Cures for Distressed Barrels

North American refiners and pipeliners are working hard at near- and long-term solutions for the differential-mushrooming Midwest supply glut. 

An edited version of this article appears in the Oilsands Review 

By Peter McKenzie-Brown
After the financial crisis of 2008, the United States was flat on its back. Since that terrible period, Canada’s energy industry has been a considerable, though unwilling, contributor to its return to financial health. To a large degree because of the glut of bitumen in much of its heartland, the US is enjoying lower energy prices than other oil-importing countries. Because of the perverse economics of oilsands development, from many perspectives – not least that there are no alternative markets – it makes short-term sense to keep sending cheap bitumen into the growing glut.

Behind this debacle is a continental pipeline system that does not reflect the realities of contemporary oil supply. In a Globe and Mail report, Canadian Association of Petroleum Producers (CAPP) chairman Lowell Jackson described the industry as “taking the short end of the stick…simply because we can’t move product.” The solution? More pipelines to more markets.

A Manageable Glut
There are four reasons for the glut in much of the American oil market. First, the country is consuming less – a response to higher oil prices, lower economic activity and government policy. Second, the US is producing more oil for the first time in years – much of it coming from the Bakken play in North Dakota and Montana. Those growing supplies are a response to new production technologies – essentially the use of horizontal wells and hydraulic fracking to release tight oil from shale. Third, Western Canada exports its oil almost exclusively on the American Midwest. Finally, both bitumen and light oil production are growing rapidly in Western Canada despite the region’s limited markets.

After being in decline for decades, light oil production in Alberta is again at 2003 levels. In three years nearly 100,000 barrel-per-day of new production have taken the total to 400,000 barrel-per-day. Adding to the supply is Canadian synthetic oil and bitumen production, which increased by more than 100,000 barrels a day last year alone, to around 1.8 million barrels.

Those new volumes are fighting for market share in already tight segments of the American market, which is divided into five PADDs (Petroleum Administration for Defense Districts). Of the five districts, three – respectively encompassing the US East Coast, the Gulf Coast and the West Coast – are the largest oil consumers. However, according to Ralph Glass, economist and vice president of consultancy AJM Deloitte, “80 to 90% of the oil exports coming down from Canada are going into PADD 2 (the Midwestern states) or PADD 4 (the Rocky Mountain states). The other three PADDs are where the population is. So the problem is that you can’t get the oil from these relatively unpopulated places to the densely populated states that really need it – California and Florida, for example.”

He added that the other three PADDs are mostly fed by offshore oil, so they have to deal with offshore prices. “They are paying $15-$20 more per barrel for oil coming in from the offshore, even if it’s coming in from a Gulf of Mexico platform.”

Since Canadian export markets rely on a system of pipelines that feeds Midwestern markets from producing fields in Western Canada and the Western states, the competition for access to limited pipeline capacity is huge, and it is leading to huge differentials for Canadian oil. To cite one example, synthetic crude was recently selling for $10 per barrel less than West Texas Intermediate (WTI), although it is clearly higher-quality oil.

Pipeline capacity is relatively tight already. According to CAPP vice president Greg Stringham, “really small incidents that wouldn’t have had much impact in the past are now having a big impact on crude throughput.

The real disconnect is between WTI prices and world prices. In the next year a lot of market pressure is leading to a lot of infrastructure development with the idea of eliminating the differences between. A lot of that will be resolved within the next year and a half or so.”

Part of the solution will actually make things worse for the oilsands sector. At present, there is no major pipeline coming out of the Bakken; that oil is still mostly railed to market. The magnitude of the potential issue became clear when an American company recently proposed the 2,100-kilometre Bakken Crude Express Pipeline, a 200,000 barrel-per-day pipeline to deliver crude from North Dakota’s Bakken play to Cushing Oklahoma. When completed in 2015, the line will carry high-quality sweet oil into an already competitive market. That line could further reduce Canadian access to US markets by increasing the glut.

Winners and Losers
Alberta – which receives royalties in kind – receives lower royalty revenues because of the differentials. The differentials also affect the corporate bottom line, bringing down governmental tax revenues. In eastern Canada, refineries pay the much higher Brent prices. “The widening differential between Brent and WTI is an indication of the over-supplied North American market and limited access to the off-shore markets,” Glass added.

According to Glass, if the price differentials of early spring this year were to hold until year end, the Canadian economy would forego about $18 billion in revenue, royalties and corporate taxes. What happens on the other side of this trade? North American refiners that can process bitumen – almost entirely located in the US – make high returns by buying bitumen feedstock when differentials are high and selling refined products at regular market prices. The beneficiaries of the oil glut are mostly American.

Perverse oilsands economics mean it makes sense to sell bitumen even when there is no profit in it. Some companies have suggested that, if you apply full-cost accounting to bitumen production, they are selling product to refiners at cost. Yet it makes sense to continue doing this once the capital investments have been made because the cost of is low – perhaps $20-$30 per barrel for SAGD production. According to one bitumen trader, “operating costs are partly subsidized by the gas price collapse. Even if we only get $60 a barrel (from the buyer), we want the income stream.”

Some companies, though, use hedging strategies to beat the differentials. Beginning in 2006, three Canadian companies – Cenovus, Husky and Suncor (through the Petro-Canada takeover) – have taken deliberate steps to average away these peaks and valleys by acquiring interests in bitumen-processing US refineries. They benefit from high bitumen prices when differentials are low (and bitumen prices therefore high.) Conversely, their refining operations benefit when differentials are high, since products manufactured from lower-cost feedstock yield better returns.

Relative to the rest of the world, the energy industry is subsidizing the American economy. “The Americans see the advantage of taking as much Canadian oil as they can because it is significantly cheaper,” according to Glass. “The push by American refineries to get their hands on Canadian oil (will increase summer demand). I think that over the summer the synthetic price will pick up again, too, as it did last year. The Americans are building up their storage reserve with cheaper oil from Canada.”

But “I see the immediate issue as a short-term problem,” he added. Large price differentials “happened last year about this time, but rectified themselves by the end of summer. There is some capacity to put new oil into the pipeline system to get it to the US. Last year Edmonton par actually received a premium over WTI.”

“Enbridge is reversing the Seaway pipeline and that should help. Also, President Obama has announced that he wants to push ahead with the southern leg of Keystone XL…” Access to the Gulf Coast would do more than give Canadian producers access to the vast refining markets in those areas. It would also mean surplus volumes – as crude or as refined products – could be exported to distant buyers.

Three Things
In 2009 Canada exported 1.1 million barrel-per-day into PADD 2. By the end of last year, that number had grown to 1.68 million barrel-per-day. That 580,000 barrel-per-day increase is likely to increase because of the new projects on the oilsands side that still haven’t gone on stream.

That is the bad news. The good news, according to CAPP vice president Greg Stringham, is that the markets are working hard to fix the problems. “The real key is to be ahead in building pipeline capacity, and not to be behind. Right now we’re behind, and we have seen what problems that can cause.”

“There are three things the industry is looking at,” according to Stringham. “The first is market expansion within Canada. At present we import about 800,000 barrels a day into Atlantic and Eastern Canada, even though we have a pipeline that was built in the 1970s to supply oil from Western Canada to that region.

That’s a good light oil opportunity, and there is also some potential for refining heavy oil and bitumen at the Irving refinery. In the past they did refine some oil from Venezuela. Can we get the pipeline reversed and get the oil to those markets in the medium term? The NEP is now looking at that issue.”

Would reversal of that pipeline mean lower energy costs for Canada? “The savings would be quite substantial in the short term, but that can’t last. What will happen eventually is that North American production will be priced at world oil prices.”

The biggest potential market for Canadian oil, “the 9 million barrel-per-day market,” is the Gulf coast. “We have to get into that. Right now there are many proposals to enable us to do that. The real bottleneck is the access between Cushing and the Gulf coast. That’s what’s causing the disconnect between the pricing structures in the United States compared to the rest of the world. The market is working to reverse that, by installing new pipeline capacity.”

Both Stringham and Glass are optimistic about the impact of Enbridge’s efforts to reverse the Seaway pipeline and the construction of the southern leg of the Keystone pipeline. According to Glass, “The only way we can really get our oil out is not by building refineries and trying to export product, because we simply don’t have (pipeline) access. But we can supply world markets with products by getting our oil to Gulf Coast refineries.”

On the matter of the proposed Northern Gateway pipeline, both men are effusive. “We have really strong opportunities to develop markets from Canada’s West Coast,” according to Stringham. “We aren’t only talking here about selling oil to China, but also delivering oil to other markets like California, which is currently feeding off a diet of Alaska oil, which is in decline.” A relatively new issue with this development is related to the industry’s growing need to export light and medium oil. It is no longer just a bitumen pipeline. “We need to find new markets for light oil, also. We have to find the right balance between the exports of light oil and bitumen.”

