EDITOR'S NOTE: This story is the second of a two-part series. You can read part one here.
Drilling and hydraulic fracturing a well is only half the story when it comes to the water used in oil and gas exploration.
After the well is drilled, after the target formation is fractured and as the oil and gas begins flowing up the well, wastewater comes along with it.
As Colorado Springs and El Paso County wrestle with the sudden interest in drilling in the area, what to do with that wastewater is a big concern.
As much as half of the fluid used to fracture the rock gradually returns to the surface as flowback water, emerging from the well along with the oil and gas over a period of weeks.
Many rock formations, including the Niobrara, also contain water, often briny and laden with minerals, that comes out of the well as what is called produced water, over several years.
“Produced water can be nasty, nasty stuff; other places you can drink it,” said Thom Kerr, acting director of the Colorado Oil and Gas Conservation Commission (COGCC), which oversees oil and gas drilling in the state.
Getting rid of flowback and produced water is a challenge for drilling companies, since it’s generally too toxic to simply be poured out on the ground — although the state allows drillers to spread produced water on roads if it meets a purity standard. Some of the flowback fluid can be put through filters and reused at the next well.
Ultra Resources, a Houston, Texas-based oil company, is drilling three exploratory wells in El Paso County and has applied for permits to drill three more, two of those on Banning Lewis Ranch in Colorado Springs. The company isn’t recycling the water for those initial wells, officials say, but company officials say it will if it moves on to large-scale drilling.
“Recycling wasn’t really practical for the small volumes we pumped on our vertical well, but we absolutely plan to do it if we go to horizontal development,” said Kent Rogers, vice president for drilling and completions for Ultra Petroleum, Ultra Resource’s parent company. “If you think about it, it saves us money and makes economic sense for us to capture and re-use as much water as possible.”
Eventually, though, the wastewater needs to be disposed of, either by treating it, putting it into a pit and leaving it to evaporate, or hauling the wastewater to a special injection well and pumping it 10,000 feet beneath the surface, never to return. Those disposal wells are the ultimate destination for most of the flowback water and produced water in the state.
But the injection wells, or disposal wells, themselves have become controversial. Several studies have linked injection wells to earthquakes, even though it’s often difficult to draw a direct connection. The quakes, most recently in Ohio and Arkansas, are apparently caused by the water pressure fracturing rocks or lubricating a fault near the injection well.
It’s not common — there have only been a handful of cases linked to the roughly 500,000 injection wells in the country — but it is, literally, unsettling. Most of the earthquakes have been small, but a few have approached magnitude 5 on the Richter scale.
Colorado has about 305 disposal wells and two or three sets of earthquakes in the state have been linked to injection wells, although none since the early 2000’s. One of the earliest known cases of what’s called “induced seismicity” occurred at the Rocky Mountain Arsenal in 1966, linked to a well designed to dispose of tainted water from the chemical weapons site. More recently, a series of small earthquakes near Trinidad may have been related to injection wells.
“They have had seismic activity in the Raton Basin for a long time — that is the question, whether an event is induced or natural. Hard to say,” said Stuart Ellsworth, engineering manager for the COGCC. “We have asked operators to put in some seismometers to get a reading. The accuracy of our data down there is plus or minus 10 miles (so) it’s hard to get a discrete understanding.”
Last year, the oil and gas commission began requiring a site review by the Colorado Geological Survey to look for proximity to known faults before permitting injection wells. The commission also limits the injection pressures for the wells to prevent fractures and limits the total volume of wastewater pumped down the wells.
The hydraulic fracturing process itself is sometimes blamed for earthquakes, but the seismic activity caused by fracking is generally too small to feel at the surface. However, there have been a handful of incidents where fracking was linked to earthquakes as large as magnitude 2.8 on the Richter scale.
It’s hard to say how soon Ultra or other companies would even need an injection well in El Paso County. The 305 injection wells in use statewide service roughly 40,000 oil and gas wells. Ellsworth said the COGCC permitted 32 new injection wells in 2011 and 28 in 2010, but those were needed mostly due to drillers moving into new areas rather than because the old disposal wells were full. Currently the nearest injection wells to Colorado Springs are in Lincoln County.
“During development, quite a bit of water gets left behind in the Niobrara formation we’re producing oil from,” Ultra’s Rogers said of the water used in fracking. “It costs us money to dispose of water, so we like to dispose of as little as possible. It’s likely we’ll inject ours into a disposal well at some point in the future.”
Injection wells may not sound like an ideal solution, but the alternatives have problems of their own. Trucking wastewater to an injection well somewhere else is one possibility, but it creates additional traffic, adds costs and, of course, simply moves the issue.
The other alternative is evaporation pits, where the produced water is left to simply dry out in the sun. Ellsworth said the COGCC allows evaporation pits to be used only for relatively clean water and never for fracking fluid. Even so, the water in evaporation pits is highly salty and can leak or overflow, and they can trap animals (and potentially people) that fall into them. Kerr said his agency avoids allowing evaporation pits near populated areas.
Ultra’s permits anticipate the company will build large pits at several well sites, but those would be used only for fresh water before it’s used in the drilling process. The company is using a “pitless” drilling system for its El Paso County wells, so wastewater goes directly into tanks.
The last alternative is treating the contaminated water until it’s safe enough to drink. That’s easier in some areas than others, because of the quality of the produced water, but it’s not commonly used in eastern Colorado wells targeting the Niobrara Shale formation as Ultra is.
The final ingredient in the mix of oil and water is how local, state and federal governments ensure that oil, gas and wastewater aren’t contaminating aquifers and drinking water supplies. When El Paso County commissioners were considering new oil and gas regulations in January, they deferred most of the oversight to the state, but insisted on an enhanced water quality monitoring program, which is being codified through a memorandum of understanding with the COGCC.
Local environmental leaders say that finding leaks or spills quickly and responding to them needs to be the goal for monitoring programs.
“When you’re dealing with underground, you’re dealing with unknowns,” said Jane Ard-Smith, chairwoman of the Pikes Peak Group of the Sierra Club, who has been a keen observer of both the county and the city’s debates over how to regulate oil and gas development.
Oil and gas drilling, whether it’s successful or not, is a temporary use for the land, Ard-Smith said. The community is eventually going to need the ground water and aquifers in eastern El Paso County for other uses, so public officials need to make sure those resources will still be there.
“Water is a bigger issue than oil and gas development,” she said. “Once groundwater is contaminated, it’s nearly impossible to get that cleaned up and you really have eliminated that as a resource.”
Ultra’s permits and applications in Colorado Springs and El Paso County include requirements for testing nearby wells or groundwater before drilling begins and then at least twice after drilling is completed. The Colorado Oil and Gas Association last year implemented a similar voluntary program which most of the state’s oil and gas drillers have signed on to.
“We think it’s a really good program,” said Tisha Conoly Schuller, president and CEO of the association.
COGA’s program is modeled after one that’s been running for a decade in the San Juan Basin around Durango, she said.
“They have 10 years of data where they’ve been able to demonstrate over time that oil and gas operations can happen and groundwater can be protected,” Schuller said.