23 October 2021, Volume 48 Issue 5
    

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    PETROLEUM EXPLORATION
  • Biostratigraphy and reservoir characteristics of the Ordovician Wufeng-Silurian Longmaxi shale in the Sichuan Basin and surrounding areas, China
    WANG Hongyan, SHI Zhensheng, SUN Shasha
    Petroleum Exploration and Development, 2021, 48(5): 879-890. https://doi.org/10.11698/PED.2021.05.01
    Abstract ( ) Download PDF ( ) Rich HTML   Knowledge map Save
    Through graptolite identification in profiles, graptolite zone division, contour map compilation, and analysis of mineral composition, TOC content, lamina distribution features of shale samples, the biostratigraphic and reservoir characteristics of Ordovician Wufeng Formation-Silurian Longmaxi Formation in the Sichuan Basin and surrounding areas are sorted out. There are 4 graptolite zones (WF1 to WF4) in Wufeng Formation and 9 (LM1 to LM9) in Longmaxi Formation, and the different graptolite zones can be calibrated by lithology and electrical property. The shale layers of these graptolite zones have two depocenters in the southwest and northeast, and differ somewhat in mineral composition, TOC, and lamina types. Among them, the graptolite zones of lower WF2 and WF4 are organic matter lean massive hybrid shale, the upper part of WF1-WF2 and WF3 have horizontal bedding hybrid shale with organic matter, the LM1-LM4 mainly consist of organic-rich siliceous shale with horizontal bedding, and the LM5-LM9 graptolite zones consist of organic-lean hybrid shale with horizontal bedding. The mineral composition, TOC and lamina types of shale depend on the paleo-climate, paleo-water oxidation-reduction conditions, and paleo-sedimentation rate during its deposition. Deposited in oxygen-rich warm water, the lower parts of WF1 and WF2 graptolite zones have massive bedding, lower TOC and silicon content. Deposited in cooler and oxygen rich water, the WF4 has massive bedding, high calcium content and low TOC. Deposited in anoxic water at low rate, the upper part of WF2, WF3, and LM1-LM4 are composed of organic rich siliceous shale with horizontal bedding and high proportion of silt laminae. Deposited in oxygen rich water at a high rate, the graptolite zones LM5-LM9 have low contents of organic matter and silicon and high proportions of silt lamina.
  • Challenges and countermeasures of log evaluation in unconventional petroleum exploration
    LIU Guoqiang
    Petroleum Exploration and Development, 2021, 48(5): 891-902. https://doi.org/10.11698/PED.2021.05.02
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    To promote adaptation of logging evaluation technologies to the development trend of unconventional oil and gas exploration and development era in China, the current situation and challenges of logging evaluation technologies in China are analyzed systematically. Based on the concept of that demand drives technology development, and referring to the international leading technologies, development strategy of logging evaluation technology in China has been put forward. (1) Deepen petrophysics study: mobile 2D NMR laboratory analysis technology for full diameter core should be developed, characteristic charts and evaluation standards of different fluid properties, different pore structures and different core exposure times should be established based on longitudinal and traverse relaxation spectra; in-depth digital rock experiment and mathematical and physical simulation research should be carried out to create innovative logging evaluation methods; acoustic and electrical anisotropy experimental analysis technology should be developed, and corresponding logging evaluation methods be innovated. (2) Strengthen target processing of logging data: precise inversion processing technology and sensitive information extraction technology of 2D NMR logging should be developed to finely describe the micro-pore distribution in tight reservoir and accurately distinguish movable oil, bound oil, and bound water etc. The processing method of 3D ultra-distance detection acoustic logging should be researched. (3) Develop special logging interpretation and evaluation methods: first, mathematical model for quantitatively describing the saturation distribution law of unconventional oil and gas near source and in source should be created; second, evaluation methods and standards of shale oil and deep shale gas “sweet-spots” with mobile oil content and gas content as key parameter separately should be researched vigorously; third, calculation methods of pore pressure under two high-pressure genetic mechanisms, under-compaction and hydrocarbon charging, should be improved; fourth, evaluation method of formation fracability considering the reservoir geologic and engineering quality, and optimization method of horizontal well fracturing stage and cluster based on comprehensive evaluation of stress barrier and lithologic barrier should be worked out.
