(Source: Red Deer Avocate) EDMONTON — There’s lots of life in Alberta’s conventional oil industry and plenty of resources and political will to clean up the mess it leaves behind, says the head of the province’s energy regulator.
“Will there be halcyon-days growth in the sector? Probably not,” said Alberta Energy Regulator president Laurie Pushor.
“We still see an industry that is healthy and anticipating relatively stable production.”
Pushor spoke to The Canadian Press after his first year on the job, a year that saw 20 per cent layoffs at his agency at a time when the government is asking it to do more. There are also growing worries over the industry’s environmental liabilities and concern about the growth of coal mining in the Rocky Mountains.
“This organization has had a profound amount of change,” he said Thursday.
Pushor acknowledged problems with how Alberta ensured industry has cleaned up after itself.
A recent report from the University of Calgary found more than half the province’s wells no longer produce, but remain unreclaimed. The regulator’s own predictions suggest such wells will double between 2019 and 2030.
The regulator wasn’t making sure companies that bought old wells had the wherewithal to operate and close them safely, Pushor said. Companies would pass the regulator’s tests, then collapse anyway.
“We were seeing failures of companies that had positive ratings.”
That’s changed, he said. The regulator can now look at a much broader range of factors, including whether it’s honouring lease payments to landowners and tax obligations to municipalities — in arrears by $245 million.
“How they treat their partners on the land is a pretty clear and strong indication of their performance in protecting the land,” Pushor said.
“We think there will be an opportunity for us to be more diligent in protecting the interests of Albertans if a company is in failure.”
New rules are coming in the fall that will force operators to spend a certain slice of their estimated clean-up costs every year.
“That’s the key tool here. We start it out at whatever percentage (and) monitor the data to see whether we’re making gains or not.”
Similarly with the tailings ponds, said Pushor, who noted policies are in place.
The province’s auditor general has said the amount of surety Alberta holds to guarantee the remediation of the oilsands is inadequate. That amount hasn’t changed since 2016.
But that’s because Alberta doesn’t require payments to accelerate until near the end of mine life — which, in some cases, is decades into the future.
“We would have full financing held six years prior to end of (mine) life,” said Pushor.
The regulator’s recent move to base security requirements on a company’s own revenue projections won’t affect that, he said.
Pushor said the regulator is also on top of ensuring environmental impacts of coal exploration in the Rockies are dealt with. Although the regulator does not collect any deposits to make sure the work is done, Pushor said clean-up requirements are part of the licence.
“We expect the reclamation to follow right on the heels as their permit requires. We stay pretty diligent to ensure exploration projects are being reclaimed.”
Stock prices for some of those mining companies plummeted after the government’s decision to pause all activity on those leases in response to public concerns. Pushor said the regulator doesn’t have concerns about them not being able to meet their obligations.
“It’s hard for me to speculate on what might happen. We will be diligent in holding the companies to account.”
Pushor said, despite losing 200 staff and more than 10 per cent of its now-$206 million budget, the Alberta Energy Regulator has a handle on things. He said it has come along in regaining public trust after facing conflict-of-interest investigations into its previous leadership.
“We probably slid a bit,” he said.
“The challenge before us is to continually work to regain that. And that’s probably not good enough — we probably want to continue to grow and build that confidence.”
This report by The Canadian Press was first published May 27, 2021.
Study finds abandoned oil and gas wells place unfair burden on landowners, taxpayers
(Source: Global News) The costs of Alberta’s growing stock of abandoned and inactive oil and gas wells are falling unfairly on landowners and taxpayers, says a report from the University of Calgary.
“Landowners have been left behind,” said Braeden Larson of the university’s School of Public Policy. “Landowners got the short end of these burdens that have popped up with the number of wells that have grown in this crisis.”
Larson and co-author Victoria Goodday use industry and government data as well as previous research to point to troubling trends in Alberta’s beleaguered conventional oilpatch.
More than half of Alberta’s wells no longer produce oil and gas but haven’t been cleaned up. That includes 97,000 wells that haven’t been properly closed and another 71,000 that have been closed but not reclaimed.
And the pace of abandonment is accelerating.
