23 June 2021, Volume 48 Issue 3
    

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    PETROLEUM EXPLORATION
  • The mechanism of unconventional hydrocarbon formation: Hydrocarbon self-containment and intermolecular forces
    JIA Chengzao, PANG Xiongqi, SONG Yan
    Petroleum Exploration and Development, 2021, 48(3): 437-452. https://doi.org/10.11698/PED.2021.03.01
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    The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-containment of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-containment, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-containment of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.
  • An analysis of major scientific problems and research paths of Gulong shale oil in Daqing Oilfield, NE China
    SUN Longde, LIU He, HE Wenyuan, LI Guoxin, ZHANG Shuichang, ZHU Rukai, JIN Xu, MENG Siwei, JIANG Hang
    Petroleum Exploration and Development, 2021, 48(3): 453-463. https://doi.org/10.11698/PED.2021.03.02
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    Through analysis of the problems in the production of Gulong shale oil in the Songliao Basin and the scientific exploration of the preliminary basic research, the special characteristics of Gulong shale oil in terms of reservoir space, phase distribution, flow pattern and mineral evolution are proposed, and six basic scientific problems currently faced are concluded, including: (1) The source of organic matter, mechanism of hydrocarbon generation and expulsion, and key factors affecting shale oil abundance; (2) The types and structural characteristics of effective reservoir space and their contribution to porosity and permeability; (3) The genesis and evolution of minerals and their control on reservoir availability, sensitivity and compressibility; (4) The rock mechanical characteristics and fracture propagation law; (5) The shale oil products, phase change law and main control factors of adsorption and desorption conversion; (6) The shale oil-liquid solid-liquid gas interaction mechanism and enhanced oil recovery mechanism. Three key research suggestions are proposed for realizing the large-scale economic utilization of the Gulong shale oil: (1) Deepen research on the mechanism of oil and gas generation and discharge, storage and transportation, to guide the selection of geological sweet spots of shale oil; (2) Deepen research on the compressibility and fracture initiation mechanism to support the selection of engineering sweet spots and optimization of engineering design; (3) Deepen research on the fluid action mechanism under formation conditions, to guide the optimization of development schemes and the selection of technologies for enhancing oil recovery.
  • Differences in source kitchens for lacustrine in-source and out-of-source hydrocarbon accumulations
    ZHAO Wenzhi, ZHANG Bin, WANG Xiaomei, WU Songtao, ZHANG Shuichang, LIU Wei, WANG Kun, ZHAO Xia
    Petroleum Exploration and Development, 2021, 48(3): 464-475. https://doi.org/10.11698/PED.2021.03.03
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    Because of the differences of hydrocarbon accumulation between in-source and out-of-source oil pools, the demand for source kitchen is different. Based on the establishment of source-to-reservoir correlation in the known conventional accumulations, and the characteristics of shale oil source kitchens as well, this paper discusses the differences of source kitchens for the formation of both conventional and shale oils. The formation of conventional oil pools is a process of hydrocarbons enriching from disperse state under the action of buoyancy, which enables most of the oil pools to be formed outside the source kitchens. The source rock does not necessarily have high abundance of organic matter, but has to have high efficiency and enough amount of hydrocarbon expulsion. The TOC threshold of source rocks for conventional oil accumulations is 0.5%, with the best TOC window ranging from 1% to 3%. The oil pools formed inside the source kitchens, mainly shale oil, are the retention of oil and gas in the source rock and there is no large-scale hydrocarbon migration and enrichment process happened, which requires better quality and bigger scale of source rocks. The threshold of TOC for medium to high maturity of shale oil is 2%, with the best range falling in 3%-5%. Medium to low mature shale oil resource has a TOC threshold of 6%, and the higher the better in particular. The most favorable kerogen for both high and low-mature shale oils is oil-prone type of I-II1. Carrying out source rock quality and classification evaluation and looking for large-scale and high-quality source rock enrichment areas are a scientific issue that must be paid attention to when exploration activity changes from out-of-source regions to in-source kitchen areas. The purpose is to provide theoretical guidance for the upcoming shale oil enrichment area selection, economic discovery and objective evaluation of resource potential.
