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Table of Content

    28 June 2018, Volume 39 Issue 3
    Previous Issue    Next Issue
    Origin of on natural gas in the Lower Silurian Songkan Formation from Well Anye 1,north Guizhou area
    Zhang Jinchuan, Lei Huaiyu, Zhang Fu, Li Long, Liu Ziyi, Liu Yang, Zhang Peng
    2018, 39(3):  419-428.  doi:10.11743/ogg20180301
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    The Well Anye(AY)1 of north Guizhou,in the Sichuan Basin,is a shale gas well of major breakthrough in oil and gas exploration of the basin.The Lower Silurian Songkan Formation of this well has good resources of potential of oil and gas.To better understand the genesis of natural gas in the gas reservoir of the formation,we distinguished the Lower Silurian Songkan and Shiniulan Formation in the area,and made a series of experiments in geochemistry,gas composition,gas isotopes.The experimental results show that(1)under special lithologial combinations,the average content of TOC of the Songkan Formation in this area is 0.16%,the Ro value varies from 2.75% to 2.92% with the average of 2.95%,and the kerogen type is mainly Type Ⅱ;meanwhile its gas accumulation is dominated by methane(over 96%),plus a small amount of ethane,propane,and other hydrocarbon gases;(2)the natural gas drying coefficient of the Songkan Formation in the study area is much smaller than that of the Wufeng-Longmaxi Formation,and the CO2 content of the Xintan Formation is significantly higher than that of the Songkan and Wufeng-Longmaxi Formation;(3)the δ13C1 value of gas isotopes in the Songkan Formation ranges from -33.2‰ to -33.9‰,with the average of -33.5‰;δ13C2 value is in the range between -36.5‰ and -37.0‰,and the average is -36.8‰,while the δD(CH4) value is within the range between -145.8‰ and -156.6‰,averaging at -150.0‰,and the kerogen carbon isotope value in the formation is from -32.9‰ to -32.6‰,with the average of -32.75‰.Combining CO2 tracer gas migration theory,gas drying coefficient and gas source correlation characteristics,we conclude that the natural gas of the Songkan Formation strata from Well AY1 is mainly derived from the formation's mudstone shale gas after heat cracking.
    Genesis and intensity of hydrothermal sedimentation in hydrocarbon source rocks in the Lower Cambrian Niutitang Formation,Guizhou area
    Jia Zhibin, Hou Dujie, Sun Deqiang, Jiang Yuhan, Zhang Ziming, Hong Mei
    2018, 39(3):  429-437.  doi:10.11743/ogg20180302
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    The study case is the source rocks of the Lower Cambrian Niutitang Formation in Guizhou area.Their trace element content is analyzed to accurately identify the hydrothermal sedimentation effect on source rocks and evaluate the intensity of the effect.The results show that(1)the diagram V/Sc-V/Cr can be used to judge whether hydrothermal sedimentation effect is a contributing factor for the composition of source rocks in the study area,which in turn,can reflect the redox environment change;(2)the slope Sc/Cr ratio is applicable for evaluating the intensity of hydrothermal sedimentation:when the Sc/Cr ratio is more than or equal to 0.144,normal sedimentation dominates and hydrothermal sedimentation effect is weak,and there is a linear correlation between V/Sc and V/Cr ratios,reflecting the redox environment change;when the Sc/Cr ratio is less than or equal to 0.120,hydrothermal sedimentation dominates,and the V/Cr ratio,which is distorted by the element content anomaly in the hydrothermal sediments,can not indicate the actual change of the redox environment,but remain useful to indicate the environment change;however,when the Sc/Cr ratio varies from 0.120 to 0.144(with both ends included),both sedimentary processes function,and the value of V/Cr ratio is influenced by the hydrothermal sediments,but can still indicate the trend of redox environment change,and thus can be applied normally.The conclusion can be drawn that the diagram V/Sc-V/Cr can accurately identify the influence and indicate the intensity of the hydrothermal sedimentation on source rocks.
