Table of Content

01 August 2019, Volume 40 Issue 4 Previous Issue    Next Issue

For Selected:

Download Citations EndNote Reference Manager ProCite BibTeX RefWorks

Toggle Thumbnails

Geological Characteristics, Resource Potential and Exploration Direction of Shale Oil in Middle-Lower Permian, Junggar Basin ZHI Dongminga, SONG Yongb, HE Wenjunb, JIA Xiyub, ZOU Yangb, HUANG Liliangb 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190402 Abstract ( 223 )   PDF (300KB) ( 556 )   Save The Middle-Lower Permian series, the most important source rocks in Junggar basin, are dominated by multi-source, fine-grained mixed sediments deposited in a terrestrial salty lake environment and have good conditions for shale oil generation. A shale oil province with the OOIP of one billion tons has been discovered in the Lucaogou formation of Jimsar sag. Based on the previous study results and combined with the available geological data, the paper systematically summarizes the geological characteristics of the favorable shale oil areas in the Middle-Lower Permian of the basin. Meanwhile, on the basis of benchmarking with the geological characteristics of the shale oil in the Lucaogou formation of Jimsar sag, the shale oil exploration potential in the Fengcheng formation of Mahu sag and the Pingdiquan formation of Wucaiwan-Shishugou sag is analyzed and the next exploration direction for the shale oil in the basin is discussed. The study results show that the multi-source fine-grained mixed sediments of shore-shallow lacustrine-semi-deep lacustrine facies in the Middle-Lower Permian strata of the basin are the high-quality source rocks where tight sweet-spot reservoirs are developed, and the reservoir combination is characterized by source rock-reservoir superposition and frequent interbed with each other vertically, which lays a foundation for shale oil accumulation in the Middle-Lower Permian strata. Typical terrestrial shale oil characteristics such as hydrocarbon mainly coming from neighboring source rocks, self generation as the complementary and in-situ accumulation can be obviously seen. The maximum proven resources of the shale oil in the basin is 27.25×108 t. The geological conditions of the Fengcheng shale oil in the Mahu sag are better than those of the Lucaogou shale oil in Jimsar sag, therefore, the Fengcheng formation in Mahu sag is considered as the next key area for shale oil exploration. The geological conditions of the Pingdiquan shale oil in Wucaiwan-Shishugou sag are relatively poor, and the shale oil here can only be considered as a prospect area for exploration. Additionally, the Luocaogou formation in the piedmont of Bogda Mountain and the Pingdiquan formation in the slope area of Fukang-Dongdaohaizi sag are the potential areas for shale oil exploration and at present comprehensive geological research should be performed to gain more geological understandings and to complete technical preparation work Related Articles | Metrics

Practices and Prospects of Shale Oil Exploration in Jimsar Sag of Junggar Basin WANG Xiaojuna, YANG Zhifengb,c, GUO Xuguangb, WANG Xiatianb, FENG Youlunb, HUANG Liliangb 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190403 Abstract ( 134 )   PDF (300KB) ( 259 )   Save Based on the review of the exploration history of Permian shale oil in Junggar basin, the geological conditions, oil and gas accumulation mechanism and enrichment pattern of the shale oil in Jimsar sag are analyzed, the geophysical prospecting techniques obtained from previous shale oil exploration practices are systematically summarized and the direction of future shale oil deployment in Junggar basin is pointed out. The exploration practices prove that the shale oil in Jimsar sag is very typical in China’s terrestrial shale oil which is characterized by salty lake basin, multi-source mixed sedimentation, source rock-reservoir integration and scattered “sweet spot” distribution. The shale oil in the Lucaogou formation exhibits 2 occurrences such as absorbed state and free state and is considered as accumulation within source or accumulation near source. Many technological breakthroughs in shale oil exploration have been made and matched seismic prediction technologies for sweet spot and high-resolution comprehensive logging evaluation technologies have been developed. The study results show that the western part of Jimsar sag has favorable geological conditions for high yield of shale oil and should be considered as the new area for the terrestrial lacustrine shale oil exploration in Junggar basin. Based on which, a national demonstration zone for shale oil exploration and development will be established in order to provide reference and technical support for the exploration deployment of terrestrial lacustrine shale oil in China Related Articles | Metrics

