20 February 2020, Volume 47 Issue 1
    

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    PETROLEUM EXPLORATION
  • Types and resource potential of continental shale oil in China and its boundary with tight oil
    ZHAO Wenzhi, HU Suyun, HOU Lianhua, YANG Tao, LI Xin, GUO Bincheng, YANG Zhi
    Petroleum Exploration and Development, 2020, 47(1): 1-10. https://doi.org/10.11698/PED.2020.01.01
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    Continental shale oil has two types, low-medium maturity and medium-high maturity, and they are different in terms of resource environment, potential, production methods and technologies, and industrial evaluation criteria. In addition, continental shale oil is different from the shale oil and tight oil in the United States. Scientific definition of connotations of these resource types is of great significance for promoting the exploration of continental shale oil from "outside source" into "inside source" and making it a strategic replacement resource in the future. The connotations of low-medium maturity and medium-high maturity continental shale oils are made clear in this study. The former refers to the liquid hydrocarbons and multiple organic matter buried in the continental organic-rich shale strata with a burial depth deeper than 300 m and a Ro value less than 1.0%. The latter refers to the liquid hydrocarbons present in organic-rich shale intervals with a burial depth that in the "liquid window" range of the Tissot model and a Ro value greater than 1.0%. The geological characteristics, resource potential and economic evaluation criteria of different types of continental shale oil are systematically summarized. According to evaluation, the recoverable resources of in-situ conversion technology for shale oil with low-medium maturity in China is about (700-900)×108 t, and the economic recoverable resources under medium oil price condition ($ 60-65/bbl) is (150-200)×108 t. Shale oil with low-medium maturity guarantees the occurrence of the continental shale oil revolution. Pilot target areas should be optimized and core technical equipment should be developed according to the key parameters such as the cumulative production scale of well groups, the production scale, the preservation conditions, and the economics of exploitation. The geological resources of medium-high maturity shale oil are about 100×108 t, and the recoverable resources can to be determined after the daily production and cumulative production of a single well reach the economic threshold. Continental shale oil and tight oil are different in lithological combinations, facies distribution, and productivity evaluation criteria. The two can be independently distinguished and coexist according to different resource types. The determination of China's continental shale oil types, resources potentials, and tight oil boundary systems can provide a reference for the upcoming shale oil exploration and development practices and help the development of China’s continental shale oil.
  • Breakthrough of shallow shale gas exploration in Taiyang anticline area and its significance for resource development in Zhaotong, Yunnan province, China
    LIANG Xing, XU Zhengyu, ZHANG Zhao, WANG Weixu, ZHANG Jiehui, LU Huili, ZHANG Lei, ZOU Chen, WANG Gaocheng, MEI Jue, RUI Yun
    Petroleum Exploration and Development, 2020, 47(1): 11-18. https://doi.org/10.11698/PED.2020.01.02
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    Based on exploration and development results and evaluation of marine shale gas in South China in the past ten years, in view of the features of "high maturity, strong tectonic reconstruction and high shear stress" of the shale in Zhaotong exploration zone in the Yunnan and Guizhou Plateau, as well as the key issues of long time diffusion and leakage of shallow shale gas, and the preservation conditions, the factors controlling shallow shale gas sweet spot and key zone selection evaluation technology of shale gas are investigated. From 2017 to 2018, the first significant exploration breakthrough was made in the Taiyang anticline at a buried depth of 700 to 2 000 m, discovering large-scale proved geological reserves of shallow shale gas. By examining the accumulation conditions and sweet spot control factors of the shallow shale gas in this area, it is found that the accumulation and productivity potential of shale gas in the mountainous area with complex structure outside basin are controlled by five factors: (1) The gas rich area has weak tectonic reconstruction and good preservation conditions on the whole, taking on typical anticline trap occurrence mode. (2) The gas-rich area is in over-pressure state and high in shale gas content. (3) The gas rich area has high quality shale and thus superior source rock condition. (4) The gas-rich area has high quality reservoirs dominated by classⅠ. (5) The shale in the gas-rich area has high content of brittle minerals and small difference between maximum and minimum horizontal stresses which are conducive to hydraulic fracturing. The innovative practice and core technologies formed during the exploration and production capacity construction of shallow shale gas in the Zhaotong demonstration zone have great reference significance for shallow shale gas exploration and development in other areas.
