Selling Canada?

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As Asian efforts to secure Canadian energy supplies intensify, can nationalist forces be silent much longer? This article appears in the November issue of Oilweek.

 By Peter McKenzie-Brown
In Canada, economic nationalism fell into a slumber twenty years ago. Is it likely to begin stirring again? According to Dr. Robert Mansell of the University of Calgary, “I could imagine a new period of nationalism. After all, public attitudes tend to go through regular cycles.”

An economist, Mansell is academic director of the university’s School of Public Policy and the founding director of the Institute for Sustainable Energy, Environment and Economy. Although he recognizes the possibility, Mansell puts a lot of caveats on the prospect of a nationalistic surge. “We’re still in a period with a high level of globalization, so I would be surprised if we said ‘No more foreign ownership.’ The markets are too big now (for Canada) to finance a lot of (the petroleum industry’s) activities, so you have to go into international markets for large amounts of money. We don’t have a lot of fiscal surpluses to finance many of these projects. This limits our options.”

However, he notes that political conflict with China, say, could lead to public concern about Chinese investments in Canada’s oil industry. In the United States, an outright political row wasn’t even required five years ago. That’s when a public outcry put an end to an $18.5 billion hostile bid by state-controlled China National Offshore Oil Corporation for UNOCAL, an American major. Chevron-Texaco acquired Unocal later that year.

Asian Investments
This has become an issue of interest because the sources of overseas funding for North America’s energy industry are undergoing a fundamental shift. “The axis of investment capital is rotating from a north-south flow over the 49th parallel to an east-west current across the longitude of the Pacific Ocean,” says author and analyst Peter Tertzakian of ARC Financial. “A recent swell of Asian money coming into the Canadian oil patch represents one of the biggest megatrends in the business.” Tertzakian does not mention a sub-feature of this shift of Asian funds: much of the money is coming from national oil companies
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By no means is this trend limited to Canada. Increasingly, developing countries with financial reserves are investing those funds in countries with large oil and gas resources. “Relative growth in energy demand has shifted quite dramatically toward Asia,” says Robert Mansell. “As demand shifts, one would expect (Asian) interest to shift to Alberta, especially since the number of countries which are attractive for petroleum investment is shrinking. There has been an expansion of interest in national oil companies for a variety of reasons, one of which is to achieve security of supply. Energy security (in Asia) is an even bigger issue than it is North America.”

Peter Tertzakian puts the issue starkly. “Since world war two there has been a symbiotic, bi-directional flow of capital and energy resources between Canada and the US. Now a new dynamic is emerging…. Growth economies like China look very similar to the United States in the 1950s and 60s – capital rich and hungry for energy.” In a series of charts and tables, he sums up the shift in funding.

“Big foreign companies like India’s Reliance Industries, China National Petroleum Corporation and Mitsui have been teaming up with domestic independents that hold large land positions in shale gas plays, mostly in the US” he says. “Under twelve joint venture agreements these foreign entities have committed $17.2 billion of funding to obtain carried interest in new wells being drilled by independent natural gas producers like Chesapeake, EnCana, Pioneer, Atlas and Carrizo.” The charts illustrate the recent flow of money from overseas economic powers into North America’s shale gas business.

Within Canada, some funds have flowed to shale gas, but more has gone to the oil sands. The table of foreign investments in the last 12 months illustrates that Asian investment in Canada has focused more on the oil sands more than shale gas. The table does not include another notable 2009 investment: Sinopec’s acquisition of Addax Petroleum for $8.27 billion.

Of the new Asian partners, four are national oil companies headquartered in China or Korea. However, the acquisition of Harvest Energy by an agency of the Korean government deserves special note. Harvest was an intermediate-sized Canadian energy trust. From a standing start, in ten years president and CEO John Zahary created an entity he was able to sell for more than $4 billion. That’s a lot of money, but relatively small potatoes in the context of Canada’s hundreds of billions of dollars’ worth of total oil and gas assets. Outside the industry, people paid scant attention
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Harvesting Energy Companies
Of course, Korea isn’t China, and Harvest Energy isn’t Unocal. Even so, the deal stoked concern that, after watching parts of the oil patch go to other state-owned companies, the Canadian government will eventually step in to block transactions.

According to John Zahary, though, the South Korean company’s commitment to boost spending is the only thing that’s relevant. “We see this as an opportunity for increased jobs in the country, increased capital investment in (Harvest’s) assets,” he said. “KNOC (the Korean National Oil Company) now owns 100% of the equity in the company – that’s true. But I believe that even under the new ownership Harvest is still a Canadian company. The management is here, the employees are here, the resources are here and the resource owner is here. We now have a board of directors of eight people: five are Canadians and three are Korean nationals.” To make the deal happen, Zahary negotiated a 47% premium to the company’s then-current price. He now expects to see Harvest continue to grow.

