20 November 2017, Volume 44 Issue 6
    

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    PETROLEUM EXPLORATION
  • Genetic types of gas hydrates in China
    DAI Jinxing, NI Yunyan, HUANG Shipeng, PENG Weilong, HAN Wenxue, GONG Deyu, WEI Wei
    Petroleum Exploration and Development. 2017, 44(6): 837-848. https://doi.org/10.11698/PED.2017.06.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Researches were carried out on the origin of gas hydrate samples from the tundra in the Qilian Mountain, Pearl River Mouth Basin in the northern South Sea and the continental slope of Taixinan Basin in China. Gases of the gas hydrate samples from the Jurassic Jiangcang Formation in the Muli County in Qilian Mountain are mainly of oil-derived origin, characterized by self-generation and self-preservation. δ13C1 values range from -52.7‰ to -35.8‰, and the δ13C2 values vary from -42.3‰ to -29.4‰. There was a small amount of coal-derived gases, which might source from the coal-bearing Middle-Jurassic Muli Formation with δ13C1 of -35.7‰ - -31.3‰ and δ13C2 of -27.5‰ - -25.7‰. Gases of the gas hydrate samples from the Pearl River Mouth Basin and Taixinan Basin are dominated by bacterial origin of carbonate reduction, with δ13C1 of -74.3‰ - -56.7‰ and δD1 of -226‰ - -180‰. A trace amount of thermogenic gases were also found in these basins with δ13C1 of -54.1‰ - -46.2‰. This study combined the geochemical data of gas hydrates from 20 areas (basins) in the world, and concluded that thermogenic gases of the gas hydrates in the world can be either of coal-derived or oil-derived origin, but dominated by oil-derived origin. A small amount of coal-derived gas was also found in the Qilian Mountain in China and the Vancouver Island in Canada. The coal-derived gas has relatively heavy δ13C1 ≥ -45‰ and δ13C2 > -28‰, while the oil-derived gas has δ13C1 from -53‰ - -35‰ and δ13C2 < -28.5‰. Gas hydrates in the world mainly belong to bacterial origin of carbonate reduction. Methanogensesis of acetate fermentation was only found in some gas hydrates from the Baikal basin in Russia. Bacterial gases of carbonate reduction have relatively heavy δD1 ≥ -226‰, while gases of acetate fermentation have δD1 < -294‰. The bacterial gas of gas hydrates in the world has the highest δ13C1 value of -56.7‰ and lowest of -95.5‰, with a peak range of -75‰ - -60‰. Gas hydrate in the world has the highest δ13C1 of -31.3‰ and lowest of -95.5‰ and the highest δD1 of -115‰ and lowest of -305‰.
  • Petroleum geological characteristics of two basin belts in southern continental margin in South China Sea
    ZHANG Gongcheng, TANG Wu, XIE Xiaojun, ZHAO Zhigang, ZHAO Zhao
    Petroleum Exploration and Development. 2017, 44(6): 849-859. https://doi.org/10.11698/PED.2017.06.02
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the seismic, drilling, cores and outcrops data, the formation of basins, source rocks and hydrocarbon accumulations in the southern South China Sea (SSCS) were systematically analyzed to reveal the petroleum geological features of continental margin basins and summarize the distribution rule of oil and gas in the SSCS. The results show that the South China Sea (SCS) has experienced three tectonic stages, namely, the formation and development of pro-SCS, the subduction of pro-SCS and development of neo-SCS, the rapid subsidence and shrinking of SCS. The tectonic evolution of pro-SCS and neo-SCS controlled the regional tectonic pattern of continental margin in the SSCS, forming southern and northern basin belts, and also dominated the formation of basins, source rocks and hydrocarbon accumulation characteristics. The source rocks were mainly Miocene coal source rocks in the southern basin belt, with different thermal evolution degree, and the near-shore source rock was chiefly oil-generating while the off-shore source rock was mainly gas-generating. Compressive folding structural belts and reefs were the favorable belts. Within the northern basin belt, the source rocks were gas-prone and dominated by the Eocene to Oligocene, with high thermal evolution degree. Reefs and faulted blocks were the major accumulation areas. Our study demonstrates that the continental marginal basins of SSCS still have great exploration potential and is an important strategic area of oil and gas exploration and development. The southern basin belt focuses on oil and gas exploration and the northern basin belt focuses on gas exploration.