Part of finding the right balance may involve expanding the TransMountain pipeline to BC’s lower mainland – a three/four year project. That longer-term timeframe is where the biggest risks lie. How fast can Keystone XL be approved, and then how long will it take to bring it to completion? What about Northern Gateway? Reversing the TransCanada pipeline to Eastern and Atlantic Canada could also be done in the medium term, and in that timeframe it may be possible to turn part of the TransCanada gas pipeline into an oil line to Quebec.

“But looking five to 10 years out there is going to be a lot more bitumen production. We will need new markets, and those are going to require more options from (Kitimat) to California, to the East and to the farther east. Western Canada is going to need new markets. Over the next 10 to 15 years we will need to increase pipeline capacity by 1.5 to 2 million barrels a day.”

The message that Canada needs market diversification is getting a lot of traction. In a widely reported speech, Prime Minister Stephen Harper told a group in Washington that delays in the Keystone XL pipeline have greatly increased Canada’s interest in export pipelines. “We cannot be in a situation where really our one and only energy partner can say no to our energy products….The very fact that a no can be said underscores to our country that we must diversify our energy export markets.”

Tallying the Oil Reserves

How Canada made it to number three in the world

This article appears in the April issue of Oilsands Review

By Peter McKenzie-Brown
The issue of how much recoverable oil is in the ground in Canada has been a matter of political and commercial interest since the first surveys undertaken by the Geological Survey of Canada in the 1870s.

American eyes were opened to the true potential in April 2003 at a hearing of the U.S. Senate’s foreign relations committee. Convened to examine international energy security, the committee learned that Canada was an energy superpower. Alberta’s energy regulator had changed its method of calculating oilsands reserves, with the result that booked reserves in Canada suddenly rose from 5 billion to 180 billion barrels.

Canada suddenly stood in second place worldwide after Saudi Arabia. The Canadian Association of Petroleum Producers (CAPP) has since moved Canada into third place by accepting a calculation of Venezuela’s vast extra-heavy crude oil reserves which puts that country at the head of the pack.

No one knows what happened to the eyes of Canadian senators when they heard the first credible estimate of how much oil was in place in the Athabasca area, at a hearing that took place in 1888. The senators were provided with an estimate from R.G. McConnell of the Geological and Natural Survey of Canada.

McConnell’s calculation came from assumptions based on field and lab work: first, there were at least 1,000 square miles of bitumen-saturated sand in the area; second, the sands were 150 to 225 feet thick; third, and this result came from laboratory tests that involved boiling oilsand samples, that the bitumen content averaged 12 per cent by weight. Therefore there were about 30 million “long tons” of bitumen in place—roughly speaking, 220 million barrels. McConnell’s estimate was short by orders of magnitude; to put it in perspective, Canada now consumes about 200 million barrels every three months.

McConnell’s number was an estimate of resources in place, of course, and not a reserves estimate. At that time the very concept of reserves – hydrocarbons that are economically producible at current prices using current technology – was unknown. No one had any idea how to calculate what percentage of oil in the ground would ever see the inside of a pipeline.

Bedevilled engineers
Petroleum engineering gradually emerged as a profession, and engineers soon figured out how to book reserves from conventional oil and gas reservoirs. However, how to calculate oilsands reserves was an issue that bedevilled engineers and geologists for many decades. This led to some curious anomalies.

For example, when the $235 million, 45,000 barrel per day Great Canadian Oil Sands (now Suncor Energy Inc.) plant went on stream in 1967, it represented a substantial investment for the company and soon became a significant contributor to Canadian oil supply. The Canadian Petroleum Association (CPA-now CAPP) booked 6.3 billion barrels of oilsands reserves in its authoritative Statistical Handbook when the project went on stream, but reduced that number to about 1.5 billion in 1975. And when the 140,000 barrel per day, $2.3 billion Syncrude plant went on stream in 1978, the situation became even more absurd: the association didn’t add any new reserves. It was as though the oil was appearing out of nowhere. By the early 1980s a growing number of in situ projects, including Imperial’s Cold Lake activities, made the situation untenable.

According to Hans Maciej, retired vice president of the CPA, in the early 1980s he asked the group’s reserves committee, “‘Where the hell is [the oil] coming from?’ That was quite the discussion,” he recalls.

The committee eventually agreed that they had a problem, but there further endless questions about how to resolve it. “One thing was very easy,” says Maciej. “We could put whatever Great Canadian Oil Sands produced, let’s say it produced a million barrels that year and just add it to reserves – you know, wipe it out. Well that didn’t go very far. [However], after lengthy discussions we decided that we would credit every producing project, and every project that had approval and was sort of certain to go ahead. There was some judgment involved, but we said we would [book their reserves at] 25 times their annual production.” Maciej adds, “This was a very conservative estimate, [but] just to get things going we finally agreed on 25 years.”

CAPP’s reserves committee relies heavily on data provided by its member companies, and the association laboured mightily to stay on top of the country’s burgeoning oilsands reserves, which with special speed during the last 15 years as Syncrude and Suncor expanded, new mines came on stream and in situ projects multiplied.

However, according to CAPP’s research manager, Steve Rodrigues, it became increasingly difficult to get the necessary data from oilsands producers in the last decade – “not because of concerns about revealing competitive information, but because companies increasingly felt that they were not adding value by generating this information.”

One result was that CAPP’s calculation of oilsands reserves – historically, the Canadian standard – now compared to those being calculated by provincial and federal regulators. The numbers presented to the U.S. Senate’s foreign affairs committee were, after all, government numbers, and they were 24 times greater than CAPP’s.

Throwing in the towel
Where did the regulators get their numbers? In a recent presentation, Neil McCrank, who served as chair of the Alberta Energy and Utilities Board until 2007, offered the background. The “new focus on in situ development created a need for the regulators to find new ways of assessing and monitoring these projects…one of the major contributions made by the [regulator] was to recognize the need to re-categorize the in situ bitumen ‘resource’ to a ‘reserve’ where it was proven on the ‘core and cuttings’ analysis to be commercially viable with current technology.”

Bob Taylor, who was then Alberta’s assistant deputy minister for oil development, stresses that the Department of Energy does not play a role in these discussions. However, he says, the information used to recalculate reserves would have been rigorous and the models used would have been mathematically challenging.

“Every leaseholder is obligated to go out and prove up a resource on the basis of one well per section, or the equivalent of one well per section plus some seismic, so it might be one well every couple of sections with seismic lines connecting them so that you can get the stratigraphy. So what [the regulator] did was to have geologists look at each company’s assets,” while examining proven technologies and likely future demand. Using all this information, they created models that could generate highly credible reserves calculations.

Such was the origin of the proved reserves that caused so much excitement in Washington in 2003. According to the McCrank, the announcement of more than 173 billion barrels of oilsands reserves “was initially criticized, but after a stout defence of its scientific approach… the international oil and gas community accepted these reserves calculations.”

So did CAPP. In 2010 the organization threw in the towel as far as using its own method of calculation was concerned. An organization that has celebrated its independence from government since its earliest predecessor was formed in 1927 began using numbers from both Alberta and federal regulators as the basis for calculating oilsands reserves.

The association’s in situ oilsands reserves suddenly jumped by around 2,000 per cent, while its mineable reserves more than tripled. Canada’s industry had caught up with its regulators, and the results were parabolic.

Of course, reserves estimates will never be unanimous. The most widely accepted global authority on energy numbers, BP’s Statistical Review of World Energy, most recently puts Canadian oil reserves at 33 billion barrels, or tenth place. Venezuela at 175 billion stood in second place, while Saudi Arabia is the top dog at 264 billion.

We’ve come a long way since 1888, but we still have a way to go.

This article is part of a  series which reflects information from the Petroleum History Society’s current Oil Sands Oral History Project, which is recording the stories of oilsands pioneers in their own words. As with its previous oral history projects, transcripts and recordings will reside in Calgary’s Glenbow Archives. Peter McKenzie-Brown is part of the team of researchers/writers behind the project.

The Captain Takes a Bow

Suncor Energy starts the long goodbye to Rick George, the man who built it from broken to megaweight

This article appears in the February issue of Oilsands Review; photo from here

By Peter McKenzie-Brown
Bob McClements has had a long association with the oilsands industry. He was construction manager for Sun Oil Company’s (Sunoco) original Great Canadian Oil Sands plant and the first plant manager when it went on stream in 1967. When it commissioned that pioneering plant, Sunoco was one of the largest integrated oil companies in the world. In the 1980s McClements rose to its highest ranks, becoming president and chief executive officer.

When Sunoco was near the top of its game, McClements asked American-born Rick George—who at the time was in charge of Sunoco’s North Sea development and production, and had overseen construction of Europe’s first purpose-built offshore production platform—to take charge of the company’s Canadian subsidiary, Suncor Energy Inc.

“I flew over to London and asked him whether he would give up his position with an established operation in the UK and move to a totally different environment in Canada. After only a day, he agreed,” says McClements. “You have never met a more unassuming, low-key but brilliant executive in your life. He’s quiet and unassuming, but when he speaks you listen. He knows what he’s doing because he came up the ranks. He was given increasing responsibilities and he did well in every one of them.”

