Colorado Frackers Doubled Freshwater Use During Megadrought, Even as Drilling and Oil Production Fell

In the middle of the longest-running drought in more than a thousand years, Colorado energy companies diverted rising volumes of the state’s freshwater resources for fracking, a new analysis shows.

Colorado operators doubled their use of high-quality water to prepare wells for fracking over the last 10 years, with diminishing returns on oil production, the nonprofit group FracTracker Alliance reported earlier this month. Average volumes of water used per well quadrupled over that time, the analysis found.

Colorado standards governing what water sources energy companies can access for fracking and how they dispose of wastewater are unsustainable and “incredibly wasteful,” concluded Kyle Ferrar, FracTracker’s western program coordinator, in the report.

Fracking, short for hydraulic fracturing, injects water, sand and chemicals of varying toxicity under high pressure to splinter rock and prepare wells for extracting oil and gas trapped within rock formations. Completing wells can prove water- and energy-intensive as operators extend the length of horizontal wells to reach sequestered fossil fuels. It can also yield massive amounts of wastewater, known as produced water. 

Colorado provides a “particularly striking example” of a state where the freshwater demands for oil and gas extraction have substantially increased, Ferrar noted in the report, even as rates of new drilling and fracking operations slowed down.

Ferrar found that fracking operators’ freshwater consumption rose from about 5 billion gallons in 2013 to more than 10 billion gallons last year and increased from an average of 2.7 million gallons per individual well to 10.9 million gallons during the same period. Injecting more and more water into wells did little to boost oil production. 

But most importantly, Ferrar said, the data show that Colorado’s operators have generated enough wastewater to supply fracking operations without having to draw on the state’s precious freshwater resources.  

Ferrar analyzed the state’s water use after Democrats in Colorado’s House of Representatives introduced a bill in March to limit freshwater consumption in oil and gas operations. The bill, HB 23-1242, would require operators to reduce their freshwater use and instead use water recycled from their oilfields. It would also require operators to report the miles trucks travel to haul water for oil and gas operations.

“As we continue to combat the worst drought conditions of our lifetime, it’s vital for us to use every method at our disposal to preserve our water,” said the bill’s cosponsor, Rep. Andrew Boesenecker (D-Fort Collins), after it passed the House in April.

Colorado oil and gas regulators estimate that surface water and groundwater accounts for 84 percent of the oil industry’s water use.

To get a handle on overall water consumption, Ferrar obtained data from FracFocus, a national fracking registry, and the Colorado Oil and Gas Conservation Commission, or COGCC, which regulates the industry. He plotted operators’ use of water against how much wastewater and oil they produced between 2013 and 2022. 

Statewide volumes of water used for fracking tripled in 2018, he found, then dipped two years later, likely due to Covid-related market declines, before rising again. The dramatic spike in 2018 did not result in higher oil production, a trend that continued through last year. Volumes of produced water exceeded operating demands in all but one year. 

“These oil and gas companies are using completely unnecessary volumes of water for hydraulic fracturing,” Ferrar said. In the process, he added, they’re generating enough produced water to satisfy their fracking water needs.

All that wastewater can be treated to remove contaminants that interfere with fracking operations and then recycled, he said, instead of diverting water that could otherwise supply agriculture and municipalities.

There’s one major complication, though. The region that consumes the most high-quality water—the Front Range, which includes Boesenecker’s district—lacks the type of infrastructure needed to capture, treat and transport wastewater, which operators in other parts of the state built years ago.

Scrambling to Find a Solution

How much water Colorado oil and gas operators use and recycle varies by basin. That’s generally a reflection of how much water exists in a petroleum reservoir and whether operators built the necessary infrastructure over the years to reuse and recycle wastewater.

The Piceance Basin in northwest Colorado tends to have large volumes of water in the geologic formations targeted for gas extraction, said John Messner, COGCC commissioner. With so much water coming out of the wells, Messner explained, companies had to develop the infrastructure to reuse that water from the beginning.

Now it’s actually more cost effective for Piceance operators to recycle their produced water than it is to dispose of it, Messner said.

The Denver-Julesburg Basin, or DJ Basin, is a different story. The formations generally don’t have much water in the rocks, and most of the water that returns to the surface was injected to frack wells, Messner said. Plus, operators in the region never built the infrastructure to recycle their wastewater.

That’s a problem because most of Colorado’s recent crude oil production comes from the Niobrara Formation in the DJ Basin, which skirts the eastern edge of the Rocky Mountains along the Front Range. Here, Colorado’s fastest-growing and most populous region bumps up against the center of its oil production, Weld County. About 9 out of 10 barrels of Colorado crude oil comes from Weld, according to the U.S. Energy Information Administration. 