  • Sublacustrine hyperpycnal channel-fan system in a large depression basin: A case study of Nen 1 Member, Cretaceous Nenjiang Formation in the Songliao Basin, NE China
    PAN Shuxin, LIU Huaqing, ZAVALA Carlos, LIU Caiyan, LIANG Sujuan, ZHANG Qingshi, BAI Zhongfeng
    Petroleum Exploration and Development. 2017, 44(6): 860-870. https://doi.org/10.11698/PED.2017.06.03
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    Based on the integrated analysis of the seismic sedimentology, drilling and core data from the Nen 1 Member of the Cretaceous Nenjiang Formation in the Qijia-Gulong area, a large channel fan system of hyperpycnal flow origin was found in the Songliao Basin, and the hyperpycnal flows and hyperpycnites distributed in the deep water area of large depression lake basin were examined to find out the depositional model of channel-fan of hyperpycnal flow origin in the continental lake basin. The study shows that the hyperpycnal flow in this area originated from the edge of the basin, passed the northern delta, and then gave rise to a complete channel-fan system in the deep water area. The channel-fan system consists of straight channel and meandering channel from north to south with a straight extension of over 80 km and width of 100-900 m, and distal fan lobes at the channel tip with the maximum area of 20 km2. Dominated by fine-grained deposits, the system contains massive sandstone and sedimentary structures of flow water origin, internal erosion surfaces, and rich continental organic clasts, and shows bed-load and suspended-load transportation mechanisms. The hyperpycnite sequence has a coarsening-upward lower sequence and fining-upward upper sequence appearing in pairs, reflecting the dynamic feature of flood strengthening and then weakening cycle.
  • Subsalt high steep structure imaging technique: A case study of Keshen area in Kuqa depression, Tarim Basin, NW China
    ZENG Qingcai, ZENG Tongsheng, OUYANG Yonglin, DAI Chunmeng, SONG Yaying
    Petroleum Exploration and Development. 2017, 44(6): 871-879. https://doi.org/10.11698/PED.2017.06.04
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    The seismic imaging has three difficulties in the Keshen area of the Kuqa depression in Tarim Basin: difficult static correction, poor original data, difficult velocity modeling and pre-stack depth migration. A dual-scale tomography inversion approach based on BP neural network and LSQR was developed to obtain the accurate near-surface velocity of the complex near-surface structure, to address the static correction of subsalt high steep structure imaging. On the basis of applying high-precision static correction and root-mean-square (RMS) velocity to the seismic data, three dimensional cone filtering and spherical spreading amplitude compensation were used to enhance the signal to noise ratio and restore the deep effective signals to cope with the poor quality of original seismic data. Under the constraints of geologic, well logging and drilling data, the dual-scale velocity modeling technology based on model-based velocity updating and grid-based tomography was adopted to obtain the precise velocity model of the complex substructure, and then the pre-stack depth migration was taken to improve the imaging effect of structure with complex surface conditions, to solve the problem of subsalt high steep structure velocity modeling and pre-stack depth migration. By applying these three techniques, the high-quality imaging achievements of subsalt high steep structure were obtained. The results of seismic imaging prediction are in good agreement with drilling results and three ultra-deep wells have been drilled successfully.
  • Evaluations of oil and gas lateral migration across faults: A case study of Shigezhuang nose structure of Wen’an slope in Baxian sag, Jizhong depression, Bohai Bay Basin, China
    WANG Chao, LYU Yanfang, WANG Quan, FU Guang, WANG Yougong, SUN Yonghe, HUO Zhipeng, LIU Junqiao
    Petroleum Exploration and Development. 2017, 44(6): 880-888. https://doi.org/10.11698/PED.2017.06.05
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    To quantitatively study the possibility and location of lateral migration of oil and gas across faults, a quantitative evaluation method for lateral migration of oil and gas across faults was established using the Shuangjing Knipe graphic method to identify the juxtaposition site and juxtaposition patterns of sand and sand in the upper and lower walls of the reverse faults and the consequent faults, combined with the oil and gas limit method of fault lateral seal in the test oil area. The quantitative evaluation method was applied to the first and two members of the Paleogene Shahejie strata (referred to as Es1 and Es2) of Shigezhuang nose structure of Wen'an slope in Baxian sag, Jizhong depression, Bohai Bay Basin, to determine the juxtaposition site of sand and sand in the upper and lower walls of the fault, and the shale gouge ratio (SGR) lower values are 26% and 29% respectively in the strata Es1 and Es2. Thus, the location of lateral migration of oil and gas across faults was determined. Based on the oil and gas distribution characteristics of the strata Es1 and Es2, and variation trend of nitrogen compounds in 4 wells in the strata Es1, the results were consistent with the quantitative evaluation of the location of lateral migration of oil and gas across faults, the feasibility of the evaluation method was preliminarily verified.
