23 June 2020, Volume 47 Issue 3
    

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    PETROLEUM EXPLORATION
  • Geological characteristics and development potential of transitional shale gas in the east margin of the Ordos Basin, NW China
    KUANG Lichun, DONG Dazhong, HE Wenyuan, WEN Shengming, SUN Shasha, LI Shuxin, QIU Zhen, LIAO Xinwei, LI Yong, WU Jin, ZHANG Leifu, SHI Zhensheng, GUO Wen, ZHANG Surong
    Petroleum Exploration and Development, 2020, 47(3): 435-446. https://doi.org/10.11698/PED.2020.03.01
    Abstract ( ) Download PDF ( ) Rich HTML   Knowledge map Save
    The shales in the 2nd Member of Shanxi Formation in the east margin of the Ordos Basin were deposited in a paralic environment during the Permian. Based on the recent breakthroughs in the shale gas exploration and theoretical understandings on the shale gas of the study area, with a comparison to marine shale gas in the Sichuan Basin and transitional shale gas in the U.S., this study presents the geological characteristics and development potential of transitional gas in the study area. The 2nd Member of the Shanxi Formation in the study area has four geological features: (1) stable sedimentary environment and widely distributed organic shale; (2) well developed micro and nano scale pore and fracture systems with good storage capacity; (3) high content of brittle minerals such as quartz, which is conducive to reservoir fracturing; and (4) moderate reservoir pressure and relatively high gas content. The 2nd Member of Shanxi Formation in the east margin of Ordos Basin is rich in shale gas resource. Three favorable zones, Yulin-Linxian, Shiloubei-Daning-Jixian, and Hancheng-Huangling are developed, with a total area of 1.28×104 km2 and resources between 1.8×1012 and 2.9×1012 m3, indicating a huge exploration potential. Tests of the 2nd Member of Shanxi Formation in vertical wells show that the section has stable gas production and high controlled reserves per well, good recoverability and fracability. The shale section has sufficient energy, stable production capacity, and good development prospects, as evidenced by systematic well testing. The east margin of the Ordos Basin has several shale layers in the Shanxi and Taiyuan formations, and several coal seams interbedded, so collaborative production of different types of natural gas in different layers can be considered. The study results can provide reference for shale gas exploration and development and promote the rapid exploitation of shale gas in China.
  • Huizhou Movement and its significance in Pearl River Mouth Basin, China
    SHI Hesheng, DU Jiayuan, MEI Lianfu, ZHANG Xiangtao, HAO Shihao, LIU Pei, DENG Peng, ZHANG Qin
    Petroleum Exploration and Development, 2020, 47(3): 447-461. https://doi.org/10.11698/PED.2020.03.02
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    The Huizhou Movement refers to the Middle Eocene tectonic transition from the early to late Wenchang Rift stages (about 43 Ma ago) in the Pearl River Mouth Basin. Based on seismic reflection, drilling, logging and geological data, the fault characteristic analysis, denudation thickness recovery, magmatism statistics, regional tectonic dynamics comparison and other methods are used to reveal the characteristics, properties and dynamic mechanism of the Huizhou Movement. The Huizhou Movement mainly shows the North-South transition of rifting and the migration along the faults, basement uplift, magmatic diapir and stratigraphic denudation. It is believed that the Huizhou Movement is a comprehensive reflection of plate interaction and lithospheric thinning process in the Pearl River Mouth Basin, which is closely related to the transition of lithosphere from initial rifting to rapid thinning, the India-Eurasia hard collision and the change of subduction direction of the Pacific plate. The Huizhou Movement has important influence and restriction on Paleogene hydrocarbon-generating sags and the development of hydrocarbon source rocks, sedimentary system and deep high-quality reservoir, hydrocarbon migration and accumulation in the Pearl River Mouth Basin.
