No abstract

Summary The potential leakage of hydrocarbon fluids or carbon dioxide (CO2) out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil-and-gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 µm can pose a significant leakage danger with effective permeability in the range of 0.1–1.0 md. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair; thus, a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application with pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. The pH-sensitive microgels viscosify after neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition with real-time visual observation and measurements of pressure gradient and effluent pH. Although the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cations from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that were subjected to various degrees of syneresis often failed to hold backpressures. Multiple chemicals were tested for pretreatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer-gel strength is determined by recording the maximum-holdback pressure gradients during liquid-breakthrough tests after various periods of pretreatment and polymer shut-in time. Cores pretreated with Na5P3O10 successfully held up to an average of 70 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2-storage applications. The use of such inexpensive, pH-triggered polyacrylic acid polymer allows the sealing of leakage pathways effectively under high-pH conditions.

The potential leakage of hydrocarbon fluids or CO2 out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil and gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 microns can pose a significant leakage danger with effective permeability in the range of 0.1–1 mD. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair, thus a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application using pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. pH-sensitive microgels viscosify upon neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition via real-time visual observation and measurements of pressure gradient and effluent pH. While the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cation from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that subjected to various degrees of syneresis often failed to hold back pressures. Multiple chemicals were tested for pre-treatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer gel strength is determined by recording the maximum holdback pressure gradients during liquid breakthrough tests after various periods of pre-treatment and polymer shut-in time. Cores pre-treated with Na5P3O10 successfully held up to an average of 80 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2 storage applications. The use of such inexpensive, pH-triggered poly-acrylic acid polymer allows to seal leakage pathways effectively under high pH conditions.

No abstract