Abstract
This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.
Highlights
A major challenge in carbon dioxide (CO2) enhanced oil recovery (EOR) is poor macroscopic CO2 sweep efficiency caused by the low viscosity and density of injected CO2 [1, 2]
During single-cycle surfactant-alternating gas (SAG), foam generation occurred within the first pore volumes (PVs) of CO2 injected and foam remained stable for the 2 PV with only a slight dry-out effect towards the end of injection
During multi-cycle SAG, surfactant solution was introduced to the system in an imbibition process, which caused a decrease in capillary pressure, likely triggering foam generation
Summary
A major challenge in carbon dioxide (CO2) enhanced oil recovery (EOR) is poor macroscopic CO2 sweep efficiency caused by the low viscosity and density of injected CO2 [1, 2]. These adverse properties can result in viscous fingering and gravity override, greatly hindering oil recovery and sweep efficiency [3, 4]. Entrapment of CO2 in foam and CO2-surfactant emulsification increases CO2 apparent viscosity and reduces CO2 mobility [8, 9] These combined effects are capable of diverting flow from high permeability, wellswept regions, into less permeable areas with higher oil saturations, thereby increasing macroscopic displacement and oil recovery
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