  • Heterogeneity and influencing factors of marine gravity flow tight sandstone under abnormally high pressure: A case study from the Miocene Huangliu Formation reservoirs in LD10 area, Yinggehai Basin, South China Sea
    FAN Caiwei, CAO Jiangjun, LUO Jinglan, LI Shanshan, WU Shijiu, DAI Long, HOU Jingxian, MAO Qianru
    Petroleum Exploration and Development, 2021, 48(5): 903-915. https://doi.org/10.11698/PED.2021.05.03
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    The characteristics of reservoir heterogeneity of the marine gravity flow tight sandstone from the Miocene Huangliu Formation under abnormally high pressure setting at LD10 area in Yinggehai Basin are studied, and the influencing factors on reservoir heterogeneity are discussed, based on modular formation dynamics tester, thin sections, XRD analysis of clay minerals, scanning electron microscopy, measurement of pore throat image, porosity and permeability, and high pressure Hg injection, as well as the stimulation of burial thermal history. The aim is to elucidate characteristics of the heterogeneity and the evolution process of heterogeneity of the reservoir, and predict the favorable reservoirs distribution. (1) The heterogeneity of the reservoir is mainly controlled by the cement heterogeneity, pore throat heterogeneity, quality of the reservoir heterogeneity, and the diagenesis under an abnormally high pressure setting. (2) The differences in pore-throat structure caused by diagenetic evolution affected the intergranular material heterogeneity and the pore throat heterogeneity, and finally controlled the heterogeneity of reservoir quality. (3) Compared with the reservoir under normal pressure, abnormally high pressure restrains strength of the compaction and cementation and enhances the dissolution of the reservoir to some extent, and abnormally high pressure thus weakening the heterogeneity of the reservoir to a certain degree. The favorable reservoirs are mainly distributed in the gravity flow sand body under the strong overpressure zone in the middle and lower part of Huangliu Formation.
  • Microscopic pore-fracture configuration and gas-filled mechanism of shale reservoirs in the western Chongqing area, Sichuan Basin, China
    FU Yonghong, JIANG Yuqiang, DONG Dazhong, HU Qinhong, LEI Zhi’an, PENG Hao, GU Yifan, MA Shaoguang, WANG Zimeng, YIN Xingping, WANG Zhanlei
    Petroleum Exploration and Development, 2021, 48(5): 916-927. https://doi.org/10.11698/PED.2021.05.04
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    Taking the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation shale reservoirs in western Chongqing area as the study target, the argon ion polishing scanning electron microscope and nuclear magnetic resonance (NMR) experiments of different saturated wetting media were carried out. Based on the image processing technology and the results of gas desorption, the pore-fracture configuration of the shale reservoirs and its influence on gas-filled mechanism were analyzed. (1) The reservoir space includes organic pores, inorganic pores and micro-fractures and there are obvious differences between wells in the development characteristics of micro-fractures; the organic pores adjacent to the micro-fractures are poorly developed, while the inorganic pores are well preserved. (2) According to the type, development degree and contact relationship of organic pore and micro-fracture, the pore-fracture configuration of the shale reservoir is divided into four types. (3) Based on the differences in NMR T2 spectra of shale samples saturated with oil and water, an evaluation parameter of pore-fracture configuration was constructed and calculated. The smaller the parameter, the better the pore-fracture configuration is. (4) The shale reservoir with good pore-fracture configuration has well-developed organic pores, high porosity, high permeability and high gas content, while the shale reservoir with poor pore-fracture configuration has micro-fractures developed, which improves the natural gas conductivity and leads to low porosity and gas content of the reservoir. (5) Based on pore-fracture configuration, from the perspective of organic matter generating hydrocarbon, micro-fracture providing migration channel, three types of micro gas-filled models of shale gas were established.