Genesis and Accumulation Periods of Oil in Yanchang Formation of Daijiaping Area, Ordos Basin LIU Xuezhen1, YANG Yingchun1, ZHOU Xiang2 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190404 Abstract ( 77 )   PDF (300KB) ( 139 )   Save To solve the disputes about oil-source relationship in Yanchang formation of Daijiaping area, Ordos basin, the paper systematically analyzes the geochemical characteristics and accumulation periods of the oil in different horizons of Yanchang formation based on the analysis on the extract group components, saturated hydrocarbon gas chromatography-mass spectrometry and inclusion homogenization temperature test of the oil and source rock samples. The results show that the geochemical characteristics of the oil in different horizons are basically the same, indicating a fairly deep-deep lacustrine sediments formed in a fresh water-brackish water and weak reduction-reduction sedimentary environment. The kerogen is characterized by the mixtures of lower hydrobiont and terrestrial higher plant. The homogenization temperatures of the rock samples from different horizons of Yanchang formation in Daijiaping area show a feature of double-peak distribution, and the homogenization temperatures of the inclusions in the reservoirs of Chang 82 and Chang 9 are higher than those in reservoirs of Chang 6 and Chang 81. The analysis on the burial history shows that there were 2 oil charging periods, namely the end of Late Jurassic-the middle of Early Cretaceous. Using the parameters of biomarkers to do Q-type analysis, the oil of Yanchang formation can be divided into 2 types, TypeⅠincludes the oil from Chang 6 and Chang 81 and TypeⅡincludes the oil from Chang 82 and Chang 9. Although both of the 2 types of oil come from the source rocks of Chang 7, but the oil maturity parameters such as C2920S/(20S+20R), C29 ββ/(αα+ββ), Pr/Ph and gammacerane index of TypeⅠoil are obviously lowerer than those of TypeⅡ, and the parameters reflecting organic matter source like αααC27 sterane/（C27-29）sterane, 4-methy sterane/regular sterane and Pr/nC17 of TypeⅠoil are slightly higher than those of TypeⅡ. The analysis on hydrocarbon accumulation periods indicates that TypeⅠoil is the mixture of the matured oil generated during the hydrocarbon generation peak and the previously existing low-maturity oil in the source rocks of Chang 7, and TypeⅡoil should be the product of large scaled hydrocarbon charging during the middle of Early Cretaceous Related Articles | Metrics

Discovery of Flysch Facies and Its Oil-Gas Geology Implication of Early Carboniferous Strata in Dibei Swell, Junggar Basin HUANG Yun1, LIANG Shuyi2, REN Jiangling3, LI Yanping1, GU Xinping1, FU Xiaopeng1 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190405 Abstract ( 106 )   PDF (300KB) ( 71 )   Save Combining the related study of the Carboniferous prototype basin in Junggar basin, based on the analysis on the data of drilling, logging, seismic, fossil and thin section, and comparing with the characteristcs of the Early Carboniferous marine sediments in Dinan swell, the paper identifies that the Early Carboniferous was the extension period of the Kalamaili Ocean after its subduction. Under the background of the remain ocean after the closing of ocean basin, thick flysch formations which are typical in Well Quan-5 were developed and submarine volcano erupted intermittently. In the massive flysch formation with the thickness about 1 000 m, marine dark shale of the Bouma sequence E and sandstones of Bouma sequence A and B constituted the structures of source rocks interbedded with reservoirs vertically. The geochemical analysis results show that the dark shales are widely developed and has high maturity in the flysch formation and can be considered as relatively good-good source rocks. The understanding not only changes the previous opinion that the low-maturity Carboniferous source rocks in Dibei swell have no exploration potential, but expands the existing hydrocarbon accumulation pattern of near source rocks and controlled by uplifts in Kelameili gas field. A new gas accumulation pattern of source-reservoir integration in tight sandstones is proposed for the Lower Carboniferous strata in Dibei swell, which will be of practical significance for the natural gas exploration in the Carboniferous formation Related Articles | Metrics

