Wettability alteration toward a more water-wet state was found to be a promising approach for oil recovery improvement in oil-wet and naturally fractured carbonate reservoirs. This approach has been extensively studied in the literature using low-salinity/smart water and surfactant injection separately. However, application of surfactants in enhanced oil recovery is limited by their compatibility with the conditions of the reservoirs. In this study, polyethoxylated non-ionic surfactants with different ethylene oxide units were combined with low-salinity brine for a more efficient and cost-effective process. The compatibility of the surfactant solutions highly improved by reducing the salinity in the range of 200–2 g/L. Interfacial tension (IFT) measurements revealed that IFT decreased with increasing salinity. Contact angle measurements of calcite surfaces showed that wettability can be altered from a strong oil-wet state to a water-wet state after treatment with solutions of non-ionic surfactants over a wide range of salinities (∼2–110 g/L). ζ potential, Fourier transform infrared spectroscopy, and thermogravimetric analysis revealed that the non-ionic surfactant could partially displace carboxylate compounds from the surface and adsorb by forming a hydrogen bond with the hydroxyl group on the calcite surface. The formation of hydrogen bonds between ethoxy groups of the surfactant and hydroxyl or carboxylic groups on the solid surface can result in the replacement of organic compounds on the calcite surface. The organic compounds could form a new layer on the layer of adsorbed surfactant molecules via hydrophobic interactions. In addition, adsorption of the hydrophobic part of the non-ionic surfactant on the hydrophobic calcite surface and the formation of a surfactant double layer could partially contribute to the wettability alteration process.

The effect of synthetic surfactant molecular structure on the dynamic interfacial tension (DIFT) behavior in Na 2 CO 3 /surfactant/crude oil was investigated. Three surfactants, a nonionic (iC 17 (EO) 13 ), an alcohol propoxy sulfate (C 14-15 (PO) 8 SO 4 ), and sodium dodecyl sulfate (SDS) were considered in this study. Sodium tripolyphosphate (STPP) was added to ensure complete compatibility between brine and Na 2 CO 3 . In Na 2 CO 3 / iC 17 (EO) 13 /oil and Na 2 CO 3 /C 14-15 (PO) 8 SO 4 /oil systems, a strong synergistic effect for lowering the dynamic interfacial tension was observed, in which the dynamic IFT are initially reduced to ultralow transient minima in the range 1.1 9 10 -3 -6.6 9 10 -3 mNm -1 followed by an increment to a practically similar equilibrium value of 0.22 mNm -1 independent of Na 2 CO 3 concentration (for iC 17 (EO) 13 ) and to decreasing equilibrium values with increasing alkali concentrations (for C 14-15 (PO) 8 SO 4 ). The observed difference in the equilibrium IFT for the two systems suggest that in both systems, the mixed interfacial film is efficient in reducing the dynamic interfacial tension to ultralow transient minima (*10 -3 mNm -1 ) but the mixed film soap-iC 17 (EO) 13 is much less efficient than the mixed film soap-C 14-15 (PO) 8 SO 4 in resisting soap diffusion from the interface to the bulk phases. In both systems, the synergism was attributed, in part, to the intermolecular and intramolecular ion-dipole interactions between the soap molecules and the synthetic surfactant as well as to some shielding effect of the electrostatic repulsion between the carboxylate groups by the nearby ethylene oxide (13 EO) and propylene oxide (8 PO) groups in the mixed interfacial monolayer. SDS surfactant showed a much lower synergism relative to iC 17 (EO) 13 and C 14-15 (PO) 8 SO 4 , probably due to the absence of ion-dipole interactions and shielding effect in the mixed interfacial layer at the oil-water interface.

