20 April 2018, Volume 45 Issue 2
    

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    PETROLEUM EXPLORATION
  • The pre-Sinian rift in central Sichuan Basin and its control on hydrocarbon accumulation in the overlying strata
    WEI Guoqi, YANG Wei, ZHANG Jian, XIE Wuren, ZENG Fuying, SU Nan, JIN Hui
    Petroleum Exploration and Development, 2018, 45(2): 179-189. https://doi.org/10.11698/PED.2018.02.01
    Abstract ( ) Download PDF ( ) Rich HTML   Knowledge map Save
    Based on the latest seismic data, resistivity profile, outcrop evidence and logging data, the structural features of basement in Sichuan Basin and its control on the hydrocarbon accumulation in the Sinian-Cambrian strata was discussed. It was found that a NE striking pre-Sinian rift was developed across the whole basin. Controlled by a series of rift-parallel normal faults, horst-graben structures were developed inside the rift, large horst-graben structures and later activity of their boundary faults controlled the distribution of beach facies of the overlying strata. The horst-graben structures induced the formation of local highs of ancient landform and controlled the successive development of overlapped bioherm beach facies in long-term marine setting from the Sinian period to the Permian period, and as a result a widely distributed favorable sedimentary facies belt was developed. The pre-Sinian rift and later activities of related normal faults controlled the development of the grain beach and karst reservoirs and the deposition of high quality source rock, which form structural-lithologic traps. Through comprehensive evaluation, two large structural-lithologic composite trap favorable exploration areas in the south and north of the Gaoshiti-Moxi area, were selected.
  • Tectonic deformation features and petroleum geological significance in Yinggehai large strike-slip basin, South China Sea
    FAN Caiwei
    Petroleum Exploration and Development, 2018, 45(2): 190-199. https://doi.org/10.11698/PED.2018.02.02
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    The subtle strike-slip tectonic deformation and its relationship to deposition, overpressure and hydrocarbon migration were studied on the basis of systematic sorting of tectonic data. (1) The local T (tension) fractures derived from sinistral strike-slip process were formed before 10.5 Ma, large in number in the nose structure of the eastern slope, and reactivated episodically under the effect of fluid overpressure in the late stage, they served as dominant vertical hydrocarbon migration paths in the slope area of basin. (2) The dextral strike-slip extension was conducive to the increase of depositional rate and formation of regional under-compacted seal, and induced generation of local T fractures which triggered the development of diapirs; in turn, the development of diapirs made T fractures grow in size further. (3) The sinistral strike-slip process weakened after 10.5 Ma, causing tectonic movement characterized by compression in the north and rotational extension in the south, and the uplift and erosion of strata in Hanoi sag and a surge in clastics supply for south Yinggehai sag. Finally, migrating slope channelized submarine fans and superimposed basin floor fans were developed respectively on the asymmetrical east and west slopes of the Yinggehai sag.
  • Sinistral strike slip of the Zhangjiakou-Penglai Fault and its control on hydrocarbon accumulation in the northeast of Shaleitian Bulge, Bohai Bay Basin, East China
    PENG Jingsong, WEI Ajuan, SUN Zhe, CHEN Xinlu, ZHAO Dijiang
    Petroleum Exploration and Development, 2018, 45(2): 200-211. https://doi.org/10.11698/PED.2018.02.03
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    The structural style, fault activity, strike-slip displacement, and the formation mechanism and hydrocarbon migration and accumulation in the center tectonic zone in the northeast Shaleitian Bulge of Zhangjiakou-Penglai Fault Zone were studied by seismic attribute analysis, structural geometric analysis, fault activity analysis, structure evolution history and simulation of hydrocarbon migration, based on 3-D seismic and drilling data. The main results are as follows: (1) The study area is a superimposed tectonic zone, which experienced early (Paleocene and Eocene) extension and late (Oligocene and Pliocene-Quaternary) strike-slip and pull-apart. (2) The sinistral strike slip of the northeast Shaleitian Bulge of Zhangjiakou-Penglai Fault Zone went through two periods, Oligocene and Pliocene-Quaternary, and the Bohai section was active earlier than the inland section. (3) The sinistral strike slip displacement of Zhangjiakou-Penglai Fault is 4 km since Cenozoic, including 1 km in the Oligocene, and 3 km in the Pliocene-Quaternary. (4) The strike-slip movements have resulted in the increase of fault activity and basin-mountain restructure in the fault zone, also contributed to the formation of the central tectonic belt and the conjugate evolution in north-east structural belt. (5) The conjugate strike slip of the Zhangjiakou-Penglai Fault Zone dominated the migration and accumulation of hydrocarbon in shallow formations by controlling the injection points and segments of hydrocarbon from the deep layers to shallow layers.
