BAI Zhitao, NIE Wancai, HE Zhengguang Xinjiang Petroleum Geology    2021, 42 (5): 605-611.   DOI: 10.7657/XJPG20210514 Abstract （219）   HTML （7）    PDF（pc） （17456KB）（243）       Knowledge map    Save The Lower Permian Taiyuan formation of marine-continental transitional facies and the second member of the Middle Permian Shanxi formation (Shan 2 member for short) of delta front facies are primary natural gas pay zones in eastern Ordos basin. They are tight lithologic gas reservoirs characterized by thin sand body and small scale. In the Taiyuan formation and the Shanxi formation, there are several coal seams, among which No. 4+5 coal seam in the middle-lower Shan 2 member and No. 9 coal seam at the bottom of the Taiyuan formation are most developed. With lower wave impedance, coal seams show stronger reflection than sandstone and shale with higher wave impedances, so that the former shield the weak reflection from the latter, making it difficult to effectively predict thin sand bodies by using conventional methods such as prestack inversion and seismic attributes. On the geological model of sandstone and shale reservoirs in the target intervals in the study area, we carried out forward modeling and time-frequency analysis, and found that generalized S-transform could adaptively adjust time-frequency analysis window according to signal frequency, and its resolution was higher. In the actual application, strong reflections from coal seams were suppressed, then generalized S-transform was performed to predict thin reservoirs in the study area. The result shows a high coincidence rate between seismic data and well logging data. The method can effectively predict thin reservoirs on the background of coal seams. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 410-417.   DOI: 10.7657/XJPG20210403 Abstract （291）   HTML （6）    PDF（pc） （5006KB）（241）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Paleo-Hydrogeomorphic Characteristics of EpisodeⅡof Middle Caledonian Movement and Their Controls on Karst Cave Development in Western Slope Area of Tahe Oilfield ZHANG Changjian, LYU Yanping, WEN Huan, WANG Zhen, MA Hailong Xinjiang Petroleum Geology    2022, 43 (2): 135-144.   DOI: 10.7657/XJPG20220202 Abstract （338）   HTML （9）    PDF（pc） （7377KB）（240）       Knowledge map    Save In order to understand the mechanism that the karstification during the Episode Ⅱof the Middle Caledonian movement controlled the development of karst caves in the Upper Ordovician coverage area in the western slope area of Tahe oilfield, the paleo-hydrogeomorphic and underground karst cave system of the Episode Ⅱ of the Middle Caledonian movement were precisely described using different methods. The results show that the karst platform is dominated by karst hills and depressions, the surface water system is dendritic, and the underground river-cave system is developed, forming an “open” underground river-karst system. The karst slope is dominated by hills and valleys, and deep incised valleys are developed because of strong vertical erosion, forming a “downward” buried fault-controlled karst system. The karst basin in the southern part of the platform margin is flat and the surface runoff is underdeveloped, with weak vertical erosion, but mainly horizontal dissolution, forming a “rising” buried fault-controlled karst system. Based on the paleo-hydrogeomorphic characteristics, the development model of karst caves under the control of special hydrogeomorphology of the Episode Ⅱof the Middle Caledonian movement was established for the Lianglitage formation coverage area in the western slope area of Tahe oilfield, which provides a geological basis for subsequent rolling development. Table and Figures | Reference | Related Articles | Metrics

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Well Logging Evaluation of Bauxite Reservoirs in Ordos Basin LIU Die, ZHANG Haitao, YANG Xiaoming, ZHAO Taiping, KOU Xiaopan, ZHU Baoding Xinjiang Petroleum Geology    2022, 43 (3): 261-270.   DOI: 10.7657/XJPG20220302 Abstract （490）   HTML （21）    PDF（pc） （4208KB）（237）       Knowledge map    Save Bauxite gas reservoir is a kind of very rare unconventional gas reservoir recently discovered in the Ordos basin, and well logging evaluation plays an important role in its exploration and development. In the early well logging evaluation, bauxite was considered as the weathering crust caprock, but not as a reservoir, and there was no systematic well logging evaluation method suitable for the exploration and development of bauxite gas reservoirs. Based on the aluminous rocks in Taiyuan formation in the Longdong area, southwestern Ordos basin, the well logging evaluation method for bauxite gas reservoirs was studied from five aspects, that is, qualitative lithology identification, mineral composition, reservoir physical properties, quantitative calculation of gas-bearing properties and systematic summary of imaging model-pore structure characteristics. The well logging response for identifying aluminous rock formations was clarified and the aluminous rock identification chart by acoustic time-gamma ray was established. The porosity-permeability-saturation evaluation model for bauxite gas reservoirs was constructed through petrophysical experiments, and the criteria for identifying bauxite reservoir was proposed by combining micro-resistivity scanning imaging and nuclear magnetic resonance logging data. Finally, a well logging evaluation method for bauxite gas reservoirs was formed. Table and Figures | Reference | Related Articles | Metrics

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Brittle Characteristics of Lucaogou Formation Reservoir in Jimsar Sag, Junggar Basin SHI Shanzhi, ZOU Yushi, WANG Junchao, ZHANG Shicheng, LI Jianmin, ZHANG Xiaohuan Xinjiang Petroleum Geology    2022, 43 (2): 169-176.   DOI: 10.7657/XJPG20220206 Abstract （297）   HTML （17）    PDF（pc） （2337KB）（235）       Knowledge map    Save The lithology of the Lucaogou formation reservoirs in Jimsar sag is complex, and the rock brittleness has a significant impact on productivity. Based on the analysis of mineralogy, mechanical parameters and energy evolution characteristics, a new method for brittleness evaluation suitable for the Lucaogou formation reservoirs was proposed, which follows an analytic hierarchy process to compare the brittleness characteristics of different lithologies. The results show that the Lucaogou formation reservoir in the Jimsar sag has a low clay content and small differences in the contents of brittle minerals, so it is difficult to accurately evaluate the rock brittleness with the brittleness index; the reservoir is very heterogeneous, and the brittleness of different rocks varies greatly: the average comprehensive brittleness index of the argillaceous siltstone, sandy dolomite and mud shale is higher than 0.60, the average comprehensive brittleness index of the dolomitic siltstone and micrite dolomite is medium, ranging from 0.50 to 0.60, and the average comprehensive brittleness index of the dolomitic mudstone is relatively lower, only 0.49; for the rock samples taken from the same core, the brittleness in parallel bedding direction is larger than that in vertical bedding direction; and the development of beddings may easily lead to complex fracture patterns, which affects the brittleness evaluation results. Table and Figures | Reference | Related Articles | Metrics

