20 June 2018, Volume 45 Issue 3
    

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    PETROLEUM EXPLORATION
  • Geological characteristics of shale rock system and shale oil exploration in a lacustrine basin: A case study from the Paleogene 1st sub-member of Kong 2 Member in Cangdong sag, Bohai Bay Basin, China
    ZHAO Xianzheng, ZHOU Lihong, PU Xiugang, JIN Fengming, HAN Wenzhong, XIAO Dunqing, CHEN Shiyue, SHI Zhannan, ZHANG Wei, YANG Fei
    Petroleum Exploration and Development. 2018, 45(3): 361-372. https://doi.org/10.11698/PED.2018.03.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    A deep understanding of the basic geologic characteristics of the fine-grained shale layers in the Paleogene 1st sub-member of Kong 2 Member (Ek21) in Cangdong sag, Bohai Bay Basin, is achieved through observation of 140 m continuous cores and systematic analysis of over 1 000 core samples from two wells. Basic geological conditions for shale oil accumulation are proposed based on the unconventional geological theory of oil and gas. The shale rock system mainly developed interbedded formation of felsic shale, limy and dolomite shale and carbonates; high quality hydrocarbon source rock formed in the stable and closed environment is the material base for shale oil enrichment; intergranular pores in analcite, intercrystalline pores in dolomite and interlayer micro-fractures make tight carbonate, limy and dolomite shale and felsic shale effective reservoirs, with brittle mineral content of more than 70%; high abundance laminated shale rock in the lower section of Ek21 is rich in shale oil, with a total thickness of 70 m, burial depth between 2 800 to 4 200 m, an average oil saturation of 50%, a sweet spot area of 260 km2 and predicted resources of over 5×108 t. Therefore, this area is a key replacement domain for oil exploration in the Kongdian Formation of the Cangdong sag. At present, the KN9 vertical well has a daily oil production of 29.6 t after fracturing with a 2 mm choke. A breakthrough of continental shale oil exploration in a lacustrine basin is expected to be achieved by volume fracturing in horizontal wells.
  • Formation patterns of Chang 9 oil reservoir in Triassic Yanchang Formation, Ordos Basin, NW China
    YAO Jingli, ZHAO Yande, LIU Guanglin, QI Yalin, LI Yuanhao, LUO Anxiang, ZHANG Xiaolei
    Petroleum Exploration and Development. 2018, 45(3): 373-384. https://doi.org/10.11698/PED.2018.03.02
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    Based on analysis of main controlling factors of Chang 9, the source rock, driving force of migration, migration and accumulation modes, reservoir forming stages and model and enrichment law of Chang 9 reservoir were examined. The study showed that the oil of Chang 9 reservoir in the Jiyuan and Longdong areas came primarily from the source rock of Chang 7 Member, but the oil of Chang 9 reservoir in the Zhidan area came primarily from the source rock of Chang 9 Member. There developed lithologic-structural oil reservoirs in Gufengzhuang- Mahuangshan area in northwest Jiyuan, structural-lithologic oil reservoirs in east Jiyuan, and lithologic reservoirs in Huachi-Qingyang area and Zhidan area. The overpressure of Chang 7 Member was the driving force of oil migration. The burial history showed that Chang 9 Member experienced two stages of reservoir forming, the reservoir formed in the Late Jurassic was smaller in charging scope and scale, and the Early Cretaceous was the period when the source rock generated oil and gas massively and the Chang 9 reservoir came into being. Along with the tectonic movements, Chang 7 bottom structure turned from high in the west and lower in the East in the sedimentary stage to high in the east and lower in the west in the hydrocarbon accumulation stage and at last to gentle western-leaning monoclinal structure at present. In Early Cretaceous, the Chang 7 bottom structure was the lowest in the west of Huanxian-Huachi-Wuqi-Dingbian areas, so the oil migrated laterally towards the higher positions around after entering the reservoir. In the main reservoir forming period, Chang 7 bottom had an ancient anticline in Mahuangshan-Hongjingzi area of west Jiyuan, controlling the oil reservoir distribution in west Jiyuan.