  • Tectonic relationship between the Kelameili range and the Dajing depression: Insights into the Carboniferous tectonic-sedimentary framework
    ZHANG Lei, HE Dengfa, YI Zejun, LI Di
    Petroleum Exploration and Development, 2020, 47(1): 29-44. https://doi.org/10.11698/PED.2020.01.03
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    Based on comprehensive analysis of typical outcrops, latest deep wells drilled and high resolution seismic profiles in the study area, we examined the geologic structure of the Kelameili range, and analyzed the structural relationship between the Kelameili range and the Dajing depression, and discussed the tectonic-sedimentary framework in different periods of Carboniferous by using axial surface analysis and balanced section techniques. Understandings in three aspects are achieved: (1) The study area experienced five stages of compressional tectonic movements, the Early Carboniferous, the Late Carboniferous, the Middle-Late Permian, Late Cretaceous and Paleogene, and three stages of extensional tectonic movements, the middle-late Early Carboniferous, the middle-late Late Carboniferous and Early Permian. At the end of the Early Permian and the Mid-Late Cretaceous, the tectonic wedges moved southward respectively. (2) The Kelameili range and Dajing depression had the first basin-range coupling during the early Early Carboniferous, basin-range decoupling in the following middle-late Early Carboniferous to the Early Permian, then basin-range strong recoupling in the Middle Permian, and the basin-range coupling had been inherited in the subsequent Indosinian, Yanshanian and Himalayan movements. (3) During the early Early Carboniferous, the study area was a foreland basin where the Dishuiquan Formation source rock developed; in mid-late Early Carboniferous, a series of NW- and NWW-trending half-garben fault basins developed, where the Songkaersu Formation volcanic reservoir formed. In late Early Carboniferous, the study area entered into depression basin stage after rifting, and the Shuangjingzi Formation source rock developed; in the mid-late Late Carboniferous, Batamayineshan fault basin emerged, and the Upper-Carboniferous volcanic reservoir was formed, affected by the tectonic compression during late Carboniferous and Mid-Permian, the Batamayineshan Formation suffered extensive erosion, and only partially remains in the piedmont depression zone.
  • Fluid interaction mechanism and diagenetic reformation of basement reservoirs in Beier Sag, Hailar Basin, China
    LI Juan, WEI Pingsheng, SHI Lanting, CHEN Guangpo, PENG Wei, SUN Songling, ZHANG Bin, XIE Mingxian, HONG Liang
    Petroleum Exploration and Development, 2020, 47(1): 45-56. https://doi.org/10.11698/PED.2020.01.04
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    Based on analysis of core observation, thin sections, cathodoluminescence, scanning electron microscope (SEM), etc., and geochemical testing of stable carbon and oxygen isotopes composition, element content, fluid inclusions, and formation water, the fluid interaction mechanism and diagenetic reformation of fracture-pore basement reservoirs of epimetamorphic pyroclastic rock in the Beier Sag, Hailar Basin were studied. The results show that: (1) Two suites of reservoirs were developed in the basement, the weathering section and interior section, the interior section has a good reservoir zone reaching the standard of type I reservoir. (2) The secondary pores are formed by dissolution of carbonate minerals, feldspar, and tuff etc. (3) The diagenetic fluids include atmospheric freshwater, deep magmatic hydrothermal fluid, organic acids and hydrocarbon-bearing fluids. (4) The reservoir diagenetic reformation can be divided into four stages: initial consolidation, early supergene weathering-leaching, middle stage structural fracture-cementation-dissolution, and late organic acid-magmatic hydrothermal superimposed dissolution. Among them, the second and fourth stages are the stages for the formation of weathering crust and interior dissolution pore-cave reservoirs, respectively.
