Abstract:The 8th member of Shihezi Formation in Block Su6 of Sulige gas field is the main gas-producing strata of the Sulige gas field in the Ordos Basin. However，the understandings on the sedimentary characteristics have long been controversial and the cognition for evolution of sandbodies have remained unclear. Based on the data of rock lithology，sedimentary architecture，cycle characteristics and other sedimentary facies indicators，the 8th member of Shihezi Formation in Block Su6 belongs to the fluvial sedimentary facie. Furthermore，works have been made to that the lower 8th member of Shihezi Formation is the braided river facies in which microfacies of central bar，braided channel，floodplain and overbank develop；while the upper 8th member is the meandering river facies in which marginal bar，abandoned channel，floodplain and overbank develop. According to the characteristics of multistage positive cycle of natural gamma logging curve and the difference in incision degree，the positive cycle superposition in the target layer of the study area can be subdivided into 4 types：aggradation superposition-strong incision，aggradation superposition-medium incision，retrogradation superposition-medium incision and retrogradation superposition-poor incision. According to the difference of positive cycle characteristics and a comparison method based on cyclic and hierarchical control，the lower 8th member can be subdivided into 2 sets of subzone and 6 sets of single layer from bottom to up，while the upper 8th member can be subdivided into 2 sets of subzone and 4 sets of single layer. On this basis，through the identification of single channel and the extraction of channel architecture elements，the evolutionary process of channel sand body in the study area was divided into 10 periods and 4 stages. The 1st，2nd and 3rd periods mark the evolution of the pebbly braided river；the 4th，5th and 6th periods indicate the evolution of the sandy braided channel；the 7th and 8th periods correspond to the evolution of the pebbly meandering channel，and the 9th and 10th periods are characterized by the evolution of sandy meandering channel.

Abstract:The pore structure of He8 reservoir in eastern Sulige Gasfield of Ordos Basin is complex，and the study on seepage laws is relatively weak. It is difficult to evaluate the reservoir quality by conventional methods. Therefore，techniques of casting thin sections，scanning electron microscope，rate-controlled mercury penetration，nuclear magnetic resonance and microscopic waterflooding model based on real sandstone were used to study microscopic pore structure and influencing factors on movable fluid saturation. The results show that the types of reservoir space are mainly residual intergranular poreintercrystalline pore，intercrystalline pore-debris dissolved pore and microcracks-micropore，and their development degree successively decreases and their physical properties become worse in order. The reservoir seepage capacity，oil isplacement efficiency，mine recovery and movable fluid saturation also decrease successively and the corresponding oil displacement pattern changes from homogeneous network-like flooding to finger-like flooding. Nuclear magnetic resonance data show that the average saturation of movable fluid in He8 reservoir is 39.16%，and the types of reservoir are mainly II，III and IV. The movable fluid saturation is positively related to porosity，permeability，residual intergranular pore face rate，average throat radius，effective pore volume and throat volume，and it is negatively related to pore throat radius ratio.

Abstract:The research of microscopic pore structure characteristics is the core issue of shale gas reservoir，and the summary of influencing factor is mainly based on single factor analysis. The causes and differences of different types of shale gas reservoir and its microscopic pore structure were summarized from the aspects of petrology，sedimentology and organic geochemistry. The result shows that shales formed in different sedimentary environments have very different microscopic pore structure after a series of diagenetic and thermal evolution. The sedimentary environment determines the content of TOC，brittle minerals and clay minerals in shale，which is the material foundation for the formation of microscopic pores. The types and development degree of microscopic pore structure vary with diagenetic evolution stages of shale. The influence of thermal evolution on microscopic pores shows that a large amount of organic matter pores occur with the increase of maturity and the specific surface area and pore volume will change with the transformation of clay minerals. Based on multi-factor analysis，three-element coupled control on microscopic pore structure was proposed including sedimentary environment，diagenetic evolution and thermal evolution，and the mainly controlling elements at different evolution stages were also analyzed.

