Some breakthroughs have been made in the exploration of tight sandstone oil reservoir in Chang-8 Member of Yanchang Formation in Xiasiwan Oilfield recently. However, as the basic geological study of Chang-8 Member is relatively weak and the hydrocarbon accumulation condition is complex, the main controlling factors of enrichment and the sweet spot mode have not been proved. Therefore, the development efficiency is low in most areas. In order to further explore the prospect of exploration and development for the tight sandstone oil reservoir in Chang-8 Member, based on the previous study, the main controlling factors of reservoir formation were analyzed deeply in the study area by the data of core, logging, mud logging, analysis and testing, and combined with the production data of oil testing, production testing and horizontal wells. The results show that the accumulation of the tight sandstone oil reservoir Chang-8 Member is mainly controlled by four main control factors: high quality source rocks, excellent reservoir properties under favorable sedimentary microfacies, higher excess pressure difference and widely developed micro-fractures. And on this basis, five sweet spot modes of Chang-8 Member tight oil could be established, and the reasonable development modes are analyzed respectively according to these five modes, which indicated the direction for the efficient exploration and development of the tight oil reservoir in Chang-8 Member.

The tight-sandstone gas reservoir in Zhongba gas field is a fracture-pore type reservoir controlled by structures and fractures. On the basis of analyzing the basic characteristics of reservoirs, the factors controlling the fractures are discussed to figure out the effect of fractures distribution on the formations and predict the distribution of residual gas. The reservoir is mainly composed of light gray-gray fine-medium lithic feldspar quartz sandstone with its average porosity and permeability being 6.29 % and 0.19×10 ^-3 μm ², respectively. It belongs to low porosity and permeability formations. And based on this, the fracture was studied by means of tectonic curvature method and rock mechanics experiment. The results showed that the fractures on the surface were mainly developed along the structural axis and close to the southeast arc and the northern conjunction of the saddle. The developments of fractures were tightly related with lithology. Combined with the numerical simulation results of gas reservoir, the potentials of the gas reservoir are analyzed to support the scheme adjustment in the next stage of development.

In order to find out the complex situation of remaining oil distribution at the middle and high water-cut stage of Suizhong 36-1 Oilfield, and by the study of the flow field variation characteristics of nine-point well pattern for complex heterogeneous reservoirs by high temperature and high pressure experiments, the physical simulation experiments for the nine-point well pattern and the characteristics research for flow field of infilled row shape injection-production well pattern were designed and carried out based on the newly developed 3D large-scale core modeling technology and the stereoscopic acquisition system for oil-water saturation. For the injection and production patterns with complex rhythms, the distribution of remaining oil was also very complicated, but there were certain rules: under the condition of single positive rhythm, the subsidence of injected water was obvious even in the experiments, and the remaining oil was mainly distributed in the upper part of the positive rhythm; under the condition of inverse rhythm, the injected water could spread evenly to all permeability layers of the model, and the remaining oil was mainly accumulated in the weak hydrodynamic area; under the condition of complex compound rhythm, the distribution of remaining oil depended on the low permeability zone with weak water flooding in the complex structure, and it was not necessarily the area without streamline between corner wells. At the same time, based on the above characteristics, it was found that the water flooding degree of nine-point well pattern was high, most recoverable reserves could be produced. And when nine-point well pattern transformed into row injection-production well pattern, the recovery rate of heterogeneous reservoir could be improved by about 8 % ~ 10 %. Experimental studies suggest that no matter for the nine point injection production well pattern or the converted row shape injection-production well pattern, the maximum recovery rate of structure reservoirs with complex rhythmic was difficult to exceed 40 %.

