Leaving Libya

A hot Arab Spring and civil turmoil spreading throughout the Middle East left Canadian expats scrambling to get out

This article appears is the July issue of Oilweek; photo: CBC

By Peter McKenzie-Brown

Want to appreciate the risks facing oil-producing regions in the Arab World? Consider this: With few exceptions, companies with assets there won’t discuss business or operating conditions; they refer reporters to sanitized news releases. Expatriate workers will often talk only if guaranteed anonymity.

That said, most of the people contacted for this story confirmed an undercurrent of brutality in Libyan society. Take the case of a geologist working in Tripoli, who received a call at the office warning of a home invasion that could put his family at risk. He had received a tip from a neighbour, and immediately headed home. “I locked myself in the apartment,” he explains. “My wife had already been sent away by one of other tenants who had seen what was going on. My children were at school.”

Soon a large group of uniformed and plainclothes people arrived at the complex demanding access to the apartments, and he heard automatic rifle fire coming from the road. After breaking through the main complex gate, they managed to get security keys to the complex, and then pilfered apartments belonging to the mostly western residents. “The invaders carried side arms and automatic weapons,” he says. “This was most disconcerting for me.”

The invasion clearly had government support. His apartment seized, he and his family returned to Alberta in disgust. He soon accepted another job as a petroleum geologist in the Persian Gulf.

Atrocities
Of course, what happens to Western expatriates is less severe than what can happen to rebellious Libyan nationals. A video on CBC’s website describes a recent outrage through the voice of eyewitness Arif Pervez.

Pervez was working on a horizontal drilling project for Waha Oil Company – a joint venture owned by Libya’s National Oil Company, ConocoPhillips, Marathon and Amerada Hess. Shortly after fighting began in other parts of Libya, a military plane landed at the airstrip near Jalu, a small oasis village. Soldiers rounded up oil workers and locals, according to Pervez, then randomly selected two villagers and beat them to death.

Here is how one of them met his end: “Four men were there to torture him” said Pervez. “One was holding his hands, one was holding his feet, and they started beating him with a piece of wood, and he was shouting, screaming and crying. Then they poured benzene or gasoline on him and started burning him. He started shouting a lot, so they continued beating him. Then he died.”

Another Canadian witness to that atrocity was Rick Souther of Taber, Alberta. This was Souther’s second revolution: he had been working in Iran when that country’s revolution began in 1979. When the fighting in Libya started, he was well-site supervisor for two horizontal development wells – 2,700 metres deep with a horizontal length of maybe 1,000 metres with the potential to produce 4,000 to 5,000 barrels per day.

He and Pervez were living in the Waha complex at Jalu – 200 kilometres from the Mediterranean and another hundred kilometres from the oilfield, which is in the burning desert sands. Souther says he and Pervez both witnessed the Jalu murders. Sickened and aware of the gathering danger, they began making plans to leave. Souther first called Canada’s foreign affairs bureau which advised him not to leave the village because Tripoli was too dangerous. “‘Lady, we’ve got no food, no water.’ I told her. ‘If we stay here the villagers are going to make us fight. There’s no sitting on the fence.’” They boarded a plane to Tripoli, but it took a week of bedlam before they could get out of the country.

A study in contrast
Compare these experiences to those of employees working for Canadian companies in Libya – Suncor’s expat workers, for example.

The Canadian energy giant operates a Libyan joint venture company in the Sahara. The company evacuated its own expat employees – about 100 people – quite early after the turmoil began. It then elected to evacuate contractors who worked directly for the company and expatriates who worked for contractors within the joint venture company. The company was quite focused on keeping its people safe and out of harm’s way. There were no questions about the financial resources required for pulling out.

“We had plans in place and contingencies,” according to Suncor’s Kelli Stevens, “but we had hoped we would never have to use them. This wasn’t a Suncor thing. It was a huge exercise in cooperation between Suncor and the (Canadian) government, other companies and other embassies. We ended up evacuating more than 200 people of more than 20 nationalities.”

Libyan nationals working for the joint venture remain in the country. However, with the exodus of Suncor staff and its joint venture contractors, field operations stopped. Suncor’s share of production was 34,700 barrels per day last year – about 6% of the company’s total production and 2% of total Libyan oil production.

Suncor’s Libyan assets are operated by a joint venture with the country’s National Oil Company along the lines of the Waha Oil Company model. Acquired through its merger with Petro-Canada, the company’s Libyan assets are technically known as “Exploration and Production Sharing Agreements.” Having invested $1.4 billion in its Libyan operations, the company acknowledged in May that it might have to write down some or even much of its investment.

Another Canadian company active in Libya also acted quickly to get its employees out. Calgary-based Pure Technologies Ltd was providing pipeline monitoring systems for what is known as the Great Man-Made River water supply project. The largest underground network of pipes and aqueducts in the world, this project consists of more than 1,300 wells supplying six and a half million cubic metres of fossil water each day to Libyan cities. Qaddafi once described the Great Man-Made River as the “eighth wonder of the world.” Like Suncor, Pure Technologies had safely evacuated its expat personnel by the end of February.

The business case for Libya
There isn’t much of a Canadian presence in Libya. As the turmoil began, only six Canadian companies had established themselves in the country. These included Montréal-based SNC-Lavalin, which is heavily involved with engineering and construction of the Great Man-Made River and other projects; Hyduke Energy Services and Caradan Chemicals (both based in Nisku, Alberta); Calgary-based Pure Technologies and producers Suncor Energy and Verenex Energy. Verenex sold out to a government-owned company two years ago, after a bitter dispute with the regime over a property the company had acquired in 2005 – a property with crude potential of some two billion barrels, as it turned out.

Formerly president and CEO of Caradan Chemicals, Dale Clemmer recently resigned that position. He is now president of the company’s international division, which he owns. His company provides oilfield chemicals for production and transportation – “chemicals for treating oil from well to tanker,” says Clemmer.

When the trouble began, he says, “We had employees there from Britain, Bosnia, and the Philippines” in addition to Libyan nationals. “My manager was in the desert at the time. He despatched the expats out of the country, and he was the last to leave. The Filipino had a wife and child there, but he was out of the country getting his visa renewed, so getting the family back together was a real challenge.” Although he stopped doing business in the country when the turmoil began, he kept his staff on small retainers.

“I think there will be regime change,” says Clemmer. “Everybody seems to want it, and there is great potential in that country. I have assets there, like computers and trucks, but (when things settle down) they will need chemicals to get restarted. The world needs the oil. We have been working there getting set up for two years. We’ve made sales, but we now have new systems and ideas in place. We were all ready to take new orders, but I’m really glad they didn’t come in before this started, because we would have a hard time collecting receivables.”

Clemmer believes in the country’s future. “Libya has a lot of potential,” he says, “thousands of kilometres of great beaches and not a single hotel on any of them.” Then he adds with a flourish, “I love the international side of operations. There’s so much potential there. Canadians are really appreciated and welcomed with open arms. There’s a lot we can do.”

Canada may have a small presence in Libya, but it isn’t for lack of trying. As the Arab Spring began, 70 Canadian companies were trying to develop business there. One of those companies is Calgary-based Western Petroleum Management (WPM).

“Before we made the decision to go into Libya we did our in-country evaluation of Libya,” according to Dennis Besler, president of WPM International Inc.’s Libyan branch. “We could see since 1998 a steady progression of change. Twelve years of progress was a major contributing factor to our decision.”

“I was in Canada when the revolution started,” he adds. “We were basically in the marketing mode, building contracts in Libya. Under Libyan law you have to hire Libyan staff. Practically speaking, you need Libyan staff to negotiate your way through the difficulties of working in the country.” Besler stays in touch with his staff in Tripoli by Skype or cell phone. “I know these people personally and consider them friends so my interest extends well beyond business.”

