23 February 2016, Volume 43 Issue 1
    

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    Orignal Article
  • Tectonic evolution from Late Sinian to Early Paleozoic and natural gas exploration in northwestern Sichuan Basin, SW China
    GU Zhidong, YIN Jifeng, JIANG Hua, ZHANG Baomin, LI Qiufen, YUAN Miao, ZHAI Xiufen, ZHANG Li, YANG Fan
    , 2016, 43(1): 1-11. https://doi.org/10.11698/PED.2016.01.01
    Abstract ( ) Download PDF ( ) Knowledge map Save
    Based on the field outcrops, drilling and seismic data of northwestern Sichuan Basin, this paper systematically discusses tectonic evolution characteristics from the Late Sinian to the Early Paleozoic, analyzes the petroleum geology significance, and points out the recent favorable exploration directions in this area. The area experienced mainly three times of tectonic evolution during the Late Sinian to the Early Paleozoic: (1) During the Late Sinian to the early period of Early Cambrian, this area was affected by tension action and formed two sets of nearly north-south trending continental rifts, and two sets of platform margins in the Sinian Dengying Formation. (2) During the middle period of the Early Cambrian to the Middle Ordovician, this area was eroded strongly (stronger in the northwest than in the southeast) because of multi-period uplifting of the northwestern Bikou paleo-land. (3) During the Late Ordovician to the Late Silurian, this area was eroded strongly again because of the compression of the Kwangsian Orogeny, and the erosion was stronger in the southwest than in the northeast. During the Late Sinian to the Early Cambrian, the formation of continental rifts controlled the development of bioherm beach facies reservoirs on the platform margins in the Dengying Formation and the high quality source rock in the Lower Cambrian series. During the middle of the Early Cambrian, the uplifting of the Bikou paleo-land controlled the distribution of the Kongmingdong Formation oolitic beach facies reservoirs around the paleo-land. It is suggested that, vertically, the fourth Member of the Dengying Formation and the Kongmingdong Formation be the main exploration targets, and, horizontally, the Jiulongshan structural trap be the most beneficial exploration belts recently due to its matching with petroleum migration and accumulation.
  • Deep strata geologic structure and tight conglomerate gas exploration in Songliao Basin, East China
    ZHAO Zehui, XU Shujuan, JIANG Xiaohua, LIN Changsong, CHENG Honggang, CUI Junfeng, JIA Li
    , 2016, 43(1): 12-12. https://doi.org/10.11698/PED.2016.01.02
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    The geologic structure of deep formations, basic geologic pattern of fault depressions, geologic conditions of Shahezi Formation tight gas reservoir, and the exploration direction in the next step in the Songliao Basin are examined based on a comprehensive and comparative analysis of the outcrop, drilling, seismic and geochemical data. Systematic comparison analysis shows that the geologic structure of deep formations in the basin is characterized by a double-layer structure with fault depression in the lower layer and depression in the upper layer. In the deep fault depression (DFD) stage, fault depressions bounded by faults or onlaps and uplifts, developed independently. The faults related to the formation and evolution of the fault depressions can be divided into regional major faults, basement depression controlling faults and secondary faults in subsags, and their actions in the evolution of the fault depression groups are presented in the paper. Based on analysis of regional tectonics and basin evolution features, three exploration fields, tight conglomerate gas, volcanic rocks and basement buried hills are pointed out, and it is concluded the tight conglomerate gas in the Shahezi Formation is currently a new strategic field with the most promising exploration prospect. Based on comprehensive analysis of basic oil geologic features of Shahezi Formation, it is proposed that conglomerate is the main category of clastic reservoir in Shahezi Fromation, and parent rock composition, sedimentary structure and facies, and diagenesis are the main factors affecting the distribution of conglomerate reservoirs. Furthermore, the gas reservoirs in Shahezi Formation, all source and reservoir in one, include two types, lithologic and structural types. Favorable sedimentary facies belts in the gentle slope and steep slope control the distribution of the reservoirs, formation of lithologic traps and gas reservoir scale; while secondary faults in side fault depressions control the formation of structural traps and enrichment of natural gas. Finally, seven fault depressions in Shahezi Formation with the most promising prospect of tight gas have been sorted out through comprehensive evaluation.
