23 October 2017, Volume 44 Issue 5
    

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    PETROLEUM EXPLORATION
  • Discovery of Wanyuan-Dazhou Intracratonic Rift and its exploration significance in the Sichuan Basin, SW China
    ZHAO Wenzhi, WEI Guoqi, YANG Wei, MO Wuling, XIE Wuren, SU Nan, LIU Mancang, ZENG Fuying, WU Saijun
    Petroleum Exploration and Development. 2017, 44(5): 659-669. https://doi.org/10.11698/PED.2017.05.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    With the development of gas exploration of the Sinian-Cambrian strata in the Sichuan Basin, creative understandings of geology were achieved. An N-E trending intracratonic rift was found in the Wanyuan-Dazhou area, northeastern Sichuan Basin. Based on seismic interpretation data, outcrop data and analysis of regional structural geological background, studies on the boundary, distribution, formation and evolution history of Wanyuan-Dazhou rift were carried out, and the significance on exploration was discussed. The following findings were obtained. (1) The seismic section indicated that a steep-slope belt was developed in the first and second members (Z2dn1-Z2dn2) of the Dengying Formation of the Sinian System, showing platform edge facies. The rift generally strikes in NE direction. (2) The thicknesses of the first and second members of the Dengying Formation are thicker than the third and fourth members (Z2dn3-Z2dn4) at the rift periphery, while it came to the opposite conclusion at the inside of the rift. (3) The rift formed in Z2dn1-Z2dn2 of Sinian deposition period. Filling and subsidence occurred in Z2dn3-Z2dn4 of Sinian deposition period. The shrinkage stage was the deposition period of the Early Cambrian Maidiping Formation - Qiongzhusi Formation. The formation of the rift was controlled by the Nanhua rift and regional uplift. The finding of the Wanyuan-Dazhou rift changed the traditional understanding of the Sinian - Early Cambrian tectonic sedimentary framework, and the rift will be the significant exploration direction in the future due to its superior natural gas accumulation conditions in the Sinian.
  • Accumulation features and mechanisms of high saturation natural gas hydrate in Shenhu Area, northern South China Sea
    ZHANG Wei, LIANG Jinqiang, LU Jing’an, WEI Jiangong, SU Pibo, FANG Yunxin, GUO Yiqun, YANG Shengxiong, ZHANG Guangxue
    Petroleum Exploration and Development. 2017, 44(5): 670-680. https://doi.org/10.11698/PED.2017.05.02
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    Based on the comprehensive interpretation of cores, loggings and 2D/3D seismic data of Shenhu GMGS3 drilling area in the northern South China Sea, the distribution characteristics, differential accumulation mechanism and reservoir forming mechanism of diffusion type natural gas hydrate with high saturation discovered from clayey silt reservoirs were investigated. The following findings are reached through the research: (1) Gas hydrate with high saturation often displays high resistivity, low interval transit time, and strong bottom-simulating reflectors (BSRs), and accompanies with fluid seepage phenomena beneath BSRs, such as mud diapiric structure and gas chimney. (2) The gas hydrate reservoirs are dominated by fine grained clayey silt sediments, and the reservoirs have higher porosity and permeability in local parts. (3) The gas hydrate is largely type I, whereas type II gas hydrate may exist below the type I gas hydrate. (4) The gas sources are mixed microbial and thermogenic gases, and the thermogenic gas originated from the deep formation in the center of Baiyun Sag migrated into shallow strata through faults, mud diapirs and gas chimneys, then was mixed with microbial gas in situ and continued to migrate until they accumulated in the temperature and pressure stability zone and formed diffusion type gas hydrate with high saturation finally. (5) The fluid migration system influenced and controlled the differential distribution of gas hydrate with high saturation.
