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

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.

CT coreflood study of foam flow for enhanced oil recovery: The effect of oil type and saturation

“…All of our experiments are conducted in water-wet conditions. A number of recent foam EOR field pilots are carried out in carbonate reservoirs [10,13], which are usually oil wet. Sanchez and Hazlett [44] conclude that foam cannot be generated in oil-wet formations with oil present, and that foam can be generated in oil-wet conditions without oil only when the formation wettability is altered by surfactant to water-wet.…”

“…These features give foam injection into geological formations broad engineering applications, e.g. remediation of aquifers or soils [7,8] and carbon capture, utilization and storage [9,10,11]. In the petroleum industry, both laboratory studies and field pilots identify foam as a promising technology in assisting gas-injection EOR [6,12,13,14].…”

CT Coreflood Study of Transient Foam Flow with Oil

“…All of our experiments are conducted in water-wet conditions. A number of recent foam EOR field pilots are carried out in carbonate reservoirs (Alcorn et al, 2018;Carpenter, 2018), which are usually oil wet. Sanchez and Hazlett concludes (1992) that foam cannot be generated in oil-wet formations with oil present, and that foam can be generated in oil-wet conditions without oil only when the formation wettability is altered by surfactant to water-wet.…”

“…These features give foam injection into geological formations broad engineering applications, e.g. remediation of aquifers or soils (Hayes, 2001;Hirasaki et al, 1997) and Carbon Capture, Utilization and Storage (Alcorn et al, 2018;Bui et al, 2018;Ren and Duncan, 2019). In the petroleum industry, both laboratory studies and field pilots identify foam as a promising technology in assisting gas injection EOR (Andrianov et al, 2011;Carpenter, 2018;Patil et al, 2018;Rossen, 1996).…”

Three‐Phase Fractional‐Flow Theory of Foam‐Oil Displacement in Porous Media With Multiple Steady States

“…Tang, Vincent-Bonnieu, and Rossen (2019) show that this model gives realistic representation of steady state foam behavior with oil. Either this simulator or a foam model similar to that in the simulator has been used to represent a variety of coreflood studies and field applications of foam (Alcorn et al, 2018;Chalbaud et al, 2002;Ma et al, 2013;Norris et al, 2014;Rognmo et al, 2018;Sharma et al, 2017;Spirov et al, 2012). Thus, it is essential to understand the model's behavior, including how it represents displacements with multiple possible displacing states.…”