Abstract
While Mutual Solvents have been widely used to improve contact surface area between rock and chemicals applied for scale inhibition or acid stimulation purposes during squeeze treatments, the literature does not identify study of their impact on injectivity enhancement for water injection wells.
This paper examines the impact of using solvents prior to water injection to displace otherwise residual oil from the near injector formation, and thereby improve injectivity while under matrix injection conditions. The work described includes both experimental studies - evaluating mutual solvents in sandstone core floods - and near-wellbore modelling to demonstrate the benefit and to explore the impact of chemical concentration and volume.
Experiments involved measuring effective brine permeability before and after application of a mutual solvent solution, vs water injection only, into cores at initial water saturation at both reservoir and room temperature.
A radial reactive transport model was used in which interpolation between relative permeability functions is dependent on the concentration of the solvent, as well as on salinity and temperature. The model also accounts for the impact of injection rate on the balance between viscous and capillary forces in the very near well formation. Sensitivity to solvent concentration, solvent volume, and the implication of application temperature for this waxy crude oil were investigated.
The consequence of mutual solvent injection is that the aqueous phase injected thereafter would have access to greater pore volume (oil saturation in core will be below normally defined Sor), and hence the effective permeability to the aqueous phase would be increased. Measurements identified 98% removal of oil at reservoir temperature with mutual solvent vs only 17% improvement in brine permeability with seawater alone. For the room temperature coreflood, emulating cooling of the near wellbore with water injection, the recovery of brine permeability was again better for the mutual solvent treatment.
Similarly, the modelling study identified that for a given injection pressure limit and under the reservoir conditions assumed, a 2.5 ft slug of 20% mutual solvent in water would improve injection rate within the first year of injection by over 11% leading to an incremental volume of water injected of over 1.26 MMstb.
This study highlights the potential for a simple chemical treatment to improve waterflood injection performance while under matrix flow conditions, with ensuing economic and environmental benefits of greater injection capacity without drilling additional wells.
