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Table of Content

    28 October 2020, Volume 41 Issue 5
    Previous Issue    Next Issue
    Petroleum Geology
    Hydrocarbon charging and accumulation of BZ 19-6 gas condensate field in deep buried hills of Bozhong Depression, Bohai Sea
    Yong'an Xue, Qi Wang, Chengmin Niu, Quanyun Miao, Mengxing Liu, Jie Yin
    2020, 41(5):  891-902.  doi:10.11743/ogg20200501
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    The sources' charging and possible accumulation processes of hydrocarbon in the BZ 19-6 buried hill reservoirs were investigated based on analyses of the geochemistry of condensate samples, the hydrocarbon generation history of source rocks in neighboring sags, and the petrology, homogenization temperature and GOI values (frequency of quartz grains containing oil-bearing inclusions) of fluid inclusions.The results reveal that the gas condensate in the BZ 19-6 reservoirs is high in thermal maturity and its corresponding source rocks have Ro values approximately 1.3%.The light hydrocarbon and carbon isotopic compositions as well as biomarkers all point to oil-prone source rocks in the Shahejie Formation (Es3 and Es1).Most hydrocarbon inclusions are distributed in the micro-cracks of quartz, with only a few scattering at the overgrown edge.Liquid hydrocarbon inclusions have yellow-green and blue-white fluorescent, with a GOI value of up to 80%, indicating an almost fully-charged reservoir.The gas condensate reservoirs in the Bozhong Sag are characterized by nearby source rocks with continuous charging of early oil and late gas.The oil charging concentrated during the deposition of the Lower Minghuazhen Formation (12-5.1 Ma), and the large-scale gas charging occurred in the late stage of the Lower Minghuazhen Formation or even later (5.1-0 Ma).Despite an obvious vertical migration of oil and gas during the Neotectonic Movement, the rapid maturation of source rocks and strong near-source charging are considered to be a more important physical foundation for the dynamic hydrocarbon enrichment in deep buried hills of activation zones.

    Genesis of natural gas and genetic relationship between the gas and associated condensate in Bozhong 19-6 gas condensate field, Bohai Bay Basin
    Anwen Hu, Deying Wang, Haibo Yu, Tao Jiang, Zhe Sun
    2020, 41(5):  903-912, 984.  doi:10.11743/ogg20200502
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    The genesis of natural gas in the Bozhong 19-6 gas condensate field in the Bohai Bay Basin is analyzed by means of petroleum geochemical analyses, and the genetic relationship between condensate and natural gas is thereby determined.The results show that the natural gas in the Bozhong 19-6 gas condensate field is mainly composed of wet hydrocarbon gases with relatively low C1/(C2+C3) values ranging from 6.4 to 7.3, and carbon isotope values of methane and ethane ranging from -38.0‰ to -39.0‰ and from -25.4‰ to -27.0‰, respectively, indicating humic-prone kerogene-cracked gases probably derived from the source rocks of the third member of the Shahejie Formation.A number of condensate and gas maturity parameters show that both condensate and natural gas from the field are mature, with natural gas slightly maturer than condensate.Geological evidences also reveal that the field went through a hydrocarbon accumulation process of "early oil and late gas", with the main condensate accumulation stages (since 12 Ma) prior to those of natural gas (since 5 Ma).

    Charging characteristics and accumulation process of deep low-permeability (tight) sand gas reservoirs in Banqiao Sag, Huanghua Depression
    Xianzheng Zhao, Jianhui Zeng, Guomeng Han, Sen Feng, Qianru Shi, Yazhou Liu, Dongli Fu, Yanu Wang, Jie Zong, Yi Lu
    2020, 41(5):  913-927.  doi:10.11743/ogg20200503
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    A large number of deep low-permeability (tight) sand gas reservoirs are discovered in the Bohai Bay Basin, but the systematic investigation of hydrocarbon charging mechanism and accumulation process related to those reservoirs is rarely seen.The study investigates the Banqiao Sag by analyzing genetic affinities among gas samples at first, and then the relationship between the charging path, dynamics and resistance, as well as discussing the charging patterns by using a series of data, including logging, core observation, seismic surveys, tests and analyses.Meanwhile, combined with the systematic test and analysis of fluid inclusions, the charging characteristics and accumulation process of deep low-permeability (tight) sand gas in Banqiao Sag are discussed.The results show that gases in the study area are primarily a mixture of condensate oil associated gas and coal-derived gas from the 3rd member of Shahejie Formation (Es3) at mature to high-mature stages.According to the spatial distribution patterns between source rocks and reservoirs, the source-reservoir assemblages can be classified into three types, namely, the united source-reservoir type, the adjacent source-reservoir type and the separated source-reservoir type.The networks of pores, fractures and faults in the deep sand beds constitute the pathways for gas charging.The charging dynamics of deep natural gas is greater than the displacement pressure of faults and sand beds with 7.80-7.95MPa for the united source-reservoir assemblage, and 4.80-9.55 MPa for the last two.Whereas the displacement pressure of fault zones and sand beds ranges from 3.14 to 7.05 MPa, and from 0.01 to 0.29 MPa respectively.There are two kinds of charging patterns for the first assemblage:the first one is that the gas can be charged directly to the sand beds through the source rocks, the primary mode for the united source-reservoir type; the second one is that natural gas has sufficient dynamic to migrate upward through faults, and then can be migrated laterally in the upper sand beds, the main mode for the last two.In addition, the multi-stage and dynamic accumulation process of the deep gas reservoirs in Banqiao Sag is described as "two stages of oil charging, that is, oil charging before gas charging, a dominant pattern in the late period", which results in a distribution of "upper petroleum and lower gas vertically, and hydrocarbon accumulation near faults".

