Table of Content

08 February 2016, Volume 37 Issue 1

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Pore type classification scheme for continental Yanchang shale in Ordos Basin and its geological significance

Wang Xiangzeng, Zhang Lixia, Li Zongtian, Fu Haijiao

2016, 37(1):  1-7.  doi:10.11743/ogg20160101

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The continental Yangchang shale reservoirs in Ordos Basin are unconventional reservoirs,for which no specific pore classification scheme is available.Based on an investigation of pore type classifications of both abroad and domestic,we selected two classification schemes suggested by Loucks and Yubingsong and proposed a new classification upon modification of the previous two by combining the actual observation data of samples taken from the Formation.Argon ion milling scanning electron microscope was employed to characterize and systematically probe into pore development(including forming mechanisms,scale and geological bearings)of the reservoirs.The results show that pores in between congregated mineral lamellae contribute most to oil and gas poolings and followed by pyrite intergranular pores,organic pores,microfractures and pores in clay mineral lamellae.Intergranular pores and edge pores of rigid particles are still less meaningful in terms of geological indication.Solution pores among quartz grains are believed to be the least important among all types of pores found in the reservoirs.

Potential evaluation of enriched shale oil resource of Member 4 of the Shahejie Formation in the Damintun Sag, Liaohe Depression

Lu Shuangfang, Chen Guohui, Wang Min, Li Jinbu, Wang Xin, Shan Junfeng, Hu Yingjie, Mao Junli

2016, 37(1):  8-14.  doi:10.11743/ogg20160102

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Recovery efficiency of shale oil is low due to high density,high viscosity,low porosity and low permeability,and it is necessary to evaluate the resource potential of the enriched resources that are high in resource abundance and low in exploitation difficulty.TOC over 4% is taken as the criteria for classification of enriched shale oil resource according to the triple-division relationship between S₁ and TOC.Because of the light and heavy hydrocarbon loss in S₁,S₁ should be corrected before it is used to evaluate the resource potential.Comparative analysis shows that S₂ decreases when the shale sample is extracted by chloroform,indicating that there are some residual hydrocarbons in S₂ but they have been eliminated by extracting process.The distinction ΔS₂ is used to correct the heavy hydrocarbon of S₁,and the correction coefficient increases with the increase of maturity.Assuming that the light and heavy hydrocarbons expel at the same rate during the hydrocarbon expulsion process,the ratio calculated with hydrocarbon generation kinetics theory is used to correct the light hydrocarbon of S₁.With the increase of maturity,the correction coefficient of light hydrocarbons first decreases and then increases.On the basis of evaluating the organic heterogeneity by logging,the enriched shale oil resource is classified,and its potential is evaluated by using the corrected S₁.The potential enriched shale oil resource is about 2.2×10⁸ t in E₂s⁴⁽²⁾ sub-member in the Damintun Sag,Liaohe Depression,Bohai Bay Basin.

Correction of oil content-one key parameter in shale oil resource assessment

Xue Haitao, Tian Shansi, Wang Weiming, Zhang Wenhua, Du Tiantian, Mu Guodong

2016, 37(1):  15-22.  doi:10.11743/ogg20160103

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Pyrolysis parameter S₁ (content of free hydrocarbon) and chloroform-extractable bitumen "A" are often used to reflect oil content during shale oil resource assessment.However,due to inherent flaws of experimental procedures,laboratory-measured S₁ values fail to truthfully record the loss of light (bitumen "A" only) and heavy hydrocarbons and the measured bitumen "A" values cannot truthfully record the loss of light hydrocarbons.In order to be more accurate in quantitative assessment of oil shale resources,we performed correlation of these parameters to mend up the losses based on analyses of hydrocarbon genesis kinetics of organic matter and comparison of the parameters before and after extraction experiments on samples from mudstone/shale of the Qingshankou Formation in Songliao Basin.The results show that the correlated average S₁ and bitumen "A" are 4.2 and 1.2 times higher than the measured average ones,respectively.The S₁ equals to bitumen "A" after correction,while the former is only 0.28 times the value of the latter before correction.This indicates the necessity of correction to the two parameters in the resource assessment.

