Should the state continue to allow waste fluids from oil and gas drilling to be pumped underground in Fayette County? That’s the question officials must answer as an underground injection control (UIC) well in Lochgelly comes up for re-permitting.
Everyday citizens may not have much experience with such wells, and there’s a lot to learn. So — why does the injection well in Lochgelly exist, and how does it work?
Class II disposal wells exist because of the large amount of fluid produced by oil and gas extraction in the U.S. — more than 3 trillion gallons over the course of several decades.
Instead of discharging it into rivers or collecting it in cesspools, the fluid is pumped deep underground.
Disposal wells make up approximately 20 percent of the 144,000 Class II UIC wells in the country. Class II wells collectively inject 2 billion gallons of produced fluid into the earth every day, according to the Environmental Protection Agency (EPA). They are one of six types of UIC wells permitted by federal regulation.
Much of the fluid is brine brought to the surface during oil and gas production. The salty water can also contain toxic metals and radioactive substances from underground, plus fracking chemicals, which have been shown to contain a variety of toxins.
The fluid is injected into the same geological formation from which it came, or a similar one, using a pressurized well.
The idea is that confining layers of rock keep the fluid from migrating upward and contaminating the water table. The injection pressure is kept below the pressure it would take to fracture the rock around or above the fluid.
Why it matters for Fayette County
Danny Webb Construction operates two disposal wells and one holding pit with a divider down the middle on Towne Hollow Road in Lochgelly.
The produced fluid is trucked to the site and either pumped into holding tanks or — if it contains a lot of dirt or coal — into the holding pit, where the solids settle out. The fluid then passes through a 5-micron filter and is injected underground.
“It was nothing but a pure garbage dump when I purchased the property,” says Webb, who has been in the oil and gas business since 1984, has an interest in about 100 gas wells, and defends his business as not only legal but “the environmental thing to do.”
“The state (Office of Oil and Gas) was the ones that brought me in and showed this to me in the first place and told me they thought there was a need for it,” he says.
Only one well is actively being used at the moment, and that’s the one up for re-permitting. It has absorbed more than 1.4 million barrels of brine since 2002, when it was created.
There is no limit on the amount of fluid that can be injected, as long as the company passes mechanical integrity tests on the wells.
Any fluid from an oil and gas operation — from West Virginia or elsewhere — is fair game, including not only brine but drilling fluid, fracking fluid, and other wastes. Webb’s company must do the hauling of the waste; no third-party haulers are allowed.
“Five years ago, it was probably one of the higher volume wells (in the state), but currently it’s dropped off,” says Jamie Peterson, who oversees Class II wells for the West Virginia Department of Environmental Protection (DEP).
He says that now there’s more competition from other disposal wells in the northern part of the state, which are closer to thicker deposits of recently tapped Marcellus shale. Fewer and fewer coal bed methane wells, which supplied most of the well’s business, are being drilled these days.
Webb says the state also suggested building the pit, to save on cost and keep him in business.
“They want this to go,” he said.
The longer he holds the water in the pit, the less he has to filter it. He calls the pit the “backbone” of his operation, without which he would spend three times as much on filters. He spends about $100,000 per year currently.
“I’m not the only one doing this, but seems like I’m the only one they pick on,” he says, referring to those with a concern over how the well might be affecting health, water and the environment.
Indeed, West Virginia is host to 759 Class II wells, including another in Fayette County operated by EQT Production Company.
Webb pays $118 in property taxes to Fayette County each year for his 4.76-acre property around the well.
So is it safe?
The waste is injected into the Weir sandstone, 2,703 feet underground and, in theory, separated from groundwater by several layers of rock.
“The formation just takes it,” says Peterson. “There is a confining layer [of rock] above that layer that is not permeable so the fluid is not expected to come up above that formation.”
Moreover, he says a steel surface casing, long string casing, packer and several layers of cement prevent any contamination. It’s “basically impossible” for the waste to enter the water table, says Peterson.
The pressure of the annulus — the space between the tubing and long string casing — is monitored for any changes, which would indicate a leak.
“The last thing we want to do is have a leak,” says Webb. “If you have a leak, you’ll know immediately. We would immediately stop and clean it up and make sure it would never happen again. If I thought we were ever going to have one, I’d stop now.”
The EPA’s website discusses how UIC wells “protect drinking water resources” by avoiding dumping brine into surface waters, while acknowledging that “injection activities have the potential to cause the movement of contaminants” into drinking water, thus endangering human health. Overall, the EPA, DEP, and Webb himself downplay any risk for contamination.
But the safety of such wells has been called into question, most recently in an investigation by ProPublica, a nonprofit, independent news organization working in the public interest. They say there are “hidden risks” associated with pumping so much waste underground.
Their analysis of 220,000 inspection records found that structural failure inside injection wells is “routine,” with one well integrity violation written for every six wells between late 2007 and late 2010. That’s a total of 17,000 violations.
ProPublica reports that 7,000 wells showed signs of leakage and that wells “are frequently operated in violation of safety regulations” and “under conditions that greatly increase the risk of fluid leakage and the threat of water contamination.”
Studying the way fluid flows underground is complex and expensive. Part of the problem, say some experts, is that theoretical models used to determine the safety of an injection well have proved inaccurate in some instances. Anyone who claims certainty about the way fluids flow underground is not to be believed, they say.
A 2012 study published in the journal Ground Water concludes that, over time, contaminants will naturally flow toward the surface from deep within the ground via natural cracks, and that industrial fracking could reduce the transport time.
What might have taken up to tens of thousands of years could happen in “tens or hundreds of years” because of the fracking of shale. In addition, says the study’s author, the pressure from injecting so much fluid underground could widen existing fractures and reduce the travel time to “less than ten years.”
In short, natural and manmade fractures underground can combine to challenge the notion that the contaminants will stay put.
Places where industry has already dramatically changed the underground geologic landscape — the oil and gas fields in Texas are an extreme example — are more likely to run into trouble with injection.
“When injection wells intersect with fracked wells and abandoned wells, the combined effect is that many of the natural protections assumed to be provided by deep underground geology no longer exist,” Abrahm Lustgarten wrote for ProPublica.
The consequences for contaminating drinking water include fines, required cleanup, or closure of the well, according to the EPA.
The permit for the Lochgelly well expired last October, but it is still actively injecting waste “with (the DEP’s) blessing,” says Webb. The well passed a mechanical integrity test in May 2012.
Peterson says he takes responsibility for the fact that the re-permit is running late.
Webb’s application hasn’t changed since the last re-permitting, but Peterson’s office is asking for two additional, nonrequired reports this time around.
One is a fault investigation, which will explore the potential for seismic activity. The other is a plume prediction model, or a migration model, which is supposed to provide some idea of where the fluid in the formation is going.
A re-permit also involves reporting any new wells that have been drilled or plugged in a quarter-mile radius, well water testing, and testing of representative samples of the fluid being injected.
Peterson says the permit could be changed or not re-issued at all, but he won’t know until he gets all the information and sees how a public hearing goes. A date has not yet been set for the hearing, but Peterson says there is enough public interest to warrant one.
— E-mail: email@example.com
For more info:
About Underground Injection Control wells from the EPA,
ProPublica’s investigation of injection wells is available at
n A helpful diagram of how a Class II injection well works is available at