Abstract:Since the coring data and indoor test data of deep coal seam are few，it is difficult to identify the key parameters of coal seam structure，maceral，gas content and permeability，which is not conducive to the prediction of favorable coalbed methane development zones. To solve this problem，the logging data were compared with the laboratory test data and the injection pressure drop testing data using the mathematical statistics method to compare. The log interpretation model of coal reservoir parameters was established and applied to further coal seam evaluation in the study area. The results show that the errors resulted from the logging model computation of components of coal industry，coalbed methane content and permeability logging are 0~13.8%，1.9%~16.5% and 4.2%~28.6%，respectively. The model is effective and reliable and has a good application prospect. The geological parameters of coal seam thickness，permeability，gas content and coal seam structure in the study area were calculated. On this basis，the coal seam was divided into class Ⅰ，Ⅱ and Ⅲ. The theoretical gas production is higher than 1 000 m3/d in the class I which is a high yield gas area；the theoretical gas production is between 500 and 1000 m3/d in the class Ⅱ which is a medium gas producing area；and the theoretical gas production is less than 500 m3/d in the class Ⅲ which is a low production area.

Abstract:High production of industrial oil and gas has been obtained in Well AH12 for the first time，which opens a new exploration field in high-efficiency reservoirs in Maxi slope. The hydrocarbon accumulation conditions and rules in the Badaowan Formation of Maxi slope are unclear，and the oil and water relations are complex，resulting in the failure of several exploratory wells. A large amount of data of geology，seismic，engineering and laboratory test were comprehensively applied to analyze the reservoir type，accumulation characteristics and patterns of reservoirs in the Badaowan Formation，and the exploration directions were pointed out. The results show that the oil and gas of the Badaowan Formation were mainly migrated from the source rock in the Permian Fengcheng Formation. The high-quality sand bodies of subaqueous distributary channel in the braided river delta of the first member of Badaowan Formation are favorable reservoirs；while the top lacustrine mudstones of the formation act as the cap rock. On this basis，a favorable reservoir-seal assemblage was formed.Two types of high-effective carrier system，the straight-through type and the relay type，were built at the high angle faults that formed during the Hercynian-Indosinian and the Indosinian-Yanshan periods. The oil reservoir types in the study area are fault-block type and fault-lithologic type，which are controlled by inherited nosing structure，lithofacies and effective layouts of faults and sand bodies. The model of hydrocarbon reservoir formation is characterized by“source rock supplying hydrocarbon，faults providing migration paths through strata，hydrocarbon accumulation in nosing structure and faults and lithology controlling reservoirs”. The middle-shallow layer hydrocarbon exploration should be based on the structural background，and more attention should be paid on effective oil-migrating faults and zones of fault nose and uplift. Reservoirs which are covered by the flooding shale in the Karamay，Badaowan and Sangonghe Formation are the most favorable zone.

Abstract:The Yuertusi Formation in the Lower Cambrian is one of the important source rocks in the deep-buried carbonate sediments，Tarim Basin. It is overlaid by the lower-middle Cambrian reservoir which is platform-edge reef bank facies and has good physical property and large-scale distribution. With the deepening of the exploration，a new understanding on the distribution of the source rock in the Yuertusi Formation was proposed. On this basis，the single-well models of thermal history and hydrocarbon generation and migration were built to further define the distribution of effective liquid and gaseous hydrocarbon source rock and determine the dominant directions of hydrocarbon migration using the basin modeling technology，and finally the favorable zones of petroleum migration and accumulation were predicted. The research result suggests that：①the source rock in the Yuertusi Formation experienced two main hydrocarbon generation periods，which are the late Caledonian movement and the late Hercynian movement under the control of tectonic and hydrothermal activity，and the thermal evolution degree was relatively high in the east and relatively low in the west；②After the Permian，the source rock was mainly in the stagnation stage of hydrocarbon generation and its scope of expanded gradually，except the region from the southwest edge of the Bachu uplift to the southwest of the Tarim Basin where the source rock entered the hydrocarbon generation peak；③the liquid hydrocarbon accumulated in the low uplifts during the middle Caledonian and in the slopes around depressions during the late Caledonian，while the gaseous hydrocarbon mainly accumulated in a large scale in slopes around depressions from the late Caledonian to the late Hercynian and migrated along faults，up into the overlying strata，and after the Permian，the favorable hydrocarbon accumulation zones are basically finalized except the southwest of Tarim Basin，which are the large-scale palaeo-uplift and the low peripheral uplifts and slopes；④the junction of oil and gas occurred in the northern Shuntuoguole during the late Hercynian，which makes it the most favorable hydrocarbon accumulation zone；⑤the tectonic inversion during the late Hercynian in the southwest of Tarim Basin destroyed most of the early reservoirs and the favorable hydrocarbon accumulation zone is the southwestern part of the Bachu uplift. Nine favorable zones for liquid hydrocarbon accumulation and ten favorable zones for gaseous hydrocarbon accumulation were predicted.