“Why did they want to invest here?” he asks rhetorically. “We have a resource that is relatively underdeveloped, a people base and a technology base. We have relatively stable fiscal and regulatory systems and a history of openness to foreign investment, and that differentiates us from other countries. Canada is an excellent place to invest. I look at foreign investment (in this country as part of the) maturing of the nation.” The University of Calgary’s Mansell agrees. “….In this global environment even companies that you think are purely Canadian are likely to have most shares held outside the country. The key issue is their local presence. The control is local. There are a lot of regulations in Alberta,” for example. “Whether foreign or local, companies have to follow the rules that we make. They can’t avoid them.”

Another rhetorical question: Why did Zahary want to sell Harvest Energy Trust? Partly because Ottawa’s Halloween Massacre in 2007 made energy trusts so much less attractive. Prior to the sale, Harvest’s unit price had cratered since its pre-massacre high – down about 80%. This, of course, illustrates government’s power.

The case for economic nationalism
Perhaps the most unlikely supporter of government regulation is Richard Haskayne. Known universally within business circles as Dick, he has served as the chair of six large Canadian companies: Interhome Energy Inc., TransCanada Corporation, Fording Inc., NOVA Corporation, TransAlta Corporation and MacMillan Bloedel.

“My philosophy is that Canada needs regulation to protect strategic sectors,” he says. “This is not a new hobby horse for me. A few years ago I wrote an article promoting the idea behind Canada’s Bank Act, and I got a lot of flak about it. But recent events have demonstrated that it worked really well for Canada. The reason (I support that kind of government control) is that banking is so strategic for Canada.”

He supports government regulation of energy and mining ownership because they, too, are strategic. “That’s our strength. Of the ten top stocks in Canada there are four banks, three energy companies and three mining companies. Seventy percent of the stocks on the TSX are in those industries.”

“I’m not opposed to foreign ownership as such,” he says “– only when someone takes over 100% of a classic Canadian company like Potash Corp. Look at Vancouver without McMillan Bloedel. Look at the Windsor waterfront now that Hiram Walker is no longer there. Head offices are critical to the operation of Canada and to our decision-making.”

Haskayne sees Canada’s Bank Act as a good model for bank regulation. The act prevents any individual from owning more than 10% of the shares of top tier banks, and says the aggregate holdings of non-residents and their associates may not exceed 25%. In addition, their head offices must stay in Canada and their boards must consist mostly of Canadians. Deeply concerned about what he calls the “hollowing out” of head offices from Canada, he’d like to see similar provisions applied to Canada’s biggest energy and mining companies. “It’s the concentration of shares that’s the critical part.”

An irony of Haskayne’s position is that as chairman he sold Nova’s controlling interest in Husky to Li Ka-shing. “I admit I sold that company to Hong Kong interests,” he says, “but in those days Husky was in terrible shape. It was almost broke. The banks were on their tail. We tried to sell it. I went to David O’Brien at PanCanadian and tried to get him to buy. I said, ‘It’s a hell of a deal for you. It’s got so much heavy oil and it’s got refining interests….’ David turned to me and said, ‘Haskayne, get out of my office. I don’t want that sick dog [Husky] in my kennel.’ You can’t get much more of a refusal than that. So we sold our share (to Hong Kong interests) for $375 million. Well, today that interest is probably worth $15 billion, so they made a hell of a deal. I apologise for that, in a way. However, there wasn’t much we could do. Li Ka-shing’s group was holding the golden shares, and that made it hard to sell” the company to anyone else. Husky is now one of Canada’s biggest energy companies.

Asia’s energy security
Canada’s last round of economic nationalism began in the 1970s, when nationalization of the petroleum sector within OPEC inspired Canadian governments to set up their own oil companies. The idea was to Canadianize a vital resource sector. The last vestiges of those experiments disappeared a year ago, when Suncor absorbed Petro-Canada.

Are Asia’s efforts to find energy security with the aid of national oil companies (NOCs) also doomed to fail? “For the foreseeable future,” says the University of Calgary’s Robert Mansell, “Asian countries are not likely to be getting any Canadian product directly. But they can still do swaps and so on, taking oil that would otherwise have gone to the United States, diverting production. Markets enable you to move that oil around. Different market arrangements will allow you to increase security.”

He cautions against thinking of all NOCs as being the same, however. “There are quite different NOCs. For example, Statoil is really not much different from what we think of as a privately owned company. Some of the other companies are a different animal, though – they are just an extension of the state. There are quite different variations when you start looking at national oil companies.”

