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    Multi-stage activity characteristics of small-scale strike-slip faults in superimposed basin and its identification method: a case study of Shunbei area, Tarim Basin
    HUANG Cheng
    Petroleum Geology & Experiment    2019, 41 (3): 379-389.   DOI: 10.11781/sysydz201903379
    Abstract   PDF (4438KB)  
    The strike-slip faults in superimposed basins usually experienced multi-stage activities. The episodic formation and evolution of strike-slip faults match with the important tectonic transformation periods of superimposed basins. Generally speaking, strike-slip fault zones converge (or stretch) in stress fields at different tectonic stages. It will result in the formation of specific associated structural styles of near-surface tectonic layers in the same period. Finally, a complete vertical tectonic sequence is formed. If the strike-slip associated structures peculiar to each tectonic layer are taken as geological records of strike-slip fault activities in the same period, the episodic activity of the strike-slip faults can be restored step by step from the present underground geological structure, and then the active periods of faults can be determined. In addition, during the episodic slip of strike-slip faults, changes in horizontal slip direction and faulted tectonic-sedimentary geological bodies often occur. These two phenomena actually reflect the core content of the kinematic characteristics of strike-slip faults, namely, the direction and distance of slip. It can also be used as an important basis for judging the active stages of strike-slip faults. Therefore, the Tarim superimposed basin is divided into five tectonic layers on the basis of the study of basin tectonic-sedimentary evolution background. On this basis, the vertical structural sequence and main associated structural styles of strike-slip fault system in the study area are determined. The geometric and kinematic characteristics of strike-slip associated structures in different tectonic layers of Tarim superimposed basin are analyzed. Two types with seven applicability techniques for distinguishing active periods of faults based on seismic data have been formed.
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    Reef control factors and new seismic prediction techniques of Changxing Formation, east of Kaijiang-Liangping trough, Sichuan Basin
    PENG Cai, ZHENG Rongcai, CHEN Hui, WANG Lanying, LUO Jing, LIANG Hong
    Petroleum Geology & Experiment    2019, 41 (4): 614-620.   DOI: 10.11781/sysydz201904614
    Abstract   PDF (2297KB)  
    The sedimentary characteristics, main controlling factors and reef reservoir facies of the Upper Permian Changxing Formation reef on the eastern side of the Kaijiang-Liangping trough in the northeastern Sichuan Basin were studied using comprehensive seismic prediction technology.Through the study of single well sedimentary facies, it is found that there are two stages of longitudinal development of the reefs in this area. The paleogeomorphology of the Changxing Formation has a controlling effect on the development and migration of the reefs:the larger the slope, the thicker the reefs.Early paleo-geomorphology controlled the development of reefs. In the northern steep slope zone, early reef strips developed, while in the southern gentle slope zone, late reef blocks developed. Late paleotopography controlled the migration of reefs to the platform, resulting in the second row of reefs.Targeted prediction techniques were used to account for differences in sedimentary environments in different regions. In the central transitional belt, the amplitude property on the top of Changxing Formation on the platform margin was optimized to predict reef thickness. In the southern gentle slope sedimentary zone, the bioreef is predicted by the seismic-based interpretation technique. The predicted results have been confirmed by actual drilling, and many wells have obtained high-yield gas flow.
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    Discovery and significance of subtle buried hills in Jiyang Depression, Bohai Bay Basin
    MA Lichi, WANG Yongshi, JING Anyu
    Petroleum Geology & Experiment    2020, 42 (1): 13-18.   DOI: 10.11781/sysydz202001013
    Abstract   PDF (1086KB)  
    The exploration of carbonate buried-hills in the Lower Paleozoic in the Jiyang Depression of the Bohai Bay Basin are at a minimum now, and the exploration targets are not clear. Hydrocarbon accumulation conditions were analyzed, especially the effectiveness of traps, which broke the shackles of traditional accumulation models and achieved exploration success. Three new buried-hill reservoir models have been discovered, namely the Chengbei 313 negative structure, the Chengbei Guxie 14 slope, and the Chengjiazhuang laterally adjacent high-permeability reservoirs. These three new models make the buried-hill negative structure, the slope zone with poor trap effectiveness, and the laterally unblocked buried hill fault blocks that were considered to have no exploration potential earlier become favorable exploration targets. The effectiveness of traps was analyzed from the aspects of fault activity characteristics. At the same time, a development model of ‘sand-like mudstone’ buried hill reservoirs was provided, which provided a new idea for the effectiveness analysis of buried hill traps.