Main controlling factors on shale adsorption capacity of the Lower Silurian Longmaxi Formation in western Hunan-Hubei area

Chen Kang, Zhang Jinchuan, Tang Xuan, Yu Jingdu, Liu Yang, Yang Chao

2016, 37(1):  23-29.  doi:10.11743/ogg20160104

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Various laboratorial techniques are applied for dissecting the characteristics of the Longmaxi Formation shale in Western Hunan-Hubei Area,including organic carbon,mineral,porosity and methane adsorption.It is found that the Longmaxi Formation shale has good methane adsorption capacity with an average saturated adsorption gas content of 2.46 cm³/g under constant temperature 30℃,thus has favorable gas capacity storage.Correlation analysis reveals that the content of organic carbon,appropriate maturity,contents of vitrinite and inertinite,content of pyrite as well as the volume of micropores and mesopores,as the major internal controlling factors,are positively correlated with gas adsorption capacity,while temperature and pressure,as the external controlling factors,have negative and positive relationships with adsorption capacity,respectively.The tectonic uplifting produced a considerable influence on temperature and pressure due to its relatively high intensity.It is suggested that the influence of tectonic uplifting on adsorption capacity can be divided into two stages.When the strata are uplifted within high pressure zone,the impact of temperature on gas adsorption is greater than that of pressure,enhancing adsorption capacity.In contrast,when the strata enter into low pressure zone due to strong tectonic uplifting,the influence of pressure on gas adsorption is greater than that of temperature,rapidly lowering adsorption capacity.

History of natural gas accumulation in Leshan-Longnyusi Sinian paleo-uplift, Sichuan Basin

Li Jijun, Cao Qun, Lu Shuangfang, Wang Weiming, Li Wenhao, Yan Xintong, Shi Yinglin, Yin Jianxin

2016, 37(1):  30-36.  doi:10.11743/ogg2016020105

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History of natural gas accumulation in Leshan-Longnyusi Sinian paleo-uplift in the Sichuan Basin was studied with chemical kinetic methods of gas generation and isotopic fractionation.The results show that:①Gaoshiti-Moxi gas bearing structure is an inherited uplift which is conducive to efficient accumulation of natural gas.The natural gas generated since 191 Ma mainly gathered in the Sinian Dengying Formation,while that generated earlier didn't accumulate or dissipated after accumulation.The gas accumulation participation rate is about 79%.②The Ziyang structural trap gradually evolved into a tectonic slope of Weiyuan trap during the Yanshan tectonic movement.The remaining non-pyrolysed crude oil migrated to the new structural high-Weiyuan trap and continued to pyrolyse there during the tectonic movement.So Ziyang and Weiyuan gas fields gather the natural gas generated before and after structural adjustment(106-104 Ma),respectively.③Weiyuan structural trap captured limited pyrolysis gas due to its late formation,and its gas accumulation participation rate is about 51%,which is lower than that in Gaoshiti-Moxi area.④Much natural gas in Ziyang paleo-uplift was lost during Ziyang-Weiyuan tectonic inversion.Although the ending of gas generation in Gaoshiti-Moxi area is 90 Ma earlier than that in Ziyang-Weiyuan area,which is not conducive to the preservation,its gas reservoir fullness is higher than the later area.

Inversion method of shale oil reservoir mineral component content and its application in the Fourth Member of the Shahejie Formation in the Damintun Sag, Liaohe Depression

Xiao Dianshi, Lu Shuangfang, Lu Zhengyuan, Zhang Luchuan, Guo Siqi, Gu Meiwei

2016, 37(1):  37-44.  doi:10.11743/ogg20160106

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Accurate characterization of mineral content is the key to evaluate its fractability for shale oil reservoir.Because of being rich in organic matter and with complex mineral composition,mineral evaluation with traditional volume model method is of low accuracy.This paper took the fourth member of the Shahejie Formation shale-oil reservoir in the Damintun Sag of Liaohe Depression,Bohai Bay Basin as an example.Bulk rock analysis and geochemistry test data were used to analyze lithology,mineral composition and curve response characteristics of the shale-oil reservoir,and then constructed the volume model and logging response equation suitable for the shale-oil reservoir.Genetic algorithm-based optimization method was utilized to calculate mineral composition,porosity and kerogen content.The calculation results showed that the mineral distribution predicted by multi-mineral inversion method was consistent with that of ECS,and its precision was obviously higher than that of linear fitting.The standards of shale-oil sweet spot were built in terms of oil-bearing property and fracability.The multi-mineral interpretation results can effectively guide sweet spot identification of shale oil.

