Wenjisang area in Turpan-Hami Basin developed multi-stage braided river delta in the Jurassic Sangonghe Formation with reservoirs dominated by low porosity and low permeability.Its “sweet spot” in tight sandstone is mainly controlled by fractures and sedimentary micro-facies of delta front underwater distributary channel.Based on the comprehensive analysis of tight sandstone reservoir geophysical response characteristics,by the application of seismic inversion,spectral decomposition,seismic attribute slicing technology and fracture prediction technology,this article portrayed and described the plane distribution characteristics and sedimentary evolution of sand-body from multi-stage braided river delta front underwater distributary channel in the Wenjisang area.Advantageous areas of sweet spots in tight sandstone reservoirs and the exploration targets are predicted.
Based on bulk analyses of core observation,thin section identification,physical analysis and logging analysis,this paper studied the lithologic features and diagenesis in low permeability reservoir of Sangonghe Formation in block 1 of central Junggar Basin,divided seven lithofacies and seven diagenism facies.Through reasonable combination with lithofacies and diagenism facies,the authors divided twelve sedimentary-diagenetic synthetic facies in the study area.On this basis,using the logging curve characteristics of spontaneous,natural gamma,interval transit time,density,compensated neutron and deep lateral resistivity,the Fisher typical discriminant was adopted to determine the quantitative discrimination functions of each sedimentary-diagenetic synthetic facies Cross-plot of logging parameters was established,and sedimentary-diagenetic synthetic facies of each well were calibrated and the correctness of the identification result was tested.Combined thin section identification with logging identification results,this paper analyzed sedimentary-diagenetic synthetic facies of each well meticulously and predicted the distribution of the reservoir sedimentary-diagenetic synthetic facies in the study area.
Litho-stratigraphical reservoir has been and will be the most potential and realistic petroleum exploration field for a long time in China′s onshore exploration.Sand-lens pool is a litho-stratigraphical reservoir,and its formation and distribution has been valued hot spot.However,no consensus has yet reached about the formation condition of sand-lens pool.Based on detailed classification on the formation of possible models of sand-lens pool,the formation condition of in-source horizontal sand-lens pool without fault connection is studied with advanced numerical modeling software,taking litho-stratigraphical reservoir in oilfield as an example.The result shows that primary shale oil saturation is dominant factor for the formation of in-source horizontal sand-lens pool without fault connection.
Since “Donghe sandstone” was found,there are lots of disputes about the age assignment and the position of the top interfaces of sequence.It is difficult to understand the characteristic of the top reservoir and predict the reservoir distribution as a result.In order to figure out the characteristic of top and back sequence interfaces of the Donghe sandstone interval and controlling process of the reservoir,this study performed analysis on the type,distribution and lithology combination of the top and back unconformity interface based on outcrop,rock core,seismic and well logging data.Research shows that,according to formation mechanism,the top and back unconformity interface could be divided into 5 types;on the basis of lithology combination,23 collocations were recognized in this area.Reservoir characteristic of gas and oil field which had been found was analyzed based on the effect of unconformity interfaces to the accumulation of oil and gas.
Taking Dibei tight sandstone gas reservoir in the east Kuqa Foreland Basin as an example,this paper provides a detailed discussion of how fractures to affect the storage space and gas flow capacity,and thus how to control gas accumulation,enrichment and prolific production in tight sandstone reservoir.According to the statistics of laser confocal fluorescent microscopy observation,the micro-structural fracture width in Dibei gas reservoir is mainly in 8-25μm and the associated micro-fractures width is mainly in 4-10μm,while throat radius are mainly in 1-4μm.The fractures width is much wider than throat radius and serves as a main channel of gas flowing.Based on physical simulation experiment of gas charging into core samples with saturated water,mercury injection and gas-water two-phase permeability experiment,it illustrated that the fractures developed samples are easier for gas to flow under equal porosity condition,because of the lower expulsion pressure,higher mercury injection saturation and increased gas relative permeability.Based on these analyses,it had been deduced that the fractures control tight gas in many aspects:(1)Fractures play a significant role in reservoir property improvement.The isolated pores are linked by fractures to form connective reservoir spaces,and the solutions are prior to occur along the fractures forming new pores,and the fractures mostly with width bigger than the throat radius can provide reservoir space themselves.(2)Fractures can increase fluid flow capacity because fractures will decrease the starting pressure gradient,increase gas effective permeability and thus improve gas injection efficiency as well as gas production.(3)The fractures developed in different time and spatial places have different effects on gas accumulation,enrichment and production in tight sandstone reservoirs.
