Table of Content

28 December 2019, Volume 40 Issue 6

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Petroleum Geology

Exploration prospect of normal-pressure shale gas in Middle and Upper Yangtze regions: A case study of the Lower Cambrian shale in Xiangzhong Depression

Zheng Herong, Peng Yongmin, Tang Jianxin, Long Shengxiang, Liu Guangxiang, Gao Bo, He Xipeng, Wang Yunhai, Gu Zhixiang

2019, 40(6):  1155-1167.  doi:10.11743/ogg20190601

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The domain of normal pressure shale gas in the Middle and Upper Yangtze region is a new focus of attention,with a typical case of the Lower Cambrian shale gas in the Xiangzhong Depression.Based on two measured outcrop sections,eight observation outcrop sections,one shallow-drilling and seismic data,we studied the geological characteristics of the Lower Cambrian shale gas in the Xiangzhong Depression.The study area is favorable for the generation of shale gas.The Lower Cambrian black-carbonaceous and siliceous shales were deposited under deep-water environments for favorable slope and basinal facies,with a continuous thicknesses of more than 150 m and a high-quality shale thickness of 50-90 m.The TOC of the black shales ranges between 1.12% and 22.07%,averaging at 4.64%;and the reflectance of vitrinite (R_o) averages 2.78%.The shale reservoir space consists of organic-matter nanopores,dissolved pores,intergranular pores of pyrites and clay minerals,high-angle fractures,bedding-parallel fractures,and so on,but the organic-matter nanopores are dominant.The organic-matter nanopores occur in strips or irregular polygons due to pressure relief and exposure to the surface,with aperture size ranging from 21.8 nm to 328.4 nm.Samples from the surface are observed to be filled with many secondary dissolved pores of meteoric water origin,and cracks due to tectonic stress.The porosity ranges between 2.0% and 8.7%,averaging at 6.05%.Quartz predominates the mineral composition of shales,averaging at 61.2%.Clay minerals rank second,averaging at 23.5%.Brittle mineral content averages 73.38%.Large number of isothermal adsorption experiments have indicated that its average adsorption capacity is 5.95 m³/t.Favorable zones of Type I shale gas in the new interval of Lower Cambrian were predicted to distribute in an area of 8 766.1 km²,by comprehensive geological methods.It is proven that the exploration potential of shale gas is significant in the both sides of the Longshan uplift,where the burial depth of the Lower Cambrian is mostly between 3 000 m and 4 000 m,a favorable condition for preservation.

Mechanism for generation and accumulation of continental tight oil in China

Zhu Rukai, Zou Caineng, Wu Songtao, Yang Zhi, Mao Zhiguo, Yang Haibo, Fan Chunyi, Hui Xiao, Cui Jingwei, Su Ling, Wang Huandi

2019, 40(6):  1168-1184.  doi:10.11743/ogg20190602

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Chinese tight oil is mainly distributed in continental petroliferous basins of the Mesozoic to Cenozoic,where tight sandstone oil or tight carbonate oil reservoirs are distributed in large areas and are interlayered with or in contact with lacustrine petroleum source rocks.Recently,great progress has been made in continental tight oil exploration and development.By the end of 2018,an annual production capacity of 3.155 million tons was built for Chinese continental tight oil,and its production rate reached 1.05 million tons in 2018.Lacustrine organic-rich shale in China serves as the main hydrocarbon source rocks of the Chinese continental tight oil.Most of the shale was deposited in fresh,brackish-to-saline water environments with a thickness of tens of to several hundred meters,having a total organic carbon (TOC) content of 0.4% to 16% and a vitrinite reflectance (R_o) of 0.5% to 1.3%. Appropriate volcanism,low sedimentation rate,anoxic and reducing environment,transgression,and stratification of water body are dominant factors controlling the quality of organic-rich shales.Chinese continental tight oil reservoirs include tight sandstone,tight carbonate rock,tight peperite,and tight tuffite,featuring strong heterogeneity and poor physical properties.Their overlying matrix permeability tends to be less than or equal to 0.1×10^-3 μm².Nano-scale pore thoats,complex in structure and with a diameter ranging between 40 nm and 900 nm,are dominant in the reservoir space.Their pressure coefficient varies from 0.7 to 1.8,indicating the coexistence of overpressure and pressure deficiency.Their acquifer energy and oil property vary greatly,with an oil density of 0.75 g/cm³ to 0.92 g/cm³.The continental tight oil in place and technically recoverable resources in China are 178.20×10⁸ t and 17.65×10⁸ t respectively,mainly distributed in the Ordos Basin,Bohai Bay Basin,Songliao Basin,Junggar Basin and Qaidam Basin.In conclusion,we put forward the concept of "sweet spot zone (section)",which tends to develop in local,low amplitude structures in a wide,gentle structure setting.A sweet spot zone refers to a tight oil-rich area with commercial productivity within the distribution area of mature high-quality source rocks; while a sweet spot section refers to a high productivity interval of tight oil with commercial value through artificial stimulation,located in the black shale section intercalated by tight reservoir layers.The source rock quality and the type of source-reservoir configuration serve to control the lateral distribution of the sweet spot zones.Sweet spot zone (section) evaluation methods,including resource assessment technique,logging identification of the "six properties",high-resolution 3D seismic imaging,horizontal well production from well pads,and artificial reservoir alternation,may facilitate the efficient development of tight oil.