Gas preservation conditions of marine shale in northern Guizhou area: A case study of the Lower Cambrian Niutitang Formation in the Cen'gong block, Guizhou Province

Wang Ruyue, Ding Wenlong, Gong Dajian, Leng Jigao, Wang Xinghua, Yin Shuai, Sun Yaxiong

2016, 37(1):  45-55.  doi:10.11743/ogg20160107

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South China,where develops several sets of marine organic-rich shales,is an important area for shale gas E & D.Compared with North America,the marine organic-rich shales in southern China have the characteristics of old geologic age,high maturity,multi-episodic tectonic movements,complex surface conditions,complicated earth stress state and large differences of preservation conditions.In comparison with the Longmaxi shale that has achieved a breakthrough in shale gas exploration and development in Sichuan Basin and its periphery,the Lower Cambrian Niutitang shale has an older age,greater particularity and complexity and higher requirement to preservation conditions.On the basis of the geological conditions of the complex structure areas in southern China,the preservation conditions of the Niutitang shale in the Cen'gong block were analyzed through precise seismic interpretation,tectonic evolution,material foundation,cap rocks,reservoir pressure,and component of natural gas and aquifers.The results indicate that late tectonic reconstruction dominated by denudation and faulting is the major factor leading to the dissipation of shale gas.The tectonic evolution of the study area has the characteristic of "moderate early uplifting,long-term stability and intensive late reformation".Besides,NE-NNE-trending trough-like folds,high dip-angle thrust faults and strike-slip faults are well-developed in the study area,and the central wide and gentle structure zone has less faults,moderate buried depth and good preservation conditions.In addition,the component of the natural gas and strata water shows that the superior roof,floor and regional cap rocks can effectively retard the gas dissipation and strata water invasion.Finally,an evaluation index system of structural preservation conditions is put forward and applied to identify the favorable preservation zones in the Cen'gong block.

Major controlling factors of poroperm characteristics of shale oil reservoirs in the Xingouzui Formation, Jianghan Basin

Li Wenhao, Lu Shuangfang, Xue Haitao, Wang Weiming, Li Jijun, Hu Ying, Zhang Pengfei, Li Junqian

2016, 37(1):  56-61.  doi:10.11743/ogg2016020108

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Based on the integrated analysis of X-ray diffraction,high-pressure mercury and scanning electronic microscope,this paper discusses space types and controlling factors of the shale oil reservoir in the Xingouzui Formation in the Yajiao-Xingou Low Uplift and the Chentuokou Sag of the Jianghan Basin.The results show that inorganic pores (including intercrystalline pores,intergranular pores and dissolved pores) are the main reservoir space of the shale oil reservoir.There also exist a small amount of organic pores and micro fractures.Porosity and permeability of the argillaceous dolomite and the dolomite are the best in the study area.Secondary pores are well developed in shale oil reservoirs both in the Yajiao-Xingou Low Uplift and the Chentuokou Sag,improving the poroperm characteristics.The influences of the mineral components on the reservoir poroperm characteristics are different between the Yajiao-Xingou Low Uplift and the Chentuokou Sag.The porosity of shale oil reservoir in the former has no relationship with mineral components, while that in the latter area is negatively correlated with the content of clay minerals and detrital minerals but positively correlated with the content of the dolomite.Meanwhile, the permeability is negatively correlated with the content of detrital and clay minerals,but positively correlated with the content of the dolomite in both areas.

Brittleness characteristics and its control on natural fractures in tight reservoirs: A case study from Chang 7 tight reservoir in Longdong area of the Ordos Basin

Zhao Xiangyuan, Zeng Lianbo, Zu Kewei, Hu Xiangyang, Jiao Jun, Zhu Lifeng, Shi Jinxiong

2016, 37(1):  62-71.  doi:10.11743/ogg20160109

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Study of brittleness of tight reservoir and its effect on natural fractures is of great significance to quantitative prediction of natural fractures in tight reservoirs.This paper summarized more than 20 brittleness testing methods,focusing on the development and application of brittleness evaluation methods for unconventional oil and gas reservoirs.Moreover,it also evaluated the brittleness characteristics of tight reservoir and its effect on natural fractures in the Chang 7 tight reservoir in Longdong area of Ordos Basin.The results show that several groups of high angle structural fractures are developed widely in intervals of various lighologies in the Chang 7 reservoir in Longdong area.Sandstones show the highest brittleness,followed by shaly sandstones,and mudstones has the lowest brittleness.The brittleness decreases with the increase of shale content.On the specific paleo-structure stress background,rock brittleness controls the development characteristics and development degree of natural fractures.There is a brittleness threshold,above which high angle fractures are more likely to develop,while below which it is likely to develop low angle fractures.Brittleness also controls rock fracturing ability.When brittleness index is large,rock is easier to fracture under the structure stress,resulting in more fractures.In contrast,when it is low,rock deforms instead of fracturing,thus fractures are poorly developed and even not developed.