  • Fracture development and hydrocarbon accumulation in tight sandstone reservoirs of the Paleogene Huagang Formation in the central reversal tectonic belt of the Xihu Sag, East China Sea
    ZHOU Xinhuai, XU Guosheng, CUI Hengyuan, ZHANG Wu
    Petroleum Exploration and Development, 2020, 47(3): 462-475. https://doi.org/10.11698/PED.2020.03.03
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    By using thin section identification, cathodoluminescence, major and trace elements and fluid inclusion tests and authigenic illite dating, based on observation of core cracks, combined with the microscopic characteristics and imaging logging characteristics of fractures, the stages of the fractures in the Huagang Formation of the central reversal tectonic belt of the Xihu Sag in the East China Sea, and the matching relationship between the fracture development stages and the oil and gas charging stages are clarified. There are diagenetic fractures and tectonic fractures in the reservoirs of the Huagang Formation in the study area. The diagenetic fractures developed during the diagenetic stage of the reservoirs and have less effect on oil and gas migration and transport. The tectonic fractures are divided into three stages based on tectonic movements controlling the fractures and their relationships with hydrocarbon charging: The first stage of fractures was generated in the early stage of the Himalayan Movement-Longjing Movement (12-13 Ma ago), when the tectonic stress caused the sutures and shale strips to twist, deform, and break. Tectonic microfractures generated in this period had short extension, narrow width, and poor effectiveness, and had little effect on oil and gas migration and transport. The second stage of fractures came up during the middle-late period of Himalayan Movement-Longjing Movement (9-12 Ma ago), when tectonic movements caused the development of tectonic fractures in the central reversal tectonic belt, these fractures are of large scale, long extension, and good effectiveness, and matched with the first stage of large scale oil and gas charging (9-12 Ma ago), so they play an important role in oil and gas migration, transportation, and accumulation. The third stage of fractures were created from Himalayan Movement-Okinawa Trough movement to the present day (0-3 Ma ago), the fractures are tectonic ones developing successively; matching with the second stage (0-3 Ma ago) of large-scale oil and gas charging, they created conditions for continuous natural gas migration and transportation. All these prove that the development of reservoir fractures in the Huagang Formation of Xihu Sag can provide seepage space and continuous and effective channels for efficient migration and accumulation of oil and gas.
  • Sedimentary environment and petrological features of organic-rich fine sediments in shallow water overlapping deposits: A case study of Cambrian Yuertus Formation in northwestern Tarim Basin, NW China
    JIN Zhimin, TAN Xiucheng, TANG Hao, SHEN Anjiang, QIAO Zhanfeng, ZHENG Jianfeng, LI Fei, ZHANG Shixuan, CHEN Lei, ZHOU Chenggang
    Petroleum Exploration and Development, 2020, 47(3): 476-489. https://doi.org/10.11698/PED.2020.03.04
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    Taking the Cambrian Yuertus Formation outcrop profiles in the Aksu-Keping-Wushi areas of northwestern Tarim Basin as examples, the depositional environments of organic rich fine sediment were analyzed by examining the outcrop profiles macroscopically and microscopically. The study reveals that: (1) The lower part of the Yuertus Formation consists of organic-rich fine sediment or thin rhythmic interbeds of organic-rich fine sediment and siliceous sediment, the formation transforms to terrigenous diamictic grain shoal and inverse grading carbonate rocks upward. (2) The thin limestone interbedded with dark shale rhythmically has inverse grading. (3) The thin-bedded siliceous rock has metasomatic residual granular texture, stromatolithic structure and cementation fabric in vugs. (4) There are iron crust layers at the top of the shallowing diamictic grain shoal, beneath which exposed karst signs, such as karrens, dissolved fissures, sack-like vugs, near surface karst (plastic) breccia, breccia inside the karst system and terrigenous clastic fillings, can be seen. (5) Both the outcrops and seismic profiles show that organic-rich fine sediments above the unconformities or exposed surfaces are characterized by overlapping. The organic-rich fine sediment of the Cambrian Yuertus Formation was deposited in the anoxic-suboxidized restricted gulf lagoon environment, and its formation was controlled by high paleoproductivity and poor oxygen exchange jointly, then a shallow-water overlapping sedimentary model has been established. The results will help enrich and improve the sedimentary theory of organic-rich fine sediments.
