Based on the data of the heavy mineral, core, logging and physical, we studied the sedimentary microfacie reservoirs' characteristics of the upper reservoir of the lower Gangchaigou formation in eastern Lenghu region. The results show that during the deposition period, the area is close to the source, and the developed raided river delta plain, sandstone type is mainly composed of feldspar lithic sandstone and lithic feldspar sandstone, and its composition and structure maturity are low. The main pore types of the reservoir are the residual intergranular pores, and the grain size is positively correlated with the porosity and permeability. According to the reservoir classification standard, the reservoir area is divided into three types, most of which not only belong to reservoir Ⅱ and Ⅲ with low porosity and permeability, but also belong to medium and low porosity-low permeability reservoirs with strong heterogeneity. The physical properties of reservoirs in the study area are related to the hydrodynamic forces at the time of the sedimentation. The high quality reservoirs are mainly distributed in thick sand bodies with braided river delta distributions.

Aiming at the architecture fine characterization of the fluvial reservoir in the offshore field under the condition of the large well distance and low well pattern, based on the vertical river channel period division, and combined with the recent classical quantitative method of sedimentology, we defined the reservoir boundary and mode simulation to determine the plane by the guidance of quantitative model, and the combination of well and seismic information, to achieve the quantitative characterization research for point bar sand body of subsurface meandering river environment. This method combined the advantages of dense well pattern dissection with the seismic stratigraphy, so that to approve not only the cross-well sand body extension prediction, but also the reservoir structural characterization precision. Meanwhile, we summarized the meandering river channel sand plane geometry form and its control mechanism. The results show that the quantitative characterization method of channel sandbody in surface meandering river by statistical analysis of modern deposits and outcrops is also feasible for the subsurface environment.

By the experimental data of the forefathers and the dew point pressure of the gas condensate reservoirs derived from different parts of the domestic, we make an empirical correlation expression for the calculation of the dew point pressure based on the genetic algorithm（GA）. This expression considers more factors than that of other existing models including the temperature, fluid compositions, molecular mass and density ratio of heavy constituent, gas-oil ratio. The calculation results are more closed to the experimental data than the previous test values. The average of the relative error's absolute value is 3.05 %. In order to further verify the new empirical expression's prediction ability, the experimental data of other 10 groups of dew point pressure are compared with the results calculated by four models that is the N-K, Elsharkawy, Sun Zhidao's model and Wang Haiying's model. The results are relatively high in accuracy with the absolute value of 1.79 %. The absolute values of other four models are 49.53 %, 27.05 %, 3.30 % and 7.05 %.

In tight oil reservoirs, the upper limit value of permeability is an important parameter, which is used to determine the tight oil reserves and reasonable development way. The existing calculation or determination methods can't fully and accurately reflect the geology and development characteristics in tight oil reservoirs. It can't even better reflect the characteristics of the seepage and the current unity understanding which is embodied in the development way of tight oil reservoir at home and abroad. On the basis of the research on the methods for calculating the upper permeability limit in tight oil reservoir at home and abroad, by using the seepage theory, and from dense reservoir development and production practice, we proposed a new method, which is used to calculate the upper limit value of permeability in tight oil reservoir by the power function relationship between the air permeability and start-up pressure gradient. The studies show that based on the unified understanding on the development of the tight oil reservoir, although there are some difficulties during it, the tight oil reservoir could realize the effective economic usage through the technology research, and the tight oil reservoir could be difficult to achieve the economic usage of the reservoir under the condition of the development technology. This understanding determines that the calculation and determination of the upper limit value of permeability in tight oil reservoir must fully and accurately reflect the characteristics of the non-Darcy seepage in the tight oil reservoir, which is affected by the start-up pressure gradient. The new method has the theoretical basic. At the same time, the new method not only relies on the mathematical theory, but also is more sufficient in theoretical basis, and more reliable, reasonable and practical than the previous calculation methods. Therefore, it has better promotion value.

Based on the volume source, we established an unstable state model of coupling the horizontal wells to the gas reservoir, considering the friction resistance of the wellbore, the acceleration pressure loss and the influence of the wellbore inflow. It is showed that the calculation results of this model fit well with the commercial numerical simulation software--Eclipse, and has proven the correctness of this simulation method. The results show that we may overestimate the production of the horizontal wells when the wellbore pressure drop is neglected. The flow distribution of the horizontal wells is affected by the factors such as the wellbore inflow, acceleration and friction. And the influence of the gas production profile in the period of the unstable state is greater than that of the quasi-steady state.