  • Petrophysical characteristics and logging evaluation of asphaltene carbonate reservoirs: A case study of the Cambrian Longwangmiao Formation in Anyue gas field, Sichuan Basin
    LAI Qiang, XIE Bing, WU Yuyu, HUANG Ke, LIU Xinggang, JIN Yan, LUO Wenjun, LIANG Tao
    Petroleum Exploration and Development. 2017, 44(6): 889-895. https://doi.org/10.11698/PED.2017.06.06
    Abstract ( ) Download PDF ( ) Knowledge map Save
    The petrophysical and logging response characteristics of asphaltene carbonate reservoirs were examined based on the measurement of porosity and permeability, density, compressional and shear wave slowness, resistivity and Nuclear Magnetic Resonance transverse relaxation time (T2) of cores before and after the bitumen dissolving. The results show that (1) the asphalt can damage the pore structure of the reservoir and cause reduction of effective reservoir space and permeability; (2) with the increase of asphalt content, the compression and shear wave slowness generally decrease while the density and resistivity increase; (3) with the increase of asphalt content, the compressional wave slowness and density change less, while the shear wave slowness and resistivity change larger; and (4) the T2 values of asphalt are generally less than 3 ms, and the higher the maturity of the asphalt, the lower the T2 value. Based on these experiments, a method based on conventional and special logging methods was presented to evaluate asphalt content, effective porosity and water saturation in asphaltene carbonate reservoirs. The method has already been applied to 80 wells in the Longwangmiao Formation of the Anyue gas field in the Sichuan Basin to pick out zones rich in asphalt on the plane, which has effectively guided the selection of well location in the gas reservoir development.
  • Formation and distribution of the high quality reservoirs in a deep saline lacustrine basin: A case study from the upper part of the 4th member of Paleogene Shahejie Formation in Bonan sag, Jiyang depression, Bohai Bay Basin, East China
    MENG Tao, LIU Peng, QIU Longwei, WANG Yongshi, LIU Yali, LIN Hongmei, CHENG Fuqi, QU Changsheng
    Petroleum Exploration and Development. 2017, 44(6): 896-906. https://doi.org/10.11698/PED.2017.06.07
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    The upper part of the 4th member of Paleogene Shahejie Formation in Bonan sag, Bohai Bay Basin, East China was taken as the study object. Conventional core analysis, casting and conventional thin section inspection, scanning electron microscope observation, particle size analysis and fluid inclusion analysis were carried out on cores, and the data from these analyses and tests was used to find out the evolution of diagenetic environment of the saline lacustrine basin and the main factors controlling the deep formation of high quality reservoirs. The diagenetic environment of the saline lacustrine basin experienced alkali and acid alternation. In the early alkali diagenetic environment, large amounts of carbonate cement filled the primary pores, making the reservoir porosity reduce sharply from 37.3% to 18.77%, meanwhile, keeping the primary pores from compaction, and retaining the dissolution space. In the middle-late stage of acid diagenetic environment, early carbonate cement was dissolved, resulting in rise of reservoir porosity by 10.59%, and thus the formation of the deep high quality reservoirs. The distribution of high quality deep reservoirs is controlled by the development of gypsum salt rock, source rock, fracture system and sedimentary body distribution jointly. Deeply buried high quality reservoirs in the upper part of the 4th member of the Shahejie Formation in Bonan sag are nearshore subaqueous fan-end sandstone and some fan-medium fine conglomerate buried at 3 4004 400 m in the north steep slope.