    Development conditions, evolution process and depositional features of hyperpycnal flow
    Luan Guoqiang, Dong Chunmei, Lin Chengyan, Ren Lihua, Jiao Hongyan, Zhao Haiyan, Peng Xianguo
    2018, 39(3):  438-453.  doi:10.11743/ogg20180303
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    Hyperpycnal flows are dense,formed when a sediment-laden fluid plunges into the bottom of a water body and flows basinward.After a large number of literature review,we summarized the development conditions,evolution process and depositional features of hyperpycnal flow.The formation of hyperpycnal flow is controlled by tectonic and climatic conditions,closely related to the location of the source-to-sink system.And the favorable conditions for its development are loose parent rocks,semi-arid climate,high elevation difference,low degree of evaporation of river drainage area,a significant slope at the river mouth and low-density water body.Typically,sedimentary sequence of hyperpycnites can reflect the evolution of hyperpycnal flow energy.To identify hyperpycnites,we should pay attention to important features such as coupling of inverse and normal grading (Ha-Hb),internal mutation/erosion contact,typical flowing depositional structures and concentration of plant debris.Based on previous workers'studies,we established an ideal model of hyperpycnal facies consisting of channel-filling sedimentation,channel margin sedimentation,natural levees and front lobes.
    Research status and development trend of the reservoir caprock sealing properties
    Fu Xiaofei, Wu Tong, Lyu Yanfang, Liu Shaobo, Tian Hua, Lu Mingxu
    2018, 39(3):  454-471.  doi:10.11743/ogg20180304
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    Caprock directly determines the scale of oil-gas accumulation.The lithology of caprock in large-medium oil and gas fields is mainly mudstone,gypsolyte/saline rock and carbonate rock.In recent decades,we have made great progress in the sealing mechanism and evaluation methods for sealing property study.Scholars have proposed the capillary,hydraulic,overpressure,and hydrocarbon concentration sealing mechanisms through the years.For different sealing mechanisms,the sealing property evaluation criteria were set up,which played an important role both in the evaluation of hydrocarbon plays and the selection of exploration targets.Conventional study on the sealing properties of caprock is mainly based on static evaluation,but in fact,its sealing properties may change during multi-stage burial-uplift tectonic evolution.Jin(2013)established a quantitative evaluation method for the dynamic evolution of caprock sealing properties,which was based on the relationship between the porosity and capillary pressure during burial,the permeability and capillary pressure during uplift,and the OCR,a quantitative prediction method for the evolution of capillary sealing properties.And the method provides a reasonable basis for the study of oil and gas accumulation in multi-stage tectonic evolution basin.Thus,based on the study of the above-mentioned mechanisms and methods,it was pointed out that faults,tectonic fractures and hydraulic fractures were the key factors to the integrity of caprock,and the condition for the oil and gas to break through caprock was clarified,which provided a new way to find the secondary reservoir.The formation and evolution process of faults and fractures and their destruction to the caprock integrity depend on the seal's mechanical characteristics,that is,the caprock brittle-deformation prone or ductile-deformation prone.Based on the density and rock mechanics of mudstone,a method for distinguishing brittle and ductile deformation of mudstone was established.According to Byerlee's friction law and Goetes's criterion,a method for distinguishing brittle-ductile deformation of gypsolyte/saline rock is formulated.Therefore,the mechanisms for destruction of faults and fractures on brittle,brittle-ductile or ductile cap-rocks were clarified.Nowadays,there are still many problems necessary to be explored further,including the effects of different caprocks on hydrocarbon preservation,the effects of regional geologic factors on the sealing properties of caprock,the division of diagenesis stages and the dynamic evolution of sealing properties of shale,the brittle-ductile transition of caprocks and quantitative characterization of fracture conditions,the effect of deep faults on oil and gas migration and preservation,quantitative evaluation of caprock integrity,etc.