  • The dating and temperature measurement technologies for carbonate minerals and their application in hydrocarbon accumulation research in the paleo-uplift in central Sichuan Basin, SW China
    SHEN Anjiang, ZHAO Wenzhi, HU Anping, WANG Hui, LIANG Feng, WANG Yongsheng
    Petroleum Exploration and Development, 2021, 48(3): 476-487. https://doi.org/10.11698/PED.2021.03.04
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    A new method for reconstructing the geological history of hydrocarbon accumulation is developed, which are constrained by U-Pb isotope age and clumped isotope (Δ47) temperature of host minerals of hydrocarbon-bearing inclusions. For constraining the time and depth of hydrocarbon accumulation by the laser in-situ U-Pb isotope age and clumped isotope temperature, there are two key steps: (1) Investigating feature, abundance and distribution patterns of liquid and gaseous hydrocarbon inclusions with optical microscopes. (2) Dating laser in-situ U-Pb isotope age and measuring clumped isotope temperature of the host minerals of hydrocarbon inclusions. These technologies have been applied for studying the stages of hydrocarbon accumulation in the Sinian Dengying gas reservoir in the paleo-uplift of the central Sichuan Basin. By dating the U-Pb isotope age and measuring the temperature of clumped isotope (Δ47) of the host minerals of hydrocarbon inclusions in dolomite, three stages of hydrocarbon accumulation were identified: (1) Late Silurian: the first stage of oil accumulation at (416±23) Ma. (2) Late Permian to Early Triassic: the second stage of oil accumulation between (248±27) Ma and (246.3±1.5) Ma. (3) Yanshan to Himalayan period: gas accumulation between (115±69) Ma and (41±10) Ma. The reconstructed hydrocarbon accumulation history of the Dengying gas reservoir in the paleo-uplift of the central Sichuan Basin is highly consistent with the tectonic-burial history, basin thermal history and hydrocarbon generation history, indicating that the new method is a reliable way for reconstructing the hydrocarbon accumulation history.
  • Quantitative evaluation of lateral sealing of extensional fault by an integral mathematical-geological model
    LYU Yanfang, HU Xinlei, JIN Fengming, XIAO Dunqing, LUO Jiazhi, PU Xiugang, JIANG Wenya, DONG Xiongying
    Petroleum Exploration and Development, 2021, 48(3): 488-497. https://doi.org/10.11698/PED.2021.03.05
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    To evaluate the lateral sealing mechanism of extensional fault based on the pressure difference between fault and reservoir, an integral mathematical-geological model of diagenetic time on diagenetic pressure considering the influence of diagenetic time on the diagenetic pressure and diagenetic degree of fault rock has been established to quantitatively calculate the lateral sealing ability of extensional fault. By calculating the time integral of the vertical stress and horizontal in-situ stress on the fault rock and surrounding rock, the burial depth of the surrounding rock with the same shale content and diagenesis degree as the target fault rock was worked out. In combination with the statistical correlation of clay content, burial depth and displacement pressure of rock in the study area, the displacement pressure of target fault rock was calculated quantitatively. The calculated displacement pressure was compared with that of the target reservoir to quantitatively evaluate lateral sealing state and ability of the extensional fault. The method presented in this work was used to evaluate the sealing of F1, F2 and F3 faults in No.1 structure of Nanpu Sag, and the results were compared with those from fault-reservoir displacement pressure differential methods without considering the diagenetic time and simple considering the diagenetic time. It is found that the results calculated by the integral mathematical-geological model are the closest to the actual underground situation, the errors between the hydrocarbon column height predicted by this method and the actual column height were 0-8 m only, proving that this model is more feasible and credible.
  • Major biological events and fossil energy formation: On the development of energy science under the earth system framework
    PAN Songqi, ZOU Caineng, LI Yong, JING Zhenhua, LIU Entao, YUAN Ming, ZHANG Guosheng, YANG Zhi, WU Songtao, QIU Zhen, LIU Hanlin
    Petroleum Exploration and Development, 2021, 48(3): 498-509. https://doi.org/10.11698/PED.2021.03.06
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    In geological history, one major life explosion and five times of mass extinction occurred. These major biological and environmental events affected the evolution of the Earth ecosystem and controlled the formation of organic-rich strata. The life explosion occurred in Cambrian and the five mass extinction events happened at the end of Ordovician, Late Devonian, end of Permian, end of Triassic, and end of Cretaceous, respectively. They are corresponded to the formation of multiple suites of organic-rich strata globally, which are crucial to the formation, evolution and distribution of the fossil energy on Earth. From the perspective of the Earth system evolution, we investigate the multiple relationships between energy and Earth, energy and environment, as well as energy and human beings, and carry out comprehensive research on energy. Energy science refers to the science of studying the various energy sources formation and distribution, evaluation and selection, production and utilization, orderly replacement, development prospects, etc. in temporal and spatial scales based on the evolution of the Earth system. The connotation of energy science includes three core contents: (1) The relationship between the Earth and energy, including the formation of energy in the Earth system and the feedback of energy consumption to the Earth's climate and environment; (2) The relationship between the Earth environment and the human beings, including the Earth environment breeding human beings and human activities transforming the earth environment; (3) The relationship between the energy and the human beings, including the development of energy technology by human beings and the progress of human society driven by energy utilization. The energy science focuses on the formation and development of fossil energy, development and orderly replacement of new energy, exploration and utilization of energy in deep earth and deep space, and energy development strategy and planning. The proposal of energy science is of great significance for improving the discipline system, promoting energy development, clarifying the development direction of energy transition, and constructing a habitable Earth.