  • Prediction method of physical parameters based on linearized rock physics inversion
    ZHANG Jiajia, YIN Xingyao, ZHANG Guangzhi, GU Yipeng, FAN Xianggang
    Petroleum Exploration and Development, 2020, 47(1): 57-64. https://doi.org/10.11698/PED.2020.01.05
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    A linearized rock physics inversion method is proposed to deal with two important issues, rock physical model and inversion algorithm, which restrict the accuracy of rock physics inversion. In this method, first, the complex rock physics model is expanded into Taylor series to get the first-order approximate expression of the inverse problem of rock physics; then the damped least square method is used to solve the linearized rock physics inverse problem directly to get the analytical solution of the rock physics inverse problem. This method does not need global optimization or random sampling, but directly calculates the inverse operation, with high computational efficiency. The theoretical model analysis shows that the linearized rock physical model can be used to approximate the complex rock physics model. The application of actual logging data and seismic data shows that the linearized rock physics inversion method can obtain more accurate physical parameters. This method is suitable for linear or slightly non-linear rock physics model, but may not be suitable for highly non-linear rock physics model.
  • Three-dimensional discrete element numerical simulation of Paleogene salt structures in the western Kuqa foreland thrust belt
    LI Jianghai, ZHANG Yu, WANG Honghao, WANG Dianju
    Petroleum Exploration and Development, 2020, 47(1): 65-76. https://doi.org/10.11698/PED.2020.01.06
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    Taking the Paleogene salt strata in the west of Kuqa foreland thrust belt as study object, the deformation features of salt structure in the compression direction and perpendicular to the compression direction were examined to find out the control factors and formation mechanisms of the salt structures. By using the three-dimensional discrete element numerical simulation method, the formation mechanisms of typical salt structures of western Kuqa foreland thrust belt in Keshen and Dabei work area were comprehensively analyzed. The simulation results show that the salt structure deformation of Keshen and Dabei work areas is piggyback type, with deformation concentrated in the piedmont zone; early uplift near the compression end basement, pre-existing basement faults, synsedimentary process and the initial depocenter of the salt rock affect the formation of the salt structure; in the direction perpendicular to the compression direction, the salt rock near the compression end has stronger lateral mobility and velocity component moving towards the middle part, the closer to the middle, the bigger the velocity will be, so the salt rock will aggregate towards the middle and deform intensely, forming complex folds and separation of salt structure from salt source, and local outcrop out of ground with thrust fault. Compared with 2D simulation, 3D simulation can analyze the salt structure in the principal stress direction and direction perpendicular to the principal stress, give us a full view of the formation mechanisms of salt structure, and guide the exploration of oil and gas reservoirs related to salt structures.
  • Forward simulation of array laterolog resistivity in anisotropic formation and its application
    YUAN Chao, LI Chaoliu, ZHOU Cancan, XIAO Qiyao, LI Xia, FAN Yiren, YU Jun, WANG Lei, XING Tao
    Petroleum Exploration and Development, 2020, 47(1): 77-85. https://doi.org/10.11698/PED.2020.01.07
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    A scaling-down experiment system of array laterolog resistivity was developed, and a corresponding formation model was built by 3D finite element numerical method to study the effect of different factors on the logging response quantitatively. The error between the experimental and numerical results was less than 5%, validating the reliability of the numerical simulation method. The single factor analysis of the formation relative dip, resistivity anisotropy and drilling fluid invasion was carried out by numerical simulation method, and the results show that: (1) The increase of relative dip can lead to the increase of formation resistivity, but the increasing value is relatively small, and the values of five array resistivity curves will reverse when the relative dip angle reaches a certain degree. (2) The increase of anisotropic coefficient λ can also cause the formation resistivity to rise, and the resistivity will increase by about 10% when λ increases from 1.0 to 1.5 in vertical wells. (3) Drilling fluid invasion has a more significant effect on the logging response than the former two factors. The order of the five curves will change due to mud invasion in anisotropic formation and the change rule is contrary to resistivity anisotropy. Taking the logging data of the Yingxi oilfield in the Qaidam Basin as an example, an anisotropic formation model considering drilling fluid invasion was built, and the numerical simulation results from the above methods were basically consistent with the logging data, which verified the accuracy of the method again. The results of this study lay a theoretical foundation for multiple-parameter inversion in anisotropic formation under complex well conditions.