  • Geochemical significances of 8,14-secohopanes in marine crude oils from the Tazhong area in the Tarim Basin, NW China
    BAO Jianping, YANG Qian, ZHU Cuishan
    Petroleum Exploration and Development, 2021, 48(5): 928-938. https://doi.org/10.11698/PED.2021.05.05
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    8,14-secohopanes in the marine oils from the Tazhong area in the Tarim Basin are detected by gas chromatography-mass spectrometry (GC-MS) and GC-MS-MS, and their distributions and compositions are compared in order to study their potential significances in oil-source correlation. C35+ long chain hopane series and three series of extended 8,14-secohopanes can be detected in two kinds of end-member oils in the Tazhong area in the Tarim Basin, and they are different in distribution, suggesting that they may have some special geochemical significances. The presence of 8,14-secohopanes in two kinds of end-member oils in the Tarim Basin suggest that these biomarkers are primary, and not related to biodegradation. The relative abundance of 8,14-secohopanes in the type-A oil is much less than that in the type-B oil, and the 8,14-secohopanes content in end-member oils is much less than that in the corresponding mixed oils. Based on the relative contents of 8,14-secohopanes and the compositions of common steranes and triterpanes, it is very effective to distinguish different crude oils from the Tazhong area. The great difference in the relative abundance of 8,14-secohopanes between the type-A oil and type-B oil suggests that their formation may require some specific geological- geochemical conditions.
  • Limits and grading evaluation criteria of tight oil reservoirs in typical continental basins of China
    ZHOU Nengwu, LU Shuangfang, WANG Min, HUANG Wenbiao, XIAO Dianshi, JIAO Chenxue, WANG Jingming, TIAN Weichao, ZHOU Lei, CHEN Fangwen, LIU Wei, WANG Zhixuan
    Petroleum Exploration and Development, 2021, 48(5): 939-949. https://doi.org/10.11698/PED.2021.05.06
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    Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China, such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin, sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin, the theoretical lower limit, oil accumulation lower limit, effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method, oil bearing occurrence method, oil testing productivity method and mechanical balance method, respectively. Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs, determine the grading criterion of tight reservoirs, and analyze its correlation with the limit of reservoir formation. The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties, the boundary of class II and class III tight reservoirs corresponds to the lower limit of effective flow, the boundary of class III and class IV tight reservoirs corresponds to the lower limit of reservoir forming, and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir. Finally, the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir, and class I and class II tight reservoirs are the favorable sections for high production of tight oil.
  • Magmatic hydrothermal fluid genesis of zeolite in the Paleogene Kongdian Formation of Zaoyuan oilfield, Bohai Bay Basin, China
    HAN Guomeng, WANG Li, XIAO Dunqing, LOU Da, XU Muyue, ZHAO Yonggang, PEI Yanlu, GUO Xiaowen, TENG Jiancheng, HAN Yuanjia
    Petroleum Exploration and Development, 2021, 48(5): 950-961. https://doi.org/10.11698/PED.2021.05.07
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    Electronic probe, fluid inclusion homogenization temperature, Raman spectroscopy and laser ablation inductively coupled plasma mass spectrometry were utilized to identify the hydrothermal fluid-rock interactions in the second member of the Paleogene Kongdian Formation of Zaoyuan oilfield in Bohai Bay Basin (Kong 2 Member for short) of Well Z56 to find out the relationship between zeolite and hydrothermal fluid. The experimental results show that: (1) Pyrobitumen coexists with hydrothermal fluid characteristic minerals such as chlorite, barite, chalcopyrite, pyrite, natrolite and analcime in mudstone fractures. (2) The temperatures calculated from laser Raman spectrum of pyrobitumen, from the chlorite geothermometer and from measured homogenization temperature of natrolite inclusions are 324-354 ℃, 124-166 ℃ and 89-196 ℃, respectively; although vary widely, all the temperatures are obviously higher than the normal geothermal temperature. (3) The positive Eu anomaly of chlorite and barite, and the similar distribution pattern in rare earth elements between natrolite and basalt indicate they are from magmatic hydrothermal fluid. Moreover, drilling data shows that the Kong 2 Member in Well Z56 has several sets of basalt interlayers, suggesting there was geologic base of magmatic hydrothermal fluid activity. The magmatic hydrothermal fluid-rock interaction may be one of the reasons for the abnormal enrichment of zeolite in Kong 2 Member of the Cangdong Sag.