The report says inactive wells increased by more than 50 per cent between 2015 and 2020. The Alberta Energy Regulator expects another 6,014 of them in 2021.
More than half have been inactive for more than a decade and even relatively new wells, once closed, have less than a one-in-five chance of being reactivated.
More and more are simply deserted. Over the last six years, the number of orphan wells has quintupled, the report says.
Many companies have stopped paying rent to landowners, the paper says. Almost always, the public picks up the tab.
In 2018, the Surface Rights Board, which adjudicates disputes between landowners and energy companies, ordered $6.4 million in payments from general revenue. In 2014, the tab was less than a tenth that.
The number of rent recovery applications in 2019 was 10 times the average from 2004-2014. In 2018, applications to the board were twice the number of claims resolved.
“(It’s) sometimes one or two years before a landowner can even put their case before the Surface Rights Board,” Larson said.
Rural Municipalities Alberta says the amount of outstanding property taxes from the oilpatch has tripled since 2019 to $245 million.
The impact of abandoned or inactive wells on property values has never been calculated, the report says.
The burdens are not only financial.
The province’s energy regulator has found that about 10 per cent of inactive wells and seven per cent of abandoned wells leak. Farmers and ranchers complain about poor weed control contaminating their crops and pastures.
Recent federal and provincial programs tend to favour industry by encouraging spending in areas where the most wells can be cleaned up, instead of targeting the most hazardous wells or those that have been idle the longest, the report says.
Larson recommended more research on the costs as well as policy changes, including bringing in time limits for companies to clean up their wells, as is done in other jurisdictions.
“Past legislation and legislators couldn’t see a future where the number of inactive and orphan wells would become such an overwhelming crisis,” Larson said. “It’s now an opportunity that we have a chance to focus on solutions.”
That’s an understatement, said Regan Boychuk of the Alberta Liabilities Disclosure Project, an independent group that has studied the issue for years.
“A year ago, before COVID, rural Alberta was on fire (over the issue). Landowners were threatening sabotage.”
He points out that the report estimates the total liability from unremediated wells at $338 million. Estimates from the regulator, which include other energy facilities such as pipelines, put the number anywhere between $58 billion and $260 billion.
The real problem, Boychuk said, is that Alberta’s aging and depleted conventional oilpatch isn’t profitable in today’s energy market.
“This industry can’t repay its mortgage. If the people operating this stuff don’t have the resources to clean it up, they shouldn’t be operating it.”
$100 million in federal funding for cleanup of Alberta oil and gas wells went to sites licensed to CNRL
Hundreds of millions of dollars in federal funding allocated to clean up oil and gas well sites in Alberta has gone toward cleaning up sites owned by some of Canada’s largest oil and gas companies, data shows.
In the early days of the COVID-19 pandemic, Prime Minister Justin Trudeau announced $1.7 billion in federal funding to help with the sealing and cleaning up of orphan and inactive oil and gas wells across B.C. and the Prairies — on the heels of intense industry lobbying efforts.
“Our goal is to create immediate jobs in these provinces while helping companies avoid bankruptcy and supporting our environmental targets,” Trudeau said.
Alberta received the bulk of the funding, to the tune of $1 billion. The province began rolling out those funds last year — through an initiative it dubbed the Site Rehabilitation Program — to contractors with plans to clean up oil and gas sites licensed to companies that had ostensibly been struggling to pay to clean them up themselves.
But an analysis of publicly available data for two granting periods — which together allocated more than $400 million in federal funds — shows the lion’s share of Alberta’s federal funding in those periods was used to clean up sites owned by some of the country’s largest oil and gas companies.
Half of the more than $400 million went to sites held by eight companies — including Canadian Natural Resources Limited (CNRL), Cenovus, Husky Oil Operations Limited, Imperial Oil Resources Limited and Torxen (which acquired $1.3 billion in assets from Cenovus in 2017 and is headed by a former Cenovus executive). The remaining half was divided between sites held by 275 other companies.