Origin of nitrogen in marine shale gas in Southern China and its significance as an indicator

Su Yue, Wang Weiming, Li Jijun, Gong Dajian, Shu Fang

2019, 40(6):  1185-1196.  doi:10.11743/ogg20190603

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Marine shale gas resources are abundant in Southern China,and nitrogen (N₂) content accounts for a larger proportion in the composition of some shale gas.Analytical data of the geological and geochemical characteristics of shale gas in southeastern Sichuan,Three Gorges Region of Yangtze River,and Cengong in Guizhou Province,and the thermal simulation experiment of gold tube,are integrated in the study of the origin of nitrogen in shale gas and its indicative significance.The results show that N₂ in shale gas is typically of organic crustal origin,shale gas with higher N₂ content is mainly derived from the late pyrolysis of kerogen,and the higher content of N₂ is just an embodiment of the early gene-ration of crude oil cracking gas under no migration and accumulation or under destruction after accumulation.Therefore,the fact that shale gas resources are limited may be verified by the following three aspects.First of all,the shale kerogen is typically of saprolite.Under good preservation conditions,the shale gas is supposed to be dominated by crude oil cracking gas.However,the identification of shale gas types indicates that the shale gas with higher N₂ content belongs to the kerogen pyrolysis gas or a mixture of crude oil cracking gas and kerogen pyrolysis gas.Secondly,the carbon isotope value of shale gas with higher N₂ content is significantly heavier than that of the secondary cracking gas of crude oil obtained by thermal simulation experiment,through the gold tube thermal simulation experiment of the crude oil samples taken from the Cambrian.Finally,with the growth of organic matter evolution,the N₂ content keeps increasing,and the shale gas wells with better preservation conditions are usually lower in N₂ content but better in gas-bearing properties.Therefore,the N₂ content is of indicative significance to the preservation conditions.

Microscope dynamic process and controlling factors of oil charging in tight reservoir

Huang Wenbiao, Zhan Zhuochen, Lu Ruijing, Gao Yang, Lu Shuangfang, Bai Zhenhua, Yang Liang

2019, 40(6):  1197-1204,1214.  doi:10.11743/ogg20190604

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The microstructure of tight reservoir affects the charging efficiency of crude oil,and restricts the abundance and distribution of tight oil.Based on experiments including the physical simulation of tight oil charging,stable rate mercury injection,Scanning Electron Microscopy (SEM) and nuclear magnetic resonance (NMR),the charging process of crude oil and structural characteristics of pore throats of the tight reservoir were quantitatively characterized,and the effects of diagenesis,authigenic mineral growth patterns and pore throat structural features on oil charging in tight reservoirs were discussed.The results show that the oil charging process can be divided into three stages:initial stage,rapid-increase stage and slow-increase stage.This is a result of the dynamic balance between displacement pressure and capillary pressure during the charging process and the distribution of main reservoir space.In detail,there are two increasing modes in the rapid-increase stage,namely,the sustained rapid-increase and rapid-increase by pulses.The two modes reveal the differences in the distribution characteristics of mainstream throat radii in these samples.It is found that diagenesis,including compaction,cementation,dissolution,and authigenic mineral growth,has greatly affected the size and distribution of reservoir space and throat radius,and determined the quality of tight reservoir.Therefore,under the condition of abundant oil source,the key to tight oil enrichment lies in the sufficient driving force and high-quality reservoir,and thus the sand bodies near the open faults/micro-fractures are concluded to be the favorable zones for hydrocarbon exploration.

