Core-scale sensitivity study of CO₂ foam injection strategies for mobility control, enhanced oil recovery, and CO₂ storage

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.

Red Noise in Steady‐State Multiphase Flow in Porous Media

“…Typically, the pressure measured during steady-state, which is used to calculate the relative permeability of the fluid phases, shows notable fluctuations Rücker et al (2015), Datta et al (2014), Menke et al (2019); Gao et al (2017Gao et al ( , 2019Gao et al ( , 2020, Alcorn et al (2020), Wang and Masalmeh (2019), Lin et al (2019), Spurin et al (2020). Historically these fluctuations have been discounted as noise or a failed experiment.…”

The Origin of Non-thermal Fluctuations in Multiphase Flow in Porous Media

“…By focusing on the specific case of steady-state experiments where wetting and non-wetting phases are co-injected at varying fractional flow, we can exclude transient effects. Even though in many cases of such fractional flow experiments, after injection of hundreds of pore volumes, pressure and saturation eventually stabilize, there are many other reported cases, where significant fluctuations in pressure and saturation persist in a wide range of different rock types, experimental conditions and scales investigated, which suggests that the phenomenon is somewhat universal and applicable to a wide range of rock types (Datta et al, 2014a,b;Masalmeh et al, 2014;Reynolds and Krevor, 2015;Sorop et al, 2015;Gao et al, 2017Gao et al, , 2019Gao et al, , 2020Lin Q. et al, 2018;Alcorn et al, 2019;Clennell et al, 2019;Lin et al, 2019a;Spurin et al, 2019;Wang and Masalmeh, 2019). Based on capillary number and pore-scale mechanisms involved the cause of the fluctuations is of capillary nature.…”

“…However, many of these fractional flow experiments show notable fluctuations (Datta et al, 2014a,b;Masalmeh et al, 2014;Reynolds and Krevor, 2015;Rücker et al, 2015a;Sorop et al, 2015;Gao et al, 2017Gao et al, , 2019Gao et al, , 2020Lin Q. et al, 2018;Alcorn et al, 2019;Clennell et al, 2019;Lin et al, 2019a;Spurin et al, 2019;Wang and Masalmeh, 2019;Menke et al, 2021), for instance in pressure drop but also saturation. In some cases, the magnitude of these fluctuations is comparable or even larger than the average values of the respective property, e.g., pressure drop, between the previous or following fractional flow.…”

Carbon Dioxide Applications for Enhanced Oil Recovery Assisted by Nanoparticles: Recent Developments

“…Tests have shown that multiple SAG cycles make it possible to generate foam with an apparent viscosity of 120 mPa·s, which is almost two times more than with the combined injection of a foaming agent and CO 2 (56 mPa·s). 18 Those tests also revealed that the additional oil recovery associated with the use of foaming surfactants and CO 2 averaged 30%. By applying a combined water–gas treatment model together with foaming surfactants (FAWAG), it is possible to obtain a more stable oil displacement profile without premature breakthroughs and viscous tongues ( Figure 4 ).…”