“We’re very busy in Canada, so I was lucky. When I left Libya I had a lot of work to do here. (Before the uprising began) there were maybe a million expats Libya-wide, and many of them had good jobs. Now those people, a lot of them, are out of work.”

Besler looks forward to returning to Libya. “We first need to see stability within the government and the country overall,” he says. “WPM does wish to share in the future of Libya but for now we wait, hoping for a quick resolution to the conflict. It is difficult to hear about the loss of life when you have spent time there. To a large degree we look forward to going back because Libyans are such a gracious people.”

The real surprise
One Canadian interviewed for this article works for a Libyan company based on western models. The Trans-Sahara Group is a Tripoli-based oil services and IT company owned by prominent western-educated Libyan business people; chairman Naaman el-Bouri, who formerly worked for a Swiss bank, is based in Logan, Switzerland.

Gamal Ghobrial’s story is an unusual one – not least because his wife Samia, who had been living with family in Egypt during that country’s insurrection, moved to Libya for relief from the stress. She arrived just before the Libyan upheaval began. “There was supposed to be a peaceful march in two days’ time” says Ghobrial, “but that wasn’t what it turned out to be. It quickly became an uprising.

Calgary-based Tarco International had hired Ghobrial to develop business in Libya, but closed the operation when the 2008 financial crisis hit. Fluent Arabic and a lifetime of experience in the energy service industry were both assets, and Ghobrial soon found himself working for Trans-Sahara.

“I personally have not witnessed brutality,” he says, “but Libya is not a reasonable place to live in for many reasons. Normal day-to-day life is very difficult; quality of life is poor for an oil-rich country. We lived in what was supposed to be a nice area, but the roads were dirt, the water came from a well and there was no sewer. We experienced power cuts. To live in a compound where you can have everything to a North American standard would cost you $7,000 to $10,000 per month.”

To illustrate Qaddafi’s frequently erratic behaviour, Ghobrial cites a 2009 diplomatic incident. Canada and many other Western countries were angry that Libya had given a hero’s welcome to the man convicted of the 1988 Lockerbie bombing. In protest, foreign minister Lawrence Cannon planned to rebuke Qaddafi when his plane landed for refuelling in St. John’s, Newfoundland. To avoid the incident, Qaddafi cancelled the stopover. “Every day under there were new rules for Canadians,” he says. For six months after that, “You couldn’t plan anything. You couldn’t even plan your visa issues. Work permits were very difficult.”

According to Ghobrial, “The leader Qaddafi and his family say ‘The oil revenue is for me and my family. You have nothing to do with it.’ Qaddafi himself looks after that. This is common knowledge for everyone living in Libya, and to people who work with international oil companies. Of course, I don’t have documents to prove it.”

When a service provider does work for the oil industry, he says, “It takes six to 12 months before you get paid. That’s because the National Oil Company produces the oil and then the revenue goes to the government, which produces a budget every year giving them less than they need to pay their bills. So they pay the bills that have to be paid immediately and just wait to pay the others.”

“Because (Libya) is a dictatorship, you mostly feel secure there,” he adds. “We only became scared when Saif al-Islam (Qaddafi’s son) gave his speech threatening everyone, and saying that everyone would be punished. Because we were foreigners with Canadian citizenship, we were afraid of being harassed by pro-Qaddafi Libyans. We didn’t live in a compound, so we were quite exposed to the public.” On February 25th he and Samia decided to leave. “Things were getting very dangerous.”

“I had registered with the Canadian government as a Canadian abroad, so they had the information they needed and we were prepared to leave. My friend who had gone to the airport with his two kids and his mother in a wheelchair called me at five the next morning to say ‘Nothing is moving, so look for an alternative.’” Only an hour later, though, the foreign office in Ottawa called to say there would be a flight. After a hair-raising ride with a driver they knew, they got to the airport, where confusion reigned. “There were two vans with Canadian flags on them. The ambassador was there, everything was extremely chaotic, and then the Canadian flight was cancelled for some reason.”

Two hundred Canadians were at the airport, but cooperation among countries contributed greatly to their evacuation. Ghobrial speaks highly of the efforts of Canadian ambassador Sandra McCardell, who left the country the same day. “Some of the people went on a Brazilian flight, some went to Gatwick (London) on a British flight and we were lucky to go to Malta on a fixed-wing plane that serves the oil teams.”

Until things settle, Ghobrial and his family are enjoying the stability of Egypt.

Where is Libya headed? Everyone interviewed for this article had a sense of optimism about the country’s future. According to another senior person who requested anonymity, “The brutality (of recent events) doesn’t surprise me, because I have seen that before. What has surprised me is the success of the uprising. The low rates of pay and Libya’s other efforts to keep these people subdued…the people just said it wasn’t right. They didn’t want to be treated as third-class citizens anymore. The successes of the Arab Spring are the real surprise.”

The Leader

Rarely ever did an individual have such a singular force on a global industry as Muammar al-Qaddafi, who began ruling Libya after a successful coup on September 1, 1969. Within months of his seizure of power he had broken the pricing power which had long been asserted by large international oil companies. The result was a petroleum world which rapidly became unlike anything anyone could have imagined before.

In The Prize, his magisterial history of the global petroleum industry, Daniel Yergin describes what was to follow. Qaddafi “would plot and campaign endlessly against Israel, Zionism, other Arab states, and the West, and – equipped with huge oil revenues – he would become banker, sponsor, and paymaster for many terrorist groups around the world.” Today he is known as “the leader,” although he doesn’t hold formal office.

Rocketing oil prices were the hallmark of the 1970s, to a very large extent because of Qaddafi’s mischief and machinations. He made Libya a key player in the 1973 Yom Kippur War and the related oil price shock. Triggered by an embargo of Arab oil to countries supporting Israel, this crisis put OPEC firmly in control of prices for a decade and led to the nationalization of the petroleum industry within OPEC and beyond.

As his rule presumably comes to an end, Qaddafi’s final gift to the world is – you guessed it – higher oil prices. By using brutality to try to retain power, he has caused great damage to the Libyan oil industry and taken 1.6 million barrels per day out of the market. Once the turmoil is over, it will take years to return the country’s production to pre-revolutionary levels. The experiences of Iran, the Soviet Union, Venezuela and Iraq all demonstrate that this is so. Don’t expect WTI prices to soon drop to $86 – the low in mid-February, before the revolution got ugly.

The Desirable Barrel

Why conventional heavy oil is a sizzling commodity in Alberta and Saskatchewan

By Peter McKenzie-Brown

As an oil producer, Saskatchewan seems to have it all. The Bakken light oil trend is a play of frenzied activity. So is Cenovus Energy’s carbon injection oil operation at Weyburn (the world’s largest carbon capture and storage facility). But the province’s meat and potatoes – conventional heavy oil production in the Lloydminster and Kindersley areas – are hidden behind these high-profile developments.

The province’s first 2010 land sale tells the story, but it’s only clear if you dig deeply into the numbers.

Out of nearly $40 million in bonus bids, about $26 million went for land in the Weyburn-Estevan – a reflection of the importance of Bakken and Weyburn. Dig a bit deeper into the numbers, though, and you will find that the highest price paid for a single parcel was $2.1 million for a 1,552-hectare exploration licence in the Lloydminster area. One operator, Baytex Energy, paid $6,512 per hectare for a 16-hectare parcel near Maidstone, also in the Lloydminster area – by far the highest bid per hectare.