Abstract:The forming environment，genesis and distribution rule of the Oligocene lacustrine gypsum-salt rock in western Qaidam Basin have been not clear for a long time，which hinders the progress of petroleum exploration. In order to solve these problems，the sedimentary petrology and geochemical methods were used to study the types and characteristics of gypsum-salt rock，the nature of water bodies during deposition，temporal and spatial distribution and development modes. The results show that the Oligocene gypsum-salt rock in the lower Ganchaigou Formation in western Qaidam Basin is mainly layered halite，followed by gypsum rock，a little glauberite and mirabilite，and it is well euhedral and formed during primary deposition. The gypsum rock is mainly developed at the late stage of water regressive deposition. The sedimentary paleoenvironment has the characteristics of semi-saline and saline brackish and deep water，anoxic water body and low temperature.Its formation mechanism is that the crystalline precipitates due to the evaporation and concentration in a supersaturated lake. The vertical distribution of the gypsum rock is controlled by the fluctuation of lake level. There are 6 key salt-forming periods. The gypsum-salt rock is confined in a zonal distribution in the plane with multiple sub salt-forming centers，which is controlled by the paleomorphology of the lake bottom. Based on the evolution of the Oligocene water body of the lake basin in western Qaidam Basin，there are mainly two development model-the late salinization stage and the wide salt lake stage. In the early stage，the development of gypsum-salt rock mainly formed in the depression area with a limited distribution，while in the late stage，the gypsum-salt rock was distributed widely，extending to the low amplitude uplift area.

Abstract:Research on sedimentary environment of the 3rd member of Funing Formation in Hai’an Sag is weak and disputed. Most studies are limited to sub-sags，and systematic research on the whole Hai’an Sag is rare. This paper is based on the abundant logging，core，analytical laboratory data and isochronous stratigraphic framework. Combined with the petrology，grain size analysis，sedimentary structures，electric logging and sand distribution，the identification signs of the beachbars were demonstrated，and the types of sedimentary microfacies，distribution rules，formation conditions and sedimentary model were analyzed. The results show that the 3rd member of Funing Formation in Hai’an Sag is dominated by the beachbar deposits. The beach-bar is common in the shallow lake. The jumping components show two straight lines in the curves of grain-size cumulative probability. The sedimentary structure reflects the wave effect. The distribution of sand body presents oval-like or band-like shape and is parallel to the shoreline distribution. The beach-bar is controlled by multiple factors，which can be summarized as source supply，paleogeomorphology and dynamic conditions of palaeo-wind（wave）. During the sedimentation of the 3rd member of Funing Formation，the south wind prevailed in Hai’an Sag. Waves continued to propagate from south to north，forming a broad area influenced by wave in the gentle slope on the south side of the Jianhu Uplift. Under the action of waves and coastal currents，the sand bodies of the wave-controlled delta in the northern Gaoyou Sag were redistributed，which provides a material basis for the formation of the beach-bar in Hai’an Sag.