  • Lower limit of thermal maturity for the carbonization of organic matter in marine shale and its exploration risk
    WANG Yuman, LI Xinjing, CHEN Bo, WU Wei, DONG Dazhong, ZHANG Jian, HAN Jing, MA Jie, DAI Bing, WANG Hao, JIANG Shan
    Petroleum Exploration and Development. 2018, 45(3): 385-395. https://doi.org/10.11698/PED.2018.03.03
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the drilling data of the Silurian Longmaxi Formation in the Sichuan Basin and periphery, SW China, the Ro lower limits and essential features of the carbonization of organic matter in over-high maturity marine shale were examined using laser Raman, electrical and physical property characterization techniques. Three preliminary conclusions are drawn: (1) The lower limit of Ro for the carbonization of Type I-II1 organic matter in marine shale is 3.5%; when the Ro is less than 3.4%, carbonization of organic matter won’t happen in general; when the Ro ranges from 3.4% to 3.5%, non-carbonization and weak carbonization of organic matter may coexist; when the Ro is higher than 3.5%, the carbonization of organic matter is highly likely to take place. (2) Organic-rich shale entering carbonization phase have three basic characteristics: log resistivity curve showing a general “slender neck” with low-ultralow resistance response, Raman spectra showing a higher graphite peak, and poor physical property (with matrix porosity of only less than 1/2 of the normal level). (3) The quality damage of shale reservoir caused by the carbonization of organic matter is almost fatal, which primarily manifests in depletion of hydrocarbon generation capacity, reduction or disappearance of organic pores and intercrystalline pores of clay minerals, and drop of adsorption capacity to natural gas. Therefore, the lower limit of Ro for the carbonization of Type I-II1 organic matter should be regarded as the theoretically impassable red line of shale gas exploration in the ancient marine shale formations. The organic-rich shale with low-ultralow resistance should be evaluated effectively in area selection to exclude the high risk areas caused by the carbonization of organic matter. The target organic-rich shale layers with low-ultralow resistance drilled during exploration and development should be evaluated on carbonization level of organic matter, and the deployment plan should be adjusted according to the evaluation results in time.
  • Model construction of micro-pores in shale: A case study of Silurian Longmaxi Formation shale in Dianqianbei area, SW China
    CHEN Keluo, ZHANG Tingshan, CHEN Xiaohui, HE Yingjie, LIANG Xing
    Petroleum Exploration and Development. 2018, 45(3): 396-405. https://doi.org/10.11698/PED.2018.03.04
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on scanning electron microscopy and nitrogen adsorption experiment at low temperature, the pore types and structures of the Longmaxi Formation shale in the Dianqianbei area, SW China were analyzed, and a molecular model was built. According to mathematical statistics, the validation of the model was solved by converting it into a mathematical formula. It is found by SEM that the pores in clay mineral layers and organic pores occupy most of the pores in shale; the nitrogen adsorption experiment at low temperature reveals that groove pores formed by flaky particles and micro-pores are the main types of pores, and the results of the two are in good agreement. A molecular model was established by illite and graphene molecular structures. Moreover, based on the fractal theory and the Frenkel-Halsey-Hill formula, a modified Frenkel-Halsey-Hill formula was proposed. The reliability of the molecular model was verified to some extent by obtaining parameters such as the fractal dimension, replacement rate and fractal coefficients of correction, and mathematical calculation. This study provides the theoretical basis for quantitative study of shale reservoirs.
