10 May 2016, Volume 27 Issue 5
    

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  • Natural gas exploration domains and analysis of carbonate reservoir characteristics in the east of Tarim Basin,NW China
    Zheng Xing-ping, Zhang You, Chen Xi-guang, Yang Zhao, Shao Guan-ming, Bai Xiao-jia
    Natural Gas Geoscience. 2016, 27(5): 765-771. https://doi.org/10.11764/j.issn.1672-1926.2016.05.765
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    Carbonate rocks have been developed in Ordovician,Cambrian,and Sinian of Eastern Tarim Basin,and the cumulative maximum thickness exceeded 2000 meters.They are the main carrier of oil and gas,and a great deal of natural gas have been found in the past five years.Based on geological horizons,lithofacies,and reservoir differences,carbonate natural gas exploration domains of Eastern Tarim Basin can be classified into five types:carbonate platform limestone of Ordovician,carbonate platform dolomite of Ordovician,bioherms-shoal flats of platform margin in Cambrian,carbonate gravity flow of Cambrian slope,Sinian dolomite.Carbonate reservoir characteristics of all areas are synthetically analyzed through drilling core,thin section,experiments and logging data of over 10 drilling wells.It is held that good fracture and cave reservoir in carbonate platform limestone of Ordovician can partly distributed.Carbonate platform dolomite of Ordovician is better than limestone.Bioherms-shoal flats of platform margin in Cambrian have large Stacking thickness.Good quality and large thickness of carbonate gravity flow can be found in Cambrian slope.And effective reservoir also was found in Sinian dolomite.Commercial Gas has been found in limestone and dolomite of Ordovician in Shunnan-Gucheng area.Hence,the two regions can learn from each other's experience of exploration to expand the scene.
  • Dolomization and influence on reservoir development in deep-burial stage:A case study of Lower Paleozoic in Tarim Basin
    Liu Wei, Huang Qing-yu, Wang Kun, Shi Shu-yuan
    Natural Gas Geoscience. 2016, 27(5): 772-779. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0772
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    Lower Paleozoic strata of Tarim Basin were buried deeply in most of the late history.Understanding the formation and transformation of dolomite and the impacts on reservoir areimportant to deep petroleum exploration.Based on the study of Cambrian and Lower Ordovician Penglaiba Formation dolomite,we can get two conclusions.First,most of the Lower Paleozoic dolomite in Tarim Basin formed before deep burial stage.In deep burial stage,magnesium-rich residual evaporation brine and hydrothermal fluid cause burial dolomitization.Second,burial dolomitization generally results in recrystallizationof dolomite which will make crystal larger.Besides,higher strata temperatureleads to overgrowth of dolomite which will occupyoriginal porosity.
  • Microstructure characterization based on CT imaging technology of Cambrian dolomite reservoir in Tarim Basin
    Zheng Jian-feng, Chen Yong-quan, Ni Xin-feng, Yan Wei, Huang Li-li, Zhang Yan-qiu
    Natural Gas Geoscience. 2016, 27(5): 780-789. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0780
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    Reservoir microstructure characterization is a basis to identify the effectiveness of reservoir.The traditional methods such as casting thin sections,scanning electron microscope and mercury intrusion have limitation to characterize carbonate reservoir,furthermore,they can't characterize the 3D features of pores and throats.Using CT imaging technology,8 typical dolomite samples which represent 8 different reservoir spaces of Cambrian in Tarim Basin were scanned and their pore-throat structural parameters were calculated.CT images 3D structure models clearly show the shape,size,connectivity and distribution characteristic of intracrystalline pore,intercrystalline dissolved pore,vug,intergranular pore,intragranular dissolved pore,algae framework pore,Gypsum-dissolved pore and fracture in 3D space;The structure parameters of pore-throat such as porosity,radius,quantity and connectivity can quantitatively characterize the effectiveness of the dolomite reservoir.By comparing these parameters，it can be known that the dolomite with evenly distributed pores,high porosity and connectivity can be a high-quality dolomite reservoir,so vug is the most effective and important reservoir space,intracrystalline pore,intercrystalline dissolved pore and intergranular pore are second.This method provides a new way for the judgment of the scale and effectiveness of dolomite reservoir in Tarim Basin.