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Deformation and Favorable Area Evaluation of Shunbei No.4 Strike-Slip Fault Zone in Tarim Basin LI Haiying, HAN Jun, CHEN Ping, LI Yuan, BU Xuqiang Xinjiang Petroleum Geology    2023, 44 (2): 127-135.   DOI: 10.7657/XJPG20230201 Abstract （339）   HTML （39）    PDF（pc） （7486KB）（235）       Knowledge map    Save The Shunbei No. 4 strike-slip fault zone which is located in the Shuntuoguole low uplift of the Tarim basin and extends northward to the Shaya uplift is characterized by deep burial，horizontal segmentation，vertical stratification，multi-stage activities，and complex structure. Through the interpretation of high-quality 3D seismic data from the Shunbei No. 4 strike-slip fault zone，the stratification，segmentation，staging，activity and favorable area evaluation of the fault zone were carried out. The results show that the Shunbei No. 4 strike-slip fault zone has a 4-layer structure in the Paleozoic，roughly bounded by the top of the Middle Ordovician，above which echelon faults are found and below which high-steep strike-slip faults are developed. The strike-slip fault zone is visibly segmented into the northern segment，the middle segment，and the southern segment according to the strike，showing an overall characteristic of compressed in south and extended in north. In the Paleozoic，the strike-slip fault zone successively experienced four periods of activity，namely，EpisodeⅠof the middle Caledonian，Episode Ⅲ of the middle Caledonian，late Caledonian，and Hercynian. By combining the main controlling factors (e.g. source-reservoir connectivity，reservoir size，and late adjustment) for hydrocarbon enrichment and accumulation in the Shunbei area，the favorable areas in the Shunbei No. 4 strike-slip fault zone were evaluated. Multiple favorable areas have been identified and then verified by actual drilling. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 66-71.   DOI: 10.7657/XJPG20220110 Abstract （357）   HTML （5）    PDF（pc） （624KB）（234）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Characteristics and Sand Body Architecture of Shallow Delta Front in Ordos Basin: A Case Study of Chang 9 Member in Shiwanghe Section in Yichuan REN Yilin, ZHAO Junfeng, CHEN Jiayu, GUAN Xin, SONG Jinggan Xinjiang Petroleum Geology    2022, 43 (3): 310-319.   DOI: 10.7657/XJPG20220307 Abstract （359）   HTML （8）    PDF（pc） （5476KB）（234）       Knowledge map    Save As an important reservoir for storing oil and gas,the sand bodies in delta front are found with enormous petroleum exploration potential. However,there are few studies on architecture of sand bodies in shallow delta front through field outcrops. Guided by sedimentology and reservoir architecture theories,the outcrop observation and sampling was combined with the results of laboratory experiments and statistical analysis to clarify the sedimentary characteristics and sand body architecture of Chang 9 member in the Shiwanghe section in Yichuan,Ordos basin. The results show that during the deposition,the Chang 9 member in Shiwanghe section lied in a warm and humid environment,especially an oxidation to weak-reduction transitional freshwater environment that was not obviously stratified,and shallow delta front subfacies was mainly developed,including microfacies such as underwater distributary channel,estuary bar,sheet sand and interdistributary bay. The single sand bodies of shallow delta front in Chang 9 member in the study area can be divided into two vertical stacking styles such as non-connected and connected,and two lateral contact styles such as butted and cut-stacked. The accommodation growth rate and sediment supply rate jointly controlled by terrain slope and lake level rise/fall are important factors affecting the spatial development style of the composite sand bodies. The gentle slope allows the channels to incise weakly and present the characteristics of plane intersection. The rise of lake level and the decrease of source supply increase the ratio of accommodation growth rate to sediment supply rate,which may lead to the weakening of sand body connectivity. The architecture models of sand bodies like river-river cut stacking and river-bar cut stacking are favorable for hydrocarbon accumulation. Table and Figures | Reference | Related Articles | Metrics

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Development of Low-Permeability Heavy Oil Reservoirs by CO2 + Surfactant Combination Huff and Puff : A Case Study of Upper Wuerhe Formation Reservoir in Southern Block 5, Karamay Oilfield HUANG Weiqiang Xinjiang Petroleum Geology    2022, 43 (2): 183-187.   DOI: 10.7657/XJPG20220208 Abstract （351）   HTML （13）    PDF（pc） （553KB）（229）       Knowledge map    Save The reservoir in the upper Wuerhe formation, southern Block 5, Karamay oilfield, is a heavy oil reservoir with low porosity and low permeability, indicating poor reservoir physical properties. When it was developed by water injection, the production decreased rapidly, and the formation energy kept low; as a result, all production wells were shut in or suspended. In recent years, some wells have been refractured to resume production and good effects have been gained in the initial stage, but the production declines rapidly. In order to solve the problems of low production and low efficiency of production wells, the CO2 + surfactant combination huff and puff technology was developed and tested for production enhancement. On the basis of experiment on stimulation mechanism, through multi-component reservoir numerical simulation, the method and parameters for injecting CO2 + surfactant were optimized. The relationship between the changes of the production increment and the parameters such as injection volume, injection rate, soaking period and production intensity in different cycles of huff and puff were established, and the optimal parameters for injecting CO2 + surfactant were determined for huff and puff. Field application reveals a natural flow of a sing well for 240 days and an incremental oil production of 630 t. It is concluded that the CO2 + surfactant combination huff and puff technology can effectively supplement formation energy and improve fluid mobility, which can be used as a reference for the development of similar reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Characteristics and Connectivity of Fault-Controlled Fractured-Vuggy Reservoirs: A Case Study of Unit T in Tuofutai Area, Tahe Oilfield LI Jun, TANG Bochao, HAN Dong, LU Haitao, GENG Chunying, HUANG Mina Xinjiang Petroleum Geology    2022, 43 (5): 572-579.   DOI: 10.7657/XJPG20220509 Abstract （286）   HTML （9）    PDF（pc） （3554KB）（227）       Knowledge map    Save Fault-controlled fractured-vuggy reservoirs are extremely heterogeneous and exhibit the diversity and complexity in inter-well connectivity. Clarifying the influence of faults and karsts on reservoirs is conducive to reservoir connectivity analysis and injection-production strategy adjustment. Taking Unit T in the Tuofutai area of Tahe oilfield as an example, the development characteristics of reservoirs were systematically analyzed based on the results of seismic interpretation and the analysis of overlying water system and production performance responses. It was clarified that the reservoir development is mainly controlled by faults and surface water systems. The difference in karstification intensity leads to different characteristics of the reservoirs, which makes development wells show different production behaviors and inter-well connectivities. Based on the analysis of dynamic and static data, an inter-well connectivity model suitable for fault-controlled fractured-vuggy reservoirs was established, which can provide a basis for the adjustment of subsequent treatments. Table and Figures | Reference | Related Articles | Metrics

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Reservoir Comparison and Exploration Enlightenment of Baikouquan Formation in Northern and Western Slopes of Mahu Sag CHEN Cheng, PENG Mengyun, ZHAO Ting, WANG Jingang Xinjiang Petroleum Geology    2022, 43 (1): 18-25.   DOI: 10.7657/XJPG20220103 Abstract （388）   HTML （16）    PDF（pc） （3650KB）（226）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Geological Age and Petrogenesis of Volcanic Rocks in Southern Chepaizi Oilfield WANG Tao, XU Qian, LI Yongjun, KONG Yumei, ZHENG Menglin, GUO Wenjian Xinjiang Petroleum Geology    2022, 43 (2): 160-168.   DOI: 10.7657/XJPG20220205 Abstract （332）   HTML （14）    PDF（pc） （1226KB）（222）       Knowledge map    Save The Carboniferous in southern Chepaizi oilfield is mainly composed of amygdaloidal basalt, basaltic andesitic agglomerate, andesitic breccia tuff and a small amount of basaltic andesitic breccia tuff. In order to determine the geological age of these rocks, isotopic and biofossil analyses were carried out, and then the analytical results were compared with the Carboniferous rocks in the outcrop area in the basin margin. It is found that there are abundant sporopollen fossils in the bottom of the Carboniferous sandstone in Well C47, and the zircon U-Pb age of the rhyolitic breccia-bearing vitric tuff from Well C68 is 314.6±2.1 Ma, suggesting that both the geological age and isotopic age of the volcanic rock are Late Carboniferous, which are comparable to the Hala’alat formation in the piedmont at the northwestern margin of the Junggar basin. The volcanic rocks are generally calc-alkali-tholeiitic series and relatively rich in Al2O3, with a weak positive Eu anomaly. Moreover, the volcanic rocks are strongly short of high field-strength elements such as Nb, Ta, and Hf, and relatively rich in large ion lithophile elements such as Ba, Rb, and K. There exists an obvious Nb-Ta trough, and the magma source area may be the depleted mantle of spinel peridotite because of metasomatism, and formed in the subduction-related island arc tectonic environment. For the well blocks in southern Chepaizi oilfield, the Carboniferous in the northwest wall of the large fault can be compared with the Aladeyikesai formation, and the volcanic rock formation in the southeast wall can be correlated with the Hala’alat formation in the piedmont of the northwest margin. Table and Figures | Reference | Related Articles | Metrics