  • Effects of vugs on resistivity of vuggy carbonate reservoirs
    HE Jiahuan, LI Min, ZHOU Keming, YANG Yu, XIE Bing, LI Nong, DANG Lurui, TANG Yanbing
    Petroleum Exploration and Development, 2020, 47(3): 490-498. https://doi.org/10.11698/PED.2020.03.05
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    The pore structure characteristic parameters of vuggy carbonate reservoirs were extracted, and matrix resistivity of vuggy reservoir was calculated by the percolation network simulation. A segmented cross-scale resistivity calculation method was established, in which the finite element method was used to simulate the resistivity of vuggy reservoirs. The mathematical models of vug porosity and water saturation with rock resistivity in vuggy carbonate reservoir were established, and the relationships between them were obtained. Experimental results verified the reliability of the simulation results. The method presented provides new technical means and research method for the resistivity log interpretation of vuggy carbonate reservoirs. The matrix porosity, vug porosity and matrix pore water saturation are the key factors determining the resistivity of reservoir rocks.
  • Reservoir geological modeling and significance of Cambrian Xiaoerblak Formation in Keping outcrop area, Tarim Basin, NW China
    ZHENG Jianfeng, PAN Wenqing, SHEN Anjiang, YUAN Wenfang, HUANG Lili, NI Xinfeng, ZHU Yongjin
    Petroleum Exploration and Development, 2020, 47(3): 499-511. https://doi.org/10.11698/PED.2020.03.06
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    Take the Cambrian Xiaoerblak Formation in the Keping outcrop area as an example, a 28 km reservoir scale geological model was built based on description of 7 profiles, observation of more than 1000 thin sections, petrophysical analysis of 556 samples and many geochemical tests. The Xiaoerblak Formation, 158-178 m thick, is divided into three members and 5 submembers, and is composed of laminated microbialite dolomite (LMD), thrombolite dolomite (TD), foamy-stromatolite dolomite (FSD), oncolite dolomite (OD), grain dolomite (GD)/crystalline dolomite with grain ghost and micritic dolomite (MD)/argillaceous dolomite. The petrology features show that its sediment sequence is micro-organism layer - microbial mound/shoal - tidal flat in carbonate ramp background from bottom up. The reservoir has 5 types of pores, namely, framework pore, dissolved vug, intergranular and intragranular dissolved pore and intercrystalline dissolved pore, as main reservoir space. It is found that the development of pore has high lithofacies selectivity, FSD has the highest average porosity, TD, OD and GD come second. The reservoir is pore-vug reservoir with medium-high porosity and medium-low permeability. The dolomite of Xiaoerblak Formation was formed in para-syngenetic to early diagenetic stage through dolomitization caused by seawater. The reservoir development is jointly controlled by sedimentary facies, micro-organism type, high frequency sequence interface and early dolomitization. The classⅠand Ⅱ reservoirs, with an average thickness of 41.2 m and average reservoir-stratum ratio of about 25.6%, have significant potential. It is predicted that the microbial mounds and shoals in the middle ramp around the ancient uplift are the favorable zones for reservoir development.
