Surfactant flooding as a potential enhanced oil recovery technology in depleted reservoirs after water flooding has attracted extensive attention. In this study, 12 surfactants belonging to five different types of surfactants and their compounded formulations were investigated for surfactant flooding under 90−120 °C and 20 × 10 4 mg/L salinity. Two surfactant formulations obtained a stable ultralow interfacial tension (IFT) level (≤10 −3 mN/m) with crude oil after aging for 125 days. The surfactant formulations were used to further investigate the effects of the initial IFT values, the dynamic reduction rate of IFT, and the surfactant concentration and emulsification on oil recovery through core flooding experiments. The results indicated that oil recovery increased with the decrease of the initial IFT values and the increase of the dynamic reduction rate of IFT. The 10 −3 mN/m IFT level yielded an additional oil recovery of approximately 7% compared with the 10 −1 mN/m IFT level. However, under the same IFT level (10 −4 mN/m), it was not the bigger the surfactant concentration that resulted in a higher additional oil recovery. In four surfactant concentrations (0.2%, 0.5%, 1%, and 3%), the 0.5% surfactant formulation obtained the highest oil recovery of 36.65%. Further study manifested that emulsification has important effects on oil recovery. When surfactant concentrations were increased to 1% and 3%, the emulsification was too strong, which makes it more difficult to displace oil. The two selected surfactant formulations could successfully yield additional oil recovery of 20−26%, which indicates these two formulations have great potential for improving oil recovery in high temperature and high salinity oil reservoirs.

This research is intended to reveal the difference and connection of oxidation behavior between crude oil and its SARA fractions. Thermogravimetry (TG) and differential scanning calorimetry (DSC) techniques were used to characterize oxidation behavior. The results showed that the oxidation behavior of individual SARA components exhibited an obvious difference. Saturates showed a weak high-temperature oxidation (HTO) region. Asphaltenes generated more heat in HTO than in the low-temperature oxidation (LTO) region. Aromatics showed intense exothermic activity in both LTO and HTO regions. Heat release and mass loss showed a good correspondence in the HTO region for all SARA fractions, which means heat release and mass loss were caused by the same reaction mechanism that is believed to be the coke combustion as it is the only significant reaction in the HTO region. However, the good correspondence did not exist in the LTO interval where the reactions are more complicated and a multiple-step mechanism should be considered. In addition, it is not quite reasonable to determine the reactivity of SARA fractions only by TG data as little mass loss does not mean reactants are inactive. Kinetic parameters of LTO and HTO reactions were determined by Friedman and Ozawa–Flynn–Wall isoconversional methods. In general, for the crude oil and each fraction, the activation energies of HTO were higher than that of LTO. The additivity of DSC data could be applied quite well in the LTO region. However, the predicted curve seriously deviated from the actual situation after 350 °C, which implies the exothermic reaction process of individual components was influenced by the presence of other components. Nevertheless, the total heat release of the measured and predicted values was similar, which makes it possible to predict the heat effect of crude oil from individual SARA components.

The oxidation behavior of three crude oils was characterized by thermogravimetry coupled with Fourier transform infrared spectroscopy (TG−FTIR) to investigate the oxidation mechanism of crude oils. The results indicated that the entire oxidation process can be divided into three main reaction intervals: low-temperature oxidation (LTO) interval (<400 °C), coking process (400−500 °C), and high-temperature oxidation (HTO) interval (500−650 °C). For the LTO interval, oxygen addition reactions to produce hydroperoxides were believed to be dominant at the early stage, while the isomerization and decomposition reactions of hydroperoxides became more significant at the later stage. For light and medium oils, the isomerization and decomposition reactions that release H 2 O started at about 200 °C and the isomerization and decomposition reactions that release CO 2 and CO started at about 300 °C. However, no CO 2 and CO were detected in the LTO interval of the heavy oil, which means that the reaction pathways of the heavy oil might be a little bit different from those of the light and medium crude oils in LTO intervals. Evaporation played an important role during the entire LTO interval. In the coking process, the coke formation by the oxidative cracking of the LTO residue is believed to be the main reaction with the release of gaseous products of CO 2 (and CO), H 2 O, and hydrocarbons. In the HTO interval, the combustion of coke was considered as the only one significant reaction. For the LTO and coking process, the activation energies increased with the decrease of the American Petroleum Institute (API) gravity of crude oils. However, for the HTO stage, the activation energies were similar (100−125 kJ/mol) for different crude oils.

High pressure air injection (HPAI) without ignition has attracted extensive attention in the air injection based improved oil recovery (IOR) process for light oil reservoirs but was rarely proposed as an IOR process for heavy oil reservoirs. This study aims at evaluating the potential of HPAI without ignition for deep, high pressure, heavy oil reservoirs (Tahe oilfield, Tarim Basin, China). Many low-temperature oxidation (LTO) experiments were carried out to study the oxidation behavior of heavy oil under the reservoir conditions (120 °C, about 30–40 MPa) using an isothermal oxidation reactor. The produced gases were analyzed using gas chromatography for their content of O2, CO2, CO, and hydrocarbon gas (C1–C6) content. The apparent hydrogen/carbon (H/C) and molar ratio of the carbon oxides (m-ratio) were also calculated from effluent gases to analyze oxidation behavior. The effects of quartz, reservoir core (characterized by X-ray diffraction), formation water, and catalyst on LTO were analyzed. Thermogravimetry (TG-DTG) experiments were conducted to characterize the oxidation behavior and kinetics of heavy oil. The Arrhenius method was employed to calculate reaction activation energy. The isothermal oxidation experimental results show that reservoir core, formation water, and catalyst have important influences on LTO. The upgrading of heavy oil occurred in the presence of catalyst. The inflammable coke was formed, and combustion reaction happened at 40 MPa and 120 °C after oxidation for 7 days, which implies heavy oils have a spontaneous combustion potential for HPAI without ignition process in Tahe heavy oil reservoir. Simultaneously, the heavy oil upgrading indicates that HPAI without ignition process in the presence of catalyst is a promising and potential air injection based IOR technique for deep, high pressure, heavy oil reservoirs such as the Tahe oilfield.

Foam performance during oil displacement is closely related to the reservoir environment. In this study, both bulk and porous media experiments were conducted to investigate surfactant foam and polymersurfactant foam behaviors at high temperature and with crude oil. After aging at 90 C for 90 days, the foam drainage half-life of the aged polymer-surfactant foam was four times longer than that of the fresh surfactant foam. Scanning electron microscope images indicated that, even experienced high temperature aging, the polymer and surfactant could still develop multilayer complexes to enhance the foam film strength. Within a certain oil content, the foam stability in the presence of oil could be better than in the absence of oil. Stereoscopic microscope images revealed that the existing form and content of oil in the foam film had played a vital role. Core flooding experiments further confirmed that stable surfactant foam and polymer-surfactant foam could generate in the presence of waterflooded residual oil and give rise to additional oil recovery of 15.35% and 35.75% at 90 C, respectively. The positive responses of this study may be attractive to potential foam field applications.