  • Differential structure of Ordovician karst zone and hydrocarbon enrichment in paleogeomorphic units in Tahe area, Tarim Basin, NW China
    ZHANG San, JIN Qiang, HU Mingyi, HAN Qichao, SUN Jianfang, CHENG Fuqi, ZHANG Xudong
    Petroleum Exploration and Development, 2021, 48(5): 962-973. https://doi.org/10.11698/PED.2021.05.08
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    Based on a large number of drilling, logging, seismic and production data, the differential structures of karst zone and hydrocarbon distribution in different paleogeomorphic units of the Tahe area, Tarim Basin, are discussed by analyzing the karst drainages and flowing channels. The karst paleogeomorphy of Ordovician in Tahe area is composed of watershed, karst valley and karst basin. The watershed has epikarst zone of 57.8 m thick on average and vadose karst zone of 115.2 m thick on average with dense faults, fractures and medium-small fracture-caves, and 76.5% of wells in this area have cumulative production of more than 5×104 t per well. The karst valleys have epikarst zone, vadose karst zone and runoff karst zone, with an average thickness of 14.6, 26.4 and 132.6 m respectively. In the runoff karst zone, the caves of subsurface river are mostly filled by fine sediment, with a filling rate up to 86.8%, and 84.9% of wells in this area have cumulative production of less than 2×104 t per well. The karst basin has no karst zone, but only fault-karst reservoirs in local fault zones, which are up to 600 m thick and closely developed within 1 km around faults. Different karst landforms have different water flowing pattern, forming different karst zone structures and resulting in differential distribution of oil and gas. The watershed has been on the direction of oil and gas migration, so medium-small sized connected fracture-caves in this area have high filling degree of oil and gas, and most wells in this area have high production. Most caves in subsurface river are filled due to strong sedimentation and transportation of the river, so the subsurface river sediment has low hydrocarbon abundance and more low production oil wells. The faults linking source rock are not only the water channels but also the oil-gas migration pathways, where the karst fractures and caves provide huge reservoir space for oil and gas accumulation.
  • Sequence stratigraphy and lithofacies paleogeographic evolution of Katian Stage - Aeronian Stage in southern Sichuan Basin, SW China
    ZHU Yiqing, CHEN Gengsheng, LIU Yong, SHI Xuewen, WU Wei, LUO Chao, YANG Xue, YANG Yuran, ZOU Yuanhong
    Petroleum Exploration and Development, 2021, 48(5): 974-985. https://doi.org/10.11698/PED.2021.05.09
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    Based on the lithologies, sedimentary structures, graptolite zones, inorganic geochemical characteristics, electrical data of 110 shale gas wells in southern Sichuan Basin and the mineral quantitative analysis technology of scanning electron microscope, the stratigraphic sequences of Upper Ordovician Katian Stage-Himantian Stage-Silurian Rhuddanian Stage-Aeronian Stage are divided, the sedimentary characteristics and fourth-order sequence evolution are analyzed. The target layer can be divided into two sequences, SQ1 and SQ2. According to Ordovician-Silurian sedimentary background, target layer GR and w(U)/w(Th), 5 maximum flooding surfaces and 12 system tracts are identified. According to system tracts and their combinations, eight fourth-order sequences are identified, namely, Pss1-Pss8 from old to new. The development period and scale of dominant shale facies from Katian stage to Aeronian stage in southern Sichuan are restored. The best-quality dolomite/calcite-bearing siliceous shale facies, siliceous shale facies, clay-bearing siliceous shale facies and feldspar-bearing siliceous shale facies mainly occur in Pss3-Pss5 of Weiyuan, Western Chongqing and Luzhou, Pss6 of Western Changning-Northern Luzhou- Central Western Chongqing and Pss3-Pss4 of Changning. The siliceous clay shale facies second in quality mainly occurs in Pss6 of Southern Luzhou-Changning area (excluding Western Changning area), Pss7 of Eastern Weiyuan- Northern Western Chongqing- Southern Luzhou and Pss8 of Northern Luzhou-Weiyuan-Western Chongqing. The fourth-order sequence evolution model of Katian stage-Aeronian stage in southern Sichuan is established. During the depositional period of Pss1-Pss8, the sea level had six regressions and five transgressions, and the first transgression SQ2-MFS1 after glaciation was the largest flooding surface.
