After multiple rounds of steam huff and puff processes, problems of excessive steam injection pressure, a large heat loss, a small sweep range of steam, and steam channeling arise, thus severely affecting the effective utilization of the oil reservoir. To solve these problems, one dimensional and three dimensional (3D) physical simulation tools were used to study the plugging performance of high temperature composite foamsby adding tanning extract and alkali lignin. The influence of reservoir temperature, salinity of formation water, and injection methods was investigated. The experimental results show that the foam can produce a synergistic effect with both the gel systems, indicating that the gel increases the stability of the foam. The foam can transfer more gel into the high permeability formation, thus efficiently controlling the foam. The 3D physical simulation experiments indicate that both the systems enhance the recovery of heavy oil reservoir and reduce its moisture content significantly using steam injection. The method involving tannin extract foam and steam injection increased the recovery by 20% compared to the foam involving only steam injection. The method involving alkali lignin foam and steam injection increased the recovery by 11%.

For the poor stability of general foams, NanoSiO ₂ was added into surfactant solution to increase the stability of foams. The surface tension and surface dilatational properties of the compounded system were measured by Tracker Interfacial Rheometer. The distribution of remaining oil and its oil displacement mechanism at each method of displacement were analyzed by microscopic model. The effect of oil recovery with two different foam systems was also studied by core experiments. It was proved that the increase of surface dilatational modules was the main reason for foam stability which can increase the sweep area and extrusion for oil on the channel wall. The core flooding results showed that both the oil recovery and the pressure drop increased with the SiO ₂/SDS foam system. 

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).