  • Origin and growth mechanisms of strike-slip faults in the central Tarim cratonic basin, NW China
    WU Guanghui, MA Bingshan, HAN Jianfa, GUAN Baozhu, CHEN Xin, YANG Peng, XIE Zhou
    Petroleum Exploration and Development, 2021, 48(3): 510-520. https://doi.org/10.11698/PED.2021.03.07
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    Through fault structure analysis and chronology study, we discuss the origin and growth mechanisms of strike-slip faults in the Tarim Basin. (1) Multiple stages strike-slip faults with inherited growth were developed in the central Tarim cratonic basin. The faults initiation age is constrained at the end of Middle Ordovician of about 460 Ma ago according to U-Pb dating of the fault cements and seismic interpretation. (2) The formation of the strike-slip faults were controlled by the near N-S direction stress field caused by far-field compression of the closing of the Proto-Tethys Ocean. (3) The faults localization and characteristics were influenced by the pre-existing structures of the NE trending weakening zones in the basement and tectonic lithofacies from south to north. (4) Following the fault initiation under the Andersonian mechanism, the strike-slip fault growth was dominantly fault linkage, associated with fault tip propagation and interaction of non-Andersonian mechanisms. (5) Sequential slip accommodated deformation in the conjugate strike-slip fault interaction zones, strong localization of the main displacement and deformation occurred in the overlap zones in the northern Tarim, while the fault tips, particularly of narrow-deep grabens, and strike-slip segments in thrust zones accumulated more deformation and strain in the Central uplift. In conclusion, non-Andersonian mechanisms, dominantly fault linkage and interaction, resulted in the small displacement but long intraplate strike-slip fault system in the central Tarim basin. The regional and localized field stress, and pre-existing structures and lithofacies difference had strong impacts on the diversity of the strike-slip faults in the Tarim cratonic basin.
  • Reservoir space and enrichment model of shale oil in the first member of Cretaceous Qingshankou Formation in the Changling Sag, southern Songliao Basin, NE China
    LIU Bo, SUN Jiahui, ZHANG Yongqing, HE Junling, FU Xiaofei, YANG Liang, XING Jilin, ZHAO Xiaoqing
    Petroleum Exploration and Development, 2021, 48(3): 521-535. https://doi.org/10.11698/PED.2021.03.08
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    The lithology, lithofacies, reservoir properties and shale oil enrichment model of the fine-grained sedimentary system in a lake basin with terrigenous clastics of large depression are studied taking the organic-rich shale in the first member of Cretaceous Qingshankou Formation (shortened as Qing 1 Member) in the Changling Sag, southern Songliao Basin as an example. A comprehensive analysis of mineralogy, thin section, test, log and drilling geologic data shows that thin-layered shale with high TOC content of semi-deep lake to deep lake facies has higher hydrocarbon generation potential than the massive mudstone facies with medium TOC content, and has bedding-parallel fractures acting as effective reservoir space under over pressure. The sedimentary environments changing periodically and the undercurrent transport deposits in the outer delta front give rise to laminated shale area. The laminated shale with medium TOC content has higher hydrocarbon generation potential than the laminated shale with low TOC content, and the generated oil migrates a short distance to the sandy laminae to retain and accumulate in situ. Ultra-low permeability massive mudstone facies as the top and bottom seals, good preservation conditions, high pressure coefficient, and thin-layered shale facies with high TOC are the conditions for “lamellation type” shale oil enrichment in some sequences and zones. The sequence and zone with laminated shale of medium TOC content in oil window and with micro-migration of expelled hydrocarbon are the condition for the enrichment of "lamination type" shale oil. The tight oil and “lamination type” shale oil are in contiguous distribution.
  • Formation of overpressure system and its relationship with the distribution of large gas fields in typical foreland basins in central and western China
    LI Wei, CHEN Zhuxin, HUANG Pinghui, YU Zhichao, MIN Lei, LU Xuesong
    Petroleum Exploration and Development, 2021, 48(3): 536-548. https://doi.org/10.11698/PED.2021.03.09
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    Based on the data of measured formation pressure, drilling fluid density of key exploration wells and calculated pressure by well logging, combined with the analysis of natural gas geological conditions, the characteristics and formation mechanisms of formation fluid overpressure systems in different foreland basins and the relationship between overpressure systems and large-scale gas accumulation are discussed. (1) The formation mechanisms of formation overpressure in different foreland basins are different. The formation mechanism of overpressure in the Kuqa foreland basin is mainly the overpressure sealing of plastic salt gypsum layer and hydrocarbon generation pressurization in deep-ultra-deep layers, that in the southern Junggar foreland basin is mainly hydrocarbon generation pressurization and under-compaction sealing, and that in the western Sichuan foreland basin is mainly hydrocarbon generation pressurization and paleo-fluid overpressure storage. (2) There are three common characteristics in foreland basins, i.e. superimposed development of multi-type overpressure and multi-layer overpressure, strong-extremely strong overpressure developed in a closed foreland thrust belt, and strong-extremely strong overpressure developed in a deep foreland uplift area. (3) There are four regional overpressure sealing and storage mechanisms, which play an important role in controlling large gas fields, such as the overpressure of plastic salt gypsum layer, the overpressure formed by hydrocarbon generation pressurization, the residual overpressure after Himalayan uplift and denudation, and the under-compaction overpressure. (4) Regional overpressure is an important guarantee for forming large gas fields, the sufficient gas source, large-scale reservoir and trap development in overpressure system are the basic conditions for forming large gas fields, and the overpressure system is conducive to forming deep to ultra-deep large gas fields.
