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    01 December 2019, Volume 40 Issue 6 Previous Issue    Next Issue
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    Prediction of Multi-Provenance Sand Body Distribution in Triassic Baikouquan Formation of Madong Area, Junggar Basin
    SONG Yong1a,2, ZHOU Lu1, WU Yong1b, YOU Xincai2, NIU Zhijie2, REN Benbing2
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190601
    Abstract ( 217 )   PDF (300KB) ( 124 )   Save
    Aiming at the complex relationship among the sand bodies controlled by different fans under the multi-provenance conditions and based on the structural interpretation results of the contiguous 3D seismic data formed by several 3D seismic survey networks in the Madong area of the Mahu sag, Junggar basin. The paper clarifies the forming conditions and paleo-tectonic characteristics of the multiple provenances in the area on the basis of structural interpretation and paleo-geomorphic analysis of the Triassic Baikouquan formation in the Madong area; performs identification and prediction of the fan boundaries and their relations with multiple provenances in different intervals of the Baikouquan formation in the Madong area by using seismic waveform classification method. Using seismic attribute and seismic inversion prediction methods, the authors comprehensively analyze the distribution of the sand bodies in the fan delta fronts of different fans and conclude the features of complex superimposition vertically and continuity but disconnection laterally, or spot-like isolated distribution
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    Sedimentary Evolution of Alluvial Fan Under Combined Action of Drainage System and Structure: A Case of Huangshuigou Alluvial Fan in Piedmont of Southern Tianshan Mountains
    GAO Zhiyong1, SHI Yuxin1, FENG Jiarui1, ZHOU Chuanmin1, ZHAI Yicheng2, FAN Xiaorong2
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190602
    Abstract ( 209 )   PDF (300KB) ( 116 )   Save
    By dissecting the evolution characteristics of the proximal-distal drainage systems of the modern alluvial fan in the piedmont of the southern Tianshan Mountains, the relationship between the sandy conglomeratic sediment variation and the transport distance, the structural characteristics, the slope gradient of fan surface, and the controlling effect of tectonic activities on sediments, it is considered that there are many new types of alluvial fans developed in the piedmont of the southern Tianshan Mountains, which are influenced by both drainage system and structure. The drainage system on the surface of the alluvial fans is distributed from provenance area to alluvial plain, which has the evolution features of intermountain river-single braided channel-composite braided channel zone-low curvature single runoff channel-seasonal river. The sudden increase of the slope gradient on the alluvial fan surface caused the changes of river channel type, channel width and sediment grain size. Meanwhile, a "steep in the north and gentle in the south" fold belt which is parallel to the provenance area in the southern Tianshan Mountains and extends tens of kilometers formed in the early deposited alluvial fan of weak consolidation diagenesis under the action of tectonic uplift. Like the secondary step in the piedmont area, the topographic slope of the depositional area increased and the sandy conglomerate with weak consolidation diagenesis provided the secondary source for the present deposition. Under the combined action of active drainage system and fold belt resulted from tectonic uplift, multi-stage sandy conglomeratic alluvial fan occurred. Based on the above understanding, the paper establishes a new model of alluvial fan sedimentary evolution under the combination of drainage system and tectonism in arid-semi-arid climate, which provides references for the genetic mechanism of large-scale distribution of sandy conglomeratic sediments in foreland thrust belt
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    Influences of Feldspar Dissolution on Reservoir Physical Properties of Clastics in the Lower Jurassic Coal Measures, Eastern Kuqa Depression
    WU Jin, WANG Bo, ZHU Chao, GONG Qingshun, SONG Guangyong, WANG Hui
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190603
    Abstract ( 95 )   PDF (300KB) ( 66 )   Save
    The dissolution of acid fluids to feldspar is commonly found in the Lower Jurassic coal measures in the eastern Kuqa depression and the thin section analysis shows that a large number of secondary dissolution pores are developed in feldspar and rock debris. Under different diagenesis conditions, feldspar dissolution degree, feldspar dissolution product type and feldspar dissolution product quantity are different, which result in different effects on reservoir physical properties. Based on the analysis of thin section, cast thin section and scanning electron microscope and using whole rock analysis, clay mineral analysis and fluid inclusion data, the paper analyzes feldspar dissolution, diagenetic environment, the differences of feldspar dissolution products and their effects on reservoir physical properties in different diagenetic environments. The study shows that in the Lower Jurassic reservoirs in the Dibei area of the eastern Kuqa depression, the dissolution of feldspar occurs in a