20 February 2018, Volume 45 Issue 1
    

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    PETROLEUM EXPLORATION
  • Petroleum geological conditions and exploration importance of Proterozoic to Cambrian in China
    ZHAO Wenzhi, HU Suyun, WANG Zecheng, ZHANG Shuichang, WANG Tongshan
    Petroleum Exploration and Development. 2018, 45(1): 1-13. https://doi.org/10.11698/PED.2018.01.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The discovery of the giant Anyue gas field in Sichuan Basin gives petroleum explorers confidence to find oil and gas in Proterozoic to Cambrian. Based on the reconstruction of tectonic setting and the analysis of major geological events in Mesoproterozoic-Neoproterozoic, the petroleum geological conditions of Proterozoic to Cambrian is discussed in this paper from three aspects, i.e. source rocks, reservoir conditions, and the type and efficiency of play. It is found that lower organisms boomed in the interglacial epoch from Mesoproterozoic-Neoproterozoic to Eopaleozoic when the organic matters concentrated and high quality source rocks formed. Sinian-Cambrian microbial rock and grain-stone banks overlapped with multiple-period constructive digenesis may form large-scale reservoir rocks. However, because of the anoxic event and weak weathering effect in Eopaleozoic-Mesoproterozoic, the reservoirs are generally poor in quality, and only the reservoirs that suffered weathering and leaching may have the opportunity to form dissolution-reconstructed reservoirs. There are large rifts formed during Mesoproterozoic-Neoproterozoic in Huabei Craton, Yangtze Craton, and Tarim Craton in China, and definitely source rocks in the rifts, while whether there are favorite source-reservoir plays depends on circumstance. The existence of Sinian-Cambrian effective play has been proved in Upper Yangtze area. The effectiveness of source-reservoir plays in Huabei area depends on two factors: (1) the effectiveness of secondary play formed by Proterozoic source rock and Paleozoic, Mesozoic, Cenozoic reservoir rocks; (2) the matching between reservoirs formed by reconstruction from Mesoproterozoic- Neoproterozoic to Eopaleozoic and the inner hydrocarbon kitchens with late hydrocarbon generation. As for Tarim Basin, the time of Proterozoic and the original basin should be analyzed before the evaluation of the effective play. To sum up, Proterozoic to Cambrian in the three craton basins in China is a potential exploration formation, which deserves further investigation and research.
  • Discovery and theoretical and technical innovations of Yuanba gas field in Sichuan Basin, SW China
    GUO Xusheng, HU Dongfeng, LI Yuping, DUAN Jinbao, JI Chunhui, DUAN Hua
    Petroleum Exploration and Development. 2018, 45(1): 14-26. https://doi.org/10.11698/PED.2018.01.02
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    To solve the difficulties in exploration and development in Yuanba Great Ultra-deep Gas Feild in Sichuan Basin, SW China, the article studies the mechanism of development of quality reef reservoirs gas accumulation and innovates techniques for ultra-deep seismic exploration, drilling, completion and testing. Through the dynamic depositional evolution process of homoclinal ramp-fringed platform and reconstruction of regional depositional framework in the Permian, it is found that the reservoirs in the Changxing Formation of Yuanba area, Sichuan Basin are developed in a pattern of “early shoal and late reef, multiple stage stacking, in rows and belts”, dissolution in early exposure stage and dolomitization during shallow burial give rise to the pores in matrix, overpressure caused by cracking of liquid hydrocarbon during deep burial induces fractures, and coupling of pores and fractures controls the development of ultra-deep high quality reservoirs. From correlation of oil and source rock, it is concluded that the Wujiaping Formation and Dalong Formation of deep-water continental shelf are the major source rocks in the Permian of northern Sichuan Basin. The hydrocarbon accumulation mode in ultra-deep formations of low-deformation zones is characterized by “three-micro migration, near-source enrichment, and persistent preservation”. Through seismic inversion using the pore structure parameters of pore-fracture dual structure model, the high production gas enrichment area in Yuanba gas field is 98.5 km2. Moreover, special well structure and unconventional well structure were used to deal with multiple pressure systems and sealing of complex formations. A kind of integral, high pressure resistant FF-level gas wellhead and ground safety linkage device was developed to accomplish safe and environmentally friendly gas production.