    Lithological combination, genesis and exploration significance of the Lower Cambrian Wusonggeer Formation of Kalpin area in Tarim Basin: Insight through the deepest Asian onshore well-Well Luntan 1
    Tianfu Zhang, Lili Huang, Xinfeng Ni, Ran Xiong, Guo Yang, Guangren Meng, Jianfeng Zheng, Wei Chen
    2020, 41(5):  928-940.  doi:10.11743/ogg20200504
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    The Wusonggeer Formation is a set of dolostone adjoining the gypsum pool of the Middle Cambrian.Its lithological combinations and genesis are therefore of great significance to the exploration strategy transition from "approaching source rocks" of the Lower Cambrian to "gypsum or gypsum-related strata" of the Middle Cambrian in the Tarim Basin.The study investigates the lithology and reservoir space types and discusses the sedimentary facies evolution and reservoir forming mechanisms in the Wusonggeer Formation of the Keping area through observation of outcrops and analyses of representative wells.The result shows that the Wusonggeer Formation in the Keping area is dominated by tidal flat facies of the mixed flat with terrigenous clastics and carbonates, dolomitic flat, gypseous-dolomitic flat and grain shoal flat, lithologically corresponding to the terrigenous clastic dolomite, argillaceous dolomite, granular dolomite, muddy-silty algal dolomite, stromatolite dolomite and etc.The algae-related dolomites including the grain dolostone, silty alga dolostone, and stromatolite dolostone, provide most reservoiring space with their intergranular and intragranular dissolved pores.The grain shoal was developed in the intertidal high-energy zone during a transgression against a tidal flat environment and contains intergranular pores dissolved by atmospheric fresh water during a penecontemporaneous stage.The silty algae dolostone was mainly developed in the dolomitic tidal-flat and gypsum dolomitic tidal-fat environment and contains intercrystalline pores and intercrystalline dissolved micro-pores due to microbial-induced dolomitization and dissolution of soluble substances like gypsolyte.Based on an integration of the tectonic high characterization, tidal flat settings of gypsolyte, lithological combinations and genesis of the Wusonggeer Formation in the Keping area, we identified six potential exploration targets in the periphery of several paleo-uplifts in the south of Tarim Basin and the south of Luntai and Yaha areas.

    Hydrocarbon accumulation characteristics of the Silurian reservoirs in Shuntuoguole region of Tarim Basin and their exploration significance
    Huili Li, Jingjing Li, Sujyu Yang, Zhongyuan Ma
    2020, 41(5):  941-952.  doi:10.11743/ogg20200505
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    A light oil reservoir was discovered in a reservoir-cap assemblage at the middle-to-lower members of the Silurian Kepingtage Formation in Well SH 9 drilled in the low uplifting area of Shuntuoguole region in Tarim Basin.Its properties were found to be quite different from those of the heavy oil reservoirs in the upper members of the Kepingtage Formation.A comparative study of the reservoirs in the upper and lower members was then conducted to better understand their accumulation process through geochemical analyses as well as characterization of reservoir bitumen and fluid inclusions in crude oil and oil-bearing sandstone extracts gathered during the drilling of Well SH 9.The results show that the samples from the lower member all have higher content of saturated hydrocarbon and lower content of asphaltene, but those from the upper member vary greatly from one to another.The two members share the similar distribution of normal alkanes, steranes and terpenes as well as carbon isotopic compositions.However, the 25-norhopanoids compounds are identified only in samples from the upper member.Both members contain reservoir bitumen but with different occurrence and optical properties.Oil inclusions in both members are similar in host mineral, fluorescence characteristics, and homogeneous temperature distributions.Combined with tectonic evolution and drilling activities, the study suggests that both members have experienced the same first stage of hydrocarbon accumulation and formed two petroliferous intervals with different hydrocarbon properties due to different preserving conditions.The lower member has better preservation conditions than the upper member.The light oil reservoir discovered in the lower member is very likely to be an old primary reservoir formed during the Late Caledonian to Early Hercynian, hence the primary oil reservoirs in the Silurian are still the focus of exploration in Shuntuoguole region.