  • Characterization of micro-nano pore networks in shale oil reservoirs of Paleogene Shahejie Formation in Dongying Sag of Bohai Bay Basin, East China
    HU Qinhong, ZHANG Yuxiang, MENG Xianghao, LI Zheng, XIE Zhonghuai, LI Maowen
    Petroleum Exploration and Development. 2017, 44(5): 681-690. https://doi.org/10.11698/PED.2017.05.03
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    For typical blocky, laminated and bedded mudrock samples from the Paleogene Shahejie Formation in the Dongying Sag of Bohai Bay Basin, this work systematically focuses on their structure characterization of multiple micro-nano pore networks. A use of mercury injection capillary pressure (MICP) documented the presence of multiple μm-nm pore networks, and obtained their respective porosity, permeability and tortuosity. Different sample sizes (500-841 μm GRI fractions, 1 cm-sized cubes, and 2.54 cm in diameter and 2-3 cm in height core plugs) and approaches (low-pressure N2 gas physisorption, GRI matrix permeability, MICP, heliumpy cnometry, and pulse decay permeameter) were used to measure pore size distribution, porosity and permeability. The average porosity and matrix permeability determined from MICP are (6.31±1.64)% and (27.4±31.1)×10-9 μm2, the pore throat diameter of pores is mainly around 5 nm, and the median pore throat diameter based on 50% of final cumulative volume is (8.20±3.01) nm in shale. The pore-throat ratios decrease with a decrease of pore size diameter. Moreover, the permeability of shale samples with lamination is nearly 20 times larger than matrix permeability. The geometrical tortuosity of the nano-scale 2.8-10.0 nm pore networks is 8.44 in these shales, which indicates a poor connectivity of matrix pore network and low flow capability. Overall, the variable and limited pore connectivity of shale samples will affect hydrocarbon preservation and recovery.
  • Geological features, hydrocarbon accumulation and deep water potential of East Indian basins
    QIN Yanqun, ZHANG Guangya, JI Zhifeng, LI Zhi, WU Yiping, WANG Xinglong, LIANG Xu
    Petroleum Exploration and Development. 2017, 44(5): 691-703. https://doi.org/10.11698/PED.2017.05.04
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    Based on the tectonic evolution, sedimentary filling and hydrocarbon geological characteristics, this paper establishes a variety of deep water fan models and accumulation patterns and analyzes exploration potential of deep water area in East Indian basins. Due to the breakup of East Gondwana, the passive continental margins of East India are evolved. The basins in these margins experienced four evolution stages, which include intracratonic rift (P1-T), East Gondwana rift (J1-K1), post-rifted thermal subsidence (K2), and passive continental margin (K3-N). There are three obvious unconformities which were formed in the end stages of post-rift thermal subsidence and first and second phases of passive continental margin. Four sets of structural layers were formed, rift stage, and the first, second and third stages of passive continental marginal structural formation. The main deposition of these basins is the sediments evolved during the passive continental margin stage. Two prolific fan systems were developed: superposition fans are complicated in near shore and delta; low fans are located at fault slope-break while turbidity fans are located in front of delta. Four sets of proven source rocks were developed, the Lower Permian, Lower Cretaceous, Upper Cretaceous and Paleogene. There are many middle porosity reservoirs and low permeability reservoirs, such as sandstone and local carbonate in rift period, sandstone of delta and deep water gravity flow in the rifted thermal subsidence and passive continental margin stages. Many seals were developed in the basins, regional seals in drifted stage and local seals in other stages, and the seals thickness change are enormous. There are eight plays in these basins which include Upper Cretaceous sandstone, Paleogene sandstone, Neogene sandstone, etc. The hydrocarbon exploration of deep water area during the passive continental margin stage should focus on Krishna and Cauvery river delta on the plane, and delta sandstone related to fault, low fan located at fault slope-break and near shore fan complex in vicinity of 85°E ridge and south offshore of Cauvery basin vertically.
  • Features, origin and distribution of microbial dolomite reservoirs: A case study of 4th Member of Sinian Dengying Formation in Sichuan Basin, SW China
    CHEN Yana, SHEN Anjiang, PAN Liyin, ZHANG Jie, WANG Xiaofang
    Petroleum Exploration and Development. 2017, 44(5): 704-715. https://doi.org/10.11698/PED.2017.05.05
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the drilling cores and slice observations, single well data and geochemical analysis, this paper analyzed features, origin and distribution of the 4th Member reservoirs of Sinian Dengying Formation (Z2dn4) in the Sichuan Basin. It is demonstrated that the main reservoir is a set of microbial dolomites. The discovery of spherical dolomite has revealed that the dolomitization was related to the microbial action, belonging to the early protodolomite of low-temperature precipitation; the primary matrix pores and the penecontemporaneous eroded pores constituted the subject of the reservoir space, which was not due to the interlayer karst process related to the Tongwan Movement and burial-hydrothermal dissolutional process. The microbial mound-shoal complex and penecontemporaneous dissolution mainly control the development and distribution of the scaled reservoirs in Z2dn4. The microbial dolomite reservoir surrounding the intracratonic rift had a large thickness, good continuity and high quality, and was an important target of the survey.