In order to probe the quantitative classification method of diagenetic facies,logging data and test results have been used to establish classification standard and state characteristics of diagenetic facies according to diagenesis and logging parameters taking Shan 2 sandstone of Shenmu Gasfield in Ordos Basin as an example.The lithology is lithic quartz sandstone,lithic sandstone and quartz sandstone.It develops lithic dissolved pore,inter-crystalline pore,inter-granular dissolved pore,mixed solution pores and inter-granular pore.Shan 2 sandstone experienced compaction pressure-solution,cementation and dissolution with medium to strong compaction rate,medium cementation rate,moderate to strong dissolution rate,respectively.Five types of diagenetic facies can be classified according to the diagenesis quantitative parameters and diagenetic facies can be effectively distinguished based on natural gamma ray,deep lateral resistivity,acoustic and density logging.The moderate compaction,illite cementation,intergranular pore and dissolution pore facies distributing in the middle of distributary channel sand body is the most favorable diagenetic facies because of the highest pore development degree,the best properties,the widest distribution of pore throat and high content of large pore throat,followed by moderate compaction,illite and kaolinite cementation,dissolution pore and intergranular pore facies.
By using abundance,type,maturity and gas generation intensity of organic matter,the comprehensive analysis of Upper Paleozoic source rocks in southwest Ordos Basin has been made to determine the plane distribution characteristics of main gas reservoirs,and the controlling effects of gas source rock on the formation are analyzed,which has been compared with that in the Sulige area.The Upper Paleozoic source rocks are composed of coal and dark mudstone of Shanxi Formation,Taiyuan Formation,of which coal seams are main source rocks.The average thickness of coal seams is 4.7m in the study area,while 14m in Sulige.Source rocks are abundant in organic matters.That is,the mean residual TOC in coal seam of the second member of Shanxi Formation and Taiyuan Formation are 54.94% and 66.96%,respectively and in mudstone are 2.88% and 1.75%,respectively;The carbon isotope of kerogen varies from -24.56‰ to -22.05‰,indicating that the kerogen belongs to type Ⅲ;Vitrinite reflectance of organic matter is 1.6%-3.2%,with an average of 2.3%,which is at high to over-mature stage.Gas generation intensity is mainly between (8-20)×108m3/km2,while between (11-29)×108m3/km2 in Sulige region.Compared with the condition of gas source rocks of Sulige region,condition in the study area is slightly bad.Condition of source rocks controls the formation and distribution of gas reservoir in the study area.Horizontally,gas-producing wells are mainly distributed in coal seams with thickness more than 4m and gas generation intensity greater than 10×108m3/km2,showing a trend that the better the source rocks,the more the hydrocarbon content.Vertically,it has a good positive correlation among the vertical migration distance of gas migration,the thickness of coal seam and gas generation intensity.That is,the vertical migration distance of gas becomes farther along with greater thickness of coal seam and higher gas generation intensity.
Relationship between sedimentation rate and organic matter abundance of source rocks has been studied mainly in marine sediments,which is generally thought to be positive or negative correlation.Based on the data sets of sediment intervals from 61 exploration wells in the lacustrine Erlian Basin,the relationship in ancient lacustrine sediments has been studied.It has been found out that the relationship between sedimentation rate and organic matter abundance of source rocks is controlled by the redox conditions when sedimentation rate is lower than 5cm/ka,while when sedimentation rate is higher than 5cm/ka,the relationship is controlled by the paleo-productivity.When sedimentation rate is lower than 5cm/ka,the relationship is positively correlated under the oxidation conditions,while in reduction conditions,there is no significant relationship between sedimentation rate and organic matter abundance.When sedimentation rate is higher than 5 cm/ka,the relationship is controlled by the paleo-productivity.The relationship is negatively correlated in low palaeo-productivity environment while there is no significant relationship between sedimentation rate and organic matter abundance in high paleo-productivity environment.