Quantitative classification of high-frequency sequences in fine-grained lacustrine sedimentary rocks based on Milankovitch theory

Shi Juye, Jin Zhijun, Liu Quanyou, Huang Zhenkai, Zhang Rui

2019, 40(6):  1205-1214.  doi:10.11743/ogg20190605

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Fine-grained lacustrine sedimentary rocks are characterized by high continuity and resolution,and can faithfully record the changes in climate and environment of lacustrine basins.Considering the high stability during deposition,these sedimentary rocks have been regarded as good information carriers to identify Milankovitch cycles;while in return,the recognition of time connotation of the Milankovitch theory is an effective way to perform classification and correlation of high-frequency cycles,and to improve the temporal resolution of stratigraphic classification,thus being a powerful complement to the conventional sequence stratigraphy.The accurate identification of Milankovitch Cycles is the basis for the classification of high-frequency sequences in the fine-grained lacustrine sedimentary rocks,and constraining the variation of sedimentary rate is the key to the recognition of Milankovitch Cycles.In view of the fast transformation of sedimentary facies and strong heterogeneity in continental sedimentary sequences,we used the magnetic susceptibility as a proxy.In addition,the evolutive harmonic analysis (EHA) and average spectral misfit (ASM) techniques were introduced to constrain the vertical variation of sedimentary rate,so as to more accurately recognize signals of Milankovitch Cycles.Combined with the base level cycle theory in high-resolution sequence stratigraphy,we found that the fourth-order sequence corresponds to the medium-term base level cycle and the time is quantified as 405 ka;the fifth-order sequence corres-ponds to the short-term base level cycle and the time is quantified as 100 ka;and the sixth-order sequence corresponds to the super-short-term base level cycle ant the time is quantified as 40 ka.Finally,the periodic curves of long-eccentricity,short-eccentricity and tilt are taken as referential curves for classification of the fourth-,fifth-and sixth-order sequence,and thus the quantitative classification of high-frequency sequences of fine-grained lacustrine sedimentary rocks can be achieved.

Characterization,classification and contribution of marine shale gas reservoirs

Xiao Dianshi, Zhao Renwen, Yang Xiao, Fang Dazhi, Li Bo, Kong Xingxing

2019, 40(6):  1215-1225.  doi:10.11743/ogg20190606

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The Wufeng-Longmaxi Formations shale gas in Pengshui area,southeastern Chongqing,was studied through several pore characterization experiments including low-temperature carbon adsorption (LTCA),low-temperature nitrogen adsorption (LTNA),nuclear magnetic resonance (NMR),high pressure mercury intrusion porosimetry (MIP),scanning electron microscopy (SEM),and Helium porosity measurement.The shale pore structure was comprehensively described,and the characterization and classification methods of full range of pore size were established to study their individual contributions to shale gas occurrence and migration.The results show that the pore volume by Helium porosity measurement is the largest,followed by LTNA and NMR.The latter two have obvious advantages in characterizing smaller (<10 nm) and larger pores,and thus the combination of LTNA and NMR can be applied to the characterization of full range pore size distribution of shale.The distribution reveals a wide range of shale gas pore distribution,but 70% of the pore volume is concentrated in pores less than 25 nm in diameter.Combined with fractal features,the pores can be divided into micropores,small pores,mesopores and large pores in diameter with a lower boundary of 5 nm,25 nm and 100 nm.The pore throat size is mainly a result of organic matter and clay contents.The larger pores are composed of intergranular pores and inter-clay-layer fractures.The mesopores are also affected by intragranular dissolved pores.The micropores and small pores are the main sites where the shale adsorbed gas and free gas occur.The small pores and mesopores are inter-connected,providing channels for the shale gas to migrate in the matrix.The research results are significant as it may guide the classification of shale gas reservoirs and the understanding of infiltration mechanism.