  • Prestack inversion identification of organic reef gas reservoirs of Permian Changxing Formation in Damaoping area, Sichuan Basin, SW China
    ZHOU Lu, ZHONG Feiyan, YAN Jiachen, ZHONG Kexiu, WU Yong, XU Xihui, LU Peng, ZHANG Wenji, LIU Yi
    Petroleum Exploration and Development, 2020, 47(1): 86-97. https://doi.org/10.11698/PED.2020.01.08
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    Organic reef reservoirs in the platform margin of Kaijiang-Liangping trough in Damaoping area, Sichuan Basin are thin in single layer, fast in lateral variation, and have small P-impedance difference from the surrounding rock, it is difficult to identify and predict the reservoirs and fluid properties by conventional post-stack inversion. Through correlation analysis of core test data and logging P-S wave velocity, this work proposed a formula to calculate the shear wave velocity in different porosity ranges, and solved the issue that some wells in the study area have no S-wave data. AVO forward analysis reveals that formation porosity is the main factor affecting the variation of AVO type, the change of water saturation cannot affect the AVO type, but it has an effect on the change range of AVO. Through cross-plotting analysis of elastic parameters, it is found that fluid factor is a parameter sensitive to gas-bearing property of organic reef reservoir in the study area. By comparing results of post-stack impedance inversion, post-stack high frequency attenuation property, pre-stack simultaneous inversion and AVO anomaly analysis of angle gathers, it is found that the gas-bearing prediction of organic reef reservoirs by using fluid factor derived from simultaneous pre-stack inversion had the highest coincidence rate with actual drilling data. At last, according to the characteristics of fluid factor distribution, the favorable gas-bearing area of the organic reef reservoir in Changxing Formation was predicted, and the organic reef trap at the top of Changxing Formation in Block A of Damaoping area was sorted out as the next exploration target.
  • Factors controlling the development of tight sandstone reservoirs in the Huagang Formation of the central inverted structural belt in Xihu sag, East China Sea Basin
    XU Fanghao, XU Guosheng, LIU Yong, ZHANG Wu, CUI Hengyuan, WANG Yiran
    Petroleum Exploration and Development, 2020, 47(1): 98-109. https://doi.org/10.11698/PED.2020.01.09
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    By means of thin section analysis, zircon U-Pb dating, scanning electron microscopy, electron probe, laser micro carbon and oxygen isotope analysis, the lithologic features, diagenetic environment evolution and controlling factors of the tight sandstone reservoirs in the Huagang Formation of Xihu sag, East China Sea Basin were comprehensively studied. The results show that: the sandstones of the Huagang Formation in the central inverted structural belt are poor in physical properties, dominated by feldspathic lithic quartz sandstone, high in quartz content, low in matrix, kaolinite and cement contents, and coarse in clastic grains; the acidic diagenetic environment formed by organic acids and meteoric water is vital for the formation of secondary pores in the reservoirs; and the development and distribution of the higher quality reservoirs in the tight sandstones of the Huagang Formation are controlled by sediment source, sedimentary facies belt, abnormal overpressure and diagenetic environment evolution. Sediment provenance and dominant sedimentary facies led to favorable initial physical properties of the sandstones in the Huagang Formation, which is the prerequisite for development of reservoirs with better quality later. Abnormal overpressure protected the primary pores, thus improving physical properties of the reservoirs in the Huagang Formation. Longitudinally, due to the difference in diagenetic environment evolution, the high-quality reservoirs in the Huagang Formation are concentrated in the sections formed in acidic diagenetic environment. Laterally, the high-quality reservoirs are concentrated in the lower section of the Huagang Formation with abnormal high pressure in the middle-northern part; but concentrated in the upper section of Huagang Formation shallower in burial depth in the middle-southern part.
