Multi-phase foam system is composed of gas, liquid and solid. The method used to evaluate the effects of particles on foam stability was presented due to the foam formation process altered by particles. Research shows that foam liquid drainage volume was linear with respect to its drainage time in double logarithmic coordinate system, so the slope can be used to characterize foam decay rate. Experiments were conducted to investigate the foam decay rate of 3 foaming agents and the results show that foam decay rate is only related with foaming agent concentration in the general foam system, and it is unchangeable at constant mass fraction. Experiments of the effects of particle category, size and concentration on foam decay rate were also conducted, and the results present that preformed gel particle can be used to combine with foaming agents to form a good multi-phase foam system with high foam volume and half life period; the smaller the particle size the more stable multi-phase foam system, mass fraction of particle has an impact on foam ability, and there is an optimum value for the foam stability.

For CO ₂ flooding in heterogeneous reservoir, gas channeling of CO ₂ is easy and premature to happen along the high permeable layers, which leads to low recovery efficiency of CO ₂ flooding and low-permeability reservoir is difficultly produced, optimal selection of different CO ₂ injection modes was developed in laboratory test. The influence of slug size, foam-gas ratio and surfactant-gas ratio on the optimal injection mode was also studied. The results show that foam-gas alternative flooding is an effective practice to tackle serious interlayer contradiction and prevent early gas break-though, leading to a high oil recovery. The best parameters for FAG are as following: slug size (0.4 PV), foam-gas ratio (1∶1), surfactant-gas ratio (1∶1).

The influence of certain parameters on foam flooding in heterogeneous formations was researched using paralleled core experiment.The results show that the lowpermeability formations attribute more to the increment of oil recovery in foam flooding,while the increment of oil recovery of high permeability formations is small;Considering the oil recovery and economic benefit,the injection volume of foam is supposed to be 0.3PV~0.5PV;the permeability max-min ratio should be smaller than 15 in foam flooding,and when the permeability max-min ratio was 10,the increase amplitude of oil recovery reaches maximum.The increase amplitude raises first and then declines along with the increase of water cut,when the water cut was 80% ~90%,the oil recovery reaches maximum.The continuous injection exhibits better performance than the slugging injection and the method of alternative injection of gas and liquid between foam injecting.

The foaming behavior and its influence of an anionic sulphonate foaming agent(FA220) were researched.It was found that both of the foaming volume and half-time of foam reach the highest point when the concentration of foaming agent is 0.6%;FA220 has a good ability of resistance to Mg²⁺ ,NaCl and Ca²⁺ bring some neglect impact on the stability of foam and very little impact on the foaming volume; the addition of polymer improves the foam system stability and decreases the foaming volume,the foaming volume and half-time of foam make better result when the concentration of polymer was between 0.3~0.8g/L;oil has obvious defoaming effect,the defoaming effect become stronger with the increase of oil saturation.

Bounded reservoir produced oil mainly by self-expanding energy, and pressure decreases rapidly. It can increase bounded reservoir pressure and formation expansion ability by injecting CO ₂ or flue gas. Injected flue gas, CO2 and heavy oil into a HTHP PVT equipment, and measured it's viscosity and volume factors in the condition 1 MPa to 7 MPa. Simulating heavy oil, after injected flue gas or CO ₂ , pressure depleted recovery process by using core huff and puff experiment. Experimental results show the CO ₂ and flue gas dissolved in oil can greatly decrease oil viscosity. Oil viscosity, saturated CO ₂ , decreased more than 95%, and volume expansion increased 15% in 40 ℃, 7 MPa condition；but in the same condition oil viscosity, saturated flue gas, decreased 38.1%，and volume expansion increased 4.9%. Pressure depletion experiments show the injecting 0.4 PV gas is optimum. It can displace out 57.84% oil by injecting three runs o.4 PV CO ₂; and get 43.99% by injecting three runs 0.4 PV flue gas. Oil recovery increases separately 17.31%, 13.29% by injecting 0.4 PV CO ₂ or flue gas after water flooding.

The combinational chemical agent washing experiment was carried out in order to solve the problem of low oil sand elution efficiency by using water. The affection of NaOH, Na ₂CO ₃ , combinational chemical agent and XY series agent on elution ratio of oil sand of inner Mongolia Tumidi area was studied. The optimization combinational chemical agent was selected according to the oil sand elution ratio. The experiment result shows that in the experimental condition of agent with the oil sand quality ratio is 1∶1, the constant temperature 85 ℃ and heats up for 60 min, elution ratio of NaOH and Na ₂CO ₃  combinational chemical agent is better than single lye, when XY-1 and XY-2 combustion with alkali, the optimization prescription is NaOH(1.0%)+Na ₂CO ₃ (1.0%)＋XY-1(0.15%) and NaOH(1.0%)+Na ₂CO ₃ (1.5%)＋XY-2(0.10%).

Foam fluid has good property, widely used in petroleum engineering. Density of foam fluid is very important in site application. Device designing used to measure density of foam fluid was introduced under underhole situation. Method to quantitatively determine the density-pressure-temperature relation of the foam fluid was also put forward. The relations between the density of the foam fluid and the pressure and temperature were measured using the method. Experiential formulas calculating density of foam fluid were gained through regression method. The results of measurement and conventional calculation were compared. It shows that density of foam fluid increases with pressure increases, and decreases with temperature increases. The larger the ratio of gas and liquid weight in foam fluid is, the better the condensability of foam fluid is. The measured density of foam fluid is always less than that of calculated by conventional method. Difference lies in 1.45 %to 11.31%. The reason is that repellent force of surfactant ions has not been considered when calculating by conventional method. The regressed formulas have good accordance with the experimental data. The research conclusions can direct foam fluid application in oil field.