    Structural differences in organic pores between shales of the Wufeng Formation and of the Longmaxi Formation's first Member,Jiaoshiba Block,Sichuan Basin
    He Chencheng, He Sheng, Guo Xusheng, Yi Jizheng, Wei Zhihong, Shu Zhiguo, Peng Nyujia
    2018, 39(3):  472-484.  doi:10.11743/ogg20180305
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    Nanoscale organic pores are the dominant pores in the marine organic-rich shales of the Wufeng Fomration and the Longmaxi Formation's first Member in the Jiaoshiba Block,Sichuan Basin,which provide important reservoir space for shale gas.In this study,a combination of field emission scanning electron microscopy(FE-SEM),statistical analysis based on ImageJ software and gas adsorption test,was conducted to investigate structural characteristics of organic pores,such as pore shape,pore quantity,pore-size distribution.The surface pore rate of organic matter(OM)was calculated,based on 20 sample rocks from the three sets of shales in the Wufeng Formation and the lower and upper Longmaxi Formation's first Member.FE-SEM images show that the pore sizes are within a range of 2-900 nm,and significant variations exist for the nanoscale organic pore structures with the sizes of 10-900 nm among the chosen shale samples.Most of the organic pores in the Wufeng Formation shales are irregular polygons in shape,while elliptical and sub-rounded organic pores are observed in the Longmaxi's first Member.Organic pores with width of 10-50 nm are most popular in the Wufeng Formation shale samples,followed by the upper part of the first Member of the Longmaxi Formation,while the lower part of the first Member of the Longmaxi Formation mostly develop organic pores with the width of 50-900 nm,with the upper part of the Member ranked the second.Based on the statistic results over 61 400 organic pores with the size ranging from 10 nm to 900 nm in the shale samples,we observe that the average surface pore rate of OM for a single grain has a weak positive correlation with the total organic carbon(TOC)content,but the average surface pore rate of OM in the sample shales of the Wufeng Formation is relatively smaller than that in the Longmaxi Formation.The gas adsorption test and pore size measurement show that a good positive correlation between TOC content and nanometer pores with pore-sizes of 0.3-1.5 nm and 2-10 nm exists.Thus we may conclude that the structural differences of organic pores in the sampled shales are derived from the TOC content variation and the special location of the Wufeng Formation,the shales of which are located at the bottom of compressive decollement formations and had experienced layered decollement reconstruction which in turn results in partial gas release under overpressure.
    Lithofacies types and reservoir characteristics of marine shales of the Wufeng Formation-Longmaxi Formation in Fuling area,the Sichuan Basin
    Wang Chao, Zhang Boqiao, Shu Zhiguo, Lu Yongchao, Lu Yaqiu, Bao Hanyong, Li Zheng, Liu Chao
    2018, 39(3):  485-497.  doi:10.11743/ogg20180306
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    Lithofacies identification and reservoir characteristics study of shale are fundamental to the geological evaluation of shale gas exploration and development.Based on the drilling data,X ray diffraction and thin section analysis,we proposed a scheme for lithofacies classification of marine shale.Then,we systematically analyzed the reservoir quality of varying shale lithofacies from the Wufeng Formation-Longmaxi Formation's first member,based on geochemical test results such as the total organic carbon(TOC) content,pore structure,porosity-permeability properties,lamina features,gas-charging properties,etc.The stratigraphic member developed three categories of shale lithofacies in the Fuling area,which can be subdivided into five major lithofacies(argillaceous-siliceous shale,dolomitic-argillaceous-siliceous shale,siliceous-clay shale,mixed argillaceous-siliceous shale,and mixed dolomitic-argillaceous-siliceous shale).There is a significant difference in reservoir characteristics between various lithofacies:the siliceous shale is a high-quality lithofacies with high TOC,high porosity and high gas content.The sedimentary setting determines reservoir quality development,while also controlling the shale lithofacies development.During the sedimentation of siliceous shale in the lower Wufeng Formation-Longmaxi Formation's first member, frequent volcanic activities provided abundant nutrients for plankton outburst,and induced an oxygen-poor and anaerobic environment which is conducive to the preservation of organic matter and the development of organic carbon-rich siliceous shale.The mixed shale and argillaceous shale developed in the middle and upper part of the first member are affected by bottom current and terrigenous debris supply respectively,which led to an oxygen-rich depositional environment,deteriorating the preservation condition of organic matters,thus lower content of TOC and less gas generation.
    Sedimentary characteristics and favorable reservoir facies distribution of the Middle Triassic Leikoupo Formation,Sichuan Basin
    Sun Chunyan, Hu Mingyi, Hu Zhonggui, Deng Qingjie
    2018, 39(3):  498-512.  doi:10.11743/ogg20180307
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    In order to look for new fairways for future gas exploration in the Sichuan Basin,we worked on revealling the sedimentary characteristics and distribution of favorable reservoir facies in the Middle Triassic Leikoupo Formation.The study took marine carbonate sequence stratigraphy and reservoir sedimentology theory as guidance.Based on the markers in logging data,from cores,and sequence boundaries including unconformity,we conducted the sequence stratigraphy division and identification of sedimentary facies.Then spatial boundaries of sedimentary facies in each sequence are delineated,and the lithofacies paleogeographic map of each system tract in every sequence are compiled to predict favorable reservoir facies distribution.The results show that the Middle Triassic Leikoupo Formation in the Sichuan Basin develops a set of shallow water carbonate platform sedimentary system,including 4 major sedimentary facies,namely,restricted platform,evaporitic platform,platform edge and open platform.In general,the formation appears to be higher in the east and plunges to the west,with significant uplift and sag within the platform driven by early Indosinian tectonic movement.Due to basement uplift,some of the upper sections of the formation are eroded by long-term exposure,companied by development of a weathering crust.Furthermore,based on sedimentary facies recognition and sequence interface markers,we divided the Middle Triassic Leikoupo Formation into 4 third-tier sequences and 8 system tracts:the paleo-uplift in the central basin and its surrounding dolomite flat,and the platform edge bank of the northwestern Mianzhu and Jiange uplifts,are favorable reservoir facies because of their better reservoir properties and effective coupling of reservoir and caprock.Therefore,we conclude that these fairways are the most favorable areas for future exploration in the Middle Triassic Leikoupo Formation in the Sichuan Basin.