    Origin of Cambrian dolomite from Well Milan 1 in Tadong area and its significance to dolomite reservoirs
    Chuntao Guo, Haiqiang Song, Jie Liang, Lingmei Ni
    2020, 41(5):  953-964.  doi:10.11743/ogg20200506
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    Knowing reservoir distribution pattern is key to the exploration of deep dolomite reservoirs in the eastern Tarim Basin.To understand the origin of the Cambrian dolomite in the Milan area of the Tadong low uplift, we measured the rare earth elements (REE) of dolomite of various types taken from a representative well Milan 1 for geochemical characterization based on core and thin section observations.The results show that the content of all REEs in various dolostones is low, and the total mass fraction decreases with the increase of grain size.There are obvious differences in δEu anomalies for dolostones of different types.The δEu anomaly values of silty-micritic, finely-crystalline, medium-crystalline and coarse-crystalline dolostones range between 0.97-1.08, 0.77-1.05, 0.80-3.23 and 0.81-2.23, respectively.Most of the samples have negative δCe anomaly values, ranging from 0.86 to 1.02.The results show that the PAAS-normalized pattern of REEs in all samples can be divided into three types:the negative, positive and normal types.An in-depth study on the dolomitization process demonstrates that the formation of the Cambrian dolomite is essentially caused by evaporation pump mechanism.In addition, the dolomite of the negative type was also under the impact of a burial environment at a later formation stage; the positive type was modified in a hydrothermal environment at a later stage; and the normal type was mainly formed under the effect of seepage reflux.In conclusion, the formation of dolomite reservoirs is conditioned by a variety of factors, including a favorable distribution of sedimentary facies as a prerequisite; large-scale dolomitization as the foundation; dissolution as the key, and the fracture systems as versatile influencers.

    Hydrocarbon accumulation stages and their controlling factors in the northern Ordovician Shunbei 5 fault zone, Tarim Basin
    Bin Wang, Yongqiang Zhao, Sheng He, Xiaowen Guo, Zicheng Cao, Shang Deng, Xian Wu, Yi Yang
    2020, 41(5):  965-974.  doi:10.11743/ogg20200507
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    The characterization of faulted-karst reservoirs in the Shunbei area demonstrates well the important role played by strike slip faults in hydrocarbon accumulation.Based on the identification and division of the crystallization stages of the calcite veins in the Ordovician reservoirs at the north section of the Shunbei 5 fault belt, the hydrocarbon accumulation stages are determined through fluid inclusion analyses and the effect of strike-slip faults on hydrocarbon accumulation stages is revealed by fault zone activity analyses.The results show that there are three phases of calcite vein generation in the Ordovician reservoirs, of which the second phase was formed during the late Silurian.The development characteristics of bitumen and fluid inclusions in the reservoirs reveal two stages of oil charge, with the first stage presumably occurring (before the second phase of the calcite generation) in the late Caledonian and being destroyed later in the early Hercynian.The second stage from the late Hercynian to Indosinian (ca.260-230 Ma) is the main stage for hydrocarbon accumulation in the Ordovician faulted-karst.Fault zone activity analyses of the Shunbei 5 fault belt show a good correspondence between the activity times and the hydrocarbon charge and destruction stages, indicating that the strike-slip fault activities in the Shunbei area is the main factor controlling the hydrocarbon accumulation.