  • Accumulation conditions and exploration directions of Ordovician lower assemblage natural gas, Ordos Basin, NW China
    XU Wanglin, LI Jianzhong, LIU Xinshe, LI Ningxi, ZHANG Caili, ZHANG Yueqiao, FU Ling, BAI Ying, HUANG Zhengliang, GAO Jianrong, SUN Yuanshi, SONG Wei
    Petroleum Exploration and Development, 2021, 48(3): 549-561. https://doi.org/10.11698/PED.2021.03.10
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    Based on drilling cores, well loggings and seismic data, source rocks and reservoirs are evaluated; and the natural gas genesis is identified through the analysis of natural gas isotopes, components and fluid inclusions, to study the gas accumulation conditions of the gypsum salt rock related strata of the Ordovician lower assemblage in Ordos Basin. (1) The natural gas from Ordovician lower assemblage is high thermal evolution dry gas from marine source rock, characterized by relatively light δ13C value of methane and heavy δ13C value of ethane. The natural gas is identified as gas cracking from crude oil according to component analysis. Thermochemical sulfate reduction (TSR) reaction has happened between the hydrocarbon fluid and sulfate as sulfur crystals are found in the cores, hydrogen sulfide is found in the natural gas, and hydrocarbon and hydrogen sulfide fluid inclusions are widespread in secondary minerals. (2) Around the gypsum-salt lows, argillaceous rocks are extensive in the Ordovician lower assemblage, reaching a cumulative thickness of 20-80 m. The effective source rocks include argillaceous rock rich in organic laminae, algal clump and algal dolomite. Analysis shows that the source rocks have a dominant TOC of 0.1%-0.5%, 0.31% on average and 3.24% at maximum. The source rocks have an average TOC of 0.58% after recovered through organic acid salt method, indicating the source rocks have high hydrocarbon supply potential. (3) In the sedimentary period, the palaeo-uplift controlled the distribution of reservoirs. The inherited secondary palaeo-uplift in Wushenqi-Jingbian east of the central palaeo-uplift and the low uplift formed by thick salt rocks near Shenmu-Zizhou area controlled the distribution of penecontemporaneous grain shoal dolomite reservoirs. The salinization sedimentary environment of gypsum salt rock can promote the development of reservoir. There are three types of dolomite reservoirs, the one with intercrystalline pore, with dissolution pore, and with fracture; intercrystalline and dissolution pores are main reservoir spaces. (4) There are two types of cap rocks, namely tight carbonate rock and gypsum-salt rock, constituting two types of source-reservoir-cap assemblages respectively. The general accumulation model is characterized by marine source rock supplying hydrocarbon, beach facies limy dolomite reservoir, small fractures acting as migration pathways, and structural-lithologic traps as accumulation zones. (5) The third and fourth members of Majiagou Formation are major target layers in the lower assemblage. The Wushengqi-Jingbian secondary paleo-uplift area and Shenmu-Zizhou low uplift are dolomite and limestone transition zone, there develops tight limestone to the east of the uplift zone, which is conducive to the formation of gas reservoir sealed by lithology in the updip. Two risk exploration wells drilled recently have encouraging results, indicating that the two uplift zones are important prospects.
