Table of Content

28 April 2017, Volume 38 Issue 2

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Fluid inclusion evidence for multi-period oil charge in Shahejie Member 4, Bonan Subsag,Bohai Bay Basin

Lin Hongmei, Cheng Fuqi, Wang Yongshi, Song Guoqi

2017, 38(2):  209-218.  doi:10.11743/ogg20170201

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To confirm oil charge stages in the Bonan Subsag,Bohai Bay Basin,Twenty six samples collected from twenty four wells in Shahejie member 4(Es⁴) were used for fluid inclusion analysis.Based on microscopic identification,micro-beam fluorescence spectra and homogenization temperature testing in combination with sedimentary burial and thermal evolution histories,oil charge stages and their timings were obtained.There mainly developed three types of inclusions in the Es⁴ reservoirs including aqueous inclusions,oil inclusions and hydrocarbon brine inclusions.In addition,asphalt inclusion and filling asphalt in cracks and pores were also observed in some samples.Fluorescence colors of oil inclusions mainly are yellow-yellowgreen and blue-white,with a little of orange color.Main peak wavelength (λ_max) distribution of orange,yellow-yellowgreen and blue-white oil inclusions are 555.76-576.88,513.25-555.76,and 491.13-497.93 nanometers respectively.Red-green entropy Q_650/500 and Q_{t 535} of the three colors oil inclusions are 0.21-0.39 and 2.25-2.71,0.43-0.96 and 0.99-2.45,and 0.95-1.17 and 0.60-1.13 respectively.Homogenization temperatures of coeval aqueous inclusions of the three colors oil inclusion are 92.6-112.2,106.4-143.7(mainly 120-140) and 143.2-162.7 degree centigrade.Conclusion could be drawn that reservoirs in the Es⁴ had experienced at least three oil charging stages(early,middle and later stages)with different maturity of the oils.By positioning the aqueous inclusions homogenization temperature values on sedimentary burial and thermal evolution history chart,the geological times of the three oil charging stages are obtained which are 30.7-27.7,18-5 and 3.8-0 million years respectively.Current oil and gas found in the Es⁴ were mainly accumulated during the second and the third charging stages.

Heterogeneity and evolution model of the Lower Shahejie Member 3 mud-shale in the Bonan Subsag,Bohai Bay Basin:An example from Well Luo 69

Peng Li, Lu Yongchao, Peng Peng, Liu Huimin, Liu Zhanhong, Du Xuebin, Li Jijun, Zhang Sansheng

2017, 38(2):  219-229.  doi:10.11743/ogg20170202

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Multiple heterogeneity characteristics and evolutionary process of the Lower member 3 of Paleogene Shahejie Formation lacustrine shale in the Bonan Subsag,Jiyang Depression have been analyzed based on previous sequence stratigraphic framework and analysis of core observation and sample testing.The results show that the Lower Es^3(下) can be described as a third-order sequence,which can be divided into expanding systems tract (EST),early highstand systems tract(EHST) and late highstand systems tract (LHST).Lithofacies associations,mineralogy,algae species occurrence,as well as TOC (total organic carbon) and kerogen type,change noticeably and regularly in the Lower Es³ shale within the sequence stratigraphic framework.For lithofacies associations,six lithofacies are identified.From the EST to the LHST,there are increased abundance in clay minerals,quartz and feldspar,and reduced abundance in calcite and dolomite,while pyrite reached the highest abundance in EHST.Algaes have the largest number and most variety of species in the LHST.TOC content is the lowest in the EST.Kerogen type is dominated by type Ⅰ and Ⅱ₁.The oil richness is influenced by multiple heterogeneity characteristics,comparative analysis suggests the EHST is the most potential shale oil target interval in the study area with excellent oil richness.

Probability cumulative grain-size distribution curves and their implications for sedimentary environment identification of coarse clastic rocks of the Es³ in Yongbei area,the Dongying Sag,Bohai Bay Basin

