Abstract

Fluid volumes in fracturing treatments have increased substantially, while water supply has become more of a public concern. Rather than paying to treat and dispose of produced and flowback water, operators would like to reuse it in subsequent stimulation treatments. Produced water with high total dissolved solids (TDS) and high divalent cation content poses extreme challenges for emulsion friction reducers because cations hinder the inversion of friction reducers and cause loss of efficiency of friction reduction. Treating produced water to the quality suitable for conventional fracturing fluids is time-consuming and often cost-prohibitive.

A salt-tolerant friction reducer was developed to address the challenges of high-TDS produced water. In a produced water sample with high TDS and high total hardness, the new polymer hydrates within 10 seconds and gives a friction reduction profile similar to that of current inverse-emulsion friction reducers in fresh water. The fluid is compatible with other common stimulation additives such as scale inhibitors, biocides, clay stabilizers, surfactants, and breakers.

The paper discusses field test results and production response from slickwater fracturing operation in Delaware basin with produced water containing more than 250,000 ppm TDS and 60,000 ppm total hardness. Head-to-head comparison with conventional crosslinked fluids and friction reducers under field conditions showed significant oil and gas production improvement resulting from increased fracture complexity by pumping low viscosity fluids at higher pumping rate in extremely high-TDS produced water. It provides the oilfield industry a cost-effective solution of reducing produced water disposal and fresh water demands, thereby ultimately improving environmental and economic impacts of well operations.

Introduction

Large quantities of high-TDS produced water (typically greater than 250,000 mg/L) are produced from existing oil and gas wells from Delaware basin. In 2011, more than 164 million bbl of produced water were produced and the reinjection cost into disposal wells alone was estimated at an average cost of USD 0.75 to USD 1.00 per bbl (LeBas et al. 2013). Meanwhile, the fluid volumes in slickwater fracturing treatments have increased substantially. Rather than paying to treat and dispose of produced and flowback water, operators would like to reuse it in stimulation treatments. For typical slickwater operation, friction reducers (FRs) are normally added to the water-based fracturing fluids "on the fly" as water-in-oil emulsions to reduce friction pressures. When FRs are pumped into water, the emulsion inverts to oil-in-water emulsion, releasing the polymer, which swells (hydrates). The hydrated, disentangled polymer molecules then work as a FR. This process is also known as "inversion". Aften (2010) summaried three key factors determining the potential performance of these inverse-emulsion FRs:

  1. solubility and flexibility of polymer in various aqueous phases;

  2. the polymer's ability to instanteously destabilize the inverse emulsion into stimulation fluids, e.g. produced or flowback water; and

  3. the polymer's compatibility with other fracturing additives, such as breakers, scale inhibitors, biocides, surfactants, and effectiveness under field conditions such as extremely low temperature.

High total dissolved solids (TDS) and high divalent cation content in the Delaware basin produced water poses great challenges for hydration of emulsion FRs because cations hinder the inversion of FRs and cause loss of efficiency of friction reduction to below 30%. Treating produced water to the quality suitable for conventional fracturing fluids is time-consuming and often cost-prohibitive.

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