  • Types, distribution and play targets of Lower Cretaceous tight oil in Jiuquan Basin, NW China
    CHEN Qilin, DENG Yilin, WEI Jun, MA Guofu, LONG Liwen, XIAO Wenhua, LI Wei, ZHANG Liping
    Petroleum Exploration and Development, 2018, 45(2): 212-222. https://doi.org/10.11698/PED.2018.02.04
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    Based on drilling and laboratory data, the formation conditions of tight oil reservoirs in the Jiuquan basin were comprehensively analyzed and the exploration domains were sorted out. The Jiuquan basin underwent three cycles of lake level fluctuation in early Cretaceous, leaving three sets of high-quality source rocks, the Zhonggou, Xiagou and Chijinbao Formations in the Lower Cretaceous. There are two types of reservoir assemblages, source-reservoir in one type and source below reservoir type, and two types of tight reservoirs, argillaceous dolomite and conglomerate. The “sweet spots” control the enrichment of oil and gas. Argillaceous dolomite tight oil reservoirs have the characteristic of “integrated source-reservoir”, with fractures connecting the matrix micro-pores, pore-fracture type and fracture-pore type “sweet spots” distributed in large scale. The sandy conglomerate tight oil reservoirs were formed by source-reservoir lateral connection, and can be divided into source below reservoir type, source-reservoir side by side type and “sandwich” type. The overlapping areas of the favorable facies belts of fan-delta front and the secondary pore developing belts are the “sweet spot” sites. The favorable areas for seeking conglomerate tight oil are fan-delta front deposits around the Qingxi, Ying’er and Huahai sags, with an exploration area of 550 km2; while the area to seek argillaceous dolomite tight oil is the NW fracture developed belt in Qingxi sag, with an exploration area of 100 km2.
  • Micro pore and throat characteristics and origin of tight sandstone reservoirs: A case study of the Triassic Chang 6 and Chang 8 members in Longdong area, Ordos Basin, NW China
    LIU Hanlin, YANG Youyun, WANG Fengqin, DENG Xiuqin, LIU Ye, NAN Junxiang, WANG Jin, ZHANG Hongjie
    Petroleum Exploration and Development, 2018, 45(2): 223-234. https://doi.org/10.11698/PED.2018.02.05
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    The microstructure differences of the Triassic Chang 6 and Chang 8 members tight reservoirs in the Longdong area of Ordos Basin were compared by means of cast thin sections, scanning electron microscope, X-ray diffraction, and constant rate mercury injection. Their pore evolution models were established, and the effects of main diagenesis on densification were examined. The throat is the main factor controlling the physical properties of the Chang 6 and Chang 8 members reservoirs: The lower the permeability, the smaller and the more concentrated the throat radius and the larger the proportion of the throats in the effective storage space. There are several obvious differences between Chang 6 and Chang 8 members: (1) with the increase of permeability, the contribution of the relative large throats to the permeability in the Chang 8 member reservoir is more than that in the Chang 6 member reservoir; (2) the control effect on pore-throat ratio of the nano-throats in the Chang 6 member reservoir is more significant. The sedimentary action determines the primary pore structure of the Chang 6 and Chang 8 members sand bodies, and the diagenesis is the main factor controlling the densification of the reservoirs. Because of the difference in rock fabrics and the chlorite content of Chang 6 and Chang 8, the strong compaction resulted in less porosity reduction (17%) of the Chang 81 reservoir with larger buried depth and larger ground temperature than the Chang 63 reservoir (19%). The siliceous, calcareous and clay minerals cement filling the pores and blocking the pore throat, which is the key factor causing the big differences between the reservoir permeability of Chang 6 and Chang 8 members.