  • Fine prediction of reef boundary based on slope attributes: A case study of Permian Changxing Formation in Luodingzhai area, Sichuan Basin, SW China
    WU Yong, ZHOU Lu, ZHONG Feiyan, ZHONG Kexiu, YUAN Bing, ZHOU Jieling
    Petroleum Exploration and Development. 2017, 44(6): 907-918. https://doi.org/10.11698/PED.2017.06.08
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    Based on the slope theory in geomorphology, a method, which can identify the boundary of platform reef by high precision slope attribute calculation based on the horizon data of fine seismic interpretation, combining the ancient geomorphic analysis method, was established. The conventional seismic prediction methods, drilling results and the thickness data of Changxing Formation were used to verify and supplement this method. Then, this method was used to identify the boundary of uplifted reef on the planar image in the Permian Changxing Formation in Luodingzhai area of Sichuan Basin. The results show that the reef boundary imaged by this method is consistent with the reef distribution revealed by the drilling, and is clearer in local details. Compared with conventional seismic prediction methods, the reef boundary identified based on the same fine seismic horizon interpretation results by this method has no multiple solution on the planar image.
    • OIL AND GAS FIELD DEVELOPMENT
  • Dynamic and static comprehensive prediction method of natural fractures in fractured oil reservoirs: A case study of Triassic Chang 63 reservoirs in Huaqing Oilfield, Ordos Basin, NW China
    SU Hao, LEI Zhengdong, ZHANG Diqiu, LI Junchao, ZHANG Zeren, JU Binshan, LI Zhiping
    Petroleum Exploration and Development. 2017, 44(6): 919-929. https://doi.org/10.11698/PED.2017.06.09
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    In consideration of the limited adaptability scope, low accuracy and high demand of great cost data of existent fracture prediction methods, a new fracture predicting method was advanced by implementing geological static data and production dynamic data from the Triassic Chang 63 reservoirs in the Huaqing Oilfield. Five constraints, lithology, sedimentary facies, thickness, rock rupture index and fracture intensity controlling the development of fractures were sorted out based on the static geological data. The multiple linear regression method was adopted to work out the quantitative relationships between the five constraints and fracture density, and the fracture density property of the whole area was calculated. Based on production dynamic data of well history, tracer, well interference test and intake profile test, the direction and distribution of fracture horizontally and vertically were figured out by reservoir engineering analysis method. The fracture density property was verified and quantitatively corrected with numerical simulation, and a 3D discrete fracture geological model in agreement with both geological cognition and dynamic production performance was built. The numerical simulation shows that the fracture model has higher fitting consistency, high reliability and adaptability.
  • Experiment on gas-water two-phase seepage and inflow performance curves of gas wells in carbonate reservoirs: A case study of Longwangmiao Formation and Dengying Formation in Gaoshiti-Moxi block, Sichuan Basin, SW China
    LI Chenghui, LI Xizhe, GAO Shusheng, LIU Huaxun, YOU Shiqiang, FANG Feifei, SHEN Weijun
    Petroleum Exploration and Development. 2017, 44(6): 930-938. https://doi.org/10.11698/PED.2017.06.10
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    Gas-water relative permeability was tested in the full diameter cores of three types of reservoirs (matrix pore, fracture and solution pore) in Gaoshiti-Moxi block under high pressure and temperature to analyze features of their gas-water relative permeability curves and gas well inflow dynamics. The standard plates of gas-water two-phase relative permeability curves of these types reservoirs were formed after normalization of experimental data. Based on the seepage characteristics of fractured reservoirs, the calibration methods of gas-water two-phase relative permeability curves were proposed and the corresponding plates were corrected. The gas-water two-phase IPR (inflow performance relationship) curves in different type reservoirs were calculated using the standard plates and validated by the actual performances of gas wells respectively. The results show that: water saturations at gas-water relative permeability equal points of studied reservoirs are over 70%, indicating strong hydrophilic; the dissolved cave type has the biggest gas-water infiltration interval and efficiency of water displacement by gas, followed by the matrix pore type and then fractured type; and the fractured type has the highest the permeability recovery degree, followed by the dissolved cave type and then matrix pore type. The calibrated gas-water two-phase relative permeability curves of fractured carbonate reservoirs can better reflect the gas-water two-phase seepage law of actual gas reservoirs and the standard plates can be used in the engineering calculation of various gas reservoirs. The characteristics of calculated IPR curves are consistent with the performance of actual producing wells, and are adaptable to guide production proration and performance analysis of gas wells.
