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Gemini surfactants have attracted intensive attention owning to their unique physical and chemical properties and have gradually been applied in the field of enhanced oil recovery (EOR). In this work, a combined cationic/anionic-nonionic gemini surfactant system consisting of cetyltrimethyl ammonium bromide (CTAB) and anionic-nonionic gemini surfactants (GAES-9) was proposed for EOR. The surface performance of the combined system was superior to that of either surfactant alone. Critical micelle concentration (CMC) data were used to calculate the molecular interaction parameters according to the regular solution theory. The combined CTAB/GAES-9 surfactant system could greatly affect the interfacial tension (IFT) between water and crude oil, and the strength of this effect depended on the mole fraction and concentration of CTAB/GAES-9. The system could reduce the IFT to an ultra-low level at a total concentration of 200 mg/L, and the system could still maintain ultra-low IFT at a salinity of 10 × 104 mg/L. The mechanism underlying the synergistic effect of CTAB/GAES-9 to obtain ultra-low IFT was systematically investigated. It is most probably related to a large number of anions and cations being adsorbed onto the oil-water interface due to electrostatic attraction. Meanwhile, the spatial structure of the elongated, flexible EO chains in the gemini surfactant entangled at the oil-water interface shields some CTAB cations, enabling the adsorption of more cations. To summarize, the combined surfactants exhibit remarkable abilities and could serve as a candidate for EOR in harsh reservoirs.

Abstract The matrix permeability of the tight sandstone reservoir is very low, which causes difficulty to inject water, the CO2 flooding is applied widely to these reservoirs for the better oil displacement and low injection pressure, but natural fractures develop as well as artificial fractures exist in the tight reservoir, makes gas-channeling along the fractures severe when proceeding a CO2 flooding process, blocking the fractures is necessary for displacing the residual oil trapped in the matrix. The self-developed tight sandstone fractured cores which can simulate different conditions of fracture width and matrix permeability had been used to evaluate the blocking effect of the high strength starch gel system, the mechanism that the high strength gel system blocked the fractures and activated the residual oil in matrix was analyzed by comparing the pressure when CO2 broke through and the incremental recovery after blocking in CO2flooding experiments, then the applicable limits that the high strength starch gel system improved the oil displacement of CO2 flooding in the tight sandstone fractured reservoir had also been discussed. The results showed that the high strength starch gel system could be used to block the fractures, and the blocking effect and the incremental recovery were the best when the fracture width was 0.42mm, however both effects became worse when the fracture width decreased to 0.08mm or increased to 0.65mm because of the injection limitation or the reduction of blocking effect; furthermore, the residual oil in the matrix could be activated effectively after the high strength starch gel blocked the fractures even if the matrix permeability reduced to 0.1mD, the research results can provide reference to the design and optimization of project when proceeding a CO2 flooding process in the tight sandstone reservoir.

In order to study the effect of gas channel on CO 2 flooding in porous medium, the gas flow velocity is divided into two parts: gas breakthrough stage and gas channeling stage. The breakthrough velocity has an exponential relationship with concentration in the frontal zone of gas area, while the channeling velocity has a linear relationship with injection pressure drop. A new method is proposed to determine the gas channeling time by using the trend line of gas–oil ratio in gas breakthrough and gas channeling stage. The production characteristics in CO 2 flooding show that recovery greatly improves after the gas breakthrough at the outlet of core sample, and most of the oil displaces before gas channeling. Thus, the extension of the stage between gas breakthrough and gas channeling becomes a key factor to improve CO 2 recovery efficiency. Improving the injection pressure drop increases the dissolved gas diffusion, which will improve the oil displacement efficiency of simultaneous oil and gas production stage, but it also increases gas channeling velocity, which will increase the gas/oil ratio sharply and result in ineffective gas injection. An optimal displacement pressure can control the diffusion rate, the channeling rate and improve the recovery of CO 2 flooding effectively. Keeping a constant pressure drop, increasing of injection pressure can not only increase the diffusion rate, but also reduce the gas channeling velocity. The achievement of a lower gas channeling velocity is advisable for extending the stage of gas–liquid production, and improving the immiscible CO 2 recovery significantly.

Compared with the traditional water-based fracturing fluid, the water-based clean fracturing fluid had the advantages of low friction, easy flowback and no residue. A kind of erucic amide propyl betaine (EAPB) was synthesized by using erucic acid and N, N-dimethyl-1,3-propanediamine as raw materials, and a clean fracturing fluid was furtherly constructed by combining EAPB with organic acid. The composition of the fracturing fluid system was determined according to the viscosity change of the system. Meanwhile, the temperature resistance, salt resistance, sand-carrying performance and micelle-breaking properties of the system were studied. The results showed that the optimum molar ratio of EAPB to sodium salicylate (NaSal) in fracturing fluid system was 50:9. The zero-shear viscosity could reach up to 129 Pa·s at 25 ℃. When the shear rate was 170 s−1 and the temperature was 80 ℃, the viscosity could keep above 60 mPa·s after continuous one-hour shearing. Furthermore, it had good sand-carrying and micelle-breaking performance. There was easy flowback and no residue after the micelle-breaking, which did low damage to the formation and achieved the effect of increasing oil and gas production. In addition, the average permeability damage rate of the fracturing fluid to the natural core of the reservoir in the target block was 6.07 %. This showed that the fracturing fluid system had the characteristics of low damage, which could effectively reduce the secondary damage after fracturing and play a certain role in reservoir protection. Therefore, it could be used as a clean fracturing fluid. The research results could provide guidance and reference for the fracturing fluid system in oilfield application.

Tahe oilfield is one of the most important fractured-vuggy carbonate oilfields in China. The characteristics of this kind of reservoir are greatly complex due to its multiple flow units: matrix, fractures and vugs. The main problems during development include the complicated oil-water relationship and the lack of fluid flow mechanism etc. However, one- and two-dimensional physical models due to its limitations cannot overall reflect fluid flow status. Based on Tahe oil field geological conditions, a 3-D visual fractured-vuggy physical model was designed and fabricated according to similarity criterion. Bottom water drive, water flooding and gas flooding were conducted in this model. Multiphase flow behavior was recorded by high resolution camera system and the pressure response was monitored at different oil displacement stages. Finally, the effect of different energy complement methods was discussed. Experimental results show that the 3-D visual physical model can be used to systematically and comprehensively investigate the fluid flow status and the oil displacement process. The pressure response presented different characteristics at different flooding stages. The fractured-vuggy structure and the ratio of displacement force and gravity determine the water/gas flooding behavior. The fluid flow mechanisms were discussed combining the pressure response and dynamic displacement phenomenon. Regarding displacement effect, water breakthrough and even serious water channeling occur more easily in fracture well than vuggy well. And water cut increases dramatically in fracture well. Compared to one- and two-dimensional physical models in previous studies, the 3-D visual physical model proposed here is more representative of the real reservoir conditions. This study could provide a constructive guide for the fractured-vuggy carbonate reservoir to improve production performance.