Table of Content

08 June 2016, Volume 37 Issue 3

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Types and characteristics of eogenetic karst in the Yingshan Formation in northwestern Tazhong area,Tarim Basin

Zhang Heng, Cai Zhongxian, Qi Lixin, Yun Lu

2016, 37(3):  291-303.  doi:10.11743/ogg20160301

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It is recognized that the Yingshan Formation was in eogenetic stage both in depositional and exposure period according to the tectonic evolution history in Tazhong area.Based on a large amount of image logging,cores,thin sections,geochemical data and 2D & 3D seismic data in combination with cathode luminescence,scanning electronic microscope and seismic attributes extraction,we identified two types of eogenetic karst in the Yingshan Fm.in northwestern Tazhong area,namely mixing water karst and meteoric karst,discussed their formation characteristics and built karstification models.The following results were obtained.①The mixing water karst was formed by fabric-selective dissolution and controlled by high-energy sedimentary facies in coastal regions and occurs mainly in Well Shun7 in northern slope break zone;②The meteoric karst was produced by non-fabric-selective dissolution,and is universal in areal distribution.Karst reservoirs are dominated by fractured reservoirs and fractured-vuggy reservoirs.The karst is incomplete in vertical architecture and the reservoirs are insignificant in differential characteristics in respect of paleogeomorphology and are controlled by the NWW-trending fault system.The karstification mode is “fissure-seepage” type in an open system under the control of low relief paleogeomorphology.

Restoration of multistage paleogeomorphology during Caledonian Period and paleokarst cavernous reservoir prediction in Halahatang area, northern Tarim Basin

Dan Yong, Zou Hao, Liang Bin, Zhang Qingyu, Cao Jianwen, Li Jingrui, Hao Yanzhen

2016, 37(3):  304-312.  doi:10.11743/ogg20160302

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This paper studied the controlling mechanism of multi-stage Caledonian karstification on the development of the Ordovician carbonate reservoirs through reconstruction of the Palaeogeomorphology with different methods in Halahatang area, northern Tarim Basin.It shows that the karst geomorphology is dominated by mound-cluster depression and mound-cluster valley during the Lianglitage period.Several deep incised-rivers are developed from north to south and seismic sections reveal that they often cut through the Yijianfang Formation.The pre-Silurian paleokarst can be divided into three zones from north to south,namely buried hill karst zone, shallow coverage karst zone and thick coverage karst zone.The terrain is high in north and low in south.The northern buried hill karst zone is dominated by mini-karst physiognomy without deep incised-rivers.In contrast,the southern thick coverage karst zone is in clastic rock mountain landform where a drainage system flowing from north to south and finally into the karst lake near the pinchout line of clastic rock.Based on the statistics of logging,drilling and cores,the cavernous reservoirs in the shallow coverage karst zone mainly occur in two intervals.One is 0 to 30 m below the top Yijianfang Formation (corresponding to the horizon of the Yijianfang Formation) and the other is 50 to 110 m below the top Yijianfang Formation (corresponding to the horizon of the Yingshan Formation).In contrast,the cavernous reservoirs in the thick coverage karst zone mainly occur in an interval of 0 to 40 m below the top Yijianfang Formation without obvious zonation.A comprehensive analyses of the geomorphology,ancient drainage system,tectonic fault and other factors shows development of the cavernous reservoirs in the lower part of the shallow coverage zone and thick coverage zone was mainly controlled by paleokarstification in runoff zone during Lianglitage period when the deeply incised-rivers in the southern part acted as the runoff drainage points controling the size and direction of cavernous reservoirs.In contrast,the development of cavernous reservoirs in the upper part of the shallow coverage zone was mainly controlled by paleokarstification in runoff zone during the pre-Silurian period when the karst lakes were karst runoff drainage areas.

