Alkali-Surfactant Adsorption and Polymer Injectivity Measurements Using Reservoir Core from a Giant High Temperature and High Salinity Clastic Reservoir to Design an ASP Pilot

Abstract

This paper discusses static and dynamic adsorption experiments to evaluate surfactant and alkali consumption as well as polymer injectivity to guide well perforation design for an Alkaline Surfactant Polymer (ASP) pilot in a giant clastic reservoir in Kuwait. Alkali and surfactant consumption in the reservoir and polymer mechanical degradation near the wellbore have a significant impact on the effectiveness of the injected ASP slug to recover additional oil from the reservoir post water flooding. Aqueous solutions consisting of alkali, surfactant and co-solvent with and without hydrolyzed polyacrylamide polymer were injected into outcrop (Bentheimer) and cleaned reservoir cores at a reservoir temperature of 90°C. The concentration of surfactant and alkali in the effluent stream was measured using potentiometric titration and the retardation of the chemical waves in comparison to the salinity tracer wave was used to estimate chemical adsorption. For the injectivity tests, ASP and polymer drive solutions were injected at various rates into cleaned reservoir core to determine threshold onset rates for screen factor and apparent viscosity loss at room temperature and at 40°C. This laboratory study shows that surfactant adsorption can be higher when the experiments are conducted using reservoir core at the reservoir temperature of 90°C compared to literature reported adsorption values for internal olefin sulfonates (IOS) on Berea rock in the absence of alkali and polymer at room temperature. Both the static and dynamic adsorption experiments revealed that surfactant adsorption and alkali consumption was reduced in the presence of polymer. This is likely due to a competition between surfactant and polymer molecules for the adsorption sites on the rock surface. The polymer injectivity tests showed that screen factor declined above a Darcy velocity of 83 ft/day and apparent viscosity peaked at a Darcy velocity of 166 ft/day. Based on these results, it was recommended that well perforations for injection wells be designed such that flow rate does not exceed 100 - 150 ft/day to preserve the benefits of mobility control through ASP and polymer injection.

Enhancing ASP Flooding by Using Special Combinations of Surfactants and Starch Nanoparticles

“…This indicated that, over the period of five days, there was a noticeable variation that occurred in the value of SFT for this surfactant, with a slight difference between day 2 (37 mN/m) and day 3 (42 mN/m). This led to the conclusion that this surfactant is not suitable for ASP flooding, despite the fact that it has been suggested for other EOR techniques by many researchers [22,23].…”

“…The results of the adsorption and injectivity tests for the surfactants and nano-polymers are shown in Table 3. The criteria for successful application were an RF and RFF less than 1.2 and an adsorption value for every tested solution of less than 0.4 mg/1g of the core weight [23]. The RF and RFF were calculated using Equations ( 1) and ( 2), respectively.…”

Optimizing Polymer Costs and Efficiency in Alkali–Polymer Oilfield Applications

“…Similarly, field applications of using an alkali alone as an EOR agent resulted in a lower oil recovery of 1-6% [5]. Although a chemical reaction between an alkali and crude oil generates in situ saponification, alkali consumption and plugging remain significant challenges [6][7][8]. The synergy of alkali and polymer injection can surpass the reported limitations of injecting them separately.…”