    Characteristics of Ordovician reservoirs in Shunbei 1 and 5 fault zones, Tarim Basin
    Zicheng Cao, Qinghua Lu, Yi Gu, Xian Wu, Donghua You, Xiuxiang Zhu
    2020, 41(5):  975-984.  doi:10.11743/ogg20200508
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    The Ordovician reservoir characteristics in two major fault zones (Shunbei 1 and 5) in the Shunbei area of the Tarim Basin were studied by integrated petroleum geochemical analysis techniques.The reservoir characteristics in the two fault zones are finely described and compared based on petroleum physical properties and hydrocarbon facies attributes, with a view to obtaining the origin of differential characteristics for reservoirs in different fault zones.The results show that the two fault zones share similar oil-gas sources of sapropelic hydrocarbon-generating parent materials with strong reducibility and of high thermal maturity.However, the Shunbei 1 fault zone has unsaturated volatile oil reservoirs, whereas the Shunbei 5 fault zone has unsaturated light oil reservoirs; and the maturity of oil and gas from the Shunbei 1 fault zone is significantly higher than that from the Shunbei 5 fault zone.These differences could be attributed to the multi-stage oil and gas charge and later reformation in the Shunbei area, which may have undergone three stages of hydrocarbon charge.The reservoirs in the Shunbei 5 fault zone were formed by both the first and second stages of hydrocarbon charge (mainly by the second stage as the hydrocarbon from the first stage of charge was mostly dissipated due to some damage) and those in the Shunbei 1 fault zone were largely the result of the third stage of hydrocarbon charge.Neither fault zones have undergone obvious thermal cracking, except for a slight thermochemical sulfate reduction (TSR) to the crude in the Shungbei 1 fault zone, and BSR to the early charged crude in the Shunbei 5 fault zone.Different charging processes are the main factors leading to different reservoir characteristics of different fault zones in the Shunbei area.

    Characterization of paleo-topography and karst caves in Ordovician Lianglitage Formation, Halahatang oilfield, Tarim Basin
    Chaozhong Ning, Suyun Hu, Wenqing Pan, Zixiu Yao, Yong Li, Wenfang Yuan
    2020, 41(5):  985-995, 1047.  doi:10.11743/ogg20200509
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    The typical eogenetic karsts developed in the Ordovician Lianglitage Formation of the Halahatang area, Tarim Basin, are characterized by the featured paleokarst topography and subsurface paleokarst cave systems.This study initiates from the characterization of the karst terrain on top of the Lianglitage Formation with seismic data and then turns to the analysis of basic features of collapsed karst cave systems by core and thin section observation and log interpretation.In addition, the distribution pattern of the karst cave system is depicted through RMS amplitude and variance attribute fusion; and the factors controlling the development of the karst cave systems are explored against the paleogeological background therein.This study shows that the karst landform on top of the Lianglitage Formation consists of typical elements such as karst highlands, karst ramps, karst troughs and valleys as well as dolines, each with a different distribution pattern.The internal cave systems in the Lianglitage Formation underwent distinctive collapse, filling and compaction, leading to the pathways inside the systems occurring in rectilinear pattern and interweaving into reticular structure.The factors controlling the karst system development include extensive subaerial exposure during the LST period, pre-existing faults and fractures and surficial fluvial systems.

    Discussion on identification, prediction and development pattern of faulted-karst carbonate reservoirs:A case study of TH10421 fracture-cavity unit in block 10 of Tahe oilfield, Tarim Basin
    Hong Cheng, Jie Zhang, Wenbiao Zhang
    2020, 41(5):  996-1003.  doi:10.11743/ogg20200510
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    Faulted-karst carbonate reservoirs have been a focus of study in the Tahe oilfield in recent years.The heterogeneity of the reservoirs is a key issue that restricts their development.The TH10421 unit in the block 10 of the Tahe oilfield is taken as an example to classify the reservoirs based on logging data and high-frequency seismic attribute analysis.There are four types of reservoir as a result, namely the cavity type, dissolved pore or cavity type, fracture-cavity type, and fracture type, among which the first two are the most common reservoir types, and the last two, still at early stages of evolving into large-scale cavities, serve mainly as connection between reservoirs.The results show that the evolution of reservoirs from fractures to pores and then to cavities indicates a gradual increasing dissolution from outside to inside, and that multi-stage fractures caused by strike-slip faults facilitated the dissolution.Each reservoir type in the faulted-karst carbonates corresponds to specific log and seismic responses.Seismic texture attributes can be used to clearly predict the distribution of different types of reservoirs within, which will in turn further confirm the proposed development model of the reservoirs.The study helps to promote the understanding of the forming process of faulted-karst reservoirs and to provide a geological basis for their future development.