  • Geologic features of fine-grained facies sedimentation and tight oil exploration: A case from the second Member of Paleogene Kongdian Formation of Cangdong sag, Bohai Bay Basin
    PU Xiugang, ZHOU Lihong, HAN Wenzhong, ZHOU Jiansheng, WANG Wen’ ge, ZHANG Wei, CHEN Shiyue, SHI Zhannan, LIU Sa
    , 2016, 43(1): 24-33. https://doi.org/10.11698/PED.2016.01.03
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    Based on analysis of successive and whole cores over six hundred meters from the second Member of Kongdian Formation (Kong 2 Member) of fine-grained facies zone in central lake basin of Cangdong sag, ten thousands of systematic and joint analysis data, and the matching logging data, the sedimentary characteristics in the fine-grained facies zone is examined by means of traditional petroleum geology, sedimentology, and new theory and method of tight oil and gas generation. The Kong 2 Member is the sedimentation during the maximum lake flooding in the Kongdian Formation. Fine-grained sedimentation of half-deep lake to deep lake are widely distributed, the fine-grained feldspar-quartz contained sedimentary rock, fine-grained mixed sedimentary rock, and dolomite are developed, and the clay rock is poorly developed. The fine-grained rocks have these features as follows: more rock compositions, less advantageous minerals; more debris minerals, less clay minerals; more analcites, less pyrites; more brittle minerals, less quartz; more rock types, less oil shale; more tight reservoirs with less non-cracked reservoirs; more high-quality source rocks, less non-source rocks; more high-frequency cycle sediments, less single sediments. These understandings updated the former view that only mud shale source rock was dominantly developed in the closed continental lake. With the help of geologic research and matched engineering technologies, several exploration wells have produced industrial oil flows, showing a good prospect of tight oil exploration in fine-grained facies zones of continental lacustrine basins.
  • Hydrocarbon migration pathways in the Neogene of Laixi structural belt, southern Bohai Sea, China
    QIAN Geng, NIU Chengmin, YANG Bo, TU Danfeng, LI Guoying, GAO Wenbo
    , 2016, 43(1): 34-41. https://doi.org/10.11698/PED.2016.01.04
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    Characteristics, distribution, temporal and spatial configuration, and effectiveness of hydrocarbon migration pathways have been investigated through geochemical and formation pressure analysis etc, to further reveal hydrocarbon accumulation patterns in the Neogene of the Laixi structural belt, southern Bohai Sea of China. Firstly, three factors, faults, carrier rocks (beds) and mud caprocks of the transporting framework in the Neogene were examined to find out its feature and space configuration and made static state evaluation. It is found that besides the Guantao Formation - lower Minghuazhen Formation No. V oil layers, the No. I - III oil layers in the lower Minghuazhen Formation are also the dominant oil and gas carrier beds. Cutted by the adjustment faults and sealed by mudstone capcocks, the two carrier layers are combined into a “layered cake” type hydrocarbon migration framework. Then the hydrocarbon passage pathways were tracked dynamically and described using nitrogen compounds concentration, formation pressure, fluorescence logging and sand bodies description, which shows that the “T03-T02-T01 mudstone cap layers” separate the Neogene hydrocarbon migration pathways into upper and lower units. The massive sandy conglomerate reservoirs in the Guantao Formation - lower Minghuazhen Formation No. V oil layers are the carrier bed of the lower hydrocarbon migration pathway, while the north-south trending overlapped and connected channel sandbodies in lower Minghuazhen Formation No. I - III oil layers are the carrier bed of the upper unit. Hydrocarbon migrated laterally along the two passage ways, accompanying with differential accumulation.
  • Guanyinqiao Member lithofacies of the Upper Ordovician Wufeng Formation around the Sichuan Basin and the significance to shale gas plays, SW China
    WANG Yuman, DONG Dazhong, HUANG Jinliang, LI Xinjing, WANG Shufang
    , 2016, 43(1): 42-50. https://doi.org/10.11698/PED.2016.01.05
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    The stratigraphic distribution and lithofacies features of the Guanyinqiao Member of the Upper Ordovician Wufeng Formation around the Sichuan Basin were studied based on the data of drilling, outcrops, rock minerals, geochemistry and logging. The stratigraphic distribution of the Guanyinqiao Member is generally dominated by sea-level variation. This formation is in conformable contact with the overlying and underlying formations inside and locally outside the basin and is locally lost outside the basin. The Guanyinqiao Member is usually composed of deep-water siliceous shale and calcareous and siliceous shale facies, similar to those overlying and underlying lithologies inside the basin; and composed of shallow marl facies or lost, greatly different from the surrounding lithologies in the conformable area outside the basin. The study confirmed that the lithofacies of the Guanyinqiao Member is of great significance to the identification of the reservoir properties of the Wufeng and Longmaxi formations shale gas and to the selection of shale gas. The exploration and development of shale gas is promising in the depressions in the south, east and northeast of the Sichuan Basin, where good reservoirs are developed. The zone where the Guanyinqiao Member is lost has no “sweet spot” formation and is risky in exploring shale gas. The reservoir quality and exploration prospect of the Guanyinqiao Member marl zones are between the two zones mentioned above.