The geological conditions of fault block reservoirs are complex, whose small faults are developed, and reservoir heterogeneity is serious. When the reservoir enters the development stage with ultra-high water cut, the remaining oil is highly dispersed, the streamline between injection and production wells is fixed, the benefit of water drive becomes worse, and the spread of water flooding is difficult to further expand. Streamline adjustment and development have become the main direction of cost reduction and efficiency enhancement for fault block reservoirs when the price of oil is low. Conventional dynamic analysis is not suitable for the adjustment of high water cut fault block reservoirs. In this paper, streamline simulation method is used to analyze the influence of each factor on the streamline of water flooding, and grey relational method is used to calculate the influence degree of each factor. It is found that vertically heterogeneity, areal heterogeneity and injection-production well pattern have significant influences on streamline, while injection-production well spacing and injection-production pressure difference have relatively small influences. The streamline distribution model is divided into three categories: dense area, sparse area and blank area, on this basis, the optimal adjustment technology is formed. In several fault block reservoirs in Subei Basin, the adjustments of vector allocation, adding new waterline, reducing the number of wells in the well pattern, and reorganization after subdivision have been carried out. Remarkable effect of increasing oil production and efficiency has been achieved. It has certain guiding significance for the adjustment of the same type of reservoirs.

For the characteristics of condensate gas reservoirs, evaluation methods on just one side would lead to misjudgment on retrograde condensation of gas reservoir. Therefore, qualitative and quantitative comprehensive evaluation method of retrograde condensation damage was established. Firstly, the retrograde condensate phase evaluation and production dynamic analysis were used to judge whether the retrograde condensation of gas wells occurred or not. And then, methods such as the gas well productivity, pollution skin coefficient, numerical simulation and pressure build-up testing were comprehensively applied to quantitatively evaluate the degree and radius of the retrograde condensate damage. The established method was carried out in the case of the well-169 of Zanarol condensate gas reservoir in Kazakhstan. The results show that gas condensate has occurred in Zanarol condensate gas reservoir. Retrograde condensation has great influence on oil productivity, but a little on that of gas. And the damage degree is different for different gas wells. Generally, retrograde condensation damage was little and its influence rate was less than 16 %. Pollution radius was about 20 m. Thicker gas layer and carbonate reservoirs with developed fracture-vug were important reasons for less influence of retrograde condensation damage on gas well productivity in Zanarol. The established method can be used as a reference for the analysis of complex condensate gas reservoirs.

The existing faults affects the propagation of pressure waves in the composite reservoirs, meanwhile, the location of faults affects the curves of the bottom hole pressure. Based on the principle of seepage mechanics and point source function, the fractured-well line source solution of fault composite reservoirs in Laplace domain was obtained by image principle, pressure drop superposition principle and Laplace integral transformation. The bottom hole pressure solution of finite-conductivity fractured wells was obtained by coupling fracture of fractured-well and reservoir model. The typical characteristic curves of dimensionless bottom hole pressure and pressure derivative were drawn by Stehfest numerical inversion in the real space. The results showed that the characteristic curve was divided into seven flow stages generally. In the early stage, the position of dimensionless bottom hole pressure and pressure derivative curves decreased with the increase of the fracture conductivity. When the mirror well was located in the inner region, the pressure derivative curves of radial flow and subsequent bottom hole pressure showed horizontal lines of 0.5, 1 and fluidity ratio M₁₂ in inner part and outer part, and the larger the inner radius was, the longer the radial flow in the inner zone would be. When the mirror well was located in the outer region, the pressure-derivative curve of radial flow and subsequent bottom hole pressure showed horizontal lines with the value of 0.5, 0.5M₁₂ and fluidity ratio of M₁₂ in inner and outer zones.

In order to study the effects of caves and flow rates on hydraulic fractures propagation and initiation pressure, two sets of cube hydraulic fracturing specimens—A and B（the size is 200 mm×200 mm×200 mm）—with two same specimens in each group are made by the mixture of cement, fine sand and water. The specimens in group A are intact, while that in group B is with Karst cave（the PVC pipe is pre-buried during pouring, and then, when the cube is formed, the pipe is removed to simulate natural caverns）. Fracturing experiments are carried out for two specimens in each group when the displacement was 7.5 and 10.0 mL/min respectively. The results indicate that for intact rock mass, the initial pressure will rise up with the increase of flow rate, and the induced hydraulically fractures will be more straightness; for the rock mass with caves, the caves will affect the extended path of hydraulic fractures and exert a kind of “attraction” on hydraulic fractures, which will make the hydraulic fractures extend towards caves, and the effect of “attraction” will decrease with the increase of the displacement. The initial pressure of fracturing in intact rock mass is higher than that in rock mass with caves under the same conditions. Caves are the main storage area for petroleum resources. The key to enhance oil and gas recovery in fractured-vuggy reservoirs is to set up fracturing operation parameters reasonably and produce hydraulic fractures that communicate caverns and boreholes. This study has certain guiding significance for optimizing the fracturing operation parameters.