Wang Zhukun, Li Yuzhi, Cao Yingchang, Wang Yanzhong, Yang Tian, Zhao Bo

2017, 38(2):  230-240.  doi:10.11743/ogg20170203

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Sediment hydrodynamic conditions are the basis of the study on sedimentary facies and the key to hydrodyna-mic analysis is the distribution of grain size.On the basis of elaborate observation of cores and facies analysis,characteristics and its relationship with sedimentary environment of probability cumulative grain-size distribution curves of coarse clastic rocks of Es³ in Yongbei area of the Dongying Sag,Bohai Bay Basin are systematically studied through mass grain size data.The grain-size distribution curves can be classified into 4 basic types(including debris flow type,high-density turbidity current type,low-density turbidity current type and tractive current type) and 2 transitional types(including debris flow to low-density turbidity current transitional type and high-density turbidity current to low-density turbidity current transitional type).The debris flow type includes broad convex arc pattern and arc-linear composte pattern reflecting debris flow deposition,and mostly develops in main channels of inner fan of the nearshore subaqueous fan and the fan-delta plain.The high-density turbidity current type consists of one suspension segment pattern and low-slope two-segment pattern reflecting high-density turbidity current deposition,and develops in channels of the nearshore subaqueous fan and aquatic or subaqueous distributary channels of the fan-delta.The low-density turbidity current type contains low-slope two-segment pattern and low-slope two bouncing segment-one suspension segment pattern reflecting low-density turbidity current deposition,and mainly develops in space between main channels and space between braided channels of the nearshore subaqueous fan.The tractive current type includes high-slope two-segment pattern,one roll segment-one bouncing segment-one suspension segment pattern,one bouncing segment-one suspension segment-one transitional zone pattern and two bouncing segment-one suspension segment reflecting tractive current deposition,and mainly develops in middle fan of the nearshore subaqueous fan and fan-delta front.The debris flow to low-density turbidity current transitional type shows step-like multi-segment pattern representing transition from debris flow to turbidity current and develops in subaqueous distributary channels of the fan-delta.The high-density turbidity current to low-density turbidity current transitional type is of one bouncing segment-one suspension segment-one transitional zone pattern and only develops in deeply-cutting channels of the outer fan on behalf of the density decline phenomenon of turbidity current.

Oil-water movement pattern based on research of delta front monogenetic sand:A case study from the E₃d₂^L of Oilfield Z in the Bohai Bay Basin

Han Xuefang, Yan Guanshan, Liu Zongbin, Song Hongliang, Wang Xinran

2017, 38(2):  241-247.  doi:10.11743/ogg20170204

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At the mature development phase of an oilfield,the analysis of monogenetic sand reservoir architecture is efficient to instruct the research on the oil-water movement pattern and the operation of tapping remaining oil.Based on the reservoir configuration theory,this paper divided the composite sand reservoir into multiple monogenetic sandbodies in Oil-groupⅠ and Ⅱ of the E₃d₂^L in Oilfield Z of the Bohai Bay Basin using three vertical stage identification markers and four lateral delimitation identification markers.The vertical stage identification markers include shale interlayers,pebbly sandstones,calcareous interlayers and the lateral delimitation identification markers include logging curve shape difference,lithology difference,thickness difference and water flooding feature difference.Each monogenetic sandbody represents a single sedimentary microfacies (e.g.underwater distributary channel or mouth bars,etc).In addition,the definite logarithm correlation between interwell sandbody thickness variation and top boundary dip was used to quantitatively identify the pinch out point of the single sandbody.Therefrom,the subsurface complex sedimentary characteristics were reconstructed to display the contiguous distribution of mouth bars and the cross superimposition of underwater distributary channels within this oilfield.Combing with the other static and dynamic data,the comprehensive analysis revealed that the quality difference of monogenetic sandbody is the major factor influencing the oil-water movement and remaining oil distribution in the study area.The independent flow unit develops within the individual lobe,within which the different types of monogenetic sandbodies with different reservoir quality correspond to different seepage capacities and flooding features.The premium monogenetic sandbodies are prone to form dominant pathways and result in enrichment of remaining oil.The study of oil-water movement based on monogenetic sandbody analysis will provide a solid geological foundation for tapping the potential of remaining oil through infill drilling and enhancing the oil recovery in the oilfield.

Identification, origin and distributions of barriers/baffles Xing-Ⅰ oil layer in Block Du-84 of the western Liaohe Depression

Wu Jun, Fan Tailiang, Gao Zhiqian, Li Chen, Zhang Tao, Ma Congming

2017, 38(2):  248-258.  doi:10.11743/ogg20170205

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Barriers/baffles in reservoirs have been considered as one of the control factors of reservoir heterogeneity.A study on barriers/baffles may provide a sound foundation for a fine characterization of reservoirs and a more accurate prediction of remaining oil distribution.By combining core observation and dynamic production data as well as logging data of 1 735 wells in the Shuyi Block in western Liaohe depression,we drew cross plots of five parameter (i.e.interval transit time,lateral resistivity,induction conductivity,porosity and permeability) in accordance with core calibrated logging curves,and analysis result of electrical and physical property tests.We classified the barriers/baffles into two types (shaly barriers/baffles and physical barriers/baffles) and established a standard and a template for their quantitatively identification.The barriers/baffles developed in the study area were mainly controlled by factors including sedimentation of flooding stage,weakening local hydrodynamics,multi-stage fluvial erosion cuttings,progradation and riverbed lag deposition.The shally barriers/baffles were mainly distributed in shallow lakes and interdistributary bays,while the physical barriers/baffles were mostly located in bifurcations of underwater channels and local areas of interdistributary bays.Barriers/baffles were scarce and isolated in the stacked channels near provenance.However,they were more frequent and thicker away from provenance.Their vertical distribution was closely related with the base level cycles and their number and thickness got larger from bottom up in the ascending semi-cycles of the middle-long term base level cycles.We also proposed that the lithology,physical properties,thickness and distribution of barriers/baffles had certain effects upon the performance of SAGD (steam-assisted gravity drainage) in heavy oil discovery of Liaohe Oilfield.