Intra-stratal heterogeneity of high rank coalbed methane reservoirs and their quantitative evaluation: A case study from Zhengzhuang block in the southern Qinshui Basin

Li Junqian, Lu Shuangfang, Xue Haitao, Wang Weiming, Zhang Ping

2016, 37(1):  72-79.  doi:10.11743/ogg20160110

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Coal reservoir heterogeneity affects the exploitation of coalbed methane (CBM).The No.3 coal reservoir in the Zhengzhuang block in southern Qinshui Basin was taken as an example for intra-stratal heterogeneity study of high rank CBM,and vertical heterogeneity characteristics was quantitatively evaluated on physical properties (gas content,adsorption time,densities of macro-micro fracture) and coal petrology (macerals and maximum vitrinite reflectance) by using a variation coefficient.The following results were obtained.The ranking of intra-stratal heterogeneity of coal reservoir parameters from strong to weak is adsorption time (average variation coefficient is 0.5246),mineral content (0.4665),total density of micro-fracture (0.4381), total density of macro-fracture (0.3143), inertinite content (0.2473),vitrinite content (0.1125),gas content (0.0877) and maximum vitrinite reflectance (0.0135),among which adsorption time,mineral matter content and fracture densities have stronger intra-stratal heterogeneity and need to be evaluated as key parameters.This study proposed a new method for the description and quantitative evaluation of intra-stratal heterogeneity of coal reservoir.

Microscopic pore structure of shale oil reservoirs in the Lower 3^rd Member of Shahejie Formation in Zhanhua Sag, Bohai Bay Basin

Zhang Leilei, Lu Zhengyuan, Wang Jun, Tian Tonghui, Wang Xingjian

2016, 37(1):  80-86.  doi:10.11743/ogg20160111

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Core observation,thin section identification,X-ray diffraction,physical property and organic matter testing are integrated to reveal the mineral composition,physical properties,organic matter and lithology of the shale oil reservoirs in the Lower 3^rd Member of Shahejie Formation in Zhanhua Sag,the Bohai Bay Basin.And the characteristics of pore types and structure and their influences on reservoir property are analyzed by using Argon-ion milling and scanning electron microscope (SEM) technique.The mineral compositions of the target strata are dominated by clay,carbonate and terrigenous clastics.Both the porosity and permeability are low.The kerogen belongs to type I with high total organic carbon (TOC) content in the range of 0.52%~9.32% and vitrinite reflectance (R_o) in the range of 0.7%~0.93%.The lithologies are dominated by argillaceous limestone,limy mudstone and mud bearing limestone,with minor limy dolomite.With Argon-ion milling and SEM method,we studied 10 core samples from Well Luo 69 via qualitative analysis and quantitative statistics.According to the pore characteristics,pores can be divided into micropores and microcracks.The micropores can be further subdivided into intergranular pore,intercrystalline pore,dissolved pore and intracrystalline pore.The microcracks,dissolved pores,large intercrystalline pores and intergranular pores provide the main reservoir space for the shale oil reservoir.Pore types and distribution vary with different reservoir lithologies,which control the reservoir storage capacity.The limy dolomite is the best in storage capacity,followed by limy mudstone,argillaceous limestone and mud bearing limestone,and the limestone is the least.