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Early Warning Model for Critical Sand Production in Horizontal Wells Based on Pressure Monitoring: A Case of H Gas Storage in Xinjiang WANG Quan, CHEN Chao, Hasyati SAYITI, ZHANG Yi, BAO Yingjun, WU Min Xinjiang Petroleum Geology    2022, 43 (2): 214-220.   DOI: 10.7657/XJPG20220213 Abstract （302）   HTML （5）    PDF（pc） （594KB）（222）       Knowledge map    Save For H gas storage in Xinjiang, the largest gas-reservoir-type sandstone underground gas storage in China, the adjustment plan adopts full arrangement with horizontal wells. The single well is characterized by intensive injection and production as well as large-displacement huff and puff. If the production pressure difference is too large, the rock skeleton may be damaged, and the sand carried out may erode the production string or even block the wellbore, causing production suspension of gas wells and affecting the overall peak-shaving capability of the gas storage. This paper discusses the early warning on critical sand production in horizontal wells based on pressure monitoring. Based on the material balance equation, state equation and flow equation applicable to the H gas storage, a dynamic production pressure difference monitoring model of horizontal wells was established. Meanwhile, the field test on critical sand production pressure difference of horizontal wells was carried out, and the criterion “C” formula model determining rock solidity was defined to predict the critical sand production pressure difference. Finally, an early warning model for critical sand production in horizontal wells based on pressure monitoring was established. The coincidence between the model-derived pressure and the measured pressure exceeds 93%. The model can realize the real-time monitoring of the dynamic production pressure difference in horizontal wells and also lay a foundation for the evaluation of maximum peak-shaving capacity and subsequent peak-shaving and production allocation of the gas storage. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 107-114.   DOI: 10.7657/XJPG20220116 Abstract （329）   HTML （6）    PDF（pc） （16052KB）（218）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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BP Neural Network-Based Models to Predict Clay Minerals LI Xinyu, OUYANG Chuanxiang, YANG Bowen, ZHAO Hongnan, NIE Bin Xinjiang Petroleum Geology    2021, 42 (5): 624-629.   DOI: 10.7657/XJPG20210517 Abstract （254）   HTML （12）    PDF（pc） （650KB）（216）       Knowledge map    Save Accurate prediction of clay minerals is the key to deep drilling operation and pay zone protection. In order to determine the distribution law of clay minerals in the Jurassic Ahe formation in the northern tectonic zone of the Kuqa depression, Tarim basin, a well logging model and a combined model based on BP neural network were constructed by using GR logging parameters, cation exchange capacity, hydrogen index and photoelectric absorption cross-section index. The average absolute errors of the two models are 5.34% and 2.38%, respectively. Applied to Well Yinan 5, the average absolute errors of the models are 4.64% and 3.45%, respectively, by considering X-ray diffraction data. The prediction result shows that the clay mineral contents from high to low are illite, chlorite, illite/smectite mixed layer and kaolinite in Well Yinan 5. Damages from velocity sensitivity and acid sensitivity should be prevented in reservoir development. Table and Figures | Reference | Related Articles | Metrics

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Pore Structure and Sensitivity of Shale Reservoir in Lu 1 Member of Jimsar Sag LI Jingjing, SUN Guoxiang, LIU Qi, LIU Miao Xinjiang Petroleum Geology    2021, 42 (5): 541-547.   DOI: 10.7657/XJPG20210504 Abstract （268）   HTML （7）    PDF（pc） （612KB）（215）       Knowledge map    Save In order to determine reservoir sensitivity of the shale in the first member of the Lucaogou formation (Lu 1 member for short) in Jimsar sag, we analyzed the pore structure and carried out physical simulation experiments on the reservoir sensitivity after understanding the reservoir mineral composition. The Lu 1 member reservoir belongs to terrigenous clastic deposits with complex mineral composition and rich clay minerals, most of which are swellable. The high content of brittle minerals and complex pore structures in the reservoir aggravated stress sensitive damage; the high content of swellable clay minerals increased water sensitive damage; the high contents of (iron) dolomite and clay minerals induced acid and alkali sensitive damage, but the high content of calcite slightly reduced acid sensitive damage. In conclusion, the Lu 1 member shale reservoir in the study area is moderately-strongly sensitive to stress and water, weakly-strongly sensitive to acid and weakly-approximately moderately sensitive to alkali. Reservoir sensitivity damages from acid, water and stress should be prevented in oilfield development. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 450-455.   DOI: 10.7657/XJPG20210408 Abstract （223）   HTML （5）    PDF（pc） （576KB）（214）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Formation Mechanism and Geological Significance of Carbonate Cements in Baikouquan Formation on Northern Slope of Mahu Sag LYU Huanze, ZOU Niuniu, CAI Ningning, HUANG Yongzhi, NING Shitan, ZHU Biao Xinjiang Petroleum Geology    2022, 43 (5): 554-562.   DOI: 10.7657/XJPG20220507 Abstract （265）   HTML （12）    PDF（pc） （2281KB）（213）       Knowledge map    Save In order to further investigate the diagenetic environment, formation mechanism of carbonate cements and its influences on the physical properties of the sandy conglomerate reservoirs in the Lower Triassic Baikouquan formation on the northern slope of the Mahu sag, Junggar basin, the types, forming periods, and genesis of the carbonate cements in the study area and their effects on the reservoirs were studied through combining core observation, rock thin section identification and measurement of carbon and oxygen isotopes in carbonate cements. The results show that there are three periods of carbonate cements in the Baikouquan formation on the northern slope of the Mahu sag, that is, from early to late, micritic calcite in Period Ⅰ, ferrocalcite in Period Ⅱ, and ankerite in Period Ⅲ. δ13CPDB ranges from -47.23‰ to 3.88‰, while δ18OPDB ranges from -23.64‰ to -17.98‰. The bigger range of δ13CPDB reveals the presence of various carbon sources and the complex interaction between water and rock. The paleosalinity and paleotemperature restored from the carbon and oxygen isotope calculations show that the carbonate cements were mainly formed in freshwater environments, and partly influenced by seawater. The Baikouquan formation in Well Ma-19 is a low-porosity and low-permeability reservoir as a whole. The physical properties of the Bai 2 member are slightly better than those of the Bai 3 member, presumably indicating the presence of secondary pores. Post-drilling analysis finds that oil layers are developed in both Bai 2 member and Bai 3 member, which is basically consistent with the conclusion obtained from carbon and oxygen isotope analysis. Table and Figures | Reference | Related Articles | Metrics

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Technologies and Application of Sidetracking Horizontal Well in Existing Wells in Sulige Gas Field WANG Liqiong, WANG Zhiheng, MA Yulong, ZENG Qingxiong, ZHENG Fan Xinjiang Petroleum Geology    2022, 43 (3): 368-377.   DOI: 10.7657/XJPG20220316 Abstract （273）   HTML （7）    PDF（pc） （1058KB）（209）       Knowledge map    Save In order to improve the effective reservoir encounter rate during sidetracking drilling in existing wells,with a block in central Sulige gas field as an example,and combined with the geological characteristics and development status of the gas field,the key geological technologies for sidetracking horizontal drilling in existing wells were summarized from the aspects of optimal deployment and geosteering. On this basis,the development effect of sidetracking horizontal wells was discussed in light of drilling effect,production index,benefit evaluation,etc.,and the influence of various factors on the development effect was comprehensively analyzed. The research results show that the remaining gas mainly enriches in the areas including the rim of mid-channel bar,braided channel,and middle or bottom of the mid-channel bar in the sand belt of main channel. Based on the economic evaluation,the selection criteria for sidetracking well locations were established,that is,the lower limit of the effective thickness of recoverable beds is 4 m vertically,and the lower limit of the abundance of the remaining reserves is 0.42×108 m3/km2 on the plane. Using 3D geological model,stratigraphic dip evaluation,pilot hole information and data acquired while drilling,the horizontal-well geosteering sidetracking technology was formed,and three horizontal-section geosteering modes were provided. For 23 sidetracking horizontal wells in the study area,the average effective reservoir encounter rate is 59.7%,the average initial gas production is 2.9×104 m3,and the cumulative incremental production is 3.13×108 m3. Table and Figures | Reference | Related Articles | Metrics