  • Karst monadnock fine characterization and reservoir control analysis: A case from Ordovician weathering paleokarst reservoirs in Lungu area, Tarim Basin, NW China
    ZHANG Yunfeng, TAN Fei, QU Haizhou, ZHONG Zhiqi, LIU Yong, LUO Xinsheng, WANG Zhenyu, QU Fang
    Petroleum Exploration and Development. 2017, 44(5): 716-726. https://doi.org/10.11698/PED.2017.05.06
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    Based on the fine characterization of weathering crust paleokarst landform of the Ordovician Yingshan Formation in Lungu area, Tarim Basin, the size, number and reservoir controlling characteristics of karst monadnocks have been investigated quantitatively. Impression method and karst monadnock volume formulas were employed to characterize the various levels of karst microtopography, to work out the number, relative relief, area, volume and other parameters of monadnocks, and analyze the reservoir development situation at different parts of monadnock. The results showed that the weathering crust karst reservoirs in Lungu area are 140-160 m in relative altitude, and thinning from karst highland to karst slope and terrace. Two hundred fifty-two karst monadnocks have been identified in the study area. Among them, typeⅠand typeⅡmonadnocks are fewer in number, but larger in bulk volume, and are favorable reservoir development zone. The monadnocks have a high coincidence ratio with current structural high points of 96.42%, and the monadnock morphology has remained basically unchanged during the late tectonic movement, thus “karstification-reservoir-accumulation” configuration has been kept good. In the main part (core) of karst monadnocks, there are cave, vug, fracture-vug, and fracture reservoirs, thicker high quality reservoir, and all reservoir parameters are better than those of karst monadnock wings. It is found that the relative amplitude of karst monadnock is positively correlated with single well productivity, and the scale and position of monadnock are closely related with productivity.
  • Genetic types and sedimentary model of sandbodies in a shallow-water delta: A case study of the first Member of Cretaceous Yaojia Formation in Qian’an area, south of Songliao Basin, NE China
    ZHANG Li, BAO Zhidong, LIN Yanbo, CHEN Yuming, LIN Xiaohai, DOU Luxing, KONG Bin
    Petroleum Exploration and Development. 2017, 44(5): 727-736. https://doi.org/10.11698/PED.2017.05.07
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    Based on outcrop, core, logging and mud logging data, and modern deposition analog, the sandbodies genetic types and spatial distribution in different facies belts of the shallow water delta in the first Member of Cretaceous Yaojia Formation (K2y1) of Qian’an area in Changling sag of southern Songliao Basin were analyzed, and the sedimentary model of shallow water delta was established according to deposition process. Active channel sandbodies, point bar sandbodies and bifurcation bar sandbodies in distributary channels and complex sandbodies formed the main sandbodies in the delta plain, while terminal distributary channels and mouth bar sandbodies formed the main sandbodies in the delta front. The delta prograded gradually under the construction of river mouth and reconstruction of river erosion, the early delta front evolved into delta plain and was reformed by distributary channels, and new delta fronts were formed at the river mouth ahead constantly. Under the control of the above deposition process, the size of main distributary channels in delta plain-delta front declined, while mouth bars developed increasingly. The sandbodies of different genetic types formed framework of river-dominated shallow water delta. The point bar and active channel sandbodies in main distributary channels of the delta, with the best reservoir quality, are lithologic reservoir targets in future exploration.
