An Integrated CO2 Foam EOR Pilot Program with Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field

Abstract

Abstract A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of in-situ foam generation, SAG operations must be optimized for field implementation. This study presents an integrated upscaling approach for designing a CO2 foam field trial, including pilot well selection criteria, comprehensive laboratory coreflood experiments combined with reservoir scale simulation to offer recommendations for a SAG injection schedule while assessing CO2 storage potential. Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam. A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection. Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.