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Influences of Shale Rheology on Pore Structures of Qiongzhusi Formation in Chengkou Area, Northeastern Sichuan Basin YU Shuyan, WANG Yang, FENG Hongye, ZHU Hongjian Xinjiang Petroleum Geology    2022, 43 (5): 513-518.   DOI: 10.7657/XJPG20220502 Abstract （299）   HTML （10）    PDF（pc） （14955KB）（207）       Knowledge map    Save In order to determine the influence of natural rheology of shale on microscopic pore structure, taking the marine shale of the Lower Cambrian Qiongzhusi formation in the Chengkou area, northeastern Sichuan basin as an example, the types and characteristics of rheological structure and microscopic pore structure in the shale and their relationship were studied by using rock thin sections, focused ion beam scanning electron microscope and low temperature liquid nitrogen adsorption experiment. The microstructures of shale rheology mainly include porphyroclast system, cataclastic flow, pressolutional stylolites, microscopic fold, S-C fabric and crenulation cleavage, and the micro-nano structures include mylonite zone, micro-hybrid zone, and rotating porphyroclast. Rheological shale is dominated by nanoscale intergranular pores, and most of the primary pore structure is difficult to preserve under rheological action. Ductile rheology leads to a decrease in the number of pores, pore diameter, pore volume and pore specific surface area of shale, which reduces the storage performance of shale. Table and Figures | Reference | Related Articles | Metrics

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Influences of Cemented Natural Fractures on Propagation of Hydraulic Fractures CHENG Zhenghua, AI Chi, ZHANG Jun, YAN Maosen, TAO Feiyu, BAI Mingtao Xinjiang Petroleum Geology    2022, 43 (4): 433-439.   DOI: 10.7657/XJPG20220408 Abstract （248）   HTML （8）    PDF（pc） （2487KB）（204）       Knowledge map    Save In order to determine the role of natural fractures in the forming of hydraulic fracture network in tight sandstone reservoirs, a numerical model was established using the coupled hydraulic-mechanical-damage (HMD) model, and a fracture network model was generated in the numerical model by the Monte-Carlo method. With these models, the influences of natural fracture orientation, natural fracture strength, horizontal principal stress difference, fracturing fluid injection rate and fracturing fluid viscosity on the propagation of hydraulic fractures were analyzed. The results show that when the angle between the natural fracture and the maximum horizontal principal stress direction ranges from 30° to 60°, the induced hydraulic fractures are the most complex. The increase in natural fracture strength is not conducive to the generation of branch and steering fractures. Under the condition of low horizontal principal stress difference, the orientation of natural fractures dominates the extension of hydraulic fractures. Under the condition of high horizontal principal stress difference, stress dominates the extension of hydraulic fractures. When the horizontal principal stress difference falls between 3.0 and 4.5 MPa, the hydraulic fractures exhibit the highest complexity and the largest extension. Increasing the injection rate of fracturing fluid can promote the formation of complex hydraulic fracture network. Appropriately increasing the viscosity of fracturing fluid can promote fracture propagation, but too high viscosity can only lead to complex fractures in limited areas around the perforations. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 52-58.   DOI: 10.7657/XJPG20220108 Abstract （308）   HTML （8）    PDF（pc） （634KB）（204）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Core Experiment and Stimulation Mechanism of Unstable Waterflooding in Low Permeability Reservoirs ZHOU Jinchong, ZHANG Bin, LEI Zhengdong, SHAO Xiaoyan, GUAN Yun, CAO Renyi Xinjiang Petroleum Geology    2022, 43 (4): 491-495.   DOI: 10.7657/XJPG20220417 Abstract （288）   HTML （11）    PDF（pc） （1256KB）（201）       Knowledge map    Save According to the typical characteristics of low permeability reservoirs in Changqing oilfield, parallel core and double-layered core experiments were carried out to simulate the effect of unstable waterflooding in heterogeneous low permeability reservoirs. Due to the poor visibility of core experiments, numerical models for simulating interlayer and intralayer heterogeneous reservoirs were established, which may reveal the stimulation mechanism of unstable waterflooding according to the change of flow field. The results show that for interlayer heterogeneous reservoirs, compared with continuous waterflooding, unstable waterflooding can promote the advancement of the flooding front in the layers with lower permeability, and give full play to capillary force in oil displacement, so unstable waterflooding can significantly improve the oil recovery of the layers with lower permeability, and the pattern of short-term injection combined with long-term quit can enhance the recovery rate the most. For intralayer heterogeneous reservoirs, unstable waterflooding can generate pressure oscillations in the layers to enable the fluid percolation between the higher permeability layers and the lower permeability layers, so that the sweep efficiency of injected water in the lower permeability layers is increased and the recovery rate of the lower permeability layers is enhanced, thereby increasing the total oil recovery rate of the reservoir. Table and Figures | Reference | Related Articles | Metrics

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Fractal Characteristics of Shale Pores From Taiyuan Formation to Shanxi Formation in Qinshui Basin YAN Gaoyuan, ZHANG Junjian, LU Guanwen, QUAN Fangkai Xinjiang Petroleum Geology    2021, 42 (5): 548-553.   DOI: 10.7657/XJPG20210505 Abstract （295）   HTML （8）    PDF（pc） （588KB）（200）       Knowledge map    Save Based on the data of shale samples, including TOC, vitrinite reflectance and mineral composition, and through high-pressure mercury intrusion experiment, the pore structure parameters such as pore diameter, pore volume, specific surface area and porosity were obtained from the Taiyuan formation to the Shanxi formation in the Qinshui basin, and then fractal analysis was performed on the shale pore structure with a Sierpinski carpet model. The results show that the fractal mercury intrusion curve of the shale samples from the Taiyuan formation to the Shanxi formation can be divided into 3 sections such as AB, BC and CD. The pore diameter corresponding to the BC section is 21 to 6,035 nm. When performing fractal processing on a Sierpinski model, the pore structure of the BC section has the best characterization. In the range from 21 to 6,035 nm, the higher the clay mineral content, the stronger the heterogeneity and the more complicated of the pore structure. Pore volume, specific surface area and porosity are all negatively correlated with fractal dimension. Among them, pore volume and porosity have a good correlation with fractal dimension, and can be used as an indirect criterion for judging the complexity of pore structure. Table and Figures | Reference | Related Articles | Metrics

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Enhancing Oil Recovery of Tight Conglomerate Reservoirs by Asynchronous CO2 Huff and Puff in Mahu Sag DENG Zhenlong, WANG Xin, TAN Long, ZHANG Jigang, CHEN Chao, SONG Ping Xinjiang Petroleum Geology    2022, 43 (2): 200-205.   DOI: 10.7657/XJPG20220211 Abstract （369）   HTML （11）    PDF（pc） （2510KB）（197）       Knowledge map    Save CO2 can increase formation energy and reduce oil viscosity. Asynchronous CO2 huff and puff is becoming one of the effective methods for improving the recovery of tight oil reservoirs. The interaction among injection, production and soaking processes can significantly increase inter-well reserves producing degree, and this technology is expected to become an option for enhancing the oil recovery of the Mahu tight conglomerate reservoirs in the Junggar basin. According to the formation pressure, saturation pressure and minimum miscible pressure, an asynchronous CO2 huff and puff experiment with two cores in parallel was designed for clarifying the influence of reservoir physical properties, injection-production pressure difference and huff-puff timing on development effect. The results show that the crude oil recovery after asynchronous CO2 huff and puff is about 3-5 times higher than that of the depletion development; the better the physical properties of the reservoir, the smaller the flow resistance, and the more favorable for asynchronous CO2 huff and puff to improve oil recovery; the greater the injection-production pressure difference, the more significant the inter-well pressure change, and the more crude oil is produced; when the gas injection pressure is greater than the miscible pressure, it is beneficial for supercritical CO2 to play the role and to improve the recovery; when the formation pressure is higher than the miscible pressure, it is necessary to increase the pressure of the gas injection well and reduce the pressure of the adjacent production well through asynchronous CO2 huff and puff to increase the pressure difference of the injection-production system, expand the swept volume, and improve the inter-well reserves producing degree. Table and Figures | Reference | Related Articles | Metrics

