The miscibility of flue gas and different types of light oils is investigated through slender-tube miscible displacement experiment at high temperature and high pressure. Under the conditions of high temperature and high pressure, the miscible displacement of flue gas and light oil is possible. At the same temperature, there is a linear relationship between oil displacement efficiency and pressure. At the same pressure, the oil displacement efficiency increases gently and then rapidly to more than 90% to achieve miscible displacement with the increase of temperature. The rapid increase of oil displacement efficiency is closely related to the process that the light components of oil transit in phase state due to distillation with the rise of temperature. Moreover, at the same pressure, the lighter the oil, the lower the minimum miscibility temperature between flue gas and oil, which allows easier miscibility and ultimately better performance of thermal miscible flooding by air injection. The miscibility between flue gas and light oil at high temperature and high pressure is more typically characterized by phase transition at high temperature in supercritical state, and it is different from the contact extraction miscibility of CO2 under conventional high pressure conditions.

The increasing difficulty of reservoir development leads to poor effect of EOR measures, small waterflooding sweep area and difficult miscibility of gas injection, resulting in low ultimate recovery. Air injection thermal miscible enhanced oil recovery technology can solve the problem that miscibility cannot be realized in the process of gas injection. It has been carried out in the domestic experiment and reservoir research, and has laid a solid foundation for the development program design. In reservoir testing, new technologies are proposed and supported by development plan deployment. This paper compares different injection well patterns and spacing, discusses the recovery efficiency and stable production time, determines the suitable well pattern deployment, and analyzes the advantages and disadvantages of different well patterns, so as to provide reference for the same type of reservoir and provide ideas for the development of other reservoirs. Finally, increase the sweep volume and improve reservoir recovery.

Summary The problems of oil/steam ratio (OSR) and oil production decline are prominent during the middle/later stages of steam-assisted gravity drainage (SAGD) in superheavy oil reservoirs. Using noncondensable gas (NCG) by SAGD can reduce heat loss to the overburden and reduce carbon dioxide (CO2) emissions. However, to date, laboratory experiments have mainly been conducted to simulate NCG coinjection with steam in the early stage of SAGD. There has been limited research on the NCG coinjection into the mature SAGD steam chamber. For this study, five sets of 2D physical simulation experiments are introduced and designed based on NCG coinjection with steam into the sand-packed model. The influencing factors of steam-assisted and gas push (SAGP) are analyzed through experiments, including different NCGs [methane (CH4), CO2, and nitrogen (N2)] and coinjection of NCG at different times (i.e., during the lateral expansion and descending stages of the steam chamber). The results indicate that the mechanism of SAGP includes reducing the steam consumption, maintaining the pressure balance of the steam chamber, reducing the partial pressure of the steam, maintaining the quality of the steam, and improving the displacement efficiency of the steam during the lateral expansion of the steam chamber. In addition, the top gravity displacement is the primary mechanism during the later stage of pure gas injection, which manifests that the residual oil at the bottom of the steam chamber is further recovered by using the residual heat of the the steam chamber. Compared with SAGD, the recovery of CO2-assisted SAGD (CA-SAGD), CH4-assisted SAGD (MA-SAGD), and N2-assisted SAGD (NA-SAGD) increased 6.8%, 5.4%, and 4.4%, respectively. The NCG coinjection effect was better during the descending stage of steam chamber, and the oil recovery was 4.7% higher than that during the lateral expansion stage. The selection of NCG and coinjection timing plays a crucial role in improving the ultimate oil recovery and OSR during the middle and later stages of SAGD in superheavy oil reservoirs.

Polyacrylamide (HPAM) and other traditional polymers have poor temperature resistance and salinity tolerance and do not meet the needs of high-temperature and high-salinity reservoirs. In this study, a new temperature-resistant and salinity-tolerant polymer QJ75-39 was synthesized using acrylamide (AM) as a hydrophilic monomer, 1-acrylamide-2-methylpropanesulfonic acid (AMPS) and N-vinylpyrrolidone (NVP) as functional monomers and DS-16 as a hydrophobic monomer. Through laboratory experiments, the properties (temperature resistance, salinity tolerance and aging stability), polymer injection and core displacement effect of the polymer were studied. The experimental results showed that the new polymer could meet the needs of polymer flooding technology in high-temperature and high-salinity reservoirs. Experiments showed that the polymer had a temperature resistance of 95 °C and a salinity tolerance of 1.66 × 105 mg/L. When the temperature was 95 °C and the TDS was 55,376.8 mg/L, the viscosity of the polymer was 31.3 mPa s, and the viscosity remained above 30 mPa·s after aging for 60 days. The polymer had good injectivity between 300 and 600 mD, and the injection pressure could reach equilibrium quickly. The oil recovery effectively increased with the grsowth in the amount of injected polymer. When the injection amount was 0.5 PV, the enhanced oil recovery was 20.65%. This study is of great significance for the application and popularization of polymer flooding technology in high-temperature and high-salinity reservoirs.