  • Big data paradox and modeling strategies in geological modeling based on horizontal wells data
    HUANG Wensong, WANG Jiahua, CHEN Heping, XU Fang, MENG Zheng, LI Yonghao
    Petroleum Exploration and Development. 2017, 44(6): 939-947. https://doi.org/10.11698/PED.2017.06.11
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    Based on analysis of horizontal well data characteristics, the differences of data distribution and variogram between vertical and horizontal wells in MPE3 oil field of Orinoco heavy oil belt were compared, and modeling strategies were proposed to cope with the big data paradox when data of horizontal wells was used directly into geologic modeling. The study shows the horizontal wells in the study area contain a large quantity of information, strong directionality of well trajectories and high drilling ratio of sandstone, causing variogram analysis result unconformable to the geologic understanding, and in turn making errors in the modeling of sedimentary microfacies and reservoir physical properties and prediction of probabilistic reserves. Firstly, the distributary channel distribution variogram was analyzed with data of vertical wells, and then the lithofacies framework was established under the control of the sedimentary facies and seismic data. After that, the horizontal wells data revealing high heterogeneity accuracy of reservoir, was combined with the vertical wells data to analyze argillaceous interlayer variograms and the corresponding reservoir lithofacies models were constructed. Finally, reservoir physical property models were generated and the geological reserves were calculated by wellblocks. This reservoir modeling method does not only reflect the geologic features underground, but also improve the accuracy of inter-well sand body prediction, and enhance the reliability of reservoir geologic model ultimately.
  • Micro-influencing mechanism of permeability on spontaneous imbibition recovery for tight sandstone reservoirs
    GU Xiaoyu, PU Chunsheng, HUANG Hai, HUANG Feifei, LI Yuejing, LIU Yang, LIU Hengchao
    Petroleum Exploration and Development. 2017, 44(6): 948-954. https://doi.org/10.11698/PED.2017.06.12
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    Taking the Chang 8 tight sandstone reservoir of the Yanchang Formation of Fuxian area in Ordos Basin as an example, the influencing mechanism of permeability on imbibition recovery in tight sandstone was explored by spontaneous imbibition experiment, combining nuclear magnetic resonance (NMR) and CT Scanning. Results show that: (1) spontaneous imbibition played a vital role in water-flooding of the tight sandstone reservoir, the recovery by spontaneous imbibition of experimental core samples can reach 5.24% - 18.23%, and the higher the matrix permeability, the higher the recovery degree by spontaneous imbibition; (2) because of the thickness of adsorbed layer, pores above sub-micron scale made a great contribution to the imbibition recovery of tight sandstone reservoir, and nano-submicron pores made less contribution to imbibition recovery; (3) the connectivity of pore and throat was the major microscopic mechanism of the positive correlation between matrix permeability and spontaneous imbibition recovery. Samples of different permeability didn’t differ much in the sizes of sub-micron to micron pores, but with the rise of permeability, the connected pores and throats and surface porosity increased exponentially, leading to significant increase of imbibition recovery.
  • New water drive characteristic curves at ultra-high water cut stage
    WANG Jiqiang, SHI Chengfang, JI Shuhong, LI Guanlin, CHEN Yingqiao
    Petroleum Exploration and Development. 2017, 44(6): 955-960. https://doi.org/10.11698/PED.2017.06.13
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    A function expression of the oil-water relative permeability ratio with normalized water saturation at high water saturation was proposed based on statistics of measured oil-water relative permeability data in oilfields. This expression fits the later section of conventional relative permeability ratio curve more accurately. Two new water drive characteristic curves at the ultra-high water cut stage (fw>90%) were derived by combining the new oil-water relative permeability ratio expression and reservoir engineering method. Then, the numerical simulation results of five point well pattern and production data of Yangerzhuang Oilfield and Liuzan Oilfield were used to verify the adaptability of the new water drive characteristic curves. The results showed that the new water drive characteristic curves are more accurate than conventional water drive characteristic curves after A type and B type water drive curves rise, and can be used to predict production performance at ultra-high water cut stage, ultimate recovery efficiency and recoverable reserves.