  • Oil and gas source and accumulation of Zhongqiu 1 trap in Qiulitage structural belt, Tarim Basin, NW China
    LI Jian, LI Jin, XIE Zengye, WANG Chao, ZHANG Haizu, LIU Mancang, LI Dejiang, MA Wei, MAO Danfeng, ZENG Xu
    Petroleum Exploration and Development, 2020, 47(3): 512-522. https://doi.org/10.11698/PED.2020.03.07
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    Well Zhongqiu 1 obtained high-yield oil and gas flow in the footwall of Zhongqiu structure, marking the strategic breakthrough of Qiulitag structural belt in the Tarim Basin. However, the oil and gas sources in Zhongqiu structural belt and the reservoir formation process in Zhongqiu 1 trap remain unclear, so study on these issues may provide important basis for the next step of oil and gas exploration and deployment in Qiulitage structural belt. In this work, a systematic correlation of oil and gas source in Well Zhongqiu 1 has been carried out. The oil in Well Zhongqiu 1 is derived from Triassic lacustrine mudstone, while the gas is a typical coal-type gas and mainly from Jurassic coal measures. The oil charging in Well Zhongqiu 1 mainly took place during the sedimentary period from Jidike Formation to Kangcun Formation in Neogene, and the oil was mainly contributed by Triassic system; large-scale natural gas charging occurred in the sedimentary period of Kuqa Formation in Neogene, and the coal-type gas generated in the late Jurassic caused large-scale gas invasion to the early Triassic crude oil reservoirs. The Zhongqiu 1 trap was formed earlier than or at the same period as the hydrocarbon generation and expulsion period of Triassic-Jurassic source rocks. Active faults provided paths for hydrocarbon migration. The hydrocarbon source rocks-faults-traps matched well in time and space. Traps in the footwall of the Zhongqiu structural fault have similar reservoir-forming conditions with the Zhongqiu 1 trap, so they are favorable targets in the next step of exploration.
  • Formation of inter-salt overpressure fractures and their significances to shale oil and gas: A case study of the third member of Paleogene Shahejie Formation in Dongpu sag, Bohai Bay Basin
    LIU Weibin, ZHOU Xingui, XU Xingyou, ZHANG Shiqi
    Petroleum Exploration and Development, 2020, 47(3): 523-533. https://doi.org/10.11698/PED.2020.03.08
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    Taking the inter-salt organic-rich shales in the third member of Paleogene Shahejie Formation (Es3) of Dongpu sag in Bohai Bay Basin as an example, the origin of overpressure, development characteristics, formation and evolution mechanism, formation stages and geological significance on shale oil and gas of overpressure fractures in the inter-salt shale reservoir were investigated by means of thin section identification, scanning electron microscopy observation, analysis of fluid inclusions, logging data analysis, and formation pressure inversion. The results show that overpressure is universal in the salt-lake basin of Dongpu sag, and under-compaction caused by the sealing of salt-gypsum layer, pressurization due to hydrocarbon generation, transformation and dehydration of clay minerals, and fault sealing are the 4 main factors leading to the occurrence of overpressure. The overpressure fractures are small in scale, with an average length of 356.2 μm and an average underground opening of 11.6 μm. But they are densely developed, with an average surface density of 0.76 cm/cm2. Moreover, they are often accompanied by oil and gas charging, and thus high in effectiveness. Overpressure fractures were mainly formed during two periods of large-scale oil and gas charging, approximately 30-25 Ma ago and 5-0 Ma ago. Inter-salt overpressure fractures play dual roles as the storage space and migration paths of shale oil and gas. They contribute 22.3% to the porosity of shale reservoir and 51.4% to the permeability. They can connect fracture systems of multiple scales, greatly improving the quality of shale reservoir. During the development of shale oil and gas, inter-salt overpressure fractures can affect the extension and morphology of hydraulic fractures, giving rise to complex and highly permeable volumetric fracture networks, improving hydraulic fracturing effect and enhancing shale oil and gas productivity.
  • Distribution pattern of deltaic sand bodies controlled by syn-depositional faults in a rift lacustrine basin
    DOU Luxing, HOU Jiagen, ZHANG Li, LIU Yuming, WANG Xixin, WANG Jian, WU Gang
    Petroleum Exploration and Development, 2020, 47(3): 534-546. https://doi.org/10.11698/PED.2020.03.09
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    Take the lacustrine delta in the second member of Paleogene Shahejie Formation in block Wang43, Dongying sag, Bohai Bay Basin as an example, the deposition architectural characteristics of lacustrine deltaic sand bodies controlled by syn-depositional faults in complex fault blocks of rift basin are examined from the aspect of structure-deposition response, using cores, well logs and three-dimensional seismic data. The small-scale syn-depositional faults in complex fault blocks are dense and different in dip, the activity along the strike of syn-depositional fault varies in different positions, and all these control the sedimentary process of deltaic sand bodies. Influenced by syn-depositional faults, the deltaic distributary channel is more likely to pass through the position with weak fault activity, and be deflected or limited at the position with strong fault activity. In downthrown side of a single syn-depositional fault or micro-graben areas, sand bodies increase in thickness and planar scale, and sand bodies of multiple stages are likely to stack over each other vertically. In micro-horst areas controlled by syn-depositional faults, the sand bodies decreases in number, and appear in intermittent superimposed pattern vertically. This study can provide new research ideas and theoretical basis for exploration and development geological research of complex fault block oilfields.