    Genetic mechanism and evolution characteristics of overpressure in the lower play at the southern margin of the Junggar Basin, northwestern China
    Fengqi Zhang, Xuesong Lu, Qingong Zhuo, Hongli Zhong, Pei Zhang, Chi Wei, Wei Liu
    2020, 41(5):  1004-1016.  doi:10.11743/ogg20200511
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    Intensive tectonic compression during the late Himalayan resulted in overpressure of complex evolution history in the lower play at the southern margin of the Junggar Basin.Based on an integration of formation pressure with geological data, this study discusses the features of log responses and comprehensive compaction of sandstone and mudstone in the lower play of the study area.The genetic mechanisms of the overpressure in the play are identified in combination with modified overpressure recognition diagrams and paleo-tectonic stress measured by Kaiser effect.The evolution characteristics of these mechanisms and their contribution to the current overpressure are also quantitatively evaluated based on the numerical simulation of both tectonic stress and overburden on compaction.The results show that horizontal tectonic compression is the main cause of the over-pressurized Qigu Formation in the lower play of the study area, followed by vertical disequilibrium compaction and overpressure transmission vertically along the faults and laterally in sandstone.The vertical disequilibrium compaction began to develop in certain parts of the study area since the Paleogene to the deposition of the Taxihe Formation.Its contribution to the presently over-pressurized Qigu Formation in the eastern Sikeshu Sag and the east part of the third row of structural belt in the play are 1.4% and 33.3%, respectively.The continuous tectonic compression in high intensity led to a rapid increase of overpressure in the lower play since the end of the Taxihe depositional period, with contributions of 65.8% and 50.8% respectively to the overpressure in the formation of the two locations.The overpressure transmission mechanism was initiated and accelerated in the deep reservoirs of the play since the end of the Dushanzi depositional period, especially the Quaternary, when anticlines and faults were formed.Its contributions to the overpressure of the formation in the two locations are 32.8% and 15.9%, respectively.

    Structural characteristics of Qiyueshan Fault and shale gas preservation at the southeastern margin of Sichuan Basin
    Xiusong Tuo, Kongquan Chen, Shunshe Luo, Jiguang Tang, Douzhong Zhang, Junjun Shen
    2020, 41(5):  1017-1027.  doi:10.11743/ogg20200512
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    Exploration activities show that the Qiyueshan Fault at the southeast margin of the Sichuan Basin is behind the significant differences in shale gas accumulations on both sides of the basin margin.Based on the latest seismic data and regional geological data, this study applied fault-related fold theories to a systematic discussion on the structural deformation features of the Qiyueshan Fault, particularly the fault's geometry, formation and evolution, and influence on the preservation of shale gas.The results show that the laterally S-shaped Qiyueshan Fault is composed of several discontinuous sub-faults in a right-stepping en echelon arrangement from the left to the north, and a left-stepping en echelon arrangement from the right to the south.The Qiyueshan Fault served to control the formation of two transition zones on the west side (the anticline and slope), and facilitated the development of two structural deformation patterns, namely the "basement thrust→fault-related folds→decollement", and "basement thrust→decollement".In addition, the throw of the Qiyueshan Fault gradually decreases from Jiaoshiba to Gulin.The fault took shape during the transition from trough-like folds to comb folds triggered by the uplift of the main detachment zone in the Late Jurassic.A later transformation by the central Guizhou block in the Late Cretaceous and the differential uplift at the end of Neogene helped the fault to take the present shape.Controlled by the Qiyueshan Fault, the preservation conditions in the severely deformed fold belt on the east side are so poor that only some gentle and broad synclines contain some normal pressure shale gas reservoirs.However, four anticlines, formed by the uplift of layers of interest due to detachment of the basement branch faults on the west side, are potential exploration targets with their moderate burial depths and gradually improving preservation conditions from south to north.

    Difference between eastern and western Paleogene sedimentary systems in deep waters off the northern South China Sea continental margin and its effect on source rock distribution
    Ying Chen, Yinxue Han, Lizeng Bian, Qingbo Zeng, Shuai Guo, Mo Ji, Dongsheng Yang, Longying Wang
    2020, 41(5):  1028-1037.  doi:10.11743/ogg20200513
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    The striking discrepancy of oil-gas exploration results in deep waters of the Pearl River Mouth and Qiongdongnan Basins in northern South China Sea is rarely interpreted in terms of formation mechanism.With a view to objectively assessing the resource potential of the deep waters off the northern South China Sea, the study analyzes the conditions for basin formation and hydrocarbon generation based on the essential geological factors such as the basinal structure, provenance and sedimentation and charging, with the focus on the main sedimentary characteristics of the hydrocarbon source rock development during the Paleogene, and on the distribution patterns of the source rocks.The two basins are significantly different in terms of their Early Oligocene sedimentary systems, which may be traced back to the different basinal structures and provenances at that time.The major pay source rocks of the deep waters off the northern South China Sea were developed during the Early Oligocene, when the deep-water zone of the Pearl River Mouth Basin was filled with rifts and depressions, and the Baiyun and Liwan Sags in it had their respective depocenters and subsidence centers receiving sediments from surrounding uplift zones and the paleo-Pearl River system outside the basin and developing large delta systems of bay facies.Meanwhile, the deep waters of the Qiongdongnan Basin were a faulted depression with multiple rows of separated small sag groups developed on the terrace of both sides and the central lowlands of the basin.These sag groups subsequently formed barrier-coast systems and small-scale deltas in receiving short-range provenances from waters off the southern Hainan Island and Thu Bon river in Vietnam in a closed-semi-closed bay setting.In all, the sedimentary systems control the types and distribution patterns of the source rocks in the basins, so it is of great significance to the discussion of the distribution patterns and favorable zones of source rocks in the deep waters off the two basins from the perspective of the differences in sedimentary system architecture.

