Fracturing Fluid Design: A Closer Look at Breaker and Surfactant Selection

Abstract

Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.

Review on High-Temperature-Resistant Viscoelastic Surfactant Fracturing Fluids: State-of-the-Art and Perspectives

“…However, due to the slow swelling rate of guar gum, they are prone to microbial degradation, so it is necessary to add bactericides . In addition, the biopolymers such as guar gum can cause significant formation damage through various mechanisms (core permeability damage rate of 10%–38%), which depend on factors such as polymer type, concentration, cross-linking agent, gel-breaker type or concentration, and rock permeability. , The application in high-temperature environments exacerbates this problem, as a high polymer loading is required, and polymer residues can hinder the flow of hydrocarbons. Yan et al reported that the core-damage rates of different fracturing fluids were guar gum (34.1%) > polymer (27.5%) > VES (8.8%).…”