By the pressurized sealed gold tube pyrolysis experiments,the fluid composition of Jurassic coal from the Minhe Basin at different maturity was analyzed.Combined with the Corresponding States Method in software PVT-sim,the fluid viscosity was calculated and the impact on fluid viscosity of CO2 during the evolution of the coal was discussed.The study showed that the fluid viscosity was closely related with the fluid phase,the viscosity of the liquid phase would be an order of magnitude higher than that of the associated gas under geological conditions.With increasing maturity,viscosity of the gas and liquid phases both decreased.After the Easy%RO reaches 0.86%,at 10-30MPa and 25-125℃,the maximum value of liquid viscosity was less than 1.0 mPa·s,and the minimum value would reach 0.13 mPa·s.For the gas viscosity,it was 0.1mPa·s and 0.013mPa·s,respectively.CO2 generated from coal has important influence on the petroleum viscosity.Under different temperature and pressure conditions,the distribution ration of the CO2 in gas-liquid phases affects the viscosity directly.Overall,the viscosity of both liquid and gas phases decreases with the decrease of CO2 content in total component,which is because CO2 could extract short carbon chain component in the liquid hydrocarbon Viscosity increases with the decrease of CO2 only when it is at low temperature or with low maturity.
In order to strengthen the oversea development of tight sandstone in CNPC orderly and effectively,the article investigated the characteristic differences between Groundbirch tight sandstone reservoir and domestic typical tight sandstone reservoirs such as Sulige and Xujiahe.There were six significant differences including forming rules,sedimentary environments,sand architectures,pore structures,physical properties,and adsorbed gas contents.The extremely tight marine sandstone of Groundbirch was thick,massive and prograding.The forming rule was “self-generated and self-contained”.The reservoir itself was rich in TOC and adsorbed gas content.The article also generalized the research trend of tight gas which was summarized into five “more” based on the contrast with before:The geological forming theory would be more “rich”,the reservoir description would be more “fine”,the reservoir evaluation would be more “comprehensive”,the production capacity forecast and well network deployment would be more “reasonable”,the single well stimulation techniques would be more “effective”.
Two methods to hold the experiment pressure were adopted to select the best condition for testing the gas seepage law of the marine shale gas core in south China,which are constant confining pressure mode and constant net confining pressure mode.The influence of different confining pressure mode on the experiment results was analyzed.And the best mode was selected under the actual formation condition.The conclusions show that gas flow rate increases with the injection pressure,whatever by the way of constant confining pressure or constant net confining pressure.The gas seepage law curve of the marine shale gas core in south China is nonlinear.The curve is divided into two regions including segment curve and pseudo linear curve,and the inflection points are 1MPa and 1.3MPa,respectively.The values of average permeability damage rate are 52.41% and 40.56%,respectively.The slip effect was affected by the confining pressure control mode.The change of injection pressure caused stress sensitivity,and the stress sensitivity effect was more obvious in the actual formation under the constant confining pressure.The influence of the slip effect on seepage law of marine shale gas is more than the stress sensitivity under the condition of low effective stress.A complete seepage law curve can be obtained,and a period of the seepage situation in the formation can be simulated under the constant net confining pressure.The results provide meaningful guidance for the gas field.The net confining pressure mode was also affected by the confining pressure,and the flow rate would decrease with the increase of the confining pressure.Above all,the net confining pressure is the best way to test the seepage law of the marine shale gas core in south China.
The distribution of gas and water is complex for tight sandstone gas reservoir in Shan 2 reservoir of Zizhou Gasfield.There is general water breakthrough during development in some regions.As a typical lithologic gas reservoir,this is dominated by structure,sand body characteristics,reservoir physical property and hydrocarbon accumulations.Therefore,given all sorts of factors,the fluid recognition method and effectiveness was researched.Based on the conventional cross-plot method of natural gamma-resistivity,natural gamma distinguished gas,water and dry layers clearly,and resistivity distinguished gas and water layers effectively.The conventional cross-plot method,the cross-plot of resistivity-porosity,P1/2 cumulative frequency method and multiple discriminating methods are applied to identify the gas,water and dry layers.The result shows that these methods can effectively distinguish reservoir fluid.Among them,the identification effect of the natural gamma-resistivity and multiple discriminating methods are better,and the model can be used for fluid identification in the study and adjacent areas.The practical application approved that these methods used together to identify the gas,water and dry layers in the study area must be effective.Compared with gas testing results,the discriminating rates have reached 95.8%,which confirmed that this method has good accuracy.The above methods have a good effect on the gas and water interpretation,which can be widely used in similar adjacent reservoirs.