Sedimentary setting of thick sandstone in the 3rd member of the Oligocene Huagang Formation in A gas field in the Xihu Sag,East China Sea Basin

Zhu Yixiu, Huang Daowu, Wang Huan, He Xianke, Shi Yuan, She Yaming

2019, 40(6):  1226-1235.  doi:10.11743/ogg20190607

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The thick clastic reservoir in the 3rd member of the Huagang Formation is a major gas pay zone and high-qua-lity reservoir in A gas field in the Xihu Sag,East China Sea Basin,but there still exists great dispute over its sedimentary microfacies.We studied the facies markers,microfacies types,sedimentary setting,and facies distribution of the target interval through integration of core,logging,seismic and laboratory data.The results show that the study area mainly deve-lops the braided river delta-front subfacies,which mainly consists of underwater distributary channels and interdistributary microfacies without sediments and facies markers indicating marine facies and transgression.Vertically,multi-stage underwater distributary channel sand bodies superimpose,featuring large thickness and great horizontal extension.Laterally,the underwater distributary channels are characterized by tree-like bifurcation and continuous distribution from northeast to southwest,with its provenance in the northeast.It is believed that a lacustrine-delta sedimentary system of continental setting exists in the study area and is typical traction current deposits without any transgression sequence.The underwater distributary channels microfacies of high-energy traction currents is advantageous for the development of prolific gas reservoirs in the study area.

Discussion on the enrichment and mobility of continental shale oil in Biyang Depression

Feng Guoqi, Li Jijun, Liu Jiewen, Zhang Xinwen, Yu Zhiyuan, Tan Jingjuan

2019, 40(6):  1236-1246.  doi:10.11743/ogg20190608

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China is rich in continental shale oil resources,but no substantial breakthrough has been made in their deve-lopment over recent years.In view of the issue,various data including thin section observation,rock pyrolysis,low-temperature nitrogen adsorption (LTNA),shale oil adsorption experiment,high pressure mercury injection (HPMI) experiment,and nuclear magnetic resonance (NMR) are integrated to investigate the major factors controlling shale oil accumulation and mobility in Biyang Depression.The results show that the TOC of shale interval enriched with oil is relatively higher,and its inorganic macropores are well developed.The shale reservoir enriched with oil is usually characterized by higher content of saturated hydrocarbon and lower content of asphaltene,so the shale oil has higher mobility.Clay minerals are the main contributor to the specific surface area of shale and the main carrier for shale oil adsorption.Thus,the lower the clay mineral content,the better the mobility of shale oil.The optimal depth for shale oil enrichment is 2 800 m in Biyang Depression.When the burial depth exceeds 3 000 m,the shale oil has a higher API degree and lower viscosity,thus fair mobility.The depth of Wells HF1 and Anshen1 is in the range from 2 400 m to 2 500 m,being shallower compared with the optimal depth for shale oil production.In addition,the adsorption capacity of small molecular hydrocarbons is relatively weaker under high temperature,so the deep intervals (over 3 000 m in depth) are the play fairway for petroleum exploration in the area.The pressure coefficient of Biyang formations is relatively small,and the higher interval transit time mainly indicates higher TOC.

Quantitative evaluation of adsorbed and free gas and their mutual conversion in Wufeng-Longmaxi shale,Fuling area