Sedimentary filling evolution of small-scale lake basins during intensive faulting:an example from the Shahezi Formation of Songzhan region in Xujiaweizi fault depression,Songliao Basin

Cai Quansheng, Hu Mingyi, Hu Zhonggui, Deng Meng

2017, 38(2):  259-269.  doi:10.11743/ogg20170206

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The Songzhan region in northern Xujiaweizi Fault Depression of Songliao Basin is a small-scale faulted basin.The latest drilling data shows great gas potential in the basin and a possible replacement of the depleting deep gas zones in Daqing Oilfield.We chose the Shahezi Formation in the basin as a research object to analyze the stratigraphic sequences,sedimentary systems and filling-up history of small scale lake basins during intensive faulting based on previous studies as well as data of core,mud logging,conventional logging and 3D seismic survey.The result shows that the Shahezi Formation can be divided into one second-order sequence and four third-order sequences,with the latter being further subdivided into LST,TST and HST,according to lake flooding surfaces.Four kinds of sedimentary facies,including braided delta,fan delta,lacustrine and volcaniclastic facies,were recognized.The filling-up history of the Formation appears to be quite different from that of large-scale fault basins.Fan deltas dominated both steep and gentle slopes at the early stage of intensive faulting.And zonation of sedimentary facies was only distinctive with the expansion of the basin.How-ever,they were segmented into many shore-shallow lacustrine sedimentary zones with multiple depocenters due to a sediment supply shortage in the short axis of the basin.As a result,the thickness of layers in the basin varies greatly from one area to another.We proposed in the paper a sedimentary model for the continental narrow faulted lake basins based on the study of the filling-up history of the Shahezi Formation.

The Early Cretaceous thermal fluid activities and their impacts on clastic reservoir rocks in the Bayingebi Formation of Chagan Sag

Wei Wei, Zhu Xiaomin, Tan Mingxuan, Wu Chenbingjie, Xue Mengge, Guo Dianbin, Jiang Feihu, Lyu Sihan

2017, 38(2):  270-280.  doi:10.11743/ogg20170207

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Analyses of sedimentary,reservoir,and structural characteristics,were combined with application of such technologies as fluid inclusion and carbon and oxygen isotopes techniques,and observations of cores,thin sections and scanning electron microscope images,to study deposition during the Early Cretaceous Suhongtu stage in Chagan Sag.The result indicates a strike-slip and pull-apart faulting stage accompanied by multi-stage volcanic activities of thermal fluid flows dominated by neutral-basic andesite and subordinate basalt.The thermal fluid activities during the Suhongtu volcanic eruptions exerted significant influence upon layers deeper than 2 800 meters in the Bayingebi Formation and resulted in an abnormal high value of paleo-heat flow,an abnormal increase of homogenization temperature of inclusions,inorganic characteristics of carbon isotopes,an abrupt change in vitrinite reflectance,and an abnormal conversion of clay minerals.The thermal fluids from the deep layers carried gases (mainly CO₂) and migrated upward along the Maoxi faults into the Wuliji tectonic belt.They then migrated horizontally along micro fissures and channels formed by unconformities to dissolve mostly carbonates and feldspar in the Bayingebi Formation.The signs of erosion were mainly found in places near deep-rooted large faults that controlled the migration of the fluids.Unconformities as well as secondary faults and fractures also played a part in controlling the flow of the thermal fluids.The dissolution was observed to be weakened toward the inner part of the sag.We therefore suggest that a study on the effect of deep thermal fluids activities upon the thermal evolution of organic matters and physical properties of reservoirs is the key to understand the distribution of dissolved pores and cavities in the study area and to explore for high-quality reservoirs there.