  • Cenozoic structural deformation in the Yuqia-Jiulongshan region, northern Qaidam Basin, China
    CHEN Siyuan, ZHANG Yongshu, WU Lei, ZHANG Junyong, WANG Liqun, XIAO Ancheng, SHEN Ya
    Petroleum Exploration and Development, 2020, 47(1): 110-119. https://doi.org/10.11698/PED.2020.01.10
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    Based on field geological survey, interpretation of seismic reflection profile and thermochronology dating, this paper systematically studied the structural deformation of the Yuqia-Jiulongshan region in northern Qaidam Basin during the Cenozoic. The results show that the area is primarily dominated by a large box-shaped anticline, with steep limbs and a wide and gently-deformed core. The Mahaigaxiu and Jiulongshan anticlines are secondary folds controlled by secondary faults in the limbs of the box-shaped anticline. Whereas the Yuqia and the Northern Yuqia anticlines are secondary folds within the wide core of the box-shaped anticline. The geometry of the box-shaped anticline is mainly controlled by some high-angle reverse faults with certain right-lateral strike-slip components, displaying distinct positive flower structures in section view. Combining the sedimentary correlation and detrital apatite fission track analysis, we believe that the Yuqia-Jiulongshan region was a paleo-uplift that developed slightly in the early Cenozoic, resulting in the relatively thin Cenozoic strata. The intense deformation that shaped the present-day structural framework occurred in or after the sedimentary period of Shizigou Formation. The Yuqia - Jiulongshan paleo-uplift is adjacent to the Sainan depression that is rich in Lower-Middle Jurassic source rocks, and thus has high potential for future hydrocarbon exploration.
    • OIL AND GAS FIELD DEVELOPMENT
  • Technological progress and development directions of PetroChina overseas oil and gas field production
    MU Longxin, CHEN Yaqiang, XU Anzhu, WANG Ruifeng
    Petroleum Exploration and Development, 2020, 47(1): 120-128. https://doi.org/10.11698/PED.2020.01.11
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    This study reviews the development history of PetroChina’s overseas oil and gas field development technologies, summarizes the characteristic technologies developed, and puts forward the development goals and technological development directions of overseas business to overcome the challenges met in overseas oil and gas production. In the course of PetroChina’s overseas oil and gas field production practice of more than 20 years, a series of characteristic technologies suitable for overseas oil and gas fields have been created by combining the domestic mature oil and gas field production technologies with the features of overseas oil and gas reservoirs, represented by the technology for high-speed development and stabilizing oil production and controlling water rise for overseas sandstone oilfields, high efficiency development technology for large carbonate oil and gas reservoirs and foamy oil depletion development technology in use of horizontal wells for extra-heavy oil reservoirs. Based on in-depth analysis of the challenges faced by overseas oil and gas development and technological requirements, combined with the development trends of oil and gas development technologies in China and abroad, overseas oil and gas development technologies in the future are put forward, including artificial intelligence reservoir prediction and 3D geological modeling, secondary development and enhanced oil recovery(EOR) of overseas sandstone oilfields after high speed development, water and gas injection to improve oil recovery in overseas carbonate oil and gas reservoirs, economic and effective development of overseas unconventional oil and gas reservoirs, efficient development of marine deep-water oil and gas reservoirs. The following goals are expected to be achieved: keep the enhanced oil recovery (EOR) technology for high water-cut sandstone oilfield at international advanced level, and make the development technology for carbonate oil and gas reservoirs reach the international advanced level, and the development technologies for unconventional and marine deep-water oil and gas reservoirs catch up the level of international leading oil companies quickly.
  • Effects of pore structure on surfactant/polymer flooding-based enhanced oil recovery in conglomerate reservoirs
    LIU Zheyu, LI Yiqiang, LENG Runxi, LIU Zhenping, CHEN Xin, HEJAZI Hossein
    Petroleum Exploration and Development, 2020, 47(1): 129-139. https://doi.org/10.11698/PED.2020.01.12
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    To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer (SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher; the SP flooding can enhance the producing degree of oil in 1-3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations.
