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 order to meet the practical needs of profile control and flooding technology in Bohai reservoir, the hydration dynamic characteristics and seepage characteristics of polymer microspheres were studied in this paper. Results indicate that, with the prolonging of hydration time, the expansion ratio of polymer microspheres increases, and the final expansion ratio is about 4.5. When the hydration time is less than 50 h, the expansion velocity is faster, then the expansion velocity slows down, and finally reaches stable after 360 h. Compared with the size distribution of molecular aggregates in the polymer solution, the size distribution of the two polymer microspheres is relatively concentrated. The initial median particle size of 10 ^# microspheres is 4.36μm, and then reaches 20.00 μm after hydration for 240 h. The initial median particle size of 11 ^# microspheres is 8.45 μm, and then reaches 40.0 μm after hydration for 360 h. The expansion ratio is about 4.72. In the injection process of polymer microsphere, the adhesion between particles and the pore filtering effect can cause the retention and temporary plugging of polymer microsphere in the core end, which leads to the abnormal increase of the pressure in the injection process. The polymer microspheres can further hydration expand in the core pore, showing the seepage characteristics of “migration, trapping, re migration and re trapping......”.

This paper researches the seepage characteristics and oil displacement effect of polymer solution and weak-base ternary compound system, taking the reservoir geology and fluid from Daqing Oilfield as research object, taking injectionpressure and oil recovery as the evaluation indexes. Results show that, under the condition of the same oil displacement agent viscosity and slug size, the oil recovery increment of weak-base ASP flooding is larger than that of polymer flooding. Because there are emulsification and Jamin effect during weak-base ASP flooding, which can increase seepage resistance and injection-pressure, and its oil sweep efficiency is also higher. Compared with ternary compound system with scaleremoval water, there are carbonate micro particles in the sewage ternary compound system, which can be detained in porous media. This can increase seepage resistance and cause fluid diversion effect, which eventually leads to a large increase in oil recovery. Compared with constant-speed experiment, it is early for constantpressure experiment to adopt peak-pressure, which accelerates the forward speed of agent in the core high permeability layer and shortens the breakthrough time. As a result, the sweep efficiency and oil displacement efficiency of constantpressure experiment is lower.

Aiming at the reservoir geological characteristics and fluid properties of BZ251s oilfield in Bohai reservoir, taking diversion ratio, interfacial tension, viscosity and structure of the emulsion as evaluation index, the reducing viscosity effects of emulsification and its related mechanism were studied. The results showed that, when the ratio of oil and water was less than 7∶3, and the concentration of emulsion agent was higher than 600 mg/L, the intensified disperse system could form emulsion liquid with crude oil, and its ratio of reducing viscosity could reach 80%. Compared with the intensified cold production system, the intensified dispersion system had a significant advantage in demulsification, reducing interfacial tension and anti adsorption. The emulsification of this system and crude oil could lead to part of the component getting into the crude oil, which influenced the interfacial tension and emulsification effects between crude oil and the intensified disperse system. The intensified dispersion system can reduce the injection pressure and water content increasing rate，and it can enhance the oil recovery more effectively.

Influence of ASP system on the fracture conductivity of alkaliresistance resin sands and quartz sands was studied. The results showed that compared with the weak base, the dissolution of strong base on the quartz sands was more serious. And the damage percentage of the particles was higher. Therefore the reduction of conductivity of fractures packed with sands was larger. Compared with quartz sands, there was little difference between the dissolution of weak base on the alkaliresistance resin sands and that of weak base on the alkaliresistance resin sands. So it was the same to conductivity. With the increase of closing pressure, the conductivity of quartz sands and alkaliresistance resin sands were both weakened. But the reduction degree became gradually small. Compared with quartz sands, the influence of closing pressure on the conductivity of fractures packed with alkaliresistance resin sands was weak. And the fracture conductivity capacity was stronger.

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.

In order to explore a method of further enhancing oil recovery after alkaline/surfactant/polymer flooding, taking Xingshugang oilfield in Daqing as an experiment platform and regarding oil recovery, water content and injection pressure as evaluation indicators on enhancing oil recovery, an experiment was conducted under the condition of the constant temperature and constant pressure. The results showed that alkali/surfactant/polymer with strong base system, surfactant polymer system and alkali/surfactant/polymer with weak base system could all further enhance oil recovery, and the effect of high concentration polymer liquor was the best. The greater the subsequent of the injection pressure rose, the more the recovery growth was. Taking into account the constraints of Daqing oilfield reservoir and equipment capacity. Based on the comprehensive consideration of technical and economic effects, aurfactant polymer system has more application prospects.

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.

Aiming at technical demand on relieving the reverse of imbibition profile, displacement effect of alternate injection of Cr3+ polymer gel and water was studied, taking reservoir of Bohai oilfield as simulation object, regarding injection pressure, water content and recovery efficiency as evaluation index. Results showed that as the displacement agent flowed into the medium and low permeability layer, on the one hand, the swept volume was magnified. On the other hand, seepage resistance and start up pressure of imbibition were increased, thus resulting in the reverse of the imbibition profile. Once the alternate injection of Cr3+ polymer gel and water was adopted, polymer solution could get priority to flow into the high permeable layer and block off it, then subsequent water flowed into medium and low permeability layers to displace the oil. Therefore the phenomenon of the reverse of imbibition profile was relieved or even eliminated. Once the alternate injection of C3+ polymer gel and water was conducted in A22 injection well in LD5 - 2 Oilfield, injection pressure get increased, which was good for enlarging sweep volume effect.

Molecular aggregation state of saltresistance polymer was changed by intermolecular association, which transparently enhanced its property of saltresistance. However, molecular size was increased while the state of molecular aggregation was changed. Thus the question of worse adaptability between saltresistance polymer and reservoir came out. By means of instrument analysis, chemical analysis and modern physical simulation method, taking reservoir geology, fluids and polymersurfactant agent of Daqing as research platform, regarding polymersurfactant solution viscosity, molecular thread size and seepage characteristics as evaluation index, the research on the adjusting method and effect of the state of molecular aggregation of polymersurfactant agent was carried out. The results showed that βCD could restrain the association of polymersurfactant molecules, thus reduce the size of molecular aggregation of polymersurfactant agent. All this led to the wider range of the permeability that could be flowed through. There existed a best matching relationship between polymersurfactant/βCD and core heterogeneity. On this point, the effect of enlarging sweeping volume of polymersurfactant agent was optimal and recovery efficiency reached a climax. 

In order to further explore intramolecular rosslinked gelation mechanism of Cr ^3+ polymer gel under different pH conditions, effect of pH on Cr ^3+  polymer gel gelation performance was researched. Polymer gelformulation composition with good gelation performance was obtained by orthogonal experiment taking polymer mass concentration, water solution salinity and "polymer/Cr ^3+ " as the influence factors, aimed at Daqing Lamadian oilfield geological characteristics and fluid properties. The results showed that acidic conditions could promote ionization of chromium acetate and increase the number of Cr ^3+  in solution, thus increase the probability of coordination reaction between carboxyl in polymer chains and polynuclear olation complex ion, which is in favor of the formation of intramolecular crosslinked Cr ^3+  polymer gel system. The number of OH ^- was increased with solvent water pH, which could result in the reduction of Cr ^3+  involved in crosslinking reaction and gelation performance getting worse accordingly. when the system was similar to intramolecular crosslinked Cr ^3+  polymer gel, gelation performance of polymer gel system can be further improved by appropriately reducing pH value of solvent water.