New understanding of the Cambrian palaeotectonic and lithofacies palaeogeography in the Ordos Craton Basin

Zhang Chunlin, Zhang Fudong, Zhu Qiuying, Liu Ruie, Xin Ming

2017, 38(2):  281-291.  doi:10.11743/ogg20170208

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A study was carried out on the Cambiran paleotectonic and lithofacies paleogeography of Ordos craton basin based on relevant outcrops,drilling and seismic data.Isopach showed that the Cambrian sedimentary framework inherited the Meso-Neoproterozoic sedimentary framework and can be described as "three troughs,two lands and one depression".Based on this understanding and guided by carbonates sedimentology,we divided the Cambrian into four sedimentary systems:the shoreland,the open carbonate platform,the shelf slope and the trough;and compiled 5 lithofacies paleogeographic maps.The overall lithofacies paleogeographic outlook may be described as the following:in the direction from ancient land to sea successively occurring shoreland,platform with depression,ramp and trough.The Ordos area had experienced a complete transgression-regression process in the Cambrian.A massive ancient land still existed in the Early Cambrian with only a set of shoreland and an open platform sedimentary facies around southwestern margin.During the Middle Cambrian,ancient land shrunk and was segmented into three isolated ancient lands along with transgression of sea.After the Luliang ancient land finally disappeared in Zhangxia Stage,the central and eastern part was featured by open platforms and the southwestern part contained mainly shelf slopes and through.During the Later Cambrian,with the beginning of regression of sea,the ancient land wound southnorth-ward in central Ordos area.

Evidences and controlling factors of hydrocarbon charging in the Late Silurian in the north slope of the Tazhong Uplift,Tarim Basin

Wu You, Chen Honghan, Zhao Yutao, Tang Daqing, Yun Lu, Qi Lixin

2017, 38(2):  292-301.  doi:10.11743/ogg20170209

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In recent years,a breakthrough has been achieved in the exploration of the Silurian strata in the north slope of the Tazhong Uplift.However,it also reveals the complexity of the hydrocarbon accumulation process,owing to the multistage tectonic movement.In this paper,fluid inclusions analysis is performed on 23 samples of the Silurian strata in the north slope of the Tazhong Uplift,and also faulting activities characteristics were studied.The results indicate that there are four events of oil charging and one event of gas charging.The oil originated from the Cambrian to the Lower Ordovician source rock charged during the Late Hercynian (318-245 Ma),while oil and gas originated from the Cambrian-Lower Ordovician source rock and Middle-Upper Ordovician source rock charged during the Yanshanian to Middle-Late Himalayan (124-25 Ma).Due to the NE extensional strike-slip faulting,the early stage charged accumulations were destroyed and only residual bitumen remains,even though oil charging was active during the Late Hercynian.The oil and gas recharged during the Middle-Late Himalayan determined the hydrocarbon characteristics in the reservoirs.In all,the major targets for hydrocarbon exploration in the north slope of the Tazhong Uplift shall be accumulations formed during the Yanshanian to Middle-Late Hercynian.

Geochemical characteristics and origin of the deep Cambrian oil and gas in the Tazhong Uplift,Tarim Basin

Shi Jianglong, Li Jian, Li Zhisheng, Hao Aisheng

2017, 38(2):  302-310.  doi:10.11743/ogg20170210

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The Cambrian carbonate reservoirs of Tazhong uplift is rich in oil and gas.However,there are different opinions on the origin and genetic types of oil and gas in this area due to the complex tectonic setting.In this paper,we studied the origin and genetic types of oil and gas through a detailed analysis of the composition and carbon isotope data of condensate oil and gas in different intervals of the Cambrian in ZS1,ZS1C and ZS5 wells and the geochemical characteristics of the Cambrian-Lower Ordovician and Middle-Upper Ordovician source rocks.The results indicate that the Cambrian gas in the Tazhong uplift is typical cracking gas of sapropelic kerogen.Gas in the Xiaoerbulake Formation is typical over-mature dry gas with a drying coefficient of higher than 0.98 and N₂ content of 2.5%~4.0%.The carbon isotopes of group composition and individual n-alkanes of condensate in the Xiaoerbulake Formation are relatively heavy.The carbon isotope of C₉-C₂₀ n-alkane are -28.8‰~-26.3‰.These geochemistry characteristics indicate that the condensate oil and gas in the Xiaoerbulake Formation originated from the Cambrian-Lower Ordovician source rocks.While the natural gas in the Awatage and Wusonggeer Formations is low-mature wet gas with a drying coefficient of 0.63~0.78 and N₂ content of 0.2%~0.8%.The carbon isotope of group composition and individual n-alkanes of condensate in the Awatage and Wusonggeer Formations are relatively light.The carbon isotopes of C₉-C₂₃ n-alkane are -37.25‰~-32.56‰.These geochemistry characteristics indicate that the condensate oil and gas in the Awatage and Wusonggeer Formations originated from the Middle-Upper Ordovician source rocks.