Although he sees economic nationalism as a possibility, Mansell is sceptical about its staying power. “A serious political conflict between, say, China and Canada could create a public reaction, and it’s quite easy to imagine” a public outcry against Chinese ownership of Canadian resources. “However, in the long run it seems to me that most Canadians appreciate that we as a country benefit from global investment.”

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Perception, Reality and Transparency

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Industry is working to improve its communications, but more importantly its actual performance

This article appears in the October issue of Oilsands Review

by Peter McKenzie-Brown and Deborah Jaremko

The oilsands industry is under near-constant attack from environmental groups and other non-governmental organizations (NGOs) bent on putting an end to “the most destructive energy project on earth.” The phrase “stop the tar sands,” and the moniker “dirty oil” are well known, and not taken lightly. The Alberta government and various industry organizations are taking on the challenge of battling negative perception with the facts about existing development, but also with something even more powerful — commitment to do better, and to prove it.

The “Big Lie” and the Age of the Internet
As Adolf Hitler was dictating his book Mein Kampf in 1925, he coined the term “the Big Lie.” A propaganda technique, the Big Lie refers to a falsehood so “colossal” that no one would believe that someone “could have the impudence to distort the truth so infamously.” Hitler used the technique to good effect through his years of tyranny. However, in established democracies things are different. Government, media, academia and business are all held to account, and among those organizations anything like the use of the Big Lie encounters widespread derision.

“Government tends to be constrained by fact,” says Alberta government spokesman Jerry Bellikka, with withering irony. “We are held to account for what we say. If we were to knowingly put out misinformation, academics, environmentalists, opposition politicians, the public and traditional media would hold us to account. When the premier is talking about emission reductions in the oilsands, if he does not say ‘per barrel,’ he is called on it right away.”

But in emergent web-based media, accountability is self-imposed. Most of the influential NGOs use reasoned arguments and collaborate with government and industry as they advocate for their causes; the Pembina Institute comes to mind. However, some major environmental groups use those media without much regard for facts. Therein we may find the 21st Century version of the Big Lie.

“[Some] people are making pretty outrageous claims,” says Bellikka. “What they want is a reaction. It’s one thing to have a discussion based on fact and current data. It’s another thing to put out inflammatory material, not much of which is accurate...it’s to get a reaction and that’s what these campaigns are designed to do. They are based on emotions, on wild accusations. Yet these same groups call governments the propaganda machines.”

The message presented by anti-oilsands groups in various forms — from feature-length documentaries and short YouTube videos to online games and protest actions — is one of environmental and social degradation that has been called as much as “Armageddon.”

“We want to lift the lid on the horrors of oil exploration taking place in a country that has a reputation for being the cleanest in the world,” says Michael Marx, executive director of Corporate Ethics International, the group behind the recent ReThink Alberta campaign. The initiative, spread through the web and via billboards in four U.S. cities as well as London, England, encourages potential tourists to Alberta to reconsider their travel investment until the tar sands industry is no more. “Tar sands mining in Alberta has not only caused irreparable damage to the environment but the health of local communities which have seen a dramatic rise in rare cancers linked to the same compounds found in tar sands operations.”

The dramatic proliferation in the number of groups like Corporate Ethics International, and the growth in public and private grants and contracts flowing to them, have enabled NGOs to become powerful political forces. In a sense, they are now filling a credibility vacuum that has been developing for 20 years. Poll after poll has shown declining confidence in such institutions as government, business and traditional media. This has created great demand for independent information and analysis, which NGOs can easily deliver through web-based communications.

“They do not work with small budgets. They are often well-funded,” notes Bellikka. “[Some NGOs] have told us that when they do one of their campaigns they get lots of donations. Whether [that is] accurate or not, we don’t know; they don’t give us access to that sort of information directly. But, what we do know is that these are very well-funded campaigns. Greenpeace is an excellent example.” Last year Greenpeace had total worldwide income of about €200 million ($272 million), and directed about €28 million ($38 million) of that to off-oil climate and energy campaigns.

From Defence to Proactive Discussion and Education
Although often characterized by highly exaggerated and even inaccurate claims, it is more than big budgets and social media wizardry that grants off-oilsands groups a position in public perception. The truth is that the concerns are not entirely unfounded — oilsands development undeniably does negatively impact the environment. It is communicating the actual extent of this impact that has been the challenging burden of industry and government, but now that mission is being taken a step further.

