Sticking out like a sore thumb in the otherwise bucolic, rolling pastures and fields of hay, sit four rusting oil tanks, “Out of Service” stenciled on their sides, along with a scattering of other weathered and unusable equipment.
For the better part of three years, Jon and Susanne Stephens have, without success, been trying to get Noble Energy to plug four wells the oil company has “temporarily” abandoned and remove the defunct equipment and underground flowlines from their land.
The wells haven’t produced any oil or gas since 2017 and Noble says it will at some point remove the equipment from the fields near Milliken, in Weld County, and plug the wells. “We will notify you when this activity is eventually scheduled,” the company, which is now part of Chevron Corp., told the Stephenses’ attorney in an email.
“When I was living in Iran, this was around the time of the fall of the shah of Iran, they had a saying he’d take the milk and leave the cow,” Jon Stephens, 83, said. “That’s how I feel about the oil companies. They take what they want and leave us to deal with the rest.”
Low-producing and inactive wells, such as those in Stephenses’ fields, stipple Colorado and are a major focus of rulemaking to ensure there are enough operator funds to plug and remediate all of the nearly 52,000 oil and gas wells in the state.
In 2020, there were 17,196 inactive wells – producing less than the equivalent of 1 barrel of oil a day, including 9,585 wells that produced no oil or gas at all. There were another 8,538 low-producing wells with an output of between 1 and 5 barrels a day, according to state data.
Together the two categories – which were defined in a draft state rule – account for almost half of all the wells in Colorado.
“This rulemaking is unmasking a problem that has been silently growing for decades,” said Kate Merlin, an attorney with the environmental group WildEarth Guardians. “Operators have neglected their old wells, and left them open and idle rather than pay to clean them up and plug them.”
More wells are being plugged than are being drilled
A prime goal of the rules being developed by the Colorado Oil and Gas Conservation Commission is to make sure there are adequate bonds posted so that if an operator goes bankrupt or disappears the state has the funds to plug and remediate these “orphan” wells.
Industry representatives caution, however, that this is a misreading of the situation and that many shut-in and temporarily abandoned wells are closed when oil prices are low, for maintenance or for safety when new wells are being drilled in the area.
Companies are now plugging more wells than they are drilling. Between 2015 and 2020, 8,104 wells were drilled in Colorado and 9,902 were plugged, according to industry statistics.
“The current situation in Colorado is improving within the existing system,” API-Colorado, an industry trade group, said in comments to the COGCC. “Colorado is well positioned to deal with the orphan wells.”
Even the low-producing wells have economic value, yielding a small but steady stream of oil and income year after year, according to Sam Bradley, a spokesman for the Small Operator Society, an industry trade group. “They just keep truckin’ along.”
Still, the COGCC was mandated by Senate Bill 181 – the 2019 law that transformed the commission’s mission from promoting oil and gas development to protecting public health, safety and welfare – to beef-up the financial assurance rules.
The commission initially drafted a rule that would have required a $78,000 plugging and clean-up bond for each well, compared to the current $10,000 to $20,000 per well. The agency has since recalculated the average plugging and clean-up cost at nearly $93,000.
Every company would also pay $200 a well into an orphan well fund, raising about $10 million a year.
Under lobbying from the industry the draft rules were scrapped and turned into a “strawman” for discussion by oil companies, local governments, and environmental and community groups.
“The proposal would have created the most expensive financial assurance rules in the country for a state that has among the fewest orphan wells in the country,” said Dan Haley, president of the Colorado Oil and Gas Association, an industry trade group.
New draft rules are set to be issued at the end of August with hearings early next year and final adoption in April 2022.
The goal, COGCC chairman Jeff Robbins said, is “better financial assurance without creating unintended consequences and adding orphan wells … Getting the balance right is really, really important.”
The commission has, however, already identified what may be lurking problems that need to be addressed by increased financial assurance.
A 2018 commission task force said some operators have maintained “active” status for wells through the ploy of “selling past production from leasehold tank inventory or by ‘swabbing’ the well to extract and sell a small amount of fluid product each year.”
The commission also has found transfers of wells to new owners involving a large number of low-producing wells “are likely to result in higher risks to the public of the new operator orphaning the wells.”