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    Formation mechanism of favorable reservoirs in red beds in lower submember of fourth member of Shahejie Formation, Bonan Subsag, Jiyang Depression, Bohai Bay Basin
    MENG Tao
    Petroleum Geology & Experiment    2020, 42 (1): 19-27.   DOI: 10.11781/sysydz202001019
    Abstract   PDF (3413KB)  
    The red beds in the lower submember of the fourth member of Shahejie Formation (Es4) in the Bonan Subsag of the Jiyang Depression of the Bohai Bay Basin have undergone a long period of sedimentation and diagenesis. The mechanism of primary pore retention and the evolution constraints of secondary pores are not clear, which restricts exploration progress. The controlling factors of favorable reservoirs in the red beds were analyzed by means of core observation, casting thin section identification and scanning electron microscopy and combined with reservoir characteristics analysis. The formation mechanism of the favorable reservoirs was summarized, and their distribution was also predicted. There are two major sedimentary systems in the red bed sediments of the lower Es4 submember of Bonan Subsag, including alluvial fan-braided river-braided river delta-lake and fan delta-lake. Sandstones are mainly lithic feldspars. Reservoir porosity is composed of residual primary pores, secondary dissolution pores and fractures. Reservoir physical properties are poor. The reservoir belongs to the category of ultra-low porosity and ultra-low permeability. Under the influence of mechanical compaction and the alternation of alkali and acid fluids, the reservoir porosity in the study area experienced three stages:primary pore retention, secondary pore formation and reservoir densification. Burial depth and favorable facies zones determine the preservation degree of primary pores, while organic acid, abnormally high pressure in overlying strata and fracture distribution determine the degree of secondary pore development. The favorable reservoirs with primary pore development are fan-terminal reservoirs of alluvial fan buried less than 3 000 m,which are distributed as belts on the southern basin margin. The favorable reservoirs with secondary pore development are braided river and braided river delta reservoirs with pressure coefficient greater than 1.2 in the upper submember of Es4 and fault system develop in the lower submember of Es4, which are distributed in sag zones and show strip-like and overlapping sheet distribution.
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    Bimodal hydrocarbon generation and immature oil do not exist in the North Jiangsu Basin
    LIU Yurui
    Petroleum Geology & Experiment    2019, 41 (4): 461-474.   DOI: 10.11781/sysydz201904461
    Abstract   PDF (1528KB)  
    A contradiction in the "immature oil in North Jiangsu Basin" theory prevails and the results of geological exploration is not consistent with it. After making a thorough analysis of previous work and validating the data, the following problems were noticed:misusing of raw data, taking outliers as evidence; multi-parameter consideration is lacking in the hydrocarbon generation model, which makes the inference invalid; the consistency of reservoir and hydrocarbon maturity was not verified after the oil-source correlation; hypotheses do not stand the test of source rock gas logging data and other prospecting results. These indicate that the "non-kerogen source rock early maturation & bimodal hydrocarbon generation model" could be incorrect, and the "immature oil" may not exist. After using big an extensive data set to analyze errors and exclude outliers, the sterane C29S/(S+R) and C29ββ/(αα+ββ), the terpane C31S/(S+R) and C32S/(S+R), as well as CPI and OEP maturity sensitive parameters of hydrocarbon and rocks were optimized. Crude oil from the thermal degradation of late kerogen can be divided into 3 types:low maturity oil, medium maturity oil and mature oil. It is pointed that the maturity parameters of a large quantity of medium maturity source rocks (Ro>0.70%) could match well with those of medium maturity oil; the maturity parameters of low maturity source rocks (0.60% ≤ Ro ≤ 0.70%) have only some matching relationships with a small number of low maturity oil maturity parameters; no crude oil matched the immature source rocks (Ro<0.60%). The results indicate that the non-kerogen immature oil does not exist. Prominent anomalous data can be detected in the medium maturity and mature source rock gas logging. Hydrocarbon traps with these source rocks usually have good exploration results, and 99.83% of the discovered oil reserves belong to this type. There is little or no anomalous data in the low maturity source rock gas logging. This source rock is unable to form a commercial scale reservoir, and only some shows of hydrocarbon may exist. No anomalous data can be found in immature source rock gas logging. If there is no mature oil supply from other places, reservoirs will not be formed.