  • Petroleum geology controlled by extensive detachment thinning of continental margin crust: A case study of Baiyun sag in the deep-water area of northern South China Sea
    PANG Xiong, REN Jianye, ZHENG Jinyun, LIU Jun, YU Peng, LIU Baojun
    Petroleum Exploration and Development. 2018, 45(1): 27-39. https://doi.org/10.11698/PED.2018.01.03
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    The relationships between crustal stretching and thinning, basin structure and petroleum geology in Baiyun deep-water area were analyzed using large area 3D seismic, gravity, magnetic, ocean bottom seismic (OBS), deep-water exploration wells and integrated ocean drilling program (IODP). During the early syn-rifting period, deep-water area was a half-graben controlled by high angle faults influenced by the brittle extension of upper crust. In the mid syn-rifting period, this area was a broad-deep fault depression controlled by detachment faults undergone brittle-ductile deformation and differentiated extension in the crust. In the late syn-rifting period, this area experienced fault-sag transition due to saucer-shaped rheology change dominated by crustal ductile deformation. A broad-deep fault depression controlled by the large detachment faults penetrating through the crust is an important feature of deep-water basin. The study suggests that the broad-deep Baiyun sag provides great accommodation space for the development of massive deltaic-lacustrine deposition system and hydrocarbon source rocks. The differentiated lithospheric thinning also resulted in the different thermal subsidence during post-rifting period, and then controlled the development of continental shelf break and deep-water reservoir sedimentary environment. The high heat flow background caused by the strong thinning of lithosphere and the rise of mantle source resulted in particularities in the reservoir diagenesis, hydrocarbon generation process and accumulation of deep-water area in northern South China Sea.
  • Structural patterns of fault broken zones in carbonate rocks and their influences on petroleum accumulation in Tazhong Paleo-uplift, Tarim Basin, NW China
    NENG Yuan, YANG Haijun, DENG Xingliang
    Petroleum Exploration and Development. 2018, 45(1): 40-50. https://doi.org/10.11698/PED.2018.01.04
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    Based on the outcrop survey, 3D seismic data interpretation, drilling data analysis, the structural patterns and distribution of fault broken zones in carbonate formations of Tazhong Paleo-uplift were established to reveal the oil and gas enrichment pattern in the fault broken zones. The following findings were reached: (1) Through the filed survey, the fault broken zone system consists of fault core, branch fault and fracture network. Affected by the active nature of the major faults, the fault broken zones differ in planar pattern and scale along the major faults. (2) 3D seismic profiles reveal that there are three types of fault broken zones in carbonate strata in Tazhong paleo-uplift, strike-slip fault broken zones, thrust fault broken zones and superimposed fault broken zones. Featuring 3 flowers and 6 belts, the strike-slip fault broken zone can be subdivided into linear type,inclined type, feather type and horsetail type. Thrust fault broken zones can be further divided into fault anticline type, anticline type and slope type. As the superimposition result of the above two kinds of fault broken zones, superimposed fault broken zones appear in three patterns, intersect type, encompassment type and penetrating type. (3) Cores from wells and geochemical data show oil and gas may migrate along the major fault and laterally. The feather type in strike-slip fault system, fault anticline type in thrust fault broken zone and intersect type in superimposed fault broken zone are possible sites for high production and efficiency wells.