Between them, the two heavy oil producing regions in Saskatchewan brought in nearly $10 million in bids – not bad for the Cinderella sister of light oil. The message is clear. The resource has been on production since 1946, but despite its longevity is an increasingly valuable asset. This reality applies to conventional heavy in Alberta as much as it does to production in Saskatchewan. In today’s market the commodity is sizzling. Although there was a blip due to low oil prices a year ago, today’s barrel of conventional heavy is almost as profitable as ever before.

Major changes in transportation to the US and modifications to US refineries have made the Canadian commodity extremely desirable. As a result, the differential paid for Canadian light compared to Canadian heavy is holding firm near historic lows. The differential has averaged about C$8 per barrel for the last year. To put that in perspective, as recently as late 2008 conventional heavy sold briefly for 45% less than Edmonton Par. That wasn’t a profitable environment.

By contrast, the market today is a bit like a winery selling this year’s plonk for 14% less than a vintage wine. Like plonk compared to fine wine, heavy oil is intrinsically less valuable than Edmonton Par, the Canadian standard for light oil. In most refineries, after all, heavy feedstock results in less high-value-added gasoline and more low-value-added asphalt.

But the big US refining complexes are changing that. “It’s a matter of adding vessels to the refinery,” according to Steven Paget; he is vice president for energy infrastructure at First Energy Capital. “Those longer-chain hydrocarbons need more work to break up, but new pipelines from Canada are accessing the refineries at Wood River (Illinois) and Cushing (Oklahoma).” Those refining complexes have the capacity to break heavy oil into lighter feedstock. “Therefore the (narrow) differential becomes minimal or close to equivalent to actual operating cost.”

The good news is that the two heavy oil provinces have a lot of plonk left to sell. According to the Canadian Association of Petroleum Producers (see chart), between them the two provinces have more than a billion barrels of established reserves left to produce. More importantly, each has estimated heavy oil in place many times the volume of reserves.

CAPP estimates that initial volumes of heavy oil in place (this includes both conventional and non-conventional heavy) were about 15 billion barrels in Alberta, and 20 billion barrels in Saskatchewan. Established reserves will thus continue to grow, just as new in-place volumes will continue to be found.

The Background
To understand the economics of conventional heavy, cast your eyes back to the industry’s beginnings.

There are three historical reasons for the growing strength of conventional heavy oil. First, since the 1980s operating costs for conventional heavy production have been in relative decline because of improving technology, higher prices and a better understanding of the reservoirs. Second, policies established since 1990 have lowered royalties for the stuff. Third, the volumes of heavy oil in the Alberta/Saskatchewan heavy oil belt are simply huge. Although the reservoirs tend to be thin, the output is large, and production lasts for many years.

Defined as oil below 20° API which can flow from its reservoirs like lighter oils, conventional heavy oil goes back a long way in Western Canada’s economy. The heavy oil belt is a series of thin sand reservoirs straddling the border of the two provinces. The oil is lighter in density (11-18° API) and of much lower viscosity than the bitumen in the oil sands deposits.

The buckle of the heavy oil belt is Lloydminster, the border town. The first conventional heavy discovery occurred in 1938, and modest development began when Husky Oil (now Husky Energy) moved into the area after World War II. Husky began producing heavy oil from local fields in 1946, and by the 1960s was easily the biggest regional producer. In 1963 the company undertook another in a series of expansions to the refinery (to 12,000 barrels per day). To take advantage of expanding markets for Canadian oil, it also began delivering heavy oil to national and export markets. These developments made conventional heavy more than a marginal resource. Within five years, area production had increased five-fold to 11,000 barrels per day. However, production volumes remained small until the 1990s.

The first of two important developments was the completion of two upgraders – the Co-op facility in Regina and Husky’s in Lloydminster. These upgraders, which were subsidized by government to reduce risk during a period of lousy oil prices, created a large local market for heavy oil. In the early 1990s, production from the heavy oil belt had risen to 300,000 barrels per day – one third of that production being upgraded and refined for local markets. Today Husky produces about 75,000 barrels per day of heavy oil – more than 10% of Canada’s total.

More importantly, in 1993 the Alberta government redefined conventional heavy as “third tier” oil, with highly favourable royalty rates. Once Saskatchewan’s New Democrats were removed from power, new governments in that province matched and then exceeded the Alberta initiative – after all, heavy oil is Saskatchewan’s single most important long-term hydrocarbon resource, so the province had good reason to kick-start development. Indeed, in a modification to the royalty system in 2002, Saskatchewan defined “fourth-tier” heavy oil, with very low initial royalties. All these new tier royalties were great kick-starters. However, as the CAPP data show in the chart below, conventional heavy oil production is now in decline despite growing reserves.

OPEC or Infrastructure?
Especially in a market of declining production, the question of whether differentials will remain narrow is critical. And on this score there is debate. Is the differential likely to narrow or to widen?

According to AJM Petroleum Consulting operations vice president Ralph Glass, the basic reason differentials are so low “is an increased demand for the heavier crude oils from US refineries. Over the last few years there has been a movement by US refineries to enhance their ability to handle the heavier crudes. With the downturn in US demand, OPEC cut their volumes. (The volumes cut were the heavier crudes and done to maximize returns from light crudes which receive higher prices). As a consequence, the US refineries found themselves short of heavier crudes to process, and are now paying a premium for Canadian heavier crudes to reduce the shortfall in their systems.”

He suggests that the demand for heavy oil to fill for new pipelines to the US – TransCanada’s Keystone pipeline into Patoka, Illinois and Enbridge’s Alberta Clipper line to Superior Wisconsin – may narrow the differential even more in the short term. However, the return of competition from OPEC will widen the differential, thus making heavy oil production less profitable.

First Energy’s Steven Paget has a more sanguine view. “The reason the differential has gone down is that we have more transportation infrastructure out of western Canada,” he says. “This allows nearly 90,000 barrels per day of crude to access the Gulf Coast refining complex.” Demand for fill for new lines will increase demand over the short term (narrowing the differential), but the more important factor in his eyes is that those new pipelines will provide increased access to markets, making conventional heavy more competitive in US markets. “The narrow margin is likely to continue.”

Ralph Glass takes the more cautious view. In 2011 and 2012, he says, the industry will experience “widening on implied concerns of heavy OPEC production coming online and increased Canadian heavy production.” If he’s right, and if production continues to decline, expect the sector’s salad days to wilt.

Melting Away

Like the Wicked Witch of the West, Petro-Canada has met its demise, and few are around to mourn

An obituary of the company's rise and fall, this article appears in the November 2009 issue of Oilweek

By Peter McKenzie-Brown
About 20 years ago I wrote a speech for Bill Hopper, who was then chairman and CEO of Petro-Canada. He had just taken on a one-year term as chair of the Canadian Petroleum Association (the CPA; now CAPP), which I then worked for.

The process was strange beyond imagination. Instead of simply going to his office to find out what he wanted to say, I learned at the last minute that I was to go with an entourage: CPA president Ian Smyth; vice president Hans Maciej; and my boss, Norm Elliott. Among the other members of the CPA’s board of governors, Hopper alone demanded that amount of attention. The interview took place in Hopper’s palatial offices in Petro-Canada Centre. Not surprisingly, the interview was a flop – a waste of time for all concerned.

This vignette is a reasonable caricature of the early years for the most controversial petroleum company in Canadian history. Especially under Hopper’s leadership, Petro-Canada set the national standard for self-importance, arrogance and underperformance. Although the worst times are long behind us, the company’s epitaph cannot be written without reference to those bad old days. In some ways, they were with the company to the end.

For example, if you believe that markets are inherently rational, try graphing the company’s share price to those of its peers. Every large Canadian oil company has done better than the People’s Oil Company, as it was once unaffectionately known.