Slow clean up keeps owners of Weld County land from selling for development
Traveling the Front Range and Eastern Plains the nature of Colorado oil and gas wells unfolds as a complex pattern that contains derelict drillers, bankruptcy and orphan wells, the clash of suburban home building and drilling, but also robust plugging programs by some companies, and profits and royalties being squeezed from even the most modest of wells.
The tale is different in the farm fields out near the Nebraska border than in the quickly rising subdivisions in communities like Broomfield, but the new financial assurance rules must encompass them all.
One provision in the draft rules tried to address the Stephenses’ problem by requiring a company to get its shut-in and temporarily abandoned wells back in production within six months or increase the bonds on them or put them on a list to be plugged within three years.
API-Colorado supports the idea of a plugging list. Texas has one, said Carrie Hackenberger, the group’s associate director, although a three-year time frame may be an issue.
Jon Stephens remains vexed by the proposal. “The farmer is left waiting three years, maybe more, after already waiting years,” he said. “We just want the return of our farmland.”
In 1921, Susanne’s grandfather Frank Spomer – one of a wave of German Russian immigrant farmers who spread out across the Midwest and West in the late 19th and early 20th centuries – bought the cropland outside Milliken.
The mineral rights on the land, however, were owned by the Union Pacific Railroad. The railroad had sold off the surface but held on to the minerals, as is allowed by Colorado’s split-estate system.
It was another 85 years before somebody showed up to tap those minerals. By that time Susanne, 84, who had grown up on the farm, owned the land, but Noble Energy, one of the biggest operators in Colorado, held the oil and gas rights.
In 2006, Noble started drilling on the property. The Stephenses had no choice. Under Colorado law a landowner cannot deny a mineral owner access.
Noble paid $27,500 for surface damage on the 160 acres of irrigated fields as it drilled five wells and laid underground flowlines to carry oil to a four-tank battery that also included a heat separator and two concrete water storage tanks and took up about two acres of the land.
“The wells were drilled over a period of a year,” Jon Stephens said. “The fields were torn up for months. We were dealing with erosion problems.”
Then in 2017, Noble pulled some, but not all its equipment, and listed the wells as temporarily abandoned.
A temporarily abandoned well is one where equipment has been removed and a temporary plug put in place. A shut-in well is one where the valves have merely been shut off. There are about 8,100 shut-in wells and 2,700 temporarily abandoned wells in the state.
In 2019, Noble plugged one of the Stephenses’ wells but did not clean up the site, Jon Stephens said.
This has left the Stephenses in limbo. The land is currently leased to a neighboring farmer, but the option of selling it, especially for development, is limited because of the unplugged wells and flowlines running through the property.
This is a problem that plagues landowners and developers across Front Range oil country. “They keep (them wells) in place to avoid plugging,” said Lance Astrella, an attorney who represents property owners in oil and gas cases. “It is an abuse of property rights. It is probably a trespass case, but most land owners can’t afford to file a lawsuit.”
Low-producing wells, even if uneconomical, are also used to hold on to leases, which require an operating well, Astrella said.
Noble, when asked by The Sun about the Stephenses’ wells, said they are scheduled to be plugged late this year or early next. “That’s not my information,” said Matt Sura, the attorney representing the Stephenses.
All this leaves Jon Stephens frustrated. “We aren’t anti-oil,” he said. “We’re pro-oil, we just think there should be a fair game.”
The economics are fragile, but every little pump jack helps
Richard Jefferson, 63, is one farmer who is happy to have oil wells – 13 bobbing, horse-head pump jacks – on his Eastern Plains’ fields of proso millet and wheat, Washington County land his family has tended for 70 years.
They are all stripper wells, each one yielding no more than 15 barrels of oil or 90,000 cubic feet of natural gas a day. Still, there is a steady stream of royalties. “I get $600 to $800 a month depending on oil prices,” said Jefferson, who unlike the Stephenses owned his mineral rights. “It is not a huge amount of money, but it is cash in the pocket. It helps.”
One of the wells on Jefferson’s land is operated by Impetro Resources, a company with 100 stripper wells, run by Sam Bradley, 37.
“I have to hand it to these young guys,” Jefferson said. “You have to have balls to buy these stripper wells.”