Structure and reservoir-controlling of top Carboniferous weathering crust in Chepaizi area, Junggar Basin

Song Mingshui, Zhao Leqiang, Wu Chunwen, Qin Feng, Zeng Zhiping

2016, 37(3):  313-321.  doi:10.11743/ogg20160303

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Based on drilling data and integrated geological research,structural characteristics and main controlling factors of the weathering crust on top Carboniferous in Chepaizi area of the Junggar Basin were systematically analyzed.The development model of weathering crust structure and its reservoir-controlling was summarized.Results show that the weathering crust features in vertically layered structure,consisting of weathered clay layer,hydrolysis layer and weathering leached layer in top-down order.The weathered clay layer is thin and has limited areal distribution and poor physical property.The hydrolysis layer is thicker and has poor physical property but wide distribution in most areas.The weathering leached layer is very thick and has better physical property and extensive distribute in the whole area.The structure of the weathering crust is mainly controlled by facies of mother rocks,hiatus time and paleotopography.The weathered clay and hydrolysis layer serve as cap rocks for petroleum reservoir,while the weathering leached layer has favorable physical property and thus can serve as lateral migration pathway on top of the Carboniferous.Under the condition of the hydrolysis layer or weathered clay layer,double migration path model can be built which includes carpet sand and wea-thering crust.Otherwise,there would be one migration path with oil and gas channeling or irrigating.Under the control of weathering crust structure,there developed three types of reservoirs including weathered crust,carpet tip and composite lithology in the Carboniferous.

Three-stage strike-slip fault systems at northwestern margin of Junggar Basin and their implications for hydrocarbon exploration

Chen Shi, Guo Zhaojie, Qi Jiafu, Xing Xiangrong

2016, 37(3):  322-331.  doi:10.11743/ogg20160304

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The Hongqian-Chepaizi,Karamay-Baikouquan,and Wuerhe-Xiazijiefaultzones faulted zones,developed at the northwestern margin of the Junggar Basin,are considered to be key controls on the development of hydrocarbon reservoirs in the area.However,the timing and span of the fault zones' evolution,and their characteristics are still under intensive debate.Our purpose here is to determine the structure attributes of the northwestern margin of Junggar Basin based on analysis of regional tectonic setting as well as previous studies.The result shows that West Junggar is dominated by NE-trending strike-slip fault systems caused by the Paleozoic-Cenozoic tectonic evolution of the basin.Three main stages of NE-trending strike-slip fault systems have been distinguished.The first stage is the Late Carboniferous sinistral strike slip fault belt that resulted in the emplacement of the Baijiantan and Darbut ophiolitic belts.The following second stage is the dextral strike-slip fault system that was expressed by the development of the Late Permian-Mid-late Triassic Karamay-Baikouquan and Wuerhe-Xiazijie dextral strike-slip fault belts.These two fault belts were resulted from the Late Permian-Triassic counterclockwise rotation of the Junggar Plate and the West Junggar relative to the western part of the Chingiz Range.The faulted noses,blocks and en echelon anticlines derived from the relevant thrust faulting and folding may account for the development of main structural traps in the West Junggar.The third stage is characterized by the development of the Cenozoic Darbut sinistral strike-slip fault,resulting in limited deformation confined in the north margin of the Basin.In field analyses,this younger imprint shall be distinguished from the Mesozoic strike-slip faults.

Sedimentary characteristics of braided river delta of the lower member of the Lower Ganchaigou Formation in southwestern Qaidam Basin

Tan Xianfeng, Xia Minquan, Zhang Qingxue, Wang Jia, Huang Jianhong, Ran Tian

2016, 37(3):  332-340.  doi:10.11743/ogg20160305

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A braided river delta deposited at the lower member of the Lower Ganchaigou Formation in the Kunbei step-fault zone of southwestern Qaidam basin is considered to be of great importance to the study of oil and gas accumulation in the region.Analyses based on drilling core,logging and seismic data,as well as grain size statistics,were employed to perform a detailed study on the sedimentary characteristics of the delta.Three subfacies were recognized in the delta:braided-river delta plain,braided-river delta front and prodelta.The plain subfacies can be further divided into two micro-facies:braided channels and flood plain.The front subfacies can be subdivided into five micro-facies:under water distributary channel,mouth bar/distal bar,sheet sand and under water distributary bay.Vertically,the delta evolved successively from braided river delta plain,braided delta front to shore-shallow lake. The plain facies experienced superimposition of multiple channels,while the front facies had only a weak influence over the channels.Horizontally,it was controlled by two major provenances and developed two main channels with horizontal heterogeneity.The syngenetic faults were consi-dered as the major controlling factors upon the development of the delta,while the provenance constraints were thought to have affected the distribution and composition of the delta sandbodies and the paleogeomorphology helped forming the present landform of the delta.A sedimentary model was then established for the delta based on comprehensive analyses of all geological factors.

