Evaluation of Friction Reducers for High-Density Brines and Their Application in Coiled Tubing at High Temperatures

Abstract

Abstract High density brines can provide increased hydrostatic pressure when used as cleanout fluids in coiled tubing operations. Due to the high viscosities of brines and the small diameter of coiled tubing, friction pressure loss will offset the additional hydrostatic pressure exerted by high density brines and lead to serious limitations in job design. One solution is to apply a friction reducer. Most commercial friction reducers are designed for water or low density fluids; their solubility and dispersion characteristics in high density brines are usually not acceptable. Additionally, high salt content and low free water in brines can diminish the effectiveness of a friction reducer. Many papers have been published on friction reducers in water or low density fluids in straight tubing and coiled tubing, but few have addressed friction reducers in high density brines. Evaluating a friction reducer normally requires full-scale flow loop testing, which requires a large volume of brine and prevents thermal evaluation of friction reducers. This study used a newly designed coiled small-diameter tubing (CSDT) flow loop to evaluate the properties of friction reducers in high density brines. The study evaluated two conventional friction reducers in brines including NaCl, CaCl2, NaBr, and CaBr2 with densities from 10.0 to 14.2 ppg. The study presents results from both CSDT and full-scale flow loop tests and demonstrates that the CSDT flow loop is a simplified and effective setup that can qualify friction pressure loss in tubing and evaluate the effectiveness of a friction reducer in high density brines. Heat-aging tests also investigated thermal degradation of friction reducers in brines. The tests can eliminate some commonly used friction reducers for high temperature applications due to thermal degradation. A case history is presented which successfully applied a friction reducer in an 11.0 ppg CaCl2 brine for a coiled tubing cleanout at 400oF. Introduction The oil and gas industry started to use coiled tubing for oilfield services in the early 1960s1. With new technological developments over the years, coiled tubing has found many applications in well operations including drilling, cementing, wellbore cleanout, acidizing and hydraulic fracturing. Among these, wellbore cleanout (removing sand or other fill material from wells) is the most common coiled tubing application today. The operation involves circulating fluids down the coiled tubing and up the well. The applied fluid carries the sand or solids from the bottom of the well to the surface. When designing a wellbore cleanout program, the fluid selected should be able to reduce the surface wellhead pressure and allow enough flow rate for solids removal. For a well with high bottomhole pressure, a high density brine or heavy weight fluid can be used as a cleanout fluid. Depending on the bottomhole pressure, the high density brines applied can be NaCl, CaCl2, NaBr, CaBr2 and ZnBr2, etc. These brines can be used as single-, two- or three-salt mixtures based on density, crystallization temperature and economic requirements. In combination, they can provide fluid densities up to 19.2 ppg or higher to help control well pressure2. The high density brines must be injected through the tubing on the reel by pump pressure. Friction of the fluid against the tubing's inner surface creates additional resistance called the friction pressure. The amount of friction pressure is determined by fluid and tubing characteristics: fluid density and viscosity, fluid flowing rate, tubing size and tubing wall roughness. Fluid viscosity significantly affects friction pressure when using high density brines because they normally have higher viscosities than water or low density fluids (see Table 1). The high viscosity of brines in the small-diameter coiled tubing at typical pumping rates will produce excessive friction pressure, limiting the maximum obtainable fluid injection rate. Also, higher working pressure significantly lowers the life of the coiled tubing and can result in premature failure. Shortening the life of coiled tubing also increases the cost of well operations. To control friction pressure, a friction reducer or drag reducer can be added to the fluids. In 1949, Toms3 reported unusually low friction pressure drop for a dilute solution of polymethyl methacrylate in monochlorobenzene when studying flow properties of polymer solutions in pipe. His friction/drag reduction findings are now known as the "Toms effect".