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Distribution of Natural Fractures and Mechanical Characteristics of Orogenic Movement in Carbonate Formations in Shunbei Oilfield CHEN Xiuping, SHEN Xinpu, LIU Jingtao, SHEN Guoxiao Xinjiang Petroleum Geology    2021, 42 (5): 515-520.   DOI: 10.7657/XJPG20210501 Abstract （329）   HTML （18）    PDF（pc） （8992KB）（196）       Knowledge map    Save Natural fractures in the Ordovician carbonate formations in the Shun 8B block in Shunbei oilfield were investigated, and the classification and distribution laws of the natural fractures were summarized. Then through damage and finite element numerical simulation, a theoretical tool for simulating the damage to the carbonate formations was developed, and the displacement direction and strain of orogenic movement corresponding to the development of natural fractures were determined. The results are as follows: ① Based on the stratigraphic structure from seismic waves and the histories of sedimentation and orogenic movement in the study area, the natural fractures/faults in 7 sections in the Carboniferous Kalashayi formation to the Middle Ordovician Yijianfang formation are divided into 5 natural fracture systems; ② The natural fractures in the Upper Ordovician Qarbag formation to the Middle Ordovician Yijianfang formation correspond to the orogenic movement of the middle Caledonian PhaseⅠand the middle Caledonian PhaseⅡ, and they are mainly open fractures and strike-slip fractures/faults penetrating the formations; ③ Based on seismic horizons, a 3D finite element model was established and 3D damage finite element numerical analysis was carried out. Forward numerical calculation provided the 3D distribution of the natural fractures/faults represented by localized damage zones under the action of the middle Caledonian orogenic movement in the study area. Numerical calculation verified that the mechanics of the middle Caledonian orogenic movement extruded the Ordovician carbonate formation at the azimuth of 15°, and the extrusion degree of the formation is equivalent to 2.4% of the strain. Table and Figures | Reference | Related Articles | Metrics

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Shale Oil Enrichment Mechanism and Sweet Spot Selection of Fengcheng Formation in Mahu Sag，Junggar Basin JIN Zhijun, LIANG Xinping, WANG Xiaojun, ZHU Rukai, ZHANG Yuanyuan, LIU Guoping, GAO Jiahong Xinjiang Petroleum Geology    2022, 43 (6): 631-639.   DOI: 10.7657/XJPG20220601 Abstract （353）   HTML （27）    PDF（pc） （5508KB）（195）       Knowledge map    Save The Fengcheng formation in the Mahu sag is an alkaline lake sediment，and is divided into Feng 1 member，Feng 2 member and Feng 3 member from bottom to top. In the Fengcheng formation，the lithology vertically changes rapidly，the mineral composition is complex，and the organic-rich shale source is integrated with the shale reservoir. The formation bears oil universally，but the sweet spots are scattered. The results of formation testing for single layers are not satisfied，showing an unclear production potential. According to core slices and geochemical analyses，the Fengcheng formation in the Mahu sag is dominated by lamellar silty shale intercalated with dolomite，which are mainly composed of terrigenous clastic minerals and carbonate minerals. With the variation of burial depth，the pore volume changes consistently with the variation of surface area of pores，and the pore volume is mainly contributed by macropores (pore diameter > 50 nm). The source rock is dominated by Type Ⅱ organic matter，and the vitrinite reflectance ranges from 0.85% to 1.40%，indicating a peak oil generation period. There are many shear fractures with middle to high angles in the Feng 2 member，and shear fractures with middle to high angles and structural fractures with low angles in the Feng 3 member，whose formation and development degree are controlled by lithology，mineral composition，rock mechanical properties，etc. Based on the characteristics of lithologic assemblage，reservoir property and oil-bearing property，four relatively concentrated sweet spots have been identified. When performing multi-interval formation testing and production testing in vertical wells，it is necessary to select sweet spots with good oil content and more fractures to conduct geological research and geology-engineering integration technology research，and to perform production improvement tests in horizontal wells，so as to realize comprehensive breakthrough for shale oil exploration and development in the Fengcheng formation in the study area Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 85-91.   DOI: 10.7657/XJPG20220113 Abstract （279）   HTML （4）    PDF（pc） （1651KB）（193）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Accumulation Conditions and Exploration Direction of Lower Jurassic Tight Sandstone Gas Reservoirs in Taibei Sag CHEN Xuan, WANG Jufeng, XIAO Dongsheng, LIU Juntian, GOU Hongguang, ZHANG Hua, LIN Lin, LI Hongwei Xinjiang Petroleum Geology    2022, 43 (5): 505-512.   DOI: 10.7657/XJPG20220501 Abstract （335）   HTML （29）    PDF（pc） （3198KB）（193）       Knowledge map    Save The Turpan-Hami basin has great potential of oil and gas resources in the Lower Jurassic strata, with a large quantity of remaining resources. The discovered oil and gas reservoirs are mainly distributed in the positive structural belts around the Shengbei and Qiudong subsags in the Taibei sag, and they are primarily structural reservoirs. Less researches on the oil and gas resources in the hinterland of the subsags have been performed. Based on the dissection of known reservoirs, a systematic study was carried out on the depositional system, source rock, reservoir rock and accumulation conditions of three major hydrocarbon-rich subsags in the Taibei sag. The results show that the coal-measure source rocks are widely developed in the Shuixigou group in the Taibei sag and are in broad contact with the braided river delta sandstones, which is conducive to the formation of near-source tight sandstone gas reservoirs. There are two types of tight sandstone gas reservoirs in the Lower Jurassic, namely, trap-type and continuous-type. The hinterlands of the subsags are favorable areas for the formation of continuous-type tight sandstone gas reservoirs. Therefore, the exploration should be switched from the source-edge positive structure to the hydrocarbon-rich subsag, and from the above-source conventional oil reservoirs to the in/near-source tight sandstone gas reservoirs. The hinterlands of the Shengbei and Qiudong subsags have the conditions to form large gas reservoirs, so they are favorable areas for exploring near-source tight sandstone gas reservoirs in the lower Jurassic. Table and Figures | Reference | Related Articles | Metrics

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Sand Body Architecture of Chang 9 Member in Jiyuan Area,Ordos Basin WU Zemin, KE Xianqi, ZHANG Pan, WEN Fengqin, TONG Qiang, LIU Linyu Xinjiang Petroleum Geology    2022, 43 (3): 294-309.   DOI: 10.7657/XJPG20220306 Abstract （262）   HTML （3）    PDF（pc） （6534KB）（192）       Knowledge map    Save In order to clarify the spatial configuration of sand bodies under the dual-provenance background in Chang 9 member in Jiyuan area,Ordos basin,the sedimentary characteristics of Chang 9 member were determined by using the core,logging,test and production data. On this basis,the sand body architecture of Chang 9 member was dissected level by level to understand the development of sand bodies under the dual-provenance background and to characterize the architectural elements and their assemblage and distribution. The results reveal that there are 8 types of skeleton architectural elements in Chang 9 member,which are different from region to region: braided channel,abandoned channel and cross-bank deposits dominated by underwater distributary channel and interdistributary bay in the west; and estuary sand bar,front sheet sand and underwater natural levee in the east. On the plane,the architectural element of braided channel extends farther with continuous distribution,the architectural element of abandoned channel extends shortly with intermittent distribution,the architectural element of underwater distributary channel extends farther with discontinuous distribution,and the architectural element of estuary sand bar is usually in the side rear of the underwater distributary channel with poor continuity. Vertically,the superimposition and assemblage of the architectural elements of skeleton sand bodies become worse from bottom to top,and the architectural elements of braided river delta system in the west display better development scale and degree than those of meandering river delta system in the east. Table and Figures | Reference | Related Articles | Metrics

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Production System of Horizontal Well in Shale Oil Reservoirs of Chang 7 Member, Ordos Basin WAN Xiaolong, ZHANG Yuanli, FAN Jianming, LI Zhen, ZHANG Chao Xinjiang Petroleum Geology    2022, 43 (3): 329-334.   DOI: 10.7657/XJPG20220310 Abstract （212）   HTML （6）    PDF（pc） （3813KB）（191）       Knowledge map    Save To ensure the production of shale oil in Chang 7 member, Ordos basin, this paper discussed the production system of the horizontal well in Chang 7 member based on the theoretical research and production data. By establishing the relationship between the distance of the pressure propagation boundary from fractures induced by volume fracturing in horizontal well and the time, and assuming that the pressure propagated to the boundary does not change with time, the reasonable well soaking period is determined to be 40 d. It is considered that the high-watercut drainage stage ends when the analyzed salinity of the produced water is similar to the salinity of initial formation water, or the replacement rate of fracturing fluid in horizontal wells is greater than 60%. By quantitatively analyzing the production profile of a single section and a 100-m horizontal section in the horizontal well, the dynamic relationship was established for determining a reasonable fluid production for each stage. Table and Figures | Reference | Related Articles | Metrics