When the crash came a year ago, Petro-Canada collapsed more deeply than most. This left it vulnerable to regime change, which quickly came in the form of a takeover encouraged by complaints from a large shareholder, The Ontario Teachers’ Pension Plan, which wanted to increase shareholder value.

The company and oilsands pioneer Suncor Energy soon announced a friendly merger, consummated on August 1st. The transaction created Canada’s largest oil and gas producer, with a market value of more than $50 billion. By the time the companies merged, Petro-Canada had nearly doubled in value from its 52-week share-price bottom, set last November. Clearly, the rational markets felt that with the takeover a better manager was in charge of its assets.

Few people will miss Petro-Canada the oil company. Its corporate history is a bit like the story line for “The Incredible Shrinking Man” – the 1957 movie in which protagonist Scott Carey, who had been contaminated by a radioactive cloud and pesticide, shrank slowly until he was reduced to living in a dollhouse.

In real, inflation-adjusted terms, Petro-Canada was the incredible shrinking company. Notwithstanding infusions of additional cash through equity sales, in real terms Petro-Canada’s market capitalization at the time of its merger with Suncor was less than the federal government’s original investment. In nominal terms (unadjusted for inflation), it lost nearly half the money its founding shareholder, the government of Canada, poured into its maw. And as the shackles of government ownership were slowly removed, it lost a combination of hard cash and opportunity for its second round of shareholders, a long-suffering gaggle of private investors.

The Background
Petro-Canada was founded as a Crown Corporation in 1975 by an act of Parliament and started operations the following year. The company was created upon noble ideals. In a period of intense energy insecurity, the left wing of Ottawa’s political establishment – the minority Liberals supported by the NDP as kingmakers – proclaimed the need for a national presence that would go boldly into the Canadian frontiers, which supposedly were being overlooked by the international players who then dominated Canada’s oil and gas sector. As importantly, the company would serve as a “window on the industry” through which policymakers could peer through clear glass. At start-up, the federal government transferred its 45 percent stake in Panarctic Oils and its 12 percent interest in Syncrude to the newly established company.

While the political issue of the day was ownership of Canadian resources – especially oil – Petro-Canada quickly went into acquisition mode by buying integrated companies rather than pure E and P operations. The idea was to wave the Canadian flag to consumers (aka voters) across the country. Outside Alberta, the political decision to create a national oil company was popular, and the company was given $1.5 billion in start-up money and easy access to new sources of capital.

During its first ten years, Petro-Canada purchased Atlantic Richfield Canada; Pacific Petroleums; Petrofina; most of BP’s Canadian refineries and service stations; and Gulf Canada’s retail and refining operations. The irony was not lost on the oil and gas sector: there were no shortages of refining capacity or retail operations, yet the company paid premium prices for assets which brought considerable liabilities with them. Other companies – BP and Gulf, for example – were selling them partly because the 1980s were a period of consolidation for retailing assets. The era of having a gas station on every corner was morphing into the present era of service stations only in heavy-traffic locations. And with service station closures came significant environmental liabilities, since product leakage from underground storage tanks was endemic across the country. That collective mess had to be cleaned up, and doing so was expensive.

The company did become an important purveyor of gasoline and motor oil at the service station, and one of its few unadorned successes was to develop the trusted and respected Petro-Canada brand of petroleum products. The single biggest boost to that brand came when the company sponsored the 1988 Olympic torch relay – a sponsorship that Ed Lakusta, at the time the company’s president, called the finest thing his company had ever done. Even sceptics began to believe Petro-Canada had a place in the oilpatch, and its gasoline sales soared.

Because of its many acquisitions in Western Canada, the company became one of the largest players in western Canada’s traditional oil fields, in the oilsands and in the east coast offshore. Did this lead to the discovery or development of more oil in the west? Certainly not. In 1927 John Bertram, an American Oil Company operative investigating the energy scene in Alberta, wrote a succinct description of what geologists now call the method of multiple working hypotheses.

“We know from our own experience,” he said, “that the geologists and also the officials of a company that operates in one area for a long time, tend to think along the same lines and to accept the same theories of oil occurrence. When other groups of men invade the same territory, the newcomers work with different methods, use different theories and drill structures the others condemned.” Through its acquisition of numerous companies on the government’s dime, Petro-Canada actually slowed oil development in western Canada – or so says the tried-and-true multiple working hypothesis method.

With the changing of the political winds, governments gradually began privatizing the company. Begun in 1991 under Brian Mulroney (who had ordered the company to act like a profit-driven company when he was first elected), this process was completed in 2004 by the Liberal government of Paul Martin, which sold more than 49 million shares for about $3 billion, bringing the government’s total recovery from its investment to $5.7 billion.

Petro-Canada acquired valuable offshore interests during the Hopper era. These included Hibernia, which is Canada’s most prolific ever oilfield. The company was the operator behind the Terra Nova discovery, which is now Canada’s second-largest offshore oilfield. Also in the offshore, Petro-Canada was the operator of the White Rose oilfield.

But the company did not truly begin operating like a profit-driven private company until 1993, when Hopper was replaced by Jim Stanford. During Stanford’s stewardship, the company made efforts to grow in important ways. Its east coast assets went on production, and the company went international, acquiring and developing in the North Sea, Libya, Syria and Trinidad and Tobago. At the end, those offshore and international operations were its biggest sources of income. After decades of rationalization, its refining and marketing operations – the second-largest in Canada – became a stable and reliable source of cash flow.

For investors, though, the bottom line is the bottom line, and Petro-Canada shares never performed close to the level you might expect from a company with its assets, image and cash flow. An important factor was the Petro-Canada Public Participation Act – Mulroney-era legislation dictating that no single entity can hold more than 20 percent of the company. This made the likelihood of a takeover remote, greatly weighing on Petro-Canada’s stock price. Call it the last curse of public ownership.

The Legacy and the Merger
The storied tale of Petro-Canada is an object lesson in the failures of government interference in the economy. Journalist Peter Foster’s 1992 book, Self Serve: How Petro-Canada Pumped Canadians Dry, won that year’s National Business Book Award and was a factor in unseating Bill Hopper.

At the end of a chilling chronology of hubris and mismanagement during the company’s first 15 years of operations Foster writes, “It can fairly be claimed that Canada is at least $10 billion deeper in debt because of Petrocan, a debt for which there is no corresponding asset. The money has gone….But although the original investment has been largely destroyed, the debt lives with us. We are like bad gamblers in debt to loan sharks, our obligations growing geometrically. The annual interest cost of the Petrocan-associated debt is about $1 billion, and all the income tax from 100,000 average Canadian families will have to go to pay that annual charge.”

According to another, highly hypothetical version of this analysis, Canada would be debt-free if, instead of spending $10 billion on petroleum assets during the high-interest-rate 70s and 80s, the federal government had instead reduced its debt by that amount. More to the point, the creation of Petro-Canada generated few if any useful results. To the extent the company contributed to the policies of the hated National Energy Program, it caused unnecessary and inestimable damage to the country and its oil industry.

Petro-Canada danced into the arms of Suncor with a tremendously deflated cash flow stream and dramatically lower profits after 2008’s oil-pricing bubble. During the company’s last quarter as an independent operator, its net earnings decreased by 95 percent to $77 million, compared with $1.5 billion a year earlier. The company cited the deadly combination of lower commodity prices and volumes plus higher costs and expenses. The recession-related collapse of oil and gas prices was clearly the most important source of this financial disaster.