The C1-C5 gas generation,carbon isotope ratios during cracking of heavy,normal and high-waxy marine oils from Tahe Oilfield,Tarim Basin,NW China,were described with closed-gold tube under high pressure.Three types of oil have similar gas-generation process,with C1 yield increasing with pyrolytic temperature and C2-C5 yield increasing at first then decreasing with the temperature.Heavy-waxy oil has the highest C1-C5 yield of 510mg/g油,whereas heavy oil has the lowest C1-C5 yield of 316mg/g油.The δ13C1 value was light at first,but gradually became heavier with the increase of pyrolytic temperature.However,the δ13C2 and δ13C3 values gradually became heavier when the temperature was greater than 420℃.Using kinetics software,the kinetic parameters of C1-C5 of different type of marine oils were calculated.With the frequency factor of about 1.78×1014s-1,the distribution of the activation energy of C1-C5 mass formation was relatively narrow,with the range from 56 to 66kcal/mol.Among the three types of oil,heavy oil has the widest activation energy distribution,with the lowest major frequency of activation energy.Based on the kinetic parameters,in combination with the fractional conversion(C)of oil to gas,the maximum temperature at which oil can be preserved as a separate oil phase varies from about 178℃ at geological slow heating rates to 206℃ at geological fast heating rates.The existence of Middle Cambrian volatile reservoir of well Zhongshen 1 from Tazhong Uplift provided a strong evidence for the conclusion.
Two sets of source rocks existed in the Triassic and Jurassic formations in the eastern part of Kuqa Depression,Tarim Basin.These two sets of source rocks have similar deposition environment and genetic types.How to identify these two sets of source rocks has always been a problem of the geochemical research.The online analytic technique of thermal pyrolytic light hydrocarbon was used to analyze the light hydrocarbon of produced in the pyrolytic experiment of source rocks from the east part of Kuqa Depression.Both of the source rocks in Triassic and Jurassic formations are typically terrestrial origin and can be identified by the relative percentage of branched alkanes and aromatic hydrocarbon.The relative content of branched alkanes in Triassic source rocks is mainly between 28%-38%,and it is 10%-27% in the Jurassic source rocks.The relative content of the aromatic hydrocarbon in Triassic is mainly between 5%-25%,and it is 20%-65% in the Jurassic.Research results have important guiding significance on the hydrocarbon accumulation theory and exploration and production deployment of the eastern Kuqa Depression.
The resource of low maturity gas in eastern Junggar Basin is abundant,and its formation mechanism and source material are the main difficulties and emphases in researches.With Rock-Eval,TOC,RO and GC-MS,saturated and aromatic hydrocarbons are analyzed.The geochemical characteristics of the low-maturity coal in the Middle Jurassic Xishanyao Formation and Lower Jurassic Badaowan Formation in eastern Junggar Basin were systematically studied.The vitrinite reflectance values range from 0.47％ to 0.73％,with an average of 0.63％,suggesting the source rocks have entered low-mature stage.Furthermore,the coals are type III organic matter that mainly comes from vascular plants.The results of source rocks evaluation indicate that samples have a great gas-prone.As an important material basis for gas formation,a series of compounds coming from resinites have been detected in saturated and aromatic hydrocarbons.Moreover,saturated hydrocarbons contain abundant benzohopanes,iso-(2-methyl) and anteiso-(3-methyl) alkanes,pristine and phytane,and high abundance is evidence for slight-moderate biodegradation.Besides,the high abundance of diasteranes could also confirm that clay materials have catalyzed the source rocks at low-maturity.Previous research showed that the biodegradation and the catalysis can decrease the activation energy of hydrocarbon,which is beneficial to gas generation at low mature stage.
Analyzed the trace mechanism of the common tracer natural gas migration index,and took the Jurassic natural gas in western Sichuan Depression as an example to examine the trace effect.The results show that the CH4 content,N2 content and arene/alkane ratio have a better trace ability in the process of migration in different phase,which all are effective migration tracer index.However,the CO2 content and iC4/nC4 ratio are relatively poor in tracing gas migration.The CH4 content is the most effective trace index for the migration direction of natural gas,because it increas with the increasing of the migration distance under the different migration phase.Whether the N2 content or the arene/alkane ratio had the opposite changes in different migration phase,therefore it is need to fully consider the migration phase of natural gas when choosing the two tracer index.When gas migration phase is known,the two tracer indexes can determine gas migration direction;if gas migration direction is known,they can determine gas migration phase.When CO2 content in natural gas was greatly influenced by carbonate minerals,it is likely to lose the function of tracing gas migration.Whether the iC4/nC4 can trace natural gas migration and what is the trace mechanism,both are still more controversial,so choose it to trace gas migration should be carefully.