Description of the Boundary of Banded Sand Body in the Fourth Member of Akekule Formation in Eastern Tahe Oilfield, Tarim Basin YANG Min1, LIU Jinhua2, XIAN Wei1, GUO Rui1, XIA Buyu2 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190406 Abstract ( 85 )   PDF (300KB) ( 191 )   Save In order to accurately understand the banded sand body distribution and its boundary in the fourth member of Akekule formation of Tahe oilfield, the detailed description of the boundary of the banded sand body is carried out based on the analysis of the sand body genesis. Based on the researches on lithology, grain size and sand body distribution, it is considered that the fourth Member of Akekule formation in the study area was deposited in a littoral-shallow lacustrine environment and the banded sand body is the genesis of littoral-shallow lacustrine sand bars. Seismic attributes sensitive to reservoir are used to identify sand body and seismic waveform is used to describe the sand body boundary. The results show that the RMS amplitude is the attribute sensitive to target sand body in the study area, SP is the reservoir-sensitive logging curve and the SP of the sandstone is less than 24 mV. Based on RMS amplitude sand body prediction and SP seismic motion inversion and combined with drilling data, the reservoir boundary of the fourth member of Akekule formation in Wellblock TK7226 is identified. Finally, the width of the banded sand body in the wellblock is determined as 170-300 m, the oil-bearing area has been ascertained accurately Related Articles | Metrics

Microfacies and Characteristics of Carbonate Reservoir in Xiaoerbulake Formation of Keping Area, Tarim Basin JIANG Weimin1, LIU Bo1, SHI Kaibo1, GAO Xiaoqiao2, LIU Fan3, YU Jinxin1 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190407 Abstract ( 113 )   PDF (300KB) ( 75 )   Save A suite of over 100 m thick dolomite was deposited in the Lower Cambrian Xiaoerbulake formation, Tarim basin. Based on the detailed observation and description of the sedimentary and paleontological characteristics of more than 1 000 thin sections obtained from 11 field sections in Keping area, the paper analyzes the petrological and fossil features and sedimentary environment of the Lower Cambrian Xiaoerbulake formation with microfacies analysis method. According to the microscopic characteristics of grain, biogroup and sedimentary fabric of the carbonate rock, 11 microfacies types and 5 microfacies assemblages with similar genesis and certain continuity in vertical variation are identified and classified in the Xiaoerbulake formation. In addition, the results of microfacies analysis also show that the reservoir development of the Xiaoerbulake formation is mainly controlled by sedimentary environment, and the intercrystal (dissolved) pore, intergranular (dissolved) pore and microbial framework pores are the main reservoir spaces. Weak-laminated fine-grained dolomite (MF2) and intraclastic dolomite (MF10) have the best petrophysical properties, and microbial microfacies such as MF6, MF7 and MF8 have relatively good petrophysical properties Related Articles | Metrics

Characteristics of Strike-Slip Faults and Fault-Karst Carbonate Reservoirs in Halahatang Area, Tarim Basin ZHENG Xiaoli, AN Haiting, WANG Zujun, ZHOU Hongbo, ZHANG Liangliang 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190408 Abstract ( 127 )   PDF (300KB) ( 260 )   Save A large number of strike-slip faults are developed in the Ordovician carbonate strata of Halahatang area in the northern Tarim basin. Fractured-vuggy reservoirs formed along these faults after multiple periods of karstification. Covered by the overlying cap rock and blocked by the lateral tight limestone, the unique “fault-karst trap” formed. Using the high-precision 3D seismic attributes of coherence and amplitude, and combining with drilling data and production performance, the paper comprehensively studies the relationship between strike-slip faults and fault-karst traps in the Halahatang area. The study results show that the strike-slip faults in Halahatang area have a characteristic of “strong activity in the north and weak activity in the south”, the main fault zone in the north of the Halahatang area are mainly composed of braided and horsetail fractures, and the main fault zone in the south of the area are dominated by linear and echelon fractures. The development of 4 types of fault-karst traps such as platy, echelon, braided and foliated traps were controlled by different structure styles, oil and gas migrated along the main faults to branch faults and finally accumulated in the higher positions of the fault-karst bodies. Both the connectivity of the fault-karst bodies and the positions of hydrocarbon enrichment in the fault-karst bodies determine the well production Related Articles | Metrics