    Hydrocarbon expulsion efficiency and oil-bearing property of the shale system in Chang 7 Member,Ordos Basin
    Huang Zhenkai, Liu Quanyou, Li Maowen, Chen Jianping, Li Peng, Zhang Rui
    2018, 39(3):  513-521,600.  doi:10.11743/ogg20180308
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    Hydrocarbon expulsion efficiency of the shale system is one of the most important issues in the shale oil and gas research,and also a key parameter for evaluating the potential of shale oil and gas resources.This paper chooses the mud shale system from Chang 7 Member of the Yanchang Formation,Ordos Basin,as the investigation object.It measures the expulsion efficiency of the shale system and also reveals the variation of oil-bearing properties among various lithologies of mud shale system,via systematic geochemical analyses.Their significance in shale oil production is also discussed.The result shows that at the medium maturity stage (Ro=0.8%),the hydrocarbon expulsion efficiency of Type Ⅰ organic mud shale and Type Ⅱ mud shale is 33% to 37% and 16% to 26%,respectively,while at the mature stage (Ro=1.1%),the expulsion efficiency of Type Ⅰ and Type Ⅱ is 64% to 67% and 54% to 58%,respectively.Thus we conclude that in the shale system with higher maturity (Ro=1.1%), the sandstone and silty mudstone with higher free hydrocarbon content and OSI index can be the favorable targets for shale oil exploration and development; the blocky mudstone with high free hydrocarbon content and OSI index would be a potential target for shale oil exploration, with integrated consideration of geological factors including oil-bearing properties of different lithologies, composition characteristics, gas/oil ratio, and fluidity of retained oil. However, the black shale (or pure shale section) might not become an effective target for shale oil exploration in the study area, restrained by some of its geological factors.

    Characteristics of sandy lamination and its hydrocarbon accumulation, Yanchang Formation,Ordos Basin
    Shi Liang, Wang Xiangzeng, Fan Bojiang, Lyu Lei, Li Yating, Yang Sen
    2018, 39(3):  522-530.  doi:10.11743/ogg20180309
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    There are a lot of sandy laminations in the Triassic Yanchang Formation shale in the central and southern Ordos Basin,but their influence on hydrocarbon accumulation is not clear.In order to reveal the geological characteristics of sandy lamination and explore its favorable effect on hydrocarbon accumulation,we have studied its lithologic and porosity-permeability characteristics,fracture development as well as oil and gas accumulation,through integration of methods such as core observation,microscopic identification,and organic geochemical analysis.The result shows that,the lithology of sandy lamination is mostly siltstone,argillaceous siltstone,and silty shale; the lamination mainly appears in the form of thin lamina,thin band,and thin interbed.And the existing sandy laminations have changed the way of lithological contact:denser development of the sandy lamination promotes more intense alternation of rock lithology,which is usually more favorable for hydrocarbon expulsion from source rocks.Besides,the sandy lamination favors pore size growth,so improving the physical property of the reservoir in turn.It changes the mechanical property of rocks,resulting in the change of distribution patterns of fractures.It also provides larger reservoir space for liquid hydrocarbon,dissolved gas,and free gas.Shale with highly developed sandy lamination in the Ordos Basin is the main target for present exploration and development,whereas thick deep-lacustrine shale,which is abundant in hydrocarbon,but due to limitations of present developing techniques,may only be producible in the future.
