Field Injectivity Improvement in Heavy Oil Carbonate Reservoirs: Effective Surfactant Formulations for Lower Permeability Carbonates

Abstract One of the significant issues in producing heavy oil is that the higher inherent in situ oil viscosities lead to poor displacement during a waterflooding operation. Polymer flooding has been shown to be beneficial to improve overall recoveries with a modest decrease in mobility ratio compared to waterflooding. However, injecting a viscous polymer solution can reduce injectivity over time due to presence of near wellbore residual oil. The objective of this study is to identify promising surfactant formulations and test them in porous media to solubilize near wellbore oil to enhance injectivity. Previously published work has focused on sandstones and there is no comparable literature in carbonates. We focus on injectivity enhancement in carbonates. Several families of anionic and non-ionic surfactant mixtures were tested initially for phase behavior studies to understand solubilization potential at the salinity and temperature of interest. Formulations that had both aqueous stability and solubilization potential based on observed Winsor Type I to Type III windows were chosen for coreflood experiments. Initially, two basic corefloods were performed in sand packs to establish baseline performance. We then followed up with testing in surrogate carbonate cores. To understand the effect of geometry on the surfactant- oil solubilization behavior, different chemical amounts were used in 2D rock slabs to quantify displacement efficiencies. In contrast to sandstones where oil displacement was the dominant mechanism for near wellbore oil saturation reduction, we observed that solubilization was the preferred approach in carbonates. Since very high viscosity polymer cannot be injected into the lower permeability carbonates, the solubilization approach was superior as it did not require displacement by a high viscosity polymer chase. Sandpack experiments in Ottawa sand to mobilize residual oil showed greater than 90% overall recovery when displaced with a Winsor Type III microemulsion design (shorter slug) with chase and continuous Winsor Type I microemulsion (longer slug). The residual oil saturation after chemical injection was 5% indicating good solubilization and mobilization with an end point water relative permeability of 0.9. Results from the surrogate rock experiments showed similar displacement characteristics with 80% recovery and multifold improvement in relative permeability after surfactant injection. The 2D slab experiments showed that even with lower treatment amount of chemical, the overall improvement in injectivity was higher proving that robust surfactant formulations can still have good sweep efficiencies. Chemical stimulation formulations for successfully displacing near wellbore viscous crude oil in carbonates have been developed. Displacement characteristics across 1D and 2D show that such formulations can effectively improve polymer/water injectivity, especially in lower permeability carbonates. Field injection of such formulations can effectively increase processing rate and is a cheaper alternative to gain additional injectivity.