  • Diagenesis-porosity evolution and “sweet spot” distribution of low permeability reservoirs: A case study from Oligocene Zhuhai Formation in Wenchang A sag, Pear River Mouth Basin, northern South China Sea
    YOU Li, XU Shouli, LI Cai, ZHANG Yingzhao, ZHAO Zhanjie, ZHU Peiyuan
    Petroleum Exploration and Development, 2018, 45(2): 235-246. https://doi.org/10.11698/PED.2018.02.06
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    The characteristics of low permeability reservoirs and distribution of sweet spots in the Oligocene Zhuhai Formation of Wenchang A sag, Pearl River Basin were investigated by core observation and thin section analysis. The study results show that there develop the fine, medium and coarse sandstone reservoirs of tidal flat - fan delta facies, which are of mostly low permeability and locally medium permeability. There are two kinds of pore evolution patterns: oil charging first and densification later, the reservoirs featuring this pattern are mainly in the third member of Zhuhai Formation between the south fault zone and the sixth fault zone, and the pattern of densification first and gas charging later is widespread across the study area. Strong compaction and local calcium cementation are the key factors causing low permeability of the reservoirs in the Zhuhai Formation. Thick and coarse grain sand sedimentary body is the precondition to form “sweet spot” reservoirs. Weak compaction and cementation, dissolution, early hydrocarbon filling and authigenic chlorite coating are the main factors controlling formation of “sweet spot” reservoir. It is predicted that there develop between the south fault and sixth fault zones the ClassⅠ“sweet spot” in medium compaction zone, ClassⅡ “sweet spot” in nearly strong compaction zone, Class Ⅲ “sweet spot” reservoir in the nearly strong to strong compaction zone with oil charging at early stage, and Class Ⅳ “sweet spot” reservoir in the strong compaction and authigenic chlorite coating protection zone in the sixth fault zone.
  • Formation mechanisms of good-quality clastic reservoirs in deep formations in rifted basins: A case study of Raoyang sag in Bohai Bay Basin, East China
    JIN Fengming, ZHANG Kaixun, WANG Quan, NIU Xinjie, YU Zuogang, BAI Guoping, ZHAO Xuan
    Petroleum Exploration and Development, 2018, 45(2): 247-256. https://doi.org/10.11698/PED.2018.02.07
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    In order to reveal the development mechanism of deep quality clastic rock reservoir, the basic characteristics of Sha-3 Member of the Shahejie Formation in the Raoyang sag of Bohai Bay Basin are analyzed based on observation of cores, observation of thin sections under microscope and SEM, and test results of petrophysical properties. It is found that high compositional and textural maturity, early oil charging, and dissolution are the main factors controlling the formation and preservation of pores in deep reservoirs. Compaction is the major factor destructing pores, whereas formation overpressure is conducive to the preservation of original pores, high compositional and medium textural maturity can enhance the resistance of the formation to compaction and protect primary pores. Early oil charging could lead to temporary cessation of diagenesis and thus inhibit the destructive impact of cementation on pores. When organic acids entered reservoir formations, considerable amounts of secondary pores were formed, leading to the improvement of petrophysical properties in local parts. When predicting good quality belt in exploration of deep formations, it is recommended that the superimposing effects of the multiple factors (overpressure; early oil charging; compositional and textural maturity; diagenesis) be taken into consideration.
  • Pore structure differences of the extra-low permeability sandstone reservoirs and the causes of low resistivity oil layers: A case study of Block Yanwumao in the middle of Ordos Basin, NW China
    WANG Jianmin, ZHANG San
    Petroleum Exploration and Development, 2018, 45(2): 257-264. https://doi.org/10.11698/PED.2018.02.08
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    The influence of pore structure difference on rock electrical characteristics of reservoir and oil reservoir was analyzed taking Triassic Chang 6 reservoir in Block Yanwumao in the middle of Ordos Basin as an example. The relationship between the pore structure difference and the low resistivity oil layer was revealed and demonstrated through core observation, lab experiments, geological research, well log interpretation and trial production etc. The results show that there were two kinds of oil layers in Chang 6 Member, normal oil layer and low resistivity oil layer in the region, corresponding to two types of pore structures, pore type mono-medium and micro-fracture-pore type double-medium; the development of micro-fracture changed greatly the micro-pore structure of the reservoir, and the pore structure difference had an important influence on the rock electrical characteristics of the extra-low permeability sandstone reservoir and oil reservoir; the normal oil layers had obvious characteristics of pore-type mono-medium, and were concentrated in Chang 61, Chang 622 and Chang 623; the low resistivity oil layers had obvious characteristics of micro-fracture-pore type double-medium, which were mainly distributed in Chang 621 and Chang 63. The mud filtrate penetrated deep into the oil layers along the micro-cracks, leading to sharp reduction of resistivity, and thus low resistivity of the oil layer; the low resistivity oil layers had better storage capacity and higher productivity than the normal oil layers.
