Foam treatments are used worldwide for acid diversion in matrix acid well stimulation. Many field treatments require foam effectiveness at elevated temperature in the presence of both acid and corrosion inhibitor.
This study examines four surfactant formulations at room temperature, 220° and 400°F, with and without acid and corrosion inhibitor. The surfactants included amphoteric as well as nonionic foaming agents. The acid formulation was a mixture of chelating agent and HCl, with pH about 4. Formulations were tested at all three temperatures for foaming with N2 gas (80% quality) at back-pressure of 600 psi in sandpacks and for bulk-foam stability in a pressure cell.
Foam was created in most cases at 75°F without acid or corrosion inhibitor. Creating foam with acid and corrosion inhibitor at 400°F was more difficult, requiring high injection rates and lower foam quality. Once formed, strong foam had higher mobility at elevated temperatures than at room temperature. Addition of corrosion inhibitor was more adverse to foaming than acid itself. At 400°F foam propagation was slower, and steady-state pressure gradient was lower, than at 75°F. The two steady-state strong-foam regimes reported elsewhere were present at 220°F and in the presence of acid. Pressure gradient at 220°F was lower in both the high-quality and low-quality foam regimes.
The bulk-foam stability results agree qualitatively with the sandpack results, but quantitative relationships between the two tests are hard to draw. These results also suggest that these surfactants degrade over a period of hours at 400°F but not at 220°. Residence time in the heated sandpack therefore may have been too short to fully represent field application at 400°F.
These results are consistent with decreasing foam stability at higher temperature; adverse interactions between foaming surfactant and inhibitor; easier foam generation and propagation at higher velocity and lower foam quality; and greater difficulty in creating foam under conditions that reduce steady-state foam strength.
These results can aid design of high-temperature foam-acid diversion treatments.
Foam has been widely used in petroleum industry.1 Foam can increase sweep efficiency in gas-injection improved oil recovery by reducing gas mobility and redirecting gas flow.1,2 Foam can reduce gas influx into production wells by forming a barrier to gas flow from a gas cap or from gas-swept layers. Foam can aid acid well stimulation by diverting acid into damaged or low-permeability layers near the wellbore.3–11 Recently foam technology has been extended from the petroleum industry to subsurface environmental remediation.12 Foam is also used in drilling, cementing, wellbore clean-up, and fracturing, because of its unique rheology, low density, ability to transport solid particles, and cost effectiveness.1