Influences of H2S Content on Condensate Gas Phases in High Sulfur Gas Reservoirs SHI Ying1, LIU Jianyi2, LI Guangming1, LI Hui2, MIAO Jinjin1, TANG Dan1 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190409 Abstract ( 116 )   PDF (300KB) ( 172 )   Save Aiming at the large differences of H2S content in the condensate gas wells in District Ⅱof Gas Field Ⅰof Tazhong area, a high-pressure physical-property experimental evaluation method is proposed. Different amounts of pure H2S gas were added to the on-site separated gas sample, and the on-site condensate oil sample was mixed with the gas sample at a constant produced gas-oil ratio and the samples with different H2S contents were obtained. The experiment was carried out at the formation temperature and the influences of different H2S contents on condensate gas phases were studied. The results show that when H2S contents increase, the contents of CO2, N2, C1—C5 and C6+ in the well fluid decrease; the dew point pressure shows a linear decrease and will decrease by 0.67 MPa every time when the H2S content of the sample increases by 1%; the anti-condensate oil saturation is basically the same, but the precipitation time of the anti-condensate oil is delayed, and the recovery factors of condensate oil and natural gas are both reduced. This is because H2S is a good oil-gas miscible solvent, which can reduce miscible pressure and result in a decrease in dew point pressure and a delay of the condensate oil precipitation, indicating that the presence of H2S is not conducive to the exploitation of condensate gas wells Related Articles | Metrics

Displacement Mechanism Analysis of Residual Oil Film in Micro-Channels LIU Lili1a,1b, WANG Lihui2, SONG Hua1c, LI Kun1a,1b, WANG Jiabo1a,1b 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190410 Abstract ( 73 )   PDF (300KB) ( 194 )   Save In order to analyze the displacement mechanism of residual oil film in micro-channels, taking micro-channel residual oil film as an example, the paper analyzes the resistance acting on the residual oil film by rock wall, the interfacial tension between displacement fluid and residual oil film and the horizontal force on the residual oil film by displacement fluid after residual oil film wetting hysteresis occurring, and discusses the displacement mechanism of the residual oil film. Combined with continuity equation, motion equation and constitutive equations of visco-elastic fluid, numerical simulation is carried out to calculate the distribution of the horizontal stress acting on the residual oil film by displacement fluid with different rheological properties. The results show that increasing the horizontal force acting on the oil film can activiate the oil film to become movable oil; under the condition that the flow rate of the displacement fluid is constant, and the size and direction of the horizontal stress acting on the oil film by visco-elastic fluid will change. The existence of the elasticity can change the force distribution rules acting on the residual oil film and is in favor of the oil film activation Related Articles | Metrics

Gravity Water-Drainage Assisted Steam Flooding of Heavy Oil: 3D Physical Modeling Experiment FENG Cuiju1a, WANG Chunsheng1b, ZHANG Rong2, SHENG Han3 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190411 Abstract ( 95 )   PDF (300KB) ( 144 )   Save Based on the model of the experimental well group Wa 60-H25 in Block Wa-59 of Liaohe oilfield, a 3D model is designed for the experiment based on the similarity theory and a high-temperature and high-pressure resistant core model which is in accordance with the corresponding permeabilities is made according to geological conditions, and the corresponding experimental procedure and condition are designed, too. The transient liquid yield, transient oil production and the variations of watercut with time during the displacement are obtained from the experiment. The production process can be classified into 4 phases and the production performance of each phase is accurately described. The experimental method, model and results can be used for reference in future experiments of heavy oil gravity flooding and have important guiding significance for heavy oil development by gravity water-drainage assisted steam flooding Related Articles | Metrics