    • OIL AND GAS FIELD DEVELOPMENT
  • Using cyclic alternating water injection to enhance oil recovery for carbonate reservoirs developed by linear horizontal well pattern
    LI Yong, ZHAO Limin, WANG Shu, SUN Liang, ZHANG Wenqi, YANG Yang, HU Dandan, CHEN Yihang
    Petroleum Exploration and Development, 2021, 48(5): 986-994. https://doi.org/10.11698/PED.2021.05.10
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    In view of high water cut and low oil recovery caused by the unidirectional flow in linear pattern of horizontal wells for the carbonate reservoirs in the Middle East, this paper provides a novel approach to improve oil recovery by converting linear water injection to cyclic alternating water injection patterns including cyclic alternating apparent inverted seven-spot pattern, cyclic alternating apparent five-spot pattern and cyclic alternating production-injection pattern. The main advantage of using this strategy is that the swept efficiency is improved by changing injection-production streamlines and displacement directions, which means two different direction displacement for the same region during a complete cycle. This technology is effective in increasing the swept efficiency and tapping the remaining oil, thus resulting in higher oil recovery. Field application with three new patterns in a carbonate reservoir in the Middle East is successful. By optimizing injection and production parameters based on the cyclic alternating well pattern, the test well group had a maximum increase of daily oil production per well of 23.84 m3 and maximum water cut drop of 18%. By further optimizing the distance (keep a long distance) between the heels of injectors and producers, the waterflooding performance could be better with water cut decreasing and oil production increasing.
  • An improved oil recovery prediction method for volatile oil reservoirs
    LU Kefeng, SU Chang, CHENG Chaoyi
    Petroleum Exploration and Development, 2021, 48(5): 995-1003. https://doi.org/10.11698/PED.2021.05.11
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    To describe the complex phase transformation in the process of depletion exploitation of volatile oil reservoir, four fluid phases are defined, and production and remaining volume of these phases are calculated based on the principle of surface volume balance, then the recovery prediction method of volatile oil reservoir considering the influence of condensate content in released solution gas and the correction method of multiple degassing experiments data are established. Taking three typical kinds of crude oil (black oil, medium-weak volatile oil, strong volatile oil) as examples, the new improved method is used to simulate constant volume depletion experiments based on the corrected data of multiple degassing experiment to verify the reliability of the modified method. By using “experimental data and traditional method”, “corrected data and traditional method” and “corrected data and modified method”, recovery factors of these three typical kinds of oil are calculated respectively. The source of parameters and calculation methods have little effect on the recovery of typical black oil. However, with the increase of crude oil volatility, the oil recovery will be seriously underestimated by using experimental data or traditional method. The combination of “corrected data and modified method” considers the influence of condensate in gas phase in both experimental parameters and calculation method, and has good applicability to typical black oil and volatile oil. The strong shrinkage of volatile oil makes more “liquid oil” convert to “gaseous oil”, so volatile oil reservoir can reach very high oil recovery by depletion drive.
