Abstract
Abstract Reduction of the CO2 mobility is beneficial during subsurface sequestration of anthropogenic CO2 in saline aquifers and hydrocarbon reservoirs by mitigating flow instabilities leading to early gas breakthrough and poor sweep efficiency. Injection of CO2 foam is a field-proven technology for gas mobility control. Foam generation and coalescence are compared between six commercially available surfactants with a range in CO2 solubility, during unsteady state injection of dense CO2-foam in a long sandstone outcrop core (1.15 m). Foam generation categories and foam decay were defined based on the observed changes in foam apparent viscosity during generation and coalescence. The degree of CO2 solubility influenced apparent viscosity development and peak foam strength for the tested surfactants. Variations in foam peak strength resulted in a range of water saturations at CO2 breakthrough (up to 24 percentage points difference observed experimentally), with implications for the CO2 storage capacity.
Highlights
Sequestration of anthropogenic carbon dioxide (CO2) in subsurface geological formations is considered necessary in most scenarios to limit global warming to 1.5 °C (IPCC, 2018) and to meet the emission goals set forward by the Paris Agreement
This paper investigates the effect of foam on the CO2 storage capacity during unsteady state foam floods
Additional complicating factors are that both the partitioning coefficients, the adsorption and foam strength depend on the surfactant concentration
Summary
Sequestration of anthropogenic CO2 in subsurface geological formations is considered necessary in most scenarios to limit global warming to 1.5 °C (IPCC, 2018) and to meet the emission goals set forward by the Paris Agreement. For decades CO2 has been pumped into geological formations containing hydrocarbons with the focus of enhancing the oil recovery (EOR) with variable degree of success (Lake et al, 2019), and without the focus of maximizing sequestered CO2 in the formation. The low viscosity of CO2 at reservoir conditions compared to the displaced brine and oil can cause viscous fingering, leading to early CO2 breakthrough and high gas oil production ratios (Jones et al, 2016; Lee and Kam, 2013). Sweep efficiency challenges are further amplified in presence of reservoir heterogeneities, and result in low utilization of the injected CO2 with lowerthan-expected oil recovery, less CO2 sequestered, and additional costs from the need to separate and recycling the produced gas. CO2 mobility control is necessary to improve the sweep efficiency, and may be achieved using direct CO2 thickeners (Cummings et al, 2012; Lee et al, 2014; Zhang et al, 2011) or CO2 foam (Enick et al, 2012; Haugen et al, 2014; Vitoonkijvanich et al, 2015)
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