What Lies Beneath

Almost 100,000 spent oil and gas wells litter Alberta. Who will pay the clean-up cost?

By Doug Horner

Tony Bruder and Ron Schmidt get on either side of the six-foot boards as I crouch down to get a better look. The two Pincher Creek-area neighbours shuffle the weather-beaten wood aside, revealing a square, concrete tub embedded in the prairie grass. We’re peering into the tail end of Alberta’s conventional oil and gas industry: an abandoned oil well. As the industry plowed forward over the past 80 years, it left more than 100,000 such well sites in its wake. 

“A little bit of water comes off the site,” says Bruder, gesturing to the base of a nearby fence, the Rocky Mountains looming beyond. “The cows won’t drink the water. They’ll walk to the other corner of the field to drink. There’s something in it they’re not liking, there’s contamination. I have no doubt in my mind.”

I move in for a closer inspection, and an acrid, engine-oil smell wafts out of the hole. I can make out a gauge flecked with grit and fastened to a steel cylinder heavily knuckled with bolts. Only the first foot of the valve stem is visible, the rest is obscured in murky water. 

Drilled in 1959 by British American Oil, and owned by three companies since, 09-10-004-29W4 is just one of the approximately 400,000 wells the oil and gas industry has sunk in Alberta since the very first, Dingman No. 1, was drilled in 1914 just outside Turner Valley. Those four designators comprise a well site’s name and point to its geographic location. Although useful, the official name can be a little cumbersome, so from here on let’s refer to 09-10-004-29W4 as simply “Pinch.” The site is part of the Pincher Creek Field, the first sour gas field in Alberta, and so the nickname fits. Also, the well hasn’t seen any activity since Husky Energy inserted a concrete plug deep into the casing back in 1995, effectively sealing or permanently “pinching” the well shut.

The land we’re standing on has been in Bruder’s family since his grandfather, Anton Bonertz, was the first of three brothers to move up from Nebraska in 1907. Bruder says his grandfather never would’ve signed the lease for Pinch in the 1950s if he’d had any notion of the trouble that would visit his grandson some five decades later. In 2007 the surface lease on Pinch expired and set in motion a battle between Bruder and Pennine Petroleum, the well site’s current licensee. In the early days of an escalating feud, Bruder reached out to the Alberta government and its regulatory bodies for help. However, it wasn’t until the Environmental Law Society put Bruder in touch with Barry Robinson, a lawyer with Ecojustice, that some sort of resolution became possible.

“You phone the ERCB and they say, ‘that’s not our jurisdiction, phone the SRB,’” says Bruder. “And you phone the SRB and they say, ‘that’s not our jurisdiction, phone Alberta Environment,’ and Alberta Environment says, ‘that’s not our jurisdiction, phone the ERCB’.” Bruder’s handlebar moustache bristles along with his contempt. “And you just keep going around in a circle.”

The not-so-merry-go-round Bruder describes is Alberta’s oil and gas regulatory system. The citizens of Alberta own about 80 per cent of the province’s mineral rights, and the Energy Resources Conservation Board (ERCB) is mandated to ensure that those resources are developed in the public interest. The ERCB, an independent, quasi-judicial government agency, is both coach and referee to the resource industry, and is funded primarily through a levy on each oil or gas well in the province. Barry Robinson, who was an environmental consultant for 15 years before becoming a lawyer, argues that the ERCB is too close to the industry it regulates and that environmental and social impacts are consistently overlooked. “Their mandate is to protect the public interest, but the ERCB operates as if their mandate is to protect industry’s interests,” he says.

Because Alberta’s mineral deposits belong to its citizens, most landowners don’t have the right to refuse access by a resource company. If a lease agreement cannot be reached between an oil company and a landowner, the Surface Rights Board (SRB) steps in to mediate. Once an agreement is reached, landowners are compensated in the form of annual payments, paid by the company with the licence to extract. 

 The ERCB supervises the life cycle of wells such as Pinch from birth until death, or from “spud date” right through to abandonment (which means sealing the well in a permanent and secure condition). Ideally, well sites in Alberta are not forgotten after abandonment. Officially they have an afterlife, which begins when Alberta Environment (AENV) steps in to oversee their journey through remediation and reclamation (unless the well is on Crown land, which is the Ministry of Sustainable Resource Development’s jurisdiction). 