  • Quantitative seismic prediction of shale gas sweet spots in Lower Silurian Longmaxi Formation, Weiyuan area, Sichuan Basin, SW China
    ZENG Qingcai, CHEN Sheng, HE Pei, YANG Qing, GUO Xiaolong, CHEN Peng, DAI Chunmeng, LI Xuan, GAI Shaohua, DENG Yu, HOU Huaxing
    Petroleum Exploration and Development. 2018, 45(3): 406-414. https://doi.org/10.11698/PED.2018.03.05
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Sweet spots in the shale reservoirs of the Lower Silurian Longmaxi Formation in Block Weiyuan 201 of Sichuan Basin were predicted quantitatively using seismic data and fuzzy optimization method. First, based on seismic and petrophysical analysis, the petrophysical features of reservoir rock were determined, and elastic parameters sensitive to high gas content shale were selected; second, high resolution data volumes of the elastic parameters were obtained from prestack simultaneous inversion, and the planar distribution of key parameters of shale gas evaluation were calculated based on the results of petrophysical analysis; third, the fuzzy evaluation equation was established by fuzzy optimization method with test and logging data of horizontal wells with similar operation conditions; fourth, key parameters affecting the productivity of horizontal wells were sorted out and the proportions of them in the sweet spot quantitative prediction were worked out by fuzzy optimization to set up a sweet spot evaluation system. Three classes of shale gas reservoirs and 2 kinds of sweet spots were predicted with the above procedure, and the sweet spots have been predicted quantitatively by combining the above prediction results with the testing production. The testing results of 7 verification wells proved the reliability of the prediction results.
  • Simulation for the dissolution mechanism of Cambrian carbonate rocks in Tarim Basin, NW China
    PENG Jun, WANG Xuelong, HAN Haodong, YIN Shen, XIA Qingsong, LI Bin
    Petroleum Exploration and Development. 2018, 45(3): 415-425. https://doi.org/10.11698/PED.2018.03.06
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Carbonate dissolution during the process of burial and evolution by percolating acid fluid was simulated using core plugs to analyze the characteristics and controlling factors of Cambrian carbonate rock dissolution in the Tarim Basin. The results showed that mineral composition and reservoir space type control selective dissolution. In the carbonate rock strata with high calcite content, the calcite is likely to dissolve first to form secondary dissolution pores; gypsum and anhydrite in the carbonate rock can be dissolved to form mold pores in contemporaneous and penecontemporaneous stages. Porous carbonate has mainly enlargement of matrix pores, with porosity and permeability increasing correspondingly, but not obviously. In comparison, dominant channels for fluid are likely to occur in fractured carbonate or porous carbonate forming cracks under high pressure, resulting in a relative reduction in the dissolution volume, but great increase of permeability. With the rise of temperature and pressure, corrosion ability of acid fluid to carbonate increases first and then decreases, there exists an optimum range of temperature and pressure for dissolution, which corresponds to the buried depth of 2 250-3 750 m of the Cambrian. Considering reservoir characteristics of the study area, it is concluded that calcite in the penecontemporaneous period is the material basis for the development of dissolution pore, and carbonate rocks were mainly dissolved by early atmospheric fresh water, superimposed and reformed to form high quality reservoirs by multiple acid fluids including deep heat fluid and acid fluid generated during the process of organic thermal evolution under burial depth condition.
  • Fluid charging and hydrocarbon accumulation in the Cambrian Longwangmiao Formation of Moxi Structure, Sichuan Basin, SW China
    XU Fanghao, YUAN Haifeng, XU Guosheng, LUO Xiaoping
    Petroleum Exploration and Development. 2018, 45(3): 426-435. https://doi.org/10.11698/PED.2018.03.07
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The multi-stage minerals filled in pore space were sequenced, and the charging stages of fluid and hydrocarbon were reconstructed based on the observation of drilling cores and thin sections, homogeneous temperature testing of fluid inclusions, Laser Raman composition analysis and isotope geochemical analysis. The Cambrian Longwangmiao Formation in the study area went through 5 stages of fluid charging, in which 3 stages, mid-late Triassic, early-mid Jurassic and early-mid Cretaceous, were related to oil and gas charging. Especially the oil and gas charging event in early-mid Cretaceous was the critical period of gas accumulation in the study area, and was recorded by methane gas inclusions in the late stage quartz. The 40Ar-39Ar dating of the 3rd stage methane inclusions shows that the natural gas charging of this stage was from 125.8±8.2 Ma. Analysis of Si, O isotopes and 87Sr/86Sr of the late stage quartz indicates that the fluid source of the quartz was formation water coming from long term evolution and concentration of meteoric water, but not from deep part or other sources, this also reflects that, in the critical charging period of natural gas, the Cambrian Longwangmiao Formation in Moxi structure had favorable conservation conditions for hydrocarbon accumulation, which was favorable for the formation of the Longwangmiao large natural gas pool.