  • Characteristics of “Guangyuan-Wangcang” trough during late Middle Permian and its petroleum geological significance in northern Sichuan Basin, SW China
    WANG Xingzhi, LI Bo, YANG Xiyan, WEN Long, XU Liang, XIE Shengyang, DU Yao, FENG Mingyou, YANG Xuefei, WANG Yaping, PEI Senqi
    Petroleum Exploration and Development, 2021, 48(3): 562-574. https://doi.org/10.11698/PED.2021.03.11
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    Based on outcrop characteristics, combined with regional tectonic background, drilling and geophysical data, the sedimentary characteristics of the Middle Permian Maokou Formation in the northern Sichuan Basin was studied by means of macroscopic and microscopic observation, geochemical element test, total organic carbon content and vitrinite reflectance measurement. There is a set of deep-water sediments rich in organic matter in the Guangyuan-Wangcang area of northern Sichuan during the late depositional period of the Middle Permian Maokou Formation. The strata are distributed from northwest to southeast, with thickness of 10-30 m, mainly composed of siliceous rocks and siliceous mudstones, intercalated with gravity flow deposits. Siliceous rocks and siliceous mudstones are characterized by thin single layer, flat bedding and rich siliceous radiolarians, calthrop and brachiopod with small body and thin shell, belonging to the typical sedimentary characteristics of deep-water trough facies. The contents of Cu, Co, Mo, Ni and the ratio of Ni to Co in the geochemical tests all indicate that the siliceous rocks are products of deep-water reducing environment. The TOC value ranges from 3.21% to 8.19%, with an average of 5.53%, indicating that the siliceous rocks have good hydrocarbon generation ability. The south side of the trough is in platform margin facies with high energy, and the sediments are mainly thick massive micritic-calcsparite biogenic (clastic) limestone, which is conducive to the formation and evolution of the reservoir. During the late sedimentary period of the Maokou Formation, the northward subduction and extension of the oceanic crust at the northwestern margin of the Yangtze Plate provided the internal dynamic conditions for the formation of the “Guangyuan-Wangcang” trough. According to the location, sedimentary characteristics and formation dynamics of the trough, it is similar to the “Kaijiang-Liangping” trough during Late Permian proposed by previous researchers. It is believed that the “Kaijiang-Liangping” trough already had its embryonic form during the Late Middle Permian.
  • Relationship between Permian volcanic rocks distribution and karst paleogeomorphology of Maokou Formation and its significance for petroleum exploration in western Sichuan Basin, SW China
    LIU Ran, LUO Bing, LI Ya, QIU Nansheng, WANG Wei, ZHANG Yu, HE Qinglin, PEI Senqi
    Petroleum Exploration and Development, 2021, 48(3): 575-585. https://doi.org/10.11698/PED.2021.03.12
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    Based on outcrop, drilling, logging, geochemical analysis and seismic data, the karst landform and distribution of Permian volcanic rocks at the end of the sedimentary period of the Maokou Formation in the western Sichuan Basin are examined, and their petroleum geological significance is discussed. Affected by normal faults formed in the early magmatic activities and extension tectonic background in the late sedimentary period of the Maokou Formation, a local karst shallow depression under the background of karst slope came up in the Jianyang area of the western Sichuan Basin, where the residual thickness of the Maokou Formation was thinner. Basic volcanic rocks like pyroclastic rock of eruptive facies, basalt of overflow facies, diabase porphyrite of intrusive facies and sedimentary tuff of volcanic sedimentary facies were formed after karstification. However, under the effects of faulting and karst paleogeomorphology, the volcanic rocks in different areas had different accumulation features. In the Jianyang area, with long eruption time, the volcanic rocks were thick and complex in lithology, and accumulated in the karst depressions. In the Zhongjiang-Santai area located in the karst slope, there’s no fault developed, only thin layers of basalt and sedimentary tuff turned up. The karst landform controls the build-up of thick explosive facies volcanic rocks and also the development of karst reservoirs in the Maokou Formation, and the western Sichuan area has oil and gas exploration potential in volcanic rocks and the Maokou Formation.
  • Growth of forearc highs and basins in the oblique Sumatra subduction system
    MUKTI Maruf M, MAULIN Hade B, PERMANA Haryadi
    Petroleum Exploration and Development, 2021, 48(3): 586-594. https://doi.org/10.11698/PED.2021.03.13
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    By analyzing the structure deformation of the oblique Sumatra subduction system, the uplift mechanisms of forearc high and the formation of the forearc basin in this system are studied. The development of the forearc high is attributed to the flexing and uplifting, basin reversal, and the uplifting of the older accretion wedge and the backthrust of the accretion wedge toward the continental margin. The latest seismic reflection data shows that the interplay between trenchward-vergent thrusts and arcward-vergent thrusts has played a major role in the uplift of forearc high. The uplifted sediments on the forearc high were previously formed in a forearc basin environment. The present-day morphology of the forearc high and forearc basin is related to the uplift of the accretionary wedge and the overlying forearc basin sediments in Pliocene. Regardless of obliquity in the subduction system, the Sumatran forearc region is dominated by compression that plays an important role in forming Neogene basin depocenters that elongated parallel to the trench.