Bradley followed his father, who is a geologist, into the “small” oil business. The elder Bradley “has a passion for vertical wells,” Bradley said. “He chased these assets for years.”
After getting a degree in petroleum engineering from the Colorado School of Mines, Bradley held a string of jobs in the industry, including as an operations engineer for the Navajo Nation Oil and Gas Co., before starting Impetro – Latin for “to succeed.”
While the focus in Colorado has been on the big new, horizontal shale wells – drilled to a depth of 10,000 feet, running as much as 3 miles underground and producing the equivalent of 5,000 barrels of oil a day or more – the majority of wells in the state are stripper wells.
The 29,000 stripper wells make up 56% of all the wells in Colorado, though they accounted for less than 5% of the oil and about 15% of the natural gas produced in 2018, according to the Colorado Office of State Auditor.
These vertical wells, about 4,000 feet deep, are often decades old. Some of Bradley’s wells have been producing oil for nearly 50 years.
“The wells decline at about 2% a year,” Bradley said. “They are bunt singles. You’re not going to get rich, but they are cash positive.”
Six days a week a contractor called a “pumper” checks each of Impetro’s wells, dropping a tape measure into the collection tanks. (There are two oil tanks, an oil-water separator, a water settling tank and a produced water pit supporting Impetro’s pump jack).
When the oil in the tank reaches 10 feet, the pumper dispatches a tanker truck to collect the contents – about 180 barrels to 230 barrels a load.
Bradley pays the pumper $400 a well each month. A pumper can cover 20 to 30 wells and, Bradley said, make a decent living. “It’s one of the better employment opportunities out here,” he said. Impetro also paid $173,000 in county property taxes last year.
Fate of companies running little stripper wells depends on big markets
Yet the economics of strippers remain fragile and their fate is perhaps bound even more tightly to the price of oil on markets like the New York Mercantile Exchange than those of the big oil companies.
Bradley said that out of every barrel of oil sold, about $25 goes to basic operating and compliance costs, $2 go to local taxes (strippers are exempt from state severance taxes), and another $5 goes to the cost of hiring a workover rig for repairs to the well bore.
Royalty payments to folks like Jefferson take another $5 a barrel, while $2.50 goes to debt service and $1.50 to general and administrative costs. The cost of paying trucks and pipelines to deliver the oil is a final $5 a barrel.
“If the NYMEX is below $45, I am bouncing below bottom,” Bradley said, “and when it is above $50, I can start to make a little money and pay off my debt.”
In the depths of the pandemic the spot price of benchmark U.S. oil dropped as low as $16.94 a barrel. It averaged $39.17 for 2020, according to the U.S. Energy Information Administration.
To make ends meet during the pandemic, Bradley laid-off employees, lived in a camper and pumped the tanks himself. Still, he says he almost lost his business.
Oil prices have rebounded and Aug. 20 spot price on the NYMEX closed at $63.40 a barrel.
“The reason guys like me invest in this business is that you can make money in these upswings,” Bradley said. But after last year’s near-death experience, Bradley hedged his output selling a large chunk of his 2021 production in fixed contracts at $45 a barrel. “I am far from flush with cash, but I am financially secure,” he said.
While margins are slim, Bradley said, an evaluation of his portfolio done for a bank by a third-party auditor found that the low-yielding but long-lived assets will make enough cash flow, over the next 13 years, to plug his wells.
The draft financial assurance rules would completely upend the economic balance of stripper wells, Bradley said.
The draft rules would call for each well to be bonded for the cost of plugging and abandoning at $78,000, but they would allow blanket bonds for operators with large numbers of wells.
Bradley and most stripper well operators, however, would fall into a category, called “Tier 3,” which was aimed at low-producing wells.
An operator with more than 60% of its wells producing less than five barrels a day would have to start paying into a fund for the next 10 years to cover each well at full-cost bonding.
“Tier 3 operators may have the highest risk of orphaning their wells, because they have a higher percentage of low producing wells that generate relatively little revenue, and they are plugging a relatively low percentage of their wells,” the commission said.
“The rules are a complete disaster,” Bradley said. “These draft rules require me to tie up all my working capital in bonding. The rules would drive operators out of business and create a whole lot of orphan wells.”