  • Classification of microscopic pore-throats and the grading evaluation on shale oil reservoirs
    LU Shuangfang, LI Junqian, ZHANG Pengfei, XUE Haitao, WANG Guoli, ZHANG Jun, LIU Huimin, LI Zheng
    Petroleum Exploration and Development. 2018, 45(3): 436-444. https://doi.org/10.11698/PED.2018.03.08
    Abstract ( ) Download PDF ( ) Knowledge map Save
    On the basis of the characterization of microscopic pore-throats in shale oil reservoirs by high-pressure mercury intrusion technique, a grading evaluation standard of shale oil reservoirs and a lower limit for reservoir formation were established. Simultaneously, a new method for the classification of shale oil flow units based on logging data was established. A new classification scheme for shale oil reservoirs was proposed according to the inflection points and fractal features of mercury injection curves: microscopic pore-throats (less than 25 nm), small pore-throats (25-100 nm), medium pore-throats (100-1 000 nm) and big pore-throats (greater than 1 000 nm). Correspondingly, the shale reservoirs are divided into four classes, Ⅰ,Ⅱ, Ⅲ and Ⅳ according to the number of microscopic pores they contain, and the average pore-throat radii corresponding to the dividing points are 150 nm, 70 nm and 10 nm respectively. By using the correlation between permeability and pore-throat radius, the permeability thresholds for the reservoir classification are determined at 1.00× 10-3 μm2, 0.40×10-3 μm2 and 0.05×10-3 μm2 respectively. By using the exponential relationship between porosity and permeability of the same hydrodynamic flow unit, a new method was set up to evaluate the reservoir flow belt index and to identify shale oil flow units with logging data. The application in the Dongying sag shows that the standard proposed is suitable for grading evaluation of shale oil reservoirs.
  • Modeling of the whole hydrocarbon-generating process of sapropelic source rock
    LI Jian, MA Wei, WANG Yifeng, WANG Dongliang, XIE Zengye, LI Zhisheng, MA Chenghua
    Petroleum Exploration and Development. 2018, 45(3): 445-454. https://doi.org/10.11698/PED.2018.03.09
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on experimental data from hydrocarbon generation with a half-open system, hydrocarbon generation kinetics modeling in gold tube of closed system, high temperature pyrolysis chromatography mass spectrometry experiment with open system and geological data, the characteristics of whole hydrocarbon-generating process, hydrocarbon expulsion efficiency and retained hydrocarbon quantity, origins of natural gas generated in high-over mature stage and cracking temperature of methane homologs were investigated in this study. The sapropelic source rock has a hydrocarbon expulsion efficiency of 30%-60% and 60%-80% in the major oil generation window (with Ro of 0.8%-1.3%) and high maturity stage (with Ro of 1.3%-2.0%) respectively; and the contribution ratio of kerogen degradation gas to oil cracking gas in total generated gas in high maturity stage is about 1:4. The degradation gas of kerogen accounts for 20%, the retained liquid hydrocarbon cracking gas accounts for 13.5%, and the amount of out-reservoir oil cracking gas (including aggregation type and dispersed oil cracking gas) accounts for 66.5%. The lower limit of gas cracking is determined preliminarily. Based on the new understandings, a model of the whole hydrocarbon-generating process of source rock is built.
