27 July 2017, Volume 44 Issue 4
    

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    PETROLEUM EXPLORATION
  • Geological factors controlling shale gas enrichment and high production in Fuling shale gas field
    GUO Xusheng, HU Dongfeng, LI Yuping, WEI Zhihong, WEI Xiangfeng, LIU Zhujiang
    Petroleum Exploration and Development. 2017, 44(4): 481-491. https://doi.org/10.11698/PED.2017.04.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the understandings on enrichment rules of marine shale gas in southern China and data obtained from exploration and development in Fuling shale gas field, this article discusses the key controlling factors on shale gas enrichment and their relationships, it also discusses further the theory of Two-Factor Enrichment of marine shale gas in southern China. The bases for shale gas enrichment are shale gas generation and accumulation, the shale gas reservoirs of deep-water shelf are characterized by high TOC, high porosity, high gas content and high siliceous content, with high hydrocarbon-generation intensity, they are rich in organic pores, favorable for reformation, so they are the base for large scale hydrocarbon accumulation. Preservation conditions are vital to the formation and enrichment of shale gas reservoir, good top and base layers can effectively prevent hydrocarbon from escaping vertically at the beginning of hydrocarbon generation. Shale gas preservation conditions depend on the intensity and duration of tectonic movements, good preservation conditions are key geological factors for shale gas accumulation, shale reservoirs have high gas content, high porosity and high pressure and are likely to form high yield area of shale gas.
  • A new method for lithology identification of fine grained deposits and reservoir sweet spot analysis: A case study of Kong 2 Member in Cangdong sag, Bohai Bay Basin, China
    ZHAO Xianzheng1, PU Xiugang1, HAN Wenzhong1, 2, ZHOU Lihong1, SHI Zhannan1, CHEN Shiyue2, XIAO Dunqing1
    Petroleum Exploration and Development. 2017, 44(4): 492-502. https://doi.org/10.11698/PED.2017.04.02
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on systematic coring of 500 m of Kong 2 Member of the Paleogene Kongdian Formation in Cangdong sag of Bohai Bay Basin, identification and XRD (X-Ray Diffraction) analysis of over 1000 thin sections, a simplified method to quantitatively calculate contents of fine grained minerals with conventional logging data such as acoustic travel time (AC) and density log (DEN) has been proposed, and a quick lithologic identification "green mode" has been worked out in this study. By fitting the relationship between normalization of logging curves and mineral content measured by XRD, the mineral contents of sections or wells not cored can be calculated to identify lithology. With this method, several dolomite sweet spot intervals and one sandstone sweet spot interval have been found in the Kong 2 Member of Cangdong sag, where high production oil and gas flows have been tapped from drilled wells. The study shows that the dolomite is in band distribution and enriched in local parts of the study area. This method is applicable to lithologic identification of fine grained deposits in front delta-lake basin center, especially lithologic identification of mud and dolomite dominated fine grained deposits with low sand content of semi-deep, deep lake facies.
  • New indexes and charts for genesis identification of multiple natural gases
    LI Jian1, 2, LI Zhisheng1, 2, WANG Xiaobo1, 2, WANG Dongliang3, XIE Zengye1, 2, LI Jin1, 2, WANG Yifeng1, 2, HAN Zhongxi1, 2, MA Chenghua1, 2, WANG Zhihong1, 2, CUI Huiying1, 2, WANG Rong1, 2, HAO Aisheng1, 2
    Petroleum Exploration and Development. 2017, 44(4): 503-512. https://doi.org/10.11698/PED.2017.04.03
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Identification of natural gas genesis and source for high-matured multiple natural gases is a great challenge in the exploration of deep-ultra deep and unconventional natural gases. In this paper, the genesis identification method system of multiple natural gases is enriched through new experimental techniques and comprehensive analysis of geological data. New indexes and charts of genesis identification for multiple natural gases were determined to distinguish the sapropelic kerogen degraded gas and crude oil cracking gas, accumulated and scattered liquid hydrocarbon cracking gas in different evolution stages, nitrogen, carbon dioxide of organic and inorganic origins, inert gases of crustal and mantled origins, coal-formed gas and oil-type gas by helium, nitrogen, carbon dioxide and mercury content in natural gas. These indexes and charts have been successfully applied in the Sichuan, Tarim and Songliao basins to identify the natural gas genesis and source for complicated gas reservoirs. The research results have provided effective support for the natural gas exploration in the Sinian-Cambrian ancient carbonate formations in the Sichuan Basin, deep formations in the Kuqa depression of the Tarim Basin, and deep volcanic formations in the Songliao Basin.