Headquartered in Toronto until 1995, George became Suncor’s president and chief operating officer in 1990; the following year the board appointed him chief executive officer. Also in 1991, McClements retired and Sunoco accelerated its policy of divesting upstream assets so it could focus instead on refining and marketing. Accordingly, it spun off Suncor as an independent entity.

Big mistake: Suncor had market capitalization of $1 billion when George took over. Today it’s about 48 times bigger, and 12 times larger than Sunoco. Rick George, who recently announced that he will fully retire at the end of July, was the architect of this spectacular business achievement. In his years at the helm of Suncor, McClements said with some understatement, “he has become the number one executive in the oilsands.”

Why did its owners divest Suncor? According to George, “We were actually going through a recession back in 1991-92, both here in North America and in Europe. It was a period of time at which the Government of Ontario [75 per cent owner] was struggling with paying their bills. This was an area they could liquidate. Sun Company had some issues around debt as well. It was just fortunate that both of them actually needed money at the time and decided to sell Suncor to the public.”

When George took over, Suncor’s primary assets included the money-losing oilsands plant, some service stations and a small refinery in Ontario. The oilsands business “really struggled with return on capital well into the mid-1990s [because of] high costs relative to low oil prices,” George said in a recent interview conducted for the Petroleum History Society’s Oil Sands Oral History Project. “There were 20–25 years of real struggle between when this industry got its first plant online and when it actually started to make enough money to make sense.”

Building an oilsands heavyweight
Assisted in the early years by Dee Marcoux, executive vice-president, oilsands, the first items of business during George’s presidency were to restructure the 60,000-barrel-per-day plant, deploy truck-and-shovel technology for mining, make major improvements to the processing plant, and expand capacity to 130,000 barrels per day by 2001.

In 1998 Suncor filed its regulatory application for Project Millennium, comprised of mining capacity increases and a new upgrader. The project was a dramatic expansion designed to increase production to 210,000 barrels per day. George recalls that, “about the time our board approved the Millennium Project, which was 1997, The Economist had a front page view that they expected prices to be at $5.00 a barrel for a long period of time…I think what they lost track of is that this industry moves through cycles and it will continue to roll through cycles as we invest, as we try to figure out where the next investments should be.”

Millennium was a good investment, he added. “We started the project when there were low oil prices. When we got the project done in 2002, oil prices rose and it was obviously a great win for our shareholders. I always think of oil companies as big deployers of capital. And I think the management and leadership of oil companies is really about making right choices at the right time.”

In 2001, Suncor announced its Voyageur growth strategy, a multi-pronged approach targeted to bring oilsands production to 500,000 barrels per day by 2012. The plan included a mine extension, third upgrader, and in situ expansions at the Firebag steam assisted gravity drainage (SAGD) project. The Voyageur strategy was slowed by the global recession, but not derailed. Its most significant piece, the Voyageur upgrader—now a joint venture with Total E&P Canada—is expected to be re-sanctioned in the near-term. George says the upgrader should reduce business volatility. “It should improve reliability. It’s going to be a project that will be online for 50 to 100 years…you’ve got to take a very long-term view of this business.”

And that long-term view rests a lot on in situ development. In addition to undeveloped leases and the MacKay River SAGD project acquired through Suncor’s 2009 merger with Petro-Canada, Suncor considers its Firebag assets to be a key piece of the future. “Firebag is in the middle of a lease we hold that has 9 billion barrels of recoverable oil,” George says. “So this is again an asset base that will be on production for the next hundred years in some form or another.”

Putting assets together
In 2009, George announced a $19.1-billion bid to take over Petro-Canada. With the merger’s success, Suncor suddenly had a much bigger refining and marketing presence in Canada, light oil and gas properties around the world and significant additional oilsands properties.

“If you look at it in a historic sense, we picked Petro-Canada off at the low point of the market, or pretty close to that,” he says. “I’d thought for a period of time about putting the assets together, particularly their downstream with our upgrading and our upstream made a lot of sense. The opportunity to drive synergies, to drive costs out the system—all of that was there in spades. I think it was a great move, made at the right time. And, you know, most mergers actually don’t drive shareholder value. This is one that did.”

George is competitive when it comes to production systems and oilsands technology, but collaborative on environmental issues. As one of the founders of the Oil Sands Leadership Initiative, he believes the industry should share “anything to do with safety, the environment, environmental improvement, anything on reducing our air, land and water footprints. This is important, very important.”

On the future of the oilsands sector
George says that even though he has been at the helm of Suncor for 20 years, the real excitement is yet to come.

“I think the next ten years in this industry are going to be some of its best,” he said, pointing specifically to technology around reducing the environmental footprint of operations. “It is going to astound people how quickly this happens and how well it happens.”

The step-changes will come particularly in the in situ area, he says. “The important thing to remember about SAGD is that is still a very, very young industry. [You’re going to see] a real take-off because of the critical mass of investment in technologies that will rapidly change how we do this. It will reduce water use. It will reduce energy intensity. It will make wells more productive. As wells get to the end of their life, we’ll figure out ways to extend that and recover more.”

George continues, “Listen, industry is looking at all kinds of ways to [improve efficiency], whether it’s use of solvents, surfactants, better downhole pumps, whether you eventually, once you get these caverns, use fire-flood. There are so many technologies out there that are being looked at, being researched, being tried in the field, you’re going to see this thing change rapidly, particularly over the next decade or so. It’s actually quite exciting.”

Suncor’s production has grown significantly under George’s leadership, and will continue as part of his enduring legacy. In the longer term, he notes that the company will “have production coming in from Fort Hills, eventually Joslyn, but also from Firebag, from MacKay River, from our two base mines. And this will feed this large upgrading complex that includes upgrader number one [constructed in 1967], upgrader number two (from the Millennium Project) and upgrader three which is Voyageur. The total capacity of that upgrading facility will be somewhere in the 550,000-barrel-a-day range.”

George leaves behind a strategic plan for Suncor to produce 1 million barrels per day by 2020. “We have the reserves to do it, the strategy to do it, and the environmental approvals for the projects. It’s really down to execution.”

On a cautionary note, he noted some worries the industry should think about.

“You’ve got to be very concerned right now about whether we have enough labour in this part of Alberta. The one difficult thing we have is this oilsands resource in a very remote area. You don’t have a nearby port, you have to bring everything in by truck or by rail. You always have to worry about these inflationary cycles, that we have seen and that we’re likely to see on a go-forward basis. So we just came through a big inflationary period, that 2005 and 2008 period. It’s been calm since the market collapsed in 2008 but…”

George’s final year in the company saw record production, record cash flow and earnings, and total debt way down, to $7 billion. Twenty years ago, could he have imagined that Suncor would become the largest oil company in North America?

“No. That would have been the most improbable thing. But you know what? It’s been an exciting ride. What I would say is, the potential to do those kinds of things is still out there. If I were, you know, 20 years or 30 years younger than I am today…. Opportunities still exist to do those kinds of things.”

Rick George will continue to innovate and lead. As he told the press when he announced his retirement, he won’t be leaving the sector. He’ll still be involved with the oilsands and technology development, but through smaller companies.

Saving Money with Monster Trucks

HOURGLASS: Lessons from the Oil Sands Oral History Project

Three stories tall, these trucks now seem like an obvious approach to 

ore delivery. That wasn't the case in  the beginning.

Retired Syncrude COO Jim Carter describes an oilsands mining technology revolution.

This article appears in the December Oilsands Review

By Adriana Davies

The haul trucks used in today’s oilsands mining industry are some of the biggest in the world—1.4-million-pound, 20-foot-tall, multi-million dollar behemoths ferrying 400-tonne loads of bitumen ore from the hydraulic shovel to the crusher at top speeds of 40 miles per hour. And this is the more agile and economic option.

In the 1980s, trucks and shovels began to replace burdensome and even more costly bucket-wheel and dragline equipment. The new system was first incorporated into overburden removal, and then for the ore itself—enabling oilsands mining producers to operate and expand in a more cost-effective and selective manner. One of the key people recognized for driving this revolutionary technology change is Jim Carter, former president and chief operating officer of Syncrude Canada Ltd.

Jim Carter was a graduate of mining engineering from Nova Scotia Technical College when he heeded the call to “go west, young man.” He had gotten a taste for mining work through summer jobs in Ontario while in high school, and his first job after graduation was with the Iron Ore Company of Canada in Labrador City, N.L. In 1974, Carter was enticed to move to Alberta by a former colleague. He went to work for Smoky River Coal Limited in Grande Cache, rising from mine foreman to mine manager and finally, mine superintendent.

It was when he headed up a provincial study examining mine lighting that he met Dennis Love, general manager of mining at Syncrude. Carter recalls Love’s comment to him about the operation: “Jim, we’ve got a bit of a challenge here with our mine plan. It’s not quite working the way we’d thought. We’re going to have to move to truck and shovel stripping of the overburden, and move our draglines and buckets onto oilsands.” It was an opportunity that the 29-year-old couldn’t pass up. In 1979, Carter went to work for Syncrude as manager of overburden operations.