    • OIL AND GAS FIELD DEVELOPMENT
  • Advanced production decline analysis of tight gas wells with variable fracture conductivity
    SUN Hedong, OUYANG Weiping, ZHANG Mian, TANG Haifa, CHEN Changxiao, MA Xu, FU Zhongxin
    Petroleum Exploration and Development. 2018, 45(3): 455-463. https://doi.org/10.11698/PED.2018.03.10
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    Considering the characteristics that the fracture conductivity formed by hydraulic fracturing varies across space and time, a new mathematical model was established for seepage flow in tight gas fractured vertical wells which takes into account the effects of dual variable conductivity and stress sensitivity. The Blasingame advanced production decline curves of the model were obtained using the mixed finite element method. On this basis, the effects of fracture space and time dual variable conductivity and stress sensitivity on Blasingame curve were analyzed. The study shows that the space variable conductivity mainly reduces decline curve value at the early stage; the time variable conductivity can result in drops of the production and the production integral curves, leading to a S-shaped curve; dual variable conductivity is the superposition of the effects given by the two variable conductivities; both time and space variable conductivities cannot delay the time with which the formation fluid flow reaches the quasi-steady state. The stress sensitivity reduces the curve value gradually rather than sharply, delaying the time the flow reaching the quasi-steady state. Ignoring the effects of variable conductivity and stress sensitivity will not affect the estimation on well controlled dynamic reserves. However, it can result in large errors in the interpretation of fractures and reservoir parameters. Conventional advanced production decline analyses of a tight gas fractured well in the Sulige gas field showed that the new model is more effective and reliable than the conventional model, and thus it can be widely applied in advanced production decline analysis of wells with the same characteristics in other gas fields.
  • Characteristics and displacement mechanisms of the dispersed particle gel soft heterogeneous compound flooding system
    ZHAO Guang, DAI Caili, YOU Qing
    Petroleum Exploration and Development. 2018, 45(3): 464-473. https://doi.org/10.11698/PED.2018.03.11
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    Considering high temperature and high salinity in the reservoirs, a dispersed particle gel soft heterogeneous compound (SHC) flooding system was prepared to improve the micro-profile control and displacement efficiency. The characteristics and displacement mechanisms of the system were investigated via core flow tests and visual simulation experiments. The SHC flooding system composed of DPG particles and surfactants was suitable for the reservoirs with the temperature of 80-110 ℃ and the salinity of 1×104-10×104 mg/L. The system presented good characteristics: low viscosity, weak negatively charged, temperature and salinity resistance, particles aggregation capacity, wettability alteration on oil wet surface, wettability weaken on water wet surface, and interfacial tension (IFT) still less than 1×10-1 mN/m after aging at high temperature. The SHC flooding system achieved the micro-profile control by entering formations deeply and the better performance was found in the formation with the higher permeability difference existing between the layers, which suggested that the flooding system was superior to the surfactants, DPG particles, and polymer/surfactant compound flooding systems. The system could effectively enhance the micro-profile control in porous media through four behaviors, including direct plugging, bridging, adsorption, and retention. Moreover, the surfactant in the system magnified the deep migration capability and oil displacement capacity of the SHC flooding system, and the impact was strengthened through the mechanisms of improved displacement capacity, synergistic emulsification, enhanced wettability alteration ability and coalescence of oil belts. The synergistic effect of the two components of SHC flooding system improved oil displacement efficiency and subsequently enhanced oil recovery.