  • Logging response characteristics and formation process of flushed zone in the Orinoco heavy oil belt, Venezuela
    CHEN Heping, CHEN Hao, LI Changwen, WANG Yusheng, LI Jianping, HUANG Rui, TIAN Congcong, HOU Qiuyuan
    Petroleum Exploration and Development, 2020, 47(3): 547-554. https://doi.org/10.11698/PED.2020.03.10
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    The origins and logging responses of flushed zones in some blocks of Orinoco heavy oil belt, Venezuela are still unclear. To solve this issue, we examined the conventional logging, nuclear magnetic resonance logging, fluid viscosity, core analysis and oil field production data comprehensively to find out the logging responses and origins of the flushed zones. The results show that the main reason for the formation of flushed zone is surface water invasion, which leads to crude oil densification. The crude oil densification produces asphalt membrane (asphalt crust) which wraps up free water, causing special logging responses of the flushed zones. According to the different logging responses, we classified the flushed zones into two types and analyzed the formation processes of the two types of flushed zones. According to the characteristics of logging curves after water flush, we confirmed that the water flush began earlier than the reservoir accumulation.
    • OIL AND GAS FIELD DEVELOPMENT
  • Dominating factors on well productivity and development strategies optimization in Weiyuan shale gas play, Sichuan Basin, SW China
    MA Xinhua, LI Xizhe, LIANG Feng, WAN Yujin, SHI Qiang, WANG Yonghui, ZHANG Xiaowei, CHE Mingguang, GUO Wei, GUO Wei
    Petroleum Exploration and Development, 2020, 47(3): 555-563. https://doi.org/10.11698/PED.2020.03.11
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    Weiyuan shale gas play is characterized by thin high-quality reservoir thickness, big horizontal stress difference, and big productivity differences between wells. Based on integrated evaluation of shale gas reservoir geology and well logging interpretation of more than 20 appraisal wells, a correlation was built between the single well test production rate and the high-quality reservoir length drilled in the horizontal wells, high-quality reservoir thickness and the stimulation treatment parameters in over 100 horizontal wells, the dominating factors on horizontal well productivity were found out, and optimized development strategies were proposed. The results show that the deployed reserves of high-quality reservoir are the dominating factors on horizontal well productivity. In other words, the shale gas well productivity is controlled by the thickness of the high-quality reservoir, the high-quality reservoir drilling length and the effectiveness of stimulation. Based on the above understanding, the development strategies in Weiyuan shale gas play are optimized as follows: (1) The target of horizontal wells is located in the middle and lower parts of Longyi 11 (Wei202 area) and Longyi 11 (Wei204 area). (2) Producing wells are drilled in priority in the surrounding areas of Weiyuan county with thick high-quality reservoir. (3) A medium to high intensity stimulation is adopted. After the implementation of these strategies, both the production rate and the estimated ultimate recovery (EUR) of individual shale gas wells have increased substantially.