  • Formation and evolution of oblique anticline in eastern Niger Delta
    SUN Yonghe, LI Xuesong, LIU Zhida, HU Guangyi, FAN Tingen, GAO Yunfeng
    Petroleum Exploration and Development. 2018, 45(1): 51-61. https://doi.org/10.11698/PED.2018.01.05
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    Based on the three-dimensional seismic interpretation data, this paper analyzed the formation mechanism and the growth process of the oblique anticline AE of the M region of the eastern Niger Delta, as well as the evolution process of the associated fault systems. The study results show that the stratigraphic sedimentary period between reflector H4-H6 of the middle and late Miocene was the initial fold-thrust stage, the anticline AE was a half-graben controlled by oblique extensional faults derived from the oblique extensional transfer structure formed by local initial differential fold-thrusting. At the same time the tear faults developed as a result of the differential sliding. During the stratigraphic sedimentary period between reflector H1-H4 of the late Miocene to Pliocene, the large-scale folding and thrusting occurred, differential contractional deformation resulted in the pre-existing extensional half-graben became AE anticline by oblique tectonic inversion, then the anticline grew continually and the crest of the anticline migrated gradually. The newly formed fault systems consist of a small number of associated tear-normal faults caused by differential thrusting and gravity-driven domino normal faults predominantly induced by the slope inclination of the anticline limb. During the stratigraphic sedimentary period between reflector H0-H1 of the Pleistocene to Holocene, as the growth of the anticline ceased, the area entered post-fold thrusting stage. The formation and distribution of conjugated faults were controlled by the local gravity return collapse, local differential sliding and reactivation of pre-existing positive inversion faults jointly. The research results of genetic mechanism of the oblique inversion anticline and evolution of associated faults are helpful to reveal the key factors controlling the accumulation and distribution of oil and gas.
  • Reservoir micro structure of Da’anzhai Member of Jurassic and its petroleum significance in Central Sichuan Basin, SW China
    PANG Zhenglian, TAO Shizhen, ZHANG Qin, YANG Jiajing, ZHANG Tianshu, YANG Xiaoping, FAN Jianwei, HUANG Dong, WEI Tengqiang
    Petroleum Exploration and Development. 2018, 45(1): 62-72. https://doi.org/10.11698/PED.2018.01.06
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    Based on the qualitative study of microscopic reservoir features using core analysis, cast and fluorescence thin sections inspection, scanning electron microscope (SEM) and field emission scanning electron microscope (FESEM) and quantitative examination of pore size and geometry using mercury injection, nano-CT and nitrogen adsorption, reservoir rock of Da’anzhai Member were divided into 9 types, while storage spaces were divided into 4 types and 14 sub-types. The study shows that sparry shelly limestone is the most promising reservoir type. Pores that smaller than 1 μm in diameter contribute 91.27% of storage space volume. Most of them exhibit slot-like geometry with good connectivity. By building up storage space models, it was revealed that micron scale storage spaces mainly composed of fractures and nanometer scale pores and fractures form multi-scale dual porosity system. Low resource abundance, small single well controlled reserve, and low production are related to the nano-scale pore space in Da’anzhai Memer, whereas the dual-porosity system composed of pores and fractures makes for long-term oil yield. Due to the existence of abundant slot-like pore space and fractures, economic tight oil production was achieved without stimulations.