Two types of hydrocarbon generation simulation experiments for two kerogen samples with typeⅠ organic matter were conducted in gold tube by continuously heating and step by step heating methods.The amount of oil and gas,and the carbon isotope of generated gas were quantified and analyzed.Then,the results of experiments were deduced to geological setting.Finally,the following knowledge about hydrocarbon generation from organic matter was concluded.(1)Both the oil generated from organic matter and gas directly generated by organic matter thermal decomposition could be gained by step by step heating methods.(2)The processes of oil generation from organic matter and cracking of oil resided in source rock overlap in the later of oil window.The cracked oil takes up 9%-10% of total oil generated by organic matter at the end of oil window.(3)The volume of accompanied gas generated directly by thermal degradation of type Ⅰorganic matter is not more than 130mL/g TOC in general.The thermal upper limits of gas generation for type Ⅰ organic matter is 3.8 %(RO).(4)The carbon isotope of methane generated by thermal degradation of type Ⅰ organic matter is heavier than that of cracking gas in the maturity range(RO=1.5%-2.5%)where primary gas from thermal degradation of organic matter and cracking gas co-exist.Their difference ranges from 0‰ to 5‰,and larger difference accompanied by higher maturity for the range from 1.5%(RO) to 2.5%(RO).
Fracability is the capability of the shale that can be fractured effectively during hydraulic fracturing.According to the network fracturing construction practice of shale reservoir,by externalizing shale reservoir “effective fracturing” concept,the practical significance of fracability evaluation of shale-gas reservoirs has been clarified.So this can be described as the probability to create a complexity fracture network and large stimulated reservoir volume in shale gas reservoir to obtain high economic benefits under the same condition fracturing technology.The consideration of the existing evaluation methods for many reasons influencing fracability was not quite comprehensive,which leads to the inaccuracy.Proposing a new method to evaluate the fracability of shale-gas reservoirs by taking into consideration of the factors of brittleness,fracture toughness and natural planes of weakness,is more comprehensive and scientific than before.Shale fracability can be divided into three levels according to the reservoir parameters.Shale with low fracability (fracablity index of 0-0.225) couldn′t be stimulated effectively.Shale with medium fracability (fracablity index is 0.225-0.5) could be stimulated effectively but the effect is actually modest.Shale with high fracability (fracablity index of 0.5-0.8) is the best choice to be fractured.It is better to choose shale with fracability index above 0.5.The new method was applied to Longmaxi shale in the Sichuan Basin.The fracability index is 0.392 8 and the fracability is modest,which agrees with result of microseismic monitoring.Applications in the Longmaxi shale show that the results of calculation are correct and soundly based and that the suggested method is practicable for use,which can be used in the selection of wells or layers for fracturing.
The shale of Lower Silurian Longmaxi Formation has become a key target for shale gas exploration and development in China recently.Based on the analysis of chemical component and stable isotope composition of natural gas in Carboniferous Huanglong Formation derived from Longmaxi Formation and Longmaxi shale gas itself,the reason of carbon and hydrogen isotopic reversal in shale gas is discussed in this paper.The shale gas is mainly composed of hydrocarbon gas in which CH4content is in range of 95.52%-99.59%,C2H6 of 0.23%-0.72%,and C3H8of 0%-0.03%.The drying coefficient (C1/C1-5) is more than 0.99,indicating typical dry gas.δ13C1 values range from -37.3‰ to -26.7‰,δ13C2 from -42.8‰ to -31.6‰,and δ13C3 from -43.5‰ to -33.1‰,respectively.The carbon isotope values indicate that the hydrocarbon gas is oil-derived gas.However,the reversal of carbon and hydrogen isotopes of hydrocarbon gases in shale gas occurs,i.e.δ13C1>δ13C2,δD1＞δD2.The geochemical characteristic of high thermal maturity and reversal carbon isotopes in the Longmaxi shale gas is similar with the Fayetteville shale gas in US.The Longmaxi shale gas is mixing of gases from decomposition of kerogen at high thermal maturity and cracking of soluble organic matter retained in the shale,suggesting there would be abundant shale gas resource for high productivity.