relatively closed high-temperature diagenetic environment, the dissolution rate of feldspar is high under high temperature conditions, and fluids flow slowly in this closed diagenetic environment. Therefore, a large amount of feldspar dissolution products precipitate in the intergranular and intragranular pores nearby. When the burial depth is less than 4 000 m (the temperature is less than 110 °C), the products of feldspar dissolution are mainly silica and kaolinite, the kaolinite is dispersed like dots and the pores are not filled. The intercrystalline pores are developed and have good connectivity so that to some extent, the physical properties of the reservoir are improved. When the burial depth is more than 4 000 m (the temperature is higher than 110 °C), the feldspar dissolution products are mainly silica and illite, the hairy and flaky illite fills the pores in sandstone, leaving no pore spaces, and it is easy to form debris to block the pores, which reduces the porosity and permeability of the reservoir. The dissolution of feldspar in the Lower Jurassic reservoirs in the Tugerming area occurs in a relatively open and shallow diagenetic environment, the products of feldspar dissolution can be effectively brought out of the dissolution zone, and only a small amount of silica and kaolinite precipitate. The feldspar dissolution in this area has an effective pore-enhancing effect on the reservoir
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    Forming Mechanism of Zeolites in Lower Wuerhe Formation in Slope Area of Mahu Sag
    YANG Hongxia1, CHEN Xuekun2, TIAN Yutong3,WANG Jian1, LI Lulu1, LEI Haiyan1
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190604
    Abstract ( 125 )   PDF (300KB) ( 193 )   Save
    A large number of zeolite cements have been found in the reservoirs of the lower Wuerhe formation in the slope area of Mahu sag, Junggar basin. In order to clarify the influences of zeolite minerals on reservoir quality and oil-bearing property, the experimental methods such as rock thin section, casting thin section, SEM, energy spectrum, electron probe, cathodoluminescence, whole-rock diffraction and inclusions have been used to research the characteristics, types and distribution of zeolite minerals. Furthermore, the formation mechanism of zeolite minerals in reservoirs is clarified and the relationship between the development of zeolite and oil-bearing property of reservoirs is revealed. The results show that five kinds of zeolite minerals are developed in the reservoirs of the lower Wuerhe formation in the slope area of Mahu sag. The zeolites are mainly consisted of laumontite with small amounts of heulandite and trace amounts of analcime, clinoptilolite and stilbite. The heulandite commonly coexists with laumontite and small amounts of clinoptilolite coexists with heulandite. The distribution of zeolites is controlled by sedimentary facies, the laumontite is mainly developed in the fan delta front with relatively good porosity and permeability and the heulandite is developed in the front of fan delta plain. The genesis of zeolite minerals can be divided into three types of two categories, namely metasomatic genesis model caused by plagioclase albitization and volcanic material alteration and cementation genesis model which is the dominant. The precipitation of zeolite in the early stage of diagenesis enhanced the ability of reservoir to resist normal compaction so that partial primary pores could be preserved, which provided flow channels for acid fluid and dissolution in the middle stage of diagenesis. The dissolution of zeolite during hydrocarbon accumulation period is beneficial to the high quality reservoir formation
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    Shale Gas Content and Its Influencing Factors in Chang 7 Member of Southeastern Ordos Basin
    ZHANG Hongjie1a, WANG Fengqin1a,1b, LIU Hang1a, LIU Jiansheng2, ZHANG Xue1a, WANG Haiping1a, WANG Yuting1a
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190605
    Abstract ( 151 )   PDF (300KB) ( 150 )   Save
    By means of empirical formula method, isothermal adsorption method and multiple linear regression method, the paper compares the characteristics of shale gas content in different phase states of Chang 7 member in the southeastern Ordos basin, establishes the qualitative or quantitative relationships between the shale gas content and its influencing factors, and discusses the main controlling factors of the shale gas content in each phase state. The results show that the average contents of adsorbed gas, free gas and dissolved gas in the shale of Chang 7 member in the study area are 1.37 m3/t, 1.81 m3/t and 0.74 m3/t, respectively, the adsorbed gas volume gradually decreases from southwest to northeast, and the contents of free gas and dissolved gas decrease gradually from northwest to southeast. The total organic carbon(TOC) content is the main factor controlling the adsorbed gas content in the shale of Chang 7 member; the mixed layer of illite/ montmorillonite in minerals has an important influence on the content of adsorbed gas; with the increase of organic matter maturity, a large number of residual liquid hydrocarbons appear, the contents of adsorbed gas and free gas decrease, and the content of dissolved gas increases. The medium-large pore volume is the main factor controlling the contents of free gas and dissolved gas. Sandstone intercalation and brittle minerals such as quartz and feldspar affect the proportion of medium-large pores and further influence the contents of free gas and dissolved gas