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Occurrence Characteristics of Movable Fluids in Unconsolidated Sandstone Reservoir of Toutunhe Formation in Santai Oilfield ZHANG Tong Xinjiang Petroleum Geology    2021, 42 (4): 469-474.   DOI: 10.7657/XJPG20210411 Abstract （387）   HTML （4）    PDF（pc） （3041KB）（191）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Methods for Separate-Layer Fracturing Optimization of Thin Interbeds in Fengcheng Formation, Mahu Sag PAN Liyan, RUAN Dong, HUI Feng, LIU Kaixin, ZHANG Min, PENG Yan Xinjiang Petroleum Geology    2022, 43 (2): 221-226.   DOI: 10.7657/XJPG20220214 Abstract （297）   HTML （11）    PDF（pc） （609KB）（190）       Knowledge map    Save In Mahu sag, where there is abundant oil in place, the reservoirs in Permian Fengcheng formation are thick and have revealed good oil/gas show. However, the thin interbeds are complex in lithological assemblages and greatly variable in in-situ stress, so fine separate-layer fracturing must be done to recover the reserves. Based on the numerical simulation method, the factors influencing fracture propagation during multi-layer fracturing were analyzed, providing a basis for rational selection of layers for multi-layer or separate-layer fracturing. The results show that the reservoir stress difference influences fracture propagation the most, followed by fracturing fluid displacement and viscosity, and the reservoir thickness ratio influences the least. Based on the BP neural network algorithm, machine learning was carried out on the numerical simulation results, and a multi-factor fine separate-layer fracturing decision-making model that considers both geological and engineering factors was established. Using this decision-making model, multi-layer or separate-layer fracturing prediction and fracturing parameter optimization were made for 6 wells in the Fengcheng formation on the Manan slope. Post-frac flowing production tests demonstrated that the daily oil production of some wells reached 10.34-32.37 t, and the average single-well production was increased by nearly 50% compared with the traditional fracturing process. The study results can provide effective guidance for the optimization of the fracturing process of thin interbeds in the Mahu sag. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2022, 43 (1): 122-126.   DOI: 10.7657/XJPG20220118 Abstract （298）   HTML （9）    PDF（pc） （529KB）（189）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Comparison of Chromatographic Fingerprint Characteristics of Heavy Oil Based on Fire Flooding Experiments YAN Hongxing Xinjiang Petroleum Geology    2021, 42 (5): 592-597.   DOI: 10.7657/XJPG20210512 Abstract （230）   HTML （3）    PDF（pc） （933KB）（186）       Knowledge map    Save In fire flooding development of heavy oil, oxidation at high temperature directly affects the evaluation on the development efficiency, and how to identify the combustion state is a technical difficulty. Physical simulation experiments on fire flooding were performed on natural cores, and fingerprint characteristics of saturated hydrocarbon, olefin and aromatic hydrocarbon in heavy oil were analyzed through gas chromatography. The results show that after fire flooding, influenced by oxidation at high temperature, (1) the content of saturated hydrocarbon in the heavy oil increases significantly, the chromatographic fingerprint is a pre-peak unimodal type, both the content of N-alkane and light-heavy ratio (∑nC21-/∑nC22+) increase, and no odd-even predominance appears; (2) on the chromatographic fingerprint, the olefins generated from cracking shows that the ratio of olefins to N-alkanes with the same carbon numbers is always less than 1, and the ratio decreases with the increase of the carbon number; (3) the chromatographic fingerprint of aromatic hydrocarbon is a pre-peak type, the content of methylnaphthalene is significantly lower than that of naphthalene in the naphthalenes, so it is easier to have methylation at the α place of the cracked naphthalenes, and the characteristics of the phenanthrenes are similar to those of the naphthalenes. Chromatographic fingerprint can effectively indicate microscopic changes of the heavy oil before and after fire flooding, which lays a foundation for identifying the combustion state of fire flooding. Table and Figures | Reference | Related Articles | Metrics

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Reservoir Benefit Classification and Development Countermeasures for Changqing Oilfield ZHOU Xiaoying, WEI Mingxia, ZHANG Yirong, LI Ting, XU Sen Xinjiang Petroleum Geology    2022, 43 (3): 320-323.   DOI: 10.7657/XJPG20220308 Abstract （276）   HTML （7）    PDF（pc） （464KB）（186）       Knowledge map    Save Influenced by the increasing reservoir types in Changqing oilfield and the low international crude oil price, clarifying the benefit categories of reservoirs and identifying the oil production limits of different types of reservoirs under different oil prices are urgent for Changqing Oilfield Company to make production and operation decisions. By combining the benefit evaluation with reservoir research, dynamic development, well production failure and comprehensive treatment, the relationship between cost or development index and benefits for different types of reservoirs was established, and the influencing factors of low-benefit wells were analyzed, providing a reference for cost-effective development of reservoirs. Table and Figures | Reference | Related Articles | Metrics

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Inversion of Fracture Parameters and Formation Pressure for Fractured Horizontal Wells in Shale Oil Reservoir Based on Soaking Pressure WANG Fei, WU Baocheng, LIAO Kai, SHI Shanzhi, ZHANG Shicheng, LI Jianmin, SUO Jielin Xinjiang Petroleum Geology    2022, 43 (5): 624-629.   DOI: 10.7657/XJPG20220517 Abstract （335）   HTML （7）    PDF（pc） （884KB）（185）       Knowledge map    Save A fractured horizontal well in shale oil reservoir should be soaked before it is put into production. In order to quickly evaluate the effect of volume fracturing, a post-frac evaluation method based on the data of soaking pressure of shale oil reservoirs was proposed. Through numerical simulation of well soaking, the pressure diffusion and fluid migration in the stimulation area controlled by the fractured horizontal well were characterized, and a post-closure linear flow calculation model and a fracture storage control calculation model were established. Then a calculation method for inverting fracture parameters and formation pressure was formed. The results show that after pump is stopped, the stimulation area goes through 9 flow stages such as flows controlled by fractures in end section of wellbore, by fractures in the whole wellbore and by reservoir matrix, and the pressure drop derivatives appear as multiple straight-line segments with different slopes in log-log coordinates. This method has been applied to four typical shale oil horizontal wells in Jimsar sag, which proves that the data of soaking pressure can be used for the inversion of fracture parameters and formation pressure, and also verifies the applicability of the proposed method. The study results provide a reference for evaluating fracturing effect and optimizing well spacing. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 480-486.   DOI: 10.7657/XJPG20210413 Abstract （229）   HTML （5）    PDF（pc） （554KB）（185）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Grading Evaluation of Mudstone Caprocks Based on Logging-Seismic Combination: A Case Study on D Basin in Chad FENG Guoliang, SUN Wangao, WANG Yifan, BAI Jianfeng, SHI Yanli, YANG Wenhui Xinjiang Petroleum Geology    2021, 42 (6): 756-762.   DOI: 10.7657/XJPG20210616 Abstract （243）   HTML （6）    PDF（pc） （773KB）（185）       Knowledge map    Save In order to evaluate the sealing ability of the Lower Cretaceous mudstone caprock in the D basin in Chad, the thickness, porosity, and break-out pressure of the mudstone caprock are obtained by using well logging data; the relationship between break-out pressure and interval velocity, and the relationship between mud-to-formation ratio and seismic attributes are analyzed; the plane distribution of break-out pressure and mudstone thickness are described; and the evaluation standard for the grading of the mudstone caprock is established by taking break-out pressure and mud-to-formation ratio as primary evaluation parameters. The results show that the mudstone in the Kedeni formation in the D Basin is classified into Type Ⅰ and Ⅱcaprocks, and the mudstone in the Doba formation is Type Ⅱ and Ⅲcaprocks. The sealing ability of the mudstone caprock in the Kedeni formation is stronger than that in the Doba formation. On plane, the mudstone caprocks in the northern steep slope zone and sags have the best sealing abilities, and are ranked as Type Ⅰ and Ⅱ, followed by the mudstone caprocks in the central low-amplitude uplift zone and the southern gentle slope zone, which is dominated by Type Ⅱ and Ⅲ, and the worst mudstone caprock is in the northeastern transition zone, which is Type IV. The evaluation results are in good agreement with the actual drilling results, indicating that the evaluation method is effective and provides a good reference for mudstone caprock evaluation in similar basins with relatively low exploration degrees. Table and Figures | Reference | Related Articles | Metrics

