Abstract:The geometric characteristics of compression-torsion faults and their evolutionary laws are complex and need to be further understood，which is of great practical significance for oil and gas exploration in western compression-torsion basins. It is revealed by the field outcrop exploration and high-density 3D seismic data process result that the high-angle thrust faults are characterized by notable strike slip accompanied by multiple series of secondary shear faults，forming a typical compression-torsion fault zone in Wuxia area in the northwestern margin of Junggar Basin. The competence difference of clastic rocks controls the vertical decoupling propagation and segmented development of the compression-torsion fault.The intensity of tectonic activity controls the fault development series and geometric patterns. The profile geometric patterns of compression-torsion faults are identified in“braided”，“flower”，and“step”shapes，corresponding to the plane distribution patterns of“network”，“plume”，and“echelon”from deep to shallow layers with the gradual decline in intensity.The discovered oil and gas reservoirs cast light on the significant differences in vertical oil and gas transmission capacity of compression-torsion faults with different geometric patterns，which is a controlling factor for the spatial distribution of oil and gas resources in the compression-shear basin.

Abstract:Songxi-Songdong transfer zone in the northern Qiongdongnan Basin was analyzed with seismic reflection data and the balanced cross-section technique to understand the generation and evolution of the convergent overlapping transfer zone in rift basins. Consequently，it belongs to the convergent overlapping transfer zone between faults 5 and 6. Its evolution has gone through four tectonic stages：initial development（Eocene），stereotyped development（depositional period of Yacheng Formation），stable development（depositional period of Lingshui Formation），and extinction（depositional period of Sanya Formation）. According to the existing genetic theory of transfer zones and the results of balanced cross-section analysis，it is considered that Songxi-Songdong transfer zone is generated mainly from the segmented growth of faults 5 and 6，and its generation and evolution processes can be explained by the theory of stress reduction zones. During the chasmic stage，Songxi-Songdong transfer zone is always tectonically high and can entrap and accumulate hydrocarbon generated by the sags on both sides. In addition，the storage and reservoir can be effectively enhanced by the plentiful secondary faults formed under the influence of the stress reduction zone and the weathering and erosion during the uplift stage of the basin.All these signal the extremely favorable conditions for hydrocarbon accumulation.

Abstract:The reservoir in the huge thick pre-salt lacustrine carbonate of M Oilfield in Brazil Santos Basin is silicified，and there are no relevant researches to clarify its geneses. Based on the data of core，thin section，fluid inclusion and X-ray fluorescence，the various silicification geneses in M Oilfield are discussed and their effects on reservoir are analyzed. The results show that the silicification in M Oilfield is common；more than half of samples in reservoirs are affected by the silicification，but only 17% of them are moderately and strongly silicified；the silicification can be divided into three categories：the sedimentation，early diagenesis and late hydrothermal fluid. Among them，the precipitation and early diagenesis silicification have limited effects on reservoir physical properties. The comprehensive evidences show that the strongly hydrothermal silicified intervals are closely related to the spatial distribution of intrusive rocks. Meanwhile，the main oxide contents of strongly silicified intervals are between those of the intrusive rocks and the surrounding carbonate rocks，showing a mixing characteristics of the two. Furthermore，the homogenization temperatures of the primary quartz fluid inclusions are high in the range of 87-193 ℃. These comprehensive evidences indicate the hydrothermal fluids resulting in silicification were originated from magmatic activity. Post-magmatic hydrothermal solution tended to move along the weak structure zones，including faults，fractures and the high-porosity matrix pores connecting with fractures，which leaded to strong silicification in reservoirs. When the silica content is more than 10%，reservoir physical properties are dramatically affected.