Characterization of pores and fracture networks in organic-rich shale and tight sandstone of the Chang-7 member, Triassic Yanchang Formation, Ordos Basin

Er Chuang, Zhao Jingzhou, Yao Jingli, Ye Xiaochuang, Wu Weitao, Bai Yubin, Deng Xiuqin, Sun Bo

2016, 37(3):  341-353.  doi:10.11743/ogg20160306

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Chang-7 member of the Triassic Yanchang Formation is rich in oil and composed of organic-rich shale and tight sandstone.The shale serves both as source rock to nearby tight sandstone and as reservoirs.An improved appreciation of pores and fracture networks in the shale and tight sandstone reservoirs is of great significance to understand storage space characteristics and migration mechanisms of shale oil and tight oil.Through qualitative description and quantitative chara-cterization,pore types and pore size of the organic-rich shale and tight sandstone were studied by comprehensively utilizing methods including core description,field emission scanning electronic microscope,laser scanning confocal microscopy,nuclear magnetic resonance,high pressure Hg injection,and low-temperature thermal adsorption.Organic-rich shale contains intragranular pores,intergranular pores and organic pores,with most pore size less than 50nm.It also contains micro-fractures.Horizontal,low angle,high angle and vertical fractures can all be observed in the shale.The tight sandstone contains residual primary intergranular pores,inter-crystals pores and secondary pores (the major type).Pore size is mostly larger than 2 μm and pore-throat size is less than 73.5 nm.However,pore-throats that contribute the most to improving permeability are those ranging between 73.5 nm and 735 nm.Microfractures and high angle fractures can also be spotted in the tight sandstone.Forming and evolution of pores both in shale and tight sandstone are suggested to be controlled by sedimentation and diagenesis.Migration and charging of diagenetic fluids and hydrocarbon fluids worked toge-ther to forge organic-rich shale and tight sandstone into an organic whole.The study also distinguishes three kinds of pore and fracture networks and pathway of oil migration in shale and tight sandstone of the Chang-7 member:①nonameter-micrometer pores- fracture networks in organic-rich shale (acting as storage space and migration pathway within source rocks);②nanometer pore throat-micrometer pores-fracture networks in tight sandstones (acting as storage space of tight oil);③differential pore throat structure-microfracture-fracture networks between shale and tight sandstone(acting as migration pathway for oil from source rocks to outside reservoirs).

Discussion on several geochemical issues of gases in Feixianguan-Changxing Formations in northeastern Sichuan Basin,China

