Abstract:The Ordovician buried-hill reservoirs in Lungu oilfield belong to the typical heterogeneous carbonate reservoirs.The paleogeomorphology of this area was resumed by impressing and residual thickness methods，and the 2nd-grade pa?leogeomorphology of Lungu oilfield is divided into gentle karst slope，karst platform，karst highland，peak-cluster valley and karst basin from west to east. The type of Ordovician karst reservoir is dominated by cave reservoir，which can be further divided into high mountain with large caves type and interconnecting underground river type. At present，the caves found by exploration and development are mainly distributed less than 135 m below Ordovician buried hill surface，but the cave filling characteristics differ significantly in different burial-depths and different zones. The cave filling facies are divided into 4 types which are chemical deposition facies，transposition lithofacies，collapse-breccia facies and vadose filling facies；the cave filling models are also divided into 4 types：cave filling models of underflow along the river in gorge districts，flood backwater of swallet stream and cave collapse filling models of deep underflow in gorge districts，sinkhole filling models caused by collapse of underflow along the river and vertical shaft unfilling models of deep underflow. Oil and gas are mainly enriched in the upper part of the monadnock of Ordovician buried hill in Lungu oilfield. The trend surface of valleys can indicate the original oil-water interface，but the valleys that control the oil-water interface differ in different well blocks.

Abstract:Although the Middle Yangtze fold belt of the western Hunan and Hubei area has been considered to be the most important region of shale gas exploration in Hubei，the exploration maturity of shale gas is low，especially in the Cambrian and the Precambrian formations. Transgression happened rapidly in Changyang area during the Cambrian and early Ordovician period，which caused a wide development of organic-rich black shale and calcareous shale in the Niutitang Formation of Lower Cambrian under the background of deep water continental shelf. Based on results from observation of field outcrops，microscopic observation of thin sections and stratigraphic correlation，the Niutitang Formation was divided into three segments according to lithology，and the formation become thicker from south to north，developing 100 m thick relatively stable black mudstone and black shale. Geochemical analysis，reservoir property and gas isothermal adsorption experiment show that the black mudstone and shale in the Niutitang Formation have higher abundance of organic matter，higher maturity of organic matter，better kerogen type for gas formation，higher content of brittle minerals，well developed organic pore and intragranular poreand relatively developed microfracture. The gas was adsorbed tightly by the shale during the simulating experiment. The mudstone and shale is characterized by low porosity and permeability，so it is regarded as low and extra-low porosity and extra-low permeability reservoir. In the study area and its adjacent region，the Niutitang Formation is regarded to be the next target of shale gas exploration for its moderate buried depth，gentle occurrence and fewer faults structures.

Abstract:Based on detailed interpretations of 3D high-resolution seismic data，the geometry and dynamics characteristics of the Zhangjiakou-Penglai Fault（Shabei strike-slip belt for short）was analyzed systematically. The differences of structural characteristics in different zones of the Shabei strike-slip belt were pointed out and their control on hydrocarbon accumulation was revealed combined with drilling data. According to the differences in structural characteristics，this strike-slip fault zone can be divided into three sections from west to east. The western section of the fault is an arc-shaped compressive-shear sinistral strike slip fault which distributes from NE-wards to NW-wards and gradually converges at an arc in right-handed stepped form shaped like a“broom”. The middle section is a conjugate strike-slip system trending left-handed NW and right-handed NE because of the limit of two uplifts in the south and the north. The main faults in the eastern section are NE-trending right-handed tenso-shear faults which are influenced by the Tanlu fault in an open distortional space.The strike slip faults in this area are characterized by negative flower structure or“Y”shape structure，showing that there were two phases of tectonic evolution in this region-extension in Eogene and strike-slip in Neocene. Shabei strike-slip zone is basically fixed after three phases of tectonic movements including Indo-Chinese，Yanshanian and Himalayan. Being controlled by distortion space and regional large-scale strike-slip faults，the general setting of Shabei strike-slip zone is shown in compression and gradually converting to extension from west to east. The different properties of each segment of Shabei strike-slip fault not only control fault traps development at different positions of the fault zone and sedimentary facies distribution in Paleogene，but also oil and gas migration efficiency，thus controlling differences in oil and gas accumulation. On the whole，petroleum geological conditions get better gradually from west to east，and the hydrocarbon enrichment in the eastern and the middle section is significantly higher than that in the western section of the Zhangjiakou-Penglai Fault.