  • Mechanisms and influencing factors of the oil bank in fire flooding
    LI Qiu, YI Leihao, TANG Junshi, GUAN Wenlong, JIANG Youwei, ZHENG Haoran, ZHOU Jiuning, WANG Xiaochun
    Petroleum Exploration and Development. 2018, 45(3): 474-481. https://doi.org/10.11698/PED.2018.03.12
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    Based on the systematic summary of current research on oil bank, the definition of oil bank in the process of fire flooding and its quantitative indices were proposed; and a new one-dimensional positive dry-fire flooding model considering temperature gradient was established based on the steady flow theory of gas and liquid phases. Single factor analysis and orthogonal experiments were adopted to verify the reliability and reveal the formation mechanisms and the controlling factors of the oil bank. Then the optimal conditions for the oil bank to form were discussed. The study results show the formation of the oil bank is controlled by 3 factors: (1) Oil bank would come into being within a certain temperature interval and above a critical value of temperature gradient (absolute value), with temperature too high or too low and temperature gradient absolute value lower than the critical value, the oil bank couldn’t form. (2) For fire flooding process in heavy oil reservoirs, the viscosity of oil influences the width of oil bank and the speed at which oil bank forms; the lower the oil viscosity is, the wider the oil bank is and the faster the oil bank forms. (3) Oil saturation could affect the developing temperature and speed of oil bank. The favorable temperature at which oil bank develops gets lower and the accumulating speed of oil gets faster when the oil saturation is higher. By orthogonal experiments with the model, the optimal combinations of reservoir conditions for forming oil bank during fire flooding in heavy oil reservoirs can be worked out.
  • A quantitative evaluation for well pattern adaptability in ultra-low permeability oil reservoirs: A case study of Triassic Chang 6 and Chang 8 reservoirs in Ordos Basin
    ZHAO Jiyong, AN Xiaoping, WANG Jing, FAN Jianming, KANG Xingmei, TAN Xiqun, LI Wenqing
    Petroleum Exploration and Development. 2018, 45(3): 482-488. https://doi.org/10.11698/PED.2018.03.13
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    Based on the previous studies and development practice in recent 10 years, a quantitative evaluation method for the adaptability of well patterns to ultra-low permeability reservoirs was established using cluster analysis and gray correlation method, and it includes 10 evaluation parameters in the four aspects of optimal evaluation parameters, determination of weights for evaluation parameters, development stage division, and determination of classification coefficients. This evaluation method was used to evaluate the well pattern adaptability of 13 main ultra-low permeability reservoirs in Triassic Chang 6 and Chang 8 of Ordos Basin. Three basic understandings were obtained: Firstly, the well pattern for ultra-low permeability type-I reservoirs has generally good adaptability, with proper well pattern forms and well pattern parameters. Secondly, square inverted nine-spot well pattern is suitable for reservoirs with no fractures; rhombic inverted nine-spot injection pattern is suitable for reservoirs with some fractures; and rectangular well pattern is suitable for reservoirs with rich fractures. Thirdly, for the ultra-low permeability type-Ⅱ and type-Ⅲ reservoirs, with the principles of well pattern form determination, the row spacing needs to be optimized further to improve the level of development of such reservoirs.
    • PETROLEUM ENGINEERING
  • Key technologies and practice for gas field storage facility construction of complex geological conditions in China
    MA Xinhua, ZHENG Dewen, SHEN Ruichen, WANG Chunyan, LUO Jinheng, SUN Junchang
    Petroleum Exploration and Development. 2018, 45(3): 489-499. https://doi.org/10.11698/PED.2018.03.14
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    In view of complex geological characteristics and alternating loading conditions associated with cyclic large amount of gas injection and withdrawal in underground gas storage (UGS) of China, a series of key gas storage construction technologies were established, mainly including UGS site selection and evaluation, key index design, well drilling and completion, surface engineering and operational risk warning and assessment, etc. The effect of field application was discussed and summarized. Firstly, trap dynamic sealing capacity evaluation technology for conversion of UGS from the fault depleted or partially depleted gas reservoirs. A key index design method mainly based on the effective gas storage capacity design for water flooded heterogeneous gas reservoirs was proposed. To effectively guide the engineering construction of UGS, the safe well drilling, high quality cementing and high pressure and large flow surface injection and production engineering optimization suitable for long-term alternate loading condition and ultra-deep and ultra-low temperature formation were developed. The core surface equipment like high pressure gas injection compressor can be manufactured by our own. Last, the full-system operational risk warning and assessment technology for UGS was set up. The above 5 key technologies have been utilized in site selection, development scheme design, engineering construction and annual operations of 6 UGS groups, e.g. the Hutubi UGS in Xinjiang. To date, designed main indexes are highly consistent with actural performance, the 6 UGS groups have the load capacity of over 7.5 billion cubic meters of working gas volume and all the storage facilities have been running efficiently and safely.
