Microemulsão inibidora de formações reativas aplicada em fluidos de perfuração de poços de petróleo e gás

• Autor(a) principal: Silva, Raphael Ribeiro da
• Data de Publicação: 2021
• Tipo de documento: Dissertação
• Idioma: por
• Título da fonte: Biblioteca Digital de Teses e Dissertações da UFPB
• Texto Completo: https://repositorio.ufpb.br/jspui/handle/123456789/22111
• topic: Interação rocha-fluido de perfuração; Formações reativas; Folhelhos; Tensoativos não-iônicos; Inibição de inchamento; Rock-drilling fluid interaction; Reactive formations; Shales; Non-ionic surfactants; Swelling inhibition; CNPQ::ENGENHARIAS::ENGENHARIA QUIMICA

The increasing production of hydrocarbons from unconventional reservoirs, particularly water sensitive formations, has led to the emergence of technologies necessary to maintain wellbore stability. The drilling fluid must always be adequate to the needs presented by such formations since serious problems may be generated due to inadequate fluid planning. Microemulsions appear in this scenario with advantages over the traditional fluids already used by the industry due to their thermodynamic stability and ease of preparation, in addition to being environmentally acceptable. This work aimed to evaluate the inhibition capacity of microemulsion-based drilling fluids added with potassium salts. Initially, two samples of shales from sedimentary basins in Northeastern Brazil were characterized using FRX, DRX, TGA, and DTA tests. Then, four drilling fluid systems were prepared, whose formulations were based on a 2³ factorial design, with a rejoinder at the central point, totaling eleven fluids in each set (with duplicates). The microemulsions were formulated from a ternary phase diagram, in which a water/glycerin solution (1:1 by mass) was used as the aqueous phase, pine vegetable oil as the oil phase, and two nonionic surfactants, Ultranex NP100 and Alkest Tween 80, were used separately in the formulated systems. Potassium citrate (INIB1) and potassium sulfate (INIB2) were also used to inhibit the swelling of reactive formations. In order to evaluate the behavior of drilling fluids, rheology tests, pH, filtrate volume, filter cake thickness, and permeability were considered. Statistical analyzes were performed in order to visualize the influence of the factors surfactant concentration (%) (A), oil phase concentration (%) (B) and swelling inhibitor concentration (g) (C), as well as their interactions (AB, AC, BC, and ABC) on the systems. A multiobjective optimization using Genetic Algorithms (GA) was performed for the four scenarios. Finally, drilling fluid systems were tested for shale inhibition and dispersion capabilities. In addition to systems composed of INIB1 and INIB2, potassium chloride (KCl) (INIB3) was also evaluated, as well as a system without swelling inhibitor (SI). It was observed that the shale samples presented clay minerals from the smectite group, which represent a more significant interaction with water for swelling of hydratable formations. Drilling fluids showed rheological behavior following the Herschel-Bulkley model. It was observed that there is a variability of interactions in the fluids concerning the concentrations of surfactant, oil phase, and swelling inhibitor, with more significant responses associated with increased concentration of the surfactant in the microemulsion. The drilling fluids analyzed showed a significant swelling inhibition, especially the fluid formulated from the surfactant Ultranex NP100 and INIB2, with a 6.9% swelling variation. Excellent results concerning dispersibility were also achieved, with the NP100_INIB1 fluid being the lowest dispersion of cuttings (0.075% and 0.215%). In general, it was observed that microemulsion-based drilling fluids were efficient in inhibiting swelling, showing good rheological and filtration behavior.