  • Seismic prediction method of pore fluid in tight gas reservoirs, Ordos Basin, NW China
    YANG Hua1, WANG Daxing2, 3, ZHANG Mengbo2, 3, WANG Yonggang3, LIU Lihui4, ZHANG Mengli3
    Petroleum Exploration and Development. 2017, 44(4): 513-520. https://doi.org/10.11698/PED.2017.04.04
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the rock physical analysis of tight gas reservoirs in He8 Member of Permian Lower Shihezi Formation of Ordos Basin, and considering that bulk modulus is sensitive to pore fluid, this study proposes a fluid property detection method by compression coefficient of tight sandstone reservoirs under the constraint of reservoir lithofacies. In this method, lithofacies is identified first by calculating distribution of tight sandstone facies with the cross plot of Vp and Vs obtained from pre-stack seismic inversion; secondly, the compression coefficient is calculated by P-wave impendance and velocity from stable pre-stack seismic inversion with the restriction of lithofacies (excluding the influence of clay content); and finally, pore fluid properties are determined using the differences of compression coefficients in gas and water layers. Its application in tight gas exploration and development in Sulige gas field of Ordos Basin shows that this pore fluid prediction method by calculating compression coefficient can effectively and efficiently delineate the distribution of gas-bearing and water-bearing sandstone.
  • Accumulation and potential analysis of self-sourced natural gas in the Ordovician Majiagou Formation of Ordos Basin, NW China
    LI Wei, TU Jianqi, ZHANG Jing, ZHANG Bin
    Petroleum Exploration and Development. 2017, 44(4): 521-530. https://doi.org/10.11698/PED.2017.04.05
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The characteristics of the marine carbonate source rocks and the accumulation and potential of self-sourced natural gas in the Ordovician Majiagou Formation of the Ordos Basin are investigated based on recent exploration progress by using geochemical and gas-source correlation methods. Massive source rocks are developed around the salt depression, east of the paleo-uplift in the Ordovician Majiagou Formation during the Caledonian; and the natural gases produced by argillaceous dolomite and dolomitic mudstone are the major sources of the Ordovician gas field. Besides widespread carbonate weathering crust karst, internal grainstone dolomite is also well-developed in the Majiagou Formation, and both can act as favorable reservoirs. The natural gas of the Majiagou Formation is mainly self-sourced oil-type gas generated by in-situ source rock and accumulated near the source area. There is only limited local accumulation of natural gas produced in the upper strata and stored below. The Majiagou Formation around the salt depression has favorable conditions for large scale natural gas generation and accumulation, has the advantage of collecting large area natural gas of self-generation and self-preservation and the frontier depression areas of the paleo-uplift to the west, north and south of Jingbian gas field are the potential Ordovician exploration targets in the future.
  • Fracture pore evaluation of the Upper Ordovician Wufeng to Lower Silurian Longmaxi Formations in southern Sichuan Basin, SW China
    WANG Yuman1, WANG Hongkun2, ZHANG Chenchen1, LI Xinjing1, DONG Dazhong1
    Petroleum Exploration and Development. 2017, 44(4): 531-539. https://doi.org/10.11698/PED.2017.04.06
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The reservoir characteristics of the Upper Ordovician Wufeng-Lower Silurian Longmaxi Formations in southern Sichuan Basin were preliminarily revealed in this study by identifying and quantitatively evaluating the fracture pores of five appraisal wells in the central and northern parts of the southern Sichuan Depression by several methods. Four conclusions were reached as follows: (1) In the central zone of the Depression, the deep reservoir space of the Wufeng-Longmaxi producing pay is composed mainly of matrix pores and the microcracks are not common, whether on the local structural highs, flanks or lows. The physical properties are similar to that of the matrix pores in Changning, Weiyuan and Fuling gas fields. (2) In the northern zone of the Depression, the deep reservoir space of the Wufeng-Longmaxi black shale is composed mainly of matrix pores, and fracture pores mainly occur in local discrete intervals, with a total porosity range from 3.5% to 6.7%, on average 5.3%, and fracture porosity of 0-2.1%, on average 0.3%. (3) In the central and northern parts of the southern Sichuan Depression, the Wufeng-Longmaxi producing pays have undeveloped fracture pores and chiefly extensively distributed matrix pores, indirectly indicating relatively stable tectonic activities and corresponding weaker reservoir reworking there than Fuling field located in eastern Sichuan Basin. (4) The size and distribution of the gypsum-salt layer in the Cambrian are the key controlling factors of fracture pore development in the Wufeng-Longmaxi Formations. Therefore, the areas including Wellblocks L7, GS1, eastern Sichuan Basin and western Hubei province, where gypsum-salt layer in the Cambrian is thick and stable, and fracture intervals are likely to occur in the Wufeng-Longmaxi producing pay controlled by decollement structure above salt structure since the Yanshan Movement, are the potential favorable areas for fracture pore development.