  • Characteristics of Ordovician fault in the Block 10 of Tahe Oilfield, Tarim Basin and its controlling effect on karst reservoirs
    Han Chang-cheng, Lin Cheng-yan, Ren Li-hua, Lu Xin-bian, Wei Ting, Zhang Xian-guo
    Natural Gas Geoscience. 2016, 27(5): 790-798. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0790
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    As with the development of exploring and developing of Ordovician carbonate reservoirs in Tarim Basin,the controlling effect of fault on carbonate reservoirs has drawn more and more attention.On the basis of cores,thin sections,drilling and well-logginganalyses,the reservoir is classified into three types,dissolution vug,dissolution pore-fracture and fractures.According to the structural evolution characteristics,taking fault times,scale and the controlling effect of karst reservoirs into consideration,the faults are classified into three grades including grade Ⅱ,grade Ⅲ-1 and grade Ⅲ-2.Faults’ controlling effect on the development of karst reservoirs and oil and gas entrapment were systematicallysummarized.Based on the comprehensive analysis,Ordovician in the Block 10 of Tahe Oilfield mainly developed three periods of faults,respectively in Late Caledonian,Early Hercynian and Late Hercynian.The Hercynian fracture plays decisive role in the formation and development of karst reservoirs,and grade Ⅱ and grade Ⅲ-1 turn out to be the most important for the development of karst reservoirs and oil and gas entrapment.Faults not only promote development of shallow karst and the formation of fractures,but also control the ancient geomorphology,the distribution of ancient water system and hydrothermal karstification.At the same time,the faults also play an important role in controlling the migration and accumulation of oil and gas.The understanding provides significant guidance of further exploration and development of carbonate oil and gas reservoir.
  • The genesis of low permeability of high-quality reservoirs in deep-buried clastic rock reservoirs and its development mechanism: A case study of Es2 Formation in the slope area of Qikou Sag
    Liu Jin-ku, Sun Yong-liang, Jiao Xu, Zhang Ze
    Natural Gas Geoscience. 2016, 27(5): 799-808. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0799
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    By means of rock (casting)thin-section,scanning electron microscope,X-ray diffraction,normal mercury injection,constant speed mercury injection,well logging and well production,a detailed study was carried out on the characteristics of reservoir,the genesis of low permeability and development mechanism of high-quality reservoirs of Es2 Formation in Qibei Slope of Qikou Sag.Research results have indicated that the component maturity and structure maturity of reservoir rocks are relatively low.Pore structure and reservoir properties are poor.The ability to resist compaction of the reservoirs is poor because of the high contents of rock fragments in the reservoirs.Massive reservoir pores were lost due to strong compaction and cementation in the process of the diagenetic evolution,which resulted in the formation of reservoirs with low porosity and low permeability.The development of high-quality reservoirs was controlled by multiple factors.Firstly,the favorable sedimentary microfacies are the material basis of the formation of high-quality reservoirs by controlling rock type and rock structure.Secondly,superposed dissolutions of multiphase various mineral formed a large number of secondary pores which are the direct cause of the development of high-quality reservoirs.Thirdly,the hydrocarbon inflow in the early stage is in favor of pore preservation and pore development.Lastly,the existence of overpressure is the key to pore preservation in the deep-buried reservoirs.High-quality reservoirs have undergone acidic diagenetic environment and the alkaline diagenetic environment in the whole process of the diagenetic evolution.The diagenetic environment mainly is alkaline environment and the secondary pores were developed by quartz dissolution in A period of early diagenetic stage.The diagenetic environment is mainly acidic environment and the secondary pores were developed by feldspars and rock fragments dissolution from B period of early diagenetic stage to A1 Subage of middle diagenetic stage.The diagenetic environment turned to alkaline diagenetic environment and the secondary pores were developed by the second phase quartz dissolution in A2 Subage of middle diagenetic stage.The present reservoir pores are caused by multiphase superposed dissolutions.