“Reclamation” entails restoring the land to its original state. If the site is contaminated, the reclamation process requires “remediation,” or, simply, the cleaning up of pollution. The process can take several years and cost millions of dollars, depending on the area’s ecology, its proclivity for revegetation and the amount of pollution. Once a company has reclaimed, they apply to AENV for a reclamation certificate—proof to citizens and the landowner that the land is back to the way it was.

As of January, the ERCB estimated the total cost to reclaim all existing wells, facilities and pipelines in Alberta at approximately $21-billion. In theory, the oil and gas industry adheres to the adage that the company that makes the mess has to clean it up. In the absence of strict regulatory timelines, however, companies are allowed to procrastinate; some of that $21-billion liability includes sites that have been ignored for over 25 years.

Pinch was downhole abandoned in August 1995, and yet the wellhead still marinates in its watery, concrete abode. Tony Bruder doesn’t know when it will be remediated. Alberta’s regulatory system may have all the pivotal moments of a well’s life cycle covered, but it doesn’t set deadlines by which those transitions must take place. 

Pinch is not alone. According to AENV, at the end of 2009 over 45,000 wells have been abandoned in Alberta but not certified as reclaimed. Pinch is one of almost 13,000 wells that have been abandoned without reclamation for longer than 10 years. On average, over the past decade, AENV has issued reclamation certificates for fewer than half of the wells that are abandoned each year. In short, the gap between the number of wells sealed and the number actually cleaned up is steadily widening. Meanwhile, roughly 60,000 wells are just plain shut off or “inactive,” neither producing nor permanently sealed.

While helping Bruder in his standoff with Pennine, Barry Robinson became increasingly concerned about the dearth of legislated timelines for abandonment and reclamation. “The longer wells sit, the fuzzier the records get,” he says. “And the longer wells sit, the more likely that if there’s underground contamination—and quite often there is—it moves off site.”

Contamination generally consists of hydrocarbon or saltwater spills. Most oil spills don’t migrate very far and are easy to remediate because they biodegrade or can be treated chemically. Lighter, carcinogenic hydrocarbons such as benzene, however, can filter into groundwater. Saltwater spills are particularly dangerous because they can grow exponentially. Extremely salty water, up to 100 times more saline than seawater, emerges from deposits along with oil or gas. Chlorides from saltwater don’t bond with soil, and so, if spilled, move freely through sediments along with runoff and groundwater. A buildup of chlorides can ruin an entire aquifer, making it undrinkable for humans, as well as useless for irrigation and livestock. Sodium molecules bond tightly to soil particles and cause clay dispersion (or “soil dehydration”); the only way to reclaim such soil is to replace the entire affected area. The longer contamination from a well site is left, the more damage it does.


A well site location with runoff flooding the lease land. (Photos Courtesy John & Colleen Aplin of the Alberta Surface Rights Federation) 

Provincial regulation requires that wells be inspected regularly and sets criteria for the reporting and remediation of leaks and spills. But environmental damage isn’t always obvious, and remediation is complicated by the fact that many suspended wells in Alberta were drilled during a time of environmental obliviousness. Bruder, for example, says his father remembers British American Oil mixing the chemicals they used to lubricate Pinch’s drill bit in a big hole in the ground, something the industry called a “mud sump.” The sump overflowed during a heavy rain in 1959, and the chemical-infused mud washed toward the coulee to the south of the lease. This is just one of the hazardous but standard industry practices that took place in Alberta right up into the early 1990s, when the first federal and provincial environmental legislation began to get traction. 

Rob Stansland, a former environmental biologist, worked for Talisman Energy’s reclamation and remediation department. While his job concerned the cleanup of old wells, he points out that most inactive wells are considered assets, not liabilities, especially since the ERCB instituted stricter regulation around inactivity. As of 2004, if a well has been inactive for longer then 12 consecutive months, it must be temporarily sealed, or “suspended,” by lodging a steel plug deep into the well casing. “‘Inactive’ now means the well is officially suspended,” says Stansland. “The wellbore itself is safe.”

Inactivity is not so risky anymore, he argues, adding that it’s actually useful because old wells can be connected to future pipelines or become viable again as energy prices rise or technology changes. Carbon capture and storage, for example, depends on accessing porous rock formations to trap greenhouse gases, a task that an inactive but not abandoned well can accommodate. Everyone loses if companies abandon prematurely, Stansland says, because there’s no going back in. “So that’s just lost revenue to the province,” he says. “It’s gone at that point.”

