Abstract:Combining core description，thin sections analysis，whole-rock X-ray diffraction and scanning electron micros copy technologies，the characteristics of mineral composition of fine-grained sedimentary rocks，sedimentary structure and laminations in the lower Es3 member in the Dongying sag were described in detail，by which lithofacies of fine-grained rocks were classified and their vertical evolution characteristics were analyzed using a case from the lower Es3 member drilled by Well FY1. The results show that the fine-grained rocks in the lower Es3 member is characterized by complex and variable mineral composition，frequent and weak bottom current reworking and abundant laminations. Based on the mineral composition and sedimentary structure，there are eleven types of lithofacies in the study area，and seven of them are mainly developed，which are parallel-laminated clay stone，interbedded calcareous limestone，parallel-laminated limestone，nonparallel-laminated limestone，parallel-laminated mixed sedimentary rock，nonparallel-laminated mixed sedimentary rock and massive mixed sedimentary rock. Their development environment are different obviously.The distribution of fine sedimentary facies is controlled by paleo-water depth and paleoclimate. The parallel-laminated clay stone are developed mainly in deep water in dry and cold reducing environment. Interbedded limestone develops when the paleoclimate changes from dry and cold to warm and wet. Parallel-laminated limestone develops in wide and deep water when the paleoclimate is semi-warm and wet. Nonparallel-laminated limestone develops when the paleoclimate becomes the warmest and wettest and the bottom current develops. Parallel-laminated mixed sedimentary rock develops when the water becomes shallower with unstable water delimitation and the paleoclimate becomes drier and colder. And the nonparallel-laminated mixed sedimentary rock will develop if there are bottom current. The massive mixed sedimentary rock develops in semi oxidation and reduction environment.

Abstract:The tight limestone in Jurassic Daanzhai Formation of Central Sichuan Basin is one of the most important tight oil reservoirs in China. The Daanzhai Formation is considered as ultra-low porosity and permeability reservoir with nanometer and micrometer pores and fractures. A total of thirty core plugs were saturated with saline water for days，and then nuclear magnetic resonance（NMR）T2 measurement was conducted. The results obtained show that there are four types of peak distribution patterns for NMR T2 spectrum，including unimodal distribution，bimodal distribution（dominated either by left peak or right peak）and pseudo triple-modal distribution. It is found that core samples with unimodal NMR T2 spectrum are characterized by nanometer pores with low permeability through comprehensive analysis of the statistic relationship between pore components and reservoir permeability and the microscopic characteristic of pores. Although T2 spectrum distribution shifts to short relaxation time，the permeability value can be high with a good relationship between components of larger pores and flowing capacity when connected intercrystal pores，extended intercrystal fractures and inter-layer pores within clay minerals develop well. When the T2 spectrum distribution shifts to long relaxation time，the permeability value can be low with a weak relationship between components of larger pores and flowing capacity if inter-shell and intercrystal pores are locally developed and intercrystal fractures or inter-layer fractures within shells has limited length. The micronscale fractures such as structural fractures and intercrystal fractures contribute to the increase of reservoirs permeability obviously.

Abstract:Good oil and gas shows have been discovered in Eogene magmatic rocks in the southern slope of Huanghekou sag，but due to the large differences of magmatic rock distribution，complex lithology and strong heterogeneity，the signaltonoise ratio of seismic data is low and the seismic response is poor，bringing difficulties to favorable reservoir prediction.In order to solve the above problems，based on the system analysis of sidewall core and logging and seismic data，“threephase”coupling relationship between magmatic rock facies，well logging facies and seismic facies was established，which helps to describe the distribution characteristics of magmatic rocks by using variance and amplitude attributes and wave impedance inversion effectively. Based on the relationship among sensitive seismic attributes，inversion and magmatic rock lithology，the temporal and spatial evolution history of magmatic activity was defined，and the patterns of magma activity were established in different periods. According to sidewall core and outcrop data，the magmatic rock reservoir features and main controlling factors of reservoir were analyzed，which helps to use root mean square amplitude attribute and wave impedance inversion method to describe the favorable reservoir of magmatic rocks under the constraint of the ancient landform background，and the prediction result was proved by drilling.