Abstract:Hydrocarbon carrier system is important as“the bridge and vinculum”between the oil sources and traps in hydrocarbon accumulation process. Based on previous study，the Neogene was taken as the target layer to analyze the measured formation pressure coefficient of four oil fields in the central uplift belt of Huanghekou sag，and then the effect of different formation pressure coefficient on oil and gas migration was discussed within the sequence stratigraphic framework.The results obtained show that there were three kinds of hydrocarbon coefficient in the central uplift belt of Huanghekou sag under the normal pressure condition. They were low pressure coefficient-high permeability carrier system，high pressure coefficient-middle permeability carrier system and middle pressure coefficient-high permeability carrier system. In the central uplift belt of Huanghekou sag，the low pressure coefficient-high permeability sandstone reservoir was the main carrier layer in Guantao and V oil group of lower Minghuazhen Formation in sag-gentle slope belt and inⅢoil group of lower Minghuazhen Formation in gentle slope-salient area. The high pressure coefficient-middle permeability sandstone reservoir was the main carrier layer inⅢoil group of lower Minghuazhen Formation in sag-gentle slope belt and the middle pressure coefficient-high permeability massive sandstone reservoir was the main carrier layer in salient area.

Abstract:The Boxing Fault is the boundary fault separating Boxing sag from the west of southern slope of Dongying sag.Some wells，with no evidences of oil and gas or showing thick layer of oil and gas but only yielding water in oil test，were drilled adjacent to the thrown side，while heavy oil was only found in Jinjia oilfield at the upthrown side currently. This indicates that the Boxing Fault experienced tectonic activity after the accumulation of oil and gas，which destroyed the palaeooil reservoir，and then some of CO2 were trapped there forming gas-bearing reservoirs. In this paper，Well Gao95 and Fan54 and the neighboring Huagou gas field in the upthrown side of Boxing Fault were taken as examples to analyze the opening and sealing properties of the fault and its control on palaeo-oil reservoirs. Based on the origin of mantle-derived CO2 gas reservoir，the accumulation period of organic CH4 and inorganic CO2 of Well Hua501 and Hua17 in Huagou gas field was analyzed. The obtained results show that organic natural gas and palaeo-oil reservoir found in Huagou gas field and the upthrown of Boxing Fault were formed in the depositional period of Guantao-Minghuazhen Formation of Neogene and the accumulation of CO2 gas reservoir happened in the Quaternary period from 2 Ma to now. The whole process can be characterized as reservoir destroyed first and CO2 gas reservoir preserved later. In the early depositional period of Guantao-Minghuazhen Formation，Boxing Fault was sealed when palaeo-oil reservoirs developed in the third member of Shahejie Formation；and then in the middle depositional period of Minghuazhen Formation，palaeo-oil reservoirs were destroyed when basalt erupted；in the late depositional period of Minghuazhen-Pingyuan Formation，the fault activity stopped and effective traps were connected to mantle source. According to the analysis on the correspondence between the fault activity and the formation time of inorganic CO2，it is concluded that the period of volcanic eruption was the time for inorganic gas accumulation but nor for trapping. Mantle derived inorganic gas migrated upward along the faults and into the favorable traps for accumulation while volcanic activity was quiet.

Abstract:In allusion to the problems encountered in research such as the complex distribution of residual middle-lower Jurassic，inconsistent knowledge about original depositional filling，etc.，the residual strata distribution of the middle-lower Jurassic was made clearly according to the Jurassic outcrop profile，drilling and seismic data and combined with the technical methods including drilling calibration，seismic facies analysis and low velocity anomaly detection. Strata sedimentary characteristics and evolution law of filling during Early-Middle Jurassic were studied systematically by field geological profile measurement and core description. Palaeo-sedimentary system of the middle-lower Jurassic in the study area was recovered combined with evolution relationship between Meso-Cenozoic basin and mountain. The research results show that the residual lower Jurassic distributed only in Hongshan sag of eastern Qaidama Basin with an area of about 640 km2；the residual middle Jurassic distributed in six sags such as Hongshan-Xiaochaidan，Gaxi-Yuqia，Hobson and Delingha，and the middle-lower Jurassic did not appear in Gaqiu，Dachaidan and Ounan areas. The depositional filling systems in Early Jurassic of eastern Qaidam Basin are characterized by alluvial fan，braided river，braided river delta，shallow lake and braided river delta，and their source came mainly from north Qilian mountain，secondarily from the south Chainan Uplift. The middle Jurassic developed while Qaidam Basin depressed and its depositional systems changed as follows：fan delta，braided river delta and sub-lacustrine transgressive cycle.