He says, “The original plan had the dragline sitting on top of the overburden and then digging it and putting it into the pit all at the same time as casting up the oilsands. What happened was that the overburden would not stay at a steep angle. It wanted to go flat, and it contaminated the oilsands, therefore rendering that mine plan inoperative.”

These were the very early days of Syncrude, when various theories not only to do with the mining operations but also the chemistry of extracting the oil from the sand were being tested on an industrial scale rather than in the lab. Carter notes: “The whole industry was really viewed as a bit of a curiosity in those days. Nobody really believed that we were going to be successful with this very complex business of mining the oilsands and extracting the bitumen, then taking this very, very heavy oil and upgrading it to a light, sweet crude that was then usable in refineries to turn into gasoline and diesel fuel, propane and whatever. The world didn’t know much about the oilsands. Certainly, even in Edmonton it wasn’t really that well-known. Calgary, it wasn’t well-known. Toronto, they didn’t know about it at all. So, if you were going to get involved in something that was really a pioneering endeavour of the highest order, this was it.”

The other issue was the link between the oil business and mining; this was not a natural match. To merge the two operations, as was happening north of Fort McMurray, Alta., was viewed with great skepticism. But they were doing it, and in driving the shift to trucks and shovels, Carter was set to play a pivotal role.

His first big challenge was sizing up the geotechnical issues associated with the soft landscape.

“Because the oilsands are soft to traffic on, there wasn’t a lot of aggregate material around for building the roads, and yet we had to move these high volumes. I wanted to use the 170-tonne trucks because those were the largest in the industry at the time, and I knew that the unit cost per tonne-mile of moving a tonne with those was going to be lower than, say, an 85-tonne truck or a 50-tonne truck, even though the conditions were very soft,” Carter explains.

“The biggest challenge I had initially was convincing people there that we could do this successfully. Great Canadian Oil Sands at the time had tried the big 150-tonne trucks, and they didn’t have much success with them. They were switching their fleet back down to 85-tonne, mechanical-drive trucks. There was a lot of skepticism to overcome, shall we say. But we persevered on that and ended up being very successful.”

If existing trucks couldn’t do the work required, then, they would need to be redesigned. In Labrador City in the iron ore business, Carter had used a particular brand of 170-tonne truck called the Terex, which was made by GM in London, Ont. It worked well in severe conditions and had a robust drive system. Carter had actually spent time with the manufacturer in their engineering offices and noted that they used the same drive motors in this truck as they did in their railway locomotives—a technology that could help move across the soft oilsands mine floor.

“The locomotive, when it goes to get started, starts off with the electricity going to the motors in series, and then it switches to series parallel, and then to parallel once it gets rolling and gets its speed up. I had thought this would be a great advantage to use in the oilsands because the trucks normally have power going to the wheel motors in parallel.” He and other Syncrude representatives asked GM whether they could do the series parallel arrangement on the trucks, and GM agreed.

The result was a design that enabled the operator to switch from parallel into series when he got on the waste dump, when the rolling resistance was really high in the soft conditions. Carter says, “It increased the torque to the rear wheels by about 45 per cent, so it made a tremendous advantage for getting across these soft waste dumps. Now, of course, whenever you do that, you’re putting more horsepower into the components, so we needed to build a bigger axle, a larger-diameter axle, which became known as the tar sands axle on those trucks. It gave them the capacity to haul a 200-tonne payload across the soft conditions. It was really then that we realized we could make these trucks work, and we used radial tires. Radial tires tend to have a greater footprint, so they got the ground-bearing pressure lower, and that enabled them to traffic over the softer conditions.”

Carter says that once the Syncrude team started using trucks and shovels for overburden removal, other opportunities for the system presented themselves.

“The first year that we had the fleet running, it was designated as a six-million-cubic-metre-a-year fleet, and we actually moved 10 million cubic metres within the first year, so it was a great success. It was the initial success of that particular fleet that enabled us then to really look at trucks and shovels on a go-forward basis. It meant that we weren’t going to be limited to bucket-wheel excavators and conveyors and draglines. So that opened up opportunities for other technologies to be introduced into the mining system.”

By the late 1990s, the truck and shovel system was well underway in replacing draglines and bucket-wheels in the oilsands industry, a technology change that has enabled the cost-effective expansion of mining operations. Syncrude retired its last bucket-wheel and dragline in 2006.

Carter steadily rose through the ranks at Syncrude, eventually taking on the role of president and chief operating officer in 1997, which he held until retiring in 2007.

This article is one in a series reflecting information from the Petroleum History Society’s Oil Sands Oral History Project, which is recording the stories of oilsands pioneers in their own words. As with the society’s previous oral history projects, transcripts and recordings will reside in Calgary’s Glenbow Archives. Adriana Davies is part of the team of researchers/writers behind the project.

12 trends for 2012

Oilsands developers gather momentum and mature in an increasingly complex business environment; this article appears in the January issue of Oilsands Review

It takes more than a global cardiac arrest to slow oilsands activity down for long. The sector has now entered what some are calling its “second boom.” The industry is feeling good as economics, supply and demand push bitumen expansion. Characteristically oilsands, the coming year promises to be laced with tests, trials, achievements, and advancement.

By Peter McKenzie-Brown and Deborah Jaremko
      With files from the Daily Oil Bulletin

Human resources: the cost of a labour shortage grows higher
The oilsands sector is moving into a full-blown labour shortage, and the associated cost implications for new projects will be on the rise in 2012.

“A number of indicators demonstrate that the labour market in Alberta is already tight,” says Chris Lee, a partner with Deloitte whose group recently prepared the report Gaining ground in the sands 2012: A deeper look at major trends and opportunities in the oil sands sector. “Last time around [in 2007-2008], this resulted in a labour shortage, with certain trades hit especially hard, and there was a significant switch of the risk to getting labour from engineering, procurement and construction to the owners. Oilsands projects will continue to be a talent drain.”

Lee says that particularly going into winter, when conventional oil and gas drilling heats up, those projects compete with the oilsands sector. And the challenge is not just in staffing for mining and upgrading “megaprojects.” The relatively smaller-scale steam assisted gravity drainage (SAGD) projects that are multiplying offer new complexities. Construction of these projects generally takes place in “bite-sized” increments replicated in stages.

“SAGD plants, steam generation, and so on require process-oriented skills more akin to refining, pulp and paper, and water handling,” says Lee. Not prevalent in the conventional oil and gas industry, “these skill sets may be harder to attract to places like Fort McMurray. This all adds up to increased labour costs in the next few years – especially when you get into periods of high investment there is a lot of competition for talent.”

The Petroleum Human Resources Council of Canada arrives at a similar conclusion although it begins at another place. According to that not-for-profit organization, the oilsands sector—which it estimates will have to hire up to 15,000 new workers between now and 2020--has challenges attracting qualified people because of its remote location, the competition for skilled labour when several large projects start at the same time, and the industry’s negative public image.

Non-labour cost inflation will stay relatively low
Labour may be the highest piece of oilsands project costs, but there are other inputs that can significantly alter the bottom line. Greg Stringham, vice-president of oilsands and markets with the Canadian Association of Petroleum Producers (CAPP), notes three of the major the indicators that forecast non-labour inflation in the oilsands: the price of steel, the price of natural gas, and the cost and availability of capital. Each of those three now reads better than it did before the global crash.

Steel is a globally priced commodity, and prices could spike rapidly (as they did in 2008) if there were sudden growth in some of the larger developing countries. At the moment, however, its price is roughly the same (US$600 per tonne) as it was in 2007. Natural gas, of course, is important as a fuel source. In 2007 natural gas was averaging between $5-$7 per gigajoule, but according to the Natural Gas Exchange, has averaged approximately $3 per gigajoule since January 2010. The price has dropped and it’s stable.

Stringham adds that, “In 2007 we had a problem with the availability of capital. That isn’t a problem anymore. There is much more East Asian interest in the oilsands, and even some coming from India.” For companies that are capital constrained, he says that, “We’ve seen many cases where the industry finds capital through another company or even overseas.” Also, of course, interest rates are near the bottom of the chart.

New business combinations and sales will help with expansions
Although it is difficult to predict merger and acquisition (M&A) activity, it is clear that in 2012 the oilsands sector will see at least a few important new transactions. Alan Tambosso, president of M&A leader Sayer Energy Advisors, for example, confirms that his company is brokering some raw oilsands properties but can’t comment until after the deals are done.

But there are at least a couple of transactions already in the works and out in the public domain, such as Connacher Oil and Gas Limited’s initiative to find a joint venture partner to enable its planned 24,000 barrel per day expansion of the Great Divide SAGD project, as well as Cenovus Energy Inc.’s efforts to execute a execute a transaction involving the proposed 90,000 barrel per day Telephone Lake SAGD project and some surrounding leases. At the end of the third quarter Connacher said it expected to receive bids by the end of 2011, while at the same time Cenovus said that interested parties were viewing transaction information.