  • Research on sedimentary characteristics of river dominated delta mouth bar and influences affected by water level fluctuations during the formation
    Zhang Yang, Qiu Long-wei, Yang Bao-liang, Wang Jun, Li Ji, Tian Mei-rong, Sui Shu-ling
    Natural Gas Geoscience. 2016, 27(5): 809-819. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0809
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    In order to discuss the sedimentary characteristics and influences affected by water level fluctuations of river dominated delta mouth bar during different developmental periods,taking the Poyang lake Xinjiang delta for modern sedimentary study object,though statistics and analysis for the satellite photos of four typical river dominated deltas home or abroad,this article made clear about the development process and its sedimentary characteristics,calculated the main parameters of river mouth bar in different developmental periods,clarified the controlling effects of water level fluctuations on the development of the river mouth bar.The study results show as follows:It will experience a series of depositions after the formation of the river mouth bar and develop levee,splay,crevasse channel,sheetflood deposits,sheet sand,mud deposits,etc.The development of the river mouth bar compomer can be divided into four stages:Triangle river mouth bar compomer,V river mouth bar compomer,irregular V river mouth bar compomer,and diara-like river mouth bar compomer.The ratio of the length of river mouth bar compomer and the width of river channel before bifurcation can be used as an important parameter to divide the development stages of river mouth bar compomer.During the high water level conditions,the development of the river mouth bar compome rpresents to the deposits of far sand bar,prodelta,lake mud and the development of splay,swamp,interdistributary bay as the result of the river overflew the levee.During the low water level conditions,the development of the river mouth bar compomer presents to the development of river mouth bar and levee.
  • Tight sandstone reservoirs characterization of Chang 7 member in Longdong area,Ordos Basin
    Han Wen-xue, Tao Shi-zhen, Yao Jing-li, Ma Wei-jiao
    Natural Gas Geoscience. 2016, 27(5): 820-826. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0820
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    Tight sandstone reservoirs develop extensively in Chang 7 member in Longdong area,Ordos Basin,and tight oil is abundant.Unconventional tight sandstone reservoirs need special experimental techniques and analytical methods,which is different from the conventional reservoirs of high porosity and permeability.This paper adopted tight rock analysis,NMR,core and thin section observation,and FMI materials,in order to characterize the reservoirs precisely.The results of the experiments show that: (1)Destructive diagenesis is very strong,and effective porosity,bounded hydrocarbons (% of BV) decrease with depth;(2)According to the centrifugal experiment,this paper sets 0.1μm as the lower limit of pore throat of tight sandstone reservoirs,which is consistent with high pressure mercury data;(3)The movable fluid saturation is high and the correlation between movable fluid saturation and porosity and permeability is poor.The micro-cracks develop widely and they greatly improve the oil and gas migration and accumulation capacity.
  • Distribution characteristics and controlling factors of movable fluid in tight oil reservoir:A case study of Chang 7 reservoir in Ordos Basin
    Shi Jian-chao, Qu Xue-feng, Lei Qi-hong, Fu Bo, He You-an, Zhao Guo-xi, Cheng Liang-bing
    Natural Gas Geoscience. 2016, 27(5): 827-834. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0827
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    The micro-porosity structure of tight oil reservoir is complex,and distribution characteristics of the fluid in tight oil reservoir are very different from that of low permeability reservoir.The movable fluid evaluation of the Chang 7 reservoir in the Ordos Basin was conducted by using nuclear magnetic resonance (NMR) technology,and the controlling factors of the differences in the movable fluid were analyzed by cast thin section,scanning electron microscopy,high pressure mercury injection,high-resolution computed tomography.The results show that T2 pattern of the tight oil reservoir displays six modes,the content of the immovable fluid is high in middle and large pore,which lead to the parameters of movable fluid being low,and the amplitude of variation and the differences in tight oil reservoir are large among different samples.The relationships are higher between the reservoir permeability and the parameters of movable fluid.The physical properties of the reservoir are better,and the change of the movable fluid parameters is greater.The microstructure characteristics of the tight oil reservoir,such as the distribution of pore and throat radius,development degree of induced porosity and connectivity between pore and throat radius,development degree and availability of micro-fracture,the content,the occurrence states,and the filling degree,are the main controlling factors to cause deviation of movable fluid parameters.