  • Hydrogeochemistry of the Arctic areas of Siberian petroleum basins
    DMITRY Novikov Anatolievich, SARAEV Mikhail Mikhailovich
    Petroleum Exploration and Development. 2017, 44(5): 737-744. https://doi.org/10.11698/PED.2017.05.08
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    The available hydrogeochemical data collected over the past four decades in Siberian Arctic areas were analyzed and interpreted comprehensively for the first time, through data ranking, evaluation and analysis, systematic estimation of region, altitude background and abnormal value, and calculation of element molar ratio, different kinds of correlation coefficients in water proximity were estimated. Paleohygdrogeological reconstructions of the Siberian sedimentary basins suggest the presence of three water genetic types in petroleum deposits: (1) Waters that formed during marine sedimentation, (2) Waters of meteoric origin that infiltrated the basin and were involved in supergene processes in the geological past, (3) Waters produced by condensation from a hydrocarbon mixture. Hydrogeochemical patterns of petroleum deposits are controlled by the long geological evolution in the water-rock-gas-organic matter system. Sodium-chloride bicarbonate, sodium chloride, calcium chloride groundwaters, and other types of brines with the total salinity of 0.2-350 g/L are distributed in the Siberian Arctic sedimentary basins. Comparative analysis of groundwaters and brines in the Siberian Arctic revealed a group of sodium chloride water samples had a total salinity of over 250 g/L, suggesting the formation of the brine was related to leaching of evaporite rock. Hydrogeochemical data indicate that composition of the brine has varied dramatically with their evolution. Mesozoic groundwaters and brines of Anabar-Laptev basin and West Siberia existed only in the beginning of their chemical evolution.
  • Evaluation method of the least horizontal principal stress by logging data in anisotropic fast formations
    LIU Zhonghua, SONG Lianteng, WANG Changsheng, SUN Ting, YANG Xiaoming, LI Xia
    Petroleum Exploration and Development. 2017, 44(5): 745-752. https://doi.org/10.11698/PED.2017.05.09
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    For transverse isotropic fast formations, the evaluation method of the least horizontal principal stress by using logging data is an important unresolved issue. An innovative method is proposed to solve this problem by derivation of five independent stiffness coefficients (C11, C33, C44, C66 and C13) in this kind of formation. Based on the functional relations between acoustic anisotropy coefficients and clay volume, and that between different stiffness coefficients, which are all approved by the assorted experiment data, an effective method is built to calculate the stiffness coefficients and the least horizontal stress of anisotropic fast formations. Successful applications in the Ordos Basin illustrate that the method is complementary to that based on the horizontal shear wave velocity which is only fit for slow formations, and is applicable to evaluating rock mechanical parameters of tight oil and gas reservoirs and selecting intervals for fracturing and testing oil.
    • OILAND GAS FIELD DEVELOPMENT
  • Field control technologies of combustion assisted gravity drainage (CAGD)
    GUAN Wenlong, XI Changfeng, CHEN Long, Muhetar, GAO Chengguo, TANG Junshi, LI Qiu
    Petroleum Exploration and Development. 2017, 44(5): 753-760. https://doi.org/10.11698/PED.2017.05.10
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    The targets, strategies and approaches of the field controlling processes of combustion assisted gravity drainage (CAGD) are discussed based on the research of its mechanisms, advantages and defects. By taking fully advantage of gravity, CAGD process can produce the mobilized oil near the combustion front through the underlying horizontal well, serving as a possible solution for extra-heavy oil production in the Xinjiang oil field. However, unidirectional conning and breakthrough of combustion front are risky to happen during the field application of CAGD. Based on laboratory three-dimensional physical simulation experiments and the experience of former pilots, it is proposed that a gently upward sloping combustion front is beneficial for the steady drainage of mobilized oil and should be the target of CAGD control. Key production parameters like the maximum production rate and corresponding air injection rate during field application. are calculated with reservoir engineering approach and material balance theory. The maximum oil production rate of the CAGD pilot in Block Fengcheng, Xinjiang oil field, is 12.9 m3/d, and the air injection rate is 14 048 m3/d. To maximize the oil productivity and sustain combustion front moving forward steadily, the ignition position should be located at the mid-upper parts of the formation; the air injection rate at the early stage should keep slow and increase gradually; meanwhile, the production rate of flue gas should be 90% of the air injection rate. A pilot of CAGD was initiated in the Xinjiang Fengcheng Field on the basis of those research outcomes. By the end of 2016, Well Group FH005 in the pilot has succeeded in steady production for more than 400 days. Key aspects, involving the shape of combustion chamber, oil production of single horizontal producer, air oil ratio and the degree of oil upgrading are in accordance with what the development plan predicted.