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Simulation on Fracture Propagation During Hydraulic Fracturing in Horizontal Wells in Shale Reservoirs of Fengcheng Formation，Mahu Sag YU Peirong, ZHENG Guoqing, SUN Futai, WANG Zhenlin Xinjiang Petroleum Geology    2022, 43 (6): 750-756.   DOI: 10.7657/XJPG20220613 Abstract （251）   HTML （5）    PDF（pc） （6827KB）（185）       Knowledge map    Save Hydraulic fracturing is an effective method for developing the shale reservoirs in the Permian Fengcheng formation in the Mahu sag，but the propagation characteristics of hydraulic fractures are unclear. Maye-1H，a typical horizontal well in this area，suffered from difficulties in fracturing initiation and sand addition. Thus，it is urgent to carry out hydraulic fracturing simulation to clarify the impacts of natural fractures，rock mechanical properties，and operation parameters on fracturing effect. According to the actual operation parameters such as pump pressure，fracturing fluid displacement and added sand volume in Well Maye-1H，a 2D hydraulic fracture propagation model and a 3D hydraulic fracturing model were established by using Abaqus software and Petrel software，and then numerical simulation on hydraulic fracture propagation was performed. The results show that the fracturing effect is closely related to natural fractures. The lower the tensile strength of the rock where natural fractures are developed，the easier the hydraulic fractures tend to be captured by the natural fractures. When the Young’s modulus in the fractured interval is relatively large，the hydraulic fractures formed are small in width，and most of them propagate and slip along the natural fracture trend，making it difficult to add sand. When the Young’s modulus in the fractured interval is relatively small，the hydraulic fractures formed are large in width，and they can directly pass through the natural fractures，making sand adding relatively easy. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 475-479.   DOI: 10.7657/XJPG20210412 Abstract （232）   HTML （1）    PDF（pc） （1371KB）（182）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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VSP Reverse Time Migration Technology and Its Imaging Effect CHEN Keyang, YANG Wei, ZHAO Haibo, WANG Cheng, ZHU Lixu, LIU Jianying, LI Xingyuan Xinjiang Petroleum Geology    2022, 43 (5): 617-623.   DOI: 10.7657/XJPG20220516 Abstract （283）   HTML （9）    PDF（pc） （3976KB）（182）       Knowledge map    Save In order to improve the precision of VSP seismic imaging, a VSP reverse time migration (RTM) operator with 16-order finite difference accuracy was constructed, and then the algorithm accuracy of VSP key links and the interchangeability of shot and receiver points were analyzed by using impulse responses to verify the accuracy of the 3D VSP RTM operator. Based on the standard theoretical model of lava dome, the imaging effects of normalized VSP RTM and conventional cross-correlation RTM were compared. It is found that VSP RTM can describe the geological body boundary and formation interface more clearly and more accurately, and can eliminate the uneven influence of folds to make energy distribution more uniform, with no well trace. The high-precision 3D VSP RTM technology was applied to the walkaway VSP data of Well L in the Songliao basin, and accurate and fine imaging of near-wellbore formations and small faults was achieved, which further verified the accuracy of the technology. The proposed VSP RTM technology can help improve the imaging accuracy of complex reservoirs around the wellbore. Table and Figures | Reference | Related Articles | Metrics

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Mid-Late Development of Reservoirs With Narrow Oil Ring, Gas Cap and Edge Water YUE Baolin, ZHU Xiaolin, LIU Bin, CHEN Cunliang, WANG Shuanglong Xinjiang Petroleum Geology    2022, 43 (1): 102-106.   DOI: 10.7657/XJPG20220115 Abstract （248）   HTML （4）    PDF（pc） （656KB）（180）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Dominant Water Flow Channels in Block VI of North Buzachi Oilfield CHI Yungang, TANG Zhixia, WEI Jing, ZHOU Huize, ZHANG Wenhui Xinjiang Petroleum Geology    2022, 43 (4): 496-504.   DOI: 10.7657/XJPG20220418 Abstract （262）   HTML （7）    PDF（pc） （968KB）（179）       Knowledge map    Save In order to understand the development characteristics of the dominant water flow channels in the North Buzachi oilfield, the dominant water flow channels in the target layers in Block VI of the oilfield were identified by using streamlined numerical simulation technology, and the development degree and formation pattern of the dominant water flow channels were quantitatively characterized. The results show that Class Ⅰand Ⅱ channels in the study area are the water flow channels with ineffective circulation, with water flooding sweep coefficient of only 0.120-0.175. For Class I channels, the water cut at the producer is greater than 97%, and the average sweep coefficient is 0.120, with extremely serious channeling. For Class II channels, the water cut at the producer ranges from 93% to 97%, and the average sweep coefficient is 0.175, with serious channeling. The dominant water flow channels are small in number and limited in volume, but they occupy most of the water volume, which results in inefficient water injection. The number of dominant channels is inversely proportional to the distance between injector and producer. The location of the main river channel is the main area where the dominant water flow channels are formed, especially in the direction that the connection line between the injector and the producer is parallel to the sedimentary direction of the main river channel. The longer the producing time of the producer and injector, and the higher the ratio of cumulative liquid production to water injection, the higher the probability of dominant channel occurs near the wells with high daily liquid production. Furthermore, the dominant water flow channels change with the initial production time of the producer and the adjustment of injector-producer relationship. Table and Figures | Reference | Related Articles | Metrics

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Comprehensive Evaluation on Steam Chamber Location and Production Prediction of SAGD in Heavy Oil Reservoirs GUO Yunfei, LIU Huiqing, LIU Renjie, ZHENG Wei, DONG Xiaohu, WANG Wuchao Xinjiang Petroleum Geology    2022, 43 (4): 484-490.   DOI: 10.7657/XJPG20220416 Abstract （261）   HTML （5）    PDF（pc） （673KB）（178）       Knowledge map    Save Production and steam chamber location are critical for steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The existing prediction model only considers the lateral expansion of steam chamber and cannot predict the production of adjacent wells after steam chamber contact. According to the different characteristics of the steam chamber in the lateral expansion stage and the downward expansion stage, a parameter of thermal penetration depth was introduced, the flow potential function was modified, and a parabolic production prediction model was established. The results show that the production increases gradually in the initial lateral expansion stage of steam chamber, and then decreases due to the reduction of the inclination of the steam chamber interface; in the downward expansion stage of steam chamber, the production further decreases. The model analysis reveals that SAGD is more suitable for thick reservoir development, and the optimal well spacing needs to be determined depending on the oilfield conditions. The parabolic production prediction model takes the characteristics of the steam chamber into account in the downward expansion stage, and the accuracy of the model is verified by comparing with the previous experimental data. Table and Figures | Reference | Related Articles | Metrics