    • PETROLEUM ENGINEERING
  • Gravel sizing method for sand control packing in hydrate production test wells
    LI Yanlong, HU Gaowei, LIU Changling, WU Nengyou, CHEN Qiang, LIU Lele, LI Chengfeng
    Petroleum Exploration and Development. 2017, 44(6): 961-966. https://doi.org/10.11698/PED.2017.06.14
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    To deal with sand production problems during the process of producing natural gas from hydrate-bearing sediments (HBS) using reservoir-fluid extraction method, a new gravel sizing method for sand control packing named “Hold coarse while eliminate fine particle (HC & EF method)” was developed for the clayey hydrate-bearing formations. Site X, in Shenhu area, South China Sea was taken as an example to describe detailed gravel sizing procedure. On the basis of analyzing basic particle size distribution (PSD) characteristics of HBS at Site X, the formation sand was divided into two components, which are coarse component and fine component. The gravel sizes for retaining coarse component and eliminate fine component were calculated, respectively. Finally, intersection of these two gravel sizes was taken as the proper gravel size for Site X. The research results show that the formation at Site X is clayey sand with poor sorting and uniformity, proper gravel size for upper segment packing is 143-215 μm, while that for lower segment packing is 240-360 μm. In consideration of the difficulty of layered sand control operation on offshore platform, proper gravel packing size for Site X is recommended as 215-360 μm.
  • Comprehensive review of water shutoff methods for horizontal wells
    SUN Xindi, BAI Baojun
    Petroleum Exploration and Development. 2017, 44(6): 967-973. https://doi.org/10.11698/PED.2017.06.15
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    This paper provides a comprehensive review of the water control techniques that have been applied in horizontal wells and presents the water control methods for wells of different completion types. Water shutoff techniques are classified as mechanical methods and chemical methods. These methods can be used individually or in combination. Mechanical methods are usually used to deal with wellbore water shutoff or near wellbore water control. Chemical methods are used in plugging matrix or fractures. Completion type should be considered when designing a water shutoff project. Both mechanical methods and chemical methods can be used in open hole and cased hole horizontal wells. In the wells that completed with perforated liners and wells completed with sand screen pipe, only chemical methods can be used to control excess water production, while the mechanical methods can only provide temporary zonal isolation. Mechanical methods are slightly higher in cost than chemical methods, and the depth correction is a challenge. Mechanical and chemical methods can be individually used if the water entry point is at the toe. A combination of packers should be designed for the wells with water entry point near the heel or along the lateral.
  • Hydraulic fracture propagation geometry and acoustic emission interpretation: A case study of Silurian Longmaxi Formation shale in Sichuan Basin, SW China
    MA Xinfang, LI Ning, YIN Congbin, LI Yanchao, ZOU Yushi, WU Shan, HE Feng, WANG Xiaoqiong, ZHOU Tong
    Petroleum Exploration and Development. 2017, 44(6): 974-981. https://doi.org/10.11698/PED.2017.06.16
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    A series of laboratory fracturing experiments was performed on samples mined from an outcrop of the Silurian Longmaxi Formation shale in the Sichuan Basin, using a true triaxial fracturing simulation system. To reveal the characteristics of acoustic emission (AE) response in hydraulic fracture (HF) propagation, the HF propagation geometry obtained by specimen splitting and CT scanning technology was compared with the interpretation results of AE monitoring. And the difference of hypocenter mechanism between hydraulically connected and unconnected regions was further discussed. Experimental results show that the AE events distribution indicates well the internal fractures geometry of the rock samples. Numerous AE events occur and concentrate around the wellbore where the HF initiated. Sparse AE events were presented nearby bedding planes (BP) activated by the HF. AE events tended to be denser where HF geometry was more complex. The hydraulically connected region was obviously distinct with the spatial distribution of AE events, which resulted in the overestimation of stimulated reservoir volume (SRV) based on micro-seismic mapping result. Both tensile and shear events occurred in the zone connected by the hydraulic fractures, while only shear events were observed around BPs those were not hydraulically connected. Thus, the hydraulically connected and unconnected region can be identified in accordance with the hypocenter mechanism, which is beneficial to improve the accuracy of SRV evaluation.