Abstract:There are still many controversies about the fluid types，mechanism and the architecture of sand bodies formed by gravity flow in deep water. Based on the detailed analysis of Permian deep-water sedimentary outcrops in Karoo Basin of South Africa，Eocene-Oligocene calcareous turbidite outcrops in Tuscan Basin of Italy and a large number of deep-water cores from Upper Jurassic to lower Cretaceous in the North Sea of England，the sedimentary types formed by deep-water gravity flow and their characteristics are redefined，the deep-water turbidite deposition model is constructed，and its oilgas significance is further discussed. The results show that the deep-water gravity flow deposits can be divided into mass transport deposits（MTD）and turbidite deposits；the former is dominated by underwater mud-supported clast flow with poorly differentiation vertically；and the latter is characterized by turbidity current，debris flow and traction flow deposits from bottom to top，with a large number of bedding structures and well differentiation. Controlled by paleogeomorphology，provenance，tectonic setting，etc.，turbidite deposits show different main flow state and scale，which form different lithology and lithofacies，and they can be divided into gully channel，overflow bank and lobe. Fluid properties determine the physical properties，internal heterogeneity and exploration value of reservoirs. The reservoir quality of turbidite deposits and traction flow deposits in turbidity channel，the core of lobes and crevasse splay reservoir are beneficial，while the debris flow deposit and mud-supported clast flow deposit are poor，which are the main factors that cause reservoir heterogeneity.

Abstract:The lower sand member of Paleogene Kumugeliemu Group in the margin of Wensu Uplift-Yingmaili Uplift area in Tarim Basin has become the focus for lithologic reservoir exploration in recent years，and the massive oil and gas has been produced from Well Yudong1 Block. However，the high-resolution sequence stratigraphy characteristics，sedimentary microfacies types，and temporal-spatial evolution laws were not yet clear. Based on core，drilling，logging and 3D seismic data，the markers，sequence interfaces，and flooding surfaces which can be isochronally tracked and compared were identified. A high-resolution sequence stratigraphy framework was constructed，under the constraint of which the types and characteristics of sedimentary microfacies of each high-frequency sequence unit were analyzed and the temporal-spatial evolution laws of sedimentary microfacies were revealed. The results show that the lower sand member of Paleogene Kumugeliemu Group is the ascending half cycle of the third-order sequence ESQ1 and can be divided into four parasequence sets，namely sand member 4，sand member 3，sand member 2，and sand member 1 from bottom to top. The sedimentary period of the lower sand member of Paleogene Kumugeliemu Group is characterized by gradually deeper lake water and bigger lake basin，thus resulting in“water progradation and sand retrogradation”. Three types of sedimentary facies such as fan delta，braided river delta，and lake are developed here，in which the sediment period from sand member 4 to sand member 3 features the lowstand system tract with small accommodation space，adequate source supply，and slowly rising lake level.Large deltas are developed in the source areas of Wensu Uplift and Yingmaili Uplift and large near lakeshore sand bars are developed in Yingmaili Uplift source area. The sediment period from sand member 2 to sand member1 is featured by the transgressive system tract with large accommodation space and fast deeper lake water. Swiftly，the source area supply of Wensu Uplift decreases；the fan delta retrogrades towards the basin edge；the early developed sand is washed by the water and redeposited to be small sand bars. The delta in Yingmaili Uplift source area shrinks gradually and the near lakeshore sand bars apparently shrink.

Abstract:The fluid distribution characteristics of tight sandstone reservoir are complicated，and the movable fluid parameters are important to evaluate the fluid distribution and percolation characteristics. Based on the low-field nuclear magnetic resonance（NMR），high pressure mercury injection capillary pressure（MICP），X-ray diffraction，and scanning electron microscope（SEM）experiments，the movable fluid in 30 core samples collected from Chang7 Member of Wuqi Oilfield in Ordos Basin are analyzed. The reservoirs can be divided into three types：Ⅰ，ⅡandⅢ，and the division standard is established. The amount of movable fluid in the pores with different pore radius of three types of reservoirs is quantitatively evaluated and the influencing factors of the movable fluid are analyzed. The results show that the macropore，pore throat connectivity and the amount of movable fluid decrease in sequence. There are large differences in the occurrence characteristics of movable fluid. The average values of movable fluid saturation in typeⅠ，typeⅡand typeⅢreservoirs are 50.35%，42.00% and 21.40%，respectively. The main direction of exploration and development in the future is typeⅠandⅡreservoirs，which have a large amount of similar movable fluid. The movable fluid of the target reservoir mainly distribute in the pores with the radius of 0.053-0.527 μm in typeⅠandⅡreservoirs. Permeability and median radius are the main factors that affect the characteristics of the movable fluid，in typeⅠandⅡreservoirs，the movable fluid is also affected by porosity，macropore porosity，sorting coefficient，effective porosity and clay minerals. However，there are many and complex influencing factors in typeⅢreservoir，and no obvious influencing factors have been found.

