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Alt. Water Transfers

Cover HW Fall 2017

Water sharing and banking, coined "alternative transfer methods" or ATMs, could provide flexibility for stretched water supplies —but not without marked challenges. Read the Fall 2017 issue of Headwaters magazine and explore options to:

  • keep water in farming
  • help municipalities plan ahead
  • share between ag and environmental uses
  • bank water on the Colorado River

Browse articles and find a flipbook of the magazine here.

Connecting the Drops

connectingdropslogo4.1Bringing you the reporting you crave over the radio airways with extras and archives on our website. Visit the audio archives or listen to the latest story on the National Wild and Scenic Rivers Act and the Colorado river that could become the state's second wild and scenic protect river—Deep Creek:

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Water Education Colorado

Risks & Rewards

By Erin McIntyre

How Will Escalating Oil & Gas Drilling Affect Colorado's Water?

As the saying goes, one person's trash is another one's treasure.

In this case, the water laced with hydrocarbons, salt and minerals gushing from the earth during oil and gas drilling every day in Colorado may be part of the answer to the state's water woes.

Some water experts would like to see this poor quality water help stretch water supplies needed for household use, agriculture and wildlife. They hate to see the equivalent of three Antero Reservoirs go to waste each year.

This mixture is called ‘produced water’ and it comes to the surface during extraction of oil or natural gas, or one of its components, methane. In Colorado, most of the time, produced water is re-injected deep below the earth's surface or placed in disposal wells. Produced water is the drilling industry's largest waste stream—but every drop counts in drought-stricken Colorado which is pondering projects like the Big Straw and eradication of tamarisk to conserve water.

More than 3 billion gallons of produced water are disposed of every day in oil and gas operations globally, and produced water amounts to 98 percent of the industry's total waste stream, according to Oilfield Review, published by Schlumberger. Water professionals are concerned about the impacts of this produced water on other water sources — including contamination and depletion of wells and streams.

But some also hate to see the resource go to waste.

‘This water is treated as waste product and in the semi-arid West we don't tend to waste water,’ says Dr. Robert Ward, director of the Colorado Water Resources Research Institute at Colorado State University. ‘Someone ought to be able to put it to beneficial use.’

But putting produced water to beneficial use in Colorado is more complicated than treating the water and distributing it. A gauntlet of permitting and review by three state agencies creates a tedious process for those wanting to use produced water.

‘People started first identifying this as a potential commodity in about 1998, 1999,’ said Dick Wolfe, Colorado Division of Water Resources assistant state engineer. ‘It wasn't until 2002 that I personally had a thorough understanding of whose jurisdiction this groundwater was under depending on what you want to do with it.’

Although the water is used in energy production, the state of Colorado does not currently consider oil and gas operations' use of the water a beneficial use. At present, energy companies do not have to obtain augmentation plans or well permits to use this water pumped out of the ground. However, a court case currently pending in Water Division 7 (Durango) is challenging this existing scenario.

Produced water's use is regulated by the Colorado Oil and Gas Conservation Commission, under legislation called Rule 907. Under the rule, produced water slated for disposal may be injected below ground, placed in a pit to evaporate, spread on roads, taken to commercial disposal facilities or released to a stream, with the proper discharge permits.
But if the water is used for anything besides drilling operations, a well permit is required and the water falls under the jurisdiction of the Division of Water Resources, said Wolfe.

Beneficial Brine?
Produced water varies widely in quality. In shallow coal-beds, the extracted water can sometimes be used for drinking water. This is often the case in Wyoming coal beds. But deeper formations, such as those tapped in Colorado, contain older water which can have higher amounts of minerals or total dissolved solids, TDS. Water produced by coal-bed methane wells in western Colorado can be 30 times saltier than drinking water, according to EnCana Oil and Gas.

The extraction process also can put underground aquifers and surface streams at risk of contamination. When drilling companies mine coal seams and gas pockets, they use ‘frac'ing fluid,’ most commonly a mixture of water and sand but sometimes containing hazardous chemicals and hydrocarbons.