  • Attenuation of microwave transmission in a diameter-variable drill string bore
    XIA Wenhe, MENG Yingfeng, TANG Bo, GUAN Wenting
    Petroleum Exploration and Development. 2018, 45(3): 500-506. https://doi.org/10.11698/PED.2018.03.15
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    With the drill string hole being regarded as an ultra-long irregular lossy cylindrical waveguide, the optimal frequency point for microwave transmission was calculated according to the electromagnetic wave coupling theory, the attenuation law and efficient transmission distance of microwave channel were obtained and the microwave mode in the waveguide was analyzed. Furthermore, the channel model and signal attenuation model were established by the microwave transmission equivalent circuit method. The power attenuation coefficient per unit of length was proposed to simplify the analysis on effective transmission distance for the ultra-long drill string. The optimal frequency points of 139.7 mm (5.5 in) and 127 mm (5 in) API drill pipes are 2.04 GHz and 2.61 GHz, respectively, and there are several inner diameter varying sections and break points in the drill string hole along the axial direction. The microwave transmission suffers a lot of reflections. The channel impedance change is a key factor affecting the transmission quality. The lab and field tests reveal that the attenuation model established in this paper is accurate, and it is helpful for guiding the design of microwave transmission measurement while drilling system.
  • A solids-free brine drilling fluid system for coiled tubing drilling
    WANG Xiaojun, YU Jing, SUN Yunchao, YANG Chao, JIANG Lizhou, LIU Chang
    Petroleum Exploration and Development. 2018, 45(3): 507-512. https://doi.org/10.11698/PED.2018.03.16
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    There are many problems associated with coiled tubing drilling operations, such as great circulation pressure loss inside pipe, difficulties in weight on bit (WOB) transferring, and high probability of differential sticking. Aiming at these problems, solids-free brine drilling fluid system was developed on the basis of formulation optimization with brine base fluid experiment, which was evaluated and applied to field drilling. Based on the optimization of flow pattern regulator, salt-resisting filtrate reducer, high performance lubricant and bit cleaner, the basic formula of the solids-free brine drilling fluid system was formed: brine + (0.1%-0.2%) NaOH + (0.2%-0.4%) HT-XC + (2.0%-3.0%) YLJ-1 + (0.5%-2.0%) SDNR + (1.0%-2.5%) FT-1A + (1.0%-5.0%) SD-505 + compound salt density regulator. Lab evaluation showed that the fluid had satisfactory temperature resistance (up to 150 ℃), excellent cuttings tolerance (up to 25%), and strong inhibition (92.7% cuttings recovery); Moreover, its lubrication performance was similar to that of all oil-based drilling fluid. The wellbore could be fairly cleaned at annular up-flow velocity of more than 0.8 m/s if the ratio of yield point to plastic viscosity was kept above 0.5. This fluid system has been applied in the drilling of three coiled tubing sidetracking wells in the Liaohe Oilfield, during which the system was stable and easy to adjust, resulting in excellent cuttings transportation, high ROP, regular hole size, and no down hole accidents. In summary, the solids-free brine drilling fluid system can meet the technical requirements of coiled tubing drilling.