  • Experimental research on imbibition mechanisms of fractured reservoirs by microfluidic chips
    YU Fuwei, GAO Zhendong, ZHU Wenhao, WANG Chuan, LIU Fan, XU Fei, JIANG Hanqiao, LI Junjian
    Petroleum Exploration and Development, 2021, 48(5): 1004-1013. https://doi.org/10.11698/PED.2021.05.12
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    To solve the problems of long experiment period and difficult measurement in core imbibition experiments, fracture-matrix microfluidic chips of different sizes, boundary conditions and wettability regulated by surface property modification were designed to research the imbibition mechanisms of oil-water, oil-surfactant solution and oil-Winsor Ⅲ type surfactant solution. In the oil-water, and oil-wettability modification system imbibition process, oil was replaced from the matrix through Haines jump, the capillary back pressure was the main resistance blocking the flow of oil, the reduction of interfacial tension caused the weakening of Haines jump, reduction of oil discharge rate, and increase of oil recovery. The imbibition of oil-water or oil-surfactant solution with low interfacial tension was a counter- current imbibition process dominated by capillary force, in which all boundaries had similar contribution to imbibition, and the recovery data obtained from this experiment fit well with the classic imbibition scaling equation. The imbibition of oil and Winsor III type surfactant solution was a co-current imbibition process dominated by gravity under super-low interfacial tension, and is essentially the formation and re-balance of neutral microemulsion. The imbibition dynamics obtained from this experiment fit well with the modified imbibition scaling equation.
  • CO2/CaO-responsive behavior and application potential of amine emulsion
    REN Yanjun, LU Yanyan, JIANG Guancheng, ZHOU Wenjing, WU Liansong, YAO Rugang, XIE Shuixiang
    Petroleum Exploration and Development, 2021, 48(5): 1014-1022. https://doi.org/10.11698/PED.2021.05.13
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    Green and low cost CO2 and CaO were used to stimulate amine emulsions to reveal the responsive behavior of amine emulsions. On this basis, oil-based drilling fluids responsive to CO2 and CaO were formulated and their properties were evaluated. The results showed that the amine emulsions inversed from water-in-oil state to oil-in-water state readily and their rheological behavior underwent transitions of decreasing, rising again and decreasing again via induction by CO2. These CO2 responsive behaviors could be reversed by CaO. Oil-based drilling fluids prepared based on the amine emulsions with oil-water volume ratios of 50:50 to 70:30, densities of 1.4-2.0 g/cm3 had good rheological and filtration properties at 160 ℃; and be readily cleaned up using CO2 bubbling. The useless solid phase with low density could be removed efficiently via reducing the viscosity of emulsion by CO2 and the residual liquid phase could be restored to the original state by CaO and reused to prepare drilling fluid. The mechanisms analysis indicated that CO2/CaO induced the reversible conversion between amine emulsifiers and their salts, which enabled the reversible regulation of both the hydrophilic-lipophilic balance of amine emulsifiers and the emulsion particles’ size and finally caused the controllable-reversion of the form and rheology of amine emulsion.
  • Combined stochastic and discrete simulation to optimise the economics of mixed single-horizontal and multilateral well offshore oil developments
    ALMEDALLAH Mohammed, ALTAHEINI Suleiman Khalid, CLARK Stuart, WALSH Stuart
    Petroleum Exploration and Development, 2021, 48(5): 1023-1034. https://doi.org/10.11698/PED.2021.05.14
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    Multilateral wells promise cost savings to oil and fields as they have the potential to reduce overall drilling distances and minimize the number of slots required for the surface facility managing the well. However, drilling a multilateral well does not always increase the flow rate when compared to two single-horizontal wells due to competition in production inside the mother-bore. Here, a holistic approach is proposed to find the optimum balance between single and multilateral wells in an offshore oil development. In so doing, the integrated approach finds the highest Net Present Value (NPV) configuration of the field considering drilling, subsurface, production and financial analysis. The model employs stochastic perturbation and Markov Chain Monte-Carlo methods to solve the global maximising-NPV problem. In addition, a combination of Mixed-Integer Linear Programming (MILP), an improved Dijkstra algorithm and a Levenberg-Marquardt optimiser is proposed to solve the rate allocation problem. With the outcome from this analysis, the model suggests the optimum development including number of multilateral and single horizontal wells that would result in the highest NPV. The results demonstrate the potential for modelling to find the optimal use of petroleum facilities and to assist with planning and decision making.