Abstract:Typical turbidite sandstones developed in the upper part of the third member of Shahejie Formation in the Shang847 block，Huimin sag. The reservoir evolution is not clear because of its complex vertical change and high heterogeneity. Based on data of core，thin section observation and laboratory analysis，the characteristics and main controlling factors of reservoir heterogeneity of the lacustrine deep-water turbidites were studied. The results show that the deep-water turbidity deposition rock in Shang847 block is mostly fine-grained lithic arkose sandstones，moderate sorted，and the grains are mainly sub-angular. The reservoir is characterized by low compositional maturity and textural maturity，poor physical property，and the reservoir space is dominated by secondary pores. The sandstone is in middle diagenetic stage A.Based on the differences of compaction，cementation and dissolution，three diagenetic facies were divided. Sand group2，which has poor physical property，high cement content and weak dissolution，is medium-compaction medium-cementation weak-dissolution facies. Sand group3，which has good physical property，low cement content and strong dissolution，is medium-compaction low-cementation strong-dissolution facies. Sand group4，which has characteristics intermediated between group2 and group3，is medium-compaction medium-cementation medium-dissolution facies.

Abstract:Due to years of water-injection recovery，the distribution of oil and water is quite complex in the Sangonghe Formation in Block Cai9 of Cainan oilfield. To improve the development efficiency of oil field is very urgent. The key to the adjustment of well pattern in the current development stage of the study area is to make clear the overlapping relation of reservoir，which refers to the distribution characteristics of reservoir architecture of the second and the third layers of the second member in the Sangonghe Formation in the braided river delta front. Therefore，first of all it is required to analyze the rock electrical characteristics of sedimentary microfacies in order to establish the identification marks of sedimentary microfacies for the single well and lay a solid foundation for further fine contrast between the wells. Then，based on the identification results of sedimentary microfacies of the single well，these dimentary microfacies were anatomized in order to make clear the identification marks of different levels of reservoir architecture unit，according to the core，mud logging and well logging data. Being guided by the fluvial facies sedimentary patterns，the static distribution model of cross-well reservoir architecture unit was established to realize the quantitative characterization of different levels of reservoir architecture unit.Finally，the rationality and reliability of the static distribution model of reservoir architecture unit was verified by the dynamic data. The result shows that the established static distribution model of reservoir architecture unit is reasonable and reliable in the Sangonghe Formation in Block Cai9 of Cainan oilfield，and it is also in good agreement with the actual production situation of the research region，which has guiding function for the development of reservoir in the later stage.

Abstract:The extra-low permeability oil reservoirs in Shengli oilfield have poor physical property，high heterogeneity，low reserves abundance and small pore throat. During the development，there are problems of low fluid production in single well，difficult effective displacement，contradictory between technical and economic well spacing，etc. In view of the above problems，factors that affect the development of extra-low permeability oil reservoirs were studied from the micro and the macro levels. Non-Darcy percolation mechanism of the extra-low permeability oil reservoirs was deepened，and evaluation method for effective seepage ability was established. A new method of improving the prediction accuracy of thin interbedded reservoirs and phase controlled stress field prediction technology were developed and improved. EOR technology that taking reservoir reconstruction and well pattern adaption as the core was formed. The study of rate-controlled mercury injection and microtubule experiment shows that size and distribution of the throat are the main influencing factors of effective percolation ability in the extra-low permeability oil reservoir；boundary layer exist in the extra-low permeability oil reservoir，which reduces effective flow radius and increases flow resistance. Through the research and application of integrated supporting technologies，the overall level of development was improved，and error between the stress obtained by phasecontrolled heterogeneous stress prediction technique and well point measurement was within 5°. Productivity gained by waterflooding technique in the pseudo-horizontal wells was 144.3×104 t. Well pattern adaptation technology of radial water jet made the recovery efficiency increase by 7.0% in Chun17-1 block. Compound stimulation technology made the average fluid production in single well increase by 3.3 t/d in the units of Es4 oil reservoirs in Bin425 block. So the efficient production and low-cost development of the extra-low permeability reserves were realized.

