Pennsylvania faces a new wave of abandoned oil and gas wells
HIGHLAND TOWNSHIP, Pa. — Ten thousand acres of Pennsylvania’s only national forest have given way, tree by tree, over the last 70 years to an oil drilling operation unique in its scope in the northeastern United States.
A network of wells, tanks, pipelines, pump houses and roads grew into the shape of an italic L cut into the Allegheny National Forest in Elk County to harvest $350 million worth of oil. The lower leg is nearly 6 miles long; the upper one roughly 9 miles. The imprint is visible by satellite.
What worries state and federal environmental regulators isn’t the project’s growth but its death.
Last year, the company that owns the field — Kane-based ARG Resources — quietly shut it down. The company didn’t have the money to run the operation — let alone plug and decommission its 1,600 wells, dozens of buildings and tanks and roughly 150 miles of roads.
“There was just one guy left working there, and he wasn’t working there anymore,” said Scott Perry, Pennsylvania’s head oil and gas regulator.
Although the ARG Resources’ operation is unusual in many ways, Pennsylvania Department of Environmental Protection officials see it as a harbinger of a troubling trend. Mr. Perry calls it “the looming crisis.”
A staggering drop in oil prices is threatening to cause a cascade of abandoned wells across Pennsylvania’s traditional oil and gas industry.
There are already roughly 200,000 orphaned wells dotting the commonwealth — abandoned by their owners over a century of drilling. For most of that time, fully sealing off expired wells wasn’t required.
Each abandoned well is a risk, although the danger depends on age, decay and proximity to people. They can channel gas and oil to the surface, pollute streams and drinking water, create explosion hazards when gas seeps into homes and emit climate-changing gases.
Very little money has been allocated for finding and plugging the old wells. Last year, DEP received about $1 million to fund the work. It is sealing abandoned wells at a rate of fewer than a dozen per year.
At that pace, it will take 17,500 years and about $6.6 billion.
The overwhelming scale of the problem has made DEP officials more determined — and creative — to prevent new abandonments. In the Allegheny National Forest, the state is trying to find a way out by giving one high-minded entrepreneur a chance to clean up where another’s grand plans are crumbling.
The unorthodox agreement with a Canadian businessman would use ARG’s forest footprint to help solve the problem — by making products from other oil and gas operators’ salty wastewater. A portion of sales from the new company, AquaPower Chemicals, will go toward plugging wells that ARG has retired.
The project’s outlook is increasingly uncertain as oil demand collapses amid a global public health crisis. But new solutions may be even more vital now that oil prices are at the lowest level in decades.
Mr. Perry, citing psychology’s prospect theory, said when you’re in a losing position, you are more willing to take a chance on a long shot.
“There is no risk to us because we’ve already lost,” he said.
‘The looming crisis’
ARG began as part of a rescue plan.
The drilling company ARG Resources is a subsidiary of American Refining Group, which operates a refinery in Bradford turning Pennsylvania sweet crude into specialty lubricants.
Harry Halloran Jr., a self-described “philanthrocapitalist,” salvaged the refinery in 1997. He bought the building for $1 to keep it from being torn down, according to an article in The Kane Republican newspaper.
Mr. Halloran has given millions of dollars to charities and to his own foundations, which focus on grants to entrepreneurs and organizations. He has commissioned books on the topic of corporate responsibility and human well-being, believing that good business practices — and good business — can solve many of the world’s problems.
Some 20 years ago, during a time of rising crude oil prices, Mr. Halloran started ARG Resources to supplement the feedstock needed for the refinery.
The plan worked for more than a decade. But with prices for oil and gas in a trough for the past five years, it became difficult to justify the cost and effort to keep pumping the wells.
That pain spread across a fragile industry.
Pennsylvania has over 100,000 active conventional wells. Some have been producing puffs of gas or buckets of oil since William McKinley was president.
These kinds of wells sit on much smaller gravel pads than the factory-style sites required by modern shale gas drilling and fracking. Most are in the woods and fields of Western Pennsylvania, ubiquitous but unremarkable as cows.
Intensifying the price squeeze, two relatively low-cost but environmentally damaging options for disposing of the wells’ wastewater — spreading it on dirt roads and sending it to municipal sewage treatment plants — have largely been cut off.