“We have spent a long time being framed as villains by environmental organizations, and we have been trying to prove them wrong. That was not an effective approach,” says Janet Annesley, vice-president of communications for the Canadian Association of Petroleum Producers (CAPP). “We have to show Canadians our business. We have to show them the kinds of people who work in our companies and the solutions we find to problems in a difficult business. We need to exit the discussion about who is right and focus on doing good work.”

She says that according to CAPP polls, 74 per cent of Canadians say that the industry should be developing the oilsands. “Our strategy should be to say, ‘Yes, Mr. and Mrs. Canadian. You are right. And that is exactly what the industry is doing today.’ The advertising campaign we launched last June is simply following that plan.”

Annesley describes the off-oil NGOs as being driven by an agenda, but shares some consternation about what that agenda is. “They really seem to think that Big Oil is the only thing standing between society and a renewable energy future. That doesn’t make any sense, but they do seem to believe it.”

She continues, “We fundamentally beg to differ. The solutions are not available today. We know that energy demand is increasing, that energy resources are declining and that much of the conventional energy available is in countries that are very difficult to do business with. We know that energy supplies must diversify. We know that energy development is under greater scrutiny than ever before. And we know that the industry has to meet the planet’s growing energy needs in ways that are increasingly environmentally accountable. That is the rock and the hard place in which we sit.”

The industry is widely understood to offer economic benefits to Canadians, she says, and “we are widely understood to be reliable suppliers of energy. However, we are not widely understood to be providing environmental solutions. That’s where we need to focus. We need to be talking about the issues of economic benefits; energy security and environmental care in a balanced way, but that conversation shouldn’t begin with someone dangling from the top of the Calgary Tower [a recent Greenpeace action].”

Roger Gibbins, president and chief executive officer of the Canada West Foundation, sums up the problem nicely. “The oilsands proponents will to some degree always be on the defensive on the environmental front,” he says. “The oilsands industry has a lot of negative images to deal with. The industry has to acknowledge that its work has had an adverse environmental impact in the past, and begin there. I think that if the industry is a bit repentant, and admits it hasn’t done the best job in the past, it will be in a better place to win people’s minds and hearts. Just arguing with environmentalists doesn’t have that effect.”

CAPP’s Responsible Canadian Energy program
In announcing the winners of its Steward of Excellence awards this spring, CAPP launched a new program dubbed Responsible Canadian Energy, which is designed to be a platform from which the industry, unified, can demonstrate and communicate its commitment to responsible resource development.

“The way the world sees us is defined by our performance. The linkages between stewardship and the reputation of the energy sector have never been clearer,” says CAPP president David Collyer. “This is not at all about communicating our way out of a problem. It never has been and it won’t be in the future. We certainly need to focus on communications to improve awareness and understanding, but it is essential that this be underpinned by ongoing improvement. In a world that is always moving and changing, we can’t stand still. We have to do better, and we will.”

Collyer continues that, “For some, the oilsands is the economic saviour of a recession-weary country. For others, oilsands development symbolizes a world that has grown far too dependent on fossil fuels. In reality, the oilsands is neither. The truth, as they say, is somewhere in between. CAPP and its members fully recognize that the reputation of this increasingly important industry is determined by two things: performance and communication. We also know that both must be delivered consistently and authentically over time.”
CAPP says a performance report based on the Responsible Canadian Energy initiative will be issued this fall, with 2010 serving as the baseline year as producers “refine and advance” the program. The report will include data on environmental and social performance, and will be followed by a white paper in December 2010 based on an energy dialogue series in Canada and the United States.

The Oil Sands Leadership Initiative
One of the worst-kept secrets in the oilsands industry is under wraps no longer — that is, the Oil Sands Leadership Initiative (OSLI), a consortium of five major players with a self-described “laser focus” on improvements in environmental performance.

With a $10-million budget for 2010 (expected to double or triple in the coming years), Suncor, ConocoPhillips, Nexen, Statoil and Total have a mind to change the bitumen game.

Gordon Lambert, Suncor’s vice-president of sustainability, explains that OSLI has been up and running for about a year and a half, with 2010 as its first official operational year. He says that the group’s genesis was a recognition of the need to accelerate the pace of environmental performance measurement and improvement, while understanding that in order for continued success in this particular space, the needs of the whole outweigh the needs of each individual company.

“We compete in some areas of the business. We don’t compete in reducing our environmental footprint,” says Lambert. “We felt we could make more progress by working collectively than by working individually. The more ideas you get on the table, the better the chance of success.”

The OSLI charter outlines working groups designed to address water management, carbon management and energy efficiency, land stewardship, sustainable communities, technology breakthroughs and other focus areas as agreed on by its steering committee.