Contracts for work on sites held by CNRL, a company that has reported an average of $1.9 billion in annual net profits over the last 10 years, were allocated more than $102 million in funding in the two grant periods. Like many in the industry, the company struggled in 2020, reporting a net loss of $435 million, though these were less than the losses it faced during the 2015 oil price crash. Despite its losses in 2020, the company’s shareholder dividends were increased by 11 per cent in March, which the company boasted marked the “21st consecutive year of dividend increases.”
“This funding definitely violates the polluter pays principle,” Julia Levin, climate and energy program manager with Environmental Defence, told The Narwhal. “It allows an industry that has profited from taking billions of dollars out of the ground in the form of oil to walk away from their environmental responsibilities.”
When companies walk away from environmental responsibilities, the impacts are felt by farmers and landowners, said Morrigan Simpson-Marran, an analyst with the Pembina Institute.
“When a company goes under, when a well sits inactive for a long time, when assets are orphaned — it’s ultimately the landowner who always feels those impacts first,” she said.
The COVID-19 pandemic meant landowners were at greater risk of facing more neglected oil and gas infrastructure, as oil prices plummeted and cleanup of inactive sites became less of a priority, or a possibility, for cash-strapped companies.
“This funding has enabled an increase to the amount of closure work in western Canada and has provided support to the oilfield service sector at a time of economic challenge,” Jay Averill, a spokesperson for the Canadian Association of Petroleum Producers (CAPP), said in emailed responses to questions from The Narwhal.
Simpson-Marran said she understands the need for this program but “it’s really important that it doesn’t become a precedent for the polluter pays principle not being upheld.”
Partial funding seen by some as an incentive to pay for cleanup
There are approximately 330,500 wells across the province, according to the Alberta government. More than half of those wells are inactive or permanently sealed but not cleaned up. (These figures do not include the more than 7,000 orphaned sites in the province that have been left behind by financially insolvent companies.)
According to the Alberta Energy’s Regulator’s most recent figures, liabilities in the province — the cost to safely seal and cleanup wells — are pegged at more than $30 billion, though the regulator has internally estimated the actual cost is much, much higher.
CNRL holds a substantial share of those liabilities, according to data available through the Alberta Energy Regulator’s information portal. The company holds licences for 38,000 wells that are no longer in use but not yet cleaned up — a fraction of its large liabilities around the world.
In its most recent filings to the U.S. Securities and Exchange Commission, CNRL notes the cost of decommissioning, permanently sealing and cleaning up its existing developments globally is pegged at more than $19 billion. (CNRL did not respond to The Narwhal’s request for an interview.)
The other large companies whose sites were the major recipients of federal funding are also sitting on huge liabilities.
The situation is similar in B.C., where data obtained by The Tyee showed that of the first $50 million allocated to cleaning up well sites, $12.4 million — roughly a quarter — was earmarked for sites licensed to CNRL. ($120 million of the $1.7 billion in federal funding went to B.C.)
Data from earlier funding periods was not available in Alberta. “Information is confidential to the licensees and their service providers,” a spokesperson for the office of the Minister of Energy said by email. “Providing this information could harm the competitive positions of service companies and their customers in negotiating contracts with licensees.”
Federal funds were distributed not to energy companies themselves, but instead paid directly to the contractors those companies would normally pay to do the cleanup work on their sites. In some funding periods, the government covered the full cost of the contractor to do the cleanup work; in other periods the government paid half and asked the company to pay the remainder.
Bruce Ralston, B.C.’s Minister of Energy, Mines and Low Carbon Innovation, told The Tyee the split-funding approach, also used in B.C., creates incentives for companies to spend their own money on cleanup.
In emailed responses to questions from The Narwhal, CAPP’s Averill said the program “provided an incentive for companies to accelerate their own spending on decommissioning and reclaiming wells and associated infrastructure.”
“The Canadian government’s reclamation program helped put people in B.C., Alberta and Saskatchewan back to work when these provinces needed it most through 2020,” he added.
Levin worries large oil companies “simply put their own programs on hold” and have “replaced their own spending with federal funding.”
Regulatory changes are needed to help hold companies accountable for their liabilities, the Pembina Institute’s Simpson-Marran said.
“There shouldn’t need to be incentives for companies to clean up their mess.”