Abstract:In Wangguantun area of Huanghua Depression with considerable potential of exploration，many oil and gas wells with high yield have been drilled in the Mesozoic and Paleozoic reservoirs. Based on the geological，geochemical，seismic，well logging and log data，the hydrocarbon accumulation conditions such as source rocks and reservoir-cap rock assemblages in Wangguantun area were analyzed. Through fluid inclusion technology and fluorescence microscopy of asphalt，the oil and gas accumulation stage and period were determined. Meanwhile，the hydrocarbon accumulation process was restored and its pattern was established. The results show that the Wangguantun area has good hydrocarbon generation conditions，in which Ek2 is the main hydrocarbon supply series of strata，with a small amount of the Carboniferous and Permian oil and gas sources mixed. High-quality reservoirs and regional cap rocks are well preserved，with regional cap rocks of mudstone，gypsolyte，and coal seam developing in the Mesozoic and Paleozoic as well as the overlying Cenozoic. The transport conditions are superior，as the hydrocarbon supply window exists between source rocks and reservoir，which are connected by the composite hydrocarbon transporting system consisting of fault with unconformity and sand body. Oil and gas from the Carboniferous and Permian source rocks are migrating into sandstone and underlying Ordovician carbonate rocks to be entrapped，while oil and gas from Ek2 source rocks are injected into the Mesozoic and Paleozoic through faults to be entrapped. As a whole，the buried hills of the Mesozoic and Paleozoic in Wangguantun area are featured by“multi-directional hydrocarbon supplies，composite transportation，and near-source accumulation”.

Abstract:After the fracturing in tight reservoirs，a complex fracture network system was usually formed near the well. The scientific and reasonable quantitative description of the characteristic parameters of the fracture network between injectionproduction wells was important to the customization of the sealing measures for gas channeling and the adjustment of development plans. Based on the previous research results，the characteristic functions of major characteristic parameters of the fracture network，such as porosity，permeability，opening，and line density of fractures，were improved with the principle of conservation of matter. Besides，the specific methods and steps for quantitative calculation of the characteristic parameters of inter-well fracture network after gas channeling in tight reservoirs were proposed. A case in point was the well group XN of Shengli Oilfield（Dongying City，Shandong Province）. The quantitative calculation results of characteristic parameters of inter-well fracture network were obtained，namely fracture porosity of 0.250%-0.251%，average fracture permeability of 42-1 563 mD，fracture opening of 14-87 μm，and fracture line density of 29-176/m. According to the analysis，the fracture porosity of well group XN is far less than the average porosity of reservoir on the whole and the fracture is strongly developed. The average fracture permeability and average gas-channeling velocity vary drastically with each individual gaschanneling well. Micro-fractures are the majority，but there are some large fractures for gas channeling. The individual well with fast gas channeling is featured by high average permeability，large fracture opening，and low line density of fractures.

Abstract:A double-layer vertical heterogeneous plate model of core that can monitor saturation field was designed and fabricated. The remaining oil distribution in the model was quantitatively described with the resistivity method. Through simulation of the water flooding，polymer flooding，and gel profile control experiments of thick positive-rhythm oil layers，the remaining oil distribution before and after gel profile control was tested，and the displacement efficiency and remaining oil distribution characteristics of the profile control of models in different injection schemes and displacement stages were obtained. According to the experimental results，the larger permeability ratio led to the more rich remaining oil and the bigger increase in swept volume in low-permeability layer after profile control. A greater permeability ratio also resulted in the more evident preferential migration passage of water flow in the high-permeability layer，larger swept volume，and better displacement efficiency. The different water injection volumes received almost the same development effects with little improvement on swept volume in the low-permeability layer. A smaller polymer injection volume and earlier profile control brought about higher enhanced oil recovery（EOR）. The more profile control agent led to larger plugging radius of the highpermeability layer，more increment of swept volume in the low-permeability layer，more percentage of producing remaining oil，and longer distance that the oil-water front advances to the production well.