Pang Xiaoting, Chen Guohui, Xu Chenxi, Tong Maosheng, Ni Binwu, Bao Hanyong

2019, 40(6):  1247-1258.  doi:10.11743/ogg20190609

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Shale gas tends to exist in the forms of adsorbed and free gas in reservoirs.Accurate determination of the ratio of adsorbed-free gas is of great significance to evaluating shale gas content and making reasonable plan for shale gas exploitation.At present,there are hardly any fine evaluation of the adsorbed-free gas content,and the influential factors and mutual conversion pattern of adsorbed-free shale gas are rarely known in the Wufeng-Longmaxi Formations,Fuling area.Hence,based on the analyses of influential factors on adsorbed-free gas,we built a model to quantitatively calculate the maximum adsorption capacity according to the mass of shale,and chose a preferred micropore filling model to characterize the absolute adsorption capacity of shale,in an effort to measure the real adsorbed and free gas contents of shale and figure out the ratio of adsorbed-free gas.In addition,the effect of factors including temperature,TOC,water saturation and porosity,on the mutual conversion of adsorbed-free gas,is also under discussion.The results show that,the adsorbed gas content tends to increase from shallower to deeper layers of the Wufeng-Longmaxi Formations,but the absolute adsorbed gas content of the shale stays steady as the depth further increasing.The average ratio of the adsorbed-free gas is about 34% in the shale studied.In comparing the effects of individual factors on the mutual conversion at a depth of 2 000 m to 3 500 m,we found that the effect of porosity and TOC is the most significant,followed by the water saturation,and that of pressure coefficient variation is the least.

Mechanism of shale oil accumulation in the Hetaoyuan Formation from the Biyang Depression,Nanxiang Basin

He Taohua, Li Wenhao, Tan Zhaozhao, Wang Ya, Zhang Wenbo, Zhang Xinwen

2019, 40(6):  1259-1269.  doi:10.11743/ogg20190610

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The continental shale oil potential is remarkably huge in China,but the current production of shale oil is much less than expected.Therefore,in order to reveal the geochemical characteristics and shale oil accumulation mechanism of organic-rich shales,a multiple geochemical techniques,mainly including total organic carbon (TOC),Rock-Eval,organic maceral and gas chromatography mass spectrometry (GC-MS),were systematically performed on a total of 50 shale samples from shale oil field in the Biyang Depression,Nanxiang Basin,in this study.On the basis of the diversities in the color,structure and microscopic characteristics,two types of shales have been identified,which are black laminated shale (type A) and gray shale (type B,including gray shale,dark mudstone and few silty mudstones),respectively.The testing results show that (1) type A,mainly formed in high salinity and strong reducing environment,is rich in TOC (up to 8.59%) and algea organic matter (AOM) with kerogen of type Ⅰ,and contains plenty of the horizontal cracks favorable for shale oil storage which have enhanced the abundant oil content (high free hydrocarbon S₁ and chloroform bitumen "A" concentrations) at present,resulting that the enriched shale oil resources occurred in this type of shales;(2) type B,mainly developed in weak reduction environment with low salinity,has less TOC abundance (low to 1.09%) with kerogen of type Ⅱ and poor AOM contribution,and vertical cracks within shales have accelerated the hydrocarbon expulsion,which has led to today's poor oil content and resulted that this type of shales only contains potential and ineffective shale oil resources.Thus,the type A of shales can effectively generate and store abundant shale oil,which is of great reference value for further exploration and development of shale oil in the future.

Genetic mechanism of carbonate cements and its impact on the Mesozoic clastic reservoir quality of the C12 and Q17 structures,Bohai Sea Area

Lu Huan, Xu Changgui, Wang Qingbin, Du Xiaofeng, Liu Xiaojian

2019, 40(6):  1270-1280.  doi:10.11743/ogg20190611

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Carbonate cements were pervasively developed in deep clastic strata of the Mesozoic formations in the Bohai Bay Basin.Based on results through thin section identification,X-ray diffraction,Scanning Electron Microscopy (SEM),elements analysis,and numerical basin modeling and laser micro-sampling analysis for carbon and oxygen isotopes,we made a comparative study on the types,occurrences,and genetic mechanisms of carbonate cements of various periods,and their impacts on reservoir physical properties in the C12 and Q17 structures.The results show that the differences of carbonate cements of the two structures have led to different reservoir physical properties,and the generation and distribution of carbonate cements were mostly under the control of burial period,leaching,tectonic conditions,and diagenetic settings.The C12 structure features high content of carbonate cements,and its reservoir pores are filled with both early and later generated carbonate cements.Furthermore,the cements of early generation experienced no dissolution at later stages,while secondary pores developed only near the top Mesozoic unconformity.The reason lies in the impact of repeated deep burial processes,sealing diagenetic conditions,and intensive evaporation of the braided rivers,as well as the early faulting,which resulted in the intense carbonate cementation and then the initiation of reservoir tightening in the C12 structure.In comparison,the Q17 structure is relatively good in reservoir physical properties.Although the carbonate cementation is also intensive in the structure,characterized by early-stage carbonate cement concentration in local intervals of fine-grained sandstones,the thick-bedded coarse-grained sandstone intervals of better original sediment facies have usually low carbonate content or experienced carbonate dissolution at early stages,resulting in sporadic cements of ferron dolomite.This is due to its shallow burial history,open diagenetic settings,continuous fault activities,and wide-spread leaching.The occurrence of ferron dolomite was associated with formation water flows and hydrocarbon charging on the sandstones.Based on these observations,we proposed a concept of differential diagenesis,and discussed its mechanism from both the macro-structure and micro-diagenesis perspectives.