Disaster that may have been, but for Suncor, with its high-cost oilsands production, the impact was far worse. In the second quarter the company suffered a net loss of $51 million, compared to net earnings of $829 million a year earlier. The financially weaker of the two companies – Suncor – was the acquisitor because of the strength of its management. The company, which at time of writing is trading at about $35 per share, started life in 1993 at about a buck. That’s serious growth – especially compared to Petro-Canada’s original $13 issue price, which had grown to only $41 at the time of the merger. Petro-Canada’s shareholders were a long-suffering breed.

Petro-Canada’s Jim Stanford and Suncor CEO Rick George first discussed merging in 1999, but the negotiations went nowhere. In the crisis atmosphere of the latest recession, though, the players were more motivated to get results. The announcement came less than two months after Petro-Canada’s big shareholder, The Ontario Teachers’ Pension Plan, began agitating for better shareholder value.

At a stroke, the merger between the two companies created Canada’s largest oil company, and the fifth largest in North America. Post-merger, Suncor controls 26.5 billion barrels of oil; the largest suite of oil-sands holdings in the world; daily production of 680 million barrels of oil equivalent; and an international reach that embraces the North Sea, Libya, Syria, and Trinidad and Tobago. The joint Canadian operations of the merged company cover the energy sector, from the Arctic to the east coast offshore, shale gas, refineries and a vast chain of retail outlets. The gas stations and other marketing operations are the only visible remains of what was once Canada’s national energy company.

What is the effect on the new, combined company? The most immediate impact is greater operating efficiency. The designers of the merger – Rick George and Petro-Canada’s Ron Brenneman, Stanford’s successor – forecast that joining forces will save $300 million a year in operating costs and about $1 billion in annual capital spending by eliminating duplication of pipelines, power and water infrastructure for oil-sands operations. In addition, Petro-Canada’s light oil assets are far less vulnerable to another oil price collapse, and will thus stabilize the combined company’s cash flow stream. Also, Petro-Canada brought with it a suite of non-core overseas assets that the company can sell to finance its core oilsands developments, like the Firebag SAGD expansion that went on hold last year.

Professor of economics and academic director of the University of Calgary’s School of Policy Studies Robert Mansell says the deal makes sense in many ways. “In a world with great uncertainty, where we don’t know what is going to happen with climate change policy, it gives you an ability to mix and blend and do all kinds of things that you wouldn’t be able to do if you were just oil sands. Long term, if you can maintain a very efficient, integrated operation that is better than a very narrow, specialized operation. And when you are talking about billion-dollar projects, being a large company is a lot better than being a small company. I see that as being an excellent strength that they can build on.”

If the new company has an Achilles heel, perhaps it is a relic of the Petro-Canada years. As a result of the merger, Suncor is now subject to the Petro-Canada Public Participation Act, which weighed so heavily on Petro-Canada for so many years. That law, which restricts ownership in the company by any single entity to 20 percent, will protect Suncor from predation during the period of consolidation. Longer term, though, will the last curse of public ownership weigh on Suncor’s shares, as it once did on Petro-Canada’s?

From North to South: How Norman Wells led to Leduc

I delivered this presentation to The International Commission on the History of Geological Sciences, August 11, 2009

Synopsis: In Canada’s early years, important hydrocarbon discoveries occurred almost independently of settlement. In the frontiers, of course, that pattern continues. The relationship between Norman Wells and Alberta’s post-war discovery at Leduc is one example of a pattern that turns on its head the American model of petroleum development. Remote exploration has always played a critical role in our industry’s development.

It would be easy to think of Canada’s petroleum industry as one that began in the south, grew wealthy, then began exploring and developing more remote lands. That is indeed a realistic caricature of the US industry, but in Canada the story was different. The most important oil discovery prior to Leduc actually took place just south of the Arctic Circle. In a drama worthy of the great white north, that discovery led directly to the creation of Canada’s modern petroleum industry.

By Peter McKenzie-Brown
Before I address the major topic of my presentation today, I would like to suggest an idea about the development of Canada’s petroleum industry compared to that in the United States. Simply put, the patterns of petroleum industry development in the two countries paralleled their respective patterns of settlement.

As you know, the US takes up the best temperate lands along the eastern seaboard, and there are no major barriers to settlement between New York and San Francisco. The Cordillera is a problem, but settlement in the far west was still not seriously hindered – especially after the construction of the transcontinental railways. That pattern exactly reflects the development of the US petroleum industry. In the US there are many sedimentary basins – smallish, but regularly spaced across the country. Once Colonel Drake drilled his historic well, the American petroleum industry developed with patterns of settlement.

Canada has quite a different geography. Settlement was difficult in this country because of the predominance of the Canadian Shield, which provided barriers in many ways. Trapped between the Shield and the Cordillera, the Western Canada sedimentary basin is far bigger than the many on-shore basins in the US. Because of the Shield, it is well separated from the small basins in eastern and central Canada. The Shield and our northern latitudes created what I call the coureurs du bois model of how the Canadian industry developed.

In case you don’t know the expression, coureurs du bois were fur traders who earned their livelihoods with the aid of canoe transport along our mostly northward-flowing rivers. They played a big role in the creation of Canada. For example, from remote northern locations they brought information about resource potential to our political and commercial centres.

Partly because of their efforts, our earliest hydrocarbons were found in outposts of settlement. Consider our Oil Springs discovery, for example, which was contemporaneous with Colonel Drake’s 1859 well. Based on investigation into the well-known gum beds near Black Creek, the Oil Springs discovery took place on the north shore of Lake Erie – in an area without roads, but along the transportation and trading system afforded by the Great Lakes.

Alberta’s first recorded natural gas find came in 1883 from a well at CPR siding No. 8 at Langevin, near Medicine Hat. This well was one of a series drilled at scattered points along the railway to get water for the Canadian Pacific Railway’s steam-driven locomotives. The unexpected gas flow caught fire and destroyed the drilling rig. The discovery took place as we built our first transcontinental railway – itself an effort to settle our empty prairies before the Americans did the job for us.

The Athabasca oil sands were already well known – in fact, the first recorded mention of Canada’s bitumen deposits goes back to a Hudson’s Bay Company record of June 12, 1719. Hoping to find light oil beneath the sands, in the late 19th century Ottawa undertook a drilling program to help define the region’s resources. Using a rig taken north by river, in 1893 contractor A.W. Fraser began drilling for liquid oil at Athabasca, where the oil sands had been known for centuries. In 1897 he moved the rig to Pelican Rapids, also in northern Alberta. There it struck natural gas at 250 metres. But the well blew wild, flowing huge volumes of gas for 21 years. It was not until 1918 that a crew succeeded in killing the well.

These few examples illustrate my point. Quite unlike the situation in the US, Canada’s early hydrocarbon exploration took place along transportation corridors rather than in settled areas. The country had been well explored during the fur trade era, but settlements were still few and far apart. That pattern is in evidence in the case of Norman Wells, to which I now turn my attention.

Ask any of Canada’s exploration professionals when Western Canada’s oil industry began, and you will get one of two answers. The first is the Dingman #1 discovery, which began disgorging wet gas at Turner Valley in 1914. The second is Imperial’s 1947 oil discovery at Leduc. The more thoughtful industrial historian would probably say Dingman was the critical event for the industry’s early years, while the modern era began at Leduc.

I want to suggest that another event was equally pivotal. The year was 1914. The occasion was an expedition down the Mackenzie River by a British geologist, Dr. T.O. Bosworth. There are direct links between that trip and the modern industry’s birth.

The Bosworth Expedition: Two Calgary businessmen, F.C. Lowes and J.K. Cornwall, commissioned Bosworth’s journey. They wanted to investigate the petroleum potential of northern Alberta and beyond, and to stake the most promising claims. Bosworth did not disappoint. His confidence that the north was highly prospective is apparent on almost every page of his 69-page report.