  • Structural characteristics and petroleum exploration of Levant Basin in East Mediterranean
    LIU Xiaobing1, 2, ZHANG Guangya2, WEN Zhixin2, WANG Zhaoming2, SONG Chengpeng2, HE Zhengjun2, LI Zhiping1
    Petroleum Exploration and Development. 2017, 44(4): 540-548. https://doi.org/10.11698/PED.2017.04.07
    Abstract ( ) Download PDF ( ) Knowledge map Save
    By using geologic and seismic data, this study restored the proto-type basins and lithofacies paleogeography of the Levant basin in East Mediterranean during main geological periods, carried out comparison analysis on the basin architecture characteristics, and based on careful examination of the characteristics of discovered gas reservoirs, established the reservoir forming pattern and discussed the favorable reservoir forming combinations and future exploration direction in this region. Three structural architectures can be identified in the basin, the early-stage faults, the mid-stage faults and the late-stage faults. The early-stage faults are mainly controlled by intercontinental depression, which were less influenced by later compression stress in the southern deep water area of the basin. Controlled by the lateral structural stress and the Syrian Arc Fold Belt, the mid-stage faults became less active from north to south and from east to west. Influenced by the collision and/or Dead Sea strike-slip Fault Zone, the late-stage faults were active but did not pierce the thick Upper Miocene evaporites. Combined with the discovered reservoirs and outcrops, the Mesozoic sandstones and carbonates in deep water area near Eratosthenes seamount of Israel offshore and the Cenozoic carbonates and Tamar sands of Lebanon offshore are the main petroleum exploration targets in the next step.
  • Tracing natural gas migration by integrating organic and inorganic geochemical data: A case study of the Jurassic gas fields in western Sichuan Basin, SW China
    YE Sujuan1, ZHU Hongquan1, LI Rong2, YANG Yingtao1, LI Qing1
    Petroleum Exploration and Development. 2017, 44(4): 549-560. https://doi.org/10.11698/PED.2017.04.08
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the integrated geochemical and isotopic analysis of natural gases, formation waters, authigenic minerals, and fluid inclusions, a set of organic and inorganic geochemical tracing parameters, including methane/ethane ratio (C1/C2), N2 content, arene/alkane ratio, carbon isotope of methane (δ13C1), total dissolved solids (TDS) and chemistry of formation water, oxygen and carbon isotopic composition of authigenic calcite cement (δ18Ocalcite and δ13Ccalcite), and homogenization temperature and salinity of hydrocarbon- bearing brine inclusions, have been proposed to indicate the phase, direction, and pathway of natural gas migration and to discuss the migration processes and mechanisms of the Jurassic hydrocarbon in western Sichuan. This study results reveal that the Middle Jurassic gas in western Sichuan depression mainly migrated in water-dissolving phase and had the characteristics of increase of arene/alkane ratio and δ13C1, decrease of TDS, light δ18Ocalcite and δ13Ccalcite in gas-bearing sands, and high homogenization temperature and low salinity of hydrocarbon-bearing brine inclusions, while the Upper Jurassic gas primarily migrated in free gas phase. Additionally, it is demonstrated that the migration directions and pathways of the Jurassic gases in western Sichuan can be investigated effectively by applying multiple organic and inorganic geochemical tracing parameters, in combination with the study results of geological setting and phase state evolution of water-dissolved gases during desolubilization and accumulation.