  • Formation mechanism of tight sandstone gas in areas of low hydrocarbon generation intensity: A case study of the Upper Paleozoic in North Tianhuan depression in Ordos Basin, NW China
    ZHANG Fudong, LI Jun, WEI Guoqi, LIU Xinshe, GUO Jianying, LI Jian, FAN Zhiyong, SHE Yuanqi, GUAN Hui, YANG Shen, SHAO Liyan
    Petroleum Exploration and Development. 2018, 45(1): 73-81. https://doi.org/10.11698/PED.2018.01.07
    Abstract ( ) Download PDF ( ) Knowledge map Save
    As the Upper Paleozoic in the north part of Tianhuan depression in the Ordos Basin,NW China has lower hydrocarbon generation intensity and complex gas-water relationship, the main factors controlling the formation of tight sandstone gas and the distribution of tight sandstone gas in the low hydrocarbon generation intensity area are studied. Through two-dimensional physical simulation experiment of hydrocarbon accumulation, analysis of reservoir micro-pore-throat hydrocarbon system and dissection of typical gas reservoirs, the evaluation models of gas injection pressure, reservoir physical property, and gas generation threshold were established to determine the features of tight gas reservoirs in low hydrocarbon intensity area: (1) at the burial depth of less than 3 000 m, the hydrocarbon generation intensity of (7-10)×108 m3/km2 is high enough to maintain effective charging; (2) tight sandstone in large scale occurrence is conducive to accumulation of tight gas; (3) differences in reservoir physical property control the distribution of gas pool, for the channel sandstone reservoirs, ones with better physical properties generally concentrate in the middle of sandstone zone and local structural highs; ones with poor physical properties have low gas content generally. Based on the dissection of the gas reservoir in the north Tianhuan depression, the formation of tight gas reservoirs in low hydrocarbon generating intensity area are characterized by “long term continuous charging under hydrocarbon generation pressure, gas accumulation in large scale tight sandstone, pool control by difference in reservoir physical property, and local sweet spot”, and the tight gas pools are distributed in discontinuous “sheets” on the plane. This understanding has been proved by expanding exploration of tight sandstone gas in the north Tianhuan depression.
  • Reservoir controlling differences between consequent faults and antithetic faults in slope area outside of source: A case study of the south-central Wenan slope of Jizhong Depression, Bohai Bay Basin, NE China
    LIU Junqiao, WANG Haixue, LYU Yanfang, SUN Tongwen, ZHANG Mengdi, HE Wei, SUN Yonghe, ZHANG Tong, WANG Chao, CAO Lanzhu
    Petroleum Exploration and Development. 2018, 45(1): 82-92. https://doi.org/10.11698/PED.2018.01.08
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The control effects of different occurrence faults on oil and gas accumulation and distribution in the outer slope area of oil and gas reservoirs were studied taking the south-central Wen’an slope of the Jizhong depression in the Bohai Bay Basin as an example. Based on 3D seismic data and the distribution of oil and water, the controlling differences between consequent fault and antithetic fault were analyzed and compared from the formation and evolution rule of faults and the formation mechanism of fault traps, including development positions of the consequent fault traps and antithetic fault traps, oil and gas distribution horizon adjusted by fault and formation period of fault traps. The differences between consequent faults and antithetic faults in controlling reservoirs have three main aspects: (1) Consequent fault traps and antithetic fault traps are in different positions, the consequent fault traps are at the segmented growing point in the hanging wall of “hard-linkage” faults, while the antithetic fault traps are developed in the position with the largest throw in the footwall because of tilting action; (2) The two kinds of faults result in different oil and gas distribution vertically, oil and gas adjusted by consequent faults is distributed in a single layer or multi-layers, while oil and gas adjusted by antithetic faults occur in single layers; (3) The two kinds of fault traps are formed in different periods, the consequent fault traps are formed at the time when the related faults enter the stage of “hard-linkage”, while the antithetic fault traps are formed at the beginning of the fault active period.
  • Characteristics of deep water depositional system in Campos basin, Brazil
    KANG Hongquan, MENG Jinluo, CHENG Tao, JIA Huaicun, BAI Bo, LI Minggang
    Petroleum Exploration and Development. 2018, 45(1): 93-104. https://doi.org/10.11698/PED.2018.01.09
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    To make clear about the sedimentary facies types and distribution of deep water sandstone reservoirs in Campos basin of Brazil, this paper researches the characteristics of deep-water sedimentary system in Campos basin through the comprehensive analysis of drilling, logging and seismic data. There are 3 subfacies and 7 microfacies in the study area. There are 3 channels from south to north in Upper Cretaceous Maastrichtian, and the sedimentary incised valley and compound channels developed in micro-salt basin are the main deep water depositional types. The Paleocene to Eocene dominated by sedimentary incised valley and eroded compound channel deposits, also include 3 channel systems. From Oligocene to Miocene, the main deposition type is lobe, which is mainly distributed in central-north of the basin. Corresponding to deep water depositional stages, 3 kinds of depositional models are found. From Turonian to Maastrichtian of Upper Cretaceous, with tectonic uplift, strong source material supply, and the negative topography produced by salt rock movement providing favorable accommodation for sand deposition, the depositional model was terrigenous direct feed mechanism with sedimentary incised valley and compound channels in micro salt basin. From Paleocene to Eocene, as the amplitude of tectonic uplift reached the maximum and the accompanied erosion peaked, accommodation space offered by micro salt basin was leveled up; the depositional model was terrigenous direct feed mechanism with sedimentary valley and incised compound channels. From Oligocene to Miocene, because of sable tectonics, sea level fluctuation is the main controlling factor for deep water deposition, so the depositional model was wide shelf indirect feed mechanism with bypass incised valley and lobe. The analysis of the characteristics and controlling factors of the 3 types deep-water sedimentary systems during 3 different stages in Campos Basin can provide valuable reference for the oil exploration in deep-water deposits in the Campos Basin and across the world.