Methods to Predict Horizontal Section Producing Status of Horizontal Wells in Reservoirs With Bottom Water GUO Changyong1, XIONG Qiyong1, DENG Weibing1, KONG Xinmin1, ZHAO Fengkai2, LI Dongdong2 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190412 Abstract ( 133 )   PDF (300KB) ( 235 )   Save In the development process of the bottom-water reservoirs in horizontal wells, the production effects in the horizontal wells are severely restricted by the unbalanced producing status of the horizontal section. In order to improve the producing effects of the horizontal sections in horizontal wells in bottom-water reservoirs, the conventional horizontal well testing data are used to perform modern well test interpretation for the target horizontal well, and the effective producing length and the geological and development parameters of the wells are obtained. Then, numerical simulation is used to establish a numerical model to simulate the reservoir production performance. With this method, the producing status of the horizontal section can be obtained and its influences are analyzed. The results show in horizontal Well H, serious bottom water invasion appears in the middle part, both edge and bottom water invasion are serious in the toe-end and the producing status is poor in the heel-end. An optimal solution is proposed, that is adding artificial barriers and controlling watercut, maintaining the liquid production rate at 20 m3/d, meanwhile increasing the water injection volume in neighboring wells and doing selective water plugging Related Articles | Metrics

Numerical Simulation of Gas Injection Development in Donghe-1 Carboniferous Reservoir With A Heavy Oil Cushion SHAO Guangqiang, BIAN Wanjiang, WANG Kaiyu, FAN Jin, TAO Zhengwu, KUANG Xiyu, FAN Kun 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190413 Abstract ( 78 )   PDF (300KB) ( 237 )   Save Aiming at the characteristics of low bubble point pressure, high structure amplitude, having a heavy oil cushion at the bottom of the reservoir and developed interlayers in Donghe-1 Carboniferous reservoir, equivalent numerical models are established to simulate the gas injection reservoir development mechanism after waterflooding, to analyze the errors of component models converted at different time, to determine the reasonable conversion timing and improve the efficiency and accuracy of the models. By comparing the differences between conventional grid and hybrid grid methods to deal with the heavy oil cushion, the paper describes the shape of the heavy oil cushion, analyzes the influences of the cushion on production performance and improves the history matching accuracy. The equivalent models are used to rapid simulate the gas injection process after waterflooding and to compare the differences between different injection media and different injection modes, providing basis for the establishment of actual reservoir model and study of gas injection mechanism. The study results show that the equivalent models can significantly improve the research efficiency; the hybrid grid method is more accurate in describing the shape and vertical properties of the heavy oil cushion; at the end of waterflooding, about 90% of the fitting time can be saved and the error can be controlled with the relative errors of main indicators less than 1% by changing the oil-water two-phase or three-phase black oil model into the component model. The mechanism study indicates that during reservoir development converted from waterflooding to gas injection, interlayers could inhibit gas channeling to some extent. Influenced by gravity and with the vertical dynamic balancing of gas-oil-water three phases, a new oil ring may occur at the bottom of secondary gas cap. When gas-oil ratio exceeds 200 m3/m3, gas yield should be controlled to increase gas injection efficiency Related Articles | Metrics

Experimental Study and Mechanism Analysis on Improvement of Oil Displacement Efficiency by Superheated Steam Injection GUO Bin, LIN Riyi, WANG Zeyu, MA Qiang, WANG Xinwei 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190414 Abstract ( 91 )   PDF (300KB) ( 175 )   Save In order to study the improvement of oil displacement efficiency by superheated steam injection, an indoor single-tube experiment was carried out to study how the steam quality and injection rate influence the recovery factor, and the oil displacement mechanism was analyzed from four aspects：viscosity, permeability, thermal expansion coefficient and distillation ratio. The results show that when the steam injection rate is 1.8 mL/min, the steam with 15 ℃ degree of superheat is the optimal injected steam quality and the ultimate recovery factor can reach 77.8%; when the optimal steam quality is injected, the optimal steam injection rate will be 1.3 mL/min, and the ultimate recovery factor can reach 79.6%. After the oil displacement by superheated steam, the viscosity of heavy oil at 50 ℃ can be reduced by 40.7%. The average thermal expansion coefficient of the experimental oil is 0.000 653 ℃-1, the oil temperature increases by 300 ℃ and its volume will increase by 19.6%. The superheated steam will cause the transformation of montmorillonite and kaolinite to chlorite or illite, physical washing can increase the pore channel and improve the reservoir seepage behavior Related Articles | Metrics