Abstract:In order to study the non-isothermal flow characterization and influencing factors of heavy oil emulsions in porous media，the porous media is simplified into a model of variable diameter capillary tube bundle，and then the non-isothermal heat transfer process of the oil-in-water emulsion in the equilibrium state is converted into a steady heat transfer process containing a negative internal heat source. At the same time，considering the variation of temperature along the way and its effect on viscosity and interfacial tension of the dispersed phase，a calculation model for the non-isothermal flow of oil-in-water emulsion in porous media is established. The calculation results of sensitivity-analysis of non-isothermal flow of oil-in-water emulsion show that the inlet pressure increases with the decline of steam injection temperature，and the transition position between the gentle pressure drop section and the fast-decline linear section moves to the injection point；the larger the viscosity of the dispersed phase，the larger the pressure gradient required for the oil-in-water emulsion droplets to pass through the pore throat，and the higher the injection end pressure. With the increase of the volume fraction of the dispersed phase，the temperature drops faster along the way，and the pressure at the injection end gradually increases.

Abstract:The viscosity reduction chemical flooding is an effective alternative production method after steam stimulation in heavy oil reservoirs，and its injection method has a great influence on the development effect. Based on the oil displacement mechanism of viscosity reduction chemical flooding，a reservoir numerical simulation model was established. The numerical simulation technology was used to analyze the characteristics of the viscosity reduction chemical flooding after steam stimulation. The injection slug sequence was optimized based on the injection and production capacity and the development effect. Based on the net present value method，an optimized model of injection parameters of the viscosity reduction chemical flooding after steam stimulation was established. The reservoir numerical simulation technology and particle swarm optimization algorithm were integrated to obtain the optimal injection parameters. The research results show that the viscosity reduction chemical flooding after steam stimulation can effectively reduce the viscosity of crude oil in the formation，and the water cut declines significantly after a rapid increase；the sequence of injecting viscosity reducer first and then polymer slug is the best；based on the optimization，the optimal mass fractions and injection volumes of the viscosity reducer and polymer in the target reservoir are 0.28%，0.32%，0.40 PV and 0.36 PV respectively. The optimization results can effectively improve the development effect of heavy oil reservoirs，and the method of injection optimization proposed in this paper is of great significance to guide the development practice of viscosity reduction chemical flooding after steam stimulation in heavy oil reservoir.

Abstract:The curve of water fractional flow is of vital importance to the research on reservoir development，which can be achieved by laboratory test. The endpoint value（water saturation）of this curve cannot be obtained directly owing to insufficient injection volume limited by experimental period and instruments. Also，the endpoint value cannot be calculated by fitting because current calculation models neglect limit displacement. Based on the reservoir engineering theory，the theoretical relationship，characteristics，and boundary condition of the curve of water fractional flow were specified. The rational formula is chosen for building the whole process model of water fractional flow through the comparison of multiple mathematical models. The results show that the rational formula model has high accuracy as the average relative error between calculation value and test value is 0.4%，for which it can be used for forecasting the residual oil saturation data at the point of limit displacement and calculating the whole process curve of relative permeability ratio. This rational formula model has great practicality and can be widely adopted because the parameters in the calculation are accessible in the test report on relative permeability. More importantly，it can provide some guidance for the theoretical limit，surplus potential，and direction adjustment of the development of water drive reservoirs.

Abstract:The apparent liquid permeability is of vital importance to studying the effective percolation capacity of shale reservoirs，and it is essential to explore the influence of negative slip length on apparent liquid permeability. Based on the fractal theory of porous media，the model of apparent liquid permeability was established，which comprehensively reflects the influence of pore structure，porosity，tortuosity，pore radius，and negative liquid slip length on apparent liquid permeability.According to the theoretical analysis，greater negative slip length leads to lower average percolation velocity of the liquid in micro/nanotubes；a larger pore radius results in less influence of negative slip length on percolation velocity. The ratio of apparent liquid permeability to Darcy permeability falls with the rise in negative slip length. The apparent liquid permeability goes up with the increase in fractal dimension of pores and down with the growth of tortuosity. The prediction results depending on the apparent liquid permeability model signals an 8.6% reduction in permeability caused by the slip effect.