Abstract:With the advent of bottleneck of the conventional oil and gas resource exploration，tight oil and gas reservoirs are becoming more and more important for exploration and development. In order to further reveal the micro pore structure characteristics and their influences on reservoirs seepage，conventional mercury injection and constant velocity mercury injection method were applied to analyze comprehensively pore structures of tight reservoir in the Lucaogou Formation of Jimsar sag in Junggar Basin combining with casting thin section analysis，scan electron microscope observation and other means. The experimental results indicate that under dissolution and cementation conditions，the main pore type in the research area is characterized by intragranular dissolved pore，half filling pole，intergranular dissolved pore，intercrystal pore and intracrystal pore. Five types of the reservoirs were divided and evaluated respectively，on the basis of the conventional mercury injection curve distribution and its morphology，the porosity and permeability and the parameters characterizing pore throat size，sorting and connectivity. The configuration between pore throat and pore and the pore throat radius of the reservoir in the study area are different from those of conventional reservoir. Reservoir seepage is controlled by both pore throat radius distribution and pore-throat ratio distribution. The bimodal distribution of pore-throat ratio indicates a combination of two types of pores in the reservoir，which suggests a potential target that should be emphatically developed in this area.

Abstract:Based on detailed petrographic and cathodoluminescence analysis，the cathodoluminescence characteristics and diagenetic stage division of carbonates in the Zhujiang Formation of the Pearl River Mouth Basin were studied. The results show that：①Carbonate minerals of the Zhujiang Formation generally emit weak CL indicating the leading role of seawater during diagenesis of Zhujiang Formation carbonates；while some samples show strong-very strong CL，which was locally influenced by non-marine fluids. ②Different rock types exhibit different CL features under the same conditions of cathode.Reef limestone are with two end-member CL of very weak-no visible or strong-very strong CL，whereas dolomitized reef limestone emits extremely weak CL. Bioclastic limestone are characterized by very weak or no CL in general，but a few sam? ples with terrigenous minerals show strong orange CL，while bioclastic dolomitized limestone shows the features of very weak or no CL with dolomite and weak-strong CL with non-dolomitized parts. ③Three or four phases of calcite cements development are recognized in turn：fringing fibrous calcite（or bladed spar calcite）-scalenohedral calcite-equant or blocky calcite-calcite filling in micro-fractures or distributing along the stylolites. Fibrous or annular leaf calcite commonly has no CL. ④Diagenesis of Zhujiang carbonates experienced four stages：penecontemporaneous sedimentary，contemporaneous sedimentary，early diagenetic and middle-late diagenetic according to the fabric of cements under different dagenetic stages and environments and their cathodoluminescence characteristics.

Abstract:Secondary hydrocarbon generation of the Carboniferous-Permian coal-measure source rocks underlying Bohai Bay Basin since the Paleogene becomes petroleum research focus of eastern China for its great significance of oil-gas accumulation. With literature review on its distribution and geological characteristics，investigation methods and models of secondary hydrocarbon generation about the source rocks，initial point，kinetic mechanism and effectiveness evaluation are concluded as the crucial issues on secondary hydrocarbon generation research of the Carboniferous-Permian coal-measure source rocks. Moreover，the tectonic evolution analysis and geochemistry evolution reconstruction are suggested to determine the initial point of secondary hydrocarbon generation. Based on different initial point of secondary hydrocarbon generation，thermal simulation experiments should contribute to imply the properties and hydrocarbon generation kinetic mechanism of organic matter during secondary hydrocarbon generation processes. Combining with temperature and pressure conditions of different structural units，resources of secondary hydrocarbon generation is predicted to evaluate petroleum sources of deep horizons.