    Depositional environment and characteristic comparison between lacustrine mudstone and shale: A case study from the chang 7 Member of the Yanchang Formation,Ordos Basin
    Liu Qun, Yuan Xuanjun, Lin Senhu, Guo Hao, Cheng Dawei
    2018, 39(3):  531-540.  doi:10.11743/ogg20180310
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    Argillaceous rocks(or argillite)can be subdivided into two categories,mudstone and shale,which differ significantly in genetic mechanism,content of organic matters and mode of occurrence,constituent minerals,etc.A study on distribution patterns of lacustrine mudstone and shale as well as comparisons of their distinguished characteristics would be of great help in building up an organic-rich shale depositional model.The Chang 7 Member of the Yachang Formation is represented by a large set of mudstone and shale,which was deposited in the period of maximum lake depth of the Ordos Basin during the Triassic.Their differences,which are ascribed into five aspects (distribution pattern,geochemical cha-racteristics,rock composition,fabric,and main and trace elements),have been disclosed by typical vertical profile analysis,core-thin section observation,geochemical analysis,etc.That is,(1)distribution pattern:mudstone and shale are complimentarily deposited,with mudstone mainly deposited in delta front,deep-lacustrine-turbidite facies,and semi-deep lacustrine facies,while shale mainly in deep lacustrine facies;(2)fabric feature:shale is characterized by laminae and organic matters occurring along layers,while mudstone exhibits no laminae and its organic matters scattered;(3)rock composition:shale is rich in pyrite,eleven times the content of mudstone pyrite,whereas mudstone holds more dolomite and si-derite;(4)organic geochemistry indices:the TOC of shale with an average of 6.6%,is three times as much as that of mudstone,and the value of S1 averaging at 3.12 mg/g,is 2.5 times that of mudstone;(5)main and trace elements:shale is significantly higher in trace elements content like U,Th,Mo,Co,Ni,and in ratios like U/Th,V/Cr and P/Al than those in mudstone,while Ti/Al and K/Al ratios are higher in mudstone.In a word,the formation of mudstone and shale in the Chang 7 Member is mainly controlled by sedimentary facies,lake depth,and lake basin productivity.Shale is deposited further away from sediment source area with higher productivity and less oxygen in water.

    Geophysical fluid recognition for tight oil in Chang 7 Member,south Ordos Basin
    Liu Zhenfeng, Zhang Jinqiang, Han Lei, Zhang Guangzhi, Wu Li, Liu Chunyan
    2018, 39(3):  541-548.  doi:10.11743/ogg20180311
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    Fluid recognition in the south Ordos Basin using seismic data encounters two challenges:one is the tight reservoir,the physical properties of which are not clear,and thus the rock physical parameters that are sensitive to oil-bearing are unknown;the other is that the quality of seismic data is relatively poor,which can hardly satisfy the need of elastic parameter inversion.Hence,this study proposed methods and procedures that can overcome these challenges in rock physical modeling,seismic data processing and inversion.Regarding the complex mineralogy compositions of tight oil reservoirs in the South Ordos Basin,we proposed a way of constructing an anisotropic rock physical model.And on the basis of modeling and rock physical analysis,we identified that the ratio of Lame's coefficient and shear modulus are sensitive to oil-bearing in strata.Given the low signal-to-noise ratio in the south Ordos Basin,we introduced some solutions for certain key parts of data processing,including multi-scale static correction,amplitude consistency correction,angle gather correction,and simultaneous inversion of elastic parameters,and got reliable results for elastic parameter inversion.In combining the sensitivity parameters and results of elastic parameter inversion after rock physical analysis,we predicted the oil-bearing property of Chang 7 Member of certain exploration area in the south Ordos Basin,and the prediction matched well with the actual drilling results.The associated methods and region-specific solutions are efficient in practical application,and thus to certain extent,the technical difficulties in seismic fluid recognition for tight oil reservoirs in the South Ordos Basin with low signal-to-noise ratio are solved.