Application of Geology-Engineering Integration in Efficient Exploration in Structure KS24 YIN Guoqing, ZHANG Hui, WANG Haiying, WANG Zhimin, LIU Xinyu 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190415 Abstract ( 82 )   PDF (300KB) ( 212 )   Save Aiming at well location deployment, drilling speed increasing and well-completion production improvement in the Structure KS24 of Kelasu tectonic belt in the piedmont area of Kuqa depression during exploration, an analysis on the three aspects is carried out from the perspective of geology-engineering integration. In the stage of well location deployment, it is predicted that the faults controlling the structure have good sealing and is conducive to oil and gas preservation. On the basis of geological prediction and geomechanical research, the borehole stabilities are identified for shallow high-steep interval, gravel interval, mudstone interval, gypsum interval and fractured sandstone interval, and measures for optimizing drilling fluid performance are proposed. In the well completion stage, according to the geomechanical characteristics, a reasonable production improvement mode is formulated, and the stimulated interval, operation pressure and perforation cluster are optimized. According to the research results, 9 wells such as Well KS24 and Well KS241 etc. have been drilled successively and no abnormalities occur. The drilling speed is increased by 39% in average, which creates a drilling record in Kelasu tectonic belt. Different stimulation methods are adopted in the 5 drilled wells, the average gas well production is 31×104 m3/d, the average open flow capacity is 170×104 m3/d, and both the exploration success rate and high-yield well rate reach 100%. During the exploration practices in the Structure KS24, a procedure of geology-engineering integration study and its application has been established, and has been combined into well location deployment-drilling and engineering integration, which has become an effective mean to solve exploration and development problems under complex geological conditions Related Articles | Metrics

An Overburden Pressure Correction Method of 3D Digital Cores TAN Hongkun, LU Shuangfang, TANG Mingming, WANG Min, LI Chuanming, WANG Hailong 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190416 Abstract ( 102 )   PDF (300KB) ( 242 )   Save Micro CT is usually used at atmospheric pressure, leading to the pore throat characteristics obtained under the actual overburden pressure different from those obtained from CT scanning. In order to make the CDRM’s pore throat structure more similar to the actual one, taking the porosity and permeability data under overburden pressure from tight sandstones of the second and third member of Qingshankou formation in Longhupao area, Songliao basin as examples, the paper studies the influences of the overburden pressure on porosity and permeability. Combined with Micro CT scanning images and dilation algorithm, the variations of porosity and permeability of a digital core under the overburden pressure are simulated and a digital core model corrected with overburden pressure is established on the basis of overburden pressure exponential function and dilation algorithm. The results show that the pore space in the digital core is reduced obviously, and the simulated permeability obtained from the corrected digital core model is consistent with the calculated value of overburden permeability test with the coincidence rate over 90%. Compared with the traditional CDRM, this model can reflect the characteristics of pore throats under the condition of overburden pressure and provide guidance for oil and gas development Related Articles | Metrics

Predicting Total Organic Carbon Content in Marine Shale Reservoirs With Nuclear Logging Data ZHAO Bing 2019, 40 (4):  1-1.  doi: 10.7657/XJPG20190417 Abstract ( 66 )   PDF (300KB) ( 150 )   Save Total organic carbon (TOC) content is an important parameter reflecting the amount of shale reservoir resources, and nuclear logging data can provide a lot of information about the abundance of organic matter in source rocks. In this paper, the correlations between the response values of various nuclear logging curves and TOC in the wells X1, X2 and X3 in the southeastern Sichuan basin are analyzed. Considering the geological factors that affect the content of TOC, the single nuclear logging curve which is sensitive to TOC content and the combination of the nuclear logging curves that can reflect the genesis of TOC are selected. Then a TOC content prediction model with nuclear logging curves suitable for this area is established through BP neural network. Finally, the model was applied to Well X4 in the southeastern Sichuan basin. Compared with the TOC contents obtained from the core analysis of 113 core samples, the mean relative error of the model prediction results is 0.41, indicating that the prediction accuracy of the new model is high, which can meet the actual production demands in the area. Then the model was applied to the marine shale reservoirs in W and Y blocks of the southern Sichuan basin and good effects have been gained, which can prove the good operability, wide versatility and high evaluation accuracy of the model. The new method provides an effective technological mean for the evaluation of total organic carbon content in marine shale reservoirs Related Articles | Metrics