Abstract:To study the development characteristics of shale fracture-microfracture system，the main controlling factors and their influences on shale gas seepage and accumulation，fractures were divided into five types according to their morphology based on core and thin section observation and statistics，including bedding fractures，cut-layer high angle fractures，internal high angle fractures，internal low angle fractures and microfractures. Through analyzing effects of multi-parameters on fracture-microfracture，it is considered that the main factors controlling the generation and development of reservoir fracture-microfracture system include the brittleness mineral content，tectonic action，internal structure of rock and its heterogeneity，mechanics characteristics and formation confining pressure. And then combining with the fracture types and main controlling factors，the evaluation of reservoir cracks was done comprehensively. The horizontal cracks，such as the bedding fracture，can enhance lateral diffusion effect，and thus significantly promote the shale gas seepage and accumulation. Especially for those areas that experienced strong tectonic deformation and developed fold structures in southern China region，the lateral diffusion effect caused by bedding fractures and low angle fractures is obvious. Syncline and anticline shale gas reservoirs，which combine characteristics of both the North American shale gas reservoir（self-sourced and in-situ accumulation）and the traditional oil and gas reservoirs（hydrocarbon enriched at the high point of the structure），belong to composite accumulation pattern. In a closed petroleum system，developed fracture network often can make free gas seepage along fracture through lateral diffusion and gas reservoir is formed at the high point of the structure.

Abstract:Tight sandstone reservoirs have been a research focus of many scholars around the world in recent years. The tight sandstones of Chang81 member，as the most important pay bed of Honghe oilfield，mainly consist of feldspathic litharenite and lithic arkose，which are extra-low porosity and permeability reservoirs and are difficult to be explored and developed. The diagenetic events and the reconstruction of diagenetic sequence and porosity evolution history of Chang81 tight sandstones were analyzed and made clear by using an integrated approach of casting thin-section，cathode luminescence，rock pyrolysis，clay X-ray diffraction，capillary pressure curve test and reservoir sensitivity test. The results show that the tight sandstones of Chang81 member are currently in the stage A of mesodiagenesis，and they have mainly suffered from mechanical compaction，cementation and dissolution. About 50％of original porosity has been destroyed by the mechanical compaction and about 30% of original porosity is filled by calcite and kaolinite cements. However，the dissolution can improve the reservoir physical property to some extent. Reservoir space are characterized by intergranular dissolution pores，residual primary pores and microfractures. The pore throat structure is characterized by fine throat，micro-fine throat and micro throat and reservoir with fine throat is the target area for the next step of exploration and development. The reservoir sensitivity to flow velocity is medium-weak；its sensitivity to salt is medium；its sensitivity to water or to alkali is weak. It is not sensitive to acid. Its sensitivity to stress is also weak. The reservoir sensitivity experiment provides an important basis for reservoir stimulation and water flooding.

Abstract:In order to study the effect of temperature，oil displacement agent，wettability and their interactions on heavy oil thermo-chemical recovery，response surface methodology was used to design experimental schemes and analyze their results. The nature and the degree of the influencing factors and their interactions were studied in lab experiments. Contribution of various factors and their interactions on heavy oil thermo-chemical recovery were made clear by use of self-defined weight of influencing factors. The results show that the weight of temperature on heavy oil thermo-chemical recovery is 58%，the weight of chemical agent is 23.3%，and the weight of their interaction is 11.4%. Therefore，temperature，chemical agent and their interaction are the dominant mechanism of thermo-chemical recovery of heavy oil. Quantitative study on effect of various influencing factors and their interactions on recovery during thermo-chemical flooding makes synergistic effects of thermal and chemical agent clear. The study deepens the understanding on heavy oil thermal-chemical flooding mechanism.