Critics call for updates to rules for Alberta oil and gas well cleanups
As part of its initial funding announcement, the federal government said Alberta “has committed to implement strengthened regulation to significantly reduce the future prospect of new orphan wells. This will create a sustainably funded system that ensures companies are bearing the costs of their environmental responsibilities.” (The Department of Finance did not respond to The Narwhal’s questions by publication time.)
Critics have long warned that insufficient regulations enable companies to acquire the rights to drill a well in Alberta without adequate assurance that they will ever be able to clean it up.
Full securities, or bonds, are not required for the cleanup of wells drilled in Alberta, nor are there any legislated timelines on when wells need to be safely sealed or cleaned up once they are no longer producing, with some sitting on the landscape for decades.
According to the regulator, $216 million in deposits are currently held against $30 billion in estimated liabilities — less than one per cent. The regulator has said well liabilities could be more than three times the official estimate in an internally used “worst-case scenario.”
Last July, the Alberta government released what it called “clear rules” to “advance cleanup of oil and gas wells,” saying in a press release that it was taking “long overdue action” that would “shrink the inventory of inactive and orphaned wells across the province.” (A spokesperson for the premier’s office did not respond to questions from The Narwhal.)
The new rules included plans for requirements on the amounts companies must spend on reclamation efforts annually.
The press release said the plan “upholds the polluter-pay principle, ensuring that industry is responsible for cleanup costs.”
Averil, the spokesperson with CAPP, said by email that the organization is supportive of inventory reduction targets, adding that “reducing environmental liabilities is a priority for the oil and natural gas industry and this initiative allows important work to accelerate, helping businesses survive and be part of the economic recovery.”
Alberta’s plan does not include deadlines for when a site needs to be cleaned up, and does not require full upfront deposits for the cost of safely sealing the well and reclaiming the site.
“At the end of the day, if we really want to cut this issue off at the knees, what we need is timelines for every stage of the well life, full security and transparency of data,” Simpson-Marran told The Narwhal.
Long time to see results of oil and gas well cleanup in Alberta
Levin with Environment Defence told The Narwhal she worries evidence has not yet surfaced to indicate Alberta’s Site Rehabilitation Program has been a success. The federal funding, she said, was announced “under the guise of environmental stewardship and job creation. We’re just not seeing those things happen.”
According to data provided to The Narwhal by a spokesperson for the Alberta Energy Regulator, the number of applications for reclamation certificates — the final seal of approval on the cleaning up and restoration of an old well site — dropped slightly in 2020 compared to 2019.
Meanwhile, there was nearly a nine per cent increase in the number of wells safely plugged and sealed (known in confusing industry parlance as “abandoned”) in 2020 compared to 2019.
Abandonment involves ensuring there are no issues with leaks, and that the well — often hundreds if not thousands of metres deep — is cut off and safely plugged and capped below the surface.
Reclamation is a lengthier process, particularly for sites with contamination issues. According to the regulator’s website, “the reclamation process can take many years or even decades, depending on how the land functioned before it was disturbed — for example, whether it was forested land, native grassland, peatland, or farm land — and the amount of soil disturbance.”
Alberta landowners may ‘bear the brunt’ of oil and gas well issues
As contractors slowly take on the work of sealing and reclaiming old oil and gas sites, landowners have the opportunity to “nominate” sites for cleanup through the Site Rehabilitation Program.
Landowners have long dealt with contamination issues, leaks, weeds, soil compaction and other impacts of having inactive wells languishing on the landscape.
“Wells that are on the brink of becoming orphans or sitting as inactive” pose the greatest threat to landowners, Simpson-Marran said.
Large companies have long had little incentive to clean up wells sitting as inactive, other than the annual rent and taxes owed on the land (much of which has long gone unpaid). That’s left landowners dealing with tens of thousands of wells across Alberta.
Regulations to ensure large companies clean up wells in a timely manner are a good step, Simpson-Marran said, and federal dollars could be best spent ensuring wells held by smaller companies don’t end up as orphans, languishing on the landscape for decades.
“We don’t want landowners to bear the brunt of the inactive and orphan well issue,” Simpson-Marran said. “These dollars would do the most good going to clean up assets of companies who aren’t financially stable.”