The commission’s financial assurance task force raised the same prospect saying, “Additional regulatory burdens placed on a large number of ‘low flow wells’ could result in a significant short-term increase in the number of orphaned wells.”
The Small Operator Society, representing 65 small oil and gas companies, lobbied the COGCC to set up a statewide fund into which all the oil and gas companies would pay based on their production and from which all operators, big and small, could draw to plug wells. The commission did not adopt the idea.
“It was pretty much an admission by the small operators that they don’t have the resources to plug their own wells,” Sura, the oil and gas attorney, said.
It is not that simple, said COGA’s Haley. “This is an industry full of small businesses, hundreds of mom-and-pop businesses across the state,” he said. “There are problems for small businesses when government increases the cost of doing business in Colorado. It may be expensive for large businesses, but they can shoulder it more easily.”
Bradley said the commission doesn’t understand the stripper well business and that as long as a well is producing more than two barrels of oil a day there will always be a buyer and operator for it. Below two barrels a day, the wells are uneconomical and there will be few takers. There are thousands of wells recording less than two barrels a day.
“Even in the worst year we’ve seen, 2020, there was only one operator who went bankrupt and created orphan wells, Petroshare,” Bradley said. “That should tell you something.”
One bankruptcy had many ripple effects
Englewood-based PetroShare Corp. initially filed for bankruptcy protection in 2019 in the hopes of reorganizing, but by June 2020, facing the pandemic collapse in oil prices and the economy, the company was liquidated.
PetroShare owned as many as 141 oil and gas wells, according to COGCC data, some dating back to the 1980s, and some brand new, horizontal wells. At the time of its liquidation the company had 89 wells.
The wells were sold in the bankruptcy proceeding to two companies to whom PetroShare owed money. Those companies, however, did not take all the wells leaving some orphaned.
At the time of the liquidation, three wells had been inactive for more than five years, 17 had been inactive for more than two years and 47 likely qualified as stripper wells, according to analysis by Carbon Tracker, a climate policy think tank.
The state seized $325,000 in PetroShare bonds for 53 orphaned wells and 58 orphan well sites. That came to a little more than $6,100 for each well, leaving the COGCC to make up the difference.
“They become our responsibility for the rest of their lives?” Pam Eaton, then an oil and gas commissioner, asked at a June 2020 hearing on PetroShare’s bankruptcy. “That’s correct,” replied Steven Kirschner, a COGCC staffer.
While PetroShare may have been the most recent, high-profile bankruptcy liquidation – there have been several other operators who have slipped into and out of bankruptcy reorganization – it is far from the most notorious. That distinction goes to Texas Tea LLC.
Texas Tea, whose mailing address was a UPS Store, between a nail spa and a juice bar, in a Lakewood strip mall, on West Colfax Avenue, ran up so many violations, at least 55, and was so delinquent in paying fines that it was banned from doing business in Colorado.
The City of Brighton took the responsibility for plugging one Texas Tea well within its city limits at a cost of $26,000, and in 2016 the COGCC took over about 30 of the company’s wells. Texas Tea had $72,000 in bonds — $2,400 a well.
There are still eight Texas Tea wells and 11 well sites on the state’s orphan well list to be cleaned up.
A review of COGCC data shows that there are other wells that may be heading toward the orphan well list, like the 22 temporarily abandoned wells of Colorado Springs-based FRAM Operating LLC.
FRAM ran as many as 83 wells in Delta and Mesa counties and was last recorded having 25 wells. It posted $345,000 in total clean-up bonds, including $250,000 for plugging.
The company’s last recorded oil production was in 2018, 65 barrels of oil and 22 thousand cubic feet of gas for the year. In April 2019, FRAM filed for bankruptcy, according to a COGCC inspection report for one of the wells in Mesa County, along Kannah Creek.
“Location should be a high priority when assigned to the OWP (Orphan Well Program) due to the proximity to residence and an active stream,” the March 2021 report said.
FRAM emerged from bankruptcy in March, but has been issued COGCC notices of violation this year for failing to report on well operations and for not performing mechanical integrity tests. The tests are required on wells once every five years. Some of the wells, according to a complaint filed with the commission by WildEarth Guardians, haven’t had a test since 2012.
