Flowback Enhancer for Acidizing Fluid Systems to Stimulate Gaseous Carbonate Reservoirs

Abstract

Abstract Acidizing of oil and gas bearing carbonate reservoirs is generally undertaken by strong mineral acids such as HCl either to alleviate the damage caused by drilling and completion fluids or to create permeability in low permeability reservoirs. In acidizing operations, HCl reacts with and dissolves carbonate minerals to form high density calcium and magnesium brines. The post-stimulation fluid recovery of high-density brines can be difficult due to higher density, higher capillary pressures, unfavorable wettability of formation by brines and the low formation pressure. The objective of this study is to disclose a formulation that is stable in strong acids at high temperature to enhance the recovery of these high density brines, retard acid reactivity and increase formation permeability for efficient production. To enhance the post acid stimulation fluid recovery of highly dense brines, four new flowback enhancers were developed. The flowback enhancers were developed from a blend of ester or terpene solvents, alcohols, and surfactants to form optically clear nanoemulsions. Surfactant that are stable in strong acids at high temperature and have good performance in high density brines are chosen for the formulations. Surface tension, stability on dilution and emulsion testing of the acidizing fluid containing flowback enhancer were determined at 0.2 vol% concentration. Brine displacement tests in packed carbonate column containing spent 28 wt.% HCl acid were conducted by flowing nitrogen gas. Core flow tests were performed with 12-inch calcite cores (1-6 mD) at 300°F using 28 wt.% HCl and 15 wt.% HCl fluid system containing all additives to determine the regained permeability in presence of flowback aid using gas. Finally, CT scans of the acidized cores were undertaken to study the wormhole propagation. The droplet size of the developed nanoemulsions were found to be between 10 and 850 nm. All the flowback enhancers demonstrated low surface tension (21-29 mN/m) at 0.2 vol.% concentration in 28 wt.% HCl fluid. They showed remarkable stability in strong acidizing fluid systems when heated to 300˚F for a period of 24 h as determined by minimum change in surface tension. The addition of flowback enhancers prevented any formation of emulsion with condensate. These formulations in fluid displacement column test provided quick brine displacement with a recovery of more than 75 vol% in comparison to one without flowback enhancer of 16 vol%. In core flow test with 28 wt.% HCl at 300˚F the permeability of core was improved by 267.49% and without flowback enhancer it improved by only 15.42%. The CT scan of the acidized cores containing flowback enhancer created deeper wormhole in comparison to one without flowback enhancer. The flowback enhancers of the present study are stable in strong acid and retarded the reactivity of acid without the need to emulsify the HCl in diesel. It provided a better regained permeability and deeper wormhole propagation paving the way to be utilized in the field to stimulate low pressure gas reservoirs and recover high density brine from formation without formation of any water block.