  • Hydrothermal dolomitization in Sinian Dengying Formation, Gaoshiti-Moxi area, Sichuan Basin, SW China
    JIANG Yuqiang, TAO Yanzhong, GU Yifan, WANG Juebo, QIANG Zitong, JIANG Na, LIN Gang, JIANG Chan
    , 2016, 43(1): 51-60. https://doi.org/10.11698/PED.2016.01.06
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    The formation conditions, existence evidence, modification modes and timing of hydrothermal dolomitization in the Sinian Dengying Formation are studied based on the basic geological conditions, mineral assemblages in dolomites, and geochemical features of the Gaoshiti-Moxi area in the Sichuan Basin. The Gaoshiti-Moxi area is a significant exploration target of the Sinian Dengying Formation in the Sichuan Basin and has the basic conditions of regional geology for the occurrence of structurally controlled hydrothermal dolomitization: (1) activity of extensional basement-fault; (2) deep-burial hydrothermal reservoirs; (3) the overlying seal strata. Based on the petrographic analysis and geochemical tests (trace elements (Fe and Mn), stable isotopes (C, O, and Sr), homogenization temperature of fluid inclusions, etc.) of the core samples of the Dengying Formation in the study area, combing with the MVT mineral assemblages and geochemical characteristics, the study demonstrates that structurally controlled hydrothermal dolomitization exists in the Dengying Formation of the study area. This type of hydrothermal dolomitization refers to transformation of matrix dolomites by hydrothermal fluids and it consists of three modes: (1) dissolution and cementation; (2) recrystallization and neomorphism; (3) hydrofracturing. It is inferred that there exists multi period of hydrothermal dolomitization, namely, Late Sinian to Early Cambrian, Late Devonian and Late Permian.
  • A logging identification method of tight oil reservoir lithology and lithofacies: A case from Chang7 Member of Triassic Yanchang Formation in Heshui area, Ordos Basin, NW China
    ZHOU Zhenglong, WANG Guiwen, RAN Ye, LAI Jin, CUI Yufeng, ZHAO Xianling
    , 2016, 43(1): 61-68. https://doi.org/10.11698/PED.2016.01.07
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    Based on the observation results of cores, structural analysis, sedimentary microfacies analysis, lithologic analysis and other analytical tests and logging data, the characteristics of lithology and lithofacies of the Member Chang7 tight oil reservoir of the Triassic Yanchang Formation in Heshui area are described and summarized and the criteria for identification of lithology and lithofacies by logging are established. The lithofacies in the Chang7 tight oil reservoir were classified into five types: fine sandstone deposited by sandy debris flow, turbidite fine siltstone, fine sandstone deposited by slump, semi-deep to deep lacustrine mudstone, and oil shale. The lithology and lithofacies in the Chang7 tight oil reservoir were characterized, both qualitatively and quantitatively, with electric logging and imaging logging and several means and methods, the response characteristics of different lithology and lithofacies were summarized through analyzing the image log and conventional log data, and the parameters characterizing sandstone’s structures were used to quantitatively characterize the lithology and lithofacies, the criteria for identification of different lithology and lithofacies by logging were established. The vertical and horizontal identification and classification of lithology and lithofacies in a single well was then accomplished by processing the log data from each well, the results of lithology and lithofacies identification tally well with the results of formation testing. In-depth lithology and lithofacies analysis proves to be an important method of tight oil reservoir evaluation and “sweet spot” prediction.