  • Classification of pore structures in typical tight sandstone gas reservoir and its significance:A case study of the He8 Member of Upper Palaeozoic Shihezi Formation in Ordos Basin,China
    Wu Hao, Liu Rui-e, Ji You-liang, Zhang Chun-lin, Zhou Yong, Zhang Yun-zhao
    Natural Gas Geoscience. 2016, 27(5): 835-843. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0835
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    Based on the existing classification methods of reservoir pore structure and 265 samples of mercury injection experiments from the tight gas reservoir of Upper Palaeozoic He 8 member in Ordos Basin,this paper discussed the classification of pore structures in typical tight sandstone gas reservoir.Considering that certain overlaps exist between the pore structure parameters which reflect the classification information,three factors were extracted from the seven parameters including porosity (Φ),permeability (K),displacement pressure (Pd),median pressure (P50),median pore throat radius (R50),sorting coefficient (Sp) and maximum mercury saturation (Smax) using Q-model principal factor analysis.According to comprehensive information characteristics from the main factors,three main factors were named as pore throat size factor,porosity-permeability factor and pore throat sorting factor,respectively.Taking the three principal factors as cluster new variables,combining characteristics of capillary pressure curve and arthroscopic characteristic,pore structures of typical tight sandstone gas reservoir are divided into four types.Through Fisher discriminant method,the correct discrimination rate of clustering results can reach 87.5%,and accordingly,discriminant functions are established to divide the type of pore structure:Type Ⅰ (Y1>2.51),Type Ⅱ (Y1=-0.12-2.51),Type Ⅲ (Y1=-3.72--0.12),and Type Ⅳ (Y1<-3.72).The results show that Type Ⅰ and Type Ⅱ pore structures are in most favor of tight sandstone gas reservoir,and they also present that this classification is consistent with the test gas data.It will also provide solid geological evidence for high quality reservoirs and further regional exploration and development of tight gas in the Ordos Basin.
  • Discussions on flow unit quantitative identification methodology in tight sandstone reservoirs
    Chen Wen-hao, Wang Zhi-zhang, Pan Lu, Li Han-lin, Hou Jia-gen
    Natural Gas Geoscience. 2016, 27(5): 844-850. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0844
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    Popular flow zone index FZI is not suitable for strong heterogeneity and complex pore throat structure reservoir flow units identification of tight sandstone reservoir.Taking Daniudi tight gas reservoir as an example,introducing the cementation exponent m which reflects the rock pore structure into improved Kozeny-Carman equation to calculate FZIm,the recognition results were satisfying.When m is not constant of 1,but a variable,it has bigger influence on the pore structure and seepage characteristics.If m=1,FZIm equates FZI,FZI is only special case of FZIm.Research suggests that FZIm is not only suitable for conventional homogeneous sandstone,but also for the recognition of tight sandstone reservoir flow unit.For sand sample without cementation exponent,using the method that introduced in this paper to predict m,we could get FZIm for flow unit identification.
  • New advancement in application of diamondoids on organic geochemistry
    MA An-lai
    Natural Gas Geoscience. 2016, 27(5): 851-860. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0851
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    Diamondoids occur in all kinds of fuel fossils.Due to peculiar cage molecular structures,diamondoids have been widely used in the maturity assessment of high mature to over-mature oils and source rocks since the 1990s. New advancements in maturity,oil-cracking,oil mixing,oil biodegradation,organic facies,TSR,gas washing,migration,and oil spill identification using diamondoids during 21st century were discussed.The origin and possible forming mechanisms of diamondoids were summarized.Due to the unclearness of the origin of diamondoid,the results of the maturity and oil cracking among researchers have great differences.It is suggested that research of the evolution of diamondoid in different type oils and source rocks be beneficial to their application in organic geochemistry,especially for the depth limits for the deep reservoirs.