    Advances in shale gas resource assessment methods and their future evolvement
    Zhenxiang Song, Xuhui Xu, Baohua Wang, Linjie Zhao, Guoqiao Yang, Qi Qiu
    2020, 41(5):  1038-1047.  doi:10.11743/ogg20200514
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    Shale gas resource assessment has been carried out mostly with the static, dynamic and comprehensive approaches based on the principles it employs and the paths it explores.Of which, the static approach is composed of the genesis, statistics and analogy methods, with each being further divided into different and specific assessment procedures.The bulk procedure under the statistics method and the analogy method are adopted more often by the Chinese assessment teams during their estimation of shale gas resources in place in the country, while the statistics method and the dynamic approach are more frequently used by assessors in other countries during their calculation of recoverable shale gas resources.This paper provides a thorough review of the applicability and the advantages and disadvantages of as well as advances in all these assessment methods.It concludes that with the development of shale gas exploration and development in China, the static and dynamic approaches have been widely used and greatly improved but the comprehensive approach has been relatively overlooked.It also suggests that the grading and spatial distribution prediction of shale gas, establishment of calibration units, utilization of big data as well as set-up of a comprehensive assessment system based on all these methods are the main development directions for shale gas resource assessment, and that the next step for those doing the shale gas assessment work in China is to facilitate the bringing in of a more applicable and completed system for economic and ecological evaluations of shale gas exploration and development.

    Identification and optimization of shale gas "sweet spots" in marine Niutitang Formation, South China
    Shiqing Wu, Jianhua Guo, Zhiyu Li, Mingyang Qin, Yanran Huang, Haonan He
    2020, 41(5):  1048-1059.  doi:10.11743/ogg20200515
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    Low-temperature adsorption/desorption of liquid nitrogen and isothermal adsorption of methane were used to characterize the shale reservoir capacity for adsorbed gas and free gas so as to describe the occurrence of shale gas in the original reservoirs of the Niutitang Formation in southern China.Combined with the gas-bearing properties of typical wells, the occurrence mechanism of the shale gas was studied and the "sweet spots" were identified and optimized in the study area.The results show that 1 to 2 layers of organic-rich shale dominated by black siliceous shale are developed in the Niutitang Formation (TOC>2.0%).Organic-matter pores (cylindrical pores with both ends open), interlayer pores of clay mineral (narrow parallel-plate pores with four sides open) and intergranular and intercrystalline pores (conical parallel-plate pores with four sides open) are developed with the organic-matter pores being the most important.The Niutitang Formation is generally poor in gas-bearing properties, except for one well (Well Ciye 1) measured with a residual gas volume fraction of as high as 69.7%.Both theoretical calculation and field experiments have shown that the occurrence of methane in Niutitang Formation shale reservoirs vary with TOC.Due to the relatively small organic-matter pore size (usually smaller than tens of nanometers), the original reservoirs in the formation store more adsorbed gas than free gas.With the increase of organic matter mass fraction, the elastic modulus of rocks decreases and the Poisson's ratio increases gradually.The "sweet spots" in the Niutitang Formation are characterized by "sweetness" and "brittleness", i.e.they have greater thickness (20-40 m) and high TOC values between 4% and 8%, high quartz mass fraction (>40%) and clay mineral mass fraction (30%-40%), low carbonate rock mass fraction (< 20%), a VBJH of (10-17)×10-3 cm3/g, a VL of 4-6 cm3/g, a free gas volume fraction of more than 40%, an elasticity modulus of 25~35 GPa and a Poisson's ratio of 0.20~0.25.In short, the "sweet spots" in the Niutitang Formation are mainly developed in deep shelf argillaceous facies with high free gas storage capacity.