The company did not reply to voicemail messages seeking comment. Its email address was no longer functioning.
An analysis, done by the COGA of all 579 wells orphaned in Colorado, found that almost a third belonged to six former operators who had had formal enforcement actions against them, including PetroShare.
“When we looked at those operator traits, they had a track record of being unresponsive to compliance issues,” said Dave Kulmann, a consultant who did the COGA analysis. “If you see this behavior and those 2 BOE (barrels of oil equivalent) wells, there is a risk.”
Of the 186 orphaned wells the six companies owned, 65% had no production in the previous three years, being listed as shut-in or temporarily abandoned, and all were classified as stripper wells.
“The true risk of becoming an orphan well is not just the well, but more critically if the operator has compliance issues or is unwilling to address well issues,” the COGA analysis said.
As it is, the bulk of inactive wells are not in the hands of small, fly-by-night drillers, but some of the largest operators in the state.
Chevron’s Noble Energy in 2020 had, according to the COGCC’s data,1,600 shut-in wells, 20% of all the wells in the state in this category, and 117 temporarily abandoned wells, including the four on the Stephenses’ land, 44% of the state total.
Noble’s most recent count puts the total for shut-in and abandoned wells closer to 1,900, while it has 2,400 producing wells. Noble also has about 700 wells producing 2 BOE a day or less.
The largest operator in the state, Occidental Petroleum Corp., had 2,112 shut-in wells and 253 temporarily abandoned wells.
Kulmann said that is actually a good thing these wells are in the hands of big operators like Chevron, one of the world’s 10 largest oil producers.
“They are a big company that gives me comfort that they are not going to abandon wells to the state of Colorado,” he said.
“The state needs to plan for the oil and gas industry not as we have known it in the past”
A 30-year-old Noble well, now in the hands of Extraction Oil & Gas Co., part of a $125 million acquisition in 2014, sits in a broad, sunflower-filled open space in Lafayette, hemmed in here by suburban housing and there by light industry.
And on an early August day, the well was in the process of being plugged, its life officially ended. A workover rig, with its 104-foot tower, was already in position. On an open space trail, a dog-walker ambled by and a jogger passed at a good clip.
Luke Hinrichs, 38, Extraction’s workover supervisor, who has overseen pretty much every one of the 435 wells the company has plugged since 2016, surveyed the scene.
“When you first turn up, people are worried you are there to drill or frack,” Hinrichs said. “You try to explain ‘No, we’re plugging a well and we’ll be gone.”
While the drilling of new wells and fracking – which sends fluids down the bore under pressure to fracture rock and release oil and gas – can take several months, plugging and remediating an old well site, including hauling off old tanks and equipment, cleaning soil and grading, takes about three weeks, Hinrichs said.
The workover rig is mobile and comes collapsed on the back of a truck trailer and pops up with its tower extending like a telescope. The actual plugging of the 7,000-foot-deep old Noble well was set to use about 840 gallons of cement and take just about 20 minutes, Hinrichs said.
Before that the workover rig has to pull up any piping and debris in the well and slide in tubing so the well can be flushed and pressurized with fresh water.
A large stack of pipe already pulled from the well was now sitting next to the rig and a big, white tanker truck filled with water lumbered on to the site.
A gyro survey, an instrument used to get an accurate downhole location of the wellbore, is lowered into the well. Sometimes heat sensors are dropped in to develop heat logs or a downhole camera is used, all aimed at getting a better understanding of the state of the well.
The plugging and abandonment plan has to be filed with and approved by the COGCC and is a public record.
One of his most challenging plugging jobs, Hinrichs said, was on a Weld County dairy farm where the well had been covered by “cow-pucky pond.” A dike had to be built around the well in the waste lagoon to get to it. “That was some fun,” he said
When the crew – Extraction was using oil field service company Ranger Energy Services on this job – is ready to seal the Lafayette well an iron plug capped with cement will be placed at the bottom and cement will be pumped in.
The most expensive part of the process is removing the old tanks and equipment and cleaning up the site. “Taking out the tanks you can find old spills,” Hinrichs said. “It’s the legacy stuff you have to contend with.”