“Landowners feel this first. They suffer through it. They bear a lot of the unseen costs. And if our policies aren’t prioritizing their rights needs and trying to foresee these issues, we need to handle that,” she said.
(Source: EnvironmentJournal.ca By Natalie Yelton) When the carbon dioxide (CO2) we emit costs money, we generally produce less of it. Economists worldwide point to carbon pricing as the most effective way to reduce emissions. Why?
Because carbon pricing reduces greenhouse gas (GHG) emissions to the lowest cost possible, where that cost includes the monetary amount of efficiency measures a company takes on and the cost of the inconvenience resulting from making do with fewer goods and services that rely on fossil fuels.
Carbon pricing is exceptionally effective because it eliminates the chance of a market failure — the unknown cost of external carbon emissions — at the source by pricing these costs.
So how does carbon tax fit into the equation? This article provides an understanding of the difference between the two when it comes to effective emissions management.
What is carbon pricing?
Carbon pricing is a market-based approach to reduce carbon emissions that uses market mechanisms to pass the cost of emitting on to the emitters. It aims to discourage the use of CO2 or emitting fossil fuels in order to address the causes of climate change, protect the environment, and meet international and national climate agreements and pledges.
“Polluter pays” is a crucial aspect of the carbon pricing strategy. By putting a monetary amount on carbon, communities can hold emitters responsible for the consequential environmental and social costs of putting GHG emissions into the atmosphere, including increased risk of dangerous weather, warming temperatures, polluted air, and community health threats from the negative impacts on food and water supplies.
Putting a price on carbon also provides financial incentives for polluters to reduce their carbon emissions.
Carbon pricing provides a long list of significant benefits. It is one of the most robust policy tools available for fighting climate change. It offers the opportunity to decarbonize global economic activities by influencing the behavior of businesses, investors, and consumers. It also offers continuous technological innovation and new, clean revenue streams that are more productive and sustainable for corporations. In other words, the best-designed carbon prices provide three key benefits: they preserve the environment, promote funding in clean technologies, and boost revenue.
What is a carbon tax?
A carbon tax is a fee that fossil fuel burning corporations pay as a result of government regulations. By fossil fuels, we mean oil, coal, natural gas, and gasoline. When these carbon-filled fuels are burned, they produce greenhouse gas emissions. These gases, such as methane and carbon dioxide, cause global warming by raising the atmosphere’s temperature. Flooding, heat waves, droughts, and blizzards, along with other extreme weather events, are a result of global warming.
The main objective of a carbon tax is to mirror the actual cost that burning carbon creates. Carbon taxes ensure corporations and consumers pay for the external costs they inflict on the wider society.
How does carbon tax relate to carbon pricing?
A carbon tax is a type of carbon pricing — the other primary type of carbon pricing is emissions trading systems or ETS.
A carbon tax sets an exact price on carbon by specifying a tax rate on GHG emissions or on the carbon amount found in fossil fuels, with the latter becoming more common. Carbon tax differs from an ETS in that the GHG emissions reduction outcome of a carbon tax is not defined in advance, but the carbon price is.
National and economic circumstances largely control the choice between using a carbon tax or an ETS. There are also more indirect ways of pricing carbon, including through fuel taxes, regulations that take into account the social cost of carbon, and the elimination of fossil fuel subsidies. GHG emissions may also be priced through payments for carbon emission reductions.
Setting an internal carbon price for your company
Many industry-leading companies are setting an ambitious internal carbon price to help consolidate their environmental impact. Cutting-edge technology can help you make sense out of complex data by quantifying targets, identifying emissions gaps, and reviewing carbon budgets more seamlessly than ever before.
Expert advice can help a company define costs and carbon pricing based on precise data analysis. It’s important to implement pricing mechanisms based on the most robust business approach possible and align your business strategy with segmented and transparent targets built around emissions pathways.
Setting an internal carbon price helps your company build resilience, and can strengthen communication in capital markets with meticulous datasets that are accessible and easy to understand, and prepare for increasingly demanding regulation.
Natalie Yelton is an environmental consultant at SINAI Technologies.