    Characteristics and controlling factors of organic-matter pores in Longmaxi Formation shale, Middle Yangtze Region: A case study of Well YY3
    Jian Hong, Xuan Tang, Cong Zhang, Huang Huang, Yansheng Shan, Yuyan Zheng, Huangchang Xie
    2020, 41(5):  1060-1072.  doi:10.11743/ogg20200516
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    The exploration and development of shale gas in the Jiaoshiba gas field, a major Longmaxi Formation shale gas field in the Upper Yangtze Region, has made great success.However, the resource potential of the formation is still unclear.To this end, the characteristics and controlling factors of organic-matter pores in shale samples from the Well YY3 in the Yongshun area, Hunan Provinces, are analyzed to provide references for the assessment of shale reservoir properties in the formation.The Longmaxi Formation shale from the Well YY3 contains typical marine organic matter, and is characterized by a total organic matter content (TOC) of 0.65%-3.81% (1.87% on average), high-to-over-mature thermal maturity and low porosity (2.06% on average).The pores in the samples were systematically observed under scanning electron microscopy (SEM) after an Argon-ion-polishing treatment.Moreover, the characteristics of organic-matter pores were analyzed with energy spectrum test and JMicro Vision image processing software; and a new characterization method based on SEM images was proposed to describe the pore connectivity.The results show that the Longmaxi Formation shale contains mostly migrated organic matters with well-developed pore systems and native organic matters with under-developed pores.As a whole, the pore growth in organic matters of the shale in the formation is heterogeneous and mainly controlled by the micro-components of organic matters as well as the content of organic carbon and clay minerals, and at higher thermal evolution stages, organic carbon content plays a critical role in the development of pores in organic matters.

    Geological features and their participation in the formation of silicified clastic reservoirs in the Shahejie Formation of Laizhouwan Sag, Bohai Sea
    Lixin Tian, Qingbin Wang, Xiaojian Liu, Yiwei Hao
    2020, 41(5):  1073-1082.  doi:10.11743/ogg20200517
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    Silicified clastic rocks in the Laizhouwan Sag, Bohai Bay, are characterized by intergranular pores among quartz crystals filled with siliceous materials and by secondary intensive quartz overgrowth.Some areas even exhibit low-level metamorphism of blastopsammitic texture, which is rarely seen in petroliferous basins.The geological features of the siliceous clastic rocks in the sag are revealed by means of seismic and log interpretations, petrological analyses and zircon U-Pb dating.It has been confirmed for the first time that volcanic activities did occur during the deposition of the Shahejie Formation in the sag.Siliceous thermal fluid activities are verified by well-developed siliceous veins of multi-stage filling and charging, intensive overgrowth of the secondary quartz, and the blastopsammitic texture of rocks.Almost all the clay minerals in intergranular pores were thermally altered to biotites and muscovites, and growing "broom-shaped" mica minerals are observed.A large number of pyrite are developed in agglomerates or random clusters.Pyrite with different occurrence is derived from multi-phase hydrothermal solution.The hydrothermal mineral assemblage of pyrite-barite-monazite-galena-rutile-anhydrite is identified under the field-emission scanning electron microscope.With siliceous hot fluids from deep entering reservoirs, the overgrown clastic quartz and siliceous precipitates worked together to fully stuff the intergranular pores, causing deterioration in physical properties of the reservoirs.However, the silicification saved the situation by greatly enhancing the reservoir brittleness, which generated numerous fracture and micro-fracture networks during later tectonic movements.In addition, the hydrothermal fluids dissolved the feldspar minerals in the reservoirs, resulting in a large amount of dissolution pores and moldic holes in feldspar grains.Thus high-quality reservoirs of pore-fissure type are formed with well-connected fracture networks.

    Relationship between excess pressure gradient and hydrocarbon distribution in the 3rd member of Shahejie Formation in Bonan Sag, Bohai Bay Basin
    Hua Liu, Jun Li, Yuelin Feng, Xuefeng Hao, Hongmei Lin, Feifei Yuan
    2020, 41(5):  1083-1091.  doi:10.11743/ogg20200518
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    In order to quantify and characterize the relationship of overpressure with hydrocarbon migration, accumulation and distribution, we took the 3rd member of the Shahejie Formation in the Bonan Sag of the Bohai Bay Basin as an example to study the excess pressure gradient and its variation patterns as well as its influence on hydrocarbon distribution based on fluid pressure prediction and through analyses of logging, geophysical and testing data.The results show that the hydrocarbon-bearing third member is generally over pressurized with the deep sag zone having greater excess pressure and the highest gradient, the steep slope and step-fault zones having moderate excess pressure and gradient, and the gentle slope zone having smaller excess pressure and the lowest gradient.The hydrocarbon migration dynamics and reservoiring capacity of a location in the member are determined by its distance to the overpressure center.For locations right in the overpressure center, the hydrocarbon migration is under strong driving forces, high excess pressure gradients are mainly distributed near faults, and oil and gas mainly accumulate near the Boshen 4 fault; for locations adjacent to the overpressure center where high excess pressure gradient mainly appears in highly heterogeneous formations, oil and gas migrate to areas with low excess pressure gradient through sandbodies with various lateral transport capacities; and for locations far away from the overpressure center, the excess pressure is relatively low and buoyancy stands out as the main driving force for oil and gas migration, and the relationship between the excess pressure gradient and the oil and gas distribution is no longer obvious.