Zhu Yangming, Sun Linting, Hao Fang, Zou Huayao, Guo Tonglou

2016, 37(3):  354-362.  doi:10.11743/ogg20160307

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Molecular and isotopic composition data of over hundred gas samples were combined with analytical data of source and reservoir rocks to deal with geochemical uncertainties of gases in the Feixianguan-Changxing Formations in Puguang,Yuanba and Tongnanba regions in northeastern Sichuan Basin.Discussion was focused on differentiation of cracking gases from oil and source rocks,causation of carbon isotope reversals in hydrocarbon gases and genetic relationship between CO₂ and H₂S.The results show that oil cracking gases from vuggy reservoirs abundant in solid bitumen in Puguang and Yuanba regions are relatively enriched in propane and have low ln(C₂/C₃) value (<3.0) as a diagnostic signature.In contrast,the source rock cracking gases (sourced from kerogen and bitumen cracking) from fractured reservoirs in Tongnanba region,exhibit a co-varying ln(C₁/C₂) and ln(C₂/C₃),and display higher values (>3.0) of ln(C₂/C₃),distinguishing from typical oil cracking gas.Isotope reversals,resulted possibly from various factors,appear extensively in hydrocarbon gases from the Formations.For the paraffin gas from the Feixianguan Fm of Hebachang gas field in Tongnanba region,the isotope reversal can be attributed to a mixture of post-mature dry gas generated from the Upper Permian Longtan source rocks and gas with slightly higher wetness coming from the Silurian source.Two non-hydrocarbon gas composition modes,namely high H₂S content-low CO₂ content and low H₂S content-high CO₂ content,are recognized in the gases experienced TSR from the Feixianguan-Changxing reservoirs.The relative proportions of these two non-hydrocarbon gases may be associated with overall interaction system of reservoir fluids and rocks.CO₂ with somewhat negative carbon isotope is possibly resulted from hydrocarbon oxidizing in high H₂S reservoirs,whereas,isotopically heavier CO₂ could be mainly formed by chemical degradation of carbonate when it presents in abnormally high amount.

Petroleum accumulation systems and distribution of medium to large marine carbonate fields

Wang Dapeng, Lu Hongmei, Chen Xiaoliang, Tao Chongzhi, Meng Xiangjun, Niu Xinjie, Bai Guoping

2016, 37(3):  363-371.  doi:10.11743/ogg20160308

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A classification of petroleum accumulation systems (PAS) of marine carbonate fields was attempted by using the latest data of 199 medium to large marine carbonate fields from 53 petroliferous basins around the world and a “source-element” classification scheme.The result shows that PAS of the fields can be categorized into six types: one source-one element,one source-two elements,one source-three elements,two sources-two elements,two sources-three elements and three sources-three elements.The distribution patterns and characteristics of petroleum reserves for each of the 6 types of PAS were investigated and the dominate types with high hydrocarbon richness in marine carbonate petroliferous basins were identified,and their controls on hydrocarbon enrichment were revealed.Statistical analytical results show that one source-three elements PAS not only hosts the largest share of petroleum reserves but also occurs the most widely.It is followed by one source -two elements and two sources-three elements PAS.For other types of PAS,both the reserves and the numbers of occurrence are relatively small.One source-two element PAS is the most promising among all the types but it requires more favorable later preserving conditions.One-source-one element PAS presents itself mostly as unconventional reservoirs but is rarely found in marine carbonate rocks.

Oligocene diabase of Eastern Sag in Liaohe Basin,NE China: characteristics,identification and hydrocarbon accumulation

Sun Ang, Huang Yulong, Li Jun, Feng Yuhui, Wang Jianfei, Wang Pujun

2016, 37(3):  372-380.  doi:10.11743/ogg20160309

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Relationships between geology and logging/seismic responses were established for the study of diabase from Eastern Sag in Liaohe Basin based on 3 555 m logging intervals and core & cuttings of diabase from 41 wells and 560 km² 3D seismic data and observation of 86 thin sections acquired in the area.We investigated the lithology,lithofacies and logging identification features of the diabase,performed well data constraining-seismic mapping,and explored the spatial distribution and hydrocarbon accumulation regularity of the rock.Diabase has wholly crystalline porphyric-like texture with phenocrysts of plagioclase and clinopyroxene.The effective reservoir space in the rocks is mainly secondary dissolved pores and fractures.Diabase can be divided into two sub-facies:centrality and border.High-quality reservoirs are inclined to be distributed in border sub-facies.The rocks display themselves as smooth or slight sawtooth logs with high resistivity and low interval transit time,and seismic reflectance signatures of high amplitude,middle- to low-frequency and fine continuity of events.Vertically,the diabase was shown to be mainly distributed in the first and third members of the Shahejie Formation.The rock shows two kinds of original invasion occurrence,namely layer-parallel and translayer invasion and two types of later transformation,i.e.saucer-shaped and fault-block transformation.Distribution of the diabase was mainly controlled by the main strike-slip fault (Jiazhangsi fault and Jiadong fault) of two intrusive manners associated with faulting of unilateral and bilateral invasion.The invasion distance were measured to be 1 375 m to 5 625 m and averaged at 2 572 m and thickness of the intrusions was 49 m to 165 m (averaged 112 m).Generally,larger volume of diabase means larger thickness of overlying strata.The intrusive age of diabase is dated back to late Dongying period as the result of volcanic-hydrothermal effects.Secondary pores caused by fluid-rock interaction is suggested to be a critical factor for the formation of diabase reservoirs and “interface reservoirs” is proposed to be the main reservoiring pattern of the rock.