Abstract:Fractured-vuggy carbonate reservoir has the features of strong heterogeneity and complex structure，whose reservoir space is mainly large caves，solution pore and fractures. Gas flooding is one of the important methods of development in this type of oil reservoir. In order to probe dynamic features，influencing factors and rules of gas flooding in the fracturedvuggy carbonate reservoir，a typical 2D visual model of fracture-vug was built to study the development of remaining oil of various types. Physical simulation experiments of nitrogen gas flooding were carried out to study the influencing factors of the nitrogen gas drive. The research results show that the nitrogen gas drive can activate the remaining oil of unswept areas during water flooding. The effect of nitrogen gas drive and flow characteristics of oil，gas and water are influenced by cavityfilling type，crude oil viscosity and energy of bottom water. The cavity-filling type mainly affects the percolation characteristic of the fluid and is beneficial to enlarge swept volume of the nitrogen gas flooding to a certain extent. The crude oil viscosity and the energy of bottom water affect the interaction between the nitrogen gas and bottom water，which may change the distribution of pressure field. Bottom water with strong energy will accelerate water breakthrough，but it can improve the effect of the nitrogen gas drive and oil recovery.

Abstract:Numerical simulation is of great importance as implementation guides of polymer flooding projects. However，there are still significant difficulties remaining in the history matching process of polymer flooding simulation due to uncertainties of some related parameters in polymer flooding. Based on laboratory experiments of polymer core-flooding，the reservoir simulation parameters for polymer flooding were determined by curve matching of water cut and oil recovery. A more reliable numerical simulation model of polymer core-flooding was then constructed. The effect of viscosity of polymer solutions，inaccessible pore volume，residual resistance coefficient and polymer adsorptive capacity and other related parameters on curves of water cut and oil recovery were analyzed. The sensitive coefficient was introduced in the model to evaluate the sensitivities of these parameters. Results show that the sensitivity order of different parameters to the increase rate of oil recovery and the decline rate of water cut is consistent. The sensitivity of these parameters from strong to weak is：polymer adsorptive capacity，viscosity of polymer solutions，residual resistance coefficient and inaccessible pore volume.

Abstract:Conventional SAGD is aimed mainly for the heavy oil reservoirs with thick formation and high viscosity. Haqian1 block has the geological features of thin formation and super heavy oil. Based on conventional SAGD，3D physical simulation experiment technology was applied for the research on adding nitrogen gas and dissolve agent to improve the development effect of the conventional SAGD. The results show that nitrogen gas can release the steam overlap and lower the steam chamber pressure，resulting in expanding the effective sweep area of steam chamber. Dissolve agent can decrease the viscosity further with the steam carrying，leading to quantitative change of steam chamber development and producing the reserves of lower reservoir effectively. Nitrogen gas and dissolve solvent aided SAGD can respectively increase the cumulative oil steam ratio by 0.036，0.023 mL/mL，and increase the oil recovery by 10.9% and 6.9%，compared with those of convention SAGD and nitrogen gas aided SAGD. In a word，nitrogen gas and dissolve solvent aided SAGD technology can obtain impressive effect.

Abstract:In the process of the development of geothermal resources，the geothermal tail water must be recharged in order to realize sustainable utilization of geothermal resources in sandstone reservoirs of sedimentary basin and keep heat reservoir pressure constant. But unreasonable mining and filling well pattern is easy to cause increase in pressure of recharging wells and decrease in the temperature of water collecting wells. A well pattern evaluation method for geothermal resources recycling was established using numerical simulation technology aiming at the key problem that restricting recharge. Geothermal fluid migration and heat transfer were simulated numerically based on generalized geothermal geological model and the software Petrosim-Tough2 was used to conduct coupled simulation of seepage field and temperature field. And then according to the determined optimal water output of single well，for different number ratios of mining well and filling well and distance between mining well and filling well，the mode of optimal well pattern was established to avoid heat breakthrough through economic evaluation and analog calculation. This method is used to effectively solve problems caused by unreasonable well network pattern of mining well and filling well during geothermal resources development in sedimentary basins，which include the thermal breakthrough and the high recharge pressure and can result in engineering and technical problems leading to high cost. This paper provides good technical support for the realization of the geothermal tail water recharge in sedimentary basins and green sustainable utilization of the geothermal resources.