  • Petrophysical properties characterization of Ordovician Utica shale in Quebec, Canada
    BAI Baojun, SUN Yongpeng, LIU Lingbo
    , 2016, 43(1): 69-76. https://doi.org/10.11698/PED.2016.01.08
    Abstract ( ) Download PDF ( ) Knowledge map Save
    With multiple techniques, the following measurements and analysis were made to characterize the Ordovician Utica shale samples: mineralogy, porosity, microstructure, and surface wettability etc. The test of mercury injection apparatus showed that the pore size of Utica shale is 15-200 nm. X-ray diffraction (XRD) mineralogy analysis and Energy-Dispersive X-ray Spectroscopy (EDS) indicated that in Utica shale non-clay minerals are dominated by calcite and quartz, while clay minerals by illite and chlorite. With the images from scanning electron microscope (SEM), the surface microstructure examination showed various types of pores exist in Utica shale, such as intragranular, intergranular, organic etc. And the pores in organic matter (kerogen) were found in nanometer size (10 to 50 nm). A three-dimensional tomography model and a geometry model of the pores space using FIB-SEM imaging tomography were reconstructed with 250 SEM images. It provides visual insights into the petrophysical properties of Utica shale. Finally, the wettability tests displayed that Utica shale has weak-water wet to intermediate wettability.
  • Stratigraphic sequence, structural framework and hydrocarbon migration of Ariki Field, Nigeria
    AHANEKU C V, OKORO A U, ODOH B I, ANOMNEZE D O, CHIMA K I, EJEKE C F, OKOLI I N
    , 2016, 43(1): 77-83. https://doi.org/10.11698/PED.2016.01.09
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    The structural framework and stratigraphy of the Ariki Field in the Western Shallow Offshore Depobelt, Niger Delta Basin, Nigeria are interpreted using well logs and 3-D seismic data, and the control of rift on hydrocarbon accumulation is analyzed. Five maximum flooding surfaces and five sequence boundaries are identified in the major reservoir of Agbada Formation in the field; and the structural framework of the field is controlled by the major faults, minor faults and rollover anticline formed by extensional tectonic movement. There are a total of seven faults identified across the field, including 3 major faults and 4 minor faults. On the western flank of the field, graben and horst-like structures were created by the minor faults. Fault throw analysis shows that below 1800 ms, the major faults with fault throw increasing act as hydrocarbon migration pathways, while above 1800 ms, with fault throw decreasing, they act as seals of hydrocarbon traps. There are four-way dip rollover anticlines and 3-way downdip traps created by the minor faults, and other prospective traps in the study area, which have substantial oil exploration potential.
  • Well pattern design and deployment for coalbed methane development
    ZHAO Xin, JIANG Bo, XU Qiang, LIU Jiegang, ZHAO Yue, DUAN Piaopiao
    , 2016, 43(1): 84-90. https://doi.org/10.11698/PED.2016.01.10
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    Based on the coalbed methane development of block III in the eastern edge of the Ordos Basin, the well pattern was optimized and dynamically adjusted, according to a system engineering including three stages: well pattern pre-development design stage, well site optimization stage and dynamic tracking stage. The geological basis for well deployment of coalbed methane was proposed and the parameters of well pattern design were optimized during the well pattern pre-development design stage. The geological conditions have been explored from several aspects which include coal bed structure, buried depth, coal seam thickness, roof and floor lithology, gas content, permeability and hydrological condition. The favorable production well pattern was the rhombus pattern. The cluster well was chosen as the main well type and then horizontal well. For the local anisotropy coal seam, rhombus long diagonal was in the direction of face cleats and short diagonal was in the direction of butt cleats. The well spacing was 300-350 m in high permeability zones and 350-400 m in low permeability zones. It is necessary to consider those factors, such as surface, subsurface and drilling conditions, to optimize the well locations during the well site optimization stage and to follow the basic requirements of “surface following subsurface, engineering following geology”. After having observed the well interference and interlayer interference phenomenon during the dynamic tracking stage, twenty-four production wells have been relocated and the producing layers for thirty-six production wells have been changed. Then the well pattern design was more reasonable in this block. It is confirmed that the posterior well pattern design and development mode are more reasonable after the optimal deployment in the block III during this five years.