According to the deficiency of the development status and the distribution law of the remaining oil in the reservoir-H, we used the fuzzy clustering analysis and numerical simulation technique to optimize the layers, evaluated the factors influencing the reservoir, and ultimately, got the comprehensive evaluation index, by which we could optimize the layers to reduce the contradiction between the layers and increase the water drive degree. Firstly, we determined 9 feature parameters as the evaluation indexes by the gray correlation analysis, that is, the water extraction degree, water flooding degree, abundance of remaining oil storage, porosity, variable coefficient of permeability, reservoir depth, oil content, and permeability. Based on the fuzzy clustering analysis, we classified the small layers into three groups. Each set of schemes was divided into two sets of layers. Then, we used the numerical simulation to predict and contrast the annual oil production, recovery, and moisture content of three schemes in 10 years later to get the preferred plan. The experimental results confirmed the feasiblility of the fuzzy clustering method in the optimization of the layer system.

The capillary bundle model is one of the most common physical models for the porous media. The most classic physical model is the straight capillary bundle model with same diameter. But the bendability of the porous media is neglected in this physical model. Therefore, based on the tight sandstone, combined with the mercury data, and by the introduction of the correction factor-tortuosity, we put forward a new approach to establish the capillary bundle model. This approach considers the bendability of the capillary bundle model and can accurately calculate the radius of capillary, capillary porosity and permeability, capillary volume of different radius and permeability contribution of capillary bundle model with different radius. This new approach has great significance for the study of the reservoir fluid imbibition of specific pressure and quantitatively characterizing the water invasion reservoir damage.

QK 18-1 Oilfield is located in the western Bohai sea. After 10 years of water flooding, the water injection now is difficult. In 2013, the sealed coring was conducted on the well P13. The core represented large amounts of the information after the long term of the water flooding, including the pore structure changes, the inorganic scale plugging, etc. By comparing the interstitial materials in the reservoir of the exploratory wells in the early stage and the exploitation wells in the late stage, we used many methods, such as the low field NMR, the electron microprobe, the environmental electron microscope, the cathodoluminescence and the rock cast sections, to study the inorganic scale in the reservoir and determine the formation mechanism of the scaling crystal in the reservoir. The results showed that the CaCO₃ cements in the early stage of the reservoir presented as the crystal or the porphyritic distribution were the products of the diagenetic stage. The well P13 contained a large number of rhombohedral CaCO₃ scales with the grain diameter of 5 ~ 30 μm and great euhedral degree of the scale. And the scale mainly distributed around the surface and the throat of the skeleton particles with high content of Mg and Fe formed during the water flooding. The average reservoir water damage rate was 44.5 % and the average velocity sensitive damage rate was 139.5 %. The clay minerals generated by swelling of part of the scale with water, the mobile formation particles and the suspension matter in water wrapped together to form a composite inclusion, accumulating in the pore space to damage the reservoir

In order to improve the accuracy of the acid fracturing by the multistage alternative injection in Longwangmiao Formation of Moxi-Longnvsi area, we studied the conservation rate of the conductivity of the acid corrosion fractures and the fracture surface morphology influence of different injection rounds, fluid groups and injection rate by the experiment and the numerical scanning. The results showed that the 3rd injection round obtained higher conservation rate of the conductivity of the acid etched fractures, and formed the acid corrosion groove through rock plate. With the increasing of the injection round, the increment of the conservation rate of the conductivity decreased gradually. With the same closing pressure and main acid, little different existed in the 3rd injection round when it took the gel and the authigenic acid as the preflush. With the increasing of the injection rate, the conservation rate of the conductivity of the acid etched fracture was more ideal. The optimized technology has been used in Longwangmiao Formation of Moxi-Longnvsi area. The acid-fracturing curves and fitting data indicate that the technology can realize the engineering purpose. It also provides an effective technical mean for the transformation of the low permeability reservoir.

The main reservoirs in Bohai have the characteristics of serious reservoir heterogeneity, large injection rate of single well and low cementation strength of rock. Due to the long-term water injection and polymer flooding, the rock structure has been destroyed and the dominant channel of water flow has been formed. This problem has caused the inefficient and ineffective circulation of the injected water. In this paper, we evaluated the gelling time, the plugging effect and the reservoir adaptability of the new inorganic geopolymer gel plugging agent by the static gelling test and the core displacement test. The results show that it is easy to adjust the curing time of the inorganic geopolymer gel. The curing time is adjustable between 20 ~ 480 hours. Based on the plugging experiments of the sandpack pipe, the plugging rate of the inorganic geopolymer gel was over 99 %. While the plugging experiment of a double pipe parallel model composed of the sandpack pipe and artificial homogeneous core bring us a plugging rate of high permeability layer more than 98 %. The permeability of the low permeability layer is almost unchanged. Therefore, the inorganic geological polymer gel has the advantages of plugging the large channel but not for the small pores. It is suitable for the plugging of the zones with ultra high permeability or the large channels in the reservoir.