During the formation process of shale gas reservoirs,there are possibilities to contain water in the formation.However,conventional material balance equations for calculating shale gas reserves rarely consider the influence of water soluble gas.Therefore,a modified material balance equation should be studied for rational prediction of shale gas reserves.Based on the principle of volumetric balance in the formation,the shale gas reservoir was divided into two types,the one with matrix and the one with fracture.With the aid of gas solubility equation,the solubility for methane in the formation water was achieved under different formation pressures.Eventually,a modified material balance equation was established taking into the consideration of water soluble gas and the method for calculating reserves was achieved by means of linearizing the modified equation at the same time.Case study shows that the correlation coefficients of the line regressed by the new model is higher than that regressed by a conventional model in the literature.What′s more,the reserve calculated by the method presented in this article is a bit higher than that predicted by the method in the literature,which can be explained by the ignorance of water soluble gas.In conclusion,the water soluble gas is also an existing gas form of shale gas reservoirs that cannot be neglected during the process of establishing a more reliable material balance equation and better prediction of reserves.
According to measured profiles and lab tests in the Longmaxi Formation of the northeast of Yunnan,TOC and maturity of the samples were determined.And also,the shale gas reservoirs were investigated by XRD,high pressure mercury intrusion,gas absorption and scanning electron microscope.Besides the above methods,isothermal absorption is also used to evaluate the favorable area in the study area.The results show that:(1)the black shales are distributed in the lower segment of Longmaxi Formation,and the average thickness is more than 30 m and it gradually increases from southeast to northwest in the study area.With Yanjin and Daguan counties as the center,the burial depth of strata increases outward.(2)Regionally,TOC of shale increases from south to north,and it is more than 2% in the northwest of Yanjin and the north of Weixin.Vertically,TOC of shale is more than 2% in lower segment of Longmaxi Formation,but less than 1% in the upper segment of Longmaxi Formation.The measured average vitrinite reflectance of shales is 3.6%,showing that the shales are at the over-mature stage.(3)The shales have more brittle minerals in the study area,so the reservoirs are easy to be artificially fractured.Compared with the major gas shales in the north American,clay mineral contents are higher but brittle minerals (quartz,et al.)and carbonate minerals (calcite,et al.)are less in the study area.(4)Mercury injection experiments show that the pores are mainly transition pores and micro pores,but the pore opening degree decreases from the bottom to top in the Longmaxi Formation.Liquid nitrogen adsorption experiments indicate that pores with diameters less than 20nm are better developed in the transition pores and micro pores.Moreover,the two ends of pores are open,with the shapes of cylinders,cones,parallel plates,and a certain amount of flask pores.Measured pore specific surface area is 6.479-17.329cm2/g,with the mean of 11.425cm2/g.The pore volume is 0.006-0.016cm3/g.The pore average size is 3.256-4.367nm.(5)Isothermal adsorption experiments show that maximum absorbed gas content of the shales in Longmaxi Formation can attain 3.21cm3/g.Comprehensively,this paper has selected three favorable areas for shale gas,including the area between Yanjin and Suijiang county,the northeast of Daguan and the southwest of Weixin.
Shale gas in coal measures is one of the important types,and the shale in coal measures holds favorable ability of gas accumulation and enrichment potential.It has important significance of research for shale reservoir characteristics in coal measure strata to confirm the coexistence and co-exploration of unconventional gas.As a case of the Lower Permian Shanxi Formation in Huainan Coal Field,the results show that the thickness of the Shanxi Formation shale is about 72m,and the thickness of mudstone accounts for about 25%.The quartz mineral content varies from 29.2% to 36.7% in the mudstone with terrigenous origin.Shanxi Formation contains 0.37% to 8.87% of TOC.The organic matter is moderate mature with RO of 0.83%-1.32% and dominated by type Ⅱ2-kerogen.Porosity of the mudstone measured by Hg intrusion ranges from 0.87% to 4.29%,and pulse permeability ranges from 0.31×10-3μm2 to 0.91×10-3μm2 with an average of 0.54×10-3μm2 .The linear relationship of porosity and pulse permeability is generally better.The development of micro-fracture observed in the mudstone includes micro-fracture extended at the edge of quartz grain,particle internal parallel linear fracture and bent irregular fracture of the internal clay minerals.The micro-porosity dominated by inter-granular and intra-granular pores,with pore size ranging from 2μm to 50nm.The promoting effect of TOC and thermal evolution to micro pore is not obvious,but the mixed-layer minerals of illite and smectite is the main contributor to pores with a large proportion in the composition of clay mineral content.Different types of sedimentary micro-facies could develop different lithic facies,and it is the sedimentary basis of the physical properties of shale gas reservoir from Shanxi Formation in the study area.
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