Hydrocarbon accumulation rules and exploration potential in the North Ustyurt Basin

Yu Yixin, Yin Jinyin, Zheng Junzhang, Li Feng, Xu Xiaolong, Wu Hang, Yu Xiao

2016, 37(3):  381-386.  doi:10.11743/ogg20160310

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Based on the integrated analysis of key geological features and distribution of oil and gas fields in the North Ustyurt Basin,central Asia,this paper focuses mainly on hydrocarbon accumulation rules,their controlling factors,and exploration potential in the basin.Because hydrocarbons are originated from multiple source rocks and depositional settings of source rocks vary,hydrocarbon distribution in the North Ustyurt Basin is characterized by‘oil accumulations in the west and gas in the east’.Oil and gas accumulated respectively in the middle Jurassic and Eocene reservoirs with high-quality.Favorable migration paths have played a key role in hydrocarbon accumulation in the North Buzachi Uplift,where the most favorable traps in the Mesozoic are the elongated faulted anticlinal structures in the northern part and top of the Uplift.Exploration potential in the Paleozoic Bashkirian and Asselian carbonate reservoirs also cannot be ignored.In the middle and eastern part of the basin,the Jurassic and Eocene reservoirs are of limited potential,but the Lower Cretaceous in the northeastern region may become a new exploration target.In addition,it is possible to discover hydrocarbon in the Carboniferous Visean reservoirs in the southeastern part of the Basin.

Mechanism of faults acting on in-situ stress field direction

Liu Zhongchun, Lyu Xinrui, Li Yukun, Zhang Hui

2016, 37(3):  387-393.  doi:10.11743/ogg20160311

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Direction of in-situ stress near a fault is significantly different with that far away from the fault.Experimental approaches and finite element simulation method were previously used to study the patterns of faults acting on in-situ stress field direction,but these patterns were never explained in respect of mechanical mechanism.The regularity of elasticity mechanical mechanism were reveals by using the analytical solution of elliptic orifice problems based on study of the change patterns of the maximum horizontal principal stress direction near a single fault.And a block was taken as an example to study the change of the direction of maximum principal stress along fault strike in areas with multiple faults.The results show that the maximum horizontal principal stress deviates to the fault strike at the ends of faults.The phenomenon can be well explained with the aid of orifice problem of elastic mechanics analytical solution.The calculation results of in-situ stress in one unit of Tahe oilfield also verify the rule.

Potential reserve growth assessment of known oilfields: A case study from Zagros Basin

Fan Yumei, Zhang Jilong, Gao Xian, Li Guangchao, Song Lina

2016, 37(3):  394-398.  doi:10.11743/ogg20160312

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Reserve growth assessment of known oil fields is an important task in resources evaluation.The reserve growth forecast models differ from region to region due to different geological and development conditions.By using modified Arrington method,this paper analyzed the recoverable reserve variation with oilfield age,established a mathematical model between cumulative growth factor and oilfield age and forecasted the potential reserve growth in the future.Meanwhile,we studied the actual reserve growth of oilfields with different reserve scales and discovery periods.Results show that the reserve growth model of Zagros Basin follows a power function.The recoverable reserves of the known oilfields in Zagros Basin will increase 20.7% in the next 30 years.The reserve growth rate of Zagros Basin is unstable and stepped in the exploration and development process.Oilfields with recoverable reserves larger than 150 MMb in this region have greater positive growth potential and reserve growth rates of the known oilfields are much larger than that of the newly discovered oilfields in the same period.

