Will flowback or produced water do?

In the near future, increased water demand will lead to shortages of freshwater available for fracturing. In addition, produced and flowback water from the fracturing treatment are becoming more costly to dispose of due to increasing trucking and disposal costs. Further, several areas have acid mine drainage (AMD) water available, a non-freshwater source mostly generated from abandoned mining sites that have become environmentally troublesome to manage. Use of these waters for fracturing treatments could alleviate some troubles.

Demand for water conditioning and reuse has increased significantly during the past decade, leading to complicated and costly water-recycling programs. Flowback and produced water can vary in composition depending on formation location, chemicals used during stimulation, and age of the well. In addition, water can contain a variety of salts, which means no single treatment method is suitable for all waters. With water treatment processes, cost of treatment chemicals, equipment, equipment maintenance, personnel, and treatment waste disposal should be considered. And as demand rises for treating waters with higher levels of contamination, treatment costs increase. These factors most likely will lead to region-specific solutions that can require different developmental efforts and infrastructure.

This chart shows the scaling potential of various field brines with and without dilution. (Charts courtesy of Halliburton)

Ideally, field waters would be used with little or no treatment in fracture stimulation operations, providing high levels of production performance so unnecessary costs could be eliminated. But using unprocessed or minimally processed field waters in water-frac applications presents specific challenges, namely scale control and variable, often unpredictable friction-reduction performance for industry-standard friction reducers. To lessen these burdens, a strategy to deploy a broad water-fracturing solution using new chemistries and surface-processing practices has been investigated.

Experimental data suggest significant friction reduction and adequate scale inhibition can be achieved in some of the most challenging waters. Qualitative trends of friction-reduction performance can be established by evaluating friction reducers in synthetic brines; however, these trends are not always followed in flowback or produced water, suggesting other chemistries greatly impact friction-reduction performance. Special attention should be given to ensure fluid additives are compatible with the given water source while maintaining desired fluid performance and minimizing formation damage.

A dynamic tube-blocking experiment was performed on field water.

Scale management provides lasting results
Because several produced brines contain high levels of barium and calcium, a critical aspect of reusing produced water is anticipating and controlling scale. This effort requires predicting scaling tendencies and developing a scale inhibitor suitable for use with produced brines.

A scaling model based on the Pitzer theory was used to assess scaling tendency for calcite, barite, and celestite of various produced brines along with typical fresh waters under usage temperatures and pressures. The Pitzer theory of electrolytes calculates scaling potential of water over a wide range of temperatures, pressures, total dissolved solids (TDS), and co-solvents. This approach is ideal for dealing with high ionic-strength brines. But it became apparent from the studies that diluting produced brines with fresh or other non-fresh waters led to unintended consequences that, in many instances, could have significant negative impacts on stimulation treatment quality due to potential scale formation. Scaling tendencies of the brines were calculated, illustrating that fresh waters can contain constituents that can, under specific circumstances, lead to scaling.

To mitigate mixing issues, a fit-for-purpose scale inhibitor was developed. The new scale inhibitor is soluble in high-TDS fluids, making it ideal for several produced brines. Its compatibility with typical stimulation additives also was validated using bulk-fluid stability. Performance testing with friction reducers was conducted to confirm compatibility with the products. Finally, the inhibitor was evaluated for scale-inhibition efficacy via dynamic tube-blocking experiments using several typical produced high-TDS brines under various mixing scenarios. Based on results of the experiments, the minimum effective dosage was found to be below 2 ppm for certain field waters, and the inhibitor was found to provide scale inhibition performance similar to traditional inhibitors across a range of waters.

Friction reduction of FR2 in field waters is shown.

Friction reducers’ performance in brines
Several friction reducers were evaluated in non-fresh waters by observing percent friction reduction over time. High salt concentrations and hardness reduce the performance of existing anionic friction reducers. Results of the study have led to a better understanding of friction reducer behavior in varying salt concentrations using synthetic brines. In particular, decreasing friction-reduction performance with increasing salt concentration was observed for both an industry-standard anionic friction reducer, FR1, and a cationic friction reducer, FR2; however, the impact on FR1 was significantly higher than the impact on FR2.

FR2 was evaluated in a variety of field waters to observe friction-reduction performance versus concentration of inorganic dissolved solids present in the waters. The cationic friction reducer exhibited excellent friction-reduction properties in synthetic brines containing TDS in excess of 150,000 mg/l. In field waters, decreasing friction-reduction performance with increasing salt concentration was not observed as it was with synthetic brines.

The trend is somewhat inconsistent when tracking friction reducer performance with TDS or the total hardness (TH) – sum of Ca2+ and Mg2+ field water concentrations. This behavior suggests there are other constituents in the water that impact friction reducer performance. If evaluated properly in advance, friction-reduction solutions can be formulated to mitigate unexpected performance issues with a given field water. For example, FR2 has higher performance than FR1 in a produced water (TDS=148,000 mg/l and TH=16,000 mg/l) and in a mixture of produced water and AMD water.

Friction reduction of FR1 and FR2 in produced water and in a produced/AMD-water mixture is illustrated.

Compatibility, performance balance needed
As oil and gas fields mature and restrictions tighten on the use of freshwater sources and field water disposal, demand for non-fresh waters for future oilfield operations likely will increase. Major treatments, including reverse osmosis and distillation, have proven costly, so reuse of fluids can be done with little or no treatment but should be done with care. Factors to be considered include scale inhibition and friction-reducer performance, with emphasis on compatibility issues in regard to recycled water and fluid additives to obtain the highest quality frac fluid.