Abstract:Liquid trapping damage has always been considered as an important reservoir damage mechanism of tight sandstone gas reservoirs. The degree and mechanism of the liquid trapping damage of ultra-tight sandstone gas reservoirs vary with different physical characteristics and working fluid types of reservoirs. In this paper，we studied the ultra-tight sandstone gas reservoirs in the Tarim Basin. The evaluation method simulating the four stages of drilling-drill stem test-killing operations-completion testing was proposed to test the comprehensive liquid trapping damage induced by the sequential contact of oil-based/organic salt drill-in fluid filtrates-organic salt completion fluids. The typical matrix and fractured samples were selected. The results showed that the permeability damage rates（PDRs）of comprehensive liquid trapping of the matrix sample treated by the sequential contact of oil-based/organic salt drill-in fluid filtrates-organic salt completion fluid were 86.00% and 98.37%，respectively. The corresponding two parameters of fractured samples were 99.95% and 63.45%，respectively. Analysis indicates that the special clay mineral types，occurrence，and narrow throats of ultra-tight sandstone gas reservoir cause oil-based drill-in fluid filtrates to suppress the intrusion of the subsequent water-based working fluids for the matrix sample. That the remaining oil-based drill-in fluid droplets in the fractures obstructing the flowback and evaporation of the organic salt completion fluid during the subsequent flowback process is the main mechanism for the oil-based drill-in fluids’mitigating the comprehensive liquid trapping damage of matrix and aggravating the comprehensive phase trapping damage of fractures.

Abstract:In view of the complex geological characteristics and strong stress sensitivity of deep high-pressure and low-permeability sandstone reservoirs，the stress sensitivity model and development index trend were studied. The effects of stress sensitivity due to the reduction of pore fluid pressure on oil productivity index，fluid productivity index，and water absorption index were analyzed through laboratory tests and field data. The stress sensitivity models of permeability，porosity，oil productivity index，fluid productivity index and water absorption index were established to generalize the controlling factors of the stress sensitivity of oil productivity index，fluid productivity index and water absorption index. It is found that in the development of deep high-pressure and low-permeability reservoirs in Wendong Oilfield，the water absorption index gradually rose while the oil productivity index and the fluid productivity index smoothly fell. The oil productivity index dropped at a higher rate than that of the fluid productivity index. The main controlling factors of oil productivity index and fluid productivity index include the oil-water viscosity ratio，starting pressure gradient and water cut.

Abstract:Owing to small size，stable property，and good deformation capacity，nanoscale polymer microspheres can migrate into deep formation to enlarge the swept area，thus enhancing waterflooding efficiency. To comprehend the plugging performance of nanoscale polymer microspheres on high-permeability layers，we used the propped fracture evaluation system to simulate the high-permeability channels and injected the solutions of nanoscale polymer microspheres with varying concentrations and particle sizes in different conditions. We analyzed and evaluated the plugging performance of these microspheres on the high-permeability layers according to the change in permeability before and after the injection. As a result，nanoscale polymer microspheres could plug the high-permeability layers. A higher injection rate led to lower plugging performance. As the closing pressure increased，the plugging performance fluctuated. No distinct linear relation was observed between the plugging performance and concentration or particle size of nanoscale polymer microspheres. Instead，concentration and particle size brought about corresponding optimal values of plugging performance. Analysis of dominant factors showed that the injection rate had the greatest influence，followed by closing pressure，and then concentration and particle size of nanoscale polymer microspheres.

Abstract:During the SAGD production of super heavy oil reservoirs using dual-horizontal wells，the accurate and rapid judgement of the effective producing degree of the horizontal section is the basis for well group production measure parameter formulation and field parameter adjustment. The conventional method of judging the effective producing degree based on the temperature has limitations due to the different controlling factors of bottom hole temperature at the toe and non-toe points of the production well. Firstly，the main factors affecting the temperature at the toe and non-toe points of the production horizontal wells were clarified from the perspective of heat supplement and loss in horizontal wells. Through numerical simulation and theoretical formula analysis，the dimensionless productivity parameters per unit horizontal section and the mathematical model with temperature and pressure coupled along the horizontal well were introduced. The producing degrees at the toe and non-toe points were judged，respectively，and then，a method of judging the effective producing degree of the SAGD horizontal section was formed. On this basis，the producing degree of 155 SAGD well groups in the normal production stage was studied，and the reliability，convenience and easy operation of this method have been confirmed. Combined with geological factors，five production modes were established，and the production characteristics of different modes were analyzed. It is clear that the main controlling factor that affects the SAGD production effect is the producing degree of the horizontal section，which provides the basis for field parameter control and measure regulation.