Evolution mechanism of micro/nano-scale pores in volcanic weathering crust reservoir in the Kalagang Formation in Santanghu Basin and their relationship with oil-bearing property

Tian Weichao, Lu Shuangfang, Wang Weiming, Li Jinbu, Li Zhuang, Li Jie

2019, 40(6):  1281-1294,1307.  doi:10.11743/ogg20190612

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Various data including casting thin section,scanning electron microscopy (SEM),XRD whole-rock mineral analysis,low-temperature nitrogen adsorption (LTNA) and high pressure mercury injection (HPMI) experiments are integrated to characterize the micro/nano-scale pore structure of the volcanic weathering crust reservoir in the Kalagang Formation (C₂k),Santanghu Basin,study in-depth the evolution mechanism of micro/nano-scale pores,and reveal the effect of pore throat structure on the oil-bearing property of reservoir in combination with oil/gas shows and formation testing data.The results show as follows.Four types of reservoir space,namely dissolution pores,residual pores,intercrystalline pores and fractures,are recognized in the volcanic weathering crust reservoir.The adsorption-desorption isotherm curves are dominated by hysteresis loops of Type H2 or near Type H2,and the efficiency of mercury ejection is quite low,varying from 24.26% to 44.91%,in samples as a whole,suggesting that the pores are mainly ink-bottle shaped.The reservoir is dominated by a pore size of below 1 μm,with micro-scale residual pores and dissolved pores developed locally.The lower content of pyroxene and the higher content of plagioclase in the original mineral composition of the volcanic rocks,will result in the development of low-content chlorite and high-content zeolite in the post-magmatic hydrothermal stage.Thereafter the volcanic reservoir can be effectively modified and get better in quality.The Swanson parameter and r_apex can well demonstrate its matrix permeability.However,the Swanson parameter is closely related with the oil-bearing property of volcanic weathering crust reservoirs.When the Swanson parameter is greater than 2,the reservoirs are the oil layers; when it varies between 0.86 and 2,the reservoirs are poor pay zones; while when it is less than 0.86,the reservoirs are mostly dry layers.In conclusion,the Swanson parameter can be used as a key parameter to indicate the oil-bearing property of reservoir,and provide a basis for play fairway selection.

Distribution pattern of paleo and present BSRs in the toe-thrust belt of Niger Delta front

Yang Jinxiu, Song Penglin, He Weiwei, Wang Hongliang, Wang Min, Xiao Dianshi

2019, 40(6):  1295-1307.  doi:10.11743/ogg20190613

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Interpretation of 3D seismic data from the compression domain of Niger Delta,related seismic attribute extraction and BSR numerical modelling are carried out in this paper to study the seismic characteristics of the present and paleo-bottom simulating reflections (BSRs),and the controlling factors of BSR vertical migration.In the study area,the present and paleo-BSRs,representing present previous and locations of the base of gas hydrate stability zones (GHSZ),are scattered and mainly located in areas with well-developed fluid pathways including folding faults,gas chimneys,and diapire structures.This indicates that fluid migration conditions control the occurrence of BSR.Compared with the present BSR,the paleo-BSRs are of weaker amplitude,and distributed in much more limited areas.The amplitude of the paleo-BSRs is interpreted to represent petrophysical interfaces caused by diagenesis driven by previous gas hydrate.The depth of the present BSR deepens as the seabed water depth increases,but the thickness of GHSZ is relatively stable,about 425 m.The upward resetting of the BSR is a result jointly contributed by various factors in the geological history.The toe-thrust belt of the Niger delta is characterized by intense tectonic activities,high sedimentary rate,and well developed fluid migration pathways,including fault and diapire,for heat flows from deep to shallow.Besides,the underlying oceanic and transitional crusts allow higher heat flows,and marine mudstones have higher heat sealing capacity.All these are driving the upward resetting of the BSR.In addition,higher gas hydrate saturation formations in the study area feature higher amplitude anomalies on the present,upper BSR with positive polarity,mainly on top of anticlines and gas chimneys,indicating the effective control of fluid migration pathways on gas hydrate accumulation.The occurrence of free gas zones (FGZs) underlying the present BSR is limited,and only thin FGZs occurred in fold belts with well-developed fluid migration pathways.