  • Deep profile adjustment and oil displacement sweep control technique for abnormally high temperature and high salinity reservoirs
    YANG Zhongjian, JIA Suogang, ZHANG Lihui, WU Xingcai, DOU Hongmei, GUO Ziyi, ZENG Lijun, LI Hongwei, GUO Liqiang, JIA Zhiwei, FANG Wei
    , 2016, 43(1): 91-98. https://doi.org/10.11698/PED.2016.01.11
    Abstract ( ) Download PDF ( ) Knowledge map Save
    To improve water flooding sweeping efficiency and oil displacement efficiency in reservoirs with abnormally high temperature and high salinity during late development stage, taking Gasikule E31 reservoir as the research object, lab study and field test of sweep control technique (SCT) were conducted. Performance evaluation and field test results of soft microgel (SMG) agent show that: SCT has good thermal stability in the target reservoir and an effective period of 100-120 d in the field test, and the success rate of SCT can be greatly increased by adjusting particle size and concentration of the gel. Unlike polymer flooding or polymer-gel flooding which improves oil recovery by enhancing sweep efficiency, SCT can improve oil displacement and water sweep efficiency, and its displacement mechanisms have been confirmed by the lab experiment and field test. The SCT has been applied in six well groups in the target reservoir, resulting in a cumulative oil increment of 1.03×104 tons, water production drop of 4.79×104 m3, and an input-output ratio of 1:2.09. But when international oil price is low, SCT project may have high failure risk in application to reservoirs with abnormally high temperature and high salinity.
  • An interwell connectivity inversion model for waterflooded multilayer reservoirs
    ZHAO Hui, KANG Zhijiang, SUN Haitao, ZHANG Xiansong, LI Ying
    , 2016, 43(1): 99-106. https://doi.org/10.11698/PED.2016.01.12
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    In view of the limitations that the current connectivity model can only forecast the fluid production dynamic change, can’t calculate the dynamics of oil and water phases, and can’t analyze the connectivity between wells layer by layer, this study establishes a new interwell connectivity model for multilayer reservoirs which can simulate dynamics of oil and water between wells. The model hierarchically separates the reservoir system into a series of interwell connecting units characterized by parameters such as conductivity and control volume, and by using the material balance equation, the pressure and interwell flow at constant liquid production and constant pressure is calculated with the connecting unit as simulation object, which are combined with the frontal advance theory to establish interwell saturation tracking calculation method, and finally water production dynamics of every layer at well points can be worked out. On this basis, using simultaneous perturbation stochastic approximation method and gradient projection method, a model parameter inversion method is set up by dynamic fitting. The application cases show that the model has good dynamic fitting and prediction effect, inversed model parameters and the actual geological parameters coincide with well, verifing the validity of the method. Compared with the current connectivity method, it can obtain the real-time model of hierarchical interwell flow rate distribution coefficient, liquid production of single well and oil split coefficient and other information, and reflect the reservoir horizontal and vertical oil-water flow relation more accurately, providing guidance for production measure adjustment in oilfield.
  • Evaluation of the stress sensitivity in tight reservoirs
    XIAO Wenlian, LI Tao, LI Min, ZHAO Jinzhou, ZHENG Lingli, LI Ling
    , 2016, 43(1): 107-114. https://doi.org/10.11698/PED.2016.01.13
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    The expressions of three types of stress sensitivity coefficients (S, α, β) are obtained on the basis of analysis of the empirical models and theoretical models on the relationships between permeability and effective stress, and the stress sensitivity evaluation standard is proposed considering experiment data and rock micro-structural features. Then the empirical models and theoretical models were used to fit experiment data of low-permeability and tight sandstones and different types of granites, which promotes the understanding of the empirical models and the physical meanings of the stress sensitivity coefficients. According to the study of the three types of stress sensitivity coefficients and the relationship of effective stress and permeability, it is found that the stress sensitive coefficient S was suitable for evaluating the stress sensitivity (strong stress sensitivity: S>0.40; low stress sensitivity: S<0.25; medium stress sensitivity: 0.25≤S≤0.4). Meanwhile, it is also found that strong-stress-sensitivity cores are more suitable to be characterized by the logarithmic model, while the exponential model (or binomial model) occurred more frequently in low-stress-sensitivity cores, and medium-stress-sensitivity cores are more likely to be described with the power model. Finally, the evaluation standard is discussed based on the micro-structure in the low-permeability and tight sandstones. The results show that the crack-like pores in the strong-stress-sensitivity cores are obvious, but low-stress-sensitivity cores have the characteristics of porous rocks; moreover, the types of cemented clay minerals, the size of rock grain and lithology have impact on stress sensitivity.
