Yanmuxi reservoir in Tuha shows low rock cementation, strong reservoir heterogeneity and high salinity of injected water.Long term water injection development has formed an advantage channel, and the existing technology is difficult to meet the technical requirements of deep liquid flow diversion.The compatibility of inorganic gel and surfactant was studied based on the reservoir geological and fluid characteristics of the target reservoir.The results showed that nonionic surfactant (DWS) solution had good salt resistance property.Inorganic gel (calcium silicate or magnesium silicate) has little effect on DWS solution,indicating that the displacement effect during alternate injection process and profile control will not be affected too much.When surfactant emulsifies with crude oil,"Jiamin effect" can produce additional seepage resistance and liquid flow diversion effect,so the recovery rate increases greatly.In the three combinations of inorganic gels,surfactants and nitrogen,the "inorganic gel+surfactant solution+gas" alternate injection mode exhibits higher injection pressure, and superior liquid flow diverting and expanding the volume effect.

The construction process of "carrying liquid + supporting agent" has been adopted in field fracturing. The preparation and transportation of carrying liquid not only cost a lot of manpower and material resources, but also have poor ability to deal with emergencies in the mine. The self⁃suspension proppant has been prepared and injected at the scene, and its product filtration and its influence on reservoir permeability have been highly concerned by petroleum technicians. The experimental study and mechanism analysis of the effect of fluid loss of self⁃suspension proppant on core permeability are carried out. The results show that when the injection speed was constant, with the core permeability increased, the filtration loss got increased, the damage rate decreased. With the gel breaking time increased, the amount of filtration loss got larger and the damage rate decreased. The degree of influence of gel breaking fluid on core permeability had little relation with its viscosity, which mainly depended on the amount of residue retention and erosion resistance in porous media after glue breaking. Under the condition of "constant pressure experiment", the larger the pressure difference of filter loss, the larger the amount of filter loss, and the damage rate presented the trend of "first increase and then tend to be stable". Compared with the constant speed test, although the amount of filtration loss is relatively small, the damage rate is high. Relationship between the damage rate of three kinds of coating materials to reservoir: hydrophobic associative polymer > medium molecular weight polymer > guanidine adhesive.

A comparative experimental study on the fracture conductivity between the self propping agent and the “propping agent + carrier fluid” has been carried out, and the mechanism analysis has been carried out. The results show that whether the self supporting proppant or the “propping agent + carrier fluid”, the fracture conductivity decreases with the increasing of closing pressure. With the increase of sand concentration, the conductivity of fracture increases. Compared with those of quartz sand, the compressive strength and the fracture conductivity of ceramsite are obviously higher. On the one hand, the polymer carrying liquids can enhance the compressive strength of proppant, reduce the crushing rate, and further increase the conductivity of fracture. On the other hand, the retention of carrier fluid among proppant particles will result in decrease in permeability, which will reduce the conductivity of fractures. Therefore, the fracture conductivity is the result of the interaction of permeability and fracture rate. Compared with that of the “proppant + carrier fluid”, the breaking rate of the self propping proppant is slightly higher, which has no obvious effect on fracture conductivity. It can be seen that the process of the self suspension proppant has no effect on the proppant compressive strength and the fracture diversion.

In recent years, with the growth of oil consumption and the reduce of new proved reserves, the development of high viscosity oil reservoir was paid more and more attention. As Kongnan block of Dagang oilfield has characteristics of hypercoagulability, high viscosity and high salinity, core flow experimental apparatus and core displacement experiment apparatus were used to study the effect of oil displacement efficiency of polymer/surfactant combination system, and analyze the mechanism of the relationship between recovery growth and core permeability. The results showed that, for the weak heterogeneous reservoir, with the increase of core permeability, the resistance coefficient and residual resistance coefficient of the polymer/surfactant combination system were decreased. With the increase of viscosity ratio (μsp/μo) and core permeability, the oil recovery increased, but the increase rate decreased. With the increasing of the core permeability, the size of the rock increased, while the inaccessible pore volume decreased. So the adaptability of the reservoir and the polymer/surfactant combination system was affected by the average permeability, and then the effect of the polymer flooding of the polymer/surfactant combination system flooding was influenced. Comprehensively considering technical and economic effects，the reasonable viscosity ratio (μsp/μo) in polymer flooding should be about 0.5~1.0．

In recent years, more attention was paid to unconventional reservoir development due to the increase in oil consumption and the reduction of new proved reserves. The reservoirs of Kongnan Block in Dagang Oilfield belong to the high temperature, high salinity and hypercoagulable reservoirs. In order to improve the effect of polymer/surfactant binary combination flooding, the effect of solvent water treatment on polymer/surfactant binary combination based on Kongnan Block of Dagang Oilfield reservoir geologic al characteristics and fluid properties was studied. The results show that, elimination of the Ca2+ and Mg2+ in the injected water can enhance the association of hydrophobic associated polymer and improve the viscosity and flow turning ability of polymer/surfactant binary combination. After adding into the polymer/surfactant binary combination, not only can eliminate the adverse effect of Ca2+ and Mg2+ on the salt resistance of hydrophobic associated polymer, but also can form a large number of particles which can further enhance flow turning ability by entering reservoir porosity. Compared with injected water and softened water, the flow turning ability and recovery of the polymer/surfactant binary combination which is configured by softened water with particles are better.

Hydrophobic associating water  solute polymer has excellent viscosity and salt resistance, but the adaptability between its "mesh" molecular aggregation and reservoir pore throat causes attention of petroleum technology staffs. Aimed at the actual need, gui ding by reservoir engineering, physical chemistry and organic chemistry, the adaptability with hydrophobic associating polymer and experimental effect on southern reservoir were carried out using instrumental analysis, chemical analysis and physical simula tion as technical means. Results showed that with the increasing of β - CD, the viscosity of hydrophobic associating water solute polymer solution first reduced quickly and then got stable. When the concentration of β - CD was 0.07%, hydrophobic association between groups was completely suppressed, and the viscosity of polymer solution was bulk viscosity. In addition, the aggregation size of hydrophobic associating polymer molecular was decreased by β - CD, and the entering extent to reservoir of the polymer molecular group was expanded, thus the adaptability of hydrophobic associating water solute polymer with reservoir was improved.