The evaluation of water flooded layer using the old data is very difficult in high water cut reservoir. In this research, the idea of establishing the relationship between water content and resistivity in target section to realize the evaluation of old wells under water flooded condition was adopted. For the same type of depositional sand body, the initial resistivity and initial water content was picked up from the drilling data of the sand body in different historical stages during the development to establish the empirical formula for the relationship between water content and resistivity. And then, the current remaining oil saturation of the old wells could be calculated by the Archie formula. Therefore, a rapid interpretation method for old wells under water flooded condition based on the water content and resistivity was put forward. Based on the new method, the ZW Oilfield with more than 30 years of development history was chosen as the example. The evaluation of the water flooded degree of old wells in the 6th sand group of first member of Sanduo Formation in the typical block, ZW12 fault block, was made. Meanwhile, through the calculation of the oil saturation of the closed coring wells, well-ZJ1 and well-ZJ4, the accuracy of this method was verified. It was proved that this method has high practicability in the rapid qualitative—semi-quantitative evaluation of old wells in high water cut reservoir under the water flooded condition.

In order to clarify the effect of extraction on miscible pressure during CO₂ flooding and make clear the characteristics of minimum miscible pressure of gas front or after gas sweep, the CO₂ extraction rate under different pressure and the distribution characteristics of oil components in the extraction process are studied by the extraction experiments under high temperature and chromatographic analysis. The changes of minimum miscible pressure of extracted oil and residual oil are quantitatively analyzed by the interfacial tension vanishing method. Under the experimental condition of 95 ℃ and 10 ~ 45 MPa, the supercritical CO₂ can extract the components of each carbon number of the crude oil, and more than 80 % of the extracted oil is C_5-20. The extraction rate of supercritical CO₂ and the minimum miscibility pressure of extracted oil and residual oil are positively correlated with the extraction pressure. Under the influence of extraction and pressure, the minimum miscible pressure in the CO₂ displacement and migration process is a dynamic value, which reduces in the following order: residual oil, crude oil and extracted oil. The minimum miscibility pressure of extracted oil and residual oil is related to component distribution. The critical components affecting miscibility in formation oil are C_5-10 and C₂₆₊ components. The study result provides good reference for CO₂ miscible displacement design and miscible phase prediction.

： Aiming at the problems of reservoir density, ultra-deep, high temperature and high closure stress of the exploration well S1 in new area, we designed the modification scheme of compound high diversion acid fracturing. It was based on the fluid with better performance. The sand adding existed in the whole stage of prepad fluid and acid liquor. The proppant placement in all fractures（near wells and far wells）was realized. Meanwhile, acid is used to etch the main fracture and communicate with the surrounding reservoirs. So that the complex flow channel of ceramsite and acid etching across the whole crack scope formed. The evaluation conductivity in the lab showed that the conductivity of the compound channel form by ceramsite and acid etching increased by 40 %. The average embedded depth of high strength ceramsite proppant was only 85 μm. By the indoor fluid analysis and evaluation technology, the fracturing fluid system with the heat resistance of 180 ℃ was selected as prepad fluid to realized the effective long hydraulic fractures. The ground cross-linked acid system with the heat resistance of 165 ℃ was developed, and the optimum HCL concentration was 15 %, which meet the requirements of sand carrying and deep penetration. Then we optimized the proppant type and adding method to realized the effective support for all fractures. Well S1 successfully completed the fracturing by the equipment with the pressure resistant of 140 MPa. The highest displacement was 5.1 m ³/min and the highest pressure was 108.5 MPa, the cumulative sand adding was 78.6 t, and the fractured daily liquid output reached 72.9 t/d. The long-term conductivity of composite fractures remains at a high level.