    Favorable accumulation region prediction and controlling factors of hydrocarbon accumulation of the Qigu Formation in the Fudong slope,Fukang Sag,Junggar Basin
    Lu Bingxiong, Wen huaguo, Dan Yong, Chen Hong, Zhu Yongcai, Yu Jingwei
    2018, 39(3):  549-557.  doi:10.11743/ogg20180312
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    As the main exploration target in the Fudong slope of the Junggar Basin,the first member of the Upper Jurassic Qigu Formation was investigated.Its lithology,reservoir pore space and physical property were analyzed in lab,and controlling factors of reservoir quality were summarized.Starting from high-quality reservoir analysis,we studied the controlling factors of hydrocarbon accumulation for the Qigu 1 Member based on oil-producing well data,which ultimately enable us to predict hydrocarbon accumulation areas.And the result shows that(1)lithology of the Qigu 1 Member is mainly fine-grained clastic sandstone with high structural maturity and low compositional maturity,and reservoir space is mainly primary intergranular pores,forming a medium porosity reservoir with medium-high permeability;(2)source provenances supply materials for reservoir deposition,while sedimentary facies and palaeogeomorphology control reservoir quality distribution; both compaction and abnormal pressure determine physical properties of reservoirs,while cementation and dissolution have limited impact on reservoir property;(3)the controlling factors of hydrocarbon accumulation are mainly oil and gas migration channels and driven power,with the former involving unconformity and fault development and the latter mainly caused by abnormal pressure difference.In conclusion,we predict four favorable accumulation regions in the Qigu 1 Member of the study area.
    Controlling factors for the formation of pore-fracture reservoirs in intermediate-basic volcanic rocks: A case study of the Carboniferous Jinlong Block,Junggar Basin
    Kong Chuixian, Chen Xuan, Qin Jun, Lu Zhiyuan, Gao Yang, Shen Bo, Chen Aizhang
    2018, 39(3):  558-566.  doi:10.11743/ogg20180313
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    This paper analyzed the characteristics of volcanic reservoir space and its formation process in the case of intermediate-basic volcanic rock in the Carboniferous Jinlong Block,by integrating the core,thin section,logging,seismic and analytical data.The results show that:(1)feldspar and other minerals in the upper volcanic cycle altered to zeolite and chlorite and formed an unstable layer during the volcano eruption quiescent intervals;(2)tectonic movement at the Late Carboniferous developed fault-fracture and unconformity,and then meteoric freshwater could cause vertical and transverse dissolution along the fault-fracture and the unstable layer at the top of the cycle;(3)new fault-fracture formed through the tectonic activity of the La te Jurassic period,and the pore-fracture reservoir was compartmentalized and the accumulation space was basically finalized.Under the control of fault-fracture,palaeo-geomorphology and contact surfaces of the volcanic cycles,the reservoirs are characterized by zonation in the vertical direction and by lenticular geometry with greater thickness in the paleo high and losser thickness down the paleo-slope.As a whole,the reservoir is a complex"multi-zone overlapping"reservoir,composed of fractures,dissolved pores,and dissolved fractures.The geological model of pore-fracture volcanic reservoir is of great value for volcanic reservoir prediction and oil/gas exploration.

    Quantitative evaluation of source tapping fault for oil migration and establishment of its migration model in LD oilfield in the Liaozhong Sag,Bohai Sea
    Tian Lixin, Wang Bingjie
    2018, 39(3):  567-577.  doi:10.11743/ogg20180314
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    In the Liaozhong sag,Bohai Sea,complex fault zones give rise to numerous secondary accommodation normal faults,which form and control a large number of fault block traps.Well data have confirmed that the vertical oil migration ability of source tapping faults,which connect mature source rocks with fault block traps located on top of it,is of great importance to abundance of oil and gas accumulation in these traps.The study regards that the geometry of source tapping fault's surface and its contact area within the mature source rocks control the oil and gas migration.Thus,the seismic data are used to elaborately interpret source tapping faults,to depict the three-dimensional geometry of fault section and its contact area within mature source rocks.Under the control of the above two geological factors,the migration ability was estimated by numerical simulation,and combined with logging data,we identified fault-associated fracture zones.Thus the model of oil and gas migration in LD oilfield is established based upon these results.The results are as follows:The oil migration ability of the six studied source tapping faults varies significantly.There are 24 charging points to the oil reservoir of the oilfield with diverse contributions,and result in different reserve abundance in different fault blocks.The intensity of associated fracture zone of the source tapping fault is different on either walls of the fault,with the better developed fractures and improved porosity and permeability near the downthrown side,where the selective hydrocarbon migration from the charging points occurs.And based on these results,we established the migration model of oil and gas in the study area,which matches well with the actual drilling results.