  • Formation permeability evaluation and productivity prediction based on mobility from pressure measurement while drilling
    SHI Xinlei, CUI Yunjiang, XU Wankun, ZHANG Jiansheng, GUAN Yeqin
    Petroleum Exploration and Development, 2020, 47(1): 140-147. https://doi.org/10.11698/PED.2020.01.13
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    Based on the measurement mechanism of mobility in pressure measurement while drilling, through analyzing a large number of mobility data, it is found that under the condition of water-based mud drilling, the product of mobility from pressure measurement while drilling and the viscosity of mud filtrate is infinitely close to the water phase permeability under the residual oil in relative permeability experiment. Based on this, a method converting the mobility from pressure measurement while drilling to core permeability is proposed, and the permeability based on Timur formula has been established. Application of this method in Penglai 19-9 oilfield of Bohai Sea shows: (1) Compared with the permeability calculated by the model of adjacent oilfields, the permeability calculated by this model is more consistent with the permeability calculated by core analysis. (2) Based on the new model, the correlation between the calculated mobility of well logging and the actual drilling specific productivity index bas been established. Compared with the relationship established by using the permeability model of an adjacent oilfield, the correlation of the new model is better. (3) Productivity of four directional wells was predicted, and the prediction results are in good agreement with the actual production after drilling.
  • Harmony search optimization applied to reservoir engineering assisted history matching
    SHAMS Mohamed, EL-BANBI Ahmed, SAYYOUH Helmy
    Petroleum Exploration and Development, 2020, 47(1): 148-154. https://doi.org/10.11698/PED.2020.01.14
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    Based on the analysis of characteristics and advantages of HSO (harmony search optimization) algorithm, HSO was used in reservoir engineering assisted history matching of Kareem reservoir in Amal field in the Gulf of Suez, Egypt. HSO algorithm has the following advantages: (1) The good balance between exploration and exploitation techniques during searching for optimal solutions makes the HSO algorithm robust and efficient. (2) The diversity of generated solutions is more effectively controlled by two components, making it suitable for highly non-linear problems in reservoir engineering history matching. (3) The integration between the three components (harmony memory values, pitch adjusting and randomization) of the HSO helps in finding unbiased solutions. (4) The implementation process of the HSO algorithm is much easier. The HSO algorithm and two other commonly used algorithms (genetic and particle swarm optimization algorithms) were used in three reservoir engineering history match questions of different complex degrees, which are two material balance history matches of different scales and one reservoir history matching. The results were compared, which proves the superiority and validity of HSO. The results of Kareem reservoir history matching show that using the HSO algorithm as the optimization method in the assisted history matching workflow improves the simulation quality and saves solution time significantly.
    • PETROLEUM ENGINEERING
  • Technical status and development direction of workover operation of PetroChina
    LEI Qun, LI Yiliang, LI Tao, LI Hui, GUAN Baoshan, BI Guoqiang, WANG Jialu, WENG Dingwei, HUANG Shouzhi, HAN Weiye
    Petroleum Exploration and Development, 2020, 47(1): 155-162. https://doi.org/10.11698/PED.2020.01.15
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    Through a comprehensive review of the development status of workover technology of PetroChina Company Limited (PetroChina), this paper presents the connotation of workover operation under the background of the new era, the latest progress of workover operation in the respects of equipment, tools, technology and the construction of information and standardization. The gaps between PetroChina and foreign counterpart in workover technology are as follows: the level of automation and intellectualization of tools and equipment is relatively low, the snubbing operation in gas wells characterized by HT/HP and high H2S is lagged behind; water plugging in the long horizontal wellbore needs to be further developed, coiled tubing and its relevant equipment for ultra-deep well operation has to be optimized; informationization, standardization and big data application of workover operation need to be started. Based on this as well as the development status of workover technology in China and the technical difficulties faced in the future, eight suggestions for future development are put forward: (1) strengthen the dynamic understanding of reservoir and improve the pertinence of workover schemes; (2) develop the general overhaul technology in a systematical way to tackle issues of seriously problematic wells; (3) put more efforts into the research of horizontal well workover operation and develop relevant technology for long horizontal section operation; (4) improve the snubbing technology and extend its applications; (5) expand the capacity of coiled tubing operation and improve the level of special operations; (6) develop automatic workover technology into the field of artificial intelligence; (7) promote clean operation in an all-round way and build green oil and gas fields; (8) perfect the informationization construction to realize the sharing of workover resources.