The effect of Na2CO3 on the cloud point in Na2CO3/surfactant/brine was investigated using two series of nonionic surfactants, C13EOx and C17EOx. The cloud point, Tcp, was found to decrease linearly with increasing Na2CO3 concentration. This was attributed to Na+ and particularly to CO32−salting‐out effect. The slope a = dTcp/d[Na2CO3] became more and more negative as the degree of ethoxylation is increased, suggesting that the higher the number of ethylene oxide (EO) groups the stronger is the cloud point depression for a given increment in Na+and CO32−ions in solution. This was also illustrated by the linear variation of ΔTcp = Tcp,0 − Tcp,[Na2CO3] with the surfactant degree of ethoxylation.

The use of ASP (alkali–surfactant–polymer) slug could be affected by the use of high hardness water, especially when injecting an alkaline agent (Na2CO3). The injection water quality of the TFT field is not adequate for cEOR (chemical enhanced oil recovery), because it contains a high hardness rate up to 160°f (report DC R&D 2019). With a TDS rate varying between 4 and 6 g/l, it could cause a formation of insoluble complexes with alkaline agents, and on the other hand, the decrease in the performances of the injected surfactants and polymers. In this work, a simulation study was carried out in order to identify the most adequate treatment process between NF (nanofiltration) and RO (reverse osmoses). The performance of the 4040 type membrane modules has been tested under different operating conditions of temperature and feed pressure (25°–45°) and (3.1–22 bar), respectively. Several membrane configurations (6:0, 4:2) have been tested to determine their effect on the process’ performance. The results showed that the NF90 4040 presents the best performances toward the requirements of the cEOR. Furthermore, the membrane configuration effects the quality of permeate and recovery rate. The results showed a rejection rate of 90% and 95%, respectively, for the total hardness (Ca2+ and Mg2+) and the sulfate.

The aim of this study is to develop and optimize a low tension water flood (LTWF) as an option for enhanced oil recovery in a tightcarbonate oilfield using a mixture of formation brines as injection water (total salinity: 165.9 g/L, Ca2+: 12.3 g/L, Mg2+: 2.0 g/L, and T = 70 °C.). In our approach, a combination of an anionic surfactant (alkyl ether sulfonate, C17EO7S(C17EO7) and a nonionic surfactant (alkyl ether, iC13EO10) were used to formulate clear and stable surfactant solutions at reservoir conditions. Formulation and optimization of a LTWF at a very low total surfactant concentration (0.01 wt%) was achieved through surfactant/brine compatibility tests (target: clear and stable surfactant solution), surfactant solution/oil interfacial tensions (target: ~ 10-3 mNm-1), phase behavior (target: type II(-) oil-in-water microemulsion) and core flooding experiments. Compatibility tests showed that the cloud point of the nonionic surfactant (0.01 wt%)is lower than the reservoir temperature (70 °C) whereas the clear point of the anionic surfactant is above the boiling point of water, suggesting that both surfactants cannot be used alone at reservoir conditions. On the other hand, clear and stable mixture of anionic/nonionic surfactants in the composition range fw = 0.1 – 0.8 (fw being the weight fraction of the nonionic surfactant) at 0.01 wt% total surfactant concentration were generated above 70 °C. Clear, transparent and gel-free oil-in-water phase behavior with relatively high oil solubilization parameters (σo ~ 125) were observed for surfactant mixture (0.01 wt%, fw = 0.1-0.8). These phase behaviors tests were validated by interfacial tension (IFT) measurements. Ultralow IFT (~ 10-3mN/m) was achieved at fw = 0.2. This optimum system was selected for core flooding experiments. Injecting surfactant (0.5PV) slug into a fully water flooded carbonate core sample resulted in additional oil recovery of 10 % of OOIP. This is a very significant result owing to the low surfactant concentration used (0.01 wt%). In another experiment, injecting a surfactant slug (0.5 PV) before water injection resulted in a total recovery of 75% of OOIP. In addition, Amott-Harvey test showed that wettability indices of the core plug samples used in the experiments changed within a narrow range (– 0.231 to + 0.164); suggesting an alteration of wettability from slightly oil-wet to weakly water-wet state.