  • Geometrical description and permeability calculation about shale tensile micro-fractures
    QU Guanzheng, QU Zhanqing, HAZLETT Randy Doyle, FREED David, MUSTAFAYEV Rahman
    , 2016, 43(1): 115-120. https://doi.org/10.11698/PED.2016.01.14
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    To study fluid flow in shale tensile micro-fractures, five shale core samples, taken from Barnnet Shale, were splitted into artificial tensile fractures based on Brazilian test. The morphology of the artificial fractures was obtained by a 3-D laser sensor profilometer. Then, 3-D information was transformed into 2-D information and the quantitative parameters, such as tortuosity, surface angularity and roughness, were calculated based on the scanning principle. Cluster analysis was introduced to make sure the distance among the parameters, the fluid flow in shale micro-fractures with the opening of 0.05-0.40 mm was simulated by Lattice Boltzmann Method (LBM), and an equation was derived for calculating the shale tensile micro-fracture permeability. The results show that, the tortuosity of the samples is close to 1.10, the angularity is among 0.99°-8.86°, and the roughness is among 0.062-0.162 mm; the parameters cannot be substituted by one another and their effects should be considered at the same time; the micro-fracture permeability is less 19%-29% than the parallel plate model permeability, so the roughness should be included. It is verified that the deviation of the equation is less than 4%, and it can be used to calculate shale tensile micro-fracture permeability.
  • Cuttings carrying characteristics of back-reaming pneumatic impactor exhaust during drilling operation
    XU Hailiang, LI Wang, ZHAO Hongqiang, XU Shaojun
    , 2016, 43(1): 121-126. https://doi.org/10.11698/PED.2016.01.15
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    The flow fields of chip removal from the impactor’s exhaust hole to its rear head were established to study the cuttings carrying characteristics of back-reaming pneumatic impactor exhaust by utilizing the computational fluid dynamics theory and simulation software Fluent. Based on the structure and working principle of the impactor, the gas solid two phase flow was simulated, and the gas phase characteristics of the flow field and the moving trajectory and concentration distribution of particles were obtained. The research shows that: once the exhaust enters the field its speed will slow down and the field pressure will gradually decrease from the entrance to the exit; cuttings particles will gather around the bottom and there is minor variation in their average concentration as they are distributed along a contrary direction against the entrance while the maximum concentration descends along the same direction and finally becomes stable. Moreover, the effect of drilling speed and exhaust mass flow of the impactor on the solid carrying characteristics was analyzed. The result demonstrates that: as the drilling speed increases, the carrying ability of exhaust decreases and when the rated operation pressure is 0.8 MPa, the drilling speed should be less than 12.6 m/h; as the mass flow rate of exhaust increases, the carrying ability increases as well, and the mass flow rate should be moderately increased under the condition of ensuring the working performance of the impactor.
  • Downhole inflow-performance forecast for underground gas storage based on gas reservoir development data
    TANG Ligen, WANG Jieming, DING Guosheng, SUN Shasha, ZHAO Kai, SUN Junchang, GUO Kai, BAI Fengjuan
    , 2016, 43(1): 127-130. https://doi.org/10.11698/PED.2016.01.16
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    In view of the gap between the inflow-performance forecasted by the traditional equation and the actual inflow-performance, experiments of gas-gas alternating seepage flow and gas-water alternating seepage flow were carried out, and a modified equation of inflow-performance relationship considering gas permeability change due to water invasion was established. This equation was verified by example analysis. The experimental results show that: gas permeability of net pay, when water-invaded reservoirs are converted into underground gas storage, is different from that during actual gas field development, in that the value of permeability decreases gradually in gas-water zone while the value increases gradually and even higher than that of original gas field in gas zone as a result of gas water alternative flooding in gas storage. Then one parameter describing the extent of permeability change when gas reservoirs are converted into gas storage was defined based on the result of the experiments, and eventually the traditional equation of inflow-performance relationship was modified to forecast inflow-performance in gas storage based on data from field development. Example analysis result shows that: the modified equation considers the effect of changing permeability, its results agree with the actual inflow-performance, while the result of traditional equation differs greatly from the actual inflow-performance.