  • A numerical method for simulating planar 3D multi-fracture propagation in multi-stage fracturing of horizontal wells
    CHEN Ming, ZHANG Shicheng, XU Yun, MA Xinfang, ZOU Yushi
    Petroleum Exploration and Development, 2020, 47(1): 163-174. https://doi.org/10.11698/PED.2020.01.16
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    To resolve the issue of design for multi-stage and multi-cluster fracturing in multi-zone reservoirs, a new efficient algorithm for the planar 3D multi-fracture propagation model was proposed. The model considers fluid flow in the wellbore-perforation-fracture system and fluid leak-off into the rock matrix, and uses a 3D boundary integral equation to describe the solid deformation. The solid-fluid coupling equation is solved by an explicit integration algorithm, and the fracture front is determined by the uniform tip asymptotic solutions and shortest path algorithm. The accuracy of the algorithm is verified by the analytical solution of radial fracture, results of implicit level set algorithm and results of organic glass fracturing experiment. Compared with the implicit level set algorithm (ILSA), the new algorithm is much higher in computation speed. The numerical case study is conducted based on a horizontal well in shale gas formation of Zhejiang oilfield. The impact of stress heterogeneity among multiple clusters and perforation number distribution on multi-fracture growth and fluid distribution among multiple fractures are analyzed by numerical simulation. The results show that reducing perforation number in each cluster can counteract the effect of stress contrast among perforation clusters. Adjusting perforation number in each cluster can promote uniform flux among clusters, and the perforation number difference should better be 1-2 among clusters. Increasing perforation number in the cluster with high in situ stress is conducive to uniform fluid partitioning. However, uniform fluid partitioning is not equivalent to uniform fracture geometry. The fracture geometry is controlled by the stress interference and horizontal principal stress profile jointly.
  • A hydraulic fracture height mathematical model considering the influence of plastic region at fracture tip
    LI Yuwei, LONG Min, TANG Jizhou, CHEN Mian, FU Xiaofei
    Petroleum Exploration and Development, 2020, 47(1): 175-185. https://doi.org/10.11698/PED.2020.01.17
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    To predict fracture height in hydraulic fracturing, we developed and solved a hydraulic fracture height mathematical model aiming at high stress and multi-layered complex formations based on studying the effect of plastic region generated by stress concentration at fracture tip on the growth of fracture height. Moreover, we compared the results from this model with results from two other fracture height prediction models (MFEH, FracPro) to verify the accuracy of the model. Sensitivity analysis by case computation of the model shows that the hydraulic fracture growth in ladder pattern, and the larger the fracture height, the more obvious the ladder growth pattern is. Fracture height growth is mainly influenced by the in-situ stresses. Fracture toughness of rock can prohibit the growth of fracture height to some extent. Moreover, the increase of fracturing fluid density can facilitate the propagation of the lower fracture tip.
