Adding a surfactant to completion fluids has been widely applied to improve the initial oil production from unconventional liquid reservoirs (ULRs). However, very limited research has been conducted to understand the interactions between surfactants and salt in ULRs, and to identify the effect of ζ‐potential (ZP), interfacial tension (IFT), and contact angle (CA) on oil recovery through surfactant/salt‐assisted spontaneous imbibition (SSASI). This study investigates the interactions of surfactant and salinity in different ULR lithologies in west Texas (WT), USA, and determines the relationship between the experimental parameters and oil recovery to provide potential screening criteria for completion‐fluid design.

With the combination of numerous chemicals at different concentrations and nine salinity levels, more than 50 variations of aqueous‐phase solution were blended. Also, heterogeneous ULR rock samples of the WT formation with two different dominant lithologies, quartz‐rich (WT QR) and carbonate‐rich (WT CR), were selected. All combinations of fluid were used for ZP, IFT, and CA measurements, and some were selected for SSASI experiments with timely computed‐tomography (CT) scans. Then, all experimental results were plotted against the oil recovery factor (RF) to determine the most impactful parameter on oil recovery and to obtain knowledge regarding desired conditions of salinity for surfactant‐added completion fluid.

The effect of salinity on ZP, IFT, and CA had a similar trend for all fluid cases. With increasing salinity, the magnitude of ZP decreased to nearly 0 mV, meaning either a thin electrical double layer (EDL) or none surrounding the rock particles. Surfactant and salt reduced IFT strongly until it reached the critical salt concentration (CSC) of 30,000 ppm, and then reduction occurred gradually and slowly. Surface wettability was different for the two rock types, and the ability to alter wettability varied by the condition of fluids. Wettability alteration occurred with the presence of both surfactant and salt, but most effectively at salinity between 20,000 and 30,000 ppm. Also, the wettability of the quartz‐rich rock type showed more water‐wetting surface compared with the carbonate‐rich rock type. Out of all the experimental parameters, CA showed the strongest effect on oil recovery. Only 5 to 10% of the oil was produced when the rock surface was oil‐wet, but the oil recovery increased up to 25% when the surface became intermediate‐wet. Finally, when the rock surface became water‐wet, 25 to 40% of the oil was produced from SSASI. Consequently, on the basis of this investigation of surfactant/salt interactions, we determined the salinity of 20,000 to 33,000 ppm to be the most favorable condition for salt/surfactant‐added completion fluids, which effectively reduces IFT and yields the strongest wettability alteration.

Understanding the interactions between salt and surfactant and their behaviors in different types of reservoirs is essential when analyzing the reusability or dilution of high‐salinity produced water and successfully designing completion fluids for ULRs. The significance of this study is the ability to determine the most synergetic condition of blended‐salt/surfactant solutions and identify the parameter with the greatest impact on oil recovery in ULRs to provide surfactant‐screening criteria. Furthermore, we demonstrate economic and environmental benefits by using produced water and fresh water for completion activities.

You can access this article if you purchase or spend a download.