Water Recycling's New Reality

By Luke Geiver | December 30, 2013

Recycling flowback and produced water created from a Bakken well is akin to fool’s gold—the process has great appeal but little economic value. The cost of implementing and operating an appropriate technology to treat the water is too high to justify the long-term investment. The risk of disrupting a proven freshwater-based fracturing fluids strategy with recycled water is too great. And the logistical nightmare that would emerge from such a process has been too daunting for a single technology provider to manage. 

When Walter Dale and Mark Johnsrud met in Houston two years ago to hypothesize about making flowback water recycling an economic, sustainable and logistically feasible reality in the Bakken, those were the opinions each had heard. “For as long as we’ve been in this business, we have always been told it had to be freshwater. It had to be water that you could drink in order to create a frack fluid,” says Mark Johnsrud, CEO of Nuverra Environmental Solutions, a Bakken shale logistics provider.

Earlier this year, Nuverra formed a contractual relationship with Dale, strategic business manager of global energy service provider Halliburton, and his team to handle the logistical elements related to Halliburton’s flowback recycling efforts. “There are a lot of customer completion engineers that for the history of the industry have been told that they need a high-quality water to make stable frack fluids that don’t harm their wells,” Dale says. Stable water means virtually no presence of boron or other suspended solids that might prohibit the proppant solution by plugging or gelling the solution in a negative way. 

In 2011, Dale was hired by Halliburton to look at water treatment technologies capable of helping the shale energy industry re-use water. His hiring was a direct result of Dale’s long history with water, spanning several companies and countries. That same year, Dale and his team successfully experimented with recycled water technology in the Haynesville Shale, but the process deployed merely combined fresh water with high total dissolved solid-infused flowback water for use in new well fracture fluid mixes. In 2012, the team got serious about using 100-percent high TDS flowback water as the main water source for new well completion fluids. During 2012, Dale had also met and spoken with various individuals from Nuverra at several industry conferences and events about the topic of recycling flowback water and the necessity of a logistical strategy suitable for the handling, treatment and storage of flowback water and eventual transport of the recycled water back to a wellsite. By mid-2013, Nuverra and Halliburton announced their venture. 

Today, pending the permitting process, the water expert working for one of the world’s most recognizable oil industry technology brands and the leading Bakken logistics provider are on the heels of creating a paradigm shift in the industry, and for all parties linked to the Williston Basin and beyond, the dual-effort is turning that fool’s gold into something worth a second look. 

The Cost of Recycling
For every barrel of oil produced through hydraulic fracturing, roughly three barrels of water is produced along with it. During the fracking process, a fluid mixture of water, chemicals and proppant (either sand or ceramic) is mixed and then pumped down the wellbore at high pressure. Water’s main role in the process is to suspend the proppant mixture before it arrives in the horizontal, fractured section of the wellbore. After the well has been fractured completely, water injected in the well, along with small amounts of water trapped in the shale formations, resurfaces. The resulting flowback water is incredibly salty and mixed with sand, sediment and other elements. It is unusable and, in most cases, trucked or piped to a saltwater disposal well. 

That flowback water is not used in its untreated form in fracture fluid mixtures for many reasons. The suspended solids in the water can compromise the proppant’s suspension ability, and microbes in the water can hurt polymers in the water mixture, also degrading the fluid's stability. 

To date, most water treatment technologies have failed for one of two reasons: the process worked too hard to remove boron and other contaminants in the flowback water, or, the process negated certain treatment steps resulting in non-desirable fluids. Overtreatment of flowback water is the main culprit, say those calling the process too expensive, and misapplied treatment is the reason some believe the process isn’t worth the work.

Halliburton believes it has found the sweetspot, treating flowback water just enough for reuse. “Our new approach is to treat the water just enough to ensure fluid integrity and well production. We change the fluid chemistry to allow for the use of these impaired waters,” Dale says. “When you do this, you have a very low cost of treatment.” 

A Bakken operator’s water costs are directly linked to the acquisition price of fresh water, transportation of the water to the site, transportation of the flowback and produced water to a disposal well and the price of disposal. In the Bakken, Dale says, water costs run between $7 and $15 per barrel. And, in some cases, operators add brine to their water to form a better fluid for completions, a step that can add an additional $1 to $3 per barrel. “For every barrel of water you recycle, you negate the cost of disposal completely,” he says. On average, 9 million barrels of freshwater are used for well completions annually in the Williston Basin. Roughly 12 million barrels of flowback water is produced. Halliburton’s multifaceted approach to water recycling could save approximately $200,000 to $400,000 in well completions and water costs per well. 