Methods and Technologies

Classification assessment of tight sandstone reservoir based on calculation of lower and upper limits of physical properties-A case study of the tight sandstone reservoir in the 1st member of Funing Formation in Gaoyou Sag,North Jiangsu Basin

Zhou Lei, Wang Yongshi, Yu Wenquan, Lu Shuangfang

2019, 40(6):  1308-1316,1323.  doi:10.11743/ogg20190614

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The classification assessment of tight sandstone reservoirs is one of the most important research focus of tight oil resource evaluation.Criteria of classification assessment for tight reservoirs can be effectively and accurately established by calculating the limits of various physical properties of tight oil reservoir,providing a theoretical basis for the classification of tight reservoirs.The tight sandstone reservoir in the 1st member of Funing Formation in the Gaoyou Sag,is taken as an example in the study.Its lower limit of oil-bearing property is calculated by methods of oil-bearing occurrence and nuclear magnetic resonance (NMR);its lower limits of physical properties for oil flowing are worked out by methods of NMR,minimum flowing pore throat radius and formation testing;and its upper limits of physical properties are figured out by balancing the buoyance and capillary resistance of oil in pores.Then following the characterization of tight reservoir permeability and verification of pore structure classification,we established the criteria for classification assessment of tight sandstone reservoirs.The tight reservoirs in the 1st member of Funing Formation,Gaoyou Sag,were accordingly classified into four classes,namely ineffective tight reservoir,oil-bearing tight reservoir,oil-movable tight reservoir and highly oil-movable tight reservoir,with the permeability boundaries of 0.07×10^-3 μm²,0.12×10^-3 μm²,0.50×10^-3 μm²,1.13×10^-3 μm² respectively.The consistency of the classification results and production tests serves to prove the accuracy and applicability of the method proposed in the study.

Quantitative characterization of fault lateral sealing capacity based on 3-D SGR model-A case from M field,Niger

Lei Cheng, Yuan Xintao, Yang Xuanyu, Xu Qingyan, Wang Min, She Jiaofeng

2019, 40(6):  1317-1323.  doi:10.11743/ogg20190615

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Many studies have been performed on sealing capacity of faults.However,most of the previous studies characterize sealing capacity based on the normal stress on faults,without considering the timing of compaction and diagenesis of fault.In the study,rock compaction strength is defined and used,in combination with Shale Gouge Ratio (SGR),to calculate the displacement pressure of faults.Then,the lateral sealing capacity of fault is quantitatively evaluated according to the differential replacement pressure between fault rock and reservoir.Finally,the method is applied to the M oilfield.The results show that when SGR is less than 11,the fault rock has no sealing capacity; when it is over 40,the fault rock is strong in sealing capacity; while when it ranges between 11 and 40,the relationship between SGR and maximum oil column height that the fault rock could support can be characterized by a linear equation.

A new method to calculate shale gas content based on gas reservoir characterization-A case study of Wells JY 1 and PY 1 in Sichuan Basin and its surrounding areas