Bosworth’s own words suggest how ambitious the expedition was. “The undertaking was planned in March 1914,” he says. “In April I consulted with the officers of the Government Geological Survey and other Departments in Ottawa and gathered from them all available information; maps and literature bearing on the subject.

“At the beginning of May, I journeyed from London to Canada accompanied by three assistant geologists and surveyors, and on May 19th, the expedition set out from Edmonton to travel northwards in the Guidance of the Northern Trading Company. We returned to Edmonton September 24th.”

During that period, the Bosworth expedition covered huge distances. And according to his report, there were excellent exploration prospects in three general regions: “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”

His report offered concise, well-written geological descriptions of rocks, formations and structures. It also included chemical reports on both rocks and oil from the many seepages in the area. Some of his greatest praise came from investigations north of Norman Wells, areas which to this day have not yielded a major oil discovery. “Near Old Fort Good Hope (lat. 67 30’) in the banks of a tributary stream, the shales are well exposed ... from the fossils it is evident that the shales are of Upper Paleozoic Age and probably belong to the Upper Devonian,” he said. “This remarkable series of Bituminous Shales and Limestones, of such thickness and of such richness contains the material from which a vast amount of petroleum might be generated and might pass into an overlying porous rock. It is admirable as an oil generating formation.”

In a discussion of the evidence of good reservoir rock, Bosworth points to a nearby occurrence of “gray clay shales and shaley sandstone,” and to another of “greenish shaley sandstone containing occasional fossils – corals, chenetes and rhynconella.”

Both of the reservoir rocks Bosworth speculates upon lie above the Devonian shales. He was looking specifically for “overlying porous rock” to form the reservoir. It does not seem to have occurred to him that reefs within the shales could have served as reservoirs, even though he specifically noted the presence of Devonian corals.

Before I turn to the outcome of this expedition, which was quite important, I would like to share with you the business advice he gave his clients in the conclusion to his general report. “To avoid all competition,” he said, “I strongly advise that you form a controlling company or syndicate containing the most influential men. I recommend particularly that you arrange matters in such a way that it would be to the obvious advantage of every oil man to join you, and that you freely provide the opportunity so that the Company may include every man who wishes to venture anything in the exploitation of the oilfields of the North. By this means alone can you hope to avoid competition and the unfortunate results which must follow….”

In his report Bosworth noted that he had “investigated” the discovery at Turner Valley. Fifteen months in the drilling, the wet gas discovery came in on May 14, 1914 – just before Bosworth left Edmonton on his expedition. Within 20 years, that discovery would be recognized as “the largest oilfield in the British Empire.” Bosworth, however, was not impressed. In his view, the real potential was in the North.

Believing Turner Valley was doomed to disappoint explorers, he wrote that that “there are a number of oil companies in Western Canada who have capital in hand which must be spent on drilling wells. At this moment they are faced with failure (at Turner Valley), and might gladly turn to any region where there is a genuine reason to expect oil. Any such companies might become associated with your controlling company to the obvious advantage of all parties, on terms which can be mutually arranged...”

After further commentary, he advises his clients in these words: “You would also provide for the transportation; the necessary railroads; the pipe lines, the refineries, and, what is more important than all the rest, and which would give you complete command of the whole situation, all of the oil produced in the region would pass through your hands to be marketed by you.

“If you could succeed in promoting a great scheme on some such lines as these, no smaller rival group could hope to compete against you, and you might eventually be in the position to control the great oil fields of the North.”

One of the great ironies of these comments, of course, is that they came barely three years after the Standard Oil Trust was dismantled for just such anti-competitive practices. In addition, Bosworth completely misread the importance of Turner Valley and the petroleum potential of Alberta, so smitten was he by the North. The practical value of his advice may be seen in the fact that seven decades elapsed before oil from the Norman Wells oilfield actually began flowing to southern markets.

Now, let us push on with our story. Bosworth does not remark on the coming of World War I. However, when he and his men left the world was at peace; when he returned, Europe and the British Empire had become embroiled in that terrible war. He was probably totally unaware of those developments while in the north.

The exigencies of war postponed exploration of Bosworth’s claims. So did the Dingman discovery. The petroleum industry by this time was focused on Turner Valley field development, where standard practice was to strip naphtha from the gas stream and flare the gas itself. By 1918 an Imperial Oil subsidiary, The Northwest Company, had acquired the properties Bosworth had staked for his clients. Imperial had hired Bosworth himself as chief geologist. The company decided to drill on one of those claims.

Imperial Oil Limited’s legendary exploration geologist, Ted Link, led the drilling expedition. By train, scow and riverboat, he and his crew followed Bosworth’s route north to Fort Norman, just south of the Arctic Circle. They had taken with them the wherewithal to assemble a cable-tool drilling rig, and they soon set to work. One valuable member of the party was an ox, which supplied heavy labour during the summer. As the autumn cold began killing off the forage, he delivered steaks and stew.

Before moving on, it is worth noting that the most important early geological work at Norman Wells, including the location of the discovery well, needs to be attributed to Ted Link – not to T.O. Bosworth. In an important 1947 presentation to the AAPG, J.S. Stewart of the Geological Survey of Canada is adamant on this point.

Canol: Imperial’s first well brought in the great Norman Wells discovery, in 1920. However, there was no practical way to get the oil to market. Because demand in the Northwest Territories was marginal, Imperial had little reason to develop the field. However, later in the decade the company constructed a tiny refinery at Norman Wells to supply gasoline and other products to missions, mines, riverboats and other local customers. The company did not need many wells to meet local needs, and did little investigation of the geology of the reservoir.

That changed after Pearl Harbor. When the Americans came into the Second World War, they were extremely concerned about having secure local fuel supplies in the North, especially after Japan took control of a couple of Alaska’s Aleutian islands. They therefore worked with Canada to develop Norman Wells into a source of local oil supply for a refining and distribution complex. This was the beginning of the Canol Project. The name supposedly comes from the contraction of “Canadian” and “oil”, but I suspect the second syllable is actually “oil” with a Texas accent.

Construction crews built a 950-kilometre oil pipeline over the Mackenzie Mountains to a newly constructed refinery in Whitehorse, in the Yukon Territory. The pipeline was built over some of the most difficult terrain in the country, and much of the work had to be done in bitter cold. Crews also laid product pipelines to Skagway, Alaska. In total, they constructed 2,560 kilometres of pipeline.

By any standard those lines were terrible. The line ran on top of the ground, alongside the road, often without supports. Vulnerable to frost heaving, snowstorms and flooding, the Canol pipelines were not designed for extreme cold. They were neither installed nor handled properly, and they failed frequently. The crude oil pipeline leaked onto the permafrost. So did the product pipelines, which delivered diesel and gasoline to a fuelling station in Skagway, Alaska.

To meet the needs of the refinery, Imperial drilled more wells, and began to better understand the Norman Wells reservoir. Of particular note, the company discovered that it was a Devonian reef – of earlier vintage than the Leduc and Redwater fields soon to be discovered in Alberta, but still a Devonian reef. That turned out to be the geological key.

By the time the refinery was ready to begin operations, the company had drilled 60 productive wells out of 67 project wells in total. The test for the field came on February 16, 1944 when the pipeline began operating. As a producer of good-quality oil (39° to 41° API), the field surpassed expectations. By October 1944 Norman Wells was producing 4,600 barrels per day by natural pressure.

The extraordinary Canol project did not contribute meaningfully to the war effort. The threat to west coast shipping had disappeared and it was clear that the war would soon be won. First oil flowed through the pipeline in 1944, and the refinery operated for less than a year before being mothballed. Perhaps Canol was the greatest white elephant in petroleum history.