Distribution pattern of tricyclic terpanes and its influencing factors in the Permian source rocks from Mahu Depression in the Junggar Basin

Chen Zhelong, Liu Guangdi, Wei Yanzhao, Gao Gang, Ren Jiangling, Yang Fan, Ma Wanyun

2017, 38(2):  311-322.  doi:10.11743/ogg20170211

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Biomarkers extracted from the crude oil and source rock samples obtained from the northwestern margin of Junggar Basin are characterized by high abundance of tricyclic terpanes (TTs).The distribution pattern of TTs has been used to distinguish oil families and to conduct oil-source correlations.Comprehensive geochemical analyses of source rock samples reveal that different distribution patterns of TTs correspond to different sets of source rocks,i.e.the Fengcheng Formation(P₁f) features in "Going Up" of C₂₀,C₂₁ and C₂₃ TTs,with higher amounts of C₂₄ and C₂₅ TTs for mudstones in comparison with carbonate rocks;the Lower Wuerhe Formation(P₂w)and the Jiamuhe Formation(P₁j)are characterized by "Going Down" of C₂₀,C₂₁ and C₂₃ TTs.The influences of sedimentary environment,kerogen type,maturity and hydrocarbon expulsion on distribution of TTs were studied through microscopic observation of thin sections and hydrous pyrolysis simulation.We concluded that the TTs distribution patterns of P₁f and P₂w are mainly controlled by sedimentary environment and kerogen type.The organic matters of the P₁f source rocks were mainly derived from autochthonous algae or bacteria and were deposited in an evaporative reducing salt lake,while allochthonous organic matters were relatively abundant in the P₂w and were deposited in a semi-reducing fresh lacustrine environment.The P₁j source rocks are currently over-mature and have experienced intense carbonization.Burial thermal evolution has limited impacts on the distribution patterns of TTs during mature and high-mature stage,but can result in the increase of low carbon number terpanes during over-mature stage.Hydrocarbon expulsion has limited influences on the TTs distribution pattern.

Diagenesis and its influence on coarse clastic reservoirs in the Baikouquan Formation of western slope of the Mahu Depression,Junngar Basin

Jin Jun, Kang Xun, Hu Wenxuan, Xiang Baoli, Wang Jian, Cao Jian

2017, 38(2):  323-333,406.  doi:10.11743/ogg20170212

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Coarse clastic reservoirs,one of the most commonly seen reservoir types in the world,feature in strong heterogeneity and are highly sensitive to diagenesis process.One of the key research areas for the reservoir is the study of the impact of diagenesis upon its storage capacity.The coarse clastic reservoirs in the slope delta fan of the Lower Triassic Bai-kouquan Formation (T₁b) in Aihu oilfield (an exploration breakthrough was made recently) in western slope of the Mahu Depression in Juggar Basin were chosen to study the diagenesis types and their impact upon storage capacity of the reservoirs.The result indicates that there were mainly four types of diagenese process in the area:mechanical compaction,mineral replacement (albitization of detrital feldspar and illitization of smectite),dissolution (K-feldspar and calcite,etc.) and cementation (calcite,kaolinite and small amounts of chlorite).These processes had significant influence upon the quality of the reservoirs.Compaction undermined the primary intraparticle pores and soured physical properties of the layers.Mineral replacement had only limited impact over the properties; but relatively speaking,dissolution of minerals like potash feldspar and etc.facilitated by hydrocarbon-bearing fluids migrating along faults greatly increased storage capacity of the layers by forming secondary pore zones in coarse clastic rocks with fair primary physical properties such as underwater channel sands of fan delta fronts and granular flow deposits.Cementation was destructive to the preservation of pores formed during the middle and late diagenetic stages,and the local enrichment of kaolinite and calcite caused the formation of low-permeability layers.The understanding was confirmed by various reservoir properties in different members of the Formation:high-quality reservoirs were found in T₁b₁ near faults connecting source rocks,high-to good-quality reservoirs were found in T₁b₂,at an updip position adjacent to the faults connecting source rocks,but almost no reservoirs were found in T₁b₃.

Sealing capacity of the Tugulu Group and its significance for hydrocarbon accumulation in the lower play in the southern Junggar Basin,northwest China

Tian Xiaoru, Zhuo Qingong, Zhang Jian, Hu Hanwen, Guo Zhaojie

2017, 38(2):  334-344.  doi:10.11743/ogg20170213

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Through the evaluation of macroscopic sealing parameters(lithology,mudstone accumulative thickness and single mudstone thickness) and microscopic sealing parameters(permeability and displacement pressure),this paper gives a comprehensive analysis of the sealing capacity of the Tugulu Group in the southern margin of Junggar Basin.The results show that the Hutubi Formation is the main cap and comprises interbedded mudstone,silt mudstone and pelitic siltstone.The shale stratum ratio,average mudstone accumulative thickness and maximum single mudstone thickness are 80%-95%,337 m and 138 m respectively.Permeability and displacement pressure of the Tugulu Group mudstone range from 0.000 001 84×10^-3 μm² to 0.000 24×10^-3 μm² and 4.72 MPa to 44.85 MPa respectively,suggesting type Ⅰ to Ⅱ sealing capacity based on the criteria for cap rock evaluation.By restoring the dynamic evolution of displacement pressure of cap rocks,the Tugulu Group is capable of sealing oil and late gas generated by the Jurassic source rock,because the timing of sealing capacity forming is well in tune with the timing of hydrocarbon generation and expulsion.Uplifting and thrust faults evolved during the Hemalaya Movement did not destroy the sealing capacity of the Tugulu Group.Through these comprehensive analysis,we conclude that cap rocks of the Tugulu Group maintains the capacity of sealing large to middle gas field.