    • OIL AND GAS FIELD DEVEIOPMENT
  • A differential wide field electromagnetic method and its application in ASP flooding monitoring
    LI Diquan, HE Jishan
    Petroleum Exploration and Development, 2021, 48(3): 595-602. https://doi.org/10.11698/PED.2021.03.14
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    To improve effectiveness of ASP flooding, it is necessary to establish a reliable parameter design and tracking adjustment method to monitor the process of oil displacement. A differential wide field electromagnetic method was proposed and applied to the ASP displacement monitoring test in a block of the Daqing Oilfield. In the process of ASP flooding, the electromagnetic field was measured many times. The data acquired before the ASP flooding were set as the background field, and the resistivity model was obtained by inversion. Then, the resistivity data were calibrated by logging data and the resistivity model was established. Finally, the range and front of ASP flooding were deduced with the residual gradient from the spatial domain first-order difference of the resistivity model. Production data of well groups in this block have proved that this method can work out the range and front of ASP flooding accurately, providing support for optimization of ASP flooding parameters.
  • Nuclear magnetic resonance experimental study of CO2 injection to enhance shale oil recovery
    LANG Dongjiang, LUN Zengmin, LYU Chengyuan, WANG Haitao, ZHAO Qingmin, SHENG Han
    Petroleum Exploration and Development, 2021, 48(3): 603-612. https://doi.org/10.11698/PED.2021.03.15
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    Factors affecting CO2 flooding of shale oil reservoir were studied by nuclear magnetic resonance (NMR) experiments, the effects of time, pressure, temperature on the recovery of CO2 flooding in shale oil reservoir were analyzed based on nuclear magnetic resonance T2 spectrum, and the effect of fracture development degree on recovery of CO2 flooding in shale oil reservoir was analyzed based on NMR images. In the process of CO2 flooding, the recovery degree of the shale oil reservoir gradually increases with time. With the rise of pressure, the recovery degree of the shale oil reservoir goes up gradually. With the rise of temperature, the recovery degree of shale oil increases first and then decreases gradually. For CO2 flooding in matrix core, the crude oil around the core surface is produced in the initial stage, with recovery degree going up rapidly; with the ongoing of CO2 injection, the CO2 gradually diffuses into the inside of core to produce the oil, and the increase of recovery degree slows down gradually. For CO2 flooding in matrix core with fractures, in the initial stage, the oil in and around the fractures are produced first, and the recovery degree goes up fast; with the extension of CO2 injection time, CO2 diffuses into the inside of the core from the fractures and the core surface to produce the oil inside the core, and the increase of recovery degree gradually slows down. Fractures increase the contact area between injected CO2 and crude oil, and the more the fractures and the greater the evaluation index of fractures, the greater the recovery degree of shale oil will be.
  • Characterization of complex hydraulic fractures in Eagle Ford shale oil development through embedded discrete fracture modeling
    FIALLOS Mauricio, MORALES Adrián, YU Wei, MIAO Jijun
    Petroleum Exploration and Development, 2021, 48(3): 613-619. https://doi.org/10.11698/PED.2021.03.16
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    This study extends an integrated field characterization in Eagle Ford by optimizing the numerical reservoir simulation of highly representative complex fractured systems through embedded discrete fracture modeling (EDFM). The bottom-hole flowing pressure was history-matched and the field production was forecasted after screening complex fracture scenarios with more than 100 000 fracture planes based on their propped-type. This work provided a greater understanding of the impact of complex-fractures proppant efficiency on the production. After compaction tables were included for each propped type fracture group, the estimated pressure depletion showed that the effective drainage area can be smaller than the complex fracture network if modeled and screened by the EDFM method rather than unstructured gridding technique. The essential novel value of this work is the capability to couple EDFM with third-party fracture propagation simulation automatically, considering proppant intensity variation along the complex fractured systems. Thus, this work is pioneer to model complex fracture propagation and well interference accurately from fracture diagnostics and pseudo 3D fracture propagation outcomes for multiple full wellbores to capture well completion effectiveness after myriads of sharper field simulation cases with EDFM.
  • Mechanism of shales stabilization by hydrophobized poly(ethylene glycol)/K+ in water-base drilling fluids
    VILLABONA-ESTUPIÑAN Santiago, de ALMEIDA RODRIGUES JUNIOR Jorge, de ABREU Carolina Ferreira, NASCIMENTO Regina Sandra Veiga
    Petroleum Exploration and Development, 2021, 48(3): 620-629. https://doi.org/10.11698/PED.2021.03.17
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    The mechanism of the hydrophobized poly(ethylene glycol) (PEG)/K+ system inhibiting shale hydration was studied by laboratory experiment. The inhibition performance was evaluated through cuttings hot-rolling dispersion, bentonite inhibition and contact angle tests. The inhibition became stronger as contact angle and PEG concentration increased. A modified cuttings hot-rolling dispersion experiment suggested that these molecular systems did not act through the thermally activated mud emulsion (TAME) mechanism. The interaction of the PEG/K+ with clay samples was investigated through adsorption studies and by Fourier transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD) and thermogravimetric analysis (TGA). The adsorption isotherms showed that the presence of K+ increased the PEG affinity for the clay surface. This inhibition effect was accompanied by a reduction of the bentonite hydration with PEG adsorption, evidenced by FT-IR, TGA and differential thermogravimetric (DTG) curves. XRD patterns were conclusive in showing that the presence of K+ ions limited the expansion of the clay interlamellar region to only one PEG layer, and the terminal hydrophobic segments of the PEG chains turned out to be determinant in enhancement of the inhibitory efficiency. The cuttings hot-rolling dispersion was carried out on water-base drilling fluid with PEG/K+, which proved the inhibition performance of PEG/K+ in oil field drilling.