  • Mechanism simulation of oil displacement by imbibition in fractured reservoirs
    WANG Jing, LIU Huiqing, XIA Jing, LIU Yuetian, HONG Cheng, MENG Qingbang, GAO Yang
    Petroleum Exploration and Development. 2017, 44(5): 761-770. https://doi.org/10.11698/PED.2017.05.11
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    The mechanism model of both static and dynamic imbibition considering capillary pressure and gravity was presented based on the imbibition mechanisms and seepage theory. The validation of the model was performed using published experiment data. Then, this model was employed to study the impacts of oil viscosity, matrix permeability, core size, interface tension, and displacement rate on imbibitions. The results show that, the recovery decreases as oil viscosity increases, and the initial imbibition rate is much faster for lower viscosity oil. Imbibitions recovery is positively related to matrix permeability, the differences of oil recovery for low-permeability to tight oil reservoirs are obvious. Imbibitions effect is negatively related to core size. If the interface tension is low, imbibitions cannot occur without consideration of gravity. But it can occur even in very low interface tension scenario with consideration of gravity. On the whole, the recovery first increases and then decreases as the interface tension decreases. The gravity and capillary play different roles at different ranges of interface tension. There exists an optimal value range of displacement rate in fractured reservoir, which should be optimized with a sufficient oil production rate to achieve higher recovery.
  • A computational method of critical well spacing of CO2 miscible and immiscible concurrent flooding
    CHI Jie, JU Binshan, LYU Guangzhong, ZHANG Xing, WANG Jiabei
    Petroleum Exploration and Development. 2017, 44(5): 771-778. https://doi.org/10.11698/PED.2017.05.12
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    Based on the theory of non-Darcy seepage, a mathematical model for CO2 miscible and immiscible concurrent flooding considering changes of oil viscosity and threshold pressure gradient of oil and CO2 is established. A computational method of critical well spacing of CO2 miscible and immiscible concurrent flooding in ultra-low permeability reservoirs is deduced by solving the distribution of CO2 concentration in miscible flooding area with the mass transfer-diffusion-absorption equation and solving the saturation equation of immiscible affected area with characteristic line method. A critical well spacing example is built in the F142 and G89 reservoir blocks and the results show: (1) The critical well spacing increases with gas injection pressure, while decreases with gas injection speed; (2) The contribution of length in pure CO2 seepage area to the critical well spacing is the largest, the contribution of length in CO2-Oil effective mass transfer area and immiscible affected area is secondary, the contribution of pure oil area is the least, the gap of length between pure CO2 seepage area and CO2-Oil effective mass transfer area and immiscible affected area decreases with gas injection speed and it increases with the decreasing of gas injection speed, meanwhile, the law is more significant; (3) Pressure drop gradient of miscible affected area is significantly different from that of immiscible affected area and pressure drop gradient of CO2-Oil effective mass transfer area in miscible affected area is bigger than that of immiscible affected area.
  • Experiments on gas supply capability of commingled production in a fracture-cavity carbonate gas reservoir
    WANG Lu, YANG Shenglai, LIU Yicheng, XU Wei, DENG Hui, MENG Zhan, HAN Wei, QIAN Kun
    Petroleum Exploration and Development. 2017, 44(5): 779-787. https://doi.org/10.11698/PED.2017.05.13
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    The CT scan, mercury intrusion test and commingled production physical simulation experiment of the cores of pore-type, cavity-type and fracture-cave reservoirs was conducted to study the effects of interlayer heterogeneity, drawdown pressure, water saturation and water invasion on gas supply capacity. The experimental results were verified by the radial numerical model of multilayer commingled production based on the Eclipse software. The experimental results showed that: the fracture-cavity type reservoir, with strong seepage capability, makes great contribution to gas production in the early stage, while the pore-type and cavity-type reservoirs with weak seepage capability, make more contribution to gas production in the middle and late stages; the absolute permeability of the reservoir affects its contribution to productivity, while the relative permeability of reservoir affects the total recovery; the “dynamic supply balance” state among various reservoirs can be achieved at a reasonable drawdown pressure; although the fracture-cavity reservoir is less affected by edge and bottom water, water breakthrough will first occur in this type reservoir and block other reservoirs, significantly reducing the commingled gas supply capacity and recovery.