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    Productivity Differences of Gas Reservoirs in the Fourth Member of Sinian Dengying Formation in GaoshitiMoxi Area, Central Sichuan Basin
    TIAN Xingwang, ZHANG Xihua, PENG Hanlin, MA Kui, YANG Dailin, SUN Yiting
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190606
    Abstract ( 119 )   PDF (300KB) ( 188 )   Save
    Sinian Dengying formation in Gaoshiti-Moxi area of central Sichuan basin is characterized by complicated lithologies and strong heterogeneity. The productivity in the western platform margin area is higher than that in eastern platform area and efficient exploration is facing great challenges. Using the data of core, logging and seismic and starting from sedimentary environment, reservoir diagenesis and hydrocarbon charging distance, the paper discusses the main factors controlling the productivity differences of the gas reservoirs in the fourth member of Dengying formation in the study area and proposes technical countermeasures on geological engineering. The results show that the tested productions in the western platform margin and the eastern platform are significantly different, the tested production of the western platform margin area is high due to large thickness of the gas zone, while that of the eastern platform is low due to small thickness of the gas zone; the main influencing factors for the productivity difference include the development degree of favorable dome-beach facies, intensity of karstification at the end of Tongwan movement, reservoir vertical development degree and position, and lateral distance to hydrocarbon generation center etc. According to the characteristics of the reservoir and its seismic responses, vertical well, highly-deviated well and horizontal well are selected to improve high quality reservoir penetration ratio and single well production, which can effectively guide the natural gas exploration and development and good effects have been gained in the study area
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    A Study on Mechanism of Oil Displacement by Imbibition
    LI Chuanliang1, MAO Wanyi2, WU Tingxin3, ZHU Suyang1
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190608
    Abstract ( 417 )   PDF (300KB) ( 585 )   Save
    Oil displacement by imbibition is an effective way of oil recovery in fractured reservoirs. However, there is not a unified recognition on its mechanism. In order to clarify the mechanism of imbibition, a study is carried out and some conclusions are obtained in this paper. Imbibition can be divided into cocurrent imbibition and countercurrent imbibition and the imbibition in reservoirs belongs to cocurrent imbibition. Imbibition can also be classified as horizontal imbibition and vertical imbibition, and vertical imbibition is more complicated than horizontal imbibition. All the imbibitions in reservoirs belong to vertical imbibition. Imbibition also includes one-side-contact imbibition, two-side-contact imbibition and all-side-contact imbibition, and the imbibition in reservoirs belongs to all-side-contact imbibition. Imbibition can also be divided into capillary pressure imbibition and buoyance imbibition. Capillary pressure imbibition can only suck water into rocks and expulse oil, while buoyance imbibition can either suck water into rocks to expulse oil or suck oil into rocks to expulse water. The imbibition in reservoirs belongs to buoyance imbibition. Imbibition in larger pores is faster than that in smaller pores. End-effect may retain some oil in rocks, which will decrease imbibition efficiency. Adding surfactant into water can decrease the influence of end-effect. The larger the matrix block is, the higher the imbibition recovery efficiency will be, but the longer time will be taken for imbibition. The matrix block size and reservoir rock fragmentation degree during volumetric fracturing can be optimized through experiments
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    Flow Mechanism of Shale Oil Reservoir in Jimsar Sag
    WANG Ziqianga,b, LI Chuntaoc, ZHANG Daiyanc, ZHANG Haoa
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190609
    Abstract ( 177 )   PDF (300KB) ( 219 )   Save
    To understand the rules of flow in shale oil reservoir, taking the Lucaogou formation of Jimsar sag in Junggar basin as an example, the micro-pore structures and flow mechanism of the shale oil reservoir were studied by means of laboratory physical experiments and digital core technology. Based on the physical experiment of single-phase flow through shale oil cores, a non-linear mathematical model of single-phase flow based on starting pressure gradient and an empirical formula of permeability related to pore structure parameters were obtained. Digital core technology and Lattice Boltzmann method were used to simulate the single-phase fluid of shale oil and to realize the fine characterization of fluid flow. The results show that the relation between seepage velocity and pressure gradient in the shale oil reservoir has a typical non-darcy flow characteristic, which is a cubic function relation with a good correlation.