    • PETROLEUM ENGINEERING
  • Research progress and prospect of plugging technologies for fractured formation with severe lost circulation
    SUN Jinsheng, BAI Yingrui, CHENG Rongchao, LYU Kaihe, LIU Fan, FENG Jie, LEI Shaofei, ZHANG Jie, HAO Huijun
    Petroleum Exploration and Development, 2021, 48(3): 630-638. https://doi.org/10.11698/PED.2021.03.18
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    By reviewing the mechanisms of drilling fluid lost circulation and its control in fractured formations, the applicability and working mechanisms of different kinds of lost circulation materials in plugging fractured formations have been summarized. Meanwhile, based on the types of lost circulation materials, the advantages, disadvantages, and application effects of corresponding plugging technologies have been analyzed to sort out the key problems existing in the current lost circulation control technologies. On this basis, the development direction of plugging technology for severe loss have been pointed out. It is suggested that that the lost circulation control technology should combine different disciplines such as geology, engineering and materials to realize integration, intelligence and systematization in the future. Five research aspects should be focused on: (1) the study on mechanisms of drilling fluid lost circulation and its control to provide basis for scientific selection of lost circulation material formulas, control methods and processes; (2) the research and development of self-adaptive lost circulation materials to improve the matching relationship between lost control materials and fracture scales; (3) the research and development of lost circulation materials with strong retention and strong filling in three-dimensional fracture space, to enhance the retention and filling capacities of materials in fractures and improve the lost circulation control effect; (4) the research and development of lost circulation materials with high temperature tolerance, to ensure the long-term plugging effect of deep high-temperature formations; (5) the study on digital and intelligent lost circulation control technology, to promote the development of lost circulation control technology to digital and intelligent direction.
  • Formation of fractures in carbonate rocks by pad acid fracturing with different phases of carbon dioxide
    GUO Jianchun, ZHAN Li, GOU Bo, ZHANG Ran, LIU Chao, LI Xiao, REN Jichuan
    Petroleum Exploration and Development, 2021, 48(3): 639-645. https://doi.org/10.11698/PED.2021.03.19
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    Carbonate outcrops were taken from Ma 51 sub-member in the Lower Paleozoic in the Yan'an gas field to conduct true tri-axial hydraulic fracturing experiments with water, liquid CO2 and supercritical CO2. CT scan was applied to analyze initiation and propagation laws of hydraulic fractures in carbonate rocks. The experiments show that supercritical CO2 has low viscosity, strong diffusivity and large filtration during fracturing, which is more liable to increase pore pressure of rocks around wellbore and decrease breakdown pressure of carbonate rocks. However, it would cost much more volume of supercritical CO2 than water to fracture rocks since the former increases the wellbore pressure more slowly during fracturing. For carbonate rocks with few natural fractures, tensional fractures are generated by fracturing with water and liquid CO2, and these fractures propagate along the maximum horizontal principal stress direction; while fracturing with supercritical CO2 can form shear fractures, whose morphology is rarely influenced by horizontal stress difference. Besides, the angle between propagation direction of these shear fractures near the wellbore and the maximum horizontal principal stress is 45°, and the fractures would gradually turn to propagate along the maximum horizontal principal stress when they extend to a certain distance from the wellbore, leading to an increase of fracture tortuosity compared with the former. For carbonate rocks with well-developed natural fractures, fracturing with fresh water is conducive to connect natural fractures with low approaching angle and form stepped fractures with simple morphology. The key to forming complex fractures after fracturing carbonate rocks is to connect the natural fractures with high approaching angle. It is easier for liquid CO2 with low viscosity to realize such connection. Multi-directional fractures with relatively complex morphology would be formed after fracturing with liquid CO2.