One of the first initiatives that OSLI is working on is a $2.5-million feasibility study into a potential new water distribution plan for the Athabasca oilsands region. Dubbed the Regional Water Solutions Study, Lambert says the idea is to work out whether it is environmentally and economically viable for oilsands producers in the area to reuse water left in mining tailings as steam generation source water for local in situ projects. The notion is not as “blue-sky” as it may sound — Suncor itself already uses its tailings water from mining operations to supply its Firebag steam assisted gravity drainage project. However, Lambert says applying it on a regional scale would require a broad consensus — the subject of the feasibility study.

Another key OSLI initiative is OSTECH, a “technology identification structure based on a web portal.” The group says that through this portal, inventors, entrepreneurs and the general public will be able to submit projects and ideas that can be further developed within OSLI. Lambert says it will be a one-window system for the member companies to share in evaluation of the new technology ideas that are presented to them, reducing duplication of due-diligence efforts.

“Innovation and the oilsands go hand in hand. It has always been that way,” he says. “New ideas are coming forward all the time.”

A key part of OSLI’s mandate is transparency around advancing its performance improvement efforts, which is one of the reasons it did not publicly herald its initial creation.

“We’ve been cautious of waiting to communicate on results and action versus intent,” says Lambert. “In 2011, you will see us stepping out more visibly.”

Maintaining the Faith

Five visionaries who changed the path of the oilsands industry, and the wall over which the sixth must climb.Photo: Karl Clark

This article appears in the September 2010 issue of Oilsands Review

By Peter McKenzie-Brown

Oilsands development continually hits a wall of some kind, and obstacles to development seem insurmountable. However, at critical times in the history of the oilsands, a visionary leads the charge over the wall and an important new stage of development takes place. This is the idea behind an excellent presentation titled “Visionaries – Climbing the Wall” given by Dr. Clement Bowman. The present commentary develops that idea, but mostly uses different historical resources.

By the 1920s it was clear that the sands are not underlain by a huge pool of light, source oil. The oilsands are just what they appear to be: huge deposits of sand saturated with thick, gunky bitumen. Encouraged by government, some entrepreneurs tried paving roads with the stuff. No luck; now what?

Enter a research chemist Bowman’s first visionary. With tremendous determination and limited support from the newly fledged Alberta Research Council, his employer, between 1923 and 1930 Clark developed and demonstrated the bitumen extraction process which, with some tweaks, is in use today in oilsands mines. His work made it clear that oil can be extracted from the sands. His name was Karl Clark.

Over the next two decades a few small projects began producing. They were not commercially successful, however, and didn’t use Clark’s extraction process. Each was eventually destroyed by fire. After the Second World War there was no commercial interest in this intractable resource – especially after the 1947 Leduc discovery, which made it clear that large reservoirs of light oil were available in the province.

Despite the legacy of failed commercial efforts, a Canadian politician became the next visionary. He arranged for the province to commission the Bitumount demonstration plant using Clark’s hot water process, and had the entire legislature visit the plant in 1949. He also commissioned an independent evaluation by Sidney Blair – an oilsands expert who began his oilsands career as Karl Clark’s research assistant. Blair concluded that the oil sands were “a commercially viable source of crude oil that could compete on the world market.” The visionary’s name was Ernest Manning, Alberta’s longest-serving premier.

The industry acquired additional oilsands properties and undertook experiments in mineable oilsands development in the 1950s and 1960s. For his part, Manning maintained a life-long belief in the importance of the sands to Canada.

In the 1960s, Alberta announced that it would only approve small oilsands projects. Light oil production was still growing, and the province didn’t want too much competition between oilsands and conventional oil. The province’s insistence on small-scale projects led to thin private sector support.

The visionary who surmounted this obstacle was an octogenarian and a personal friend of Premier Manning. On his insistence, Sun Oil Company filed an application for a 31,500 barrel per day project (later amended to 45,000 barrels per day). In 1967, he told his audience at opening ceremonies for Great Canadian Oil Sands that “No nation can long be secure in this atomic age unless it be amply supplied with petroleum . . . . It is the considered opinion of our group that if the North American continent is to produce the oil to meet its requirements in the years ahead, oil from the Athabasca area must of necessity play an important role.”

The name of this visionary is J. Howard Pew, and he was then chairman of Sun Oil Company, Today, GCOS is known as the Suncor Oilsands Plant.

In 1973, a second commercial project was losing private sector support because of the alarming escalation of costs besetting major North American projects. The Syncrude budget had more than doubled to $2.3 billion, and a major corporate partner pulled out. One man more than any other saved the day. He kept the remaining partners onside while marshalling equity participation in the project from the Alberta, Ontario and federal governments. He set up the first lab dedicated to oilsands research, and developed a long-term plan for upgrading bitumen. He was Syncrude’s first president, Frank Spragins.