It is well known that the supercritical CO₂ has the dual characteristic of gas and liquid. In order to study the forces of the sand in the fluidized bed formed by the supercritical CO₂ fracturing fluid and the migration of the proppant particle under the force, we analyzed the acting force between two particles, and the particle and the fluid, and that of the fluid on the particle. Based on the mathematical model, we derived the relation between the elastic restitution coefficient and the agglomeration concentration of particles. With the increasing of the elastic restitution coefficient, the distribution of the agglomeration concentration gets more evenly, the agglomeration concentration decreases, the collision of particles is more intense, the particles settle down more slowly, and the sand migration effect is better. Meanwhile, through the numerical simulation of the double Euler multiphase model based on the particle kinetic theory, we described the fluidization model in the fluidized bed formed by the supercritical CO₂ fracturing fluid in operation, and the two phase distribution of the particle of the supercritical phase and the solid phase. The simulation result is consistent with the mathematical model.

Firstly, we evaluated the polymer microspheres and polymer properties, then, studied the migration and plugging properties of the microspheres, polymer and compound system（microspheres + polymer） by microporous membrane filtration device, and implemented the profile control and oil displacement experiments about the systems above by the parallel cores physical simulation displacement apparatus. The results indicated that the polymer microspheres was spherical micron-grade particles with superior dispersibility, and its apparent viscosity, which was much less than that of polymer with the same mass concentration, is close to that of water under the relatively high shear rate. The polymer failed to plug the micropores effectively. The plugging ability of the microspheres was the strongest, followed by the compound system. Under the condition of the strong heterogeneity, the effects of the profile control and the oil displacement of the compound system attained the best and corresponding enhanced oil recovery for high and low permeable cores were respectively 20.86 % and 36.89 %. There was a synergistic effect between the microspheres and polymer for the compound system. That the amount of the microspheres captured and migration property reduced and intensified in the porous medium mainly due to the impact of carrying and lubrication of polymer. Additionally, the influence of mobility ratio control and viscoelastic oil displacement of polymer could effectively improve oil recovery. For the actual reservoirs with relatively strong heterogeneous conditions, it was essential to take the profile control and flooding technology of the microspheres/polymer compound system into account firstly.

The horizontal well has the charecteristics of large span and strong heterogeneity, the damage caused by drilling, completion and exploitation is characterized by strong heterogeneity, and the efficiency of the general acidizing is low. Considering the existing technical bottleneck, we proposed a design of the efficient acidizing in heterogeneous carbonate reservoirs based on the description of damage characteristics, the optimization of acidizing modes, and the injection parameters, meanwhile, built a set of 3D fine mathematical models for the simulation of the damage of the horizontal wells, the optimization of acidizing modes and parameters, and the evaluation after acidizing. Based on the method above and the mathematical models, we carried out the systemic simulation of a horizontal well. The results show that the damage degree of the horizontal well is extremely uneven in the 3D space. In accordance with the general acidification, multistage acidification and partial acidification respectively, then we carried out the simulation analysis by using the diverting acid system with the strength of 0.5 m ³/m. The partial acidification was better than the other two modes and its comprehensive skin coefficient decreased from 4.717 to -0.083. The optimum design of the process parameters was also carried out in the fourth part of the partial acidification. The optimal acid injection rate was 2 m ³/min and the optimal acid volume was 66 m ³. The results can solve the problem of the unsatisfactory matrix acidizing effect of the long section of the horizontal wells in carbonate reservoirs, and optimize the controllable parameters（such as treatment parameters） and uncontrollable parameters（such as formation parameters）, in order to achieve the reasonable and high efficiency acidification.

As a new parameter of the rock mechanics evaluation, the brittleness index （BI） has an important influence on the later fracturing and reconstruction of the reservoirs. The traditional calculation methods of the BI applied to the geosteering drilling of the shale gas horizontal wells have many limitations. Aiming at the calculation of the BI in real time by the LWD curves, we started with the experimental study on the BI and porosity to provide an experimental basis for calculating the BI by the porosity log information. Then, we used the regression method to analyze the relevance of the AC, DEN, CNL, GR logging values and BI, calculated the BI by using single LWD curves, and through the contribution of different logging curves to the BI, established a BI calculation method by logging while drilling of the shale reservoirs. Finally, we analyzed the feasibility of the model by the examples. The research result shows that the model is effective and adaptable, which provides a reliable basis for the geosteering drilling of the horizontal wells of the shale gas by the BI.

Due to the well-developed end cleat and surface cleat, the complicated fracture morphology forms easily in the coal-bed fracturing, and the conventional double-wing fracture model is not suitable for the optimization of the coal-bed methane fracturing design. In order to improve the production of the coal-bed methane, we proposed a characterization method for the equivalent seepage of the complex fracture, in which the complex network fracture was equivalent to the high permeability zone. By optimizing the size and permeability of the high permeability zone, we got the best overall fracturing fracture length and fracture conductivity. Meanwhile, we also optimized the pumping parameters by using 3D fracturing simulation software, and carried out the fracturing operation and down-hole micro-seismic monitor tests of 3 wells. The results showed that the fracture length covers a wide field and the complexity after fracturing is high, and the average post-fracturing daily production is 1 376.7 m ³/d. It provides a technical support to the integral fracturing development of coal-bed methane.