    • PETROLEUM ENGINEERING
  • Directional deflection equations for steerable drilling tools and the control mechanism of wellbore trajectory
    LIU Xiushan
    Petroleum Exploration and Development. 2017, 44(5): 788-793. https://doi.org/10.11698/PED.2017.05.14
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    To meet the wellbore trajectory control requirements for all kinds of steering drilling modes, the directional deflection equations for steerable drilling tools and the process control method for wellbore trajectory were proposed and an application example was given. By proving that the orientation direction of steerable drilling tool was consistent with the principal normal direction of borehole trajectory, directional deflection equations for steerable drilling tools were established. By establishing the relation curves between the build-up rate and tool face angle, and the relationship between built-up rate and orientation azimuth angle of steerable drilling tool, a process control technique for wellbore trajectory was presented. The research shows that the build-up rate of steerable drilling tool determines the curvature of wellbore trajectory, the orientation direction of steerable drilling tool determines the principal normal direction of wellbore trajectory; the orientation azimuth angle and the tool face angle both have the orientation function, and they can calculate and complement each other. These research results reveal the interaction mechanism and control mechanism between steerable drilling tools and wellbore trajectory, so the control scheme of wellbore trajectory can be formed based on the planned wellbore trajectory, and operating characteristics of steerable drilling tool can be controlled and monitored while drilling.
  • Key evaluation techniques in the process of gas reservoir being converted into underground gas storage
    ZHENG Dewen, XU Hongcheng, WANG Jieming, SUN Junchang, ZHAO Kai, LI Chun, SHI Lei, TANG Ligen
    Petroleum Exploration and Development. 2017, 44(5): 794-801. https://doi.org/10.11698/PED.2017.05.15
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    Due to the significant differences in development modes and operation rules of underground gas storage (UGS) and gas reservoir, the design of UGS construction has its own particularity and complexity. Key evaluation techniques in the process of gas reservoir being converted into underground gas storage were proposed and field application was analyzed. The construction and operation experience of the first batch commercial UGS in China was summarized, the mechanisms of multi-cycle injection and production with large flux in short-term was examined and some concepts were proposed such as the dynamic sealing of traps, the effective pore volume of UGS and the high velocity unstable seepage flow with finite supply. Four key technologies of UGS, i.e., trap sealing evaluation, gas storage parameter design, well pattern optimization and monitoring programs design were created. Preservation condition, storage capacity, effective injection & production and safe operation technology problems of UGS were solved respectively. The geological program design technology system of UGS construction in a gas field was gradually enriched and improved. These technologies have successfully guided geological plan design and implementation of UGS construction in a gas reservoir, the effects of dilatancy and production were great, and the actual dynamic was very consistent with design indicators.
  • Application of silica nanofluid to control initiation of fines migration
    HASANNEJADA Reza, POURAFSHARY Peyman, VATANI Ali, SAMENI Abdolhamid
    Petroleum Exploration and Development. 2017, 44(5): 802-810. https://doi.org/10.11698/PED.2017.05.16
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    Core flooding experiment was carried out through SiO2 nanofluid, which was used to change the surface properties of the pore walls, improve the attractive force between fines and pores walls against the hydrodynamic repulsive force in order to increase the critical velocity and injection rate and control fines migration. Injecting SiO2 nanoparticles has the great potential to control fines migration during water injection, which means that the higher fluid production/injection rate can be designed. The flooding test results indicated that SiO2 nanofluid with mass fraction of 0.1% showed the best performance and reduced the migration of fines by 80%. Increasing the salinity of the injection fluid had no effect on the nanofluid performance in controlling the fines migration. Measurement of the Zeta potential of the core surface showed that the SiO2 nanofluid did not change the Zeta potential of the pore walls due to the negative charge of SiO2 nanoparticles. AFM (Atomic Force Microscope) analysis proved that the SiO2 nanofluid increased the roughness of the pore walls was the main mechanism controlling fines migration and more hydrodynamic force was needed for fines movement in the porous medium. Also, for all the experiments, the total applied forces and torques on the fine particles were calculated. The theoretical results were in good agreement with the experiments, which proved that the fines migrated by rolling mechanism mainly.