  • Geochemical study of Cambrian source rocks in the cratonic area of Tarim Basin,NW China
    Yang Fu-lin, Wang Tie-guan, Li Mei-jun
    Natural Gas Geoscience. 2016, 27(5): 861-872. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0861
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    Despite that huge petroleum resources have been found reservoired in the Cambrian,Ordovician,Carboniferous and Triassic in the Central Tarim and Tabei Uplifts,source rocks of the marine petroleum in the Tarim Basin have still been disputed for decades.With the development of exploration and more discover of source rocks,it is necessary to conduct research on Cambrian source rocks comprehensively and in detail.On the basis of a series of regular geochemical analysis,including TOC(total organic carbon),GC-MS(Gas Chromatography-Mass Spectrometer) and stable carbon isotopic analysis,27 Cambrian source rocks collected from the Tarim Basin were analyzed to obtain information about hydrocarbon-generation potential and geochemical characteristics.The results show that these samples belong to good to excellent source rocks,with TOC(total organic carbon) values ranging from 0.5%-8.39%.Source rocks of the Lower Cambrian were better than those of Middle Cambrian.Molecular biomarker indicates a source facies of alleges or aquatic organisms.The strong reducing environment was evidenced by low Pr/Ph and high content of dibenzothiophenes.High content of gammacerane suggests a water-column stratification.Most samples show relative abundance of terpanes and steranes,and the ratios of C21/C23terpanes and C28/(C27+C28+C29)regular steranes were greater than 1.0% and 25%,respectively.The relative higher abundances of C26,C27 triaromatic steroids and triaromatic dinosteroids were also observed.The stable carbon isotopic values were relatively heavy(>-31‰).The geochemical parameters of mudstones from Kalpin Uplift were different from the rest Cambrian source rocks,which indicates a unique source organisms.
  • Geochemistry of low-mature gas derived from Paleogene coal-measure source rock of Bohai Bay Basin
    Liu Dan, Wu Wei, Fang Chen-chen, Feng Zi-qi
    Natural Gas Geoscience. 2016, 27(5): 873-882. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0873
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    Low mature gas derived from coal-measure was first discovered in Liaohe Sag of Bohai Basin and Subei Basin.However,large amount of low-mature gas derived from coal-measure source rock has only been developed in the Turpan-Hami Basin.As a result,research on the geochemistry of this kind of gas is mainly based on the data from Turpan-Hami Basin and the geochemistry data of gas in other basins are limited.In recent years,some new wells have been drilled in the Palaeogene reservoirs of Liaohe Depression and Huanghua Depression of Bohai Bay Basin and the gas turned out to be low-mature gas derived from coal-measure source rocks.So in this paper we integrated the data of Bohai Bay Basin with the data of Turpan-Hami Basin to study the geochemical characteristics of low-mature coal derived gas in China.We also discussed the exploration potential of low-mature gas derived from coal-measure source rock in Bohai Bay Basin.The results show that the low-mature gas of Bohai Bay Basin mainly has δ13C1<-39‰,δD1<-200‰,and δ13C2-δ13C1>10‰,the RO of the source rock ranges from 0.5% to 0.9%.In the Bohai Bay Basin,besides Huanghua and Liaohe Depressions,all the other depressions have the exploration potential of low mature gas derived from coal-measure source rock in Shahejie reservoirs.Also,the Bozhong,Huanghuaqibei,and Dongyingminfeng Depressions have exploration potential of low-mature gas in Dongying reservoirs.