Abstract:In order to characterize the apparent permeability of shale matrix and research its dynamic variation，apparent permeability model of organic and inorganic matter has been derived theoretically by considering absorption，slip，diffusion and seepage based on the fractal theory of tortuous capillary bundles and microscopic gas percolation mechanism. Thereby a fractal apparent permeability model of shale matrix is built by weighting the area factor. Reliability of this model was verified through experimental results and existing permeability calculation models，and then the effect of pore structure（pore size，porosity，fractal dimension），external environment（pressure，water saturation，effective diameter correction factors）and gas property on the apparent permeability of the shale matrix was quantitatively analyzed. The research results show that for the inorganic pore，with the decrease of formation pressure，the apparent permeability presents overall downward trend，which is influenced by the increase of water film thickness and the decrease of effective pore size，along with the increase of fractal dimension of tortuosity and the decrease of pore fractal dimension，and the gas slippage effect increases but the adsorption is still the main influential factor；for the organic pore，the permeability presents overall upward trend when the correction factor of effective diameter increases gradually with the desorption of shale gas，and the fractal dimension of tortuosity decreases while that of pore increases，and thus the slippage effect and Knudsen diffusion are enhanced in the small pore with low pressure；the variation of the apparent physical properties with the pressure and the adsorbed layer is different for the organic and inorganic matter，and the difference of permeability between the organic and inorganic matter is large. Therefore，the apparent permeability of the organic and inorganic matter in shale matrix should be calculated respectively to avoid errors brought by this difference.

Abstract:In the middle-high permeability sandstone oilfield with strong heterogeneity，invalid recycling of the injected water is formed along the natural high permeability belt at high water cut stage due to the development and geological reasons，which results in poor implementation of tapping the potential of remaining oil. Therefore，identifying the predominant streamline field accurately at this stage is very important for taking effective measures to control the predominant streamline field and tap the potential of remaining oil. A certain block in Shuanghe oilfield at high water cut stage was researched.Judging criterion for predominant streamline field was made through fuzzy comprehensive evaluation and streamline numerical simulation technology. Injected water volume and efficiency of the injection wells in single well group were determined in different affected directions to response well through streamline distribution，injection-production allocation factor and injection efficiency between oil well and injection well in each layer. Rule of plane distribution of the predominant streamline field between oil well and injection well in the studied area was studied qualitatively and quantitatively. Until October 2015，composite water cut of the studied area had dropped by 1.5% and the cumulative incremental oil had been 3.15×104 t and the recovery had been improved by 1.2%. Good effect of stabilizing oil and controlling water cut had been achieved since vectorization adjustment of variable streamline was made in the field in June 2013.

Abstract:In view of the current commercial numerical simulation software of chemical flooding is not suitable for low permeability reservoir，the mechanism of polymer flooding in the low permeability reservoir was studied by laboratory experiments. The key physical property parameters of polymer flooding in the low permeability reservoir in SINOPEC Jiangsu oilfield were characterized quantitatively，and the mathematical model of polymer flooding in the low permeability reservoir was established by using the pseudo-start-up pressure gradient and nonlinear model respectively，and the model was solved by numerical method. Research results show that the suitable relative molecular mass is 6 million to 9 million for the polymer flooding in the low permeability reservoir. The pseudo-start-up pressure gradient model ignores the bending section of the percolation curve and exaggerated the seepage resistance of the low permeability reservoirs，so the nonlinear model is more suitable for the simulation of polymer flooding process in the low permeability reservoir. The application in Sha7 block of Jiangsu oilfield shows that the numerical simulation method based on the nonlinear model can consider the influence of start-up pressure gradient for the polymer flooding in the low permeability reservoir，and the simulation results are consistent with the actual production data of the oilfield. It provides an effective technique and method for the optimization and dynamic prediction of chemical flooding in the low permeability reservoir.