Extraction said the cost of plugging and remediating a well like the one in Lafayette ranges between $80,000 and $180,000.
Similar plugging jobs are taking place across the Front Range. Between 2017 and 2020, Occidental Petroleum spent more than $100 million to plug and abandon 2,224 wells, while drilling 937, according to a filing with the COGCC.
Noble, the second largest producer, has plugged and remediated 1,700 wells and associated facilities between 2018 and 2020 and has plans to seal 445 more wells in 2021.
Since 2017, the company said, in comments to the COGCC, that it has plugged six wells for every one it has drilled and spent $200 million on the program.
Most operators, including Extraction, depend on contracting with oil field service companies for plugging, which could create a traffic jam if every company faces the same plugging deadline. Noble has 14 of its own workover crews, the company said.
As for its large number of shut-in and temporarily abandoned wells, Noble said in an email, “We don’t believe low producing or inactive wells are a predictor of orphan-well risk.”
“Many of the company’s shut-in or temporarily abandoned wells are legacy vertical wells on lease positions acquired from other companies,” Noble said. “Many of those will be plugged and removed as part of our horizontal development plans. “
That may address some, but not all of the problems, critics say. “The operators who are plugging the wells aren’t the ones we are most concerned about,” Merlin, the WildEarth Guardians attorney, said. “The problem is the stripper wells.”
“The large companies aren’t plugging out of the goodness of their hearts,” Merlin said. “By and large they are required to plug wells that could interfere with the drilling of new wells.”
In many ways the debate over the financial assurance rules is a debate over the financial health and fate of the industry.
“A healthy and growing oil and gas industry in Colorado will voluntarily plug far more older wells than any government program with ZERO cost to taxpayers,” a coalition of industry groups said in comments to the COGCC.
But Sura, the oil and gas attorney, who represents municipalities, environmental groups and property owners, like the Stephenses, said “this is an industry in decline, we are never going to see the amount of production we saw in 2019.”
“Since they are an industry in decline, they should start considering their asset retirements and the state needs to plan for the oil and gas industry not as we have known it in the past,” he said.
In 2019, Colorado posted record production of 19.2 million barrels of oil and 2.4 trillion cubic feet of natural gas. Production dropped nearly 11% in pandemic-ridden 2020 and in the first quarter of 2021 production was down 25% year-over-year, though industry representatives say they expect it to increase with the country’s economic rebound.
While not an international oil company, like Chevron or Occidental, the pending merger of Extraction with Bonanza Creek Energy and Crestone Peak Resources into Civitas Resources will create one of the largest Colorado operators with almost 2,400 producing wells and 1,000 shut-in and temporarily abandoned wells.
The three companies are also responsible for having plugged more than 1,000 wells, according to COGCC data. Extraction has plans to plug another 20 to 25 old wells before the end of the year, for a total of 50 to 60 in 2021.
From the Extraction plugging job, suburban development can be seen creeping over the horizon in neighboring Broomfield. In Lafayette, the well plugging was ahead of growing suburbia, but sometimes, as in the case of Broomfield’s Anthem Highlands, suburbia gets there first.
1 leaking well in a subdivision takes $500,000 to resolve
A drive along Graham Peak Way, in Broomfield’s Anthem Highlands development, is a trip down one of the countless new suburban streets spreading across the old farm fields and prairies of the Front Range.
The byway is lined with large, buff-colored homes, with a basketball hoop in one driveway, an American flag flying next door, scooters strewn across a front path and one of those little green plastic men parents place on curbs in the hopes that motorists will take heed of their children at play. Maple, oak and elm, saplings, still tethered to posts, line the street.
At least that is the scene until the home of Wayne Bott, 41, and his wife Bennett. Just beyond their house, the land on either side of Graham Peak Way is vacant – a few rubble piles, weeds, wildflowers and hard packed dirt.
There are placards stuck along the street showing where the developer, Richmond American Homes, was ready to build, one sign announcing: “Richmond America Lot 138, 16321 Graham Way.”
It even had the type of home to be built – Plan D601 – a five- to seven-bedroom house with a three-car garage, a formal dining room and a great room. “An entertainer’s dream,” a brochure proclaims.