  • Estimating pore volume compressibility by spheroidal pore modeling of digital rocks
    SUI Weibo, QUAN Zihan, HOU Yanan, CHENG Haoran
    Petroleum Exploration and Development, 2020, 47(3): 564-572. https://doi.org/10.11698/PED.2020.03.12
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    The real pores in digital cores were simplified into three abstractive types, including prolate ellipsoids, oblate ellipsoids and spheroids. The three-dimensional elliptical-pore model of digital core was established based on mesoscopic mechanical theory. The constitutive relationship of different types of pore microstructure deformation was studied with Eshelby equivalent medium theory, and the effects of pore microstructure on pore volume compressibility under elastic deformation conditions of one type, multiple types and mixed types of pores were investigated. The results showed that the pore volume compressibility coefficient of digital core is closely related with porosity, pore aspect ratio and volumetric proportions of different types of pores. (1) The compressibility coefficient of prolate ellipsoidal pore is positively correlated with the pore aspect ratio, while that of oblate ellipsoidal pore is negatively correlated with the pore aspect ratio. (2) At the same average value of pore aspect ratio satisfying Gaussian distribution, the more concentrated the range of pore aspect ratio, the higher the compressibility coefficient of both prolate and oblate ellipsoidal pores will be, and the larger the deformation under the same stress condition. (3) The pore compressibility coefficient increases with porosity. (4) At a constant porosity value, the higher the proportion of oblate ellipsoidal and spherical pores in the rock, the more easier for the rock to deform, and the higher the compressibility coefficient of the rock is, while the higher the proportion of prolate ellipsoidal pores in the rock, the more difficult it is for rock to deform, and the lower the compressibility coefficient of the rock is. By calculating pore compressibility coefficient of ten classical digital rock samples, the presented analytical elliptical-pore model based on real pore structure of digital rocks can be applied to calculation of pore volume compressibility coefficient of digital rock sample.
  • Partial phase flow rate measurements for stratified oil-water flow in horizontal wells
    SONG Hongwei, GUO Haimin, GUO Shuai, SHI Hangyu
    Petroleum Exploration and Development, 2020, 47(3): 573-582. https://doi.org/10.11698/PED.2020.03.13
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    To accurately measure and evaluate the oil-water production profile of horizontal wells, a dynamic measurement experiment of oil-water two-phase flow in horizontal wells and numerical simulation were combined to establish a method for measuring the partial phase flow rate of oil-water two-phase stratified flow in horizontal wells. An experimental work was performed in horizontal oil-water two-phase flow simulation well using combination production logging tool including mini-capacitance sensor and mini-spinner. The combination tool provides a recording of holdup and velocity profiles at five different heights of the borehole cross-section. The effect of total flow rate and water-cut on the response of spinner and capacitive sensor at five measured positions were investigated. The capacitance water holdup interpolation imaging algorithm was used to determine the local fluid property and oil-water interface height, and the measured local fluid speed was combined with the numerical simulation result to establish an optimal calculation model for obtaining the partial phase flow rate of the oil-water two-phase stratified flow in the horizontal well. The calculated flow rates of five measured points are basically consistent with the experimental data, the total flow rate and water holdup from calculation are in agreement with the set values in the experiment too, suggesting that the method has high accuracy.
  • Automatic well test interpretation based on convolutional neural network for a radial composite reservoir
    LI Daolun, LIU Xuliang, ZHA Wenshu, YANG Jinghai, LU Detang
    Petroleum Exploration and Development, 2020, 47(3): 583-591. https://doi.org/10.11698/PED.2020.03.14
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    An automatic well test interpretation method for radial composite reservoirs based on convolutional neural network (CNN) is proposed, and its effectiveness and accuracy are verified using actual field data. In this paper, Based on the data transformed by logarithm function and the loss function of mean square error (MSE), the optimal CNN is obtained by reducing the loss function to optimize the network with "dropout" method to avoid over fitting. The trained optimal network can be directly used to interpret the buildup or drawdown pressure data of the well in the radial composite reservoir, that is, the log-log plot of the given measured pressure variation and its derivative data are input into the network, the outputs are corresponding reservoir parameters (mobility ratio, storativity ratio, dimensionless composite radius, and dimensionless group characterizing well storage and skin effects), which realizes the automatic initial fitting of well test interpretation parameters. The method is verified with field measured data of Daqing Oilfield. The research shows that the method has high interpretation accuracy, and it is superior to the analytical method and the least square method.