    • OIL AND GAS FIELD DEVELOPMENT
  • Applicable scope of oxygen-reduced air flooding and the limit of oxygen content
    LIAO Guangzhi, YANG Huaijun, JIANG Youwei, REN Shaoran, LI Dangguo, WANG Liangang, WANG Zhengmao, WANG Bojun, LIU Weidong
    Petroleum Exploration and Development. 2018, 45(1): 105-110. https://doi.org/10.11698/PED.2018.01.10
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The mechanisms of oxygen-reduced air flooding (ORAF) and the explosion limit and the corrosion control approaches were studied based on the pilots of oxygen-reduced air flooding (ORAF) in Dagang, Changqing and Daqing oil fields in China. On the foundation of indoor investigations and pilots, the explosion limits, oxygen reduction limits and corrosion control approaches were clarified. When the temperature of reservoir is equal to and higher than 120 ℃, there is a violent reaction between oxygen and crude oil, that means the effect of low temperature oxidation would be fully taken use of to enhance oil recovery by air flooding directly; nitrogen dominated immiscible flooding with oxygen-reduced air should be applied in cases where reservoir temperature is below 120 ℃ with little oxygen consumption and little heat generated. The oxygen-reduced air flooding is suitable for 3 types of reservoirs: low permeability reservoir, water flooding development reservoir of high water-cut and high temperature and high salinity reservoir. In the process of development, in order to ensure safety, the oxygen reduction limits should be controlled fewer than 10%, while oxygen-reduced air can obviously reduce the corrosion rate of pipes; The surface pipelines and injection wells don’t need to consider about oxygen corrosion with no water, special materials and structure of pipe or corrosion inhibitor can be applied to the surface pipelines and injection wellbores with water. Air/oxygen-reduced air is a low-cost displacement medium and it could be applied in many special conditions of low permeability reservoir for energy supplement, huff and puff and displacement, that means oxygen-reduced air flooding has become the most potential strategic technology in 20 years.
  • Efficient development strategies for large ultra-deep structural gas fields in China
    LI Xizhe, GUO Zhenhua, HU Yong, LUO Ruilan, SU Yunhe, SUN Hedong, LIU Xiaohua, WAN Yujin, ZHANG Yongzhong, LI Lei
    Petroleum Exploration and Development. 2018, 45(1): 111-118. https://doi.org/10.11698/PED.2018.01.11
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    Through analyzing the development of large ultra-deep structural gas fields in China, strategies for the efficient development of such gas fields are proposed based on their geological characteristics and production performance. According to matrix properties, fracture development degree and configuration between matrix and fractures, the reservoirs are classified into three types: single porosity single permeability system, dual porosity dual permeability system, and dual porosity single permeability system. These three types of gas reservoirs show remarkable differences in different scales of permeability, the ratio of dynamic reserves to volumetric reserves and water invasion risk. It is pointed out that the key factors affecting development efficiency of these gas fields are determination of production scale and rapid identification of water invasion. Figuring out the characteristics of the gas fields and working out pertinent technical policies are the keys to achieve efficient development. The specific strategies include reinforcing early production appraisal before full scale production by deploying high precision development seismic survey, deploying development appraisal wells in batches and scale production test to get a clear understanding on the structure, reservoir type, distribution pattern of gas and water, and recoverable reserves, controlling production construction pace to ensure enough evaluation time and accurate evaluation results in the early stage, in line with the development program made according to the recoverable reserves, working out proper development strategies, optimizing pattern and proration of wells based on water invasion risk and gas supply capacity of matrix, and reinforcing research and development of key technologies.