Controlling factors and types of shale gas enrichment in the Sichuan Basin

Zhu Tong, Wang Feng, Yu Lingjie, Sun Runxuan

2016, 37(3):  399-407.  doi:10.11743/ogg20160313

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Shale gas in the Sichuan Basin features in multi-domain,multi-layer and multi-types.The main controlling factors for shale gas accumulation are favorable sedimentary facies,thermal maturity and preservation condition.High quality marine shale of deep shelf facies is high in hydrocarbon source quality,reservoir quality and fracturability,thus is the most favorable sedimentary facies.Sequences of carbonate lake slope storm beach facies consist of interbedded shale and limestone.The close combination of shale with high hydrocarbon source quality and limestone with high reservoir quality and high fracturability provides favorable conditions for shale gas accumulation.Shale with moderate thermal maturity(2%-3%) for peak gas generation has the most developed gas-saturated organic pores,thus the best storage capacity.Shale gas content generally increases with increasing buried depth under burial conditions.The adsorbed gas content decreases slowly,while the free gas content increase rapidly.Overpressure zone is favorable to free gas preservation.On this basis,gas shales in the Sichuan Basin can be divided into three layer series and five types.The thick shale of deep shelf facies with ultrahigh pressure within the Late Silurian basin and that with overpressure at the inner edge of the basin are the most favorable for shale gas enrichment.Favorable areas of shale gas in different layer series were predicted according to the criteria of favorable sedimentary facies zones,moderate thermal maturity (R_o=1.3%-3.5%),pressure coefficient over 1.2 and buried depth less than 4 500 m.

Factors influencing mobility of Paleogene shale oil in Dongying Sag, Bohai Bay Basin

Bao Youshu, Zhang Linye, Zhang Jingong, Li Juyuan, Li Zheng

2016, 37(3):  408-414.  doi:10.11743/ogg20160314

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In order to understand the relationship between mobility of the Paleogene shale oil and thermal evolution degree of the shale in Dongying Sag,Bohai Bay Basin,this paper studied three critical geological factors affecting shale oil's recoverability,including the evolution of predominant clay minerals,abnormal fluid pressure,and the evolution of hydrocarbon fluid characteristics.Furthermore,we observed the movable oil existing in fresh shale by using fluorescence microscopy,and measured movable oil quantity by using a physical simulation method.Results show that both mixed-layer illite/smectite and montmorillonite contents decrease continuously with increasing shale burial depth,and reach equilib-rium at about 3 500 m.Therefore,shale below 3 500 m is favorable for fracturing and post-frac maintenance of factures due to the weakening of hydration expansion ability of clay minerals.The continuous overpressure widely developed in shale deeper than 2 800 m provides natural energy for fluid outflow.Shale enters into oil window at a depth over 3 000 m,thus its oil saturation is generally quite high.Oil phase is predominant in shale with depth ranging from 3 000 m to 4 200 m,while condensate gas dominates in shale at a depth larger than 4 300 m.Shale oil viscosity decreases dramatically with increasing burial depth,and reaches a relatively lower value at depth of about 3 500 m,then decreases slightly with increasing depth.Fluorescence microscopy observations and simulation experiments show that movable oil widely exists in shale deeper than 3 000 m,and the ratio of movable oil increases with increasing shale burial depth.Based on a comprehensive analysis of mineral transformation mechanism,fluid pressure,fluid property in shale,and movable oil experiment results,it is concluded that the Paleogene shale below 3 500 m in Dongying sag has good shale oil exploration prospects.

Archaeal diversity analyses of core 973-3 from potential gas hydrate area in northern South China Sea