    • PETROLEUM ENGINEERING
  • Progress and development directions of shale oil reservoir stimulation technology of China National Petroleum Corporation
    LEI Qun, WENG Dingwei, XIONG Shengchun, LIU Hanbin, GUAN Baoshan, DENG Qiang, YAN Xuemei, LIANG Hongbo, MA Zeyuan
    Petroleum Exploration and Development, 2021, 48(5): 1035-1042. https://doi.org/10.11698/PED.2021.05.15
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    By reviewing the development history of shale oil reservoir stimulation technology of PetroChina Company Limited (PetroChina), we have systematically summarized the main progress of shale oil reservoir stimulation technology of CNPC in five aspects: reservoir stimulation mechanism, fracture-controlled fracturing, geological-engineering integrated reservoir stimulation design platform, low-cost materials, and large well-pad three-dimensional development mode. It is made clear that the major stimulation technology for shale oil reservoir is the high density multi-cluster and fracture-controlled staged fracturing aiming to increase fracture-controlled reserves, lower operation costs and increase economic benefits. Based on comprehensive analysis of the challenges shale oil reservoir stimulation technology faces in three-dimensional development, stimulation parameter optimization for fracture-controlled fracturing, refracturing and low-cost stimulation technology, we proposed five development directions of the stimulation technology: (1) Strengthen the research on integration of geology and engineering to make full use of reservoir stimulation. (2) Deepen the study on fracture-controlled fracturing to improve reserves development degree. (3) Promote horizontal well three-dimensional development of shale oil to realize the production of multiple layers vertically. (4) Research refracturing technology of shale oil reservoir through horizontal well to efficiently tap the remaining reserves between fractures. (5) Develop low-cost stimulation supporting technology to help reduce the cost and increase economic benefit of oilfield development.
  • Method of suspender line trajectory design
    YU Fan, HUANG Genlu, HAN Zhiyong, NI Hongjian, LI Jing, LI Wei
    Petroleum Exploration and Development, 2021, 48(5): 1043-1052. https://doi.org/10.11698/PED.2021.05.16
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    Based on the mechanical model of an elastic rod, a new trajectory design method was established. The advantages of the suspender line trajectory in reducing drag and torsion were compared, and the main controlling factors of drag and torque and their influence rules were analyzed. Research shows that the suspender line trajectory reduces drag and torque more effectively than the conventional trajectory in a certain parameter interval and has more controllable parameters than that of the catenary trajectory. The main factors affecting the drag reduction and torque reduction of the suspender line trajectory include the friction coefficient, vertical distance, horizontal distance, and deviation angle at the initial point in the suspended section. The larger the friction coefficient and deviation angle, the less the drag reduction and torque reduction. The suspender line trajectory has the best drag reduction effect when the horizontal and vertical distances are more than 3000 m and the ratio is close to 1.5. The drag in sliding drilling can be reduced up to 60%, and the torque in rotary drilling can be reduced by a maximum of 40%. Therefore, the trajectory design of the suspender line has unique application prospects in deep extended-reach wells.
  • A new model for predicting the critical liquid-carrying velocity in inclined gas wells
    WANG Wujie, CUI Guomin, WEI Yaoqi, PAN Jie
    Petroleum Exploration and Development, 2021, 48(5): 1053-1060. https://doi.org/10.11698/PED.2021.05.17
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    Based on the assumption of gas-liquid stratified flow pattern in inclined gas wells, considering the influence of wettability and surface tension on the circumferential distribution of liquid film along the wellbore wall, the influence of the change of the gas-liquid interface configuration on the potential energy, kinetic energy and surface free energy of the two-phase system per unit length of the tube is investigated, and a new model for calculating the gas-liquid distribution at critical conditions is developed by using the principle of minimum energy. Considering the influence of the inclination angle, the calculation model of interfacial friction factor on the phase interface is established, and finally closed the governing equations. The interface shape is more vulnerable to wettability and surface tension at a low liquid holdup, resulting in a curved interface configuration. The interface is more curved when the smaller is the pipe diameter, or the smaller the liquid holdup, or the smaller the deviation angle, or the greater gas velocity, or the greater the gas density. The critical liquid-carrying velocity increases nonlinearly and then decreases with the increase of deviation angle. The inclination corresponding to the maximum critical liquid-carrying velocity increases with the increase of the diameter of the wellbore, and it is also affected by the fluid properties of the gas phase and liquid phase. The mean relative errors for critical liquid-carrying velocity and critical pressure gradient are 1.19% and 3.02%, respectively, and the misclassification rate is 2.38% in the field trial, implying the new model can provide a valid judgement on the liquid loading in inclined gas wells.