  • Shale high pressure isothermal adsorption curve and the production dynamic experiments of gas well
    DUAN Xianggang, HU Zhiming, GAO Shusheng, SHEN Rui, LIU Huaxun, CHANG Jin, WANG Lin
    Petroleum Exploration and Development. 2018, 45(1): 119-127. https://doi.org/10.11698/PED.2018.01.12
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    The high pressure static adsorption curves of shale samples from Silurian Changning-Weiyuan Longmaxi Formation were tested by using high pressure isothermal adsorption equipment. The physical modeling of depletion production was tested on single cores and multi-core series by using self-developed shale gas flow solid coupling experiment system. The adsorption and desorption laws were summarized and a high pressure isothermal adsorption model was established. The calculation formula of gas content was corrected, and the producing law of adsorption gas was determined. The study results show that the isothermal adsorption law of the shale reservoir under high pressure was different from the conventional low pressure. The high pressure isothermal adsorption curve had the maximum value in excess adsorption with pressure change, and the corresponding pressure was the critical desorption pressure. The high pressure isothermal curve can be used to evaluate the amount of adsorbed gas and the producing degree of adsorption gas. The high pressure isothermal adsorption model can fit and characterize the high pressure isothermal adsorption law of shale. The modified gas content calculation method can evaluate the gas content and the proportion of adsorbed gas more objectively, and is the theoretical basis of reserve assessment and production decline analysis. The producing degree of adsorption gas is closely related to the pressure, only when the reservoir pressure is lower than the critical desorption pressure, the adsorption gas can be produced effectively. In the process of gas well production, the pressure drop in the near-well area is large, the producing degree of adsorption gas is high, the adsorption gas is low in producing degree, or not produced at all, away from the wellbore.
  • Water-out performance and pattern of horizontal wells for marine sandstone reservoirs in Tarim Basin, NW China
    LIU Guangwei, ZHOU Daiyu, JIANG Hanqiao, WANG Tao, LI Junjian
    Petroleum Exploration and Development. 2018, 45(1): 128-135. https://doi.org/10.11698/PED.2018.01.13
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    Based on geological analysis, reservoir numerical simulation and production performance analysis, water-out performance and pattern of horizontal wells in Tarim marine sandstone reservoir were studied. Compared with continental sandstone reservoirs, the marine sandstone reservoirs in Tarim Basin were characterized by low oil viscosity, good reservoir continuity, and development of interbeds, which together with the large amount of horizontal wells, resulted in fast production rate and high recovery degree of the reservoirs. The main controlling factors of uneven water-out in horizontal wells were reservoir seepage barrier, injection-production well pattern, and dominant seepage channel. Thus 9 types in 4 categories of typical water-out pattern of horizontal wells in Tarim marine sandstone reservoirs were identified, and water-out management measures were proposed for them respectively according to their water-out mechanism and remaining oil distribution characteristics. Finally, the water-out pattern can be identified based on the inflection characteristics of derivative curve of water-oil ratio. This study of the water-out pattern can provide guidance for the adjustment policy of water injection in horizontal wells in marine sandstone reservoirs of Tarim Oilfield.