  • Stepped and detailed seismic prediction of shallow-thin reservoirs in Chunfeng oilfield of Junggar Basin, NW China
    SHU Ningkai1, WANG Xinwen1, SU Chaoguang2, SONG Liang2, NIU Xuemin2, LI Qiang2
    Petroleum Exploration and Development. 2017, 44(4): 561-568. https://doi.org/10.11698/PED.2017.04.09
    Abstract ( ) Download PDF ( ) Knowledge map Save
    In view of the problems of low signal-to-noise ratio and low resolution of seismic data in shallow-thin reservoir in Chunfeng Oilfield of Junggar Basin, stepped and detailed data processing and interpretation technologies are proposed for shallow-thin reservoir prediction. The overlapping type offset packet processing technology can increase seismic fold from 8 to 16 times and increase signal to noise ratio by 1.4 times at local low noise ratio area by fine processing including frequency upgrade and de-noise imaging techniques. This study established three-level prediction techniques including pre-stack improving resolution target processing, post-stack wavelet reconstruction frequency extension, pre-stack and post-stack joint inversion, which can increase sand resolution from 12 m to 2 m and improve the identification accuracy of reservoir efficiently. The shallow-thin reservoirs after frequency extension have continuous and defined reflections, which are well coincided with actual exploration. The seismic data have well ability of preserving amplitude, and achieve good application effects.
    • OIL AND GAS FIELD DEVELOPMENT
  • Progress and prospects of reservoir development geology
    LI Yang1, WU Shenghe2, HOU Jiagen2, LIU Jianmin3
    Petroleum Exploration and Development. 2017, 44(4): 569-579. https://doi.org/10.11698/PED.2017.04.10
    Abstract ( ) Download PDF ( ) Knowledge map Save
    This paper deals with the main scientific problems, academic connotation, progress and prospects of reservoir development geology. The reservoir development geology involves the key scientific problems of reservoir connectivity, flow ability, and changeability through time. Its research focus on the forming mechanism and distribution model of geological factors controlling the reservoir development, the control mechanism of geological factors to oil and gas production, the rule of reservoir dynamic evolution during development, and the reservoir characterization and modeling technology. Important progress has been made on theory and technology of reservoir development geology in high water-cut reservoirs, low permeability and tight shale reservoirs, fracture-cavity reservoirs, which makes the reservoir development geology grow as an independent academic subject already. With the development expansion in areas of deep-strata, deep-water, and unconventional hydrocarbon reservoirs, and the increasing difficulties of high water-cut reservoir development, the theory and technology of reservoir development geology remain to be developed in order to support efficient and economic development of hydrocarbon fields with a sustainable growth.
  • Technical measures of deliverability enhancement for mature gas fields: A case study of Carboniferous reservoirs in Wubaiti gas field, eastern Sichuan Basin, SW China
    JIA Ailin, MENG Dewei, HE Dongbo, WANG Guoting, GUO Jianlin, YAN Haijun, GUO Zhi
    Petroleum Exploration and Development. 2017, 44(4): 580-589. https://doi.org/10.11698/PED.2017.04.11
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Taking the carboniferous reservoir of Wubaiti gas field in eastern Sichuan Basin as an example, the technology strategies are proposed about the following major problems during the middle to late stage of gas field development: imbalance development, low permeability and low efficient reserves left with low producing degree, unreasonable proration caused by changes of gas well dynamic productivity, universal water production in gas wells, high reserve recovery and composite decline rate of reserve-rich region, and lack of new methods for reserves producing evaluation and remaining reserves distribution prediction. The development technical strategies for Wubaiti gas field are as follows: (1) stratigraphic subdivision and structural description in which fault and tectonic fluctuations are describe based on seismic interpretation data; (2) division and quantitative characterization of reservoir units in which the reservoir shape, scale, connectivity and gas-bearing range are evaluated according to dynamic and static data; (3) fluid distribution and dynamic response analysis in which gas-water distribution pattern is figured out by combining structure, reservoir and gas well production dynamic characteristics; (4) reserves producing degree evaluation and deliverability review in which reserves producing degree and remaining recoverable reserves scale are evaluated from the perspective of static geological reserves and dynamic reserves, to make clear the direction of the next step production and establish rational production system in the late stage; (5) static geological model establishment and dynamic correction in which gas reservoir pressure and remaining reserve distribution are predicted by using fine 3D geological modeling and numerical simulation; (6) remaining reserves prediction and classified evaluation based on the dynamic revision prediction model to guide the recovery of remaining reserves; and (7) gas production technology and equipment development, targeted gas recovery techniques are provided concerning the mature gas field.