The home building was cut short when it was discovered that an old, plugged oil and gas well, now covered by Graham Peak Way, was leaking methane and that the gas had saturated the soil in the area.
“The fact there was an old well may have been buried in all the real estate papers,” Bott said. “But we didn’t know about it.”
The city found out about the problem well when it decided to have all the existing wells, mainly old and many plugged, tested after Extraction announced plans in 2017 to drill 139 new wells in Broomfield.
That is how in May 2019, ERO Resources, the city’s consultant found the soil around the Davis 43-6 well, now buried under the street, was as much as 95% saturated with methane. It looked like the concrete plugs in the well, drilled in 1994 and plugged in 2003, had not held.
“When the methane migrates up through the soil it replaces everything,” said Mike Hickey, head of the COGCC’s orphan well program. “It had years to accumulate.”
Broomfield officials put a freeze on building permits and turned to the state’s orphan well program for help. The concern was that the explosive gas could collect in basements.
In 2017, gas from a severed oil field line seeped into the basement of a home in Firestone leading to an explosion that destroyed the house and killed two people. Ten Anthem Highlands homes were tested for methane – all were negative.
There are 239 wells that need plugging on the state’s orphan well list and 535 orphan-well sites that need remediation.
The state has seized a little more than $2.7 million in bonds from defunct operators of these sites, and a 2018 executive order by Gov. Jared Polis allocated $5 million to the orphan well program over two years. The money comes from industry fees and fines.
The COGCC’s strawman proposals would raise the orphan well fund to $10 million a year though a $200-a-well fee an operator would pay.
A commission analysis of orphan well plugging and remediation costs in the state program found the average price per well was $92,710, with a range of $25,500 to $291,000.
Most of those wells, however, are in rural areas. “Remediating a well in the middle of a suburb is another story,” Hickey said.
On Nov. 14, 2019, not long after the Botts had moved in, to their surprise a towering workover rig appeared in the middle of the roadway, a few hundred feet down the street. There were fire trucks and police cars.
COGCC and Broomfield oil and gas inspectors were on site with infrared cameras to check for fugitive emissions. Air monitors were set up. “It was really some scene,” said Hickey, who oversaw the operation.
The Davis 43-6 well was buried under the asphalt and what the subdivision plans showed 8 feet of earthen fill had covered the well.
The crew had to dig through the tight, compacted material and at 11 feet down they encountered a 2-inch pipe suspected of being attached to the well; a hydroexcavator, a giant vacuum truck, was used to expand the dig.
Finally, 16 feet down they reached the well, Hickey described as “a dark, stinky hole.” The cement in the well had severely deteriorated.
“There were some plugs we were expecting to find that weren’t there, that had fallen away, degraded,” Hickey said.
The workover rig, which straddled the sidewalk, set to its task first drilling down to clear old concrete and sliding extra metal casing into the well, then a new concrete seal was pumped in. Repairs were made to a depth of 2,500 feet. The job which was supposed to take two weeks was completed Dec. 8.
Then they waited for the methane to dissipate. The readings tended downward, eventually got to single digits, but the methane lingered.
This past June, to speed the process, Richmond American Homes paid to have trenches with vents built parallel to the sidewalks along the vacant stretch of Graham Peak Way. One of the test sites that had measured 3.4% methane on June 21 was down to 0.6% by June 26.
The city is still waiting to give Richmond American Homes, which did not respond to email requests for comment, the go-ahead for new homes.
Now all is quiet on Graham Peak Way. “I am glad all the construction is over,” Bott said. “But you know they are going to start building homes, whatever it takes.”
At a City Council briefing last spring, Jack Denman, Broomfield’s environmental consultant, was asked if other municipalities were dealing with these issues or are doing methane soiling testing.
“Not only is this a new issue for the city and county, I would pose it is a new issue for the oil and gas commission as well as many of the residential developments up and down, or at least in the northern Front Range, as residential development moves into legacy oil and gas wells,” Denman said. “This is something new for the Front Range.”
And the final price tag of plugging and remediating Davis 43-6? Richmond American Homes spent $200,000 on the trenches and vents, according to the city, and the COGCC spent nearly $300,000 plugging. So, dealing with this one well on a Front Range suburban street had cost about half a million dollars.