  • The changes of hydrocarbon yields and RO for source rock in the semi-open simulation with increasing of fluids pressure
    Wu Yuan-dong, Zhang Zhong-ning, Ji Li-ming, Sun Li-na, He Cong, Su Long, Xia Yan-qing
    Natural Gas Geoscience. 2016, 27(5): 883-891. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0883
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    In order to investigate the process of thermal evolution and hydrocarbons generation of organic matter.Mudstone source rock from drilling was pyrolyzed in simulation with con-pressure and hetero-pressure experiments in semi-open system high pressure instrument.In con-pressure experiments,peak of bitumen,oil,gaseous hydrocarbon yields appeared at 350℃,520℃ and 520℃ respectively,and yields were,in order,6.17mg/g,12.07mg/g and 4.14mL/g.The corresponding RO of residues were 0.9%,3.0% and 3.0%.Times of expelling hydrocarbon were,in order 4,21 and 21.In hetero-pressure experiments,peak of bitumen,oil,gaseous hydrocarbon yields appeared at 350℃,500℃ and 520℃ respectively,and yields were,in order,12.56mg/g,24.87mg/g and 2.59mL/g.The corresponding RO of residues were 1.1%,3.1% and 3.1%.Times of expelling hydrocarbon were,in order 5,43 and 44.Results demonstrate that the times of expelling hydrocarbon were controlled by temperature and threshold of expulsion hydrocarbon pressure.Increasing simulation temperature might enhance hydrocarbon generation intensity,and causing the pressure in the reactor reached the upper limit of the threshold of expulsion hydrocarbon pressure constantly under the same threshold of expulsion hydrocarbon pressure condition,times of expelling hydrocarbon were enhanced at last.And it might promote source rocks yielding liquid hydrocarbons.Increasing the fluids pressure might enhance ource rocks yielding bitumen and oil,increasing the yield of liquid hydrocarbons.At the same time,increasing fluid pressure might reduce the yield of gaseous hydrocarbons,causing the negative influence of gaseous hydrocarbons generation.The influence of fluids pressure to RO is different in different temperature,400-500℃,enlarging RO of organic matter with increasing fluid pressure may be more obvious.
  • Stress sensitivity of shale gas reservoir and its influence on productivity
    Zhu Wei-yao, Ma Dong-xu, Zhu Hua-yin, An Lai-zhi, Li Bing-bing
    Natural Gas Geoscience. 2016, 27(5): 892-897. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0892
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    To study the shale reservoir stress sensitivity and its effect on productivity,four shale samples of Longmaxi Formation of Lower Silurian in southern Sichuan Basin were carried out sensitive experiment.The reservoir porosity was measured using mercury injection capillary pressure.The mineral content of rock was studied through XRD analysis.The experimental results show that,the shale reservoir has the characteristics of strong stress sensitivity,effective stress and permeability change rate showed a good exponential relationship.The high content of clay minerals in shale is important factor for strong stress sensitivity,which will cause the clay minerals to be more easily closed and not easy to recover under the action of external force.Through the Knudsen number calculation under reservoir conditions of reservoir,the Longmaxi reservoir flow with multi scales.Based on multi-scale flow model,the stress sensitive productivity model is established.Through case analysis,shale reservoir production declines sharply with increase production pressure.
  • Advanced production decline analytical method for a multi-fractured horizontal well in shale gas reservoirs
    Wei Ming-qiang, Duan Yong-gang, Fang Quan-tang, Li An-hao, Lu Ting
    Natural Gas Geoscience. 2016, 27(5): 898-904. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0898
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    Multi-stage fractured horizontal well (MFHW) technology is widely applied in typical ultra-low porosity and permeability shale gas reservoirs.Compared to conventional reservoirs,there are several transport mechanisms such as adsorption/desorption,diffusion and Darcy flow in the shale gas reservoirs.And there is a significant limitation of using analytical/semi-analytical method to analyze transient pressure behaviors since a strong nonlinear relationship between adsorption/desorption,diffusion and pressure.Thus,Based on multi-fractured horizontal well(MFHW)’s perpendicular bisection (PEBI) grids,the production decline numerical mathematical model of infinite conductive MFHW which considers adsorption/desorption,diffusion and Darcy flow in shale gas reservoir is established and derived by introducing the Dusty Gas Model.According to the basic principle of Blasingame production decline,the Blasingame production decline typical curves are calculated through computer programming.The results show that the flow behaviours of infinite conductive MFHW’s Blasingame production decline typical curves are divided into four stages (i.e.,early formation linear flow around fracture,early radial flow,compound linear flow,and pseudo-radial elliptic flow).The effect of adsorption/desorption is stronger,q/Δpp、(q/Δpp)i and (q/Δpp)idvalue become larger,meanwhile the typical curves are influenced by PL nonlinearly,and by VL linearly.The flow capability in shale gas reservoirs with ultra-permeability and the well rate can be improved by diffusion parameter.As the formation permeability (k),fracture number (nf),and fracture half-length (xf) increase,the values of q/Δpp、(q/Δpp)i and (q/Δpp)id of the production decline type curves become larger.The fracture spacing df influences the compound linear flow stage of production decline typical curves,and the compound linear flow appears later with df increasing.And the pseudo-radial flow is mainly affected by distance from the well to the circular boundary (re).When re increases,the pseudo-radial flow appears lately.
