With the strategic goal of “carbon peaking and carbon neutral” in China, new requirements are also put forward for the thermal recovery of heavy oil. In view of the problems of excessive greenhouse gas emission, low steam utilization rate, poor economic efficiency, and limited reservoir application of steam stimulation replacement technology in China, the emerging technologies of medium- and low-temperature thermal fluid, solvent-assisted high-temperature steam injection, solvent-based medium- and low-temperature waterless recovery and in situ electric heating-assisted recovery are discussed in terms of technical principles, technical parameters, experimental/field effects, and technical and economic potential. The technical principles, technical parameters, experimental/field results, and techno-economic potential of low-carbon heavy oil recovery technologies are summarized and future development directions and trends are anticipated. The study’s findings indicate that some of the technologies that have been tested in the field, such as HWVP, EMVAPEX, AH-VAPEX, LASER, and ESEIEH, can be developed by relying on the original well groups for production and can reduce greenhouse gas emissions, such as CO₂, by about 80% and improve crude oil recovery by 5% to 10%, while the technologies concerned have outstanding effects on increasing oil production rate and lowering upfront capital investment. Some of the technologies that have been tested significantly increase oil production rate, lower initial capital expenditure, and enable solvent recycling, among other things. Among them, COBEEOR and N-SOLV technologies can also lower the amount of asphaltene in the output crude oil, enhance the API of the recovered crude oil, and provide strong economic advantages. CSP, CHSI, and hot water solvent injection were tested in indoor two-dimensional and three-dimensional experiments to validate their feasibility, while CO₂, propane, and butane solvents were initially screened and some of the technologies’ mechanisms were revealed to lay the groundwork for pilot projects. The executive summary of the research findings will serve as a guide for future low-carbon extraction technology research and development in China.

The SAGD start-up process normally circulates steam in both the injector and producer, which consumes a large amount of steam, requires the high cost of high-temperature-produced liquid treatment, and unavoidably results in preferential communication in heterogeneous reservoirs. In order to achieve uniform preheat and full steam chamber development in SAGD wellpairs, downhole electrical heating to start up SAGD was proposed and investigated in this study using physical and numerical simulation approaches. Two 3-D scaled physical experiments were designed and implemented to investigate the feasibility and heating characteristics of such a method. Numerical simulation was conducted using an SAGD sector model with typical field properties to design the preheating process, optimize key operational parameters, and formulate the soak strategy to determine the SAGD conversion timing. The experimental results indicate that electrical heating outperforms steam circulation in achieving the uniform thermal communication in heterogeneous reservoirs, which is challenged in the conventional steam circulation process. The preheating process and operational parameters of electrical heating were formulated and optimized, which include wellbore pre-flush, wellbore saturation by heat conduction fluid, electrical heating, and replacement of heat conduction fluid periodically. Surveillance of temperature difference along the horizontal section while powering off electrical heating intermittently is optimized to be the SAGD conversion timing determination strategy. Based on the combination results of scaled physical simulation and pilot wellpair numerical simulation, full heat communication and steam chamber development are achieved along the horizontal length by electrical preheating, and the oil recovery factor of the pilot wellpair is enhanced by 14.8%, indicating encouraging potentials in heavy oil and bitumen development.

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.

The production performance of waterflood reservoirs with years of production is severely challenged by high water cuts and extensive water channels. Among IOR/EOR methods, weak gel injection is particularly effective in improving the water displacement efficiency and oil recovery. The visualized microscopic oil displacement experiments were designed to comprehensively investigate the weak gel mechanisms in porous media and the numerical simulations coupling equations characterizing weak gel viscosity induced dynamics were implemented to understand its planar and vertical block and movement behaviors at the field scale. From experiments, the residual oil of initial water flooding mainly exists in the form of cluster, column, dead end, and membranous, and it mainly exists in the form of cluster and dead end in subsequent water flooding stage following weak gel injection. The porous flow mechanism of weak gel includes the preferential plugging of large channels, the integral and staged transport of weak gel, and the residual oil flow along pore walls in weak gel displacement. The profile-control mechanism of weak gel is as follows: weak gel selectively enters the large channels, weak gel blocks large channels and forces subsequent water flow to change direction, weak gel uses viscoelastic bulk motion to form negative pressure oil absorption, and the oil droplets converge to form an oil stream, respectively. The numerical simulation indicates that weak gel can effectively reduce the water-oil mobility ratio, preferentially block the high permeability layer and the large pore channels, divert the subsequent water to flood the low permeability layer, and improve the water injection swept efficiency. It is found numerically that a weak gel system is able to flow forward under high-pressure differences in the subsequent water flooding, which can further improve oil displacement efficiency. Unlike the conventional profile-control methods, weak gels make it possible to displace the bypassed oil in the deep inter-well regions with significant potential to enhance oil recovery.

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.

There are large, heavy oil reserves in Block X of the Xinjiang oilfields, China. Due to its large burial depth (1300 m) and low permeability (26.0 mD), the traditional steam-injection technology cannot be used to obtain effective development benefits. This paper conducts experimental and simulation research on the feasibility and mechanism of CO${}_2$-energized fracturing of horizontal wells and N${}_2$ foam huff-n-puff in deep heavy oil reservoirs with low permeability in order to further explore the appropriate production technology. The foaming volume of the foaming agent at different concentrations and the oil displacement effect of N${}_2$ foam at different gas/liquid ratios were compared by the experiments. The results show that a high concentration of foaming agent mixed with crude oil is more conducive to increasing the foaming volume and extending the half-life, and the best foaming agent concentration is 3.0∼4.0%. The 2D micro-scale visualization experiment results show that N${}_2$ foam has a good selective blocking effect, which increases the sweep area. The number of bubbles per unit area increases as the gas/liquid ratio increases, with 3.0∼5.0 being the optimal gas/liquid ratio. Numerical simulation results show that, when CO${}_2$-energized fracturing technology takes into account the advantages of fracturing and crude oil viscosity reduction by CO${}_2$ dissolution, the phased oil recovery factor in the primary production period can reach approximately 13.7%. A solvent pre-slug with N${}_2$ foam huff-n-puff technology is applied to improve oil recovery factor following primary production for 5∼6 years, and the final oil recovery factor can reach approximately 35.0%. The methodology formulated in this study is particularly significant for the effective development of this oil reservoir with deeply buried depth and low permeability, and would also guide the recovery of similar oil deposits.