No one really knows how much the project cost – estimates range up to US$300 million, all paid by American taxpayers. However, for the following calculations I will use one of the conservative estimates: $134 million. Total oil production was about 1.5 million barrels. In as-spent dollars, therefore, it cost $89.33 per barrel. The Whitehorse refinery only produced 866,670 barrels of refined product. Dividing that by total project cost, you get $0.97 per litre.

Now, let’s adjust those numbers by official consumer price inflation in the United States. In today’s money, the oil would cost $982 a barrel. The refined products would cost $10.69 a litre. And that’s before taxes!

Later studies of the project’s environmental impact in Whitehorse were revealing. The Canol legacy included the creation of an environmental horror known locally as the Maxwell Tar Pit. Appalling disposal and clean-up practices during the Canol debacle had created an oily mess that was declared an environmentally contaminated site in 1998. Forty years earlier, a man had stumbled into the pit and got stuck. He later died in hospital.

Leduc: Although Canol had little impact on affairs of state, it had a huge impact on oil development in Western Canada. As the result of wartime field development at Norman Wells, Imperial learned that the field’s reservoir rock was Devonian reef. Armed with this knowledge, the company’s geologists – led by Ted Link, who by this time was in charge of Imperial’s exploration efforts – rethought their approach to Western Canada.

This was an important example of thinking outside the box. Other oilmen at the time were on the hunt for big plays that looked, walked and talked like Turner Valley. They would be roughly 340 million years old. They would be thrusted anticlines of Paleozoic age in a Mississippian formation. Much fruitless drilling in the foothills sought the next Turner Valley.

Perhaps we should not give all the credit to Imperial Oil for the geological idea that there might be Devonian reefs in Alberta. In an email, my friend Clint Tippett asked whether GSC mapping of the Rockies west of Edmonton – work undertaken by Helen Belyea, Digby Maclaren and others – influenced Imperial’s thinking. Before the Leduc discovery, Charles Stelck at the University of Alberta also gave thought to the question of Devonian reefs in Alberta.

However Imperial arrived at its revolutionary idea, the importance of its decision to drill for a reef cannot be understated. That geological idea brought forth a series of great discoveries. The first came with the aid of primitive seismic technology, and it was a big one – the famous Leduc #1 discovery well. When it came in to much fanfare on February 21, 1947, Leduc laid the groundwork for one of the world’s great post-war oil booms.

There is another important connection between post-war oil development in Alberta and the Canol project. The refinery built in Whitehorse played an important role in Alberta’s industrial development. Imperial bought the mothballed refinery for one dollar, dismantled it and moved it to Strathcona, near Edmonton. There, the company reassembled it to handle production from Leduc and other post-war discoveries. That refinery laid the foundation for one of Canada’s biggest refining complexes.

As I leave this discussion, a final piece of trivia. Although Imperial is the hero of this drama, I understand that the company’s geologists mapped the Leduc reefs at a 90° angle to their actual orientation. After mapping them correctly, Texaco came to have the dominant position in the Leduc chain of reefs.

Summary: The Norman Wells story illustrates a pattern that turns on its head the American model of petroleum industry development. Briefly put, remote exploration has played a critical role in the industry’s development since the earliest years of oil and gas exploration in this country. Bosworth was wrong in important areas. However, his work greatly influenced that of his successor, Ted Link, who ultimately proved that Devonian reefs were an important key to Canada’s petroleum wealth. That change in thinking paved the way for a series of discoveries which represented the birth of the modern petroleum industry in Canada.

It would be easy to think of Canada’s petroleum industry as one that began in southern Ontario and Alberta, grew wealthy, then began exploring and developing its frontiers. But this model doesn’t fit the facts. Key discoveries and developments took place in remote regions. In the sector’s early years, important discoveries occurred almost independently of settlement, and a great deal of oil and gas development continues to take place in sparsely populated areas. In our frontiers, of course, that pattern is fully intact.

If not for the Bosworth report, Canada’s petroleum industry would have had quite a different history. Imperial Oil’s efforts were heroic – indeed the stuff of legend. Enormously frustrated with its unbroken string of 133 dry holes, Imperial planned the program that yielded Leduc as its last major wildcat play in Alberta. If Leduc had not come in, it is easy to imagine the Devonian oil fields lying fallow for many, many years. No other big players were exploring the prairies.

In the actual case, however, oilmen around the world soon became aware of this important new discovery, and they began to bring expertise and investment into the province. They created one of the first great post-war oil booms, and helped lay the foundation for one of the world’s most diverse and technically advanced petroleum industries.

In respect to its long-term impact, T.O. Bosworth’s 1914 report may have been the most influential geological document in Canadian history. I hope my brief comments today have given you reason to consider that claim.

References:
1. T.O. Bosworth, 1914; “The Mackenzie River between Old Fort Good Hope and Fort Norman; the Tar Springs District on the Great Slave Lake; and in the Tar Sand District on the Athabasca River.”Available at the Glenbow Archives, Calgary; reference number M-8656; 69 pages.
2. J.S. Stewart, 1948; “Norman Wells Oil Field, Northwest Territories, Canada”; in Structure of Typical American Oil Fields, Volume III, pp. 86-109; original paper read before an AAPG meeting in Wichita, Kansas, on January 18, 1947.
3. Peter McKenzie-Brown, 1988; “Two Historical Documents: Notes for an Address to the Petroleum History Society”; online at http://languageinstinct.blogspot.com/2006/09/two-historical-documents.html

Just a ‘FRAC’ away

New gas mega-wells threaten to strain contractor fleet

This article appears in the April 2009 issue of Alberta Oil magazine.

The graphic compares natural gas production from a conventional sandstone reservoir to fracced, unconventional production.

By Peter McKenzie-Brown

If unconventional natural gas is a revolution in the making, so are the services required to make it happen. Industry spending patterns are shifting, with much bigger investments now being poured into operations below the ground.

Traditional ways of doing business are changing. Multiple wells are drilled from single sites, known as “pads,” to tap the new gas target. The old oilfield rhythm of busy winters and quiet summers is also changing as work grows in the warm seasons.

Despite the economic downturn, there is even a hint of a gas counterpart to the former oil sands labor shortage in the air. There is a risk that in the near future Western Canada will find itself short of powerful hydraulic equipment needed to make the networks of underground channels that make unconventional gas deposits flow. This would be a blow to exploration and production companies, but possibly a considerable financial boon to service companies with the right stuff to do the rock fracturing, a field known as “fraccing” in the industry.

The specialty is a well stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pushes a mix of water, sand and some soluble chemicals into well bores at high pressure, both to spread cracks across the formation and hold them open for gas and oil to flow.

Originally a simple operation, fraccing has evolved into a high industrial art that uses multi-stage techniques in horizontal wells, reports Dave Russum, geosciences vice-president for AJM Petroleum Consulting. “Between the heel [start] and the toe [end] of a horizontal well, you isolate an interval close to the toe and frac that region,” Russum says. “Then you move back towards the heel, isolate another interval and do another frac.”

The technique is a powerful production tool. “This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability [poorly flowing] rock than you would ever be able to reach with a vertical well,” Russum says.

In the old days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times. A well that requires so much work would likely have a horizontal reach of 3,000 metres or more.