  • New production data analysis technique for gas condensate well in shale reservoirs
    Xu Bing-xiang
    Natural Gas Geoscience. 2016, 27(5): 905-909. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0905
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    Production data analysis technique (PDA) is commonly used in shale gas reservoir as an effective tool to estimate the reservoir parameters and predict production.Presently this technique is usually applied in dry gas shale reservoir since it is only applicable to single-phase flow cases.For shale gas condensate reservoir,two-phase flow occurs and exists in formation when the pressure is below the dew point pressure,making the present PDA technique not applicable in these cases.Based on this,an analytical model with two-phase pseudo-pressure and pseudo-time for shale gas condensate wells was derived from the fundamental oil-gas two-phase flow equations,accounting for the characteristics of both shale gas and gas condensate.The new analysis approach and procedure of specialized plot were presented and validated by numerical simulation.It is more accurate than the previous method and can reduce the error by 22% in current case.This technique is also useful forshale volatile oil wells by changing several parameters in analytical model.And the analysis object becomes oil rate rather than gas rate.
  • The experimental study of water invasion mechanism in fracture and the influence on the development of gas reservoir
    Hu Yong, Li Xi-zhe, Wan Yu-jin, Jiao Chun-yan, Xu Xuan, Guo Chang-min, Jing Wei
    Natural Gas Geoscience. 2016, 27(5): 910-917. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0910
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    Aimed at water invasion law in fracture-pore gas reservoir and influencing factors of recovery percent of gas reservoir,the physical simulation experiment technique was used in the water invasion law experiment of horizontal cut-through fracture,the water imbibition experiment of matrix rock and its impacts on the formation gas supply mechanism experiment.In the paper,difference between the water invasion in matrix rock and fracture is determined.The water invasion law and the influence mechanism of water invasion on gas reservoir productivity and recovery efficiency in fracture-pore edge-bottom water gas reservoir was acquired.In the process of the water invasion into the fractured gas reservoir,while the water is invading into the fracture fast,the water is imbibing into the matrix rock which will result in reduction of gas phase percolation roads,increase of the gas phase percolation resistance of matrix rock and reduction of gas reservoir productivity and ultimate recovery percent of gas reservoir.The knowledge revealed the reduction causes of the gas well productivity and the recovery ratio of gas reservoir after water invasion into the fractured gas reservoir.Based on the above knowledge,the relation of water encroachment frontier advance rate and formation physical property,water body size was studied further.The different permeability matrix rock imbibition capacity was tested.The influence of water imbibition style and imbibition volume on the stable yield and ultimate recovery percent of reserves is evaluated.The study achievements can provide technical support for the development of Dina and Keshen gas reservoir of Tarim Basin and Longwangmiao gas reservoirs in the Moxi block of Sichuan Basin.