Arsenic legacy in lake-bottom sediments from historic N.S. mine worries researcher
(Source: CBC News) Findings from a study describing the arsenic legacy left in lake-bottom sediments near an abandoned Halifax gold mine are setting off alarm bells for a senior cancer researcher.
A paper published Monday in the journal Science of the Total Environment says a dated core sample taken from the bottom of Lake Charles discovered arsenic at 4,960 milligrams per kilogram, more than 280 times higher than levels “where biological harm is expected.”
The site is downstream from the historic Montague mines, where successive gold rushes saw the creation of 121,000 tonnes of arsenic-rich tailings between the 1860s and 1940.
Not only are the carcinogen levels high, the sample suggests the arsenic in sediments at the lake’s deepest point is actually rising closer to the water itself.
Joshua Kurek, an environmental scientist at Mount Allison University in Sackville, N.B., and one of the study’s co-authors, said in a recent interview the proximity of the arsenic to the lake water after so much time was unexpected.
“We tend to think of sediments at the bottom of a lake as a sink for a lot of materials … but here’s a case where the pollutants from mining that ended 80 years ago are slowly moving up the core and are getting closer to the sediment-water boundary,” he said.
“If environmental conditions at the bottom of Lake Charles change, what can happen is some of those contaminants that were locked into the sediments can be released into the water column.”
The popular swimming and boating lake on the outskirts of Halifax already has high levels of arsenic at 11 micrograms per litre, double the Canadian water quality guidelines for the protection of aquatic life and higher than 50 other lakes in the region, according to federal Fisheries Department data.
In a province full of abandoned mine sites, the journal article raised concerns for Dr. Graham Dellaire, the director of research in Dalhousie University medical school’s department of pathology.
The Halifax-based researcher is leading a national team of experts looking at carcinogens that affect people’s risk of getting cancer.
He said in an interview last week that while the public has often heard the message on the carcinogenic risk of being exposed to radon, many remain unaware of the risks of long-term exposure to arsenic and its links to various cancers.
Dellaire is attempting to start awareness campaigns on arsenic, and he’s seeking funding to provide information to areas where there is high risk for contamination, such as areas downstream from abandoned gold sites.
He said the program would test well water and invite people to screen for personal arsenic exposure through sampling of their toenails.
“The ghost of our mining past is coming back,” he said.
Kurek said the upward migration of the arsenic in Lake Charles may be tied in to urban influences on the body of water.
The expert in freshwater ecosystems suggests with nutrients such as fertilizer flowing in from surrounding properties, there are biological processes that can deplete oxygen in the deeper reaches, and this chemical change in the water appears to be related to the rise of arsenic.
Warming water and other climate change impacts could also be playing a role, potentially speeding the chemical processes that deplete oxygen in the lake, he added.
The Lake Charles research comes about a year after another study suggesting more work is needed to know the impact of arsenic and mercury on plants, fungi, invertebrates, mollusks, fish and mammals in Nova Scotia’s historic gold mining areas.
A 2020 paper published in the journal Environmental Reviews found only 18 of the 64 gold districts in Nova Scotia have been analyzed for mercury and arsenic accumulation in various forms of life.
In July 2019, the provincial government announced it was spending $48 million to clean up the Montague site and the Goldenville site in Guysborough County. Overall, it said it was looking at a list of 69 abandoned mining sites, including 24 gold mines, on Crown land in order to determine which ones needed containment or other work.
This came the same year the province’s auditor general issued a report concluding the province hasn’t sufficiently investigated potential contamination at many abandoned mine sites, meaning there could be unknown future tolls on the government’s finances.
During a legislative committee hearing last month, Donnie Burke, executive director of Nova Scotia Lands, said remediation work at the Montague site is expected to start by the next fiscal year.
Allison Clark, the lead author on the most recent paper, completed the work while finishing her thesis at Mount Allison’s department of biology.
“I believe our study is a call to action to work on remediation efforts of the tailing sites,” she said.
Linda Campbell, a professor of environmental science at Saint Mary’s University and another co-author, said in an interview that arsenic is an element that will remain in an ecosystem for a “very, very long time.”