Abstract:Shale gas reservoir is abundant in nanoscale pores. Therefore，the gas seepage is influenced significantly by slippage effect. Conventional flow model cannot simulate the seepage law accurately in shale gas when gas flows in nanometer pores. In order to improve the accuracy of production simulation and make guidance for fracturing operation in the shale gas reservoir，slippage effect during gas flow must be analyzed precisely and directly. Lattice Boltzmann method was applied to built seepage model of the shale gas and to know boundary condition of bounceback-specular combination. The slippage effect in the shale gas reservoir was simulated and analyzed. The results show that the pore size and Knudsen number are the decisive factors which can be used to characterize the strength of slippage effect. The slip velocity of the gas molecule along the pore channels has approximate linear growth and increases more dramatically in the outlet end，which can testify the compression effect and rarefaction effect of the gas in the shale gas reservoir. The slip velocity will increase dramatically with the rising Knudsen number，especially after gas seepage in slip zone. The limitation of models based on continuous medium formula will be highlighted. With the rise of Knudsen number，the apparent permeability has been increased sharply. Klinkenberg model is no longer suitable for simulation of slippage effect during gas seepage in slip zone after the Knudsen number is more than 0.1.

Abstract:The method of production data analysis is commonly used in shale oil and gas wells，which can be used to estimate reservoir permeability and fracture half- length and other parameters by analyzing the production characteristics curves. However，this method is applicable to shale dry gas wells or shale oil wells in which only single-phase flow exists.For shale volatile oil well，the previous method is not suitable since both oil and gas are produced in the reservoir and at surface. A series of numerical simulations was run to investigate the effect of different gas-oil ratios（GOR）on production characteristics curves and estimated parameters. A production convert method was then introduced for modification. The results show that：for the shale volatile oil wells，if only oil production rate is analyzed，the slope of square root of time curve will increase and the curve will deviate from the linear flow behavior. The deviation degree will increase with initial GOR increases；also，the calculated fracture half-length will be smaller than the true value，and the calculated error varies from 6% to 56%；the production convert method can change the gas production into the equivalent oil production. By using the modified oil production in analysis，the calculated error of fracture half-length can be reduced by a maximum of 42%. This modified method is simple，and can be easily used in field. It can be also used in tight oil reservoir.

Abstract:In the present work，the structures and diversities of the microbial communities（bacteria and archaebacteria）in the water samples collected from the three-phase separator，the reaction tank，the filter and waterflood pump of the water treatment system in Baolige oilfield were studied through the high-throughput 16S rDNA sequencing technique when activating agents were added between the three-phase separator and reaction tank. In addition，the distribution and content of the oil recovery microbes in the four water samples were also analyzed. Results showed that the community structures of the bacteria and archaebacteria varied with the site of the water sample collected. The dominant bacterial groups in threephase separator，reaction tank，filter and waterflood pump were Campylobacteraceae，Tepidicella，Tepidicella，Azoarcus and Bacillus licheniformis，respectively. The dominant archaebacterial groups in the three-phase separator and the waterflood pump were both Methanomethylovorans. The diversity of the bacteria and archaebacteria in the water sample collected from the waterflood pump was lower than that in the previous site of sample collection，which indicates that the microbial community structure became simple compared with the previous water sample collection site. The concentration of the oil recovery microbes in the waterflood pump was the largest，which can be beneficial to the oil recovery when they are injected into the oil reservoir.

Abstract:The traditional cleaning fracturing fluid，with high surfactant content，high cost and poor heat resistance，is hard to be applied widely. A novel cleaning fracturing fluid with supramolecular structure was developed with hydrophobic polymers and new surfactant by the principle of supramolecular chemistry. The new supramolecular fracturing fluid has less viscoelastic surfactant，low cost and improved heat resistance. Its formula was optimized. Its composition is 0.2% hydrophobic polymer PX-A and 0.5%viscoelastic surfactant J201. The formation mechanism of the supramolecular structure was analyzed. It is found that the surfactant and hydrophobic polymer group are mixed to form micelles. With increasing of the micelles，the micelles have more dense structure，increased strength and tangle with each other forming a bridge，which result in the formation of three-dimensional network structure and the rapid increase of solution viscosity. The performance evaluation results show that the new supramolecular fracturing fluid has good temperature and shear resistance. It can be resistant to 130 ℃ high temperature，and its storage modulus is higher than its loss modulus in general. It also has good viscoelasticity，low friction，good sand-carrying capacity，no residue and low damage. Its composition is simple，so it is easy to be prepared. Field test results show that the tested gas production of Well Sudong38-64C4 is 10×104 m3/d after using the novel supramolecular fracturing fluid，which is 2 times than that of the adjacent wells fractured by guar gum fracturing fluid. The cost is saved by 25%. It has been applied in 4 wells of Changqing oilfield，and the effect is good.

