Viscosity-reducer flooding is an effective method to improve oil recovery after the water flooding of heavy oil, and water-in-oil emulsion (W/O emulsion) is easily formed during this process. W/O emulsion has a strong ability to improve mobility ratio and block off high permeability layers, which can effectively improve sweep coefficient and enhance oil recovery. The microscopic visual glass model is mainly used to study the microscopic oil displacement mechanism of dilute oil; however, there are few studies on the emulsification mechanism and influencing factors of heavy oil. The purpose of this paper is to study the mechanism of heavy oil emulsification caused by viscosity reducer at the microscopic level, and the effect of emulsification on heavy oil recovery. The visible physical experiments with the glass microscopic models with different permeability and pore sizes were carried out to study the mechanism and main controlling factors of emulsification and the oil displacement effect of viscosity reducer. On this basis, the software was used to calculate the oil recovery in different areas of the model in different flooding stages, which provides a more intuitive understanding of the oil displacement effect of viscosity reducer. The results showed that there are mainly three types of emulsifications between pores: pore throat-breaking emulsification, blind-end emulsification, and pore channel extrusion emulsification. Hence, the mechanism of the three types of emulsifications and the relationship between droplet size with shear stress have been explored. The shear stress increased with the increase of the shear rate, and the oil droplet size in the model decreased with the increase of the shear. The blocking mechanism of pore throat and the shearing action of viscosity-reducer solution are the main mechanisms of viscous oil emulsification between pores. Generally, the particle size of the emulsified oil droplets formed by the blocking action is large, and it is easy to form pore throat emulsion. The particle size of emulsified oil droplets formed by shearing of viscosity-reducer solution is small. When the pore diameter is smaller than the particle size of oil droplets, the mobility of oil droplets between pores is poor, which means the oil droplets easily accumulate at the blind end to form residual oil. From the results of viscosity-reducer flooding experiments, the heavy oil recovery in each area of the model has been significantly improved after viscosity-reducer flooding compared with water flooding, with the recovery factor in the edge area of the model improving by up to 24.22%. The viscosity-reducer solution has a significant displacement effect on the residual oil in the edge area of the model.

In the process of waterflooding development of heavy oil, W/O emulsion has a strong ability to improve the mobility ratio and block the high-permeability layer, which can effectively improve the sweep coefficient and enhance oil recovery. In this paper, the stability and droplet size distribution of emulsions under different conditions were studied by taking heavy oil and formation water from Jimusar Oilfield in Xinjiang as samples. On this basis, double-pipe core flooding experiments were carried out to study the shut-off ability and oil displacement efficiency of W/O emulsion, and then a numerical simulation was carried out. The results show that oil and water can be completely emulsified when the stirring speed is higher than 4000 r/min. A stable emulsion can be formed when the experimental temperature is lower than 60 °C. A lower water cut results in a more stable emulsion. The emulsion is difficult to stabilize after the salinity exceeds 10,000 mg/L. When the pH value is about 7, the stability of the emulsion is the worst. With the increase in stirring speed, the increase in temperature, and the decrease in water content and salinity, the emulsion droplet size range is relatively concentrated, and the average particle size is smaller. In heterogeneous reservoirs, the permeability of different percolation channels is quite different, such that the displacement fluid only percolates along the high-permeability channel and cannot drive oil effectively. The results of displacement experiments show that the emulsion with a water cut of 60% has high viscosity and obvious sweep ability, but its stability is very poor; the effect is opposite when the water cut is less than 40%. The shut-off ability of W/O emulsion disappears gradually when the permeability contrast is more than 5.92. The research results are of great significance for improving oil recovery in heterogeneous heavy oil reservoirs.

It is necessary to establish effective communication between two horizontal wells during the preheating period of steam-assisted gravity-drainage (SAGD). However, the preheating time is usually very long, which results in high steam consumption and CO₂ emissions. There is little research on the effects of different wellbore fluids during the preheating period. The heat transfer and heating characteristics of different wellbore fluids–water, heat-conduction oil, and air–were explored by using physical experiments and numerical simulations. In this study, the results indicated that the heat-transfer performance of heat-conduction oil is the best. The numerical simulation’s results indicated that compared with the wellbore saturated with water, the heat-conduction oil reduced the viscosity of crude oil, and energy consumption was not obvious during the preheating stage. The super-heavy oil flowed into the wellbore due to the solubility of the heat-conduction oil and its own gravity. As a result, the super-heavy oil content in the wellbore gradually accumulated, increasing the risk of coking. Those experiments showed that the use of electrical heating provides good potential to improve SAGD efficiency during the preheating period, and water is the best injection fluid for wellbores during the electrical heating process.

In the process of steam injection development of heavy oil, due to the serious heterogeneity and interference of steam channeling in the high-permeability layer, there is a lot of oily sludge in the produced liquid of oil wells, which is difficult to deal with. According to existing profile control technology and the related properties of oily sludge, a profile control system was developed by using oily sludge as the main agent and by adding other additives. At the same time, the properties of sludge, the matching relationship between the particle size of sludge and the formation of pore roar, the temperature resistance, the plugging ability, and other contents were studied. The agent featured an adjustable curing time (3 to 300 h) and resistance to pressures greater than 6 MPa and temperatures greater than 350 °C. After the agent was injected into the high-permeability steam channeling, the system was cemented with the formation rock and the sealing rate was more than 85%, without any damage to the low- and medium-permeability layers. According to the different characteristics of the production well and steam injection well, the construction technology was optimized, the oily sludge profile control technology suitable for heavy oil reservoirs was formed, and the field test was carried out. At present, more than 150 wells have been used in the field, with a cumulative oil increase of 10,756 tons. The technology not only solves the environmental pollution caused by oily sludge but also reduces the cost of thermal recovery of heavy oil, with great significance for improving the final recovery efficiency and commercial benefits of the oilfield.

To resolve the issues of the high porous medium flow resistance, low oil production rate, high oil decline rate, and low oil recovery factor for the cyclic steam stimulation (CSS) of horizontal wells in heavy oil reservoirs, the CSS method assisted by the electric heating (E-CSS) of horizontal wells was proposed in this study. Combining the heat from electric heating and steam during E-CSS, the analytical model of formation temperature rise was established for the three phases of electric-assisted CSS (i.e., injection, soaking, production), and physical experiments were carried out to compare the performance of conventional CSS and E-CSS. The experimental results were used to validate the analytical model and reveal the impact of the key electric heating mechanism on the horizontal CSS performance. Meanwhile, the typical well model was used to forecast the E-CSS potential. The results indicate that electric heating can achieve uniform heating in the steam injection phase, maintain heating around the wellbore in the soak phase, and reduce flow resistance and enhance oil output in the production phase. Forecasts of the typical well model indicate that electric heating can enhance the oil recovery factor by 9.4% and the oil-steam ratio from 0.14 to 0.23, implying a significant application potential in heavy oil reservoirs developed by horizontal CSS.