Shale Sector’s Switch to Slickwater Highlights Compatibility Issues with Produced Water

Abstract

Switching from guar-based gels to slickwater fracturing fluids has delivered one of the biggest cost wins for the North American shale sector. First movers began the transition after guar prices spiked 300% in 2013. Shale producers have since reported they are trimming 20–35% from their completion chemical budget by using slickwater over the alternatives, while also reducing the pressure pumping power needed to move proppant into a tight reservoir. The replacement of gel treatments is possible thanks to the comparably low price of the key ingredient in slickwater recipes: polyacrylamide, or what some refer to as a high-viscosity friction reducer (HVFR). Beyond chemical savings, operators have experienced positive production results, too—adding fuel to the relatively quick adoption of slickwater treatments across every major play in North America. But since HVFR is a newly commoditized chemical with dozens of suppliers in North America and China, opera-tors are being advised to not let price be the sole deciding factor in which variety they pump downhole. A number of recent industry studies argue that aggressive screening is needed to make the right choice—especially if an operator is recycling or reusing produced water. “As a product, friction reducer can be different from company to company,” said Mohammed Ba Geri, a petroleum engineering PhD candidate at Missouri University of Science and Technology. “Most types work well with fresh water, but by increasing the salinity or changing the [total dissolved solids (TDS)] of the water, we see that everything changes.” Ba Geri spent more than 2 years running tests on about 30 different commercial friction reducers as part of a wider research effort that is chronicled in half a dozen SPE papers. He shared the latest of these at the recent Unconventional Resources Technology Conference (URTeC) in Denver. The variations in performance that Ba Geri cites, including in one of the papers he delivered at the conference (URTeC• 99), represent an important consideration given that more shale producers are shifting away from fresh water and toward using produced water for hydraulic fracturing. This development is being driven by a mix of regulatory, sustainability, and economic factors. By opting for produced water, distinguished by its high-salinity and TDS content, operators are essentially opting out of using linear or crosslink gels since they react so poorly to the lower-quality fluid. Per industry research, producers should also be careful in assuming this same risk is completely abated by taking the slickwater route. Friction reducers tend to hold up much better in a high-salinity and high-TDS environment. However, Ba Geri said that when the salinity or TDS rise above certain ranges, “all the polymer chains will break, and the viscosity and elasticity of that type of fluid will be less effective.” As the reaction takes place, globs of material will coagulate and reduce the ability of the friction reducer to carry proppant from the wellbore into the reservoir. Operationally, the effects can increase well costs quickly and reverse the advantages of using slickwater as stimulation rates drop, which in turn, would need to be offset with more pumping horsepower.