  • Sparse well pattern and high-efficient development of metamorphic buried hills reservoirs in Bohai Sea area, China
    TONG Kaijun1, LI Bo1, DAI Weihua1, ZHENG Hao2, ZHANG Zhannü2, CHENG Qi2, WANG Jianli2, FANG Na2
    Petroleum Exploration and Development. 2017, 44(4): 590-599. https://doi.org/10.11698/PED.2017.04.12
    Abstract ( ) Download PDF ( ) Knowledge map Save
    In order to achieve the development objective of fewer wells with higher production of metamorphic buried hill reservoirs in the Bohai Sea area, the JZ251S oilfield at Bohai Bay Basin was taken as an example to carry out elaboration of reservoir fracture, quantitative characterization of water displacing oil mechanism at dual-porosity reservoir, optimization of new well pattern mode, formulation of rational development technology policy, maintaining productivity and controlling water rising based on development experience of similar oil reservoir, thus forming the key high efficiency development technique of sparse well pattern of offshore metamorphic rock reservoir. Based on the characteristics of the JZ251S buried hill reservoir, forward simulation of wave equation for fracture anisotropy was carried out, verifying the effectiveness of narrow azimuth seismic data to fractures detection in work area. Multi-parameters prestack inversion and geostress field simulation were applied to forecast location of fractures and direction of fractures respectively. Based on the large-scale 3D physical model and numerical simulation, a new top-bottom interlaced 3D injection-production well deployment model concerning the horizontal well was presented. Considering the production demand, the reasonable oil production rate of JZ251S oil reservoir shall be controlled at 3%-4%, depletion development until that the formation pressure level maintains at 70% of initial formation pressure can be implemented for the oil field at the initial stage, and then the development mode of water flooding to keep pressure can be carried out. Considering the pilot production data at the work zone, different water breakthrough models of the horizontal well were simulated to form four diagnosis charts, which help to stabilize oil and control water effectively. The field practice shows that these techniques greatly increase the crude oil output and improve the water-injection development effect.
  • Experimental study on the mechanism of enhancing oil recovery by polymer - surfactant binary flooding
    LIU Weidong1, 2, LUO Litao2, 3, LIAO Guangzhi4, ZUO Luo5, WEI Yunyun1, 2, JIANG Wei1
    Petroleum Exploration and Development. 2017, 44(4): 600-607. https://doi.org/10.11698/PED.2017.04.13
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Aiming at the development situation of the Xinjiang oil field, the mechanism of enhancing oil recovery by the Polymer-Surfactant Binary Flooding (SP Flooding) was studied through SP Flooding sand pack, natural core and micro model experiments, and Optimum SP Flooding formula is provided. The results show that the enhanced oil recovery by the SP Flooding increases with the increase of the viscosity ratio between water and oil or the decrease of the interfacial tension. Capillary displacement ratio can reflect the synergetic effect of viscosity and interfacial tension and help screen out the optimum formula of the SP Flooding. For Qizhong block in Xinjiang Oilfield, where the critical viscosity ratio of SP flooding solution is 2.5, the order of magnitude of the critical interfacial tension is 1×10-2 mN/m, and the order of magnitude of the critical capillary displacement ratio is 1×10-3, the optimum formula of the SP Flooding composed of 0.3% KPS-1+1 115 mg/L HPAM can enhance the oil recovery by 23.96%. The polymer in the SP Flooding system increases the viscosity of the displacement fluid, accordingly the fluidity of the aqueous phase reduces and that of the oil phase increases, and the resulting decrease of the mobility ratio can control waterflood fingering, make water absorption thickness increase, enhance sweep efficiency and thus activate the residual oil trapped in dead ends. The surfactant decreases interfacial tension, and the resulting decrease of adhesion work makes residual oil emulsified, stripped, wiredrawn and easy to move. In addition, the emulsion liquid further increases the viscosity of the aqueous phase, and with interaction of lower interfacial tension and high viscosity of the emulsion liquid, the capillary displacement ratio is greatly enhanced, which in turn improves the oil displacement efficiency by displacing isolated-island, columnar and membranous residual oil, and consequently a higher oil recovery.