Despite these arguments, the ERCB has been concerned for over a decade about Alberta’s languishing wells. In July 1995, just a month before Husky pumped Pinch full of cement, the ERCB sent a letter to every oil and gas operator in the province warning about the 12,000 wells that had been inactive for more than 10 consecutive years.

“Many of these wells appear to have little economic value and may pose an increasing risk to the public and the environment,” the letter said. “The care and attention directed to these wells has traditionally been less than that afforded to a producing well.” 

The ERCB’s mandate is to protect the public interest. But it operates as if its directive is “protect industry.”

In November 1997 the ERCB attempted to force timelines on Alberta’s oil and gas industry with the launch of the Long Term Inactive Well Program. Companies were given five years to abandon, sell, put up a deposit or reactivate any well that had been inactive for 10 or more years. Robinson, an environmental consultant at the time, remembers industry kicking hard against the tightening of the regulatory screws. “Their response was that it was too financially onerous,” he says. “They said it was a liability management question, not an environmental question.” 

In 2000, facing pressure from industry, the ERCB rescinded the Long Term Inactive Well Program and replaced it with an expansion of two pre-existing regulatory mechanisms: the Licensee Liability Rating Program (LLRP) and the Orphan Program. 

Stansland remembers what prompted these programs’ inceptions back in the mid-1980s: a particular breed of oil and gas company called a “stripper” operation had been striking fear into the hearts of regulators, landowners and industry alike. “Guys had figured out a way to structure a business so that they could basically run facilities dry and then walk away,” says Stansland. “The company would be liable but there be would be nobody and no assets associated with it.” These unscrupulous profiteers begot Alberta’s first “orphan” wells—well sites with no productive value and no traceable owner.  

Industry stepped into the regulatory vacuum, creating the first incarnation of the Orphan Program in 1986. “Ordinarily it wouldn’t be industry [taking charge], but we thought ‘you know, it’s a lot easier for us to just take the liability and try to guide the regulator forward,’” says Stansland. “This way, the regulator doesn’t have to get frantic and try to be too sophisticated, because at the end of the day the only one who loses if we do it wrong is the oil industry.” 

If an oil company goes bankrupt and the ERCB cannot trace responsibility for its sites to another operator, the wells are designated “orphaned” and become wards of the Orphan Well Association (OWA). This industry-run, non-profit organization manages the abandonment and reclamation of all oil and gas infrastructure that slips through the cracks. The cleanup is paid for by an annual levy raised by charging each operator according to their proportion of the total industry liability. 

Collected by the ERCB on behalf of the OWA, the levy can be seen as a proactive industry initiative that protects the citizens of Alberta. But it can also be seen as a bargain: the levy raises $12-million in an average year, which, when divided across all of Alberta’s oil and gas infrastructure, works out to less than $50 per site (recall that Alberta’s estimated total liability from the conventional oil and gas industry is $21-billion). And while it’s true that industry took responsibility for their failed competitors, in doing so they also got to take the regulatory reins: companies remain free to abandon and reclaim wells when they want. 

For their part, government says potential liability issues are addressed by the LLRP, which was created to minimize the number of sites that become orphaned. As part of the LLRP, the ERCB assesses the financial health of every licensee monthly. If an operator’s assets dip below their liabilities, they must put up a deposit to make up the difference. An operator’s assets are calculated by measuring their production capacity; their liabilities are the sum cost to abandon and reclaim every well site and facility they own, whether active or inactive. The ERCB assigns all oil and gas infrastructure in Alberta a liability based on the cost to abandon and reclaim the site. These costs are based on regional averages. According to a 2005 ERCB report, reclamation costs per well site vary between $13,000 and $33,000,
depending on the area’s geography. 

Industry controls the regulatory reins. Companies are free to abandon wells when they want.

Stansland says he noticed a shift in how companies managed and perceived their liabilities after the LLRP’s implementation. By assigning a monetary value to abandonment and reclamation, oil and gas companies could no longer treat environmental impacts as externalities. Stansland says the LLRP forced liabilities onto companies’ financial records, and shareholders began to witness the costs associated with cleaning up. “When I left in 2007, Talisman had an aggressive reclamation and abandonment program,” he says. 