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    Research progress on marine oil and gas accumulation in Tarim Basin
    GU Yi, HUANG Jiwen, JIA Cunshan, SHAO Zhibing, SUN Yongge, LU Qinghua
    Petroleum Geology & Experiment    2020, 42 (1): 1-12.   DOI: 10.11781/sysydz202001001
    Abstract   PDF (6572KB)  
    In recent years, great achievements have been made in the exploration of ultra-deep marine oil and gas in the Tarim Basin. New oil and gas discoveries have been achieved in the Shunbei Ordovician, Tazhong Cambrian and Tahe deep strata, which provide abundant basic data for studying the marine oil and gas accumulation in the Tarim Basin. The marine oil and gas in the Tarim Basin are mainly distributed in the platform-basin area. There are various types of reservoirs, and the physical properties of crude oil vary greatly, showing the complexity of hydrocarbon accumulation. Through the analysis of a large number of samples, simulation experiments and extensive geology and geochemistry analysis, combined with the research results of tectonic evolution, sequence stratigraphy, sedimentary facies and sedimentary environments, some significant progress has been achieved such as the distribution and evolution of source rocks, oil and gas geochemistry characteristics, and the distribution characteristics of marine oil and gas reservoirs. The following achievements have been made:1) clarification that the marine oil and gas in the Tarim platform-basin area mainly come from the Lower Cambrian-Middle/Lower Ordovician source rocks formed under strongly reducing environments, especially the Lower Cambrian Yuertusi Formation in the platform-basin.Two alterations types of ultra-deep marine reservoirs, namely, TSR and thermal cracking are defined, and the corresponding identification indicators are proposed. 2) by establishing the sedimentary development mode of the gentle slope-type high-quality Yuertusi source rocks, through well-seismic calibration, forward modeling, regional survey line interpretation of seismic facies, 3D area attribute analysis and seismic inversion, the distribution of source rocks in the Yuertusi Formation may be predicted, and their evolution characteristics clarified:the "high-pressure hydrocarbon generation evolution inhibition mode" under the long-term lowgeothermal background since theYanshan period has delayed the thermal evolution of Shuntuoguole low uplift Cambrian source rocks, and the Shuntuoguole area still has the formation conditions of late high-maturity liquid hydrocarbon. 3) by comparing the hydrocarbon accumulation characteristics of the platform-basin area, the Ordovician oil and gas distribution characteristics have been clarified, further delineating the Cambrian Yuertusi in situ source rocks there, and identification of the light oil-gas reservoirs matching with the active strike-slip faults in the late Yanshan period and charged by the late hydrocarbon supply, which provide an key direction for oil and gas exploration in the ultra-deep carbonate rocks of the Tarim platform-basin area.
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    Pore structure characteristics and controls of Lower Cambrian Niutitang Formation, western Hubei Province
    HE Qing, HE Sheng, DONG Tian, ZHAI Gangyi, WANG Yi, WAN Kuo
    Petroleum Geology & Experiment    2019, 41 (4): 530-539.   DOI: 10.11781/sysydz201904530
    Abstract   PDF (5657KB)  
    The pore structure features of shale in the Lower Cambrian Niutitang Formation in the western Hubei Province were examined using low-temperature CO2 and N2 adsorption tests, Field Emission-Scanning Electron Microscopy (FE-SEM) observations, TOC content measurements, and X-ray diffraction analyses. The TOC content is high in the Niutitang Formation, and the dominant pore types are organic pores and intra-particle pores, displaying complex pore morphology. XRD analysis suggests that the mineral components are dominated by quartz and clays. The CO2 and N2 adsorption experiments show that the pore size distribution displays multi-peaks, and the size of mesopores was mostly within the range of 2-25 nm. The pore volumes and specific surface areas of Niutitang shale are mainly provided by micropores and mesopores. Three shale lithofacies can be identified including siliceous shale, mixed shale and muddy shale. The role of TOC content and minerals on pore development is different in different lithofacies of Niutitang Formation. The porosity development of siliceous shale is mainly affected by the contents of TOC and biogenic silica. The porosity development of mixed shale is mainly affected by the contents of TOC and clay minerals.