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    Analysis of Rock Mechanics and Assessments of Hydraulic Fracture Network in Conglomerate Reservoirs of Mahu Oilfield
    HE Xiaodong1, MA Junxiu1, LIU Gang2, SHI Shanzhi1, YOU Jun2, WU Juntao3
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190610
    Abstract ( 196 )   PDF (300KB) ( 318 )   Save
    Conglomerate reservoirs are characterized by tight rocks, poor cementation and strong heterogeneity, which make it difficult to analyze the complex geometry of the fractures in conglomerate reservoirs only by using geophysical well logging data or single mechanical testing method. In order to evaluate the forming capacity of hydraulic fracture network in conglomerate reservoirs, a combination of various testing methods is proposed to test the mechanical parameters of conglomerate. Taking the conglomerate reservoir of Baikouquan formation in the Well Ma-15 of the Mahu oilfield in the northwestern margin of Junggar basin as a case, the paper systematically analyzes the elasticity, compressibility, tensile property, brittleness and in-situ stress of the conglomerate reservoir and evaluates forming capacity of hydraulic fracture network. The results show that the dynamic and static elastic modulus of the reservoir are well correlated with each other, but the correlation of dynamic and static Poisson ratio is poor. The tested Biot coefficient ranges from 0.43 to 0.60, which indicates that the rock is typical of moderate-to-tight lithology. The in-situ stress in the study area is biased towards compressive strike-slip stress, and the degree of gravel cementation is low, resulting in relatively low compressive, tensile, and shear strength of the conglomerate and damages such as shear fracturing or gravel-penetrating or gravel-bypassing are easy to occur under the external loads. Planar fracture is the main form during fracturing and complex fractures form in local conglomerate formation
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    Experimental Study on Nano-Particle/CO2 Foam Flooding Effect in High-Temperature High-Pressure Reservoirs
    ZHAO Yunhai1, WANG Jian1, LYU Bolin2a, YANG Zhidong2b, HU Zhanqun2b, ZHANG Zuowei3
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190611
    Abstract ( 172 )   PDF (300KB) ( 372 )   Save
    The reservoir in the small well spacing CO2 flooding test area of the Block Hei 79, Jilin Oilfield is featured with serious heterogeneity, unbalanced displacement plane, poor gas entry and water injection profiles and gas channeling, which influence the recovery factor of miscible flooding. Due to the high reservoir temperature (96.7 ℃) and the average reservoir pressure reaching 23.9 MPa in the test area, the stability of the conventional CO2 foam system is poor. The paper proposes a nano-particle/ CO2 foam system under high-temperature high-pressure reservoir conditions and performs evaluation for its application performance under simulated reservoir conditions. The experiment results show that under the reservoir conditions, the nano-particle/CO2 foam system has very good temperature resistance and salt tolerance, and with the increase of the reservoir pressure, the CO2 foam is easy to mix with foaming agent solution and a tighter net-like structure forms when it reaches a critical state, whose performance is better than that under normal pressure. The shunt rates of both high-permeability and low-permeability intervals are about 50% after injecting the nano-particle/CO2 foam system. During the displacement foam can effectively block high-permeability interval and modify gas entry profile. Finally the recovery factor of low-permeability interval can be improved
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    Mixed Large Well Pattern Development Technology of Tight Sandstone Gas in Sulige Gas Field, Ordos Basin
    ZHANG Ji, FAN Qianqian, WANG Yan, HOU Kefeng, WANG Wensheng, WU Xiaoning
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190612
    Abstract ( 103 )   PDF (300KB) ( 176 )   Save
    Sulige gas field in Ordos basin belongs to typical large tight sandstone gas reservoirs. According to its geological characteristics such as multiple series bearing gas and poor lateral continuity of sand bodies, a three-dimensional mixed large well pattern development technology has been developed. Based on the period division of composite sand body vertically and planar division of single-period channel sand body, 4 effective sand body superimposition modes such as isolated mode, incising superimposition mode, stacking superimposition mode and lateral connection mode are identified. In-situ interference test and gas reservoir engineering demonstration method are used to optimize well pattern and a mixed well pattern