Shale & Water: Keeping It Clean

Water Sustainability Advisor at Talisman Energy, Keith Minnich told delegates at Shale Gas Results in Europe 2011 in Warsaw, Poland that he wanted to share experiences from North America which could be useful for developing unconventionals in Europe, discuss technologies available for recycle/reuse of water and address concerns about the fracking chemicals in the environment.

Most important, however, were issues like water management planning.

“Local stakeholder engagement we’ve found is extremely important to getting support of the community and the regulator,” he stated.

But first, he spoke about evaluating best practices for water sourcing, storage, and transport to and from the well.

Minnich showed a picture of a Canadian shale gas single well hydraulic fracturing operation, with a wide array of trucks, source water, well and flowback storage. The source water was in a pool on the site. A subsequent slide of another Canadian shale play had the same sort of pool for source water, but this time cylindrical tanks for flowback water at the site.

He said these were multi-well pads, of simultaneous drilling operations in Canada. “In this case the flowback is in temporary sebrings, a means of large volume storage of water. This water can be used for re fracks,” he said.

“Forest is all around and very few people are around.”

But then came a photograph of a Marcellus basin shale play, which showed several dozen red containers holding the source water, and containers for flowback storage.

He continued, “Pennsylvania is different, has a huge rural population. In this case there’s no impoundment. Lots of source water tanks in red. There are well heads with sand separators, a home, a farm in Pennsylvania- you can see how it blends into a rural setting.”

“Anything that’s in brown is in a different permit structure than for freshwater,” said Minnich, who defined the different types of water that emerged from hydraulic fracturing: Any water that flows from a well as a result of oil and gas exploration or production activity is “Produced Water,” according to him. After a well has been stimulated to fracture the formation and the pressure is reduced some of hydraulic injection fluid will flow back out of the well and is a type of produced water, often called “flowback.”

“Produced water and flowback tend to get interchanged,” he explained. “Any water from a well post production is produced water. After a well has been stimulated to fracture, that is considered flowback.”

He recognized that the public was concerned about water: issues like protection of potable water quality, protection of ground and surface water reservoirs, and the chemicals used in fracturing operations.

From a North American perspective, said Minnich, the options for sourcing fresh water were municipal water plants, surface water, and groundwater wells.

“There’s pressure on O&Gs to use brackish or saline water. In certain places there are alternative sources like mine drainage and municipal effluent.”

Finding source water for fracturing, he said, was a matter of logistics.

“Water wells near the drilling pad with surface storage of water is the simplest arrangement. The simplest and least objectionable way is to have a well right there. Impoundments and pipelines can dramatically reduce the truck traffic,” said Minnich.

“A number of these pads are directly served by pipelines,” he showed in one slide.

He said a typical water impoundment had a liner to prevent leakage, and that the type of flowback storage used depended on what percentage the flowback was.

Minnich also made mention of the technologies available for recycle/reuse of water for shale gas drilling operations. He said: “Recycling reduces impact on the environment, and in most cases there can be cost reductions. In terms of disposal of excess produced water, it can be injected into deep wells.”

There were water treatment technologies available, according to him. “The question is, is it really necessary to make drinking water from produced water?”

The first step, he said, was to sample and analyze produced water to determine its characteristics. He added that sequential flow analysis was required to fully understand the produced water. The next step, he said, was not so easy.

“There’s been a tremendous evolution,” Minnich said of the relaxation of regulations on water from slick water fracks. “As recent as two years ago, it was believed that you had to have freshwater quality; now higher levels of dissolved solids are permitted and they are working to increase the PPMs.”

Solids, he said, were not the only concern. Hardness reduction and Barium removal were also listed in his presention.

“The third step is to select the technology to meet the quality specification: filtration technology, settling for suspended solids removal; removal of traditional scaling constituents; and removal of organics.”

Minnich noted the challnge in using any membrane system was the clay.

He showed produced water analytical results from the Marcellus shale. It revealed the contents that could cause a problem like some potential for ferrous carbonate or other iron scale precipitation.

“One part of produced water was mixed with four parts fresh water, so hardness reduction was not required,” he said. “This type of chemistry is typically used in formations in Pennsylvania.”

“There are well proven water treatment techniques that can convert produced water to near drinking water quality, at a cost,” explained Minnich. “The challenge is determining what quality of water is required to enable recycling.”

He added that there were times when disposal was driven by logistics. If fracking is not going on, injection into deep wells is the traditional solution for disposal in North America.”

His presentation offered a photo of a deep well injection plant.

“It’s not available in every location and surface discharge may be an option. The state of Pennsylvania allowed it but has essentially banned the practice after concern about untreated pollutants, because regulations and guidelines for effluent are not well developed.”

Minnich added, “Sewage treatment plants typically can’t remove bromides, some of the chloride salts and some organic compounds.”

Regarding disclosure of fracking chemicals, he said, “The industry has been under pressure to disclose what’s in it. Fracfocus.org includes an educational section in addition to the disclosure form. All hazardous ingredients are listed by chemical name and the concentration of ingredients in fracture fluid.”

He admitted that the public was still asking “what’s being hidden?” because the disclosures didn’t add up to 100%. “Maintaining proprietary information is also a concern for the industry,” he said.

“Texas just passed legislation that includes a provision to try and deal with trade secret issues,” reported Minnich. “Land owners or others affected will have a right to know what’s in the fluid while maintaining the privacy of the company.”

In terms of ground water protection, he gave voice to concerns about methane contamination and the migration of the frack chemicals. “Shale wells have horizontal as well as a vertical section as well. That’s where the gas migration would occur.”

He continued: “There are many papers on how to protect groundwater from methane contamination. Alberta has extensive regulations on it and what to do about it if it happens. It is a distinct and separate situation from the migration of chemicals.”

He was adamant that there was no apparent pathway for the migration of fracking chemicals.

“There are 10,000 meters between the frack zone and shallow groundwater,” explained Minnich. “It’s a challenge to communicate that with the public.

“One of the things getting exported from America is the fear and what are the risks of shale gas. Getting people to understand the real risks is one of the challenges.”