  • Surface wettability control of reservoir rocks by brine
    LIN Meiqin, HUA Zhao, LI Mingyuan
    Petroleum Exploration and Development. 2018, 45(1): 136-144. https://doi.org/10.11698/PED.2018.01.14
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    Based on adhesion models between rock surface groups and organic molecules, the interactions between the chemical groups on the rock surface and the components of crude oil and the interactions of the electrical double layers at the rock surface and oil-water interface were analyzed to investigate the abilities and microscopic mechanisms of wettability control by H+, OH- and inorganic salt ions in brine, and a new method of wettability control for reservoir rocks was built. The results show that the interaction forces between rock surface groups and oil molecules are van der Waals forces, Coulomb forces, hydrogen bonds, and surface forces. By changing these forces, the control mechanisms of surface wettability of reservoir rocks by brine are: transformation of chemical groups, change of interfacial potential, pH variation of injected water, multicomponent ionic exchange, and salting-in or salting-out effect. For sandstone reservoirs, with the decrease of concentration and valence state of positive ions in brine or the increase of pH (increasing pH has a negligible impact on the brine salinity), the interaction between rock surface and oil becomes weak, thus resulting in increase of water wettability of rock surface. For carbonate reservoirs, CaSO4 or MgSO4 brine with high concentration is beneficial to increase water wettability of rock surface. Therefore, it is feasible to control rock wettability and improve oil recovery by adjusting the ion components of injected water.
    • PETROLEUM ENGINEERING
  • Quantitative recognition method for borehole trajectory models
    LIU Xiushan
    Petroleum Exploration and Development. 2018, 45(1): 145-148. https://doi.org/10.11698/PED.2018.01.15
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    In order to accurately calculate drilled trajectories, method of quantitatively recognizing borehole trajectory models was provided, and case analysis was conducted. Because the measurement-while-drilling data provide with measured values of tool-face angle besides inclination angle and azimuth angle, this paper presents the technological approach of recognizing borehole trajectory models based on tool-face angle. A universal tool-face angle equation was established based on the directional deflection mechanism of steerable drilling tools, and it can calculate the tool-face angles with characteristic parameters of various borehole trajectory models. Then, by evaluating the error between the theoretical value and the measured value of tool-face angle, the trajectory model most consistent with the actual well trajectory can be selected. The model recognition of borehole trajectory provides with the quantitative evaluation index and selection basis of survey calculation methods, which can avoid subjectively and randomly selecting the survey calculation method, and consequently improves the monitoring accuracy and reliability of borehole trajectory.
  • Calculation method of proppant embedment depth in hydraulic fracturing
    CHEN Ming, ZHANG Shicheng, LIU Ming, MA Xinfang, ZOU Yushi, ZHOU Tong, LI Ning, LI Sihai
    Petroleum Exploration and Development. 2018, 45(1): 149-156. https://doi.org/10.11698/PED.2018.01.16
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    For the issue of proppant embedment in hydraulic fracturing, a new calculation method of embedment depth considering elastic-plastic deformation was proposed based on the mechanism of proppant embedment into rocks by combining proppant embedment constitutive equations and contact stresses on the rock-proppant system. And factors affecting embedment depth of proppant were analyzed using the new method. Compared with the elastic embedment model, the results calculated by the new method match well with the experimental data, proving the new method is more reliable and more convenient to make theoretical calculation and analysis. The simulation results show the process of proppant embedment into rocks is mainly elastic-plastic. The embedment depth of monolayer proppants decreases with higher proppant concentration. Under multi-layer distribution conditions, increasing the proppant concentration will not change its embedment depth. The larger the proppant embedment ratio, the more the stress-bearing proppants, and the smaller the embedment depth will be. The embedment depth under higher closure stress is more remarkable. The embedment depth increased with the drawdown of fluid pressure in the fracture. Increasing proppant radius or the ratio of proppant Young’s modulus to rock Young’s modulus can reduce the proppant embedment depth.