Drillers force the fluid at high pressures into the ground, fracturing the rocks and coal beds. The sand acts as a ‘proppant,’ holding the cracks apart so the methane gas can escape. This frac'ing fluid can taint the water pumped out during the process. The fluid can also potentially contaminate the remaining ground water aquifers.
Re-injection of this tainted water deep underground is the most common practice in Colorado, but some people say it's a dangerous practice.

‘There definitely have been cases where those injection wells have caused problems,’ says Lisa Sumi, research director of the Oil and Gas Accountability Project in Durango. ‘If other wells tap into the formation where water is injected, there is a hole where water can travel upwards and contaminate adjoining groundwater.’

In a report released in 2002, the Environmental Protection Agency evaluated water quality in relation to coal-bed methane development in 11 major coal basins in the United States—including the Powder River Basin in Wyoming and the San Juan basin in southwestern Colorado and northwestern New Mexico.

People who live where hydraulic fracturing was done complained to the EPA of water-quality problems. They said water had a ‘strong, unpleasant taste and odor,’ according to the study. They also complained of the effect on wildlife and vegetation, and loss of water in wells and aquifers, as well as new ponds and swamps created from water discharged by the drilling operation.

‘If coal beds are located within USDWs (Underground Sources of Drinking Water), then any fracturing fluids injected into coal beds have the potential to contaminate the USDW,’ the study says. Researchers found that 10 of the 11 studied coal beds were located within underground drinking-water sources.

But even given that level of risk, in the end the EPA could find no conclusive proof of drinking water contamination.Its study found that ‘after reviewing data and incident reports provided by states, EPA sees no conclusive evidence that water quality degradation in USDWs is a direct result of injection of hydraulic fracturing fluids into CBM wells and subsequent underground movement of these fluids.’

Still, Sumi says there's no way to understand exactly what is going on within the Earth's natural fractures and the paths of groundwater.

‘It's such a black box underground,’ she says. ‘Even though they say that (injecting) won't (cause problems), it has.’

In one case of wells contaminated by production gas near Silt, the Colorado Oil and Gas Conservation Commission's staff recommended a fine for EnCana Oil and Gas. Hearings for the commission to make a decision have been postponed until spring 2006, says EnCana spokesman Doug Hock.

The company was fined $371,000 in August 2004 in relation to a natural-gas seep in and around West Divide Creek in the Piceance Basin. The money paid for a water-quality study scheduled for completion in January 2006 and a moratorium on drilling within a two-mile radius of the seep.

Water for Homes
Engineer Dave Stewart specializes in taking one person's problem and turning it into an asset for someone else. For more than three years, his firm, Stewart Environmental Consultants, has worked with its clients near Wellington to get approval to treat produced water from drilling operations using a membrane-treatment plant to remove contaminants. The resulting treated water is then used to compensate for well water consumed in about 1,000 northern Colorado homes. The treated water is not actually used in the homes. It is used to make up for the water pumped from their wells which previously would have contributed to local stream flows.

The treated water is released to Box Elder Creek, which converges with the Poudre River 11 miles south of Wellington near Fort Collins. Water resource engineers say that in the scope of total river flows, the amount released is negligible but likely supplies some junior users with a portion they might otherwise be without.

The plant is scheduled to start treatment in January 2006. Stewart says the regulatory hurdles were immense.

It took 1 1/2 years for Stewart's team to prove to the Colorado Division of Water Resources that the produced water pumped to the surface by the oil and gas production was not contained in aquifers which also help support flows in a surface stream. After that came a string of negotiations and permits with the Colorado Oil and Gas Conservation Commission and the Colorado Water Quality Control Commission.

‘The government should not be a hindrance to this and it's been a huge hindrance,’ Stewart says. ‘We've had numerous issues with the Oil and Gas Commission just because it's a brand-new paradigm.’

Despite the difficulties, Stewart feels this project is embarking on a drought-proof source of water that will be valuable after it is mined from the oil fields.

He estimates the Wellington project can produce 165 acre-feet per year for 1,000 years. If the water was extracted at a faster rate, Stewart estimates the field could produce 500 gallons per minute. At that rate, it could yield up to 750 acre-feet per year for 300 years.

‘Nobody's done it before,’ he says. ‘I think probably the biggest driver is…the value of water.’

Water for Industry
EnCana Oil and Gas is leading the industry in produced water treatment in Colorado, and has found a financially viable way to treat produced water and re-use it in its operations.