Physical modeling, numerical simulation and field case analysis were carried out to find out the subsurface thermal oxidation state, thermal oxidation front characteristics and production dynamic characteristics of high pressure air injection thermal oxidation miscible flooding technology. The lighter the composition and the lower the viscosity of the crude oil, the lower the fuel consumption and the combustion temperature are. The thermal oxidation front of light oil and volatile oil can advance stably, and a medium-temperature thermal oxidation stable displacement state can be formed in the light oil reservoir under high pressure conditions. With strong thermal gasification and distillation, light oil and volatile oil are likely to form a single phase zone of gasification and distillation with thermal flue gas at the high-temperature and high-pressure heat front, finally, an air-injection thermal miscible front. In light oil reservoirs, the development process of high-pressure air-injection thermal miscible flooding can be divided into three stages: boosting pressure stage, low gas-oil ratio and high-efficiency stable production stage and high gas-oil ratio production stage. Approximately 70% of crude oil is produced during the boosting pressure stage and low gas-oil ratio high-efficiency and stable production stage.

Laboratory experiments and pilot applications have proved that urea is an efficient agent to enhance heavy oil recovery. Numerous studies have been conducted to investigate the mechanisms of urea co-injection process in steam flooding or cyclic steam stimulation. However, investigations of applying urea in steam assisted gravity drainage (SAGD) process are rarely published. The mechanism of enhanced oil recovery in the urea assisted SAGD process has not been fully understood. Laboratory experiments and numerical simulations were conducted to study the decomposition rate of urea, the effect of urea decomposition products on reservoirs and pipelines, and the distribution of effective decomposition products of urea in the steam chamber at conditions of different concentrations, temperatures, and injection rates. The results show that the solubility of the effective urea decomposition products affects their distribution in the formation because of the huge difference between the solubility in oil and water. In SAGD process, urea cannot be completely decomposed and will produce solid decomposition products, which could block the reservoir pores and production pipelines in certain conditions. Moreover, numerical simulation indicates that the use of low-concentration urea injection in SAGD can effectively enhance oil recovery and oil production rate, while high-concentration urea can reduce the oil recovery and oil production rate. In addition, it was proved that CO2 mainly exists at the edge of the steam chamber and NH3 is distributed in the irreducible water near the well-bore. CO2 is more effective than NH3 for enhancing oil recovery in urea assisted SAGD. Studies indicate that urea co-injection is a feasible method for enhancing oil recovery in the SAGD process.

Hot water flooding is one of the main strategies employed in the recovery of heavy oil. However, the low viscosity of the injected hot water readily generates the formation of water channels in oil bearing formations with high permeability, resulting in relatively low oil recovery. This study addresses this issue by experimentally investigating the application of a CO2 foam injection process as a secondary strategy after hot water injection. Six surfactants were evaluated for foam generation at temperatures in the range of 57-200 degrees C in a series of screening tests, including static foam tests, thermal stability testing, and resistance factor evaluation. The optimum surfactant was accordingly selected for application in the CO2 foam injection process. The addition of 0.04 wt% anionic polyacrylamide (HPAM) as a stabilizer in the selected surfactant produced a more stable foam appropriate for use at a temperature of 80 degrees C or less. Oil displacement experiments were conducted using both a high permeability sand pack and a low permeability sand pack simultaneously to investigate water channel creation during hot water injection and the channel blockage resulting from the injected foam along with the corresponding oil recovery enhancement. The experimental results indicate that hot water in the hot water injection process flows readily through the high permeability sand pack and reduces the oil viscosity, which results in an increased degree of water channeling of the high-permeability sand pack. The high-temperature CO2 foam generated under optimum conditions using the selected surfactant effectively blocks the water channeling created during the preceding hot water injection process and significantly increases the oil displacement efficiencies of both the low- and high-permeability sand packs. The results of this study demonstrate that the secondary injection of CO2 foam following hot water injection represents a promising heavy oil recovery strategy for developing heavy oil reservoirs.