There are also cases such as Oilsands Quest Inc. and Andora Energy Corporation. The future of Oilsands Quest, its assets and proposed SAGD project in northwest Saskatchewan, is now up in the air—the company has been under a strategic review for months, and recently entered into creditor protection. Andora Energy, a subsidiary of Pan Orient Energy Corp. holds oilsands leases in the Peace River region at Sawn Lake, and has plans for a SAGD demonstration. Its strategic review process was initiated in February 2011 and closure of this process has not been indicated.

And let’s not also forget the growing interest of international players in the oilsands industry and their penchant for M&A—that is unlikely to quit in 2012.

Deloitte notes that, “National oil companies with an expressed interest or current investment in Canadian oilsands will continue in 2012 to play an evolving, if somewhat unpredictable role in development of the resource.”

That said, as Tambosso points out, one generally doesn’t know what's in the M&A pipeline until the deal is done.

Learnings from other sectors help the oilsands move into the future
According to Deloitte, there are early signs that the oilsands industry is moving away from legacy “staunchly independent or even adversarial” oil and gas attitudes and toward strategies that borrow models from other sectors in order to address complex issues such as new technology development, and environmental and social sustainability.

“Ideas about municipal water treatment jump to my mind,” says CAPP vice-president Stringham, citing a 2010 initiative where CAPP worked with the Ontario and Alberta governments to organize a “clean and green” workshop in which people from many industries and sectors, including academia and researchers, discussed ideas the oilsands sector could use to clean up its act.

“We basically started with the concept, ‘Bring your good ideas for water treatment, for reclamation and for other kinds of environmental processes and let’s see if there’s anything we can apply,” Stringham says. “Some of the ideas were already being developed for the oil industry through existing partnerships but others were brand new.”

Deloitte argues that by using ideas from the automobile, high tech and other sectors, oilsands producers can take advantage of contemporary manufacturing approaches. “These can reduce cycle times, reduce operational costs and eliminate non-productive activity.”

Producers move closer to commercializing in situ frontiers
Two major frontiers for the in situ oilsands industry—bitumen carbonates and SAGD in the Grand Rapids formation—are coming closer to commerciality, and further progress is expected for 2012. This could mean the potential unlocking hundreds of billions of barrels of currently stranded resources.

Laricina Energy Inc. is operating in both of these resource plays, deploying SAGD at Saleski in the Grosmont carbonates, and at Germain in the Grand Rapids. The 1,800 barrel per day Saleski pilot, which produced first oil in March, saw cumulative sales as of Sept. 30 of 26,300 barrels of blended bitumen.

"We are in the very early stages of unlocking this vast reservoir and, given our progress to date, we consider the results positive," the company says. In an investment note, Peters &. Co. described the oil production as a "positive initial achievement" as the Saleski pilot is the first large-scale production test in the Grosmont since Unocal’s operations in the early 1980s, but it added that well rates need to improve to demonstrate commerciality.

Laricina says that, "Based on our work to date, we expect that in the second half of 2012 the SAGD performance curve will be at a stage in maturity allowing us to initiate solvent injection, thereby beginning the [solvent-cyclic] SAGD phase of our pilot plan."

Athabasca Oil Sands Corp. (AOSC) is also advancing piloting in the bitumen carbonates. Earlier this year the company began an electric-heat pilot in the Leduc formation which it said received favourable results including indications of uniform heating of the reservoir and fast ramp-up and wider well spacing. In October AOSC filed its application for a 6,000 barrel per day pilot of the technology, expecting to start construction in 2012 and production in 2014.

Both Cenovus Energy and BlackPearl Resources Inc. recently fired up SAGD pilots in the Grand Rapids formation. As of the end of the third quarter, BlackPearl said its single well pair BlackRod project was ramping up production, currently at about 200 barrels per day. During the first quarter of 2012 the company plans to file an application for a 40,000 barrel per day SAGD project on those leases.

The Cenovus Grand Rapids pilot is located on the company’s Pelican leases; it began producing in the third quarter of 2011. The company has filed for regulatory approval to expand the project up to 180,000 barrels per day. According to executive vice-president Harbir Chhina, the company’s original target at the pilot was to get “about 600 barrels per day at a steam to oil ratio of three on a cumulative basis, and so if we’re seeing that ratio on an instantaneous basis we’re feeling pretty good.” He adds, “We want to try other unique things that we’ve learned from the last nine months or so in that pilot.”

Laricina is currently building a 5,000 barrel per day demonstration project at Germain, and recently filed its application to increase capacity to 155,000 barrels per day.

Solvents continue to be all the rage for in situ producers
More and more in situ producers are piloting solvent-assisted SAGD projects. “Solvents are the next big thing in situ development,” says CAPP’s Stringham. “Almost every company is experimenting with it now.” Companies using solvents include Connacher Oil & Gas, Cenovus Energy, Japan Canada Oil Sands, Imperial Oil Ltd. and Suncor Energy Inc. “Not only is it an effective tool for production. It’s also more environmentally responsible” since it reduces the amount of heat needed to mobilize the bitumen.

Fortunately for the companies wanting to use solvents, a lot of natural gas exploration is being directed toward liquids-rich gas--especially in shale gas development--because those liquids are much more valuable than dry natural gas. And, the design for in situ oilsands projects adding solvents is to recover as much as possible for re-use. “For the most part once a company has its solvents,” says Stringham, “there isn’t much need for more of the stuff. There is an initial demand upfront and a certain need for makeup demand.”

Collaboration grows as key to managing environmental issues
In a recent interview, Suncor president and chief executive officer Rick George said the oilsands industry should “share anything to do with safety, the environment, environmental improvement, anything on reducing our air, land and water footprint.” Given that perspective, it isn’t surprising that Suncor is one of the founding members of the Oil Sands Leadership Initiative (OSLI)—a group of major producers that has agreed to share technologies and best practices in these important areas.

According to CAPP’s Stringham, “Collaboration is the big topic for improving environmental issues. It is a growing initiative. Environmental issues are not a competitive issue, but something that needs to be worked on collaboratively. The leading edge is the Oil Sands Tailings Consortium.”

Deloitte’s report notes that, “The associations being forged now will set in motion the expectations and rules of engagement that will carry forward when addressing even bigger picture issues requiring even greater universality and solidarity.” For this to happen, says the firm, the industry will need “a wider representation of both large and small operators…to truly push ahead.”

Legislation for a single regulator planned to be tabled
The administration of Alberta Premier Alison Redford plans to establish a one-stop regulator for oil and natural gas projects in 2012, Energy Minister Ted Morton said in early November.

Alberta's previous Progressive Conservative administration under Premier Ed Stelmach and Energy Minister Ron Liepert promised to establish a "one window" regulator for the upstream sector. For example, operators would presumably be able to file a single application instead separate applications with the province's environment and energy departments.

"That's something that we're going to continue to pursue. [Environment Minister Diana] McQueen and I will work on that together," Morton said. "And we have some draft regulation now that we hope to use as a discussion matter with industry over the next several months, and would hope to move to legislation sometime next year.”

Threats build close to home
University of Alberta economist Andrew Leach says the biggest threats to the oilsands sector right now are not in its carbon footprint. Rather, he zeroes in on two problems closer to home: issues from First Nations communities, and Canada’s endangered species legislation.

Leach acknowledges that oilsands development has created a surge of employment in First Nations communities in the oilsands areas. However, there is a great deal of hostility towards the industry in aboriginal communities where there are no obvious economic benefits, for example along the proposed Gateway Pipeline right-of-way. (Another hot button issue, of course, is the tanker traffic shopping “dirty oil” along the B.C. coast.) Those issues could stop the line.

Leach admits that he is no expert on land disruption and its effect on wildlife. But what he does know about are economics and the value people place on environmental damage, "... and if you're going to kill something with your industry what you do not want to kill is something that looks like Bambi, plain and simple…threats to woodland caribou could threaten the industry’s social license to development.”

Alberta’s first BRIK refinery likely to be sanctioned
After being delayed in 2008 due to strained economics, it looks like 2012 be the year that North West Upgrading Inc.’s Redwater bitumen refinery will be sanctioned, processing volumes both from partner Canadian Natural Resources Limited as well as the Alberta government through its bitumen royalty in kind program (BRIK). Detailed engineering for the first 50,000 barrel per day phase of the project began in the first quarter of 2011.

Canadian Natural says that, “project development is dependent upon completion of detailed engineering and final project sanction by the partnership and approval of the final resulting tolls. Board sanction is currently targeted for 2012.”

The $5 billion project would then be up and running by 2014, and although it is a new step for the province in deploying BRIK, it does not necessarily signal more Alberta-fed upgrading in the province.