Robinson, though, argues that the buildup of unreclaimed well sites in Alberta is evidence that the LLRP has failed. He also notes that liability values based on regional averages drastically underestimate cleanup costs and in most cases do not account for the possibility of contamination. This gives operators a disincentive to tackle the big, expensive messes—sites such as Pinch that were drilled when the industry was doing a lot of “learning on the fly.” The only incentive for a company to reclaim, argues Robinson, is to escape the annual payment owed to the landowner. And while the annual rent under a lease can be a few thousand dollars, remediation of a severely contaminated well site can cost up to $10-million. In a regulatory environment where all cleanups are treated equally, the LLRP program assesses companies on the quantity and not the quality of sites reclaimed.

CAPP vice-president David Pryce, Rob Stansland and the ERCB representatives I spoke with all expressed incredulity that the public would be concerned about the number of unreclaimed well sites in Alberta. “If somebody’s concerned, they need to consider that industry holds the financial liability,” says Pryce. Industry argues that none of the $21-billion liability will fall to citizens, because the LLRP ensures that only financially robust companies operate in Alberta. Should anything go wrong, the Orphan Program exists to clean up the wells that become ownerless. Right now, that’s a fraction of the total number of wells in Alberta. Last year, for example, 44 orphan sites received reclamation certification, and as of December 371 remained.

But oil and gas well reclamation is progressing at a much slower rate than abandonment. The result is an ever-expanding buildup of unreclaimed wells, a situation AENV itself describes as “deteriorating.” Add to this the fact that nearly 14,000 new wells are drilled every year. The volatility of the oil and gas industry further tempers whatever reassurances the LLRP and OWA provide. 

And citizens are contributing to the cleanup cost. In 2009 the Government of Alberta injected $30-million into the Orphan Program because of the recession, part of a stimulus strategy to keep oil service companies in business. Robinson says this lump sum government funding is a foreshadow of what’s to come as production continues to decline and operators have less and less money for reclamation.

Section 144 of Alberta’s Environmental Protection & Enhancement Act was created to protect landowners from oil and gas operators wanting to terminate leases without first reclaiming the wells. Bruder says when the 50-year lease on Pinch expired in 2007, Pennine reversed the section’s meaning and argued the lease could not expire until the company chose to reclaim.

It was a stalemate, with Pennine refusing to budge and Bruder refusing to accept that Pinch could continue to exist indefinitely, all the while possibly polluting his land. “If it wasn’t for Barry Robinson, I’d still be trying to get these guys on the phone,” says Bruder. After giving up on Pennine and on Alberta’s energy regulators, he and Robinson went to the Alberta Court of Appeal to force the issue. In a Lethbridge courtroom in spring of 2009, sandwiched between a divorce hearing and a child custody case, Justice D. K. Miller heard the case and ruled that the lease had in fact expired, that Pennine had misconstrued section 144.

In January 2010, Bruder and Pennine signed an agreement that sets a new precedent. Written into the contract is a strict timeline for reclamation and remediation. If after any consecutive five-year period there’s no activity at Pinch, the company must immediately begin to remediate and reclaim. If these conditions are ignored, Pennine will have broken the contract and Bruder can take them directly to court, bypassing Alberta’s reluctant energy regulators.

As we replace the boards over Pinch, I wonder aloud when its valve stem will next see the light of day. Bruder is not optimistic. He senses another showdown brewing. “When it comes time, and there hasn’t been any activity on this site, I expect us having to go back to court,” he says. 

Beneath the boards is a hole initially drilled to a depth of 3736 m below the earth’s surface, deepened in 1964 to almost 5 km and then converted into a disposal well. Pinch has had over a million cubic metres of salt water injected through its well casing. The oil and gas industry is certainly ingenious when it comes to extracting resources, but—perhaps not surprisingly—it hasn’t devoted quite the same energy to remediating pollution or restoring the land. Regulators must balance private enterprise’s profit motive with clear rules that protect the public interest. Without a referee willing to blow the whistle, Alberta’s oil and gas industry has been given the room to choose when and where it cleans up.

There are now 100,000 unreclaimed well sites in Alberta, one quarter of all the wells ever drilled in the province. This number doesn’t include the pipelines, batteries and facilities that accompany each well. And even if the LLRP is working, which Robinson argues it isn’t, there’s no motivation for companies—other than their own goodwill—to clean up older sites that were drilled when there was little understanding of environmental impacts. Some of the industry’s “old dogs” continue to limp on today. If they’re contaminated, that pollution is spreading.  

Doug Horner graduated from the University of Calgary in 2009 and recently completed an internship with Alberta Views.


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