  • A new calculation approach of wellbore separation factor based on the relative position of adjacent wells
    HONG Difeng, TANG Xueping, GAO Wenkai, MAO Weimin, WANG Peng, LIU Ke
    Petroleum Exploration and Development, 2020, 47(1): 186-192. https://doi.org/10.11698/PED.2020.01.18
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    As the current calculation methods for wellbore separation factor have some deficiencies, a new calculation approach for wellbore separation factor based on the relative position of adjacent wellbores, named as relative position method for short, was proposed and analyzed. Based on the trajectory error ellipsoid model of single wellbore, the error ellipsoids model of adjacent wellbore was derived considering the correlation of trajectory errors between adjacent wells. Furthermore, the calculation formula of the separation factor based on relative position of adjacent wellbore was derived and solved with the conjugate gradient algorithm. Case study shows that the new approach is more precise and higher in applicability than the ellipsoid scalar method and the minimum distance method, it can evaluate the state of well collision more reasonably. By doing batch calculation with the new method and following the criterion of well collision avoidance, the permissible ranges of key parameters in the well design can be worked out quickly. This method has good application in the design of cluster wells and directional wells.
    • NEW ENERGY AND EMERGING FIELD
  • Hydrocarbon generation and storage mechanisms of deep-water shelf shales of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Sichuan Basin, China
    GUO Xusheng, LI Yuping, BORJIGEN Tenger, WANG Qiang, YUAN Tao, SHEN Baojian, MA Zhongliang, WEI Fubin
    Petroleum Exploration and Development, 2020, 47(1): 193-201. https://doi.org/10.11698/PED.2020.01.19
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    As the hydrocarbon generation and storage mechanisms of high quality shales of Upper Ordovician Wufeng Formation- Lower Silurian Longmaxi Formation remain unclear, based on geological conditions and experimental modelling of shale gas formation, the shale gas generation and accumulation mechanisms as well as their coupling relationships of deep water shelf shales in Wufeng-Longmaxi Formation of Sichuan Basin were analyzed from petrology, mineralogy, and geochemistry. The high quality shales of Wufeng-Longmaxi Formation in Sichuan Basin are characterized by high thermal evolution, high hydrocarbon generation intensity, good material base, and good roof and floor conditions; the high quality deep-water shelf shale not only has high biogenic silicon content and organic carbon content, but also high porosity coupling. It is concluded through the study that: (1) The shales had good preservation conditions and high retainment of crude oil in the early times, and the shale gas was mainly from cracking of crude oil. (2) The biogenic silicon (opal A) turned into crystal quartz in early times of burial diagenesis, lots of micro-size intergranular pores were produced in the same time; moreover, the biogenic silicon frame had high resistance to compaction, thus it provided the conditions not only for oil charge in the early stage, but also for formation and preservation of nanometer cellular-like pores, and was the key factor enabling the preservation of organic pores. (3) The Wufeng-Longmaxi Formation high quality shale had high brittleness, strong homogeneity, siliceous intergranular micro-pores and nanometer organic pores, which were conducive to the formation of complicated fissure network connecting the siliceous intergranular nano-pores, and thus high and stable production of shale gas.
  • Response laws of rock electrical property and saturation evaluation method of tight sandstone
    LI Xia, LI Chaoliu, LI Bo, LIU Xuefeng, YUAN Chao
    Petroleum Exploration and Development, 2020, 47(1): 202-212. https://doi.org/10.11698/PED.2020.01.20
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    To solve the problem that the law of rock electrical response under low and medium water saturation in tight sandstone reservoirs is not clear, an experimental method of high-speed centrifugal displacement rock electricity and nuclear magnetic resonance T2 spectrometry under different water saturation was proposed, which can drive the tight sandstone cores with the permeability less than 0.1×10-3 μm2, and provide a reliable experimental means for the study of tight sandstone electrical property. By carrying out supporting experiments such as high-resolution CT scan, MAPS and Qemscan, a multi-mineral component fine three-dimensional digital core based on multi-source information fusion was constructed. The finite element numerical simulation method was used to obtain the electrical response of tight sandstone core with low water saturation which cannot be obtained in laboratory conditions. By combining experiment and numerical simulation, the electrical response laws have been clear of tight sandstone with complex pore structure, and the saturation evaluation method of variable rock electrical parameters based on pore structure has been developed. The processing of logging data of multiple wells in tight sandstone reservoir of Chang 7 Member in the Ordos Basin shows that this method can obtain more accurate oil saturation, and provides a new idea and method for fine logging evaluation of tight sandstone reservoir.
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