    • PETROLEUM ENGINEERING
  • A novel approach of tight oil reservoirs stimulation based on fracture controlling optimization and design
    LEI Qun, WENG Dingwei, GUAN Baoshan, MU Lijun, XU Yun, WANG Zhen, GUO Ying, LI Shuai
    Petroleum Exploration and Development, 2020, 47(3): 592-599. https://doi.org/10.11698/PED.2020.03.15
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    To deal with the stress interference caused by simultaneous propagation of multiple fractures and the wettability reversal and physical property changes of the reservoir caused by fracturing fluid getting in during large volume fracturing of tight oil reservoirs through a horizontal well, a non-planar 3D fracture growth model was built, wettability reversal characterizing parameters and change of relative permeability curve were introduced to correct the production prediction model of fractured horizontal well, a fracturing design optimization software (FrSmart) by integrating geological and engineering data was developed, and a fracturing design optimization approach for tight oil reservoirs based on fracture control was worked out. The adaptability of the method was analyzed and the fracture parameters of horizontal wells in tight oil reservoirs were optimized. The simulation results show that fracturing technology based on fracture control is suitable for tight oil reservoirs, and by optimizing fracture parameters, this technology makes it possible to produce the maximum amount of reserves in the well-controlled unit of unconventional reservoirs. The key points of fracturing design optimization based on fracture control include increasing lateral length of and reducing the row spacing between horizontal wells, increasing perforation clusters in one stage to decrease the spacing of neighboring fractures, and also avoiding interference of old and new fracturing wells. Field tests show that this technology can increase single well production and ultimate recovery. Using this technology in developing unconventional resources such as tight oil reservoirs in China will enhance the economics significantly.
  • Effects of instantaneous shut-in of high production gas well on fluid flow in tubing
    ZHANG Zhi, WANG Jiawei, LI Yanjun, LUO Ming, ZHANG Chao
    Petroleum Exploration and Development, 2020, 47(3): 600-607. https://doi.org/10.11698/PED.2020.03.16
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    As the classical transient flow model cannot simulate the water hammer effect of gas well, a transient flow mathematical model of multiphase flow gas well is established based on the mechanism of water hammer effect and the theory of multiphase flow. With this model, the transient flow of gas well can be simulated by segmenting the curved part of tubing and calculating numerical solution with the method of characteristic curve. The results show that the higher the opening coefficient of the valve when closed, the larger the peak value of the wellhead pressure, the more gentle the pressure fluctuation, and the less obvious the pressure mutation area will be. On the premise of not exceeding the maximum shut-in pressure of the tubing, adopting large opening coefficient can reduce the impact of the pressure wave. The higher the cross-section liquid holdup, the greater the pressure wave speed, and the shorter the propagation period will be. The larger the liquid holdup, the larger the variation range of pressure, and the greater the pressure will be. In actual production, the production parameters can be adjusted to get the appropriate liquid holdup, control the magnitude and range of fluctuation pressure, and reduce the impact of water hammer effect. When the valve closing time increases, the maximum fluctuating pressure value of the wellhead decreases, the time of pressure peak delays, and the pressure mutation area gradually disappears. The shorter the valve closing time, the faster the pressure wave propagates. Case simulation proves that the transient flow model of gas well can optimize the reasonable valve opening coefficient and valve closing time, reduce the harm of water hammer impact on the wellhead device and tubing, and ensure the integrity of the wellbore.