    • PETROLEUM ENGINEERING
  • Connotation, application and prospect of the fourth-generation separated layer water injection technology
    LIU He, PEI Xiaohan, JIA Deli, SUN Fuchao, GUO Tong
    Petroleum Exploration and Development. 2017, 44(4): 608-614. https://doi.org/10.11698/PED.2017.04.14
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    The fourth-generation separated layer water injection technology was studied aiming at problems existing in current separated layer water-flooding technologies and production requirements. This paper discussed the connotation, core tool and key technologies, analyzed field application and prospected further development. The connotation is to realize digital real-time monitoring on single-well separated layer pressure and injection rate of injectors, network informationization of injection performance monitoring of blocks and reservoirs, and integrated reservoir and production engineering by combining injection program design and optimization with real-time adjustment of down hole separated layer water injection. An integrated water distributor, a core tool for this technology, and some key technologies including interval flow rate detection and injection allocation adjustment were developed. Moreover, this new technology was piloted in blocks and achieved expected results. In order to meet production requirements, it is necessary to keep research on key technologies, such as downhole interval flow rate detection, wellbore wireless communication, downhole self-power generation and vulnerable components fishing. In addition, this technology shall be properly combined with reservoir engineering, thereby developing a systematical and complete fourth-generation separated layer water injection technology that can underpin water flooding development sustainably.
  • Experiments on shale reservoirs plugs hydration
    QIAN Bin1, ZHU Juhui1, YANG Hai1, LIANG Xing2, YIN Congbin1, SHI Xiaozhi1, LI Deqi2, LI Junlong1, FANG Hui3
    Petroleum Exploration and Development. 2017, 44(4): 615-621. https://doi.org/10.11698/PED.2017.04.15
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    By using nuclear magnetic resonance (NMR) and CT scanning technologies, hydration experiments have been conducted on shale samples from the Lower Silurian Longmaxi Formation in Zhaotong area in North Yunnan and Guizhou Provinces under the confining pressure of 10 MPa to study the effect of hydration on the propagation of pores and natural fractures in shale formation. The results show that the hydration not only offsets the permeability drop caused by stress sensitivity, but makes the fracture network more complicated, the connection between fractures and pores better with larger volume, and permeability higher by facilitating the dilation, propagation and cross-connection of primary pores, natural fractures, and newly created micro-fissures; hydration damage mainly occurs along the bedding plane or the direction of primary fractures; samples with relatively-developed primary pores and fractures are most affected by hydration, samples with well-developed primary pores and natural fractures are less affected by hydration, samples with only pores are least affected by hydration; and the hydration intensity of shale plugs is affected by the development of primary pores and fractures, clay content and brittleness index jointly. Therefore, in shale reservoir stimulation, it is suggested that the pumping schedule, shut-in operation or clean-up with small choke during early flow-back process be considered according to the features of shale reservoir to enhance the complexity and connection of facture network and improve the stimulation effect.
  • Killing fluid loss mechanism and productivity recovery in a gas condensate reservoir considering the phase behavior change
    JIA Hu, WU Xiaohu
    Petroleum Exploration and Development. 2017, 44(4): 622-629. https://doi.org/10.11698/PED.2017.04.16
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    A single well numerical model considering rock capillary pressure and hysteresis was built to study killing fluid loss mechanism and its influence on productivity recovery under different positive pressure differentials based on the gas reservoir characteristics of the gas condensate well by combining the reservoir engineering and oil and gas phase behavior theory. The results show that when reservoir pressure of near wellbore zone increases to the critical pressure of condensate oil, the three-phase (oil, gas, water) flow will change to two-phase (oil, water) flow, the gas block effect will weaken, and water-phase relative permeability will increase, which can be manifested as sharp increase of killing fluid loss rate; and the rising fluid loss into the reservoir can affect the phase of condensate oil and gas and fluid distribution in the storage space near wellbore, and consequently lead to abnormal killing fluid loss. The larger the fluid loss volume, the longer the time is needed to flow back the killing fluid after going into operation again and the lower the fluid flow back efficiency, and the longer the time need to recover stable production of condensate oil and gas will be. Using fluid loss control solution or lowering liquid-column positive pressure differential (by using low-density killing fluid) can effectively avoid abnormal fluid loss during overbalanced well workover and guarantee productivity recovery after well workover.