  • Mechanisms of shale hydration and water block removal
    ZENG Fanhui, ZHANG Qiang, GUO Jianchun, ZENG Bo, ZHANG Yu, HE Songgen
    Petroleum Exploration and Development, 2021, 48(3): 646-653. https://doi.org/10.11698/PED.2021.03.20
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    Shale samples of Longmaxi Formation in the Changning area of the Sichuan Basin were selected to carry out scanning electron microscopy, CT imaging, high-pressure mercury injection, low-temperature nitrogen adsorption and imbibition experiments to compare the hydration characteristics of montmorillonite and illite, analyze the main factors affecting the water block removal of shale, and reveal the mechanisms of pore structure evolution during shale hydration. The hydration characteristics of shale are closely related to the composition of clay minerals, the shale with high illite content is not susceptible to hydration and thus has limited room for pore structure improvement; the shale with high montmorillonite is susceptible to hydration expansion and thus has higher potential of pore structure improvement by stimulation; the shale with high illite content has stronger imbibition in the initial stage, but insufficient diffusion ability, and thus is likely to have water block; the shale with high montmorillonite content has weaker imbibition in the initial stage but better water diffusion, so water blocking in this kind of shale can be removed to some degree; the shale reservoir has an optimal hydration time, when it is best in physical properties, but hydration time too long would cause damage to the reservoir, and the shale with high illite content has a shorter optimal hydration time; inorganic cations can inhibit the hydration of clay minerals and have stronger inhibition to illite expansion, especially K+; for the reservoir with high content of montmorillonite, the cation content of fracturing fluid can be lowered to promote the shale hydration; fracturing fluid with high K+ content can be injected into reservoirs with high illite content to suppress hydration.
    • NEW ENERGY AND EMERGING FIELD
  • Key geological factors controlling the estimated ultimate recovery of shale oil and gas: A case study of the Eagle Ford shale, Gulf Coast Basin, USA
    HOU Lianhua, YU Zhichao, LUO Xia, LIN Senhu, ZHAO Zhongying, YANG Zhi, WU Songtao, CUI Jingwei, ZHANG Lijun
    Petroleum Exploration and Development, 2021, 48(3): 654-665. https://doi.org/10.11698/PED.2021.03.21
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    Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate recovery (EUR) of shale oil and gas of the wells are predicted by using two classical EUR estimation models, and the average values predicted excluding the effect of engineering factors are taken as the final EUR. Key geological factors controlling EUR of shale oil and gas are fully investigated. The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling EUR. The storage capacity of shale oil and gas is directly controlled by total porosity and hydrocarbon-bearing porosity, and indirectly controlled by total organic carbon (TOC) and vitrinite reflectance (Ro). The resources of shale oil and gas are controlled by hydrocarbon-bearing porosity and effective shale thickness etc. The flow capacity of shale oil and gas is controlled by effective permeability, crude oil density, gas-oil ratio, condensate oil-gas ratio, formation pressure gradient, and Ro. The fracability of shale is directly controlled by brittleness index, and indirectly controlled by clay content in volume. EUR of shale oil and gas is controlled by six geological parameters: it is positively correlated with effective shale thickness, TOC and fracture porosity, negatively correlated with clay content in volume, and increases firstly and then decreases with the rise of Ro and formation pressure gradient. Under the present upper limit of horizontal well fracturing effective thickness of 65 m and the lower limit of EUR of 3×104 m3, when TOC<2.3%, or Ro<0.85%, or clay content in volume >25%, and fractures and micro-fractures aren’t developed, favorable areas of shale oil and gas hardly occur.
  • Geology and development of geothermal field in Neogene Guantao Formation in northern Bohai Bay Basin: A case of the Caofeidian geothermal heating project in Tangshan, China
    DONG Yuexia, HUANG Hongxiang, REN Lu, LI Hongda, DU Zhiqiang, E Junjie, WANG Qi, ZHANG Xiaoming
    Petroleum Exploration and Development, 2021, 48(3): 666-676. https://doi.org/10.11698/PED.2021.03.22
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    Taking the Gaoshangpu-Liuzan geothermal field in the Nanpu sag of the Bohai Bay Basin as the research object, this paper discusses the geological conditions and potential of the geothermal resources of the Guantao Formation in the study area, and introduces the development practice of geothermal energy heating in Caofeidian. The average buried depth of the Guantao Formation is 1500-2500 m, the lithology is dominated by sandy conglomerate, and the average thickness of thermal reservoir is 120-300 m. The average porosity of thermal reservoir is 28%-35%, the permeability is (600-2000)×10-3 μm2, and the temperature of thermal reservoir is 70-110 ℃. The formation has total geothermal resources of 13.79×1018 J, equivalent to 4.70×108 t of standard coal. Based on a large amount of seismic and drilling data from oil and gas exploration, this study carried out high quality target area selection, simulation of sandstone thermal reservoir, and production and injection in the same layer. The geothermal heating project with distributed production and injection well pattern covering an area of 230×104 m2 was completed in the new district of Caofeidian in 2018. The project has been running steadily for two heating seasons, with an average annual saving of 6.06×104 t of standard coal and a reduction of 15.87×104 t of carbon dioxide, achieving good economic and social benefits. This project has proved that the Neogene sandstone geothermal reservoir in eastern China can achieve sustainable large-scale development by using the technology of "balanced production and injection in the same layer". It provides effective reference for the exploration and development of geothermal resource in oil and gas-bearing basins in eastern China.
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