She said the first step to remediation of the contaminated sites is to “stop the mobility of the [gold] tailing materials themselves,” at Montague and other sites.
(Source: NNSL News) Restoring Tuk Island to its natural state is coming along, despite finding more contamination than initially expected.
Appearing remotely, Imperial Oil gave a presentation on the Tuk Base remediation and closure project April 15 in Aklavik, as well as work on Tununuk Point.
“In the mid 1980s our site activity ceased” said project manager Benjamin Fraser. “By 2001 we began environmental assessments on site. The driver for that work was really to understand where the impacts were located on site. When we have storage tanks and vessels and lots of activity happening, some environmental impacts certainly occurred. Through our assessment programs we were able to identify and map out all the locations that would require remediation activities.
“The end goal at the end of the day is to remediate the site and then return it back to beneficial use.”
Lease nears end-date
Initially used as a storage and staging area for further oil drilling further offshore in the Beaufort Sea in the 1970s and 80s, the base was closed down as the oil boom fizzled out. However, the drillers left a big footprint in the form of contaminated soil, old structures, buried contaminants and other environmental and safety hazards. Tuk Island is located roughly two kilometres southeast of the hamlet.
With their lease on the Inuvialuit land wrapping up in 2024, Imperial Oil, also known as Esso, is racing to return the island to as close to its original state as possible. Clean-up work has been ongoing since 2019 with Esso’s main subcontractor, Golder Associates. Recent work on the site has consisted of winter and summer seasons, using the thick ice to haul debris out in the winter and preparing the site for excavation in the summer.
Brian Suen of Golder explained that work in 2020 consisted of removing contaminated debris from the site over the wintertime. Bags of soil were shipped to Fort Nelson, B.C. for disposal while landfill debris was taken to the Inuvik landfill, where the town gave a special one-time tipping fee discount to EGT-Northwind, which had the contract to haul material to the landfill.
Concrete slabs from the site are being repurposed for shoreline preservation as climate change erodes the Arctic coastline out from under the hamlet. Over the summer, the landfill was excavated further and debris was sorted according to its level of contamination. Following excavation, pits are backfilled with clean soil treated at an onsite Soil Treatment Cell.
Fraser noted the soil contaminated with hydrocarbons and diesel can be treated on site. Soil with dissolved metals will need to be hauled southwards to be disposed of.
Work was initially expected to be completed in 2022, but after workers discovered more contaminated material on site, the scope of the project has expanded to 2024.
“As we were excavating the south landfill we encountered increased volumes (of contaminated material,)” explained Fraser. “We all of a sudden had a void of clean material on site to fill in these holes. So what we did was imported around 6,000 cubes of clean material from a nearby quarry that EGT had a quarry permits with. This quarry was actually used as one of the quarries for gravel material helping construct the Inuvik-Tuktoyaktuk highway, so we’ve piggybacked off that permit and brought clean fill.
“We had a lot of haul trucks running back and forth from the quarry to our site. What we have now is a large stockpile of clean material that will help us continue to progress our remedial excavations this summer and back filling in with the clean material.”
Prior to beginning remediation work in 2019, the site has been subject to periodic activity since Esso ceased operations in the 1980s.
Part of Esso’s deal with the Inuvialuit Land Authority is to continue to monitor permafrost and water quality at the site.
New ESAA Member
ESAA welcomes the following new members. If you are not a member of ESAA you can join now via: https://esaa.org/membership/join-esaa/
Indian Resource Council
105, 12111 – 40 Street NE
Calgary, AB T2Z 4E6
Phone: (403) 828-8273
Steve Saddleback, Director – NEBCE
IRC was founded in 1987 by Chiefs representing the oil and gas producing First Nations, following the recommendation of a task force that was established to study the role of the Crown in the management of First Nations oil and natural gas resources. An expanded and restructured Indian Oil and Gas Canada (IOGC) was established at the same time. The work and activities of the IRC are guided by the mandates that were approved and adopted at previous AGM’s in 1993 and 1995. These mandates, which are currently being revamped, are as follows: To support First Nations in their efforts to attain greater management and control of their oil and natural gas resources; To complement initiatives by individual First Nations to gain economic self reliance and to ensure the preservation of the Crown Trust obligations under Treaties with First Nations; To coordinate the promotion of initiatives with Federal and provincial governments, with industry and with other groups associated with oil, natural gas and related activities to enhance economic benefits realized by the First Nations from resource development; To encourage a greater development and utilization of First Nations human resources in oil, natural gas and related activities; To transform IOGC into a First Nations institution, working in partnership with the IOGC co-management Board. To this end work towards the establishment of an oil and gas business centre, and a First Nations oil and gas institution in the long term.