  • Study on fracture propagation behavior in ultra-heavy oil reservoirs based on true triaxial experiments
    LIN Botao, SHI Can, ZHUANG Li, YOU Hongjuan, HUANG Yong
    Petroleum Exploration and Development, 2020, 47(3): 608-616. https://doi.org/10.11698/PED.2020.03.17
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    As the ultra-heavy oil reservoirs developed by steam assisted gravity drainage (SAGD) in the Fengcheng oilfield, Xinjiang have problems such as huge steam usage, long preheating period, low production, and inaccessible reserve in local parts. Based on the rock mechanics and porosity/permeability characteristics of heavy oil reservoir and interlayer, a series of true triaxial experiments and CT tests considering the fracturing fluid injection rate, viscosity, perforation density and location of fracture initiation were conducted to disclose the propagation behavior of micro- and macro-fractures in the reservoirs and mudstone interlayers. These experiments show that fracturing in the heavy oil reservoirs only generates microfractures which can’t break the interlayer. In contrast, when fracturing in the interlayer, the higher the injection rate (greater than 0.6 m3/min), the lower the viscosity, the easier it is to form macro-fractures in the interlayers, and the further the fractures will propagate into the reservoirs. Also, increasing perforation density tends to create complex macro-fracture network in the interbedded reservoirs and mudstone interlayers. The findings of this study can provide scientific guidance for the selection of fracturing layer and the optimization of parameters in the interlayer fracturing of heavy oil reservoirs.
    • NEW ENERGY AND EMERGING FIELD
  • Controlling factors of marine shale gas differential enrichment in southern China
    JIANG Zhenxue, SONG Yan, TANG Xianglu, LI Zhuo, WANG Xingmeng, WANG Guozhen, XUE Zixin, LI Xin, ZHANG Kun, CHANG Jiaqi, QIU Hengyuan
    Petroleum Exploration and Development, 2020, 47(3): 617-628. https://doi.org/10.11698/PED.2020.03.18
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    Based on the exploration and development practice of marine shale gas in Fuling, Weiyuan, Changning, Luzhou and Southeast Chongqing in southern China, combined with experimental tests and analysis, six factors controlling differential enrichment of marine shale gas are summarized as follows: (1) The more appropriate thermal evolution and the higher the abundance of organic matter, the higher the adsorption and total gas content of shale will be. (2) Kerogen pyrolysis and liquid hydrocarbon cracking provide the majority of marine shale gas. (3) The specific surface area and pore volume of organic matter rich shale increased first and then decreased with the increase of thermal evolution degree of organic shale. At Ro between 2.23% and 3.33%, the shale reservoirs are mainly oil-wet, which is conducive to the enrichment of shale gas. (4) The thicker the roof and floor, the higher the shale gas content. The longer the last tectonic uplift time and the greater the uplift amplitude, the greater the loss of shale gas will be. (5) The buried depth and dip angle of the stratum have different controlling and coupling effects on shale gas in different tectonic positions, resulting in two differential enrichment models of shale gas. (6) The effective and comprehensive matching of source, reservoir and preservation conditions determines the quality of shale gas accumulation. Good match of effective gas generating amount and time, moderate pore evolution and good preservation conditions in space and time is essential for the enrichment of shale gas.
  • Data-driven optimization for fine water injection in a mature oil field
    JIA Deli, LIU He, ZHANG Jiqun, GONG Bin, PEI Xiaohan, WANG Quanbin, YANG Qinghai
    Petroleum Exploration and Development, 2020, 47(3): 629-636. https://doi.org/10.11698/PED.2020.03.19
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    Based on the traditional numerical simulation and optimization algorithms, in combination with the layered injection and production "hard data" monitored at real time by automatic control technology, a systematic approach for detailed water injection design using data-driven algorithms is proposed. First the data assimilation technology is used to match geological model parameters under the constraint of observed well dynamics; the flow relationships between injectors and producers in the block are worked out based on automatic identification method for layered injection-production flow relationship; multi-layer and multi-direction production splitting technique is used to calculate the liquid and oil production of producers in different layers and directions and obtain quantified indexes of water injection effect. Then, machine learning algorithms are adopted to evaluate the effectiveness of water injection in different layers of wells and find out the direction of water injection adjustment. Finally, the particle swarm algorithm is used to optimize the detailed water injection plan and predict production. This method and procedure make full use of the automation and intelligence of data-driven and machine learning algorithms. This method was used to match the data of a complex fault block reservoir in eastern China, achieving a fitting rate of 85%. The cumulative oil production in the example block for 12 months after optimization is 8.2% higher than before. This method can help design detailed water injection program for mature oilfields.
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