  • Structural analysis of multi-level detachments and identification of deep-seated anticline
    CHEN Zhuxin, LEI Yongliang, HU Ying, WANG Lining, YANG Geng
    Petroleum Exploration and Development, 2018, 45(2): 265-274. https://doi.org/10.11698/PED.2018.02.09
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    Based on forward modeling of detachment fold, this study presents a method to analyze multi-level detachment structures and identify the authenticity of deep-seated anticlines using time-domain seismic section. The steps include the conversion of the time-migrated seismic image into depth domain image using a constant velocity field, structural interpretation of the depth seismic image, measurement of each structural relief area and each height above reference level, plotting of area-height relationship chart with piecewise fitting etc. The area-depth correlation can help the division of structural sequences, the definition of detachment levels, the calculation of the tectonic shortening, and the identification of deep-seated structure. The segment area-height relationship is a feature of multi-level detachment structures, while little or no linear correlation between area and height is an indicator of non-deformation or pseudo-anticline. Regardless of the uncertainty of area-height relationship, the segment slopes will correspond to the differential shortenings of multi-level detachments, the intersection between adjacent segments will give the height of detachment surface above reference level and then help define the detachment level in original time-domain seismic section. This method can make use of time-domain seismic data to determine the geologic structure of complicated structure areas and assess risks of deep exploration targets. It has achieved good results in southern Junggar and eastern Sichuan areas.
  • Ternary analytic porosity-reduction model of sandstone compaction trend and its significance in petroleum geology: A case study of tight sandstones in Permian Lower Shihezi Formation of Shilijiahan area, Ordos Basin, China
    XIA Lu, LIU Zhen, LI Weilian, LU Chaojin, YANG Xiaoguang, LIU Mingjie
    Petroleum Exploration and Development, 2018, 45(2): 275-286. https://doi.org/10.11698/PED.2018.02.10
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    The tight sandstones in the Permian Lower Shihezi Formation of Shilijiahan area in the Ordos Basin was taken as study object in this research to examine the effects of burial depth, burial time and compaction strength on porosity during densification of reservoir. Firstly, sandstone compaction profiles were analyzed in detail. Secondly, the theoretical study was performed based on visco-elasto-plastic stress-strain model. Thirdly, multiple regression and iterative algorithm were used to ascertain the variation trends of Young’s modulus and equivalent viscosity coefficient with burial depth and burial time, respectively. Accordingly, the ternary analytic porosity-reduction model of sandstone compaction trend was established. Eventually, the reasonability of improved model was tested by comparing with thin-section statistics under microscope and the models in common use. The study shows that the new model can divide the porosity reduction into three parts, namely, elastic porosity loss, visco-plastic porosity loss and porosity loss from cementation. And the results calculated by the new model of litharenite in He 2 Member are close to the average value from the thin-section statistics on Houseknecht chart, which approximately reveals the relative magnitudes of compaction and cementation in the normal evolution trend of sandstone porosity. Furthermore, the model can more exactly depict the compaction trend of sandstone affected little by dissolution than previous compaction models, and evaluate sandstone compaction degree and its contribution to reservoir densification during different burial and uplift processes.