Virtual EnviroTech 2021
June 2 & 3
Starts in 2 Weeks – Have You Registered?
ESAA has listened to all of the feedback we received through 2020 and we have made a number of major changes to the delivery of EnviroTech 2021.
What changes can you expect?
ESAA has intentionally kept the registration fees low and are asking everyone to register and to spread the word about the event and the presentations. Approximately 90% of ESAA’s revenues come from events, and now more than ever your Association needs your support!
How can you help ESAA?
For the complete schedule visit: https://esaa.org/envirotech/
Thank you to our event sponsors for your continued support!
2021 Conference for the Canadian Brownfields Network
Keys to Brownfield Success: The Intersection of Planning, Development & Finance
Join us for the 2021 Brownfield Conference exploring the relationship between planning, development and finance in the successful redevelopment of brownfield sites. In response to the ongoing challenges with COVID-19, the event will be held virtually, kicking off with a panel discussion on Brownfields 2021 and Beyond on June 15th following CBN’s Annual General Meeting, and continuing through the afternoon (1pm to 4:30pm) of June 16th. CBN’s annual conference attracts attendees from across Canada, including land developers, engineering firms, environmental cleanup companies, and legal and financial experts.
- Case Studies: Don’t reinvent the wheel! Learn from experience in this review of lessons learned and novel approaches to site redevelopment.
- Delivery Barriers: A review of brownfield redevelopment challenges from a planning, development, and finance perspective. Come hear what municipal, development, lender, and international practitioners have to say about their experience overcoming brownfield challenges and what is needed to further innovate.
- Technical Challenges: Technical approaches to addressing brownfield challenges are ever evolving. In this fast-paced session, you’ll learn about more efficient, cost-effective ways to revitalize brownfields sites.
- HUB Awards: Join us as we recognize individual excellence in brownfields with our annual HUB Awards.
And, of course, you’ll have the opportunity to connect with like-minded professionals. All in all, it promises to be another engaging experience. Please note the event dates, and plan to attend!
ESAA Job Board
Check out the new improved ESAA Job Board. Members can post ads for free.
- Intermediate Reclamation/Remediation Specialist – NorthWind Land Resources
- Environmental Geologist, Hydrogeologist, Engineer or Scientist –
- Environmental Engineer, Scientist, Geologist or Hydrogeologist – 5 to 10 Years Experience –
- Environmental Scientist, Engineer, Geologist or Hydrogeologist – 10 to 15 Years Experience –
- Intermediate Reclamation/Environmental Scientist (Contract) – JMH Environmental
- Project Manager, Consulting – KBL Environmental
- Intermediate Environmental Consultant – North Shore Environmental Consultants
- Junior Environmental Consultant – North Shore Environmental Consultants
- Fugitive Emissions Field Technician – North Shore Environmental Consultants
- Intermediate Environmental Consultant – North Shore Environmental Consultants
- Client Engagement Specialist –
- Intermediate Ecologist –
- Intermediate to Senior Biophysical Specialist/Terrestrial Ecologist – NorthWind Land Resources
- Intermediate/Senior Wildlife Biologist –
- Junior Data Entry Consultant –
- Intermediate Hydrogeologist –
- CAD Technician –
- Junior Environmental Consultant –
- Intermediate Environmental Consultant –
- Graduate Environmental Scientist / Engineer / Technologist – Worley (Advisian)
- Archaeology Permit Holder –
- Archaeology Permit Holder –
- Archaeology Field Director –
- Assistant Project Manager – Archaeology –
- Intermediate Environmental Scientist –
- Senior Environmental Remediation Technologist
- Intermediate Environmental Scientist – NorthWind Land Resources