Act 13 impact fees, plunge in natural gas prices led to more plugged wells

Sometime in 2012, Bruce Jankura, an oil and gas inspector supervisor with the Pennsylvania Department of Environmental Protection, began receiving unusually large batches of requests for his plugging services from Marcellus Shale companies.

“All of a sudden, we would get 50 of them, 100 of them,” he recalled.

There are two main reasons why oil and gas wells are plugged: Something goes wrong with the well or it’s tapped out. Neither scenario fit this pattern.

The culprits lay above ground.

The price of natural gas was deep into its dive toward a low of $1.95 at the Henry Hub in April of that year. In addition, Gov. Tom Corbett had just signed Act 13, the state’s oil and gas regulatory overhaul that imposed an impact fee on shale operators.

That impact fee applied to any shale well already completed or begun, and there didn’t need to be much progress beyond digging a shallow hole in the ground for it to qualify.

At this point, of the more the 7,330 unconventional or deep, fracked wells that have been started in Pennsylvania over the past decade, 401 — or 5.5 percent — have been plugged.

Many never made it beyond infancy. They were just the beginnings of wells — a hole dug a few dozen feet deep and stuffed with a conductor pipe. That’s the first step in digging an unconventional well and it allows for the deep vertical drilling rig to have something to drill into when it gets to the site.

Companies like Talisman Energy, a Canadian operator that works mostly in the northeastern part of Pennsylvania, had started hundreds of wells between 2009 and 2011, many of which ended up being plugged in the two years since Act 13 passed.

Talisman had an aggressive drilling schedule back then. It had 12 vertical rigs on the ground.

“We were trying to put enough conductor holes in place to keep the rigs busy,” said spokeswoman April Crane.

In some cases, wells were started just to meet requirements mandated in mineral leases, which have an expiration date unless there is activity on the site.

When gas prices plummeted and the state passed the impact fee, Talisman retreated.

The company cut down to one rig for the Marcellus region and decided to abandon 147 wells by the end of last year, in part to avoid fees that were required for three full years before a non-producing well would be considered inactive and exempt from the impact fee.

Talisman had, by far, the most plugged unconventional wells, but other operators had the same idea.

Texas-based Anadarko Petroleum Corp. cut its Marcellus rig count from 21 to 13 in 2012. It ended up plugging 88 wells, the second highest among Marcellus operators.

The 2012 impact fee was $50,000 for the first year of a well. In 2013, it was was $45,000 for the first year and $35,000 for the second.

Mr. Jankura guessed that most of the unconventional wells plugged in the eastern part of the state belonged to the same category — wells with just the conductor pipe set in anticipation of further drilling but abandoned because keeping them around waiting until gas prices rebounded would have meant paying the impact fee.

In a few instances, Marcellus wells were plugged after mechanical failure, Mr. Jankura said. “One of the common things that could happen during the frack job [is] the connection of the pipe could break,” he said.

Or there could be a crack in the cement casing.

That was the case with several Cabot Oil & Gas wells in Dimock Township, Susquehanna County. The DEP began investigating the cause of gas migration in Dimock and linked the contamination to Cabot’s wells, although the company continues to disagree with that finding.

Nevertheless, Cabot — calling three such wells “unviable” — decided to plug them in 2011. According to public filings, it paid $2.1 million to do so, at an average well cost of $700,000.

A more typical plugging cost for an unconventional well is around $100,000, according to DEP and industry estimates. It involves setting cement plugs where the well comes in contact with oil, gas or water, and spacing the plugs with bentonite gel, to reduce costs.

While Marcellus operators often say that shale wells will produce for decades, they may not be economic for that long. When the cost of maintaining the well outstrips the value of its bounty, operators will either plug it or sell it to a smaller company, according to Austin Mitchell, a researcher at Carnegie Mellon University who studies well plugging economics.

For some Marcellus wells, that time has already come.

Range Resources Corp., the Texas-based operator that was first to the scene of the Marcellus and drilled its first unconventional well here in 2003, has plugged 62 wells so far.

“It’s a combination of operational and technical [reasons],” said Matt Pitzarella, a spokesman for the company. “Almost all of the vertical [plugged] wells, they were test wells.”

In 2011, Range drilled a horizontal well in Donegal Township, in Washington County, which produced a decent amount of gas and natural gas liquids. The company plugged it just two years later because Range developed newer, more productive wells nearby.

“We’re drilling them better, completing them better,” Mr. Pitzarella said.

The cost to maintain a well, including inspecting it, sometimes means it’s not worth keeping an older, less productive well active. If the company already has recovered its development cost and broken even, it might plug an older well, he said.

“It’s almost always because you have a more efficient multi-well pad nearby,” he said.

There are also other factors.

“We might have been trying a new area. We may have been testing a new technique and it wasn’t optimal,” Mr. Pitzarella said. “Or we may hit a fault.”

First Published March 3, 2014 4:38 PM

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