  • Influences of bit profiles on possible fracture modes
    HEYDARSHAHY Seyed Ali, KAREKAL Shivakumar
    Petroleum Exploration and Development. 2017, 44(4): 630-637. https://doi.org/10.11698/PED.2017.04.17
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The influence of different bit profiles on possible fracture modes was investigated using Finite Element Method. The International Association of Drilling Contractors (IADC) classification was used to design 14 types of profiles. The formation model was built, with given bit size, formation properties, meshing method and boundary conditions, etc. Moreover, the pseudo-static state and mass scaling were used to reduce the simulation time and increase the simulation accuracy. The simulation results showed that, for nine common bit profiles, larger cone height led to larger area of high stress zone, and the gauge height was not apparently related to the stress generated. When the gauge height decreased, the high stress zone turned from the nose and center to the gauge zone. For the non-common bit profiles, the convex bit produced larger high stress field, and the pilot section bottom of bicentre bits had concentrated stress. Fractures were created in the gauge zones and noses, and the bits with larger cone height and gauge height induced longer vertical fractures. The flat and convex bits did not generate longer vertical fractures. The bicentre bit can hinder the vertical fractures in the gauge zone, but enables the horizontal fractures easier. The bit with intermediate reamer has less damage to sidewall.
    • COMPREHENSIVE RESEARCH
  • Progress and development trend of unconventional oil and gas geological research
    SONG Yan1, 2, LI Zhuo1, JIANG Zhenxue1, LUO Qun1, LIU Dongdong1, GAO Zhiye1
    Petroleum Exploration and Development. 2017, 44(4): 638-648. https://doi.org/10.11698/PED.2017.04.18
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The progress in pore structure characterization, hydrocarbon occurrence state, mechanism of oil and gas accumulation, main controlling factors and high production model of unconventional oil and gas is reviewed. The unconventional oil and gas geological research developed from observation of the nanopores to quantitative full scale and 3D pore structure characterization, from macroscopic occurrence state study to microscopic occurrence state evolution discussion, from differential pressure drive and preferential channel migration to staged accumulation and wettability preferential migration, from accumulation controlled by source to accumulation jointly controlled by source-reservoir assemblage and preservation conditions, from accumulation model to enrichment and high production model, revealing the research progresses and future trends of unconventional oil and gas geology. Challenges are presented in unconventional oil and gas geological theory, enrichment conditions and recoverable resources potential of deeply buried unconventional oil and gas, combination of unconventional oil and gas geological research and engineering technique, and basic geologic research for joint mining of different unconventional oil and gas resources.
    • ACADEMIC DISCUSSION
  • A comprehensive evaluation index for shale reservoirs and its application: A case study of the Ordovician Wufeng Formation to Silurian Longmaxi Formation in southeastern margin of Sichuan Basin, SW China
    SHEN Cheng1, REN Lan1, ZHAO Jinzhou1, TAN Xiucheng1, WU Leize2
    Petroleum Exploration and Development. 2017, 44(4): 649-658. https://doi.org/10.11698/PED.2017.04.19
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Aiming at the disadvantages of existing shale reservoir evaluation methods, a new comprehensive index was proposed to accurately predict the distribution of high quality shale reservoirs and favorable fracturing intervals. The comprehensive index can be calculated using the physical properties index and fracturing index by the equivalent method. Computed by logging rock-electric parameters and mineral bulk physical model, the physical properties index characterizes reservoir property and gas-bearing property; the fracturing index characterizes reservoir fracability and is acquired by equivalent porous medium model considering mineral components. According to the comprehensive index, combined with the macro-micro characteristics of cores and logging data, the shale reservoirs in the Ordovician Wufeng Formation to Silurian Longmaxi Formation of Jiaoshiba area in the southeastern margin of Sichuan Basin are subdivided into four types, the high terrigenous siliceous and high authigenic siliceous types are the best in reservoir property and fracability, followed by the middle siliceous and then low siliceous. The comprehensive index can be used to interpret the logging data of horizontal well to figure out the proportion of reservoirs of different types, identify the spatial distribution of reservoirs with good physical properties and good fracability. The predicted results match well with actual production after fracturing.
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