Effects of crude oil composition on the ASP flooding: A case from Saertu, Xingshugang and Lamadian Oilfield in Daqing

Effects of conventional and ionic liquid-based surfactants and sodium tetraborate on interfacial tension of acidic crude oil

The application of a new class of surfactants such as ionic liquids (ILs) compared with the conventional surfactants and their interactions with each other concomitant and alkaline under salinities is not well examined based on the best knowledge of the authors. So, the current work focused on the impact of sodium lauryl sulfate (SDS), sodium dodecyl benzene sulfonate (SDBS), 1-dodecyl 3-methyl imidazolium chloride (C12mim][Cl]), 1-octadecyl 3-methyl imidazolium chloride ([C18mim][Cl]) in the presence and absence of alkali namely sodium tetraborate known as borax (Na2B4O7) on the IFT variation while the salinity was changed 0-82,000 ppm (ionic strength of 0-1.4 M). The results showed the positive impact of salinity on the pH reduction and reduced the alkaline effect for pH reduction. Also, the measurements showed that the presence of surfactant reduces the role of alkaline for pH variation as it moved from 9.2 to 6.63 for the solution prepared using SLS and SDBS. The measured IFT values showed that not only alkali has a significant impact as it combined with SLS and SDBS due to a desired synergy between these chemicals, it can reduce the critical micelle concentration (CMC) for the SDBS from 1105 to 852 ppm and much higher for [C12mim][Cl].

Optimization of enhanced oil recovery using ASP solution

Many studies have been conducted to focused on developing an optimal alkali/surfactant/polymer (ASP) composition to increase the recovered fraction of oil in reservoirs that have already undergone water injection. To analyze the effect of alkali (Na2CO3), surfactant (lauryl sodium sulfate), and polymer (commercial xanthan gum) concentration on oil recovery, a complete factorial experimental design was performed with combinations of three variables (alkali, surfactant, and polymer) and three central point replications (2³ + 3). The experiments were carried out on a core holder using rock samples from the Botucatu formation. The simulated oil reservoirs have an average permeability of 348 mD and a temperature of 60 °C. The crude oil was acquired from the Carmópolis field, with 25.72 °API. Synthetic production water containing 40,000 mg L-1 of NaCl and 13,000 mg L-1 of Na2SO4 was injected through an HPLC pump to saturate the rock samples and to recover the oil in the secondary step. From the experimental results, it was verified that the surfactant and polymer concentrations are the most statistically significant independent variables and that first-order interactions are not statistically significant for the process. The oil recovery factors in the secondary stage ranged between 30 and 36 % of the OOIP, which are within the range reported in the literature. The optimal composition of the ASP fluid obtained a recovered fraction of oil of 62 % in the advanced step. Other combinations reported in the literature used higher concentrations of alkali, surfactant, and polymer with lower recoveries and higher cost in the injection design. Thus, the present study highlights the necessity to investigate the performance of each component of the ASP solution. In addition, the results obtained in this study are very attractive for possible full-scale applications.