During her recent leadership campaign, premier Redford said that “There should be more bitumen upgrading in the province, but only if the market can sustain it. The government should not generally play a role in this sector except in special cases such as the Northwest upgrader.”

Oil prices: West Texas Intermediate takes a bow as the main North American benchmark
“Where once we could look to West Texas Intermediate [WTI] for direction in pricing, the global stage has changed,” says Ralph Glass, a vice-president at AJM Deloitte. “Today, the UK’s Brent reference price is the benchmark. Brent prices have an impact on the North American market because internationally priced oil is imported into both the U.S. and Canada.”

Glass says several international factors could affect oil pricing: “These include uncertainty in respect to whether OPEC can increase production significantly if world demand rises. How much success will Libya have increasing its production levels? There are also issues related to political stability in the Middle East and to Europe’s financial crisis.”

The quest to reach the Gulf Coast and tidewater is far from over
If Canadian crude had significantly expanded access to tidewater for export, the prices it receives would compete with Brent rather than WTI.

The November 2011 decision by U.S. authorities to investigate new routes for TransCanada Corporation’s proposed Keystone XL pipeline expansion to the U.S. Gulf Coast, delaying a decision for at least a year, was a blow to the oilsands sector. There remains confidence, however, that more Canadian barrels will eventually reach the markets they need.

According to the University of Alberta’s Leach, “it’s important not to take this decision as an anti-oilsands measure. At least in part, it’s a reaction to high-profile oil spills in the United States by Canadian pipeline companies.” He also suggests that TransCanada may have been “a bit high-handed” when it planned the line.

The transportation sector is scrambling to fix the problem. TransCanada is working on selecting a new route. Enbridge Inc. hopes to increase Gulf Coast access through its Wrangler Pipeline using existing rights-of-way from Cushing, Ok. The plan is to have Wrangler in service in 2013. The company also recently paid $1.5 billion for a half interest in the underused Seaway Pipeline, with the idea of reversing the line so it can take oil south from Cushing. Closing of this transaction and regulatory approvals are anticipated in 2012.

This year will also be significant for Enbridge’s proposed Northern Gateway pipeline to Canada’s west coast, as public hearings begin in January. Approximately 4,000 people have registered to give oral statements.

According to Robin Mann, president of AJM Deloitte, “my sixth sense says Gateway will go ahead. [Prime Minister] Harper has his majority, and he understands the significance of the line. He’ll make it happen.” He adds that both Keystone and Gateway “are important, but I think Gateway is more critical” since it will open up Asian markets to Canadian oil.

In-situ Step-change

How underground shafts and tunnels changed the future of the oilsands

This article appears in the December issue of Oilsands Review

By Peter McKenzie-Brown

The year was 1976 and the place was a small town called Yarega – about 600 miles northeast of Moscow, near the Arctic Circle. A group of Albertans had gone there to observe a Soviet “oil mine.”

The Soviets had constructed shafts and tunnels into a heavy oil reservoir. Local workers were pumping steam into the reservoir through angled drill holes and production was taking place within the mine. A mining engineer among the Canadians, Gerry Stephenson, describes the project: “The wells that were injecting steam were drilled from an upper level of tunnel, which was above the heavy oil reservoir. So the injection wells were drilled from above but from tunnels. The recovery wells were drilled from tunnels below.”

According to Maurice Carrigy, vice-chair of the Alberta Oil Sands Technology and Research Agency (AOSTRA), “They had a tap, you know like a tap you would see in plumbing, a bathroom tap, and they would turn that on and off to get the oil out.”

Chronically short of cash, the USSR was hoping to sell the technology to the Canadian oil industry. The visit in part reflected a 1972 technology-sharing agreement between Canada and the USSR – one that collapsed in ‘78 when Canada expelled 13 Soviet officials for trying to infiltrate national security services.

The Canadians were not impressed with the oil mine, but they were intrigued. According to Carrigy, it led to a “total revolution in the concept of what you could do with bitumen that you couldn’t do in a traditional reservoir.… You got (the bitumen) into a form where it was either emulsified or liquefied so that you could produce it.”

At least one other group of Canadians had visited a Soviet oil mine. Hugh Lieper, who chaired Canada’s petroleum committee for the technology sharing agreement, also visited one in 1976. He describes being hoisted 800 feet into the mine in an elevator that swung wildly from side to side. At the bottom of the shaft, he found the oil being collected in a large open pit on the operations floor. “When I asked whether the electrical motors on the site were explosion-proof, no one knew what I was talking about.”

AOSTRA’s Carrigy puts the impact of his group’s visit to the Yarega oil mine in perspective. While Canada didn’t use the primitive Soviet technology, it gave credibility to “the idea that we could go below (an oilsands reservoir) instead of working from above.” That way “we could use gravity as the driver in getting the oil out. That would be natural. It would come down and flow in and then we’d take it from below rather than pulling it up to the surface.”

Adds Stephenson, “the system was definitely working, but the mine was very, very primitive. The tunnels were tiny. They weren’t mechanized at all. The piping systems were not much better than you would find in your garden. But it demonstrated that if you heat heavy oil, it will mobilize, it will be possible then to drain it, and if you put in wellheads below the reservoir, you will get production without pumping.”

The Mac of SAGD
A few years after the Canadian expeditions to the USSR, the legendary Roger Butler began developing the two-well SAGD concept, which eventually took the form in use today: injecting steam into a horizontal well and collecting oil through a parallel well below. Clem Bowman, who worked at Imperial Oil with Butler, says he actually developed the theoretical model for SAGD in the early 1970s. However Chi-Tak Yee, who was Butler’s first graduate student at the University of Calgary, says he once saw a document dated 1969 in which Butler had sketched out his preliminary ideas.

Whatever the facts of the matter, in the early 1980s the time was ripe for radical experimentation.

The AOSTRA’s first chairman, Bowman picks up the story. According to him, one day Gerry Stephenson came into his office and said “The oil companies have got it all wrong. The idea of drilling vertical wells into the oilsands and only contacting the pay zone for the few metres where there’s bitumen and having to put multiple wells down in these grid patterns just doesn’t make sense. I’m a mining man and the logical thing to do in a mine is to put down a shaft and to drill horizontal wells from that shaft and then every foot of well that’s drilled is in the pay zone.” Stephenson added that he had gone to the oil companies with this idea without success.

“And so he came to my office and sat there and made his plea that we should build a facility, put down a shaft and he had worked out what the costs would be,” Bowman continued. “According to his numbers, drilling a shaft into the deposit is not an expensive operation and the coal companies know how to handle methane in spades. So we put together a concept called the Underground Test Facility. No oil company would put any money into it but (petroleum executives on AOSTRA’s board) said they would support it technically and they’d have people help us on it.” For the only time in its history, the government agency paid full fare – and for what seemed a most speculative idea. Total budget for shafts, tunnels and infrastructure was about $30 million.

As Bowman continues, “It seemed this was the obvious time to test (Roger Butler’s) principle of gravity drainage.” Butler had left Imperial oil to become part of AOSTRA, and he became a member of the technical team. Maurice Carrigy was the project executive. Today a vice president of MEG Energy, Chi-Tak Yee says that “one of the most fortunate things that I was involved with was the Underground Test Facility project that was essentially the birthplace of SAGD. Think of (the UTF) as the Mac of SAGD development.”

First photo taken under the oilsands;
Stephenson in centre

According to Carrigy, “although we did contemplate going right into the oil sands, we thought it would be better to go down below the oil sands, put the tunnels in a secure and safe place” – a layer of limestone – “and then drill upwards” into the reservoir.

The magnitude of the UTF is hard to imagine. Sinking the shafts was done with a drill bit almost four metres in diameter weighing 230 tonnes. The two shafts were 223 metres deep and neither one deviated from the vertical by more than an inch. As a safety measure, AOSTRA constructed two parallel tunnels through the limestone. More than a kilometre in length, the tunnels were five metres wide by four metres high.

A Subway to the Wellhead

At the UTF’s official opening on June 29th 1987, a senior executive at Shell Canada – up to that time he had been a critic of the project – went to Stephenson and said, “It’s really not a mine, Gerry, is it? This is really impressive. It’s like a subway to the wellhead.”

Then came the tests. The Phase A pilot involved three well pairs 70 metres in length, each with 40-50 metres of exposure to the McMurray formation. According to Stephenson, “steam was injected and the first experiment with SAGD wells began. After a year or so, it was obvious the system was working.”

That was the beginning of a turnaround within the industry, which soon decided to get financially involved. Ten companies each contributed $16 million to the project. That funding enabled the test crew to complete Phase A and to move on to Phase B. It also funded several years of additional experimentation.

Phase B involved another three well pairs, 70 metres apart. According to Stephenson, “the effective length in the reservoir was 500 or 550 metres. They resembled a commercial development” despite having only three producing well pairs. Project engineers expected production to reach about 1,800 barrels a day.