is established according to the different sand body superimposition modes and the reservoir features. Considering the advantages of horizontal well, vertical well and directional well, the three-dimensional mixed well pattern development technology has been established for large well groups in multiple series of Paleozoic. With the technology the three-dimensional reservoir development and one-off producing of the whole reserves have been realized in the fluvial sandstone reservoirs of Shan 1 member and He 8 member and in the marine carbonate reservoir of the fifth member of Majiagou formation, the producing degree of reserves has been effectively improved, the development cost has been reduced, and finally the economic and efficient development of the gas field can be guaranteed
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    Selection and Application of Oil Displacement System for EOR in Extra-Low Permeability Reservoirs
    ZHAO Jiyong, XIONG Weiliang, FAN Wei, LI Shuman
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190613
    Abstract ( 141 )   PDF (300KB) ( 281 )   Save
    How to effectively improve the recovery factor has always been a difficulty for extra-low permeability reservoir development. Taking the Triassic Chang-6 reservoir, a typical extra-low permeability reservoir in Changqing oilfiled as a case, the paper studies the oil displacement systems which could match with the reservoir characteristics to improve the oil recovery factor. Based on the evaluation of the oil displacement efficiencies of different displacement systems with different interfacial activities, emulsifying properties and viscosities, the paper identifies that the emulsifying property is the primary indicator of the screening of surfactant for extra-low permeability reservoirs, followed by the interfacial activity. When the oil displacement agent has the both characteristics, the oil displacement efficiency can be greatly improved. A surfactant flooding system with high interfacial activity, strong emulsibility and low viscosity is screened out and the result of core displacement experiment shows that the CQ-I system can increase oil displacement efficiency by more than 28.9% based on waterflooding. Based on the results of indoor research, a field test of 4 well groups was carried out in District A of W Oilfield in Changqing oilfield. By the end of December 2017, the incremental oil production of the test well group was 5 889.9 t, and the input-output ratio was 1∶2.25 at that stage, showing good application effects
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    Sensitive Attribute Fusion Technology to Predicct Deep Thin Interbedded ReservoirA Case from Channel Sand Bodies in the Lower Sha-3 Member of Shahejie Formation in Linnan Area
    JIANG Leia, ZHANG Yunyina, LIN Zhongkaib
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190614
    Abstract ( 100 )   PDF (300KB) ( 164 )   Save
    Deep channel sand body is characterized by deep burial, small thickness and weak seismic reflection, and it is difficult for conventional seismic attribute prediction technology to identify deep thin reservoirs. Based on the stratigraphic classification and correlation and the seismic reflection analysis, the paper establishes the seismic response characteristics of the channel sand bodies by using a forward model, studies the attributes sensitive to seismic targets, extracts reasonable attributes of small time window for geological targets, then performs clustering constrained fusion for these small time windows in different areas and conducts detailed characterization for favorable reservoirs, develops a grading sensitive attribute fusion method and finally establishes a reservoir prediction technology for deep channel sand bodies, which can guide the exploration for deep channel sand bodies
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    A Practical Method to Predict Productivity of Multistage Fractured Horizontal Well in Tight Oil Reservoirs
    LIU Wenfeng, ZHANG Xuyang, ZHANG Xiaoshuan, HE Bing, GU Mingxiang
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190615
    Abstract ( 147 )   PDF (300KB) ( 342 )   Save
    To solve the problem of the large errors in multistage fractured horizontal well productivity prediction in Mahu tight oilfield, the authors investigate the research status and countermeasures at home and abroad, conclude that the reason leading to large errors is the strong reservoir heterogeneity and it is difficult to solve the horizontal heterogeneity problem by using the formula method to predict horizontal well productivity. A tight oil productivity prediction procedure is established for horizontal wells by using stimulation ratio method. Firstly, the correlation between vertical well productivity and geological parameters is established and then the correlation between the stimulation ratio of horizontal well (horizontal well productivity divided by vertical well productivity) and geological parameters, finally the planar distribution of horizontal well productivity can be predicted. The actual production from newly-drilled wells proves that the accuracy of the new prediction method is higher than those of analogy and formula methods.Keywords:
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    Application of CT Scanning in Study on Pore Features of Mud-Rich Reservoir : A Case of Wellblock Ma-18 in Mahu Sag
    MA Cong1a, WANG Jian1a, LIAN Lixia1a, WANG Yutao1b, LEI Haiyan1a, LI Weifeng2
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190616
    Abstract ( 172 )   PDF (300KB) ( 247 )   Save
    High oil production has been achieved from the mud-rich reservoir of Baikouquan formation in multiple wells of Wellblock Ma-18 of Mahu sag, which contradicts the traditional understanding of "poor oil-bearing property of mud-rich intervals". To study the formation mechanism of shrinkage pore in mud-rich reservoir and its influences on the reservoir, micron-CT scanning technology and digital core calculation method are used to study the 3D pore structures in mud-rich reservoirs and the results show that the permeabilities of rock samples with developed shrinkage pores are much higher than those of the samples with undeveloped shrinkage pores. In-situ electronic probe technology is used to analyze the components of mud matrix in Baikouquan formation and the results indicate that during the transformation of potassium- and silicon-rich, iron- and magnesium-poor mud matrix to mica minerals, shrinkage pores occurred. The analysis on pore content, porosity, permeability and formation test production show that the porosity and permeability of the mud-rich interval with developed shrinkage pores shows an increase trend. Combined with the sedimentary analysis, it is considered that the mud-rich reservoir in the Wellblock Ma-18 deposited in an underwater distributary channel. The comprehensive analysis shows that the shrinkage pores can not only expand reservoir spaces but connect with other types of pores, then to improve the storage capacity and permeability of the mud-rich reservoir. Favorable sedimentary environment, good lithology and unique configuration of reservoir spaces are the main reasons for the high quality mud-rich reservoir, and the shrinkage pore is the key factor. Based on the above understandings, good formation test results have been gained in the mud-rich reservoir identified by using logging chart, which provides a new idea and direction for potential tapping in the Mahu area
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    Research Progress on Shale Oil Mobility Characterization
    ZHU Xiaomeng1, ZHU Wenbing1, CAO Jian2, SONG Yu1, ZHANG Dongmei1, HU Shouzhi1, LI Shuifu1
    2019, 40 (6):  1-1.  doi: 10.7657/XJPG20190617
    Abstract ( 348 )   PDF (300KB) ( 743 )   Save
    The mobility of shale oil and its characterization are key issues of shale oil study. The paper reviews the research progress on shale oil mobility characterization and proposes the study directions for shale oil mobility characterization. Shale oil mainly has 2 kinds of occurrence, namely adsorbed state and free state. The former is the main contributor for petroleum productivity so that the free oil mobility and its characterization are very important. The research methods of free oil can be divided into 2 categories such as direct characterization and indirect calculation. Direct characterization is subdivided into pyrolysis method and extraction method, but the experiment and analysis processes of the both methods are very complicated. Indirect calculation method is subdivided into the calculation method based on oil saturation of shale and the difference subtraction method based on the difference between the total shale oil content and the adsorbed shale oil content, the former leads to large errors and higher calculation results and the latter can obtain the theoretical max. mobile oil content. The accuracy of the latter method depends on the determination of the adsorbed shale oil content. The adsorption to oil mainly occurs in the organic matter of shale, but the mechanism of adsorption of organic matter to shale oil still remains unclear. Therefore, the investigation and determination of the adsorption capacity of kerogen to liquid hydrocarbons and its product composition variations and further revealing the adsorption mechanism of kerogen to shale oil are the new directions of the study on shale oil mobility characterization
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