Abstract:The resource of heavy oil in Bohai petroliferous area is rich. The produced heavy oil reservoirs are mainly developed by conventional water flooding with relatively low recovery efficiency. Economic and effective development of these resources has significant meaning on keeping the production of Bohai petroliferous area stable continuously. Taking typical heavy oil reservoirs in Bohai as research object，key injection-production parameters of steam stimulation including optimized fluid production rate，soak time and steam injection strength were optimized at various oil viscosities，reservoir thicknesses，permeabilities and water volume ratios through numerical simulation. Research results show that along with the increase of formation oil viscosity，the optimal fluid production rate and steam injection strength decrease gradually and the optimal soak time increases gradually. The optimal fluid production rate，soak time and steam injection strength increases with the increase of reservoir thickness. Along with the increase of permeability，the optimal fluid production rate increases，and the optimal soak time and steam injection strength decrease. Along with the increase of water volume ratio，the optimal fluid production rate and soak time increase，and the optimal steam injection strength increases first and then decreases. Using multiple regression mathematical method，the optimization model of injection-production parameters of steam stimulation was established. The calculated results of the optimization model is in consistent with that of reservoir numerical simulation with an error lower than 10%.

Abstract:Permeability is an important basic parameters in reservoir engineering. First step of conventional method for obtaining permeability is usually to get porosity according to the electric logging interpretation. Second step is to establish petrophysical interpretation model according to the relationship between porosity and permeability obtained from the core laboratory test. And then the permeability is gained. Experimental data of porosity and permeability in 300 pieces of cores of Bohai Y oilfield shows that the permeability in the multi-layer sandstone reservoir cannot be accurately described by unified regression relationship between porosity and permeability，and the permeability from well logging interpretation is often inconsistent with production performance. Therefore，a new method of quantitative characterization based on petrographic constraint，relative permeability test and dynamic agreement was put forward. Microscopically，main factors controlling the relationship between porosity and permeability were known by scanning electron microscope（SEM），cast thin section，logging and core data. Macroscopically，it was verified dynamically by laboratory relative permeability curve，water injection profile and initial productivity using petrographic constraints. The results show that the permeability gained by the new method based on petrographic constraints can improve the alignment with initial injection profile from 65% to 91%.

Abstract:Stress arch effect has influence on the calculation of stress and effective stress in reservoirs，and the effective stress has influence on the analysis result of stress sensitivity of porosity and permeability. The stress arch ratio is usually used to characterize the degree of stress arch effect. The influence of reservoir dip and reservoir azimuth wasn’t considered in general model of calculating the stress arch ratio. A new model of calculating stress arching ratio of inclined reservoir was established using the inclusion theory which is used to solve the problem in composite material mechanics. This model can be solved by tensor algorithm. Correlated influence factors were analyzed，such as reservoir dip，strike direction，Possion’s ratio and rock consolidation coefficient. Then the stress arch effect on porosity and permeability change were also analyzed. The result shows that the stress arch effect is obvious in vertical direction for the reservoir with small reservoir dip angle，large aspect ratio，small Possion’s ratio and small rock consolidation coefficient. While，it is significant in horizontal direction for the reservoir with large reservoir dip angle，small aspect ratio，small Possion’s ratio and small rock consolidation coefficient. Average stress arching ratio are only related to rock consolidation coefficient and reservoir Possion’s ratio.The stress arch ratio is usually positive，while it is negative in principal crustal stress direction due to stress concentration especially for inclined reservoir. The effective stress is relative to the stress arching ratio，while stress sensitivity is influenced by the effective stress. When vertical，minimum horizontal，maximum horizontal and average arching ratios of the reservoir are 0.107 2，0.674 7，0.718 1 and 0.5 respectively，the porosity and permeability calculated by the inclusion theory increase by 32% and 76.7% respectively compared with the values calculated by conventional deformation theory for the pressure drop of 30 MPa. The stress arch effect reduces the degree of stress sensitivity of the permeability and porosity in actual reservoir，which cannot be neglected during the development of low permeability tight oil reservoir.

