Hydraulic fracturing is a water-intensive process that competes with other human, agricultural and industrial uses for a growing share of limited global freshwater resources. Water for hydraulic fracturing operations typically has been sourced from surface water or freshwater aquifers and piped or trucked to well sites.

Historically, produced water from hydraulically fractured wells has been injected into disposal wells. However, mounting concerns about freshwater deficits plus environmental concerns and regulations, droughts in water-scarce areas and growing transportation costs are now driving the demand to reduce the volumes of freshwater required for hydraulic fracturing and, instead, reuse produced water for subsequent fracturing operations.

The solution sounds simple: By reusing a former waste stream, the industry can virtually eliminate the need for freshwater in fracturing operations while reducing disposal and trucking costs, saving millions of barrels of water and millions of dollars per field. The reality is far more complex. The challenge is to reuse water to create fracturing fluids that have the properties necessary to maximize production across a well’s or field’s life cycle and that also can address operators’ short- and long-term environmental and economic needs.

While no single solution exists for converting all produced or flowback water into reusable products consistently and economically, leading service companies are applying their knowledge of reservoirs and fracture systems; fluid chemistry expertise; and understanding of social, environmental, logistical and economic requirements to develop integrated water strategies, products and services tailored to specific geologic, weather, economic and regulatory considerations.

Sustainable solution

Based on a matrix that addresses a water’s “fingerprint” (chemistry and total solids) and which crosslinked fluid systems will work with which water fingerprint and expected bottomhole temperatures, Baker Hughes developed a new family of four BrineCare fracturing fluid systems. These systems enable operators to use untreated or minimally treated produced or brackish water-based fluid for each water profile and temperature range an operator is likely to encounter.

The fluids are compatible with total dissolved solids (TDS) levels greater than 300,000 ppm, total hardness levels beyond the 50,000-ppm range and bottomhole temperatures ranging from 27 C to 177 C (80 F to 350 F) to create effective fracturing fluids that perform as designed and are environmentally responsible and economically feasible.

To formulate the fluids, scientists analyze the produced or brackish water in the laboratory to determine its profile and match it to the appropriate fluid system. They then pretest the proposed fluid under the candidate job conditions to ensure its ability to execute the designed fracture treatment. Lab tests are followed by field testing prior to pumping the job.

Reducing all-in cost of water

The first performance indicator for the hydraulic fracturing fluids created from produced water is the extent to which they help increase oil and gas production. The value of these fluids is also heavily weighted on their ability to reduce the “all-in” cost of water, which encompasses the entire water life cycle from acquisition to transportation to both the well and disposal sites to recycling and finally to injection into a disposal well.

According to IHS CERA, water costs can consume up to 10% of a well’s capital budget. Disposal costs account for more than 80% of water management dollars. The true cost of water is rarely reflected in acquisition prices, especially in water-scarce areas. The all-in cost of using fresh water, for example, ranges from $2 to $24 per barrel, despite its relatively low acquisition cost. Eliminating various portions of the oilfield water service cost cycle is critical to sustainable hydraulic fracturing operations.

Sources of water for hydraulic fracturing operations, in addition to fresh surface water, include produced water from wells within the field, load water that has been recovered from previous fracture stimulation operations and, increasingly, brackish waters from saline aquifers that exist in almost every shale basin in the U.S. Using recycled water not only conserves freshwater resources, but it also can significantly reduce transportation and injection costs, particularly when trucks are used. In the Marcellus, for example, one producer estimates that 25% of its typical well costs are associated with water transportation. A University of North Dakota study estimates that 56% to 84% of total water costs in the Bakken are associated with transportation.

Field applications of produced-water frack fluids

The ease of applying a fracturing fluid that has been prequalified for use with produced water was demonstrated recently in New Mexico’s Delaware Basin. The operator wanted to conduct a 10-stage fracturing operation using a conventional plug and perf completion on a well in Eddy County.

In addition to oil and gas production, farming and ranching have been staples of the Eddy County economy since the early 1900s. Periodic drought conditions often put water use at a premium. In an effort to minimize water sourcing costs and simplify logistics, the operator wished to use produced water to build the fracturing fluid for the well.

An initial analysis of the operator’s produced water sources determined that TDS ranged between 250,000 ppm and 300,000 ppm, and water temperature ranged from 57 C to 68 C (135 F to 155 F). Based on these properties, it was determined that a 27-ppg crosslinked fluid incorporating a buffer to lower the pH could be used for the application.

Using the operator’s produced water, 42,913 bbl of fluid were mixed and pumped over a three-day operation. Water quality was closely monitored as it tended to fluctuate throughout the job, especially when the operation began to draw water from the bottom of a large storage tank being used. Near the end of the application, a freshwater cut was added to ensure sufficient water volume to complete the job. These varying water chemistries throughout the multistage stimulation treatment did not affect the performance of the BrineCare fracturing fluid system that was selected for the treatment of the well.

After stimulating and bringing the well online, production rates were compared to offset wells with similar depth and lateral lengths. The target well delivered 20,156 bbl of oil and 7.9 MMcm (279 MMcf) of gas in its first five months of production. These results were consistent with the offset wells, which had been stimulated using freshwater fracturing fluids.

To date, prequalified produced-water fracturing fluids have been applied on seven additional wells in the Delaware Basin’s Brushy Canyon and Bone Spring formations with similar results.
Additionally, these prequalified fracturing systems have been used successfully with produced water in the Tubb formation (77 C [170 F]/55,000 ppm TDS); the Uintah Basin (74 C to 82 C [165 F to 180 F]/ 125,000 ppm to 200,000 ppm TDS); the Pinedale Anticline (93 C to 121 C [200 F to 250 F]/10,000 ppm to 15,000 ppm TDS); and in the Midland Basin’s Canyon, Wolfcamp and Spraberry formations (71 C [160 F]/75,000 ppm to 90,000 ppm TDS).

Acknowledgment
Danica Hurd and Brian Callaghan contributed to this article.

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