The Benefit of Just Enough
Halliburton’s trademarked H2O Forward water recycling and reuse process emphasizes two main features. First, the process, which utilizes electrocoagulation, reduces the amount of suspended solids in the recycled water. Contaminated water is passed through a series of tubes, or cells, that release positively charged ions into the water, which attach themselves to the suspended matter that has a negative charge. The matter then has enough weight to be surfaced by gas bubbles introduced into the water. A surface skimmer removes the matter. The system can treat up to 20 barrels of water per minute and can remove 99 percent of the total suspended solids. 

The second element of the process involves ultraviolet (UV) light used to eliminate microbes and bacteria that are present below the earth’s surface and are introduced into the water stream during the fracture process. The presence of these bacteria strains in the water can cause corrosion to infrastructure and damage the chemical mixtures used in fracture fluid mixes. To treat the unwanted bacteria in the flowback and produced water, a UV light is used to disinfect the water in the same way it may be used in hospitals or water treatment plants. When UV light is flashed through the passing water stream, it is absorbed by the bacteria, damaging the DNA structure, rendering it harmless in the water.

 Typically, a chemical known as biocide is used to treat such water. 

Halliburton’s mobile treatment unit can treat up to 100 barrels per minute. Normally, a 5 million gallon fracture treatment would require 5,000 gallons of biocide. The CleanStream service unit can drastically reduce the amount of biocide required in a fracture treatment, in some cases, to zero. 

The combination of the electrocoagulation process and the bacteria clean-up step has allowed Halliburton to create a high-performance fracture fluid based entirely on flowback water. The trademarked UniStim fluid is a gelled water system that is tolerant of salt concentration in excess of 300,000 mg/L, according to the company. The process removes just enough boron and other solids to make a clean brine suitable for complex and slick water fracture fluids. To date, the H2O Forward process has been used on 60 wells, over 260 fracture stages and, according to Halliburton, shown no decrease in production versus wells that use freshwater fracture fluid. 

“We had some customers out there that were very open to this concept,” Dale says. “They allowed us to come out and try this.”

Through 2012, the company worked behind the scenes to test the process in the field and verify it in the lab, Dale says. Although the team knew it could do what others said could not be done with recycled flowback and produced water, Dale also says the team knew it had to prove the system. After roughly 18 months, the team published its work in March. “These waters are very challenging and we knew if we could make stable fluids in the Bakken and Permian, we could do it anywhere. Fortunately, there were a few forward thinking customers that were willing to try our technology advancements that have allowed us to get to this point.” 

From Field Trial To Reality
The future success and implementation of the H2O Forward process as it applies to the Bakken isn't just about the work done in the lab or the technology package created and honed by Halliburton, it is also affected in some instances by the abilities of Nuverra. Because the process will require transport and storage of toxic flowback water, and other solids, Nuverra has created a plan to ensure the process has no weak links. For proper storage of the water, Johnsrud says it will be stored in frack water tanks that typically contain fracture fluid mixtures. The tanks, he says, have already been proven to contain frack water properly. 

The process of recycling will be performed at centralized locations, based on the geographic locations of operators and their Bakken or Three Forks wells. The price point per barrel of water will depend largely on the amount of water an operator is recycling or reusing in future wells. Johnsrud anticipates that a handful of companies will try the process (in addition to a handful that already are) over a three- to six-month period after Nuverra obtains the necessary permitting to house the flowback water and recycle it at a certain location. “I think everybody is going to be cautious just to make sure there is a consistent plan,” he says. 

It’s that foresight and recognition of the need for a solid plan that helped Johnsrud develop the contractual relationship with Halliburton in the first place. “We are not a downhole company. We are not that part of the technology package. We wanted to partner with somebody that when we went to the customer, we went with a single vision,” Johnsrud says. “We didn’t want to worry about whose technology we should use and how we should use it. We wanted to make sure that we were looking for a complimentary partner. Halliburton provides that.” 

Despite the industry’s aversion to flowback recycling and reuse, Johnsrud has always been looking to make Nuverra a part of the answer to the challenge. “The industry is changing very rapidly. What we were doing a year ago has changed. There is a lot more focus on how we do things cost-effectively with long-term sustainability in mind,” he says. “What we are doing [with Halliburton], that is really the focus of where we are trying to take this.” 

To make the process part of the Bakken’s normal operational structure, Dale continues to educate potential clients about the knowledge Halliburton has gained on what truly constitutes a suitable frack solution. “I’ve been involved with some very talented people in similar projects before when it comes to combining chemistry and equipment into new product development for recycle applications,” Dale says. “All of them were really fun projects that resulted in a new way of thinking about how to solve these technical challenges. If we can continue to build momentum, this is really special when you think about the total impact hydraulic fracturing has on the economy and energy supply.” 

Author: Luke Geiver
Managing Editor, The Bakken magazine
lgeiver@bbiinternational.com
701-738-4944