Distributions of BSR and underlying free gas zones and related controlling factors

Yang Jinxiu, Richard Davies, Xiao Dianshi, Miao Xiuqing, Zhang Yanian

2016, 37(1):  87-92.  doi:10.11743/ogg20160112

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Bottom Simulating Reflector (BSR) is the seismic reflection marker of the base of gas hydrates.The blanking zones above represent hydrate-bearing sediments and the abnormally high amplitude zones below represent free gas zones (FGZs) sealed by hydrates.In this paper,high resolution 3D seismic data from offshore Mauritania are used to characte-rize in detail the seismic reflection characters of BSR and underlying FGZs,as well as their relations with nearby structural units.The BSR upwarps in the upper part of the diapir and deepens rapidly near canyon walls.In the diapir zone,the thermal flow migrating along the fault system during dipirism changed the hydrate stability conditions,causing the shallowing of the stable bottom boundary of BSR.The cooling of the surrounding deposits by the canyon,on the contrary,caused the deepening of the stable bottom boundary of BSR.Additionally,research shows that the BSR and FGZs are prone to form in areas with well-developed fluid migration conduits such as faults and chimneys,indicating that the fluid migration system is critical for the formation of gas hydrate and FGZs and may provide gas source for the hydratesystem.

Lower limits of porosity and permeability of shale oil reservoirs in the Xingouzui Formation, Jianghan Basin

Zhang Pengfei, Lu Shuangfang, Li Wenhao, Hu Ying, Xue Haitao, Li Qian, Zhang Han

2016, 37(1):  93-100.  doi:10.11743/ogg20160113

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Shale oil resources found in the argillaceous dolomite in the Xingouzui Formation of the Jianghan Basin has opened up a new domain for petroleum exploration.The study on the lower limit of prosity and permeability of effective reservoirs is significant to reveal accumulation and distribution of shale oil in the Basin.According to the porosities,permeabilities and mercury intrusion capillary porosimetry of cores, the lower limits of prosity and permeability of shale oil reservoirs in different depths (778~890、959~1070、1378~1478、2093~2200 m) in the Xingouzui Formation in the southern part of the Basin were determined using the empirical statistics,mercury curve and minimal pore throat radius methods.Moreover,the relationships between the lower limits and depths were established.The preliminary findings of this study include the followings:(1) the lower limits determined by the different methods are various;(2) the lower limits determined by the mercury curve and minimal pore throat radius are greater,while that determined by the empirical statistic method are smaller;(3) the errors of lower limits obtained from the different methods decrease with increasing depths,so that a variety of methods should be used to reduce the uncertainty of the lower limits.The lower limits of shale oil reservoirs in the study area reduce with the increase of depths.The lower limits of porosity (permeability) decrease with increasing depth in an exponent (power exponent) manner.

Characteristics and resource potential of Jurassic tight shale oil reservoirs in West Siberian Basin

Zhang Xinshun, Wang Hongjun, Ma Feng, He Zhengjun, Bai Bin, Liang Yingbo

2016, 37(1):  101-108,116.  doi:10.11743/ogg20160114

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The West Siberian Basin is one of the richest world-class petroliferous basins.With continuous development of the conventional oil,the oil production is declining continuously,so it is an urgent need to find new growth points of the oil production.The characteristics of its shale oil reservoirs are studied through analyses of the geochemical characteristics and reservoir physical properties of the main source rocks of the Bazhenov Formation in the basin,and the technical recoverable tight oil resources are estimated by using the graphics-volume method.Also the recoverability of the Bazhenov tight oil is evaluated comprehensively through comparison with some famous tight oil plays,such as Bakken,Eagle Ford and Yanchang tight oil plays.The result shows that the Bazhenov Formation is an excellent source rock featuring in high organic matter abundance,moderate maturity,large thickness of 20-50 meters. The lithologies are dominated by carbonate silicates and shaly silicates with interbeds of carbonates and siltstone.The quartz content is high,the clay content is low,and natural fractures are highly developed in local areas.The reservoir belongs to type Ⅰ and type Ⅱ tight reservoir with high oil saturation.The technical recoverable resource of the Bazhenov tight oil is 7.6 billion tons,and class Ⅰ resource of tight oil is 0.92 billion tons,which are mainly distributed in the central and west region of the basin.Taking the available facilities into consideration,the Central Ob,with all the key geological conditions at the standards of world-class tight oil plays,is the most favorable area for future development.