  • New insights and discussions on stress sensitivity of fractured tight reservoir
    Zhang Rui, Ning Zheng-fu, Zhang Hai-shan, Xie Qian
    Natural Gas Geoscience. 2016, 27(5): 918-923. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0918
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    The current insights in the applicability of stress dependent permeability and mathematical model to fracture tight reservoirs are still a controversial issue.In this paper,based on the physical meaning of Walsh model,the mathematical relationship between Walsh model and power law formula was investigated and the physical meaning of power law coefficient was analyzed and elaborated,and then the stress sensitivity tests on rock samples were conducted.Finally,the applicability of stress dependent permeability formulas was classified according to five pore types.The results show that the best regression fitting occurred in fractured tight reservoir rather than high porosity/permeability reservoir or no crack reservoir using Walsh model.Considering fracture roughness,Walsh model and power law formula are mathematically equivalent.The power law coefficient is the product of fracture “aperture term” and “tortuosity term”.The strong stress sensitivity corresponds to high fracture roughness and tortuosity.Consequently,classification result show that power law formula apply to fractured tight reservoir and microcrack reservoir,exponential formula apply to high porosity/permeability reservoir or no crack reservoir.
  • The formation and destroyment mechanism of shale gas overpressure and its main controlling factors in Silurian of Sichuan Basin
    Li Shuang-jian, Yuan Yu-song, Sun Wei, Sun Dong-sheng, Jin Zhi-jun
    Natural Gas Geoscience. 2016, 27(5): 924-931. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0924
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    Shale gas Well JY1 and Well PY1 eastern Sichuan Basin have been taken as examples to study the overpressure evolution in shale gas.The log intersection diagram between interval transit time and density has been used to distinguish the mechanic of overpressure. Fluid inclusion and PVTsim software have been used to recover the pressure evolution in the process of hydrocarbon generation and tectonic erosion.According to the research of fracture,time of uplift and times of tectonic deformation,the controlling factors on the evolution of shale gas overpressure have been discussed.The conclusion can be drawn that the mechanic of shale gas overpressure in Silurian is fluid expansion,which is caused by hydrocarbon generation.The fluid pressure decreased in the uplift process since Yanshanian generally.However,due to low porosity rebound ratio,poor pore connectivity and low formation water content,the decrement of fluid pressure cannot offset the effect of erosion,which caused the increasing of fluid pressure coefficient in the uplifting process.Well PY1 has been experienced three-period tectonic deformation since Yanshanian and its initial uplift time was 130Ma.In contrast,Well JY1 area has been experienced weaker tectonic deformation,and its initial uplift was 90Ma.As a result,low angel fractures and little high resistance fractures developed in Well JY1,high angle fractures and lots of high resistance fractures developed in Well PY1.It can be said that the development degree of high angel crack,time of uplifting and superposition of stress field are main reasons to affect the preservation of shale gas overpressure.
  • Three-dimensional basin modeling study on Zhangjiatan shale gas area in Ordos Basin
    Yang Sheng-yu, Zhang Jin-chuan, Tang Xuan
    Natural Gas Geoscience. 2016, 27(5): 932-942. https://doi.org/10.11764/j.issn.1672-1926.2016.05.0932
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    Three-dimensional basin modeling which combines geochemical and reservoir parameters can make a very good simulation of the heterogeneity of shale gas distribution and the process of its accumulation.Geochemical analysis implies that Zhangjiatan shale in Ordos Basin has a high TOC content with a moderate organic maturity.Production data also demonstrate the shale has a great potential of gas generation.Solid geological background materials,geochemical data and reservoir parameters were applied in the simulation of the geological evolution history,geo-thermal history and hydrocarbon generation and expulsion history of the shale.The distribution of shale gas was predicted by the three-dimensional basin modeling,and gas constitution,adsorb to free gas ratio,resource and reserve of the shale gas were also calculated.It was speculated that the organic conversion of the shale is about 20% and about 80% of the hydrocarbon that had been generated was expelled out of the source rock.Basin modeling result manifests that most of the shale gas is distributed to the west of Fuxian in adsorbed phase with a geological resource of  0.15×1012m3.Calibration on porosity,maturity and gas content verified that the basin modeling is solid. It was concluded that the three-dimensional basin modeling is a reliable way in shale gas resource evaluation especially in well researched areas in China.
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