Abstract:The Paleogene Shahejie Formation in Liaodong Gulf area is rich in oil and gas resources，which is an important target for exploration and development of middle-to-deep hydrocarbon reservoirs. J Oilfield is a typical middle-to-deep hydrocarbon reservoirs in Liaodong Gulf. The calcareous sandstone was drilled by development wells there，which affected the quality of reservoirs and restricted the effect of oil field development. Based on the core，thin section，SEM，drilling and logging data，the characteristics and genetic mechanism of calcareous sandstone and its controlling factors of the second member of Shahejie Formation in J oilfield were discussed. The results show that the formation and distribution of calcareous sandstone are affected by both sedimentation and diagenesis. The calcareous sandstone is characterized by fine granularity，low oil saturation，poor physical property and high density，which is resulted from the diagenesis of shale at the top and bottom of the sandstone. Affected by the sedimentation，the type and vertical position of carbonate cementation are controlled by the sediment thickness and rhythm of sandstone，while the sedimentary facies and mudstone thickness affect the horizontal distribution and cementation degree of the calcareous sandstone. Based on the horizontal distribution characteristics of the mudstone in the first member and the sandstone in the second member of Shahejie Formation，the horizontal distribution of the calcareous sandstone in the second member of Shahejie Formation was predicted. The center of the basin，characterized by thin sandstone and thick mudstone，is the favorable development area of calcareous sandstone and its development degree controls the quality of reservoirs.

Abstract:The Wufeng and Longmaxi Formation in Pengshui-Wulong area of southeast Chongqing is a normal pressure formation. The geological characteristics and production characteristics of normal pressure shale gas were systematically analyzed based on field geological survey，observation of cores from shale wells，shale tests，and production data of 5 normal pressure shale gas wells. The Wufeng and Longmaxi Formation in Pengshui-Wulong area was deposited in deep continental shelf with large thickness（more than 20 meters），high total organic carbon content（about 2%-6%），high siliceous content（more than 45%），medium physical property（porosity 2%-5%），micro-fissure development，medium preservation condition and normal pressure（formation pressure coefficient 0.8-1.2）. According to the characteristics of flowback，fluid properties，production and pressure variation in the process of shale gas well production in Pengshui-Wulong area，the normal pressure shale gas has three production modes-natural flowing，induced flowing and artificial lifting. Three stages can be divided as low gas-liquid ratio stage，two-phase transition stage and stable production stage. Entering the stable production stage，the normal pressure shale gas has the characteristics of low initial production and slow decline rate.

Abstract:Affected by reservoir conditions such as high formation pressure，thin thickness reservoir and active edge or bottom water，some heavy oil reservoirs suffer from large heat loss，high cost and low recovery during thermal recovery. Therefore，effective development is difficult. Through indoor flooding experiments，the enhanced oil recovery mechanism of viscosity reducer flooding，polymer flooding and chemical viscosity-reducing compound flooding in the heavy oil reservoir was studied，and the effect of different flooding systems on the enhanced oil recovery of heavy oil was compared and analyzed.The results show that the chemical viscosity-reducing compound flooding system that contains water-solubility viscosity reducer and polymer can increase the recovery efficiency by 16.04%，which is superior to the flooding using the viscosity reducer or the polymer system alone. From the viewpoint of oil change efficiency，the polymer concentration in the slug of compound flooding was optimized to be 0.3%，and the water-solubility viscosity-reducer concentration was optimized to be 1.0%；from the view point of improving the recovery efficiency，the injection pattern of the viscosity reducer post-slug and the polymer pre-slug is optimized and the recovery efficiency can be increase by 7.2% to 10.7%. On this basis，the optimal volume ratio of water-solubility viscosity reducer to polymer slug is 3∶2. In the heterogeneous model and the microscopic visualization model，the chemical viscosity-reducing compound flooding not only has the oil-displacement mechanism of both the viscosity-reducing agent and the polymer，but also produces a synergistic effect，which can greatly improve the sweep range and oil washing efficiency of heavy oil compared with chemical flooding by a single agent.