Weld County also accounts for roughly 90 percent of water consumed by fracking operations, Ferrar found. Weld operators used the same amount of water last year as the water district in Greeley, the county seat, sent to its 100,000-plus residents.

Although cities and farms use far more water than fracking operators, most of that water can be treated and returned to the hydrological cycle by using it to replenish surface waters. Once water is diverted for fracking, the wastewater that returns to the surface is too contaminated with petrochemicals, salts, additives and other toxic substances to release it into the environment. 

But managing huge volumes of wastewater has proven challenging. Colorado’s oil and gas industry saw a dramatic spike in produced water spills last year, the Center for Western Priorities, an environmental group, reported. And federal officials reached a $1 million settlement with Houston-based Noble Energy and its subsidiary, Noble Midstream, a few years ago related to alleged Clean Water Act violations associated with oil and produced water discharges and spills at their Weld County facilities.

Most fracking wastewater ends up injected deep underground in disposal wells, lost to the water cycle. Leaky injection disposal wells are a major source of noxious emissions, including the climate super-pollutant methane and air contaminants linked to cancer and other diseases, as well as precursors of lung-damaging ground-level ozone. 

Tackling the low rate of recycling on the Front Range was one reason Messner partnered with the Colorado School of Mines last year to launch the Colorado Produced Water Consortium, similar to those in Texas and New Mexico. The consortium, a diverse group of stakeholders from industry, government, academia, environmental groups and beyond, worked to identify challenges with reusing produced water inside the oilfield while exploring the potential for “beneficial” uses outside oil operations, including dust control and irrigation.

There are many questions associated with reusing produced water outside the oilfield, Messner said, like understanding “what constituents are actually in that water before you spray it on tomatoes.”

California regulators, by contrast, assured consumers that the crops grown with produced water pose no elevated safety risks, a claim Inside Climate News showed was not supported by the evidence. 

When Messner learned that legislators wanted to manage this growing wastestream, his agency ended up helping craft HB 23-1241. “We do actually think that encouraging the reuse and recycling of produced water, and reducing the amount of freshwater in oil and gas activities, is an important thing,” he said.

Yet the hurdles are high. On the Front Range operators invested in pipelines to ferry freshwater across the region, not to recycle their wastewater. For example, Noble Energy expanded its investment in “midstream” pipeline and transmission facilities to deliver freshwater across the DJ Basin in 2017. Water use for fracking spiked to 15 billion gallons the following year, Ferrar found, with Weld accounting for 80 percent of that year’s volume. 

“With the development of that midstream business, you see everyone’s water use just go way up, as they have more direct access to water,” said Ferrar.

Several individual operators, including Noble Energy, used more than 27 million gallons of freshwater to frack single wells in 2021, when reservoirs in the Colorado River Basin and California hit record low levels. 

Chevron acquired Noble in 2020, in a multibillion dollar deal. Chevron spokesperson Deena McMullen said the company conducted an initial pilot study on produced water recycling in Colorado in late 2021, and ended up building a recycling facility. Chevron analysts expect that recycling will lead to a roughly 12 percent reduction in the volume of freshwater usage over the facility’s lifetime. 

That’s a start. But critics say there’s an urgent need to conserve high-quality water resources in a region still coping with the driest two decades in 1,200 years.

The punishing drought, intensified by climate change, severely strained the Colorado River, which supplies drinking water for 40 million people in seven states, and fueled the largest wildfires in Colorado’s history. 

The lack of infrastructure to move produced water around remains one of the biggest roadblocks to reducing reliance on high-quality water, particularly in the DJ basin, Messner said. Without that infrastructure, you’d have to rely on trucks, he said. “The emissions associated with that would be astronomical.”

Careful attention to proper storage is also key, Messner said, because the wastewater itself releases hazardous emissions. 

Ferrar recently visited injection disposal facilities on the Front Range armed with specialized imaging equipment to document emissions escaping from the sites. He and his colleagues detected uncontrolled emissions from half of the dozen sites they visited.

The Front Range earned a “severe” air quality violation from the Environmental Protection Agency last year for failing to meet federal ozone standards. Oil and gas operations are a major source of ozone, research shows.

For Messner the magnitude of the task does not diminish its urgency. “That’s why we started the process 12 months ago to figure out ways to increase the amount of reuse and recycling occurring in oil and gas activities and decreasing the amount of freshwater use in certain basins.”

The challenge will be figuring out how to pursue aggressive recycling targets in basins lacking infrastructure without causing even more environmental harm. And that means putting the proper infrastructure in place. “If we arbitrarily just said tomorrow, ‘Operators, you need to reuse and recycle 90 percent of your produced water for all new oil and gas activities,’” Messner said, “the adverse environmental impacts associated with that would far exceed the benefits of recycling.”