Discovery of seismites in the first member of the Kelaza Formation in central Taibei Sag of Tuha Basin and its geological significance

Tang Wenbin, Xu Shenglin, Chen Hongde, Chen Anqing, Liang Jie, Xiao Dongsheng

2017, 38(2):  345-354.  doi:10.11743/ogg20170214

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Tuha Basin is a polycyclic composite basin with dual base and foreland structures.The Yanshan movement du-ring the Late Jurassic controlled and affected the sedimentation of the Kelaza Formation in the basin.Based on observations of cores from more than 20 wells drilled in the Formation,we recognized for the first time some deformed structures of soft sediments originated from seismicity,including sandstone veins (dikes),liquefied breccias,liquefied crinkling deformation,ball-pillow shaped structures,liquefied homogeneous layers and load structures of liquefaction origin;lamellar crinkling deformation,mound-trough structures,annular layers and vibration collapse structures of hydroplastic deformation origin;and seismite breccias,echelonment micro-faults and V-shaped ground fractures of brittle deformation origin.A vertical succession of seismites was established based on the deformation features of seismites recognized in the first member of the Formation.It indicates frequent and intensive seismic activities during the formation of the member.By comparing the spatial and temporal distributions of seismites,we found that the intensity of seismic activities weakened along the Shengbei area at the northern foreland to the Honglian area at the southern margin of the basin,indicating the Bogeda orogenic belt being the earthquake source.A Dickinson triangle chart also revealed that the belt was the provenance of the sandstone in the first member.The widely-distributed seismites (a special sedimentary response between basins and mountains) in the member also indicated that the Bogeda Mountain was strongly uplifted during the sedimentation of the first member in the Later Jurassic due to the second phase of the Yanshan movement.

Geochemical characteristics and petroleum geologic significance of natural gas in the north margin of the Qaidam Basin

Tian Jixian, Li Jian, Zeng Xu, Guo Zeqing, Zhou Fei, Wang Bo, Wang Ke

2017, 38(2):  355-362.  doi:10.11743/ogg20170215

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In order to understand the generation and distribution of natural gas in the northern margin of the Qaidam Basin,the geochemical characteristics of natural gas are analysed with both natural gas composition and carbon isotope.The results show that the natural gas is dominated by methane,but the content of heavy hydrocarbons is relatively high.There are obvious differences in natural gas composition in different structural belts.Research on carbon isotopes indicated that the δ¹³C₁ and δ¹³C₂ values are -36.4‰~-19.3‰ and -27.4‰~-19.82‰,respectively.The identification of na-tural gas shows that the main type of natural gas in this area is coal-generated gas and is derived from Jurassic source rocks.Carbon isotopic distribution of the northern margin of the Qaidam Basin is characterized by positive sequence,and there are carbon isotope reversal phenomena in some areas due to different maturity,different mixture types of sources and the gas generation from source rocks in the high-mature stage.The distribution of oil and gas reserves in the northern margin of the Qaidam Basin is characterized by spatial zonation from the outer edges to the centre of the basin and is controlled by the source rock maturity.The natural gas is located in mature and high maturity areas.Future promising areas for exploration have been put forward,which include Lenghu NO.6 and NO.7,Eboliang-Hulushan tectonic belt and the foreland of the Altun Mountains.

Genetic mechanism and hydrocarbon accumulation of polygonal fault system in Jinghai Sag of the Pearl River Mouth Basin

Jiang Ning, He Min, Liu Jun, Xue Huaiyan, Zheng Jinyun, Zhang Qinglin

2017, 38(2):  363-370.  doi:10.11743/ogg20170216

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Small normal faults are well developed in the Miocene in Jinghai Sag of the Pearl River Mouth Basin and they are characterized by close spacing,highly variable strike,limited trace length,small throw,steep dip,crosscutting and polygonal geometry on plane view.Comprehensive study reveals that they are non-tectonic origin.A polygonal fault system (PFS) consists of small normal faults formed due to periodical pressure release induced by shallow overpressure.The overpressure is mainly caused by differential compaction,aquathermal pressuring and chemically driven volumetric contraction (syneresis) due to rapid sediment deposition.During the Eocene and Oligocene,Jinghai Sag experienced lithospheric stretching,followed by thermal subsidence in the Early and Middle Miocene,with the deposition environment evolved from lacustrine-neritic facies to bathyal-abyssal facies.The poor development of growth faults which play a key role in connecting the source rock of lacustrine-neritic facies and reservoir of bathyal-abyssal facies resulted in the absence of vertical hydrocarbon migration pathways.Polygonal faults are highly developed in the Miocene Zhujiang and Hanjiang Formations in Jinghai Sag and can act as hydrocarbon migration pathways,thus are highly significant for hydrocarbon accumulation during post-rift thermal subsidence.