    • OIL AND GAS FIELD DEVELOPMENT
  • Water-cut rising mechanism and optimized water injection technology for deepwater turbidite sandstone oilfield: A case study of AKPO Oilfield in Niger Delta Basin, West Africa
    YUAN Zhiwang, YANG Baoquan, YANG Li, GU Wenhuan, CHEN Xiao, KANG Botao, LI Chenxi, ZHANG Huilai
    Petroleum Exploration and Development, 2018, 45(2): 287-296. https://doi.org/10.11698/PED.2018.02.11
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    Through the analysis of the reservoir connection relationship and the water-cut rising rules after water breakthrough in the highly volatile oil AKPO oilfield, a new model of water-cut rising was established, and the timing and strategy of water injection were put forward. The water-cut rising shapes of producers after water breakthrough can be divided into three types, and their water-cut rising mechanism is mainly controlled by reservoir connectivity. For the producers which directly connect with injectors in the single-phase sand body of the single-phase channel or lobe with good reservoir connectivity, the water-cut rising curve is “sub-convex”. For the producers which connect with injectors through sand bodies developed in multi-phases with good inner sand connectivity but poorer physical property and connectivity at the overlapping parts of sands, the response to water injection is slow and the water-cut rising curve is “sub-concave”. For the producers which connect with injectors through multi-phase sand bodies with reservoir physical properties, connectivity in between the former two and characteristics of both direct connection and overlapping connection, the response to water injection is slightly slower and the water-cut rising curve is “sub-S”. Based on ratio relationship of oil and water relative permeability, a new model of water cut rising was established. Through the fitting analysis of actual production data, the optimal timing and corresponding technology for water injection after water breakthrough were put forward. Composite channel and lobe reservoirs can adopt water injection strategies concentrating on improving the vertical sweep efficiency and areal sweep efficiency respectively. This technology has worked well in the AKPO oilfield and can guide the development of similar oilfields.
  • Optimization methods of production layer combination for coalbed methane development in multi-coal seams
    YANG Zhaobiao, ZHANG Zhengguang, QIN Yong, WU Congcong, YI Tongsheng, LI Yangyang, TANG Jun, CHEN Jie
    Petroleum Exploration and Development, 2018, 45(2): 297-304. https://doi.org/10.11698/PED.2018.02.12
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    Based on the productivity equation of coalbed methane (CBM) wells, three indexes, main production layer optimization index, main production layer expansion index and capacity contribution index are proposed, with which the three - step optimization method of production-layer combination is established. In selecting main production layer, the coal seam thickness, CBM content, coal seam permeability, coal seam reservoir pressure and coal structure are considered comprehensively to evaluate the potential of the production layer. In selecting expansion of the main production layer combination, on the premise of ensuring full and slow desorption of the main production layer and non-exposure of the main production layer out of liquid surface, the degree of mutual interference between the main and non-main production layers is comprehensively evaluated by coupling the critical desorption pressure, layer spacing and reservoir pressure gradient difference. In optimizing production layer combination, the main concern is the economic efficiency of the combined layers. Only when the contribution coefficient of the main production layer is greater than 30% and the contribution index of the other production layers is more than 10%, the economic benefit of a CBM well after being put into production can be ensured. Based on the comparative analysis of the development effect of the development test wells in Songhe of Guizhou province, it is proved that the “three-step method” for the optimization of production-layer combination is scientific and practical, and can be used to design the multi-layer commingling scheme of coalbed methane.
  • An enhanced oil recovery technique by targeted delivery ASP flooding
    WU Fan, HOU Jirui, WANG Zhiming, MA Yunfei, WANG Dongying
    Petroleum Exploration and Development, 2018, 45(2): 305-311. https://doi.org/10.11698/PED.2018.02.13
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    Aiming at the problem of the loss of the ASP flooding near the injection wells, this paper gives a new idea to enhance oil recovery called “Technique of Targeted Delivery”, which combines the radial horizontal well with ultra-short radius drilled by high pressure water jet with the ASP flooding, the horizontal wells work as the “Target channel” transport the ternary composite system to the remaining oil enrichment area directly, to avoid the loss of the ternary composite system near the injection wells. The plate homogeneous experiment and numerical simulation show that the technique can significantly improve the sweep efficiency and the effect of the oil displacement, and greatly improve the oil recovery rate. The optimal flooding parameters of the target transport technique are: the right angle target, the length of the channel is about 15% of the well distance and the injection volume of the ternary composite system is 0.4 PV. Under such conditions, this technique can enhance recovery by 48.87% and 22.04% respectively, compared with the water flooding and conventional ASP flooding. The target transport technique solves the problem of high loss of chemical agent in near-wellbore area during the ASP flooding, and compensates for the high cost of ASP flooding and the limitation of application, and has a broad application prospect.