    Geochemical characteristics of Cretaceous source rocks and oil-source correlation in the Songjiang Basin
    Zhou Jian, Shan Xuanlong, Hao Guoli, Zhao Rongsheng, Chen Peng
    2018, 39(3):  578-586.  doi:10.11743/ogg20180315
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    Two sets of Cretaceous source rocks,Dalazi and Changcai Formation,develop in the Songjiang Basin.In this study,we discussed the geochemical characteristics of source rocks and crude oil and the oil-source correlation based on the conventional organic geochemical analysis and biomarker compound test on Cretaceous source rocks and crude oil in the basin.The organic geochemical analysis indicates that Cretaceous source rocks are rich in organic matters,with the major organic matter being TypeⅡ1-Ⅱ2,and the source rock maturity ranges from low-mature to mature degree.And the Dalazi Formation has the greatest potential of hydrocarbon generation,followed by Changcai Formation.The analysis of biomarker compounds show that some of the Cretaceous source rocks and crude oil are subjected to a certain extent of biodegradation.Besides,source rocks of the Changcai Formation can be divided into three groups:the organic matters of source rock Group Ⅰ and Ⅱ are mainly from higher plants,which are deposited in partially oxidized fresh and brackish water,and source rock Group Ⅲ contains large amounts of gammacerane and β-carrotane,deposited in saline water.Source rocks of the Dalazi Formation are mainly deposited in reductive-brackish water environment,and their parent materials come from mixed sources.The oil-source correlation reveals that the crude oil generated from the Changcai Formation can be divided into two categories:the K1c1 oil originates from Group Ⅰ source rock and the K1c2 oil from the Group Ⅱ source rock of the source formation.Meanwhile,the reductive-prone oil from the Dalazi Formation originates from its K1d2section.
    Controlling effect of dissolution on valid volcanic reservoir formation: A case study of the Yingcheng Formation in the Xujiaweizi Fault Depression,Songliao Basin
    Zhang Yuyin
    2018, 39(3):  587-593.  doi:10.11743/ogg20180316
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    Volcanic reservoirs are usually characterized by complex rock types and higher heterogeneity.The paper systematically studied the diagenesis and porosity evolution of volcanic reservoirs from the Yingcheng Formation in the Xujiaweizi Fault Depression,Songliao Basin,via core observation and identification of casting thin slice.The result shows that all valid reservoir lithologies,including rhyolite and crystal tuff,underwent six diagenetic stages,while different types of diagenesis,stages,and evolution patterns occurred to different reservoir lithologies.That is why the porosity evolution and physical properties of those rocks were heterogeneous.In the study area,dissolution is the most effective diagenesis process to the formation of valid reservoir,including organic acid dissolution and CO2-bearing acidulous water dissolution.And the secondary pores mostly developed in the acid volcanic rocks after organic acid dissolution played a decisive role in forming valid reservoirs.In terms of the controlling factors for dissolution,some of the most important ones may be the extent of original primary porosity system,the intensity of fracture activity and tectonic cracking in later periods,the top/bottom unconformities of volcanic rocks,etc.

    Methods for pore pressure prediction based on high-precision velocity modeling technology
    Xu Jialiang, Zhou Donghong, He Dianbo, Bian Li'en, Lyu Zhenyu
    2018, 39(3):  594-600.  doi:10.11743/ogg20180317
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    The prediction of pore pressure through Eaton method requires a highly precise depth domain interval velocity model to make correct predictions,but the velocity from conventional interval velocity modeling methods cannot reach such an accuracy.So,an innovative prediction method is proposed,which is specifically suitable for the poorly compacted mudstone formation,characterized by abnormal high pressure and low velocity.Shot domain velocity coherence inversion method is proposed to establish the initial velocity model.The residual curvature analysis of common imaging point gather in angle domain(ADCIGS)is used for velocity convergence.The grid tomography based on layer constraints is used to make local modifications.These three methods are integrated as a new interval velocity prediction process,specific for abnormal high pressure zones.The new process is then applied to the modeling of depth domain interval velocity field and prediction of pore pressure in the working area M of Bohai Sea.As a result,the interval velocity model matches well with the acoustic logging velocity,and the pore pressure coefficient calculated by the new process is identical with the Palaeogene formation pressure measurements.Judging from these,we can see its accuracy is much higher than the conventional method.The realworld case study demonstrates that the depth domain interval velocity modeling can make highly accurate predictions on pore pressure,and thus are effective and feasible.These methods can improve the accuracy of pore pressure prediction while maintaining the efficiency of calculation,and thus can facilitate the safety of drilling engineering.