Analyst Kevin Lo of FirstEnergy Capital Corp. estimates that fraccing just one of EnCana Corp.’s Horn River shale gas wells in northeastern British Columbia requires a crew equipped with more than 30,000 horsepower of compression. In Western Canada, there is perhaps 800,000 horsepower available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary” if B.C.’s Horn River and Montney shale gas drilling hot spots grow, Lo says in a research note. He also worries about the heavy lifting required to deliver enough fraccing materials. Fracturing a single horizontal well in the new unconventional gas reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice-president at Trican Well Service Ltd. describes FirstEnergy’s estimates of requirements for the new gas production as conservative. “Some of the Horn River wells require up to 45,000 horsepower of compression,” Dusterhoft reports. “With 10 holes per pad, you may have 40,000 horsepower tied up for 10 weeks.”

The Trican executive predicts, “There will be shortages of equipment when we get up to full development of the shales.” If it happens, the squeeze will be a plus for service companies like his, which will then charge premium day rates, but a worry for the gas producers in the region.

Environmentalists have voiced concern that fraccing chemicals may contaminate groundwater. But Dusterhoft says that, before wells are fracced, the formations are securely sealed away from potential fresh-water reservoirs.

Use of chemicals is also limited in the unconventional wells in northeastern B.C. “We only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand,” Dusterhoft says.

Fraccing’s goal is to create a web of flow channels. When the technique is completely successful, he says, all of the fractures connect with each other to provide maximum production, he says. “We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs in northeastern B.C. require vast logistical support. Each well can require 2,000 to 3,000 tonnes of fine-grained sand. Parades of trucks deliver vast harvests of ancient sand mined from fossil beaches, often from quarries in Saskatchewan. Such a project may require a 40-member crew, operating 20 or more hydraulic compression systems mounted on large fraccing trucks.

High volumes of water are also used. A typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has contributed to the developing seasonal shift in the fraccing business. “Now the industry is drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction,” Dusterhoft reports.

Water is easier to handle in warmer weather. In the longer term, the changing work pattern will require upgrading to all-weather roads to Horn River and Montney. Until those improvements are completed, service companies have to leave equipment in the area during freeze-up.

The shift to unconventional gas occurred much more quickly than anyone expected, Dusterhoft says. Among numerous implications of the switch, an old barometer of industry health –the sheer number of wells drilled – is becoming obsolete.

The production change, while increasing oilfield work, is contributing to a reduction in the total number of Canadian wells being drilled. In 2008, nearly 40 per cent of the wells involved horizontal or directional drilling – twice the level of 10 years ago. For the first time, FirstEnergy Capital said in a recent research note, the number of horizontal wells across reservoirs will soon match the number directionally drilled at angles. Greater proportions of industry spending on wells are going into completion services like fraccing.

Unconventional gas operations are not cheap. Drilling costs are in the range of $5 million to $7 million per well at Horn River, and $4 million to $5 million at Montney. Fraccing costs are estimated to be $2 million to $3 million per well.

But the production profiles for these wells make them worth their costs. Each may produce 7.5 million cubic feet of gas per day in their first year. Production declines rapidly but typically levels off at around two million cubic feet per day then stays steady for years. When gas prices improve, the new wells will be cash registers.

Donald Alexander Smith: Lord Strathcona

b. Aug. 6, 1820, Forres, Moray, Scotland
d. Jan. 21, 1914, London, England

First Baron of Strathcona and Mount Royal East, Donald Alexander Smith was a great Victorian entrepreneur. While making a large fortune for himself, he used business and politics to help cobble together British North America.

To understand his weight in international business, it is important to remember a grant (in effect, articles of incorporation) that King Charles II issued in 1670 to the Company of Gentlemen Adventurers Trading into Hudson Bay. The grant went to his cousin, Prince Rupert, and a small group of Rupert’s business associates.

Today known as the Hudson’s Bay Company or The Bay, the organization’s charter provided for a monopoly over trade in the lands fed by rivers flowing into Hudson Bay. The equivalent of 40 per cent of modern Canada, that vast territory was known as Rupert’s Land until after Canadian Confederation began in 1867. Constructed upon trade in premium animal pelts from cold northern climates, it was history’s largest private commercial empire.

The most notable of many notable men to rise through company ranks, Smith began his career at The Bay in 1838, as a clerk. Fifty years later, he was the company’s major shareholder, and he served as governor for another 25 years, until his death in 1914.

Smith was born in Scotland in 1820, knighted in 1886 and granted a peerage in 1897. He was a fur trader, financier, railway promoter and statesman. He was also a politician, and he was not averse to using Parliament for personal advantage.

A towering figure in Canadian business and politics in the formative years of the nation, during his long life Smith displayed a brilliant, restless energy. Dour by temperament, his fur-trading years in the cold, rugged north made him as tough as nails. The Bay was a strict taskmaster.

Smith understood the company’s role in Canadian history. When he received the keys to the City of Edinburgh in 1903, he gave a thoughtful explanation of its impact – although one that suffers from political correctness in present-day Canada. The subject of his speech was “young Scotsmen – their capacity for hard work.”

According to Smith,

“The men who have been connected with the administration of the (Hudson’s Bay) Company for the last two centuries have been mostly drawn from Scotland. They cut themselves away from the world for long periods; they looked after the interests of the country, and became friendly with the aborigines. But for their watchfulness and their determination to look after British interests, it is quite certain that Western Canada today would not be a part of the Empire. And it is equally certain that the transfer of the Hudson's Bay territory to Canada could not have been carried out so readily and with so little friction, but for the civilising influence which the Company had exercised for so many years."

Smith was heavily involved in the negotiations through which The Bay ceded its lands to Canada in 1869, and he became Ottawa’s negotiator when local Métis leader Louis Riel staged a rebellion in reply. The following year Smith was elected to Canada’s House of Commons by a political riding in the new province of Manitoba; this was the beginning of his political life. He simultaneously served as chief commissioner for The Bay.

Smith was a key figure in business within the feisty frontier province, which had been home to fur-trading forts before becoming a small colony. He created a monopoly on riverboat freight traffic from Minnesota to booming Manitoba, which was now being settled through that adjacent American state. His railroading experience began when he and his partners successfully promoted the St. Paul, Minneapolis and Manitoba Railway.

Early in his years in Parliament, Smith played a decisive role in bringing down the federal government of John A. Macdonald, a fellow Conservative. At issue was the Pacific Scandal (1873), linked to an early proposal for a railroad to the west coast.

After Macdonald returned to power, he resurrected the railroad project, which went forward in 1880 with Smith’s financial support. Smith created a syndicate controlled by five Canadians (including himself) who directly owned only 20 per cent of the shares in the Canadian Pacific Railway (CPR). Prime Minister Macdonald remained angry because of Smith’s withdrawal of support during the Pacific Scandal, so Smith was not on the board of the new enterprise.

The CPR connected Canada’s commercial heartland in southern Ontario and Québec to the Pacific Ocean. This meant cutting through the stone, forests and swamp of the vast Canadian Shield; building through the flat, unsettled prairies; raising trestles and dynamiting tunnels through the western cordillera. So doing, it tied the southerly perimeter of what had once been Hudson’s Bay Company lands into the Canadian orbit, and therefore into the Empire.

In a way, in 1885 the railroad itself vindicated Smith of Macdonald’s wrath. In that year, he became the central figure in Canada’s best-known photograph. Surrounded by a crowd of railroad workers in southeastern British Columbia, he was driving the last spike in the world’s longest stretch of railroad.

Always faithful to both Canada and the Empire, at age 69 Smith became Canada’s High Commissioner to London. Eleven years later, he equipped and maintained a regiment for the Boer War (1899-1902). Also known as the Royal Canadians, Lord Stathcona's Horse Regiment celebrated its centennial anniversary in 2000.

Lord Strathcona supported educational and philanthropic causes. He was a patron of McGill University in Montreal, where he founded the Royal Victoria College for women. In addition, he served as rector and chancellor of the University of Aberdeen.