In the 1970s, multinational companies had few active development plans for in situ leases. While these deeper deposits represent 80 per cent of the resource, there were no viable in situ technologies for the Athabasca, Peace River, Carbonates, or Wabasca deposits. The major exception was Imperial Oil, which was making limited progress at its Cold Lake site.

Once again a provincial politician took the lead. In 1975, he created the Alberta Oil Sands Technology Research Authority (AOSTRA) to provide government support for private research. During its 15-year life, AOSTRA provided $670 million of funding for oilsands research. Roger Butler’s SAGD process was the single most important advancement from this program. The politician? Premier Peter Lougheed.

Visionary number six has the opportunity to change Canada over this decade, leading the shift to production of cleaner, higher-value products from the oilsands.

There are more major obstacles, they are here and now, and they are environmental. Water, air and land are no longer free; there is a powerful green consciousness demanding that they be protected. Many consumers do not want to use products manufactured from Alberta’s “dirty oil.” Financial markets are concerned about the burden of environmental risk.

Who will help the industry overcome these obstacles? According to Clem Bowman, the next visionary will be able to articulate energy as an integrated system with the oilsands, hydro, natural gas, coal, nuclear and renewable energy all performing key roles. As importantly, that person will have the skills to forge the national will to make Canada a sustainable energy superpower.

Bowman does not conjecture on who this person might be,but his or her name will be marked in history.

In Alberta, An Instinctive Understanding

This article appears in the August issue of Oilweek magazine

By Peter McKenzie-Brown
“Pipelines are us,” Bob Taylor reminded me one day over lunch. Formerly Assistant Deputy Minister of Energy (Oil) with the Alberta government and now a consultant who specializes in energy systems innovation, he was discussing the two-fold importance of pipelines to the oilsands.

Before moving to the punch line, however, he put the discussion into context. Because of environmental worries, “oilsands producers are facing steadily increasing resistance in the provincial, national and international arenas.” He continued: “Unless we address these issues, the industry risks losing the social license to operate.”

With that, our wide-ranging discussion turned briefly to a particular theme. One reason you need pipelines is to take production to market. Without new or expanded pipelines, production growth would be next to impossible. However, the oilsands also require specialized pipeline networks to reduce their environmental impacts and to produce more efficiently.

Several examples illustrate this theme, and each carries a budget of $400 million or so. One is Williams Energy’s Boreal Pipeline, which will run from just north of Fort McMurray to Redwater, Alberta. The other is Enbridge’s Waupisoo pipeline expansion. Waupisoo originates at a terminal on Enbridge’s Athabasca Pipeline, 70 kilometres south of Fort McMurray. From there it stretches southwest to a pipeline hub near Edmonton. In addition, Pembina Pipelines is building a pair of lines to serve producers operating near Slave Lake.

Boreal Pipeline
The proposed new Williams pipeline is part of a project which turns waste into commercial products. So doing, it reduces carbon emissions and feeds valuable feedstock to the petrochemical sector. Williams Energy’s cryogenic liquids extraction plant near Fort McMurray recovers natural gas liquids and olefins from a stream of off-gases produced at the Suncor plant. Located about five kilometres away, it returns a sweet, leaner fuel to Suncor, which uses the returned gas for generating industrial heat. This enables the plant to operate more efficiently and reduces its carbon dioxide emissions.

As importantly, this profitable project provides feedstock for the petrochemical industry. Williams transports the recovered gas liquids to a facility in Redwater, northeast of Edmonton, for processing into products such as ethane, propane, butane, condensate and the olefins of ethylene, propylene and butylene. Before Williams began this operation, the hydrocarbons were just burned.

Now eight years old, this business has been so successful that Williams is expanding it. The new 420-kilometre long, 12-inch diameter Boreal pipeline will initially transport to Redwater up to 43,000 barrels of liquids per day. Later, it will expand to 125,000 barrels per day. Pipeline construction will take three seasons – from this fall to spring 2012.

As part of this large project, the company is building up processing facilities at both ends of the pipe. For example, Williams recently raised a 70-metre fractionation tower at its Redwater plant. This allows the company to produce a higher-quality product from the existing 14,000-barrel-per-day plant by splitting the butane and butylene components. There is much more to come.

Waupisoo Expansion
As summer began, Enbridge announced that it had made commitments to producers to make available an additional 229,000 barrels per day of capacity on the Waupisoo Pipeline. The 380-kilometre pipeline system is designed to carry up to 600,000 barrels per day of oilsands crude.