Static and dynamic mechanical parameter calibration of tight reservoir rock mass under in-situ condition

Sheng Yingshuai, Zhang Yuguang, Gu Mingyong, Liang Yaohuan, Shi Yongmin, Fang Yuanyuan, Du Shuheng

2016, 37(1):  109-116.  doi:10.11743/ogg20160115

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In order to accurately measure static and dynamic mechanical parameters of reservoir rock mass,establish their relation and discuss the factors that result in their differences,dynamic and static mechanical parameters of 49 reservoir rock samples were synchronously measured under simulated in-situ reservoir conditions,with the influences of confining pressure,pore pressure,temperature and saturated fluids being considered.The results show that static and dynamic Young's modulus correlate well under in-situ conditions.For low permeability reservoir,dynamic Young's modulus is generally greater than the static,and their difference will get greater with the increasing of dense degree.For different samples,building dynamic and static Young's modulus plates based on subdivision of physical properties can greatly improve the relevance and accuracy.Finally,the dynamic and static Young's modulus calibration plates under in-situ conditions are built according to the differences of physical properties between samples from the low permeability reservoir rocks in Songliao and Ordos basins.The plates not only can be used to establish mechanical parameter field and stress field of low permeability reservoir rock mass,but also provides more reliable data for optimizing the design of fracturing parameters and improve the success rate of operation.

Stress sensitivity anisotropy and its microscopic mechanism of tight oil and gas reservoirs: A case from the Chang-6 reservoir in Ansai oilfield of Ordos Basin

Zhang Zhiqiang, Shi Yongmin, Li He

2016, 37(1):  117-124.  doi:10.11743/ogg20160116

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Study on stress sensitivity anisotropy of continental tight reservoirs in China plays an important role in evaluation of reservoir damage during the exploitation of low permeability oilfield.In view of the practical problems,the X,Y and Z columns from three inter-perpendicular orientation of three typical samples from Chang-6 reservoir in Ansai oilfield of Ordos Basin are used to test permeability by changing confining pressure under the in-situ condition and study the relationship between permeability and effective stress.In addition,microscopic mechanism and anisotropy of stress sensitivity in tight oil and gas reservoirs are analyzed through integrating various data including casting thin sections,scanning electron microscopy and XRD,etc.The results demonstrate that stress sensitivities of different rock samples are different and stress sensitivities of the same rock sample are also quite different in different directions.The ranking of stress sensitivity index from strong to weak is fine-grained lithic feldspathic sandstone,feldspar lithic quartz siltstone and medium to fine-grained lithic feldspathic sandstone,and the ranking of anisotropy coefficient from strong to weak is feldspar lithic quartz siltstone,medium to fine-grained lithic feldspathic sandstone and fine-grained lithic feldspathic sandstone.Microscopic experiments indicate that mineral composition,the arrangement and pore structure characteristics of different types of reservoir are key factors to cause reservoir stress sensitivity anisotropy.Therefore,stress sensitivity anisotropies are quite different in different types of tight reservoirs,and the microscopic heterogeneity characteristics of reservoirs are the major factors influencing stress sensitivity and anisotropy.This understanding is of great significance to highly-efficient exploitation of the continental heterogeneous tight reservoirs in Ordos Basin.

Quick evaluation methodology of infill drilling potential in tight sandstone gas reservoirs

Yan Jin, Shi Yunqing, Zheng Rongchen, Wang shuping

2016, 37(1):  125-128.  doi:10.11743/ogg20160117

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Recovery factor of tight sandstone gas reservoir is low due to disadvantageous geological condition.Domestic and overseas development practices indicate the importance of infill drilling for EOR.Several methods including numerical simulation,geostatistical analysis and moving split-window are available for rapid evaluation of in-fill drilling potential.However,the numerical simulation method is high in cost,and the geostatistical analysis and moving split-window methods are not accurate.In this paper,a functional relationship is established between well spacing density and incremental recoverable reserve of single well based on geological data and dynamic behavior analysis.The infill drilling profit function is developed based on economic principles.The proposed quick evaluation method can be used to evaluate the potential of infill drilling and support decision making in development adjustment and potential tapping of tight gas reservoirs.Case study result shows great infill drilling potential in DK13 Block in Daniudi gas field, the optimal economic well spacing density is 2.2 wells/km², the economic limit well spacing density is about 7.06 wells/km² under current oil price and operation cost.