Abstract:The spontaneous imbibition occurs during development of shale oil and gas by using technologies of horizontal drilling and hydraulic fracturing. Shale reservoir pore structure and mineral composition are the important factors that have an impact on shale spontaneous imbibition. The impact of pore structure，mineral composition and direction of lamination on shale spontaneous imbibition rate was studied through spontaneous imbibition experiments of shale samples，and the pore connectivity of shale reservoir was evaluated by using the slope of spontaneous imbibition curve. The results show that shale reservoir pore connectivity is poor and the slop of spontaneous imbibition curve is significantly lower than the theoretical value compared with conventional oil and gas reservoirs. Lamination direction will also have an impact on the spontaneous imbibition，and the slope of spontaneous imbibition curve tested along the lamination is usually higher than that tested against the lamination. But the experiment results of some samples also show that the slope of spontaneous imbibition curve tested along the lamination is comparable with that tested against the lamination，which is probably due to the fact that higher content of hydrophilic mineral in shale reservoirs can weaken the impact of lamination on the direction of water migration.Spontaneous imbibition behavior is closely related to the composition of the shale minerals. When the content of clay minerals is high，the original pore structure of shale changes under the effect of water swelling，which would result in the decrease of the slope of spontaneous imbibition curve if the experiment was repeated. When the content of brittle minerals，like quartz，in shale is high，the spontaneous imbibition curve would show little change in the repeated experiment，which indicates a good repeatability. The greater the slope of spontaneous imbibition curve is，the better the permeability is，and thus it is more conducive to the development of shale oil and gas.

Abstract:According to the nonlinear flow characteristics in tight oil reservoir，tree-like fractal theory was used to characterize the complex multi-scale explosive fractures net and a nonlinear flow model of explosive fracturing in hydraulic fractured layers was established. According to the different flow form of tight oil in the reformed formations，the flow area was divided into three zones，and then the coupling productivity formula of the three areas was derived. Analysis results of influencing factors of the productivity show that：the single-well productivity of explosive fracturing is 1.5 times that of conventional hydraulic fracturing. Larger fractal dimension of fracture space and tortuosity bring larger area percentage of explosive fractures and higher effective permeability of swept area of secondary fractures，and thus the productivity is higher. Productivity increases with the decreasing in bifurcation angle and the increasing in stimulated reservoir volume. So in the practical application，low energy release rate dynamite or multistage reaction rate dynamite should be chosen to reduce the bifurcation angle and magnify reservoir volume and productivity.

Abstract:Most of the low permeability reservoirs are tight and shale reservoirs，with small pore，fine throat and high filtration resistance. During the fracturing fluid flowback process，a great quantity of the fracturing fluid is retained in the layer，which causes the low fluid flowback. The mathematical model of fracturing fluid flowback was built based on the microscopic percolation of the capillary bundle model to study the influencing factors of fracturing fluid flowback in different diameter capillaries. Core test was done for natural cores in Fan 154 block of Shengli oilfield to research four influencing factors on flowback rate，including core permeability，oil viscosity，flowback pressure difference and interfacial tension between oil and fracturing fluid filtrate. The results show that the core permeability has greater influence on the flowback rate. When the permeability decreases from 1.276×10-3 μm2 to 0.13×10-3 μm2，the flowback rate declines by nearly 20%. When the oil viscosity decreases from 6.459 mPa?s to 1.192 mPa?s，the flowback rate increases by nearly 15%，and the flowback rate has the same increment when the interfacial tension between oil and fracturing fluid filtrate decreases from 14.617 mN/m to 0.021 mN/m. The flowback rate increases with the flowback pressure difference. But when it is higher than 8 MPa，the flowback pressure difference has smaller effect on the flowback rate.