Four additional pumping stations and upgrades to two existing stations are the basis for the expansion which will take Waupisoo to design capacity of 600,000 barrels a day. The expansion will take place in two phases. The first 65,000 barrel per day expansion will be complete in the second half of 2012. An additional 190,000 barrels per day will be added by the second half of 2013.

The actual capacity of the line will depend on the viscosity of the crude it is carrying. Heavier oils travel more slowly, reducing capacity. Lighter oil blends are faster, and will be the transportation product used when the line is operating at design capacity.

Regulated by Alberta’s Energy Resources Conservation Board (ERCB), Waupisoo links producers to their upgraders and to refineries in the Edmonton area. It also connects to some of Canada’s other oil pipeline systems.

Enbridge operates the world’s longest crude oil and liquids transportation system, with a network of lines in Canada and the United States. The Waupisoo expansion will strengthen Enbridge’s position as the largest pipeline operator in the oil sands region; also, it likely will cement the company’s position as the shipper of choice for new oilsands producers.

Pembina
Of course, no one will ever dominate that market, as another pair of lines now under construction by Pembina Pipelines illustrates. The company’s new Nipisi Pipeline – designed initially to transport 100,000 barrels per day of diluted heavy oil – will reach from north of Slave Lake to Judy Creek. From there it will connect to an existing pipeline system, delivering products to the Edmonton area. Ultimately, Nipisi’s capacity can be doubled.

As part of this project, Pembina will construct its Mitsue Pipeline, which will ship 20,000 barrels per day of condensate diluent from Whitecourt to producers operating north of Slave Lake. Mitsue could ultimately be expanded to 45,000 barrels per day. Cost of this package of pipelines? About $440 million.

Each in its way, the pipelines covered in this review represent different aspects of what’s going on in the industry. On the one hand, they support growth. On the other, they contribute to greater efficiency and reduced environmental impacts. In Alberta the understanding of these two purposes seems almost instinctive – probably because, for decades, within the province vast networks of these systems have been operated by tens of thousands of employees. As a result, new pipelines and pipeline expansions encounter relatively little public resistance. Pipelines are us.

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Waste to Wealth

Why waste management in the oilsands could better echo the mutually beneficial relationships in nature. This article appears in the August issue of The Oilsands Review.

By Peter McKenzie-Brown
Academics have developed a discipline known as industrial ecology to help explain the behaviour of the economic world, but you can do more than use this discipline to understand economics. You can use it for strategic planning. According to an influential group of thinkers headquartered in Alberta, the future of the oil sands lies in “industrial symbiosis” – a specialty within the field. It’s a simple idea, but it could have the power to transform the oil sands sector.

A few months ago I got an invitation to participate in a workshop developing this idea, with a key proviso: If I reported on the proceedings, I couldn’t attribute a quote to anyone without first getting permission. The point was to create a working environment in which no one felt constrained by the presence of a reporter. No problem: for this article, the ideas are more important than the industry, government, and university people behind them.

The workshop was jointly sponsored by ConocoPhillips and Alberta Innovates, an umbrella group of provincial agencies meant to be “catalysts of innovation” in the energy and environment, health, technology and bio sectors.

We met at the provincial government’s McDougall Centre in Calgary. While the topic was zero waste from the oil sands, participants produced the usual amount of think-tank rubbish in the form of Styrofoam cups and disposable plastics. Probably nothing was recycled – one of the easy forms of waste management.

The task set before the group was to brainstorm a plan for regional integration in the Fort McMurray area. Under this scheme, industry and government would look for ways to encourage the creation of waste-reducing business ties. Oil sands companies, other industries and municipalities in the region would share or co-locate infrastructure to reduce redundancy, harness waste energy and convert residual materials into value-added by-products.

The Big Word
To understand this, let’s get the big word out of the way. Symbiosis occurs when living things develop cooperative or dependent relationships with others so they can live longer or better and prosper. Familiar examples: people on the one side, cultivated plants and domesticated animals on the other. Each side needs the other to thrive.

Industrial ecology describes industries as ecosystems with behaviours somewhat similar to those in nature. Industrial symbiosis involves creating dependent or cooperative relationships within the sector. Done right, this approach can create more sophisticated, efficient and profitable businesses. It can also reduce the output of such industrial wastes as heat, carbon dioxide emissions, and other pollutants.

There are many instances of companies extracting by-products from a waste stream and then transforming them into money-making products. For example, Williams Energy Canada removes pentanes, butanes, propane and olefins from the off-gas stream at Suncor’s Fort McMurray operations. The company pipes the butanes and olefins to Redwater, where its 14,000-barrel-per-day plant further processes them into petrochemical feedstock. In May Williams announced a series of expansions to this system, including the construction of more processing facilities and a new pipeline.