Li Donghui, Nie Haikuan

2019, 40(6):  1324-1332.  doi:10.11743/ogg20190616

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Lost gas content is an integral part of the total shale gas content,and also a significant parameter for determination of total shale gas volume and evaluation of shale gas in place and reserves.However,the USBM method,the existing calculation method of lost gas content based on core desorption test of coal-bed methane,along with its modified methods,cannot truly reflect the loss of gas content in shale gas reservoirs.Focusing on the instantaneous lost gas content and desorption rate during the core-drilling,we proposed a new method to calculate the lost gas content and the total shale gas content after performing a series of analyses,including characteristics of shale gas reservoirs,reservoir types,pore structure,pore throat size,gas reservoir pressure,coring time,desorbed gas content,and desorption time.The Well JY1 in the shale gas reservoir of overpressure and Well PY1 in the gas reservoir of normal pressure were taken as examples in the study.In applying the new method to Well JY1,we figured out the total gas content of the high-quality lower shale interval,varying from 6.87 m³/t to 9.02 m³/t with an average of 7.47 m³/t,and the total gas content of the upper shale interval,varying from 3.25 m³/t to 3.82 m³/t with an ave-rage of 3.64 m³/t; while in the Well PY1,the total gas content of the high-quality shale intervals ranges from 3.18 m³/t to 4.29 m³/t with an average of 3.83 m³/t,and the total gas content of the upper shale layers ranges from 1.67 m³/t to 2.28 m³/t with an average of 1.94 m³/t.Obviously,these values above are significantly higher than those calculated by using conventional methods.The new method proposed above has been verified by both the theoretical calculation method and performance-based calculation method with the shale gas production wells in Jiaoshiba area as examples.For shale gas reservoirs,especially the overpressured shale gas reservoirs,the new method highlighted in the study serves to provide not only a great theoretical support but also a practical way to calculate shale gas content and reserves,so as to evaluate the reservoir productivity.

Mechanism of shale oil mobilization under CO₂ injection

Zhao Qingmin, Lun Zengmin, Zhang Xiaoqing, Lang Dongjiang, Wang Haitao

2019, 40(6):  1333-1338.  doi:10.11743/ogg20190617

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CO₂ injection may be the most effective method to enhance shale oil recovery due to its good injectivity and miscibility with crude oil.However,unlike conventional reservoirs,shale reservoirs usually feature fractures and micro/nano-scale pores,and thus whether CO₂ can enter micro/nano-scale pores to mobilize oil inside is the key to a successful CO₂-EOR in shale reservoirs.Therefore,a CO₂-EOR experiment was carried out to find out the features and mechanism of oil mobilization in the micro/nano-scale pores of shales by means of nuclear magnetic resonance (NMR).In addition,effects of total exposure time and times of exposure on recovery performance were also investigated.Both NMR T₂ spectrum and images indicate that oil in all shale pores can be effectively mobilized by CO₂ injection.The recovery factor is 32.63% for the first shale oil -CO₂ contact.The production rate is correlated to the exposure time:an initial fast-increa-sing stage followed by a declining stage hereafter.The CO₂ diffusion is the main mechanism driving the CO₂-EOR in shale reservoirs.In conclusion,the study has proven that CO₂ injection serves to effectively enhance shale oil recovery,which may provide an analogy to the effective development of continental shale oil elsewhere.

Identification method of sweet spot zone in lacustrine shale oil reservoir and its application: A case study of the Shahejie Formation in Dongying Sag,Bohai Bay Basin

Zhang Pengfei, Lu Shuangfang, Li Junqian, Xue Haitao, Li Wenbiao, Zhang Yu, Wang Siyuan, Feng Wenjun

2019, 40(6):  1339-1350.  doi:10.11743/ogg20190618

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The favorable target zone of shale oil reservoir is the overlapping area of resource sweet spot,physical property sweet spot and engineering sweet spot.To find out the primary geological parameters that may be applied to characterize the three kinds of sweet spots is the key to identifying favorable shale oil target zones.In the study,we propose a comprehensive quantitative method to identify favorable shale oil target zones based on major geologic parameters.First,the primary geological parameters including free oil content,permeability and Young modulus are chosen to establish a weighting evaluation function.Second,a comprehensive weighting factor is constructed by using the weighting evaluation value of primary geological parameters,to define the distribution of comprehensive weighting factors of the favorable,low-efficiency and ineffective layers in shale oil exploration.Third,the favorable target layers and zones of shale oil is thereby mapped.The method has been successfully applied to evaluate the comprehensive weighting factors of the shale oil sequence in 27 wells in the lower sub-member of the 3rd member (Es^3L) and the upper sub-member of the 4th member (Es^4U) of the Shahejie Formation,Dongying Sag,Bohai Bay Basin,and to map favorable layers and zones for shale oil exploration.The result is of certain referential meaning to the exploration and development of shale oil in the Dongying Sag.