    Concepts and methods for coalbed geology modeling: A case study in the Hancheng mining area,Southeastern margin of Ordos Basin
    Ma Pinghua, Shao Xianjie, Huo Mengying, Chu Qingzhong, Huo Chunliang, Liang Wubin
    2018, 39(3):  601-610.  doi:10.11743/ogg20180318
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    The way of coalbed geology modeling is quite different from that of modeling conventional sandstone oil/gas reservoirs due to the following factors.(1)It is difficult to obtain the actual permeability of coalbed through laboratory experiment because the coal rock sample is brittle;(2)the permeability derived through laboratory experiments cannot reveal the subsurface conditions,since the coal rock is low in elastic modulus,high in poisson's ratio,and thus it is sensitive to stress;(3)it is difficult to apply the methods of well log petrophysical interpretation to interpret coalbed permeability.Thus in this study,we determine the permeability via well testing data,and establish a quantitative relationship between in-situ stress and permeability according to the types of coalbed,based on the analysis of all critical factors for permeability.In addition,we propose a 4-step modeling,namely,to set up the model of coal reservoir space framework,the coal facies(type)model,and the in-situ stress model.Then,under these 3 constraints,the model of permeability is established with stochastic simulation technique and the controlling points from the permeability obtained from well test and well in-situ calculation.Further,the model fits well with the production data status quo from the actual coal data of bed methane fields,which proves the feasibility of the concepts and methods in practical application.
    Investigation of hydraulic fracturing process in coal reservoir by a coupled thermo-hydro-mechanical simulator TOUGH-FLAC3D
    Yuan Xuehao, Yao Yanbin, Gan Quan, Liu Dameng, Zhou Zhi
    2018, 39(3):  611-619.  doi:10.11743/ogg20180319
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    A coal-bed methane reservoir of the Anze Block,southern Qinshui Basin,is the chosen study area.The research developed a simulator linking TOUGH with FLAC3D to analyze thermo-hydro-mechanical coupling during hydraulic fracturing in the coal reservoir,and then to reveal the rules of fracture propagation and bed-penetrating under the constraint of multiple fields.The results show that hydraulic fractures that propagate along the pre-existing natural fracture's direction,tend to occur when the two fractures intersect with a small approaching angle; otherwise,hydraulic fractures will propagate along the direction of the maximum horizontal principal stress.Due to the distinctive difference of rock mechanical properties between coalbed and its roof and floor beds,and high density of micro-fractures in the coalbed,the pressure in the coalbed propagates faster than that in the roof and floor rocks seen from vertical profiles,which results in two relatively higher pressure zones near the boundaries from coalbed to roof and coalbed to floor rocks respectively.In addition,compared with the shallowly buried coalbed,the deeply buried one is subjected to plastic deformation under an existing bigger in-situ pressure.The major reason for roof/floor fracture penetration is the occurrence of flow pressure accumulation,caused by the relative small leak-off rate of fracturing fluid and relatively bigger vertical stress than that of the shallow bed.The results of sampled coal experiments and fracturing curve analysis verify the accuracy of the simulation.
    Joint development and production replacement for development optimization of multiple oilfields in deepwater oil region
    Chen Minfeng, Shi Jianhu, Zhu Xueqian, Huang Anqi
    2018, 39(3):  620-630.  doi:10.11743/ogg20180320
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    For a highly efficient development of overseas deepwater blocks composed of several oilfields,one should make an optimized master plan for producer on-stream sequence and production replacement,and tailor field development strategies for each oilfield according to their unique features.This also ensures the maximum project profits through the effective development optimization.Based on the features and requirements of joint development of multiple deepwater oilfields,we suggested three studies to be carried out to optimize reserve development and production replacement in various scenarios of combined deepwater oilfields development.(1)We established the evaluation standards for reserves ranking through comprehensive mathematical evaluation methods,and clarified the reserve ranks for various oilfields;(2)We established the prediction models for key development indexes for varying reserve levels via the analysis of main controlling factors for production and operation in deepwater oilfields,which can be used as the basis for the calculation of production operation under joint development of different oilfields;(3)We established the mathematical model to satisfy various constraints and to maximize project NPV profits.Process control theories were applied to select the best combination pattern and the optimized drilling sequence for varying ranks of reserves.Application of the methods proposed in this study to the development and deployment of XF deepwater oil region based on the actual oilfield data,we calculated the petroleum reserves for development and the strategy of production replacement to optimize multiple oilfields development under different conditions.The results meet the actual development requirements,so ultimately enhancing the reliability of deepwater oilfield development decisions.