A study on forming mechanisms of CO₂-rich reservoirs in Jupiter oilfield,Santos Basin,Brazil

Ma Anlai, Sun Hongjun, Zheng Lei, Li Yuzhan, Xu Hai, Zhang Zhongming

2017, 38(2):  371-378.  doi:10.11743/ogg20170217

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The high CO₂ content and various fluid components in oil and gas columns of reservoirs of Jupiter oilfield in the Santos Basin is the main reason why there has not been a consensus on the phase and forming mechanisms of the reservoirs yet.Based on a four-parameter-block diagram,a ternary diagram of fluid component,and a multiple parameter method with φ₁,Z₁ and Z₂ values,we tried to understand the phase of reservoirs in Jupiter Oilfield.The result shows that the reservoirs are condensate reservoirs with oil rings.The condensate was found to share similar molecular characteristics with that of the crude oil in the reservoirs:Pr/Ph value between 1.58 and 1.88,C₂₆/C₂₅ tricyclic terpane value ranging from 1.15 to 1.22,high abundance of C₂₇ sterane relative to C₂₉ sterane,hopane to sterane ratio value greater than 4 and TPP value greater than 0.5,and carbon isotope value of whole oil at -25‰.All these geochemical parameters indicate that both the condensate and the oil be originated from the Cretaceous Upper Barremian-Lower Aptian lacustrine source rocks.Both the condensate and the crude oil have similar maturity and correspond to peak oil generation stage.The maturity of alkane gas,sourced from the Upper Barremian-Lower Aptian lacustrine source rocks,corresponds to the peak oil generation-early condensate forming stage.The CO₂ is volcano-mantle type and its later influx transformed the reservoirs that formed at the early stage through evaporative fractionation,resulting in the present condensate reservoirs with oil rings.The evaporative fractionation is supported by geochemical parameters.The influx of inorganic CO₂ added some new content to the theory of the evaporative fractionation.

Study on chemical flooding relative permeability curves based on the extended capillary number theory

Wang Youqi, Yu Hongmin, Nie Jun, Xu Guanli, Lu Gang

2017, 38(2):  379-384.  doi:10.11743/ogg20170218

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In order to reflect the effect of wettability and pore structure on seepage characteristics of surfactant flooding in low permeable reservoir,an extended capillary number (ECN) theoretical model is put forward,which contains wettability and pore structure on the basis of traditional capillary number (TCN) theory and combined physical simulation and mathematical treatment methods.ECN and residual oil saturation (ROS) values are collected in the different low permeability cores through experiments,and cross correlation chart between ECN and ROS is drawn.A nonlinear processing method of the relative permeability curve (RPC) is established with ECN,and reservoir engineering application is conducted.The results show that ECN theory can embody the wettability and pore structure in low permeability reservoirs,and the chemical flooding EOR needs combined action of interfacial tension reduction and reservoir wettability change in low permeability reservoirs.There is a nonlinear,negative correlation between ECN and ROS,and ROS will decrease drastically only when the increasing ECN exceeds a critical value.The nonlinear characterization method has a good agreement with the experimental results.Finally,the new method could reflect the effect of wettability and displacement characteristics of surfactant flooding,and thus provides a new tool for reservoir engineering and numerical simulation of chemical flooding in low permeability reservoirs.

Electric simulation experiment procedure for predicting productivity of multi-stage fractured horizontal wells

Liu Changyin, Li Fengxia, Sun Zhiyu, Huang Zhiwen

2017, 38(2):  385-390.  doi:10.11743/ogg20170219

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An electric simulation experiment procedure for predicting productivity of multi-stage fractured horizontal wells was proposed in the paper.Firstly,we developed a 3D electric field simulator based on the actual situation of reservoirs after a multi-stage fracturing in a horizontal well.Secondly,we set up parameters for an electrolyte and an electrolytic cell based on sandbody distributions,flow boundary types of reservoirs,well bore trajectory in sandbodies,permeability and thickness of reservoirs and etc.We then input parameters of simulated wellbores and fractures in accordance to the length of a lateral,height and length of fractures,numbers of stages,numbers of fractures,spacing between fractures and so on.Finally,we gathered electronic signals to predict the productivity.The procedure was applied to a fluvial sandbody to optimize geometry and placement as well as numbers and spacing of fractures in laterals based on comparative simulation experiments in reservoirs of different thickness.The results provided technological support to field operation.The procedure with its accurate simulation of the influence of fracturing parameters upon productivity of wells may be used as gui-dance for the design of horizontal well fracturing and completion.