  • A high-density organoclay-free oil base drilling fluid based on supramolecular chemistry
    JIANG Guancheng, HE Yinbo, HUANG Xianbin, DENG Zhengqiang, QIN Yong
    , 2016, 43(1): 131-135. https://doi.org/10.11698/PED.2016.01.17
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    Based on supramolecular chemistry, a rheology modifier CFZTQ-1 for oil base drilling fluids was developed, and an innovative high-density organoclay-free oil base drilling fluid system centering on CFZTQ-1 was designed, evaluated and applied in the field. CFZTQ-1 can strongly increase the elasticity of invert emulsion due to the supramolecular structure assembled in water phase; CFZTQ-1 has stronger effect in elevating the yield point and suspension ability than several foreign rheology modifiers; the synergistic effect with organoclay also makes CFZTQ-1 available in traditional clay-contained invert emulsion drilling fluids. Through the category and dosage optimization of related additives, the formula of the high-density organoclay-free oil base drilling fluid was established and its performance was evaluated. The organoclay-free drilling fluid owns favorable rheology with density of 2.40-2.60 g/cm3, yield point of 13-17 Pa, moderate apparent viscosity and relative low plastic viscosity; after hot rolling at 240 ℃, the drilling fluid still keeps a stable performance as its viscosity only increases slightly, its high temperature and high pressure (HTHP) filtration loss is about 10 mL and its electrical stability is greater than 400 V. This innovative drilling fluid system achieves excellent field application as well.
  • Geologic features and genesis of the barriers and intercalations in carbonates: A case study of the Cretaceous Mishrif Formation, West Qurna oil field, Iraq
    DENG Ya, GUO Rui, TIAN Zhongyuan, TAN Wenhao, YI Yingjie, XU Zhenyong, XIAO Cong, CAO Xunchen, CHEN Liang
    , 2016, 43(1): 136-144. https://doi.org/10.11698/PED.2016.01.18
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    The type, poroperm relationship, log response characteristics and identification criteria of the barriers and intercalations in the carbonates of the Cretaceous Mishrif Formation in the West Qurna oil field of Iraq are studied through comprehensive analysis of cores, thin sections and well logs. The genesis and distribution of the barriers and intercalations are analyzed from the perspectives of sequence stratigraphy, depositional facies and diagenesis. The barriers and intercalations can be classified into three types: grainstone, packstone and wackestone. The barriers and intercalations generally exist in restricted platform facies and evaporative platform facies, some in open platform. They are common in transgressive cycles and early regressive cycles, forming continuously, extensive barriers and intercalations near the sequence boundaries. Penecontemporaneous cementation, burial compaction, and burial cementation led to the decrease of the porosity, damaged the space of the reservoir pores and became the important factors for the genesis of the barriers and intercalations. In the epidiagenetic phase, a large number of CaCO3 precipitated in the phreatic water zone below free-water table, leading to the formation of packstone and grainstone barriers and intercalations in a large scale. Through comprehensive log analysis, log identification criteria and the distribution of the barriers and intercalations are determined. The barriers are mainly distributed in the sections of CRI and CRII, and the intercalations are concentrated in the section of mB1. For different types of barriers and intercalations, packstones are the most in quantity, followed by grainstones and wackestones.
  • Influences of adsorption/desorption of shale gas on the apparent properties of matrix pores
    WANG Jing, LUO Haishan, LIU Huiqing, LIN Jie, LI Liwen, LIN Wenxin
    , 2016, 43(1): 145-152. https://doi.org/10.11698/PED.2016.01.19
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    The adsorption/desorption effects impact the petro-physical properties of matrix pores during gas depressurizing production, such as effective pore radius, effective porosity, apparent permeability, which will further impact the gas flow regime. In this paper, the dynamic models of effective pore radius and apparent permeability under the action of gas adsorption/desorption are derived. The mathematical model of shale gas flow is established considering the effects of adsorbed gas on apparent properties and gas flow regime. After that, the model is solved and validated using a finite volume method and experimental and field data. Finally, the variations of apparent parameters of matrix pores and gas flow regimes during gas production, and the influences of adsorption on gas production are demonstrated. The results show that the effective pore radius, porosity and apparent permeability increase during gas production; the gas flow regime in stimulated reservoir volume (SRV) changes from slip flow to transition flow; if the impacts of adsorbed gas on gas production is overlooked, both original gas in place (OGIP) and gas production will be significantly overestimated. The cumulative gas production changes slightly as the adsorption layer thickness increases, but the gas recovery factor decreases.
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