What was the result? “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place,” he says. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area that we’d expected, so obviously we didn’t need to drill the well pairs as close together on Phase B as we did on Phase A, so we opened them up. Anyway, on Phase A the figures were 65 percent recovery – way beyond what we’d estimated. Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The petroleum industry soon began to develop SAGD projects from well pads. According to Stephenson, however, there are many reasons why SAGD is better done from tunnels underground. “You don’t disturb the surface to the same extent. You can use gravity to your full advantage.” And, he adds, surface schemes require a high-capacity, expensive pump for each producing well. They cost a lot to buy and a lot to service.

Also, he says, “it costs more to pump through a multitude of  8-inch pipelines than it does through a single 18-inch pipeline in a shaft. Another advantage is that you can drill more accurately from underground, and you get better recovery because you can use lower steam pressures. Your production might not be quite as high, but your recovery of the bitumen is going to be better, because you’re allowing a slow process of heat soaking upwards by thermal conductivity.”

He claims still other advantages for the system. “You’re operating in an underground climate in a tunnel. You're doing all your drilling and completion of wells as well as your process manipulation work in a safe working environment at a temperature of 58 F year round and with no snow and ice to hinder and delay your work. You can operate 24 hours a day, 365 days a year, instead of being confined with your drilling and your completions to those periods when you can drill on the muskeg and so on. You can do all these things in a safe environment that allows you to work all year long.”

A visionary but not a dreamer, Stephenson acknowledges that the system also has disadvantages. One is the need for upfront capital: until you’ve constructed the shafts and tunnels you can’t do any drilling at all. Also, of course, some reservoirs simply don’t have the geological features needed to make the system work.

In the latter 1990s the UTF was acquired by Devon Energy, which then sold it to Petro-Canada. When Suncor Energy acquired Petro-Canada, it also acquired the UTF – now known internally as its “Devon Project.” Petro-Canada developed abandonment plans for the facility, and unconfirmed reports say the ERCB approved them. It’s still intact, ‘though its future is in question. 

Reaching $1,000,000,000

Shell Canada marks a major milestone with its aboriginal oilsands contractors

This article appears in the October issue of Oilsands Review 

By Peter McKenzie Brown

As the CEO of no fewer than 15 companies, Phil Peddie is a pretty busy guy.He is the chief executive officer of the Fort McKay First Nation, and it's a hefty job.

Seven of the companies he leads are wholly owned by the Fort McKay First Nation. The rest are joint ventures – 51% owned by the band and the balance owned by non-aboriginal business partners. His companies specialize in doing oilsands-related work, and they couldn’t possibly be closer to their customers. Oilsands mining companies encircle the aboriginal community.

Fort McKay is smack in the middle of the cluster of mining projects now producing or under development – those operated by CNRL, Imperial (Kearl), Shell, Suncor, Syncrude, and Total (Joslyn). The community’s location and business acumen are fascinating in themselves, but to put their success in perspective it is worth noting that over the last six years, the Athabasca Oil Sands Project (AOSP) contracted more than $1 billion in services and supplies with aboriginal companies– many of them at Fort McKay. In 2008 alone, more than C$210 million local spending went towards purchasing supplies and services from such aboriginal groups as the Athabasca Chipewyan First Nation.

To put that number in perspective, Syncrude – which began operations in 1978 – couldn’t boast $1 billion of total work with aboriginal contractors until a quarter-century after start-up.

As the crow flies, the closest plant is part of Shell-operated AOSP. Owned by Shell, Chevron and Marathon, the project includes the Muskeg River and Jackpine mines and the Scotford upgrader, near Edmonton. According to the Shell consortium, more than 70 aboriginal businesses participated in the $1 billion spend. Collectively, they provided a wide range of services and products. These include facilities management, general maintenance works, technical expertise, earthmoving, health and safety services, bussing, camp construction, catering and waste management, and many others.

In terms of social and economic renewal, the rise of aboriginal business in the oilsands areas has come at a critical time. One reason is that there are chronic shortages of labour in the oilsands areas, and they are unlikely to go away. Aboriginal communities can provide reliable local labour. The oilsands industry has become Canada’s largest employer of aboriginals by far.

The other reason is that these communities have traditionally been important sources of untapped entrepreneurial talent. To help develop this area, for a quarter of a century the industry has been helping develop aboriginal entrepreneurs to meet its business needs.

Local Labour

According to Shell vice president John Rhind, this is more than a win-win. “Labour shortages are likely to be with us for a long time, and aboriginals have traditionally been an under-represented demographic for the industry. They can bring a lot of value to the oilsands producers. This not only applies to the Fort McMurray area, but to all producers throughout northeastern Alberta. There’s no question SAGD operators can benefit as well.”

According to Rhind, the surge in First Nations businesses was partly driven by the region’s big producers. “Some years ago the oilsands companies around Fort McMurray made a strong commitment to engage with the communities in the area. These included aboriginal communities – Métis and First Nations. But it included other communities as well – for example, non-aboriginals who were not recent hires, but had lived in the area for many years."

These stakeholders in the Fort McMurray area – Rhind calls them "citizens of the environment” – have “a lot to gain from this, and we thought it was important to make this commitment….It isn’t about the dollars. It’s about members of the community participating in our business.”

Until he was appointed to his present position last March, Rhind was general manager of operations for Albian Sands, the joint venture company that operates an oilsands project for the Shell consortium. I asked him to tell me about the project’s aboriginal partnerships. “We’re about developing the ability of aboriginal people in Fort McKay so that when the oilsands is done, decades or centuries in the future, we will be leaving a sustainable culture and economy behind.”

Shell and the other operators in that area have done this in a number of ways, Rhind says. For one, “we look for aboriginals to become part of our workforce.”

He says Shell’s experience is that there is “no difference at all between a First Nations employee and one from any other background….The key is that first that you have to train your employees. Be clear about what expectations the company has of them and give constructive feedback. Second, if there is any systemic racism you have to be relentless in getting it out of the system. That enables people to contribute at the level at which they’re capable, but it also removes any barriers that might stand in the way of their becoming successful in working in an oilsands business. Once you have a cohort of aboriginal workers in the company which includes people in management, then you have a sustainable system that welcomes new aboriginal employees.”

Part of that welcome arrives through Shell’s aboriginal employee network, an internal human resources system developed to support First Nations, Métis and other aboriginal employees. According to a Shell statement, it “draws together aboriginal and non-aboriginal employees and provides a diverse range of learning and social opportunities for employees.”

Local Business

According to the Athabasca Tribal Council, which represents the interests of five Treaty Eight First Nations in northeastern Alberta, there are approximately 5,000 Cree and Dene people in the region. Besides employing aboriginal workers from these communities directly, Rhind notes that his company and others in the area have “appointed people to work with aboriginal individuals to help them develop successful businesses. We want to work with local aboriginal businesses successfully and in a mutually beneficial way.”

That’s the view through the corporate window. Multiple-CEO Phil Peddie picks up the story. He operates in the world of aboriginal entrepreneurialism.

Peddie oversees a large group of companies which collectively employ nearly 1000 men and women. A Shell news release quoted him as saying that “working with Shell and the Athabasca Oil Sands Project over a number of years has enabled the Fort McKay group of companies, joint ventures and entrepreneurs to grow, and has brought significant opportunity to develop skills, establish businesses and further our community.” This reporter phoned to find out more.

The Fort McKay First Nation has seven wholly-owned companies which, collectively, provide a large number of services mostly targeted at oilsands-sector project maintenance and development. These include, for example, light earthmoving, fuel distribution, fleet maintenance and a variety of environmental services: According to the band’s business website, “Our land reclamation services encompass the entire process from start to finish.”

The Fort McKay Group also has a number of joint venture companies in which the aboriginal community forms partnerships with established non-native companies to provide specialized services. For example, Fort McKay Landing Services, which specializes in camp construction, is a partnership with modular facilities giant ATCO Structures and Logistics.

From the First Nation’s point of view, there are many reasons to like these joint ventures. For one, the community has control of a business that is adequately financed. In addition, the venture transfers managerial and technical skills to the local community and contributes to local employment. Also, of course, for their businesses the status Indian shareholders receive their earnings tax-free.

According to Peddie, each of these companies is operated by a management committee with equal representation from both sides. “It brings together the technical and management expertise of our partners plus the labour we can supply. Our unwritten goal for each of these enterprises is 30% aboriginal content. In every business we own, our goal is 30%.” Achieving that percentage of aboriginal employees isn’t easy. “It’s difficult to achieve because the unemployment rate in Fort McKay is quite low. A lot of people are employed by Shell, Syncrude, Suncor, and so on, so for some of our companies we are below that mark and for others we are above it.”

Oilsands employment has transformed the local economy, he says. “Only 30 years ago, the people of this community were primarily trappers. A European boycott of Canadian furs destroyed the trade,” and very tough times followed.

