Technology Focus: Water Management (December 2015)
Authors: Ali Syed A. 
Published: November 2016

Technology Focus

Horizontal drilling followed by multistage fracturing is the most prevalent mode of hydrocarbon extraction from shales. Hydraulic fracturing of a well encompasses, on average, approximately 30 fracturing stages, with each stage using approximately 3,800 bbl of fresh water, equating to approximately 114,000 bbl for each well. The need for such vast amounts of fresh water in hydraulic fracturing significantly affects water availability and sourcing and the cost and logistics of accessing and trucking the water to the wellsite. Furthermore, regulations designed to protect communities and the environment from potential sources of contamination are becoming increasingly stringent.

Approximately 10–30% of the fresh water injected into a well during fracturing treatments returns to the surface along with various amounts of formation water, henceforth referred to as produced water. Thus, in the interest of conservation and sustainability, it is highly desirable to maximize any opportunity to reuse the produced water for subsequent fracturing treatments.

Produced water usually contains residual hydrocarbon; high levels of total dissolved solids (TDS), including sodium, calcium, magnesium, barium, and other salts; suspended solids; and residual production chemicals. Reclaiming produced water as the base fluid for hydraulic fracturing not only helps to alleviate the industry’s dependence on fresh water but also lowers the overall cost of the fracturing operations. Conventional fracturing-fluid systems require fairly low TDS to achieve stable rheology, so produced water requires extensive treatment before it can be used for fracturing.

There have been attempts to develop fluids that can be prepared with produced waters that contain a limited amount of TDS, typically less than 30,000 ppm. However, several operating areas, including the Haynesville, Marcellus, and Bakken shales and west Texas areas, have produced waters with much higher salinity (TDS concentrations greater than 150,000 ppm).

An ideal solution would be to reuse the high-TDS produced water in subsequent fracturing treatments with minimal filtration to remove the suspended solids. In response, a growing group of chemical suppliers, researchers, and service companies are on a mission to develop fracturing fluids using high-TDS produced water as a base fluid that provides a stable rheology.

The papers featured this month deal with the formulation of stable fracturing fluid from high-TDS produced water. I urge you to look at OnePetro, the SPE online library, and download papers. You will find updates on best practices, case studies, new fluid formulations, and much more. JPT

Recommended additional reading at OnePetro: www.onepetro.org.

IPTC 18142 Slickwater Chemistry Concerns and Field Water Management in Tight Gas by David Langille, Shell Canada, et al.

SPE 173371 Chemical Compatibility of Mixing Utica and Marcellus Produced Waters: Not All Waters Are Created Equal—A Case Study by F.B. Woodward, Shell Exploration & Production, et al.

SPE 173324 The Freshwater Neutral Challenge: The Need for Protection, Reduction, Innovation, and Conservation by R. Greaves, Southwestern Energy, et al.

SPE 173372 Overcoming Obstacles for Produced Water in Bakken Well Stimulations by Darren D. Schmidt, Statoil, et al.