Abstract:The fracture-matrix model was designed by improving traditional oil displacement experimental device to simulate fractured reservoirs. Miscible continuous CO2 injection and CO2 huff-n-puff process were carried out in fracture-matrix system to investigate the EOR characteristics of miscible CO2 injection. The composition of produced oil during CO2 injection was tested to analyze the main mechanism of oil production at different continuous gas injection times. The results indicate that the miscible continuous CO2 injection cannot significantly increase oil recovery of the fracture-matrix model.The oil recovery factor was only 18.2% when the length of matrix was 10.0 cm，and decreased to 14.1% when the length of matrix was 20.0 cm. The compositional tests of crude oil show that after 0-8 h of CO2 injection，the content of produced oil was similar to that of the initial crude oil. Oil swelling were the major production mechanism contributing to the oil recovery during this period. The most of the produced oil during continuous CO2 injection was produced by oil swelling. After 8-40 h of CO2 injection，the content of produced oil changed obviously because the hydrocarbon extraction is the main oil production mechanism. However，the incremental oil content is little during this period. The oil recovery during the CO2 huff-npuff process may be significantly enhanced by 72.8% to 73.9% after continuous CO2 injection. But the oil recovery is strongly influenced by differential production pressure. When the production pressure difference was 5 MPa，the oil recovery factor varied between 7.9% and 12.4%. When the production pressure difference was increased to 20 MPa，it was up to 73.9%.

Abstract:In order to quantitatively characterize the effect of osmotic pressure on the imbibition displacement of the tight sandstone reservoir，a semi-analytical mathematic model for the imbibition of tight sandstone reservoir considering the osmotic pressure was established based on the capillary force function and the osmotic pressure equation. Based on the established model，the parameter sensitivity of imbibition salinity，maximum relative permeability of water phase and oil phase，relative permeability coefficient of water phase and oil phase and oil-water viscosity ratio were analyzed and compared with the core experiment results so as to correct the model parameters. The research indicates that the effect of imbibition displacement is more obvious when the salinity difference of reservoir fluid and imbibition fluid is larger，and the osmotic pressure mainly affects the middle position of the imbibition displacement. The order of parameters influencing the imbibition is as follows：the relative permeability coefficient of water phase>the maximum relative permeability of water phase>the ratio of oil-water viscosity>the relative permeability coefficient of oil phase>the maximum relative permeability of oil phase.The oil-water viscosity ratio has the most significant influence on the salinity distribution. The relative permeability coefficient of water phase and maximum relative permeability of water phase mainly affect the salinity distribution of the propulsion front. The relative permeability coefficient of oil phase and the maximum relative permeability of oil phase have almost no effect on the salinity distribution. The correction coefficient of the imbibition displacement model is about 0.7. The correction coefficient of the stable imbibition time has a good linear correlation with the maximum relative permeability of water phase.

Abstract:Imbibition is one of the important oil recovery mode for the tight oil reservoir. Imbibition mechanism between the fracture and the matrix was studied thoroughly，but there is no agreement on the influence and contribution of imbibition and displacement on the recovery degree in the seepage stage. Therefore，based on the pore structure distribution characteristics and the pressure characteristics of the fracture system and matrix system of Chang8 tight oil reservoir in Shuimogou area of Yanchang Oilfield，NMR technology was used to quantitatively characterize the influence of displacement method and imbibition method on the recovery degree and the distribution of movable fluid. The experimental results show that the main controlling factor on the seepage ability of the tight oil reservoir in the study area is the throat radius；the recovery degree of the matrix system in the fractured core samples is mainly controlled by the imbibition，and the recovery degree of the fracture system is mainly controlled by the displacement. The recovery of the displacement and imbibition methods based on NMR quantitative analysis was 32.30%-39.32% and 9.60%-19.49% respectively. The microscopic pore structure of the core samples in the tight oil reservoir is complex，and the flow direction of the fluid during the process of imbibition and displacement is affected by the wettability of the microscopic pore throat，so the distribution of the movable fluid obtained by the imbibition and displacement method has no strict pore size boundaries.

Abstract:Low salinity water flooding，characterized by low cost，has become the research focus of the scholars at home and abroad due to the low oil price in the recent years. However，the microscopic displacement mechanism of remaining oil by the low salinity water flooding is not clear. The cores from Tazhong4 paleo-oil reservoir were tested. The remaining oil was divided into four types（block，net，island and membrane type）with the help of CT scanning technique and D-T2 two-dimensional NMR techniques. The production of the four types of remaining oil by the low salinity water flooding was analyzed and verified by energy spectrum experiment. The results show that the block-type remaining oil decreases gradually and the other types of remaining oil increase in the process of formation water flooding. When the low salinity water was injected，the proportion of the membrane-type remaining oil begins to decrease and the proportions of the other types remain the previous tendencies. The results indicate that the low salinity water can promote the desorption of crude oil from the surface of the rock and displace more membrane-type remaining oil，which eventually improves the recovery efficiency.