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    Shale reservoir characteristics of Ordovician Wufeng-Silurian Longmaxi formations in Dangyang synclinorium, Middle Yangtze region
    FAN Jiawei, CHEN Kongquan, SHEN Junjun, ZHU Wei, TANG Xiehua, LI Junjun, WANG Pengwan, ZHANG Fang
    Petroleum Geology & Experiment    2020, 42 (1): 69-78.   DOI: 10.11781/sysydz202001069
    Abstract   PDF (2623KB)  
    The petrological and organic geochemical characteristics, reservoir porosity types and features, and gas-bearing characteristics of organic-rich shale were systematically studied using FIB-SEM, mineral contentanalysis, organic geochemical analysis and low-temperature and low-pressure nitrogen adsorption porosity determination, and drilling data of typical wells in the Dangyang synclinorium. (1) Vertically, shale reservoirs from the Wufeng Formation(O3w) are quite different from the first section of the first member of Longmaxi Formation (S1l11). High-quality shale reservoirs are developed from S1l1(1)1 to S1l1(2)1 sublayers,with a high abundance of organic matter (2.45%-6.98%), type Ⅱ1-Ⅱ2 organic matter, rather high thermal evolution degree, high brittle mineral content (34.0%-85.5%), low clay mineral content (9.0%-40.3%), and high total gas content (1.76-4.30 m3/t). Organic pores are well developed. In the S1l1(3)1 sublayer, affected by the intensified Caledonian tectonic activity, terrigenous material input increased, and reservoir quality began to deteriorate. (2) Horizontally, organic-rich shale of the Wufeng-Longmaxi formations in the Dangyang synclinorium become thicker from southeast to northwest, and the reservoir quality becomes better. (3) Shale reservoirs in the S1l1(1)1-S1l1(2)1 sublayers in the study area are the "sweetest" and the "most brittle".However, considering the convenience of real-time monitoring and adjustment of well trajectory during horizontal drilling, the upper and lower half of GR peak in the S1l11(1) sublayer should be selected as the best horizontal target of horizontal wells.
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    Porosity measurement error and its control method
    BAO Yunjie, LI Zhiming, YANG Zhenheng, QIAN Menhui, LIU Peng, TAO Guoliang
    Petroleum Geology & Experiment    2019, 41 (4): 593-597.   DOI: 10.11781/sysydz201904593
    Abstract   PDF (508KB)  
    With the expansion of oil and gas exploration, the lithology and morphology of porosity test samples show diverse development trends. Porosity measurement faces new challenges because the same sample may have different laboratory porosity measurement results, limiting the application of porosity data. Starting from two key parameters of the total volume and skeleton volume of the rock sample, the influence of test error on the porosity measurement results was analyzed. It is found that when the relative error of the test is 0.5%, 1.0% and 1.5%, the absolute error of porosity is 0.5, 0.9 and 1.4, respectively. The test error of the two has similar influence on the accuracy of porosity measurement, and should be effectively controlled. The current situation of error control of rock sample skeleton volume and total volume was analyzed. Volume testing relies on more mature methods and devices, and its test error can be effectively controlled. The development of total volume testing technology lags behind. The acquisition of key parameters in the measurement process is affected by random human factors, resulting in differences between different operators and different laboratory results. The method for effectively controlling porosity measurement error was discussed. A total sample volume measurement system for rock samples based on the fluid density determination principle was introduced, which has no restrictive requirements on the lithology and morphology of the sample, and automates the determination of the total volume of rock sample. The influence of human factors on the test can be reduced. The average relative error of the total volume of rock sample is 0.5%, and the absolute error of porosity measurement can be controlled to about 0.5, which can be used to narrow the difference of measurement results in different laboratories.
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    Main controlling factors of shale gas enrichment and high yield: a case study of Wufeng-Longmaxi formations in Fuling area, Sichuan Basin
    FANG Dongliang, MENG Zhiyong
    Petroleum Geology & Experiment    2020, 42 (1): 37-41.   DOI: 10.11781/sysydz202001037
    Abstract   PDF (1612KB)  
    The controlling factors of shale gas enrichment and yield were discussed based on core observation, geochemical analysis, logging and seismic data of marine shale collected from the Wufeng-Longmaxi formations in the Fuling area of Sichuan Basin. Total organic carbon content, micro-to nano-scale pores and preservation conditions are the main controlling factors for shale gas enrichment. The total organic carbon content is not only an important parameter for evaluating original shale quality, but also affects micro-to nano-scale pore development. The preservation condition is important for shale gas enrichment. The high yield of shale gas is affected by brittle mineral content, burial depth, structural morphology and fractures. The higher the brittle mineral content, the better the compressibility of shale and the better the effect of fracturing. In addition, burial depth and structure features have great effect on crustal stress, and thus have significant influence on fracturing. Natural fracture development leads to directional pressure relief during fracturing, and it is difficult to form an effective and complex permeability mesh.
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