A study on mechanisms and numerical simulation of secondary foamy oil by gas injection in heavy oil reservoirs

Sun Xiaofei, Zhang Yanyu, Duan Xuewei, Zhao Chunyan, Li Xingmin

2017, 38(2):  391-399.  doi:10.11743/ogg20170220

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The paper attempted to propose a new method of improving later stage performance of cold production from heavy oil reservoirs in respect of forming secondary foamy oil through gas injection.A foamy oil unconventional swelling experiment was designed and carried out to verify the feasibility of generating secondary foamy oil by gas injection and reveal its mechanism of enhancing oil recovery.And then based on the experiment,a sandpack experiment was performed to study the formation of foamy oil during natural gas huffs and puffs,and continuous and intermittent gas flooding processes.The possibility of establishing a numerical model with gas injection characteristics of foamy oil reservoirs incorporated was explored so as to serve for simulating the mechanism of foamy oil formation and later evaluation of EOR results of secondary foamy oil with different ways of gas injection in fields.The results showed that gas injection formed secondary foamy oil with better EOR results in that the oil facilitated the volume expansion,viscosity reduction and light component increase in heavy crude.Compared with natural depletion,the natural gas huff and puff process,with a rich foamy oil fluid generated,was 7.24% higher in terms of recovery percent of reserves;but the continuous and intermittent gas injection processes yielded negative result as they weakened or totally destroyed the foamy oil.Numerical modeling also indicated that the natural gas huff and puff performed better with a cumulative oil production increased by 14.7% after 8 rounds of huff and puff processes in 12 wells;while the continuous and intermittent gas injections as well as edge gas injection were unable to generate secondary foamy oil fluids because of massive gas channeling.

A novel method to interpret fracture parameters of multistage fractured horizontal well in reservoirs with micro-fractures

Tian Shubao, Lei Gang, Yang Limin, Rao Peiyu

2017, 38(2):  400-406.  doi:10.11743/ogg20170221

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Because of the disadvantages of low accuracy,high cost and inconvenience for field application of current fracture monitoring methods,it is necessary to develop a new approach to monitor the parameters of hydraulic fractures in reservoirs.Based on the theory of tri-linear fluid flow in porous media,a novel seepage model was developed for multistage-fractured horizontal wells in reservoirs with micro-fracture.Laplace transform was performed to derive well production rate formulas for different typical flowing periods.The field daily production data were used to analyze the typical characteristics of diffe-rent segments of the production curve and to solve the model for fracture parameters including hydraulic fracture length,hydraulic fracture flow conductivity and permeability of natural fracture in the reservoir.The model was validated with the microseismic monitoring data of 3 horizontal wells in the field.The results show that the relative error of the hydraulic fracture flow conductivity between the prediction result and the real value is 1.9%,and the hydraulic fractures lengths from model calculation are in good agreement with the micro seismic monitoring results.With the advantages of conve-nience,rapid interpretation,high accuracy and good adaptability,this method proposed in the paper is helpful to the evalu-ation and design of horizontal well multistage-fracturing stimulation in reservoirs with well developed micro-fractures.

New method for reservoir petrophysical modeling of submarine fan channels:A case from Oilfield A in West Africa

Zhang Jiajia, Wu Shenghe, Fan Ting'en, Fan Hongjun, Lin Peng, Jiang Shining

2017, 38(2):  407-418.  doi:10.11743/ogg20170222

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Submarine fan channels,mainly deep-water gravity flow deposits,are generally characterized by diverse lithofacies types and poor correlation of porosity-permeability due to the complicated genetic mechanisms,which brings significant challenges to reservoir petrophysical modeling.Taking oilfield A in West Africa as an example,this paper proposes a new method for reservoir petrophyscial modeling of the submarine fan channels based on a comprehensive analysis of re-servoir features and their correlation with seismic attributes.This method features in "multi-facies control and multi-attributes collaboration".In contrast with the traditional facies-controlled modeling in which porosity modeling is simply controlled by sedimentary facies,this method first builds a reservoir facies model under the control of facies architecture model and then build porosity model under the control of the reservoir facies model.Given that the deep-water channel sandbodies show poor porosity-permeability correlation as a whole but good porosity-permeability correlation for different lithofacies,this method further supplements "lithofacies-control" in permeability modeling.Besides,this method also adds seismic-collaboration in the reservoir facies modeling in comparison with the common collaborative modeling.