Yang Yufeng, Lei Huaiyan, Shi Chunxiao

2016, 37(3):  415-421.  doi:10.11743/ogg20160315

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Methanogenesis and anaerobic oxidation of methane driven by microbial activites are important for the global methane cycle.Marine gas hydrate is a huge methane reservoir on Earth,however,it remains unclear whether archaeal community structure in marine sediments can indicate marine gas hydrate.In this study,distinct archaeal communities thriving in marine sediments of core 973-3 in southwestern Taiwan Basin of the northern South China Sea were characte-rized by 16S rDNA gene analysis.Moreover,we discussed the effect of diagenetic environment factors on archaeal community distributions.Results show that Methanosaeta is the most abundant in 20~450 cm depths,with 32.9% proportion.Methanosarcinales dominates in 542-870cm depths with 28.3% proportion,while Methanomicrobiales is predominant in 1 075-1 162cm depths with 20.7% proportion.The archaeal community structure in core 973-3 is closely related to the methanogenesis and methane oxidation,indicating the presence of gas hydrate.The variations of diagenetic environment parameters are responding to the gas hydrate formation.The pH values increase with depth,contrary to E_h,salinity and grain sizes.It is obviously different of archaeal communities in core 973-3,compared to that in gas hydrate-containing and -free sediments from Japan Sea and the Shenhu area of South China Sea,owing to the significant effects of pH,E_h and grain sizes on the distributions of archaeal community in core 973-3.Hence,it is essential to focus on the main niche for the methanogens and methanotrophs,to improve archaeal communities indicating marine gas hydrate.

Classification and quantitative characterization of microscopic pores in organic-rich shale of the Shahejie Formation in the Zhanhua Sag,Bohai Bay Basin

Zhang Qin, Zhu Xiaomin, Li Chenxi, Qiao Lijingyu, Liu Chang, Mei Xiaohan, Du Huiyao, Lu Jiajing

2016, 37(3):  422-432,438.  doi:10.11743/ogg20160316

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It is a key step for reservoir evaluation and development of shale gas to analyze characteristics of the microscopic pores in organic-rich shale and quantitatively characterize their pore size distribution.Based on core description,thin section inspection,X-diffraction,SEM and nitrogen adsorption test,this paper analyzed mineral components,classified microscopic pore types and also quantitatively characterized pore size in organic-rich shale samples of the Shahejie Formation in the Zhanhua sag,Bohai Bay Basin.The results show that the samples are characterized by high carbonate content and low clay content.According to their positions in the formation,genetic origin and occurrence,the reservoir spaces are divided into two types,namely pores and fractures,and their size classification criteria are determined.The pores consist of mineral matrix pores and organic pores.The fractures include structural,inter-bedded,over-pressure induced,diagenetic and organic shrinkage fractures.Nitrogen adsorption test mainly displays three types of curves which represent the spatial distribution of micropores,mesopores and macropores in the shale samples respectively.While nitrogen adsorption test mainly measures the mesopores and is relatively insensitive to other pore size types,SEM can reveal the characteristics of macropores much more clearly.It is suggested to further perform measurements of carbon dioxide adsorption,Nano-CT and mercury injection to quantitatively characterize the size and spatial distribution of the micropores and macropores in the shale.

Influence of oscillatory steam injection rate on performance of steam flooding

Ni Hongmei, Liu Yongjian, Li Panchi

2016, 37(3):  433-438.  doi:10.11743/ogg20160317

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Aiming at the poor oil displacement efficiency of steam flooding with a constant steam injection rate, oscillatory steam injection rate is put forward for the whole process of steam flooding.The oscillatory steam injection rate can be divided into two types.One is constant amplitude change type and the other is random amplitude change type.In order to determine the optimal steam injection rate for each cycle,a steam injection rate evaluation model with cumulative oil steam ratio as the target of appraisal is built based on the principles of mass conservation and energy conservation.Particle swarm optimization algorithm is used to optimize the optimal oscillatory steam injection rate for each cycle.Qi-40 Block in Liaohe oilfield was taken as case to evaluate the influences of oscillatory steam injection rate on the performance of steam flooding.Results show that the oil displacement efficiency of the oscillatory steam injection rate is better than that of the constant steam injection rate,and the cumulative oil steam ratio can be increased by 23.50%.In addition,the oscillatory steam injection rate with random amplitude change is better than that with constant amplitude change,and the cumulative oil steam ratio of the former is 8.98% higher than that of the latter.