Now a hamlet of some 700 souls, Fort McKay is mainly composed of status Indians from the Fort McKay First Nation. The social fabric also includes a Métis community of perhaps 200, non-treaty aboriginals, and small numbers of individuals of other origin. The Fort McKay Group of Companies can’t strictly draw from the local community to reach its “aboriginal content” goals because most working residents hold fulltime jobs with Syncrude, Shell, Suncor or another big local producer.

According to Peddie, 13% of local people work for the Treaty Eight band’s wholly-owned companies. A similar number work for its JV partnerships. “So to try to reach our content quotas, we employ aboriginal people from all over the region.”

Being Canadian

Like representatives of other companies in the Fort McMurray area, John Rhind says that “working with aboriginal contractors is one way Shell benefits the communities where we operate. We announced our billion-dollar milestone to thank the businesses and partners we worked with during those six years.”

Shell’s achievement is impressive, and certainly something to brag about. However, it is worth remembering that Syncrude began developing business partnerships with aboriginal communities in the 1970s: During the construction of the plant, chairman and CEO Frank Spragins visited aboriginal communities, and let contracts before the plant produced its first barrel of oil. This policy was spurred by Spragins’ successors, Brent Scott and Eric Newell. The company’s ground-breaking efforts were both visionary and transformational.

As the company’s initiatives were coming to fruition, Newell addressed the triumph of Syncrude’s pioneering efforts in a speech given15 years ago. “We’ve brought two decisively different belief systems…those being business and spiritual… together in understanding and cooperation,” he said. “We’ve drawn strength from each other to leap the hurdles and head down the road side by side – on a journey not only to secure Canada’s energy future, but also to explore what it really means to be Canadian.”

One outcome of Syncrude’s initiatives is that today, Phil Peddie is a pretty busy guy.

Mary Clark Sheppard on her Father, Karl Clark

Mary Clark Sheppard on her father - Karl Clark - and the quintessential oilsands research breakthrough.

This article appears in the September issue of Oilsands Review. 

By Adriana A. Davies

The renowned "father of the oilsands," Karl Clark spent his entire working career technically outside of his discipline. An inorganic chemist by training, Clark's life work was in organic chemistry. His daughter and biographer, Mary Clark Sheppard, recently described his path.

After being awarded a Ph.D. in Chemistry by the University of Illinois in Urbana in 1915, Clark went to work for the Geological Survey of Canada. Because he had previously done soil surveying in Ontario, he was assigned to road materials research.

In July 1917, Eugene Haanel, Director of the Mines Branch, asked Clark to read a collection of working papers written by Sidney C. Ells, titled “Notes on Certain Aspects of the Proposed Commercial Development of the Deposits of Bituminous Sands in the Province of Alberta.” Mary notes that Clark was uncomfortable reading a senior colleagues’ work and critiquing and making sense of it but, together with geologist/topographer J. Keele, he wrote a 5,000 word review.

In summer 1918, Clark went to Manitoba as part of his field work and was able to see first-hand the difficulty of road maintenance. He worked around Brandon and, in Mary’s words, “noted that the soil made wonderful roads in the summertime when it was hot and dry, but the clay – everything slipped apart when it got wet, and he thought if you could only – it sounds pretty simplistic now – if you could only waterproof the clay then that might be a way of preserving roads. Of course, after the war and certainly by the early 1920s, roads were big. I mean everybody had a car then, and farmers had to get things to the railway and all the rest of it.”

Clark began to ponder a solution involving the water repellant properties of oil. This theory, in brief was that, if he could obtain oil from tar sands and mix it with the clay surfaces, he could waterproof them. Mary continues, “So back in his lab, in Ottawa in the winter, he got some tar sands and he thought if he could emulsify them ...you could put this emulsification on the road. Well, instead of getting an emulsion he got a separation. That was the big ‘ah ha’ moment. He got this separation. He’d got... sand in the bottom, oil in the middle, and water on the top. So he’d got these three things, but he had to get the oil out without the sand and the water; particularly, the sand. He tried everything possible but the oil and water got mixed up again.”

In chemical terms, what Clark had succeeded in doing was a “colloidal suspension” (the suspension of a solid in a liquid, in this case two “solids’ since bitumen is thicker than water). This discovery has spurred oil sands research until today. Mary noted that this happened in 1919 but he was told to stop the research and that the orders “came down from on high.” She believes that it was because Ells had returned from the war and that Ottawa and Alberta were fighting about the bituminous oilsand resources.

The feds had tried sinking a well at Athabasca Landing as early as 1894 but that and several other efforts had failed. Federal bituminous sands research was under the control of the Honorary Advisory Council for Scientific and Technical Research. The proprietary attitude of Ottawa with respect to resource development did not sit well with the government of Alberta or University of Alberta President Henry Marshall Tory. Mary notes: “Tory, I think quite rightly said, ‘If this is going to go on in my university, it’s going to be under my control’.”

In 1919, Tory visited Ottawa looking for someone who could take on research on oil and coal in Alberta. His vision was that the University that he helped to found would support province-building through research leading to economic development. In the Mines Branch, he heard of the great excitement about Clark’s discovery and, according to Mary, “he went straight to my Dad and persuaded him to come out to Alberta. Correspondence between the two continued on Tory’s return to Alberta and, by September [1920], my Mom and dad were in Alberta.” Tory wanted Edgar Stansfield of the Mines Branch to come out first to head up coal research but Stansfield had work to tie up that would take him a year. Thus, Clark became the first full-time member of the Research Department with a focus on tar sands research. On January 6^th, 1921, by an Order-in-Council, the Industrial Research Council of Alberta was established (becoming in 1930, the Research Council of Alberta; in 1981, the Alberta Research Council; and, most recently, Alberta Innovates Technology Futures).

Tory was a staunch supporter of Clark’s efforts and a railway line to Fort McMurray made it easy to get supplies of bituminous sands for research. To facilitate Clark’s research, in the winter of 1919, Tory had secured about six tons of the bituminous sand and stockpiled it on campus. He instructed Clark to begin his research from scratch without reference to the previous work of Ells (Ells was interested in the use of super-heated steam for separation). Clark would focus his research on separation based on the use of a chemical reagent.

In 1922, Sidney Blair came to the University of Alberta and was hired by Clark as his assistant. He began surveying up north as a part of his Master’s degree program. Mary has described her father as “a quiet self-effacing intellectual” while Blair was “worldly, self-confident and aggressive.” Together they forged a solid team working together for three-and-a-half years.

Clark’s oil sands research continued throughout the Great Depression of the 1930s when most of the research staff at the Council were let go. Clark and Stansfield became part of the Faculty of Applied Science. When they had moved to the employ of the Research Council, in a far-sighted move, Tory had insisted that they be given Faculty status. The Research Council was revived in December, 1942, nearly 10 years after it effectively ceased operations. The new chairman was N.E. Tanner, minister of Lands and Mines.

While initially, Clark continued his research in relation to finding a waterproof coating material for roads, eventually, he realized the importance of the tar sands as a source of refined oil products. He had his separation facilities in the University power plant, Everything was carefully tested from the amount of sodium silicate used as a surface-active agent or soap, to the temperature of the water, amount of power consumed and duration of heating period. His process and technology was eventually piloted at Bitumount and Abasands.

In December, 1949 just after the Abasands plant closed for the winter, Blair was commissioned by the government of Alberta to make a comprehensive study of both the technical and economic viability of actual mining, separation, delivery and sale of oil derived from tar sands to southern Ontario refineries. The Blair Report, officially, The Development of the Alberta Bituminous Sands was published a year later. Mary notes: “Blair concluded, even though the price of oil was only $3 a barrel – it seems hard to believe – his reckoning was that you could produce it for $2.50. That was challenged later as they said he didn’t take into account all the capital investment for background things like roads and whatnot. That was assuming everything was in, which of course it wasn’t.” The next step was the convening of an international symposium in September 1951 on all aspects of the oil sands, which was attended by one hundred and twenty delegates.

Clark, Blair and Tanner would usher in the next era of development. The prototype science and technology were in place to be shared with industry; the Government of Alberta wanted to see the oil sands developed; and, finally, the destabilization of the Middle East (the Suez Crisis in 1956) made the oil companies look more seriously at tar sands development.

Mary had a final observation on the name oil sands: “You see, they were always known as bituminous sands officially. They were known as tar sands colloquially. It was like a nickname – a loving nickname. But that’s all it was, but after the Blair Report came out, and they knew that they could produce a crude oil because refining techniques had so improved. Then, Dad and Blair said they should no longer be called bituminous sands, or tar, because we now know they are a source of crude oil. They were now oil sands, and so officially by the Research Council, by order of something or other. I’ve got it written down in one of my books. That’s when they were officially reclassified as oil sands.” This was confirmed when the Alberta Oil Sands Authority was set up in 1973 by Premier Lougheed.

This article is the second in a series that reflects information from the Petroleum History Society’s current Oil Sands Oral History Project, which is recording the stories of oilsands pioneers in their own words. As with its previous oral history projects, transcripts and recordings will reside in Calgary’s Glenbow Archives. Adriana Davies is part of the team of researchers/writers behind the project.