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Genesis and Fluid Identification Method of Cretaceous Low-Resistivity Oil Layers in WTK Oilfield LI Fengling, XU Shipeng, LIU Tao, LU Zhiming, LI Xiang, Aini MAMAT Xinjiang Petroleum Geology    2022, 43 (2): 241-251.   DOI: 10.7657/XJPG20220217 Abstract （342）   HTML （6）    PDF（pc） （1518KB）（178）       Knowledge map    Save The Cretaceous low-resistivity oil layers in WTK oilfield, South Turgay basin are widely developed and difficult to identify. In this paper, the genetic mechanism of these low-resistivity oil layers was analyzed using core analysis and logging data, and the method for identifying oil/water layers was stuided by combining formation testing data. According to the geological features of the study area, comprehensive research was carried out on internal factors and external factors. The internal factors include the reservoir lithology and clay mineral content during the deposition process, the pore structure characteristics and fluid distribution during diagenesis, and the oil-water differentiation during hydrocarbon accumulation, and the external factors include the accuracy of measurement methods during drilling, etc. The main controlling factors for the low resistivity of the oil layers in the study area are the additional conductivity of clay mineral cations and the conductivity caused by high irreducible water saturation and salinity, and the secondary controlling factors are low structural amplitude and thin oil layers. By analyzing the reservoir conductivity model and based on the model for calculating formation water and irreducible water saturations, the relationship between electrical characteristics and fluid saturation was established, the quantitative evaluation model of low-conductivity oil layers was constructed by stratification, and the lower limit standard for dividing each fluid type was made to realize accurate fluid identification. The practical application shows that the matching degree between the results of logging interpretation and actual production reaches 88.2%, suggesting a good application effect. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Characteristics of Glutenites of Sha 3 Member in Block Tuo 826, Dongying Sag MIN Wei Xinjiang Petroleum Geology    2021, 42 (4): 428-436.   DOI: 10.7657/XJPG20210405 Abstract （276）   HTML （6）    PDF（pc） （1448KB）（178）       Knowledge map    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. Table and Figures | Reference | Related Articles | Metrics

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Feasibility and Influencing Factors of Miscible Hydrocarbon Gas Flooding for Deep Fractured-Vuggy Reservoirs LI Jikang, SUN Zhixue, TAN Tao, GUO Chen, XIE Shuang, HAO Cong Xinjiang Petroleum Geology    2021, 42 (6): 714-719.   DOI: 10.7657/XJPG20210610 Abstract （309）   HTML （6）    PDF（pc） （533KB）（177）       Knowledge map    Save In order to investigate the deep fractured-vuggy reservoir in Tahe oilfield, the minimum miscible pressure of hydrocarbon gas-crude oil system is calculated through indoor phase behavior experiments and using empirical formula method, pseudo-ternary phase diagram method and slim tube simulation method, and the influences of early nitrogen injection and crude oil quality on hydrocarbon gas miscible flooding are studied through numerical simulation. The research results show that the minimum miscible pressure calculated by the three methods is much lower than the average actual reservoir pressure, so hydrocarbon gas-crude oil miscible flooding is very feasible for the deep fractured-vuggy reservoir in the study area; and early nitrogen injection impacts the miscible flooding significantly. In the reservoir swept by injected nitrogen, the minimum hydrocarbon gas-crude oil miscible pressure becomes higher. In the reservoir where the ratio of nitrogen to hydrocarbon gas is greater than 1.208, a miscible phase wouldn’t appear. Crude oil quality also has a great impact on hydrocarbon gas-crude oil miscible flooding. The more the light components in crude oil, the lower the minimum miscible pressure of hydrocarbon gas and crude oil, and the more the heavy components in crude oil, the lower the ultimate recovery rate of the miscible flooding. Table and Figures | Reference | Related Articles | Metrics

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Sedimentary Characteristics and Connectivity of Upper Wuerhe Formation in Wellblock Ke 75, Karamay Oilfield LIU Nianzhou, LI Bo, ZHANG Yi, WU Min, WANG Quan, SU Hang Xinjiang Petroleum Geology    2022, 43 (4): 417-424.   DOI: 10.7657/XJPG20220406 Abstract （288）   HTML （13）    PDF（pc） （2524KB）（177）       Knowledge map    Save The upper Wuerhe formation in Wellblock Ke 75 in Karamay oilfield, Junggar basin has strong heterogeneity and varying connectivity between adjacent wells, and the understanding of sand body distribution in the formation is greatly different from the previous one. It is necessary to study the sedimentary facies and sand body connectivity to clarify reservoir distribution. Taking the upper Wuerhe formation in the Wellblock Ke 75 as an example, the characteristics and styles of the 4th-order architectural elements for each subfacies belt of alluvial fan controlled by both debris flow and braided channel were discussed according to the principles of sedimentology, and the sedimentary characteristics and sand body connectivity of each architectural style were analyzed. The research shows that when the electrical properties and sedimentary cycle characteristics of neighboring wells in the sheet flow zone at fan root are consistent, the sand body connectivity is good, and when the cross flow sand bodies or cross flow fine-grained sediments are developed, the sand body connectivity is poor, leading to difficulties in forming effective reservoirs. The research confirmed a Class I favorable gas reservoir area in the Wellblock Ke 75 in Karamay oilfield. Table and Figures | Reference | Related Articles | Metrics

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Production Prediction of Fractured Horizontal Wells in Tight Oil Reservoirs SONG Junqiang, LI Xiaoshan, WANG Shuo, GU Kaifang, PAN Hong, WANG Xin Xinjiang Petroleum Geology    2022, 43 (5): 580-586.   DOI: 10.7657/XJPG20220510 Abstract （278）   HTML （13）    PDF（pc） （787KB）（176）       Knowledge map    Save Regarding complex flow regime and large error in lifecycle production prediction for fractured horizontal wells in tight oil reservoirs, the stretched exponential production decline (SEPD) model dominated by transient flow and transitional flow and the exponential model dominated by boundary-dominated flow (BDF) were selected and combined based on the research on the adaptability of empirical production decline model proposed in previous studies. Given equal production and equal decline rate at nodes, a new lifecycle segmented production prediction model with BDF time as node was constructed. Furthermore, the methods for predicting BDF time based on the generalized regression neural network algorithm and for determining the parameters of piecewise function by least square fitting were established. The results show that, whether the BDF is attained, the new model realizes a better fitting than the SEPD or exponential model, and its prediction results are closer to the exponential evaluation results in the late stage of production with an error of less than 5%. Table and Figures | Reference | Related Articles | Metrics

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Correction of Measured Reservoir Physical Properties of Jiamuhe Formation in Zhongguai Uplift of Junggar Basin YANG Chuan, WU Tao, LI Xiao, ZENG Delong, QIU Peng, FENG Xin, DAI Canxin Xinjiang Petroleum Geology    2021, 42 (6): 749-755.   DOI: 10.7657/XJPG20210615 Abstract （244）   HTML （18）    PDF（pc） （9907KB）（176）       Knowledge map    Save The measured permeability of the cores from the tight sandstone reservoir in the Jiamuhe formation of the Zhongguai uplift in the northwestern margin of the Junggar basin ranges from 0.1 mD to 1000 mD, which is 4-6 orders of magnitude different from the permeability calculated from logging. The measured permeability is obviously distorted, which affects the accuracy of reservoir evaluation. Based on the geological background of the study area and combined with well logging and core data, 644 thin sections from 10 wells in the area are analyzed and the main causes of reservoir physical property distortion are studied based on mercury injection method, cast thin section, X-ray diffraction, image analysis and statistics and other methods. The results show that the pseudo granular marginal fractures formed by the decompressed expansion of the cement laumontite are the main reason for the abnormally high permeability measured from the cores taken to surface; the content of laumontite positively correlates to the surface porosity of pseudo fracture, and to the ratio of formation resistivity to neutron porosity. When the laumontite content is less than 5%, and the surface porosity of pseudo granular marginal fractures is less than 1%, the porosity has a good correlation with permeability. However, with the increase of the laumontite content, the permeability increases obviously (mostly more than 1 mD), which is inconsistent with the reservoir type and well logging results in the area. Based on the analysis of rock thin section and well logging data, the correlations between surface porosity of the pseudo fractures and laumontite content and pseudo fracture porosity are determined. By referring to the well logging porosity and eliminating the pseudo fracture porosity, the corrected true porosity and corresponding permeability values are obtained. The corrected reservoir permeability values mainly range from 0.001 mD to 5.000 mD, which is close to the permeability from well logging interpretation, proving that this correction method is reliable. Table and Figures | Reference | Related Articles | Metrics

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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 Xinjiang Petroleum Geology    2021, 42 (4): 462-468.   DOI: 10.7657/XJPG20210410 Abstract （289）   HTML （11）    PDF（pc） （654KB）（173）       Knowledge map    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%. Table and Figures | Reference | Related Articles | Metrics