  • A bull-heading water control technique of thermo-sensitive temporary plugging agent
    LIU Pingde, WEI Falin, ZHANG Song, ZHU Xiuyu, WANG Longfei, XIONG Chunming
    Petroleum Exploration and Development. 2018, 45(3): 513-519. https://doi.org/10.11698/PED.2018.03.17
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Aimed at the disadvantages of secondary damage to oil layers caused by the conventional bull-heading water control technique, a thermo-sensitive temporary plugging agent for water control was synthesized by water solution polymerization and applied in the field with a new secondary temporary plugging technique. The optimization and performance evaluation of thermo-sensitive temporary plugging agent were carried out through laboratory experiments. The optimized formula is as follows: (6% - 8%) acrylamide + (0.08% - 0.12%) ammonium persulfate + (1.5% - 2.0%) sepiolite + (0.5% - 0.8%) polyethylene glycol diacrylate. The thermo-sensitive temporary plugging agent is suitable for formation temperatures of 70-90 ℃, it has high temporary plugging strength (5-40 kPa), controllable degradation time (1-15 d), the apparent viscosity after degradation of less than 100 mPa•S and the permeability recovery value of simulated cores of more than 95%. Based on the research results, secondary temporary plugging technique was used in a horizontal well in the Jidong Oilfield. After treatment, the well saw a drop of water cut to 27%, and now it has a water cut of 67%, its daily increased oil production was 4.8 t, and the cumulative oil increment was 750 t, demonstrating that the technique worked well in controlling water production and increasing oil production.
    • COMPREHENSIVE RESEARCH
  • Division of “layer exploration unit” and high-efficiency exploration in mature exploration area
    SONG Mingshui, WANG Yongshi, LI Youqiang
    Petroleum Exploration and Development. 2018, 45(3): 520-527. https://doi.org/10.11698/PED.2018.03.18
    Abstract ( ) Download PDF ( ) Knowledge map Save
    To realize high-efficiency and sustainable exploration of the Jiyang depression at the stage of high exploration degree, a hydrocarbon accumulation-geological evaluation method is developed on the basis of current geologic knowledge and extent of fine exploration. The concept of “layer exploration unit” is proposed in the study, and it is defined as an exploration geological unit that has a relatively complete and unified tectonic system, sedimentary system and hydrocarbon migration & accumulation system in a tectonic layer or tectonic sublayer within a fault basin. Then, an approach to dividing and evaluating the “layer exploration unit” is developed. With this approach, the Jiyang depression is divided into 305 layer exploration units, thus helping realize precise and stereoscopic geological understanding and exploration deployment. Fine splitting of remaining resources and benefit evaluation of exploration targets are conducted by “layer exploration units”. As a result, 66 efficient “layer exploration units” in four major areas (i.e. Paleogene upper Es4-Dongying Formation, Neogene Minghuazhen Formation-Guantao Formation, Paleozoic buried-hill, and Paleogene Kongdian Formation-lower Es4) are determined as the targets for obtaining more reserves and breakthroughs in the short and medium term.
    • ACADEMIC DISCUSSION
  • A fault identification based on the parameter variation of apparent current
    LI Junguang, LI Diquan, YANG Yang
    Petroleum Exploration and Development. 2018, 45(3): 528-536. https://doi.org/10.11698/PED.2018.03.19
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    A new fault identification method, which is called the apparent current method, based on the parameter variation of apparent current is proposed after the analysis of the limitations of the fault interpretation method for the wide area electromagnetic data in the non-seismic exploration for oil and gas exploration. This method takes the study of the wide field electromagnetic theory and the mechanism of the fault generation, this method takes the wide field electromagnetic data as the research object, and establishes the connection between the geoelectric section and the virtual equivalent circuit, and then uses the virtual equivalent circuit as the carrier, and applies the theoretical equation of the apparent current, and combines the geological background of the study area to achieve scientific inference for location of fault in wide field electromagnetic exploration data. Theoretical model tests and the application of practical data proved that the location of underground fault can be accurately deduced by the trend of apparent current in underground space, reducing the multiple interpretations of electromagnetic data interpretation. At the same time, it also verified the correctness of the theory of apparent current and the feasibility of the method of apparent current.
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