  • An experimental study to quantify sand production during oil recovery from unconsolidated quicksand formations
    PERERA M S A, RANJITH P G, RATHNAWEERA T D, DE SILVA G P D, LIU T
    Petroleum Exploration and Development. 2017, 44(5): 811-816. https://doi.org/10.11698/PED.2017.05.17
    Abstract ( ) Download PDF ( ) Knowledge map Save
    To obtain a comprehensive understanding on sand production and main factors affecting sand production in unconsolidated quicksand oil reservoirs during their production stage, the sand production processes under different conditions have been modelled. The modelling experiment was carried out on unconsolidated sand formation model made of water washed white sand, clay (kaolinite) and distilled water, by using a newly developed sanding modelling apparatus. The effects of drag force acting on the formation and formation cementation on sand production were analysed. The experimental results show sand and oil production rates both increase with the rise of drag force acting on the formation and decrease with the increase of cement content, and the sand production rate even approaches zero at high cement content. The reservoir with higher pressure is more likely to produce sand during development due to higher drag force, and drag force and effective formation stress jointly affect oil production. Therefore, the sand production rate can be estimated according to clay content, and proper sanding prevention measures can be taken correspondingly. In some cases, sand production in oil reservoirs can be much greater than that in gas reservoirs.
    • COMPREHENSIVE RESEARCH
  • Control factors of high and stable production of Jurassic Da’anzhai Member tight oil in central Sichuan Basin, SW China
    YANG Guang, HUANG Dong, HUANG Pinghui, YAN Weipeng, YANG Tianquan, DAI Hongming, LIN Jianping
    Petroleum Exploration and Development. 2017, 44(5): 817-826. https://doi.org/10.11698/PED.2017.05.18
    Abstract ( ) Download PDF ( ) Knowledge map Save
    By systematically analyzing the basic geological characteristics of tight oil in Jurassic Da’anzhai Member in the middle of Sichuan Basin (Central Sichuan area) and combining with a large number of exploration and development data, we examine the main controlling factors and exploration direction for high and stable production of tight oil. Tight oil in the Da’anzhai Member has the following characteristics: large and low abundance resources; generally tight, relatively high quality reservoirs; adjacent source rocks and reservoirs, favorable migration and accumulation of oil; extensive oil-bearing pores. Development practice reveals that the high and stable production oil wells for tight oil are mainly distributed in fractured vuggy reservoirs in the shore-lacustrine sedimentary subfacies, and fractures are very important in affecting the high and stable production of tight oil in the Da'anzhai Member. Natural gas plays an important role (gas drive) in petroleum migration and accumulation and high production of oil wells. Combined with the characteristics of high and stable production, exploration and development results, drilling cost and other factors, it is considered that the Da’anzhai Member located in the middle and south part of Sichuan Basin is a promising field for exploration and development of tight oil in the Jurassic of the Sichuan Basin.
    • ACADEMIC DISCUSSION
  • A tight sandstone trapezoidal pore oil saturation model
    HU Shengfu, ZHOU Cancan, LI Xia, LI Chaoliu, ZHANG Shengqiang
    Petroleum Exploration and Development. 2017, 44(5): 827-836. https://doi.org/10.11698/PED.2017.05.19
    Abstract ( ) Download PDF ( ) Knowledge map Save
    "Non-Archie" phenomena are common in tight sandstone reservoirs with complicated pore structure, bringing challenges to the logging evaluation of tight sandstone. Based on the characteristics of tight sandstone pore structure, a new trapezoidal pore saturation model considering the effect of pore structure on rock conductivity is presented, in which the pore in tight sand is divided into straight pore with constant cross-sectional area and trapezoidal pore with variable cross-sectional area, and the total rock resistance is taken as the parallel resistance of these two parts to compressively consider the influence of pore structure and conductive volume on rock conductivity. The model parameters are studied by reconstructing the trapezoidal pore structure. Based on the trapezoidal pore reconstruction, characterization methods of model parameters were studied under the constraint of rock electrical properties test, and the variation was revealed of tortuosity, straight pore proportion and trapezoidal factors. The model was used in logging evaluation of tight sandstone of several wells, the results show the oil saturation obtained from the new model considering the effect of pore structure on electrical properties from the aspects of pore length and pore cross-section is in good accordance with the real regularity and petrophysical characteristics of the reservoir, and much closer to the formation oil-bearing conditions than that from the Archie model.
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