  • Oil reservoir water flooding flowing area identification based on the method of streamline clustering artificial intelligence
    JIA Hu, DENG Lihui
    Petroleum Exploration and Development, 2018, 45(2): 312-319. https://doi.org/10.11698/PED.2018.02.14
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    For the case of carbonate reservoir water flooding development, the flow field identification method based on streamline modeling result was proposed. The Ocean for Petrel platform was used to build the plug-in that exported the streamline data, and the subsequent data was processed and clustered through Python programming, to display the flow field with different water flooding efficiencies at different time in the reservoir. We used density peak clustering as primary streamline cluster algorithm, and Silhouette algorithm as the cluster validation algorithm to select reasonable cluster number, and the results of different clustering algorithms were compared. The results showed that the density peak clustering algorithm could provide better identified capacity and higher Silhouette coefficient than K-means, hierachical clustering and spectral clustering algorithms when clustering coefficients are the same. Based on the results of streamline clustering method, the reservoir engineers can easily identify the flow area with quantification treatment, the inefficient water injection channels and area with developing potential in reservoirs can be identified. Meanwhile, streamlines between the same injector and productor can be subdivided to describe driving capacity distribution in water phase, providing useful information for the decision making of water flooding optimization, well pattern adjustment and deep profile.
    • PETROLEUM ENGINEERING
  • Adsorption damage and control measures of slick-water fracturing fluid in shale reservoirs
    GUO Jianchun, LI Yang, WANG Shibin
    Petroleum Exploration and Development, 2018, 45(2): 320-325. https://doi.org/10.11698/PED.2018.02.15
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    The slick-water polymer adsorption damage and control measures in shale were examined using a shale pack model of the Ordovician Wufeng Formation-Silurian Longmaxi Formation in the Changning block of the Sichuan Basin. The adsorption law of slick water under different displacement time, concentrations, pH values and temperatures of polymer were tested by traditional displacement experiment and UV-Vis spectrophotometer. The adsorption equilibrium time was 150 min, the amount of adsorption was proportional to the concentration of the polymer, and the maximum adsorption concentration was 1 800 mg/L. With the increase of pH value, the adsorption capacity decreased gradually, the adsorption capacity increased first and then decreased with the increase of temperature, and the adsorption capacity was the largest at 45 ℃. The adsorption patterns of polymers on shale were described by scanning electron microscopy and magnetic resonance imaging. It is proved that the adsorption of polymer on shale led to the destruction of the network structure of anionic polyacrylamide molecules, and the shale adsorption conformation was characterized qualitatively. Finally, according to the adsorption law and adsorption mechanism, it is proposed to reduce the adsorption quantity of polymer on shale surface by using hydrogen bond destruction agent. The effects of hydrogen bond destruction on four kinds of strong electronegative small molecules were compared, the hydrogen bond destroyer c was the best, which lowered the adsorption capacity by 5.49 mg/g and recovered permeability to 73.2%. The research results provide a reference for the optimization of construction parameters and the improvement of slickwater liquid system.
  • Bubble dynamics characteristics and influencing factors on the cavitation collapse intensity for self-resonating cavitating jets
    PENG Kewen, TIAN Shouceng, LI Gensheng, HUANG Zhongwei, YANG Ruiyue, GUO Zhaoquan
    Petroleum Exploration and Development, 2018, 45(2): 326-332. https://doi.org/10.11698/PED.2018.02.16
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    Based on bubble dynamics theory, a mathematic model describing the cavitation bubble size variation in the flow field of self-resonating cavitating jet was developed considering the pressure field and mass and heat exchange between cavitation bubble and ambient fluid. With this model, the influence factors on the cavitation intensity are investigated. The results show that the destructiveness of cavitating jet in breaking rocks depends on the bubble’s first collapse, with decreasing intensity in the subsequent collapses. The self-resonating effect significantly enhances the cavitation intensity by promoting the collapse pressure and elongating its duration. Hydraulic parameters are proven to be the dominating factors influencing cavitation intensity: while collapse intensity monotonously increases with jet velocity, there exists an optimum ambient pressure where highest collapse intensity can be achieved. Conversely, the fluid properties show minor influences: cavitation intensity only slightly decreases with the increasing of fluid’s density and barely changes with the variation of viscosity and surface tension. The results from this investigation help to uncover the mechanism of the enhanced erosion potential of self-resonating cavitating jet. The conclusions can be used to further improve the performance of self-resonating cavitating jet in field applications.