    Deformation characteristics and formation mechanisms of salt structures in the Lower Congo Basin
    Shuaiyu Shi, Yixin Yu, Jinyin Yin, Changwu Wu, Jingjing Liu, Yanli Liu, Bo Wang
    2020, 41(5):  1092-1099.  doi:10.11743/ogg20200519
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    The salt structures of various types formed in the massive Aptian saline rocks of the Lower Congo Basin against a passive continental margin setting are among one of the main factors that affect the accumulation of oil and gas in the basin.Based on seismic section interpretations of the Lower Congo Basin, this study analyzes the deformation characteristics and evolution processes of the typical salt structures, and discusses the factors affecting their development through cross-section balancing and restoration and physical modeling.The results show that the Lower Congo Basin is characterized by zonation under obvious structural deformation, with salt rollers, salt rafts, listric normal faults, and shovel-shaped faults developed in the back extensional zone, different forms of salt diapirs in the central transition zone, and salt canopies, thrust faults and thick-bedded salt rocks in the front compression zone of the basin.The salt structures have undergone three evolutionary stages, namely the initial active stage during the Albian-Late Cretaceous, the strong active stage during the Late Oligocene-Late Pliocene, and the weak active stage during the Late Pleistocene to the present.Gravity sliding and differential loading of overlying strata were the main controlling factors that led to plastic flow of the salt structures.The basement tilting was also involved in the deformation of the salt structures.

    Methods and Technologies
    Hybrid thermal chemical recovery of thin extra-heavy oil reservoirs
    Huanquan Sun
    2020, 41(5):  1100-1106.  doi:10.11743/ogg20200520
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    China has approximately 700 million tons of extra-heavy crude with a viscosity higher than 50 000 mPa·s in reservoirs thinner than 6 meters.Though low-grade, the reserves are of strategic significance.The extra-heavy crude reservoirs respond badly to conventional steam injection thermal recovery methods due to fast heat dissipation and low heat utilization efficiency.More suitable recovery technologies are badly needed to deal with the problem.After years of research and practice, hybrid thermal chemical recovery technologies were developed together with viscosity reducers tailor-made for super heavy oil.Recovery mechanisms of "viscocity reduction by steam and chemicals, formation energy enhancement and insulation by nitrogen, and swept efficiency improvement by chemicals" during the recovery processes were explored and expounded.Other achievements include the independently-developed thermal chemical numerical simulation software, optimization chart for injection and production parameters, open hole completion technologies and sand prevention tools with screen pipes for horizontal wells, integrated processes of injection and production with horizontal pump during thermal recovery, residual heat gradient utilization and of produced water recycling.The Chunfeng extra-heavy oilfield established in the Junggar Basin of Xinjiang now has an annual productivity of more than one million tons of crude and has annually produced more than 100×104 tons for five years in a row.The newly developed technologies for extra-heavy oil extraction can be applied to enhance oil utilization and recovery of brown oilfields, thus of great significance to ensuring a stable or even high domestic oil production.

    Summary of sedimentological issues and fundamental approaches in terms of ancient "Source-to-Sink" systems
    Mingxuan Tan, Xiaomin Zhu, Zili Zhang, Wei Liu, Hongchao Zhao, Bin Su
    2020, 41(5):  1107-1118.  doi:10.11743/ogg20200521
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    Basin-mountain dynamics, earth surface process and sediment budget are always the frontier areas of geoscientific research.The "Source-to-Sink" system integrates the three issues into one complete denudation-deposition system based on the sediment routing system.With the recent development of methods and theories, the quantitative study on the "Source-to-Sink" system has extended from modern or the Quaternary to earlier stages.As the ancient "Source-to-Sink" systems were usually subject to modification of different degrees, the geological details have not been well preserved.The quantitative reconstruction and detailed characterization of palaeo-geomorphology, palaeo-drainages, palaeo-environment of source and sink areas have been the prerequisite of the study on the ancient "Source-to-Sink" systems based on the systematic summary of several critical sedimentological issues for inside elements.The quantitative tracing of detrital minerals, geomorphological scaling relationship and mass balance studies are the predominant approaches for deciphering the characteristic and process codes of ancient "Source-to-Sink" systems, thus playing a crucial role in the establishment of new models and the further understanding of geomorphic evolution, depositional history and prediction of favorable reservoirs.