Abstract:In recent years，weak-base ternary compound system has been adopted by Daqing oilfield to replace strong-base ternary compound system，which not only overcomes the scaling problem at the production end，but also enhances oil recovery. Compared with the strong-base ternary compound system，the research of weak-base ternary compound system starts late，and some chemical flooding mechanism needs to be further explored. Taking the reservoir and fluid in northern Saertu of Daqing oilfield as experimental object，the transmission and migration capacity and deep fluid diversion ability of weakbase ternary compound system and its impact on increasing oil production and decreasing water cut were researched by means of instrument detection，chemical analysis and physical simulation guided by physical chemistry，polymer materials and reservoir engineering. Seepage resistance，shunt rate and oil recovery were the evaluation indexes. Results show that polymer concentration and carbonate micro particle number are the main factors which have influence on the transmission and migration capacity of the weak-base ternary compound system. Under the condition of the same viscosity，the deep fluid diversion ability of weak-base ternary compound system is reduced with the decrease of interfacial tension. However，under the condition of the same interfacial tension，it is enhanced with the increase of viscosity. The performance characteristics of weak-base ternary compound system can be evaluated by the transmission and migration capacity and deep fluid diversion ability from different aspects. Only when the two properties and reservoir properties achieve a reasonable match，the weak-base ternary compound system can obtain the best technical and economic results.

Abstract:There is usually strong bottom water energy after water flooding in Tahe fractured-vuggy carbonate reservoir.Thus the bottom water will have influence on remaining oil in subsequent water flooding and gas drive continuously，which has vital significance. Visible physical models were applied to simulation experiment of water flooding and gas drive. Interaction of strong bottom water and subsequent injected water and gas was displayed intuitively. Related influencing factors were discussed. Experimental results show that the strong bottom water has a promoting role on the subsequent development of remaining oil. Principle of interaction among bottom water and water injection，gas injection was different in various ways.In addition，the bottom water strength，fracture cave combination，gravity and other factors will influence this interaction. Research results provide experimental basis for EOR plan design of subsequent water flooding and gas drive. Quantitative matching of injected water and gas with the strong bottom water should be the key of subsequent further research.

Abstract:Flow conductivity of fracture network is one of the key factors influencing reformation effect in tight reservoir.New diversion chamber was designed. Indoor flow conductivity experiment was made to study the influence of closure pressure，sand concentration，sandbank height，proppant diameter and type and fracture network structure on the flow conductivity of fracture network，and orthogonal experiment was made to analyze the effect degree of different factors. The results show that with the increase of closure pressure，the flow conductivity of fracture network will decrease slowly，then sharply，finally gently；with the increase of sand concentration and sandbank height，the flow conductivity will increase；the flow conductivity increases with proppant diameter，and the loading capacity of large particle is relatively poor，resulting in quick decline of flow conductivity with the increase of closure pressure；the flow conductivity will increase with larger amount of secondary fractures and smaller distance to exit end. For the effect degree of different factors on flow conductivity，the influence of closure pressure is outstanding；the influence of secondary fracture distribution and proppant diameter is large；the influence of sand concentration and secondary fracture amount is relatively low；while the influence of sandbank height and proppant type is weak.

Abstract:The accurate description of the distribution of hydraulic fracturing fractures is an important prerequisite for the fracturing design and evaluation of fracturing effect. But the position and shape of the fractures have not been described before in the research of description of the branched fracture. So a branches model established on L-system was used and a plane simulation and description method of natural weak surface distribution was established. The natural weak surface was classified using fractal similarity principle，and the corresponding shear strength，tensile strength and the gradient of pressure loss of the fracture fluid after fracturing were known. The simulation method of branched hydraulic fracture distribution was put forward based on the established natural weak surface distribution model and the shear and extension law of fracture. The results show that the number of branched fractures is closely related to the net fracture pressure at shaft wall and difference between the maximum and minimum principal stress. There are multiple branched fractures near the major fractures of hydraulic fracturing and higher net fracture pressure at shaft wall brings more branched fractures. The smaller the difference between the maximum and minimum principal stress is，the more the branched micro fractures open and the larger the connected range is. By using this method，the plane fracture shape and opening condition with fractal characteristics can be simulated. This method also provides the basis for the formation mechanism of complex fracture.