  • A wellbore creep model based on the fractional viscoelastic constitutive equation
    PENG Yu, ZHAO Jinzhou, LI Yongming
    Petroleum Exploration and Development. 2017, 44(6): 982-988. https://doi.org/10.11698/PED.2017.06.17
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    To simulate the evolution of wellbore creep accurately, predict and prevent severe accidents such as borehole wall sloughing, casing collapse and sticking of the drill, based on previous studies, the springpot element was introduced into the classical element model and the creep compliances of the fractional constitutive models were deduced. The good fitting effect of fractional constitutive model was verified. The study shows the fractional constitutive model can simulate creep with high accuracy and less input parameters, and the physical significance of the input parameters are clearer. According to the correspondence principle of viscoelastic theory, a wellbore creep model including drilling and killing processes was built up. By adjusting the value of fractional orders, the model can transform between the models of ideal elastic material and standard solid, which implies the classical wellbore shrinkage model based on standard solid model and ideal elastic model are just special cases of this model. If the fractional order is adjusted, the creep curve will change asymmetrically, which can be can be regulated by the speeding up of the transient creep and lowering the rate of steady creep, which can not be accomplished by adjusting one parameter in the classical models. The fractional constitutive model can fit complicated non-linear creep experiment data better than other models.
    • COMPREHENSIVE RESEARCH
  • Simulation of mud invasion and analysis of resistivity profile in sandstone formation module
    FAN Yiren, WU Zhenguan, WU Fei, WU Junchen, WANG Lei
    Petroleum Exploration and Development. 2017, 44(6): 989-996. https://doi.org/10.11698/PED.2017.06.18
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    Aiming at the dynamic invasion process of drilling fluid, the parameters of the physical model in laboratory were optimized based on numerical simulation and then a physical simulation system for mud invasion in undisturbed zone was developed. Then, the experiment of fresh water invasion in sandstone formation was conducted to measure the radial resistivity and mudcake parameters over time, and a mudcake porosity and permeability calculation model with the invasion time was proposed based on the measurement. Finally, the numerical simulation results were compared and calibrated with the physical simulation results to find out the regularity of drilling fluid invasion under formation conditions. The results show that the mudcake forms quickly and the porosity and permeability of the mudcake decrease sharply after the beginning of drilling fluid invasion, and the invasion process is mainly controlled by the mudcake after a certain period. The mudcake parameters model developed in this study can depict the changes of mudcake parameters during the invasion process. The characteristics of radial resistivity profile under mud invasion are affected by sandstone physical properties, mudcake parameters and formation water salinity.
    • ACADEMIC DISCUSSION
  • Carbon isotopic compositions and origin of Paleozoic crude oil in the platform region of Tarim Basin, NW China
    ZHU Xinjian, CHEN Jianfa, WU Jianjun, WANG Yifan, ZHANG Baoshou, ZHANG Ke, HE Liwen
    Petroleum Exploration and Development. 2017, 44(6): 997-1004. https://doi.org/10.11698/PED.2017.06.19
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    Based on the carbon isotopic compositions of Cambrian-Ordovician source rocks Kerogen Samples and Paleozoic crude oil in the platform region of Tarim Basin, the origin and source of Paleozoic crude oil were investigated. There are at least two sets of source rocks with different carbon isotope compositions in the Cambrian, the Lower Cambrian source rock with lighter carbon isotope composition and Middle-Upper Cambrian source rock with heavier carbon isotope composition, while the Ordovician source rock is somewhere in between. The δ13C values of Paleozoic crude oil samples are wide in distribution range, from -35.2‰ to -28.1‰. The crude oil with lighter carbon isotopic compositions (δ13C<-34.0‰) was mainly derived from Lower Cambrian source rock, and the crude oil with heavier carbon isotopic composition (δ13C>-29.0‰) was mainly derived from the Middle-Upper Cambrian source rocks, and the crude oil with δ13C value in between may be derived from Cambrian source rocks. It is concluded through analysis that the Cambrian source rock could become the major source rock in the Tarim Basin and the platform region has huge potential oil and gas resources in the deep formations.
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