    • COMPREHENSIVE RESEARCH
  • Integrated construction technology for natural gas gravity drive and underground gas storage
    JIANG Tongwen, WANG Zhengmao, WANG Jinfang
    Petroleum Exploration and Development, 2021, 48(5): 1061-1068. https://doi.org/10.11698/PED.2021.05.18
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    Based on the mechanisms of gravity displacement, miscibility, viscosity reduction, and imbibition in natural gas flooding, an integrated reservoir construction technology of oil displacement and underground gas storage (UGS) is proposed. This paper systemically describes the technical connotation, site selection principle and optimization process of operation parameters of the gas storage, and advantages of this technology. By making full use of the gravity displacement, miscibility, viscosity reduction, and imbibition features of natural gas flooding, the natural gas can be injected into oil reservoir to enhance oil recovery and build strategic gas storage at the same time, realizing the win-win situation of oil production and natural gas peak shaving. Compared with the gas reservoir storage, the integrated construction technology of gas storage has two profit models: increasing crude oil production and gas storage transfer fee, so it has better economic benefit. At the same time, in this kind of gas storage, gas is injected at high pressure in the initial stage of its construction, gas is injected and produced in small volume in the initial operation stage, and then in large volume in the middle and late operation stage. In this way, the gas storage wouldn’t have drastic changes in stress periodically, overcoming the shortcomings of large stress variations of gas reservoir storage during injection-production cycle due to large gas injection and production volume. The keys of this technology are site selection and evaluation of oil reservoir, and optimization of gravity displacement, displacement pressure, and gas storage operation parameters, etc. The pilot test shows that the technology has achieved initial success, which is a new idea for the rapid development of UGS construction in China.
  • Characteristics and origin of continental marginal fault depressions under the background of preexisting subduction continental margin, northern South China Sea, China
    PANG Xiong, ZHENG Jinyun, MEI Lianfu, LIU Baojun, ZHANG Zhongtao, WU Zhe, Feng Xuan
    Petroleum Exploration and Development, 2021, 48(5): 1069-1080. https://doi.org/10.11698/PED.2021.05.19
    Abstract ( ) Download PDF ( ) Rich HTML   Knowledge map Save
    Based on the new seismic and drilling data and the recent related research results, this paper systematically analyzes the diversity and complexity of evolution process of crustal lithosphere structure and basin structure in the Pearl River Mouth Basin on the northern margin of the South China Sea. Three types of detachment faults of different structural levels exist: crust-mantle detachment, inter-crust detachment and upper crust detachment. It is considered that different types of extensional detachment control different subbasin structures. Many fault depressions controlled by upper crust detachment faults have been found in the Zhu I Depression located in the proximal zone. These detachment faults are usually reformed by magma emplacement or controlled by preexisting faults. Baiyun-Liwan Sag located in the hyperextension area shows different characteristics of internal structure. The Baiyun main sag with relative weak magmatism transformation is a wide-deep fault depression, which is controlled by crust-mantle detachment system. Extensive magmatism occurred in the eastern and southwest fault steps of the Baiyun Sag after Middle Eocene, and the crust ductile extensional deformation resulted in wide-shallow fault depression controlled by the upper crust detachment fault. Based on the classical lithosphere extensional breaking and basin tectonic evolution in the Atlantic margin, it is believed that the magmatic activities and pre-existing structures in the Mesozoic subduction continental margin background are important controlling factors for the diversified continental margin faulted structures in the northern South China Sea.
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