Productivity of the imitation horizontal well pattern in low permeability reservoirs

Li Rongqiang, Lyu Aimin, Wang Jianzhong, Li Yang, Zhan Shiyuan, Wang Yueying

2016, 37(3):  439-443.  doi:10.11743/ogg20160318

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Imitation horizontal wells can significantly enlarge single well drainage area and increase controlled reserves,thus effectively develop low-abundance and ultra-low permeability reservoirs.In order to accurately and rapidly predict steady-state productivity of various imitation horizontal well patterns,deliverability prediction models with start-up pressure being taken into consideration were established for different imitation horizontal well patterns by using stream tube flow line integral method based on seepage flow characteristics of imitation horizontal wells.Comparison of the modeling results with actual production shows that the models are accurate in productivity prediction with an error less than 8.04% only.The models also show that staggered well pattern is better than cross well pattern in terms of steady-state productivity and sweep area when the lengths of the imitation horizontal well are the same.The latter is also more sensitive to well length than the former.The study may help theoretically guiding the application of imitation horizontal wells in ultra-low permeability reservoirs.

A new method for production calculation of complex trajectory wells in heterogeneous reservoir

Chen Zhihai, Dong Guangwei, Lian Peiqing

2016, 37(3):  444-449.  doi:10.11743/ogg20160319

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Analytical and semi-analytical formulas for production calculation of horizontal wells generally require the reservoirs being homogeneous and well trajectory parallel reservoir boundary,which make them unsuitable for complex trajectory wells.In this paper,the reservoir is divided into several regions based on well trajectory and permeability.Each region has different permeability,and the well trajectory within the region may be unparallel with the boundary.The point source function method is introduced to establish the segmented integral similarity solution for the production of complex-trajectory well in heterogeneous and constant-pressure-boundary reservoir,and the Ouyang model is used to calculate the pressure loss along the wellbore.This method can avoid numerical dispersion in simulation,and provide a fast production evaluation with fewer input parameters.Case study result shows that flow rate in wellbore with complex trajectory increases from toe to heel,the reservoir inflow rate is different in each segment due to reservoir heterogeneity and is high in the high permeability reservoir region,the pressure drop within the wellbore also increases from toe to heel and is different in each wellbore segment due to the uneven distribution of flow rate.The result of this method is consistent with that of Eclipse,confirming its feasibility.In comparison with the metered oil production in field,the calculated production of complex trajectory well has an error of less than 5%,showing that it can satisfy the demand of real-field reservoir engineering research.

Reservoir modeling of complex lithologies with sparse wells: A case from A oilfield in Shijiutuo uplift,Bohai Bay Basin

Zhang Yukun, Wang Hui, Hu Xiaoqing, Zhang Xianwen, Bu Fanqing, Gao Yufei, Fan Tingen

2016, 37(3):  450-456.  doi:10.11743/ogg20160320

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The 1^st and 2^nd Member of Shahejie Formation reservoir in Shijiutuo uplift of Bohai Bay Basin are complex in vertical lithology because of the nature of mixed clastics and carbonates.The reservoirs feature in low porosity and super-low permeability,large thickness but underdeveloped barriers and baffles with quick lateral variance,and strong internal heterogeneity.As there are limited appraisal wells available in offshore oilfield during the exploration and evaluation stage,it is difficult to understand the reservoirs.In order to finely describe these reservoirs,element capture spectroscopy logging was used to identify the complex reservoir lithology in single well,and nuclear magnetic resonance logging technique was used to optimize permeability interpretation of different lithologies. Then the reservoir lithofacies were divided according to the identified lithologies and petrophysics.By combining seismic attribute slice analysis with lithology distribution of wells,we identified different sedimentation stages of fan deltas and established a stratigraphic framework.By taking the stratigraphic framework as units,we predicted spatial extent of sandbody through seismic multi-attribute analysis and finished the lithofacies model with multilevel constraints by integrating deterministic modeling with stochastic simulation.Finally,we established the reservoir physical parameter modeling by using the lithofacies model as constraint.The modeling method adequately simulated the Paleogene reservoir heterogeneity in Shijiutuo uplift.In addition to ensuring isochronisms,the model with stratigraphic framework can realize fine subdivision of the reservoirs,and accurately map the high quality reservoir distribution,thus improve the prediction accuracy of the deep Paleogene reservoir withcomplex lithology in exploration and evaluation stages.