Quantitative evaluation of organic and inorganic pore size distribution by NMR: A case from the Silurian Longmaxi Formation gas shale in Fuling area, Sichuan Basin

Li Jun, Jin Wujun, Wang Liang, Wu Qingzhao, Lu Jing, Hao Shibo

2016, 37(1):  129-134.  doi:10.11743/ogg20160118

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The micro-pores present different wettability in shale gas.The organic pores are oil-prone wettability and the inorganic pores are water-prone wettability.Based on the differences of wettability between different pore types of shale,Nuclear Magnetic Resonance (NMR) T₂ spectrum is used to determine the pore size distributions of both organic and inorganic pores.The specific procedures are as follows.Firstly,NMR experiments are performed separately on shale core samples saturated with brine and dodecane respectively to identify T₂ spectra of the organic pore and the inorganic pore.Secondly,joint mercury injection capillary pressure (MICP) and liquid nitrogen adsorption experiments are carried out to establish the quantitative relationship between T₂ and pore-diameter distribution(r_d=52T₂).Finally,this formula is used to determine the pore size distribution of organic pore and inorganic pores.These methods are applied to the evaluation of the pore size distribution of the shale gas reservoir in the Silurian Longmaxi Formation in Fuling area,Sichuan Basin.The diameters of organic pores are mainly distributed in the range of 2~50 nm with a peak at 10 nm,and some are in the range of 200~500 nm.The inorganic pores show a wider range of diameter,i.e.2.5 nm~500 nm,with a peak at 50 nm.The micro-cracks show the largest size scale and range from 4 μm to 10 μm in width,with a peak at 5 μm. The pore size distributions derived from NMR coincide with that derived from FIB-SEM quantitative analysis.NMR experiment can measure the whole core and thus can reflect the real in-situ pore size distributions of organic pores and inorganic pores of gas shale.Moreover,the cost of NMR measurement is low,thus demonstrates a good application prospect in gas shale evaluation.

A new method to determine porosity and permeability cutoffs of tight oil reservoirs by using thickness of adsorption water film: A case study from the Damintun Sag, Liaohe oifield

Wang Weiming, Lu Shuangfang, Tian Weichao, Zhou Nengwu, Li Jijun, Shan Junfeng, Hu Yingjie, Yuan Hongqi

2016, 37(1):  135-140.  doi:10.11743/ogg20160119

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With the advancement of exploitation technologies of tight oil,the porosity and permeability cutoffs of tight oil exploitation have been greatly reduced,and are approaching to that of tight oil accumulation.In combination with experimental analysis and theatrical computation,this paper introduced the water film theory to determine the porosity and permeability cutoffs of the Damintun Sag.The results show that tight reservoirs mainly consist of oil shale in the 4^th Member of the Shahejie Formation in the Damintun Sag.Under the same geological conditions,there are water films (composed of strong bound water and weak bond water) adsorbed on the surface of tight sand particles.The minimum throat radius is equal to the thickness of water film which is so small that they can only be measured with nanometers.When the throat radius is smaller than water film thickness,the pore is filled with bound water.Only throats whose radius are larger than the film thickness can be valid oil charging pathways.Based on equilibrium of forces,relationship between water film thickness and throat radius is established,and the minimum throat radius valid for oil charging is calculated.The relationship of water film thickness with porosity,specific area and bound water saturation can be used to turn the critical value of throat radius into the critical porosity.This method not only has strong theoretical basis,but also the support of experimental data.

Research on measurement of pores in coals with NMRC technique

Guo Wei, Yao Yanbin, Liu Dameng, Sun Xiaoxiao, Gao Yangwen

2016, 37(1):  141-148.  doi:10.11743/ogg20160120

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This study compared measurement results of total pore volume and pore size distribution of 6 coal samples with different coal ranks by using the Nuclear Magnetic Resonance Cryoporometry (NMRC) and low-temperature nitrogen adsorption BJH method.Meanwhile,the possibility and feasibility of applying NMRC to analysis of coal pore size distribution were evaluated for the first time. Results show that the total pore volume measured by NMRC is significantly larger than that of BJH method for the same coal sample.This is mainly caused by two factors. Firstly,in comparison with the BJH method,the NMRC can measure more closed pores.Secondly,the BJH model itself has some limitations in calculating the pore volumes of most micropores (<10 nm) and some meso-and macro-pores.Measurement results of coal samples with different coal ranks indicate that the total pore volume measured by NMRC shows a trend of decrease followed by an increase with increasing coal rank.This trend is consistent with the trend of the change of coal porosity with increasing coal rank.In contrast,the total pore volume measured by BJH does not match the trend of the change of coal porosity with increasing coal rank,due to the existence of outlier values in the measurement results of BJH method.Compared with the conventional methods,the NMRC has advantages in quantifying coal total porosity.Moreover,the results of NMRC are less influenced by some artificial factors.Thus,NMRC is a new method that can be applied to the measurement of pore structure of unconventional reservoirs.