The target exploitation interval of CCL oilfield belongs to Fuyu reservoir in the 4th member of Quantou formation of lower Cretaceous, which has the characteristics of high viscosity, poor fluidity, low pressure and low temperature. Some difficulties exists in the the process of fracturing, for example, cold damage due to the incompatibility between the fluid and reservoir, unmanageable crack height caused by developed thin oil layer and and weak blocking ability of the interlayer, and low flowback rate because of the shallow buried depth, low formation pressure and the serious out put formation sand after fracturing. Combined with the optimization of the indoor fracturing materials, low concentration guanidine colloid system is used as fracturing fluid and 16~30 mesh quartz sand as proppant. The technology of front hot water+temporary plugging steering and variable displacement+synchronous interference+integral modification is proposed. The software FracproPT is used to simulate the half length of artificial fracture and the conductivity of fracture, and then to determine the fracturing scale and optimize the design parameters. After field test, the effect is obvious. The oil increment of a single well is twice as much as that of conventional fracturing, which can effectively slow down the decline of oil production of a single well. This modification technology provides technical guarantee for CCL oilfield to increase production of single well and achieve the goal of stable and increasing production.

In order to solve the problem of quantitative design of fiber in fiber temporary plugging and diverting acid fracturing, a total stress field model considering the initial artificial fracture, adjacent well artificial fracture, pore pressure change, temperature change and in-situ stress is established. And then the prediction model of diverting radius is established by multivariate nonlinear regression. Meanwhile, methods such as the displacement discontinuity method（DDM） are used to solve the model, and combined with the fiber plugging mechanism, the design model of fiber dosage is established. The simulation results show that the induced stress value of the initial artificial fracture in the direction of minimum principal stress is larger, and the influence of artificial fracture of adjacent well or wells, pore pressure variation and temperature variation on stress diverting are small. The smaller the original in-situ stress difference, the longer the initial artificial fracture length, the smaller the well spacing, the larger the net pressure in the fracture, and the larger the diverting radius. When the in-situ stress difference is large, it is necessary to use the temporary plugging of fiber to increase the net pressure of the fractures, and the fiber dosage can be determined according to the design plate. Applying the above design method to a well in Xinjiang, the results were basically close to the on-site construction results, and the new fracture diverted successfully.

The study of proppant transport in fractures is of great significance for guiding fracturing design and evaluation. The current researches of proppant placement rules mainly focus on displacement, proppant type, fracturing fluid viscosity, etc. However, there are few studies on the effects of different proppant combinations on proppant transport rules. In this paper, the experimental schemes of the influence of different proppant combinations on proppant transport rules are designed. Then the self-designed visual parallel plate device is used to carry out these experiments. The results show that the distribution of the proppant with smaller particle size is more evenly in the fractures, but the proppant with larger particle size is easier to settle at the wellhead. When medium particle size and large particle size proppant are combined in different proportions, there are small differences in the equilibrium heights of the formed sand bank, but the differences between the non-uniformity of the sand bank height are large. Meanwhile, a large amount of proppant settles at the entrance end of the crack. The proppant filling amount in the deep crack is small, and the effective filling crack with sufficient length and diversion capacity is failure to be formed. When the medium and small particle sizes are combined in different proportions, the proppant can obtain a farther distance than that of the combination of medium particle size and large particle size. The height of the formed sandbank is ideal, and the difference in the non-uniformity of the height of the sand bank between different proportions is also greater.

Compared with the single well development mode of the conventional gas reservoirs, multi-well pad technology has several advantages such as great improvement of operating efficiency and reduction of project cost. Strong interference between the wells and between the fractures exist in small well spacing and network fracturing mode of multi-well pad for shale reservoir, which affect the overall development effect of the well group. Based on the unstructured PEBI grid technology, its simulator for fracturing horizontal wells is developed independently. According to the results of microseismic monitoring, the stimulated reservoir volume（SRV） area formed by the network fracturing of horizontal well groups are assumed to be ovals. Considering the adsorption, desorption, diffusion and nonlinear seepage mechanisms of shale gas, the numerical simulation model of the fracturing horizontal well group in the multi-well pad mode is established by the finite element method. The difference between the cumulative production of the single well and the well group is compared, and the influence of the layout mode of the fractures and the horizontal wells on the cumulative production in homogeneous shale gas reservoirs are discussed. The results show that the inter-well seepage interference makes the cumulative production of the well group lower than the sum of that of a single well. U-shape layout mode of the fractures for single well can reduce the interference to a certain extent, which make the cumulative production of the well group superior to that of the uniform mode and the inverted U-shape mode. The cumulative production of cross distribution of horizontal wells is better than that of parallel mode.