Even before the recent price collapse, Mr. Perry feared the conditions for “a mass abandonment of wells” were already here.
Pennsylvania requires well operators to permanently seal their wells when they are done producing them, but it does not require them to demonstrate that they have the money to pay for that work. Too often, they don’t.
“My analogy is, your parents told you to save money when you were a kid,” said Richard Neville, DEP’s northwest district oil and gas manager. “The government doesn’t require you to do that. So you start to live your life and the next thing you know you’re 40 and you haven’t saved anything.”
Oil in the forest
ARG Resources bought its position in the Allegheny National Forest in 2001 after earlier operators in the field — Warren-based Pennsylvania General Energy and Pennzoil — had already drilled more than 1,300 wells since the 1950s.
The companies recovered oil from the 2,200-foot-deep Kane Sand using a method called a water flood. Oil doesn’t flow freely to the production wells here after the initial rush, so a mixture of freshwater and the oilfield’s brine is pumped down special injection wells. That frees the oil and flushes it toward production wells.
The project is located in the middle of a national forest because the surface land and the buried oil have different owners. Courts have ruled the right to extract the oil overrides the right to preserve the forest, even when the surface landowner is the federal government.
ARG Resources drilled 420 wells in the decade and a half after it took control of the field — plugging wells behind it as it explored the boundaries of the buried reservoir. When oil prices climbed, its corner of the forest became a little city.
“Ten years ago … there were people, cars — this place was just booming,” said Steve Lencer, a DEP oil and gas inspector supervisor for the northwest region.
In 2014, ARG drilled 24 wells through the end of August. Then it stopped abruptly. It has not drilled another well since.
By the following year, the depth of the company’s trouble was obvious.
A 2015 presentation prepared by DEP oil and gas supervisor Chad Meyer noted ARG Resources’ costs to produce a barrel of oil were $46, above the selling price at the time.
“At current oil prices, ARG is breaking even at best and any further drop in price will cause them to lose money on every barrel of oil produced,” he wrote.
“We may not have much time to come up with solutions.”
In slides charting the company’s years of healthy revenues, Mr. Meyer made clear that the plugging and restoration costs should not have been insurmountable. He calculated that ARG Resources had likely earned $225 million before expenses on the oil and gas pulled from the field since buying it in 2001 — more than enough to clean up the company’s messes.
Since 1991, gross earnings for the field were probably $345 million across the three operators, he said, not counting the peak production years between 1974 and 1990 for which DEP has no data.
“The taxpayers should not be on the hook” for the cleanup, he concluded.
The company had posted a $200,000 bond as part of an agreement with DEP over well plugging in 2012. But as oil prices continued their slide, ARG began to fall farther behind.
In November 2017, ARG Resources’ general manager James Bolinger alerted the U.S. Environmental Protection Agency that the company did not have the money or manpower to correct leaks at 24 of its injection wells in the field by an EPA deadline.
If it couldn’t finalize a deal with AquaPower Chemicals “in the very near future,” he wrote, the company would be forced to shut down.
While the Pennsylvania DEP has primary authority for regulating production wells, the federal EPA has primary authority for injection wells — an arrangement that carries an additional benefit in this case because federal rules required ARG Resources to set aside $1.8 million for plugging its injection wells.
By February 2019, with a deal still not signed, an attorney for ARG Resources told EPA that it was in a “dire financial condition” and couldn’t comply with the agency’s mounting orders. Although the company had repaired or plugged many of the wells EPA had ordered it to fix, it was shutting down its operation without addressing nearly 60 more.
Most of those are wells that ARG had already paid to plug once, but it turned out its contractor did not complete the job. He was sentenced to jail for six months for falsifying records, but the company was forced to replug wells that had been sealed off only halfway.
Mr. Bolinger said in an interview in March that oil prices would have to be above $80 per barrel to make it profitable to operate the wells while keeping up with the cost of the company’s state and federal environmental obligations.
Oil has not been above $80 per barrel since 2014. On Tuesday, American Refining Group’s posted prices for Pennsylvania Grade Crude ranged from $14 to $19 per barrel.
