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.

This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment. Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation. It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity testPolymer solution injectionMeasurement of oil saturationSurfactant-polymer injection followed by polymer driveMeasurement of oil saturation This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.