Another example is the fertiliser plant at Syncrude, which helps the oil sands giant comply with environmental regulations. Marsulex Inc. owns and operates the plant which, using technology the fertiliser company developed, employs waste ammonia from Syncrude to help clean up sulphur emissions from bitumen processing and upgrading. The value-added by-product from the operation is ammonium sulphate fertilizer.

Similarly, Shell strips feedstock from the hydrocarbon stream at its oil sands upgrader at Scotford. The company pipes those by-products to its nearby petrochemicals plant for feedstock.

Looking into the future, Edmonton-based Titanium Corporation has developed an entire business plan based on processing waste oil sands material into valuable products. The company has developed technology that can recover both heavy minerals (zircon and titanium) and bitumen from tailings ponds at Fort McMurray-area plants.

There are economic and environmental benefits to this approach. Companies can generate profits for their shareholders. The environmental footprint is smaller, because symbiosis enables industrial players to manage emissions and other waste streams better. And there are improvements in the economics of transforming low-cost bitumen into higher-value products. It seems like a no-brainer.

The Toilet and the Tailings Pond
Over two days, workshop discussion was thoughtful and varied, and it included colourful one-liners enlivening subtle and colourful ideas. One person summed up a complex discussion with an on-the-spot maxim: “Don’t connect the toilet to the tailings pond.” The idea is that the plumbing should be designed to easily redirect plant by-products (including waste heat) to new facilities as money-making uses for them are found.

Co-author of an executive primer titled Discovering Industrial Ecology, the University of Alberta’s Dr. Stephen Moran suggested that companies should “assign to each major waste a product number, then assign a product manager to it.” An important outcome of that perception-altering idea would be the creation of markets for valuable wastes. Syncrude’s waste ammonia is one good example. Another: the propane and heavier hydrocarbons which Suncor used for plant fuel until Williams began to extract them for feedstock.

At the other end of the feedstock spectrum, consider that ERCB regulations now require the companies drilling Steam-assisted gravity drainage (SAGD) oil sands wells to send all materials from the well, including oil sands from the horizontal legs, to a secure landfill. Why not treat that material as oil sands ore and ship it instead to a mining operation for processing?

According to Bob Taylor – formerly Alberta’s Assistant Deputy Minister for Oil and now a consultant who specializes in energy systems innovation – all manner of coordination is possible. If several facilities coordinate their waste management operations, there will be fewer garbage trucks barrelling down the road. What about gasifying solid waste produced by field camps along with suitable regional waste, including slash from woodland operations? He also suggests a regional water strategy that “seeks to utilize this limited resource to support a much higher level of development and production than if we continue down the current path.” Taylor sees co-generation as another important area of opportunity. For example, waste heat from generating electricity could produce steam for cyclic steam stimulation (CSS) or SAGD operations.

There are also opportunities in assets external to the oil sands – infrastructure like roads and highways, the power grid and an often-discussed railway link to Fort McMurray. According to Taylor, “engaging parties beyond our normal spheres of influence (will help us) realize (symbiotic) opportunities that will enable our industry to better meet social and profit expectations alike.” The ideas got increasingly complex, and it quickly became clear that the potential is huge.

Triangles
One appeal of waste management through industrial symbiosis is that it contributes positively to three of society’s broadest concerns: economic growth, stewardship of the environment and efficient energy consumption. Take the Williams off-gases project, which strips heavier hydrocarbons from Suncor’s fuel stream. This industrial magic enables the plant to operate more efficiently, reduces Suncor’s carbon dioxide emissions and provides feedstock to the petrochemical industry. Not a bad outcome for a single piece of innovation.

A participant noted with some surprise that the environmental footprint is triangular in shape, with its three sides consisting of land, air and water. “What you do to change results in one of these areas affects results in the others.”

In that context, the goal of zero waste from the oil sands can act as a principle to help the industry overcome the public perception of the industry’s behaviour by directly addressing the issue. It will also provide guidance to the build-out of the industry. Forecasts suggest that three quarters of the plants that will dot the oil sands in 2030 are yet to be built. These facilities are still at the concept or design stage, and they represent the biggest opportunity to embrace industrial symbiosis. Notably, they will be receiving the greatest scrutiny from regulators and a public demanding “greener” energy.

Another triangle is driving oil sands development. Its three sides are social attitudes and demands; regulatory and industrial codes; and technical skills and operating environments. As in the case of the footprint triangle, what you do to change results in one of these areas affects results in the others. In the area of technical skills