Abstract:Aiming at the problems of low permeability，development of fractures，bottom water coning and poor selectivity of plugging agent in buried-hill reservoirs with bottom water，the feasibility of nitrogen foam controlling the water coning and enhancing the oil recovery was evaluated. Based on the optimization of foaming agent，the three-dimensional bottom water model，which was designed and produced according to geological data，was used to simulate the process of nitrogen foam huff and puff in horizontal well under the action of bottom water. Meanwhile，the effect of nitrogen foam controlling the water coning and enhancing the oil recovery and the impact of fracture and injection pressure were investigated. Experimental results show that in the fracture-free low permeability matrix model，the optimal nitrogen foam that is used for huff and puff can make water cut decrease by 78.49% and oil recovery increase by 6.85%. It shows that the nitrogen foam has a significant effect on controlling the water and enhancing the oil recovery，which demonstrates that the injection of nitrogen foam increases the formation energy and plays the role of inhibiting the bottom water coning. In the case of matrix-fracture model，the water cut can be reduced by more than 17%，and the oil recovery can be increased by about 2%. The existence of fractures directly affects the increase of oil recovery. The results show that the flow control ability of nitrogen foam is limited in the presence of fractures. Increasing the injection pressure can further supplement the nitrogen foam energy so as to ensure the effect of controlling the water coning and enhancing the oil recovery. In addition，high strength starch gel was used to seal the fractures，which can make oil recovery of nitrogen foam huff and puff further increase by nearly 2 percent.

Abstract:In order to study the oil displacement effect of compound of different molecular weight polymers，core flooding experiments were carried out by using on-line nuclear magnetic resonance（NMR）imaging technology with 10 million single molecular weight polymer and compounded polymer. According to the NMR T2 spectrum signal after water flooding stage and polymer flooding stage，the quantitative characterization of the recovery proportion in pore throats of different sizes was performed and analyzed. The results show that by using polymers with same viscosity and cores having similar pore structure，the recovery and the proportion of fluorine oil recovered from the medium-and small-sized pore throats to total oil by compounded polymer are respectively 1.5% and 7.1% higher than those by single molecular weight polymer. The small molecular weight polymer in the compounded polymer has a small volume and can effectively displace the fluorine oil in the medium-and small-sized pore throats，while the large molecular weight polymer also has good displacement effect in large pores. Therefore，compared with the single molecular weight polymers，the compounded polymer can drive oil in a wider pore throat size range，and ultimately achieve better displacement effect.

Abstract:As the technology of flue gas flooding is increasingly used，the severe corrosion of the flue gas on the wellbore arises becomes more important. Corrosion experiment on N80 steel was conducted at simulated high temperature and high pressure using the flue gas corrosion testing device. The composition and morphology of the corrosion product were analyzed by X-ray diffractometer，scanning electron microscope and energy spectrometer. The effect of temperature，pressure，flow velocity and O2 and SO2 content on the corrosion rate of N80 steel was studied. The results show that the corrosion rate decreases fast with the increase of time and gradually reaches to a stable state after 72 h under the simulated dynamic corrosion environment of flue gas at high temperature and pressure. The corrosion product of N80 steel is mainly composed of FeCO3，Fe3O4 and Fe2O3. The corrosion product was arranged disorderly with incomplete coverage and annular distribution.The corrosion rate increases with temperature when the temperature is lower than 60 ℃ and reaches to the maximum at 60 ℃. When the pressure and the concentration of carbonic acid increase，the corrosion rate increases. With the increase of flow rate and oxygen content，the corrosion rate increases. With the increase of SO2 content，the corrosion rate shows a trend of decreasing first and then rising.