The company built its Mamm Creek water treatment facility in 2003 to treat water produced through natural-gas extraction and in September started a pilot program to treat coal-bed methane produced water. The treatment plant, located five miles southeast of Rifle, allows EnCana to recycle all of its produced water in the Mamm Creek field area. The water is de-contaminated with a membrane filtration process, with the final membrane performing reverse osmosis.

EnCana has 24 test wells exploring for coal-bed methane in the Piceance Basin. Each one of those wells can produce between 12,600 and 126,000 gallons of water per day, says Mark Thrush, EnCana water systems engineer.
The coal-bed methane produced water is actually easier to treat than the hydrocarbon-laced produced water coming to the surface during natural gas drilling, says Thrush.

The coal-bed methane produced water has a TDS of around 700, still too high for drinking-water standards, but, ‘I don't think we ever envisioned that the water would be used for drinking water,’ says Hock, EnCana's spokesman.
Before EnCana built the treatment plant, Thrush says it injected the water underground and sent water unfit for drilling or frac'ing to disposal wells. Their new treatment plant is designed to function with at least 80 percent efficiency, meaning only 20 percent of the water must be sent to disposal wells now.

Using recycled water in its drilling operations allows the company to avoid using fresh sources of water for production. It also reduces truck traffic and operating costs.

‘Otherwise we'd be paying to inject that water down hole, so it definitely saves us money,’ says Thrush.

While EnCana has a demand for all the recycled water in its operations at the moment, the company has obtained discharge permits and in the future could release the recycled water to local rivers for beneficial use.

‘We may get to a point ... where we have an excess of water, and at that point we would be in a position to release [it] to the waters of Colorado (River),’ says Thrush. ‘With coal-bed methane, it's really going to create more water than we have a need for.’

'Almost a Gift'
In the oil and gas industry, water is measured in barrels — equal to 42 gallons — an unfamiliar term to ranchers and hydrologists alike, who deal in acre-feet, cubic feet per second, or the less formal second-foot.

While barrels of water can be considered a liability for energy developers, some water users would like to convert those barrels to something everyone can use.

Pat O'Toole, a Wyoming rancher sees produced water as an asset, if managed correctly. It may serve as a possible buffer to help citizens make long-term decisions about water use and stave off demands from thirsty cities.

‘Really, it's almost a gift,’ he says.

As president of the Family Farm Alliance, he's watching water transfers from agricultural to urban uses and wondering how farming will be kept alive.

Ironically, energy development in rural areas, which is causing towns to boom and increasing water demands, may end up helping agriculture survive if its ‘waste’ can be put to new uses.

O'Toole, a former Wyoming state legislator, realizes putting contaminated water to beneficial use won't be easy from a legal standpoint. Recycling projects like the one in Wellington invoke new laws and new science. In Colorado, there are at least three state agencies that have to work together to regulate produced water's treatment and use.

If the water is released to a stream, the Colorado Water Quality Control Commission must approve a discharge permit. If the water is beneficially used and subject to administration as a water right, the Division of Water Resources gets involved.

With such daunting legal hurdles, it is not surprising that most oil and gas production companies use only the current methods of disposal accepted by the Oil and Gas Conservation Commission. It's easier at this point for the industry to just inject the produced water below ground than deal with the regulatory issues of putting it to beneficial use. But people like O'Toole want to find an incentive for the industry to help make produced water usable.

‘Clearly it needs to be an integrated approach and it's not cleanly a water issue,’ says O'Toole. ‘It's a water-mineral-taxation-environmental issue.’

CSU's Robert Ward and O'Toole are trying to tap into the bigger picture of produced water and are organizing a workshop at the university in April where representatives from Colorado, Wyoming, Montana, California, Texas and other places will gather to discuss produced water usage. Ward says it's a first step to figuring out how people in the West can put this water to use.

‘If there're significant volumes of this kind of water and it can mesh with the river systems in an appropriate water quality perspective, then maybe it will serve to ameliorate the transfer of agricultural water to growth,’ says O'Toole.

‘The (energy) companies have been talking about water and using the word 'disposal' and I think water is too valuable a commodity to think of it as disposable."

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