“I believe every well in the state is uneconomical at this price,” Mr. Bolinger said. “We’re not gonna be the only people with this problem.”
Looking for solutions
In November, the oil field was quiet. Snow dusted the still pump jacks.
Because crude oil and brine weren’t flowing through the idled network of old underground pipes, the operation’s primary environmental hazard had subsided. When the field was pumping, ARG Resources was regularly working to clean up spills from broken pipelines, Mr. Neville said. It left nine spills unresolved when it shut down.
Mr. Perry, DEP’s oil and gas chief, stood on a gravel pad that had been carved into a hillside near a pile of pipes that was topped by an overturned cooking grill.
A rodent had turned a broken production measurement tool into a nest. A pump house down the hill held three machines the size of lawn mowers and a warning on the door that toxic hydrogen sulfide gas might linger inside. The door had been left unlocked.
“Goodwill is not going to get this running,” Mr. Perry said.
DEP had few good options. It could have launched a lengthy and expensive legal effort to extract plugging money from American Refining Group or some other ARG-related entity, which may or may not have worked.
So in late January, DEP signed a consent order with ARG Resources — now renamed Resources Preservation — and AquaPower Chemicals that is part enforcement tool and part revenue-sharing arrangement.
AquaPower, whose Pennsylvania address is a UPS box in a strip mall in Pine will rent its proprietary brine water cleaning technology to oil and gas producers in Pennsylvania. Once their wastewater runs through those units to remove hazardous waste, such as radioactive metals, AquaPower will truck the brine into the Allegheny National Forest.
There, it will run a new facility on ARG’s property that will turn the brine into two products: commercial salt, most of which will likely head to Canada, and synthetic gypsum for use in wallboard and in agriculture.
The chemical company will buy natural gas from ARG to run its boilers, and ARG will buy chemicals from AquaPower to add to its injection fluid.
Those two benefits are complementary to the main attraction of the deal — the revenue-sharing arrangement, Mr. Bolinger said.
For every gallon of brine water it collects from oil and gas drillers, and for every pound of salt products it sells, AquaPower will kick a portion of the proceeds to ARG and another portion to an escrow account up to $17 million — the estimated full cost of plugging and restoring the field.
The deal is signed, Mr. Bolinger said, but cannot close until AquaPower makes two deposits: one to ARG, and the other to kick-start the plugging account with $300,000.
The DEP agreement called for the money to be deposited by March 13, but it wasn’t.
Glenn Vanderlinden, a Canadian entrepreneur who runs AquaPower, said in an email that his development plans have not changed but may be delayed an extra four to six weeks “due to virus-driven logistics and labor constrictions.”
“If anything, the lower energy prices just reduce our cost to recover the products we are after,” he said.
He’d been trying to get into the Pennsylvania oil and gas water treatment game since the Marcellus Shale rush began. A previous venture, called AquaPower Energy Services, fizzled early in the decade with no contracts. The financial model didn’t work at the time, Mr. Vanderlinden said.
ARG’s situation held the potential for AquaPower to bring several of its services — equipment rental, chemicals, project management — into one project with a high-minded mission.
“Basically, you’re making the project pay for the solutions that no one has any money to pay for,” Mr. Vanderlinden said.
The agreement requires ARG to return at least 60 of its wells to active production by the end of 2020 and submit a plan next year for plugging or producing the rest by the end of 2027.
If it works, Mr. Vanderlinden hopes it could be a model for abandoned well management across the country and abroad.
DEP officials are rooting for him. The agency said it will warn AquaPower about missing the payment deadline, but will be flexible given the sweeping economic shutdown associated with COVID-19, a spokesman said.
All the other strategies in the regulators’ toolkit for plugging abandoned wells amount to “just little slivers of impact,” Mr. Perry said, compared with a viable conventional industry paying to plug its own wells.
Success here might buy regulators time to advocate for new solutions.
“The problem is only going to get worse. It is not going to get better,” Mr. Perry said. “We’ve got over 100,000 active conventional wells, and I don’t know how much longer folks are going to hang on to them.”
Laura Legere: firstname.lastname@example.org and Anya Litvak: email@example.com or 412-263-1455.