  • Influence of monoethanolamine on thermal stability of starch in water based drilling fluid system
    NASIRI Alireza, NIK Mohammad Amin Sharif, HEIDARI Hamidreza, VALIZADEH Majid
    Petroleum Exploration and Development. 2018, 45(1): 157-160. https://doi.org/10.11698/PED.2018.01.17
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    To improve the thermal stability of starch in water-based drilling fluid, monoethanolamine (MEA) was added, and the effect was investigated by laboratory experiment. The experimental results show that the addition of monoethanolamine (MEA) increases the apparent viscosity, plastic viscosity, dynamic shear force, and static shear force of the drilling fluid, and reduces the filtration rate of drilling fluid and thickness of mud cake apparently. By creating hydrogen bonds with starch polymer, the monoethanolamine can prevent hydrolysis of starch at high temperature. Starch, as a natural polymer, is able to improve the rheological properties and reduce filtration of drilling fluid, but it works only below 121 ℃. The MEA will increase the thermal stability of starch up to 160 ℃. There is a optimum concentration of MEA, when higher than this concentration, its effect declines.
    • COMPREHENSIVE RESEARCH
  • The progress and prospects of shale gas exploration and exploitationin southern Sichuan Basin, NW China
    MA Xinhua, XIE Jun
    Petroleum Exploration and Development. 2018, 45(1): 161-169. https://doi.org/10.11698/PED.2018.01.18
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    The Ordovician Wufeng Formation-Silurian Longmaxi Formation organic-rich shales distributed widely and stably in Southern Sichuan Basin were investigated based on drilling data. Geological evaluation of wells show that the shale reservoirs have good properties in the Yibin, Weiyuan, Zigong, Changning, Luzhou, Dazu areas, with key parameters such as TOC, porosity, gas content similar to the core shale gas production zones. Moreover, these areas are stable in structure, good in preservation conditions and highly certain in resources. The shale reservoirs have a burial depth of 4 500 m or shallow, a total area of over 2×104 km2 and estimated resource of over 10×1012 m3, so they are the most resource-rich and practical areas for shale gas exploitation in China. Through construction of the Changning-Weiyuan national demonstration region, the production and EUR of shale gas wells increased significantly, the cost of shale gas wells decreased remarkable, resulting in economic benefit better than expected. Moreover, the localized exploration and development technologies and methods are effective and repeatable, so it is the right time for accelerating shale gas exploitation. Based on the production decline pattern of horizontal wells at present and wells to be drilled in the near future, at the end of the 13th Five Year Plan, the production of shale gas in southern Sichuan Basin is expected to reach 10 billion cubic meters per year. The resources are sufficient for a stable production period at 30 billion cubic meters per year, which will make the South Sichuan basin become the largest production base of shale gas in China.
    • ACADEMIC DISCUSSION
  • A new permeability calculation method using nuclear magnetic resonance logging based on pore sizes: A case study of bioclastic limestone reservoirs in the A oilfield of the Mid-East
    HAN Yujiao, ZHOU Cancan, FAN Yiren, LI Chaoliu, YUAN Chao, CONG Yunhai
    Petroleum Exploration and Development. 2018, 45(1): 170-178. https://doi.org/10.11698/PED.2018.01.19
    Abstract ( ) Download PDF ( ) Knowledge map Save
    It is difficult to accurately obtain the permeability of complex lithologic reservoirs using conventional methods because they have diverse pore structures and complex seepage mechanisms. Based on in-depth analysis of the limitation of classical nuclear magnetic resonance (NMR) permeability calculation models, and the understanding that the pore structure and porosity are the main controlling factors of permeability, this study provides a new permeability calculation method involving classifying pore sizes by using NMR T2 spectrum first and then calculating permeability of different sizes of pores. Based on this idea, taking the bioclastic limestone reservoir in the A oilfield of Mid-East as an example, the classification criterion of four kinds of pore sizes, coarse, medium, fine and micro throat, was established and transformed into NMR T2 standard based on shapes and turning points of mercury intrusion capillary pressure curves. Then the proportions of the four kinds of pore sizes were obtained precisely based on the NMR logging data. A new NMR permeability calculation model of multicomponent pores combinations was established based on the contributions of pores in different sizes. The new method has been used in different blocks. The results show that the new method is more accurate than the traditional ones.
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