  • Prediction of wax precipitation region in wellbore during deep water oil well testing
    GAO Yonghai, LIU Kai, ZHAO Xinxin, LI Hao, CUI Yanchun, XIN Guizhen, SUN Baojiang
    Petroleum Exploration and Development, 2018, 45(2): 333-338. https://doi.org/10.11698/PED.2018.02.17
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    During deep water oil well testing, the low temperature environment is easy to cause wax precipitation, which affects the normal operation of the test and increases operating costs and risks. Therefore, a numerical method for predicting the wax precipitation region in oil strings was proposed based on the temperature and pressure fields of deep water test string and the wax precipitation calculation model. And the factors affecting the wax precipitation region were analyzed. The results show that: the wax precipitation region decreases with the increase of production rate, and increases with the decrease of geothermal gradient, increase of water depth and drop of water-cut of produced fluid, and increases slightly with the increase of formation pressure. Due to the effect of temperature and pressure fields, wax precipitation region is large in test strings at the beginning of well production. Wax precipitation region gradually increases with the increase of shut-in time. These conclusions can guide wax prevention during the testing of deep water oil well, to ensure the success of the test.
    • COMPREHENSIVE RESEARCH
  • Laminae characteristics of gas-bearing shale fine-grained sediment of the Silurian Longmaxi Formation of Well Wuxi 2 in Sichuan Basin, SW China
    SHI Zhensheng, QIU Zhen, DONG Dazhong, LU Bin, LIANG Pingping, ZHANG Mengqi
    Petroleum Exploration and Development, 2018, 45(2): 339-348. https://doi.org/10.11698/PED.2018.02.18
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    Based on various test data, the composition, texture, structure and lamina types of gas-bearing shale were determined based on Well Wuxi 2 of the Silurian Longmaxi Formation in the Sichuan Basin. Four types of laminae, namely organic-rich laminae, organic-bearing laminae, clay laminae and silty laminae, are developed in the Longmaxi Formation of Well Wuxi 2, and they form 2 kinds of lamina set and 5 kinds of beds. Because of increasing supply of terrigenous clastics and enhancing hydrodynamics and associated oxygen levels, the TOC content and brittle mineral reduces and clay mineral content increases gradually as the depth becomes shallow. Organic-rich laminae, organic-rich + organic-bearing lamina set and organic-rich bed dominate the beds 1-3 of Member 1 of the Longmaxi Formation, suggesting anoxic and weak water hydraulic depositional setting. Bed 4 is dominated by organic-rich laminae, organic-bearing laminae and silty laminae, suggesting increased oxygen-bearing and hydraulic level. Beds 1-3 are the best interval and drilling target of shale gas exploration and development.
    • ACADEMIC DISCUSSION
  • Production prediction for fracture-vug carbonate reservoirs using electric imaging logging data
    XIE Fang, ZHANG Chengsen, LIU Ruilin, XIAO Chengwen
    Petroleum Exploration and Development, 2018, 45(2): 349-356. https://doi.org/10.11698/PED.2018.02.19
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    Considering the fluid flow non-darcy characteristics in fracture-vug carbonate reservoirs, a new multi-scale conduit flow model production prediction method for fracture-vug carbonate reservoirs was presented using image segmentation technique of electric imaging logging data. Firstly, based on Hagen-Poiseuille’s law of incompressible fluid flow and the different cross-sectional areas in single fractures and vugs in carbonate reservoirs, a multi-scale conduit flow model for fracture-vug carbonate reservoir was established, and a multi-scale conduit radial fluid flow equation was deduced. Then, conduit flow production index was introduced. The conduit flow production index was calculated using fracture-vug area extracted from the result of electrical image segmentation. Finally, production prediction of fracture-vug carbonate reservoir was realized by using electric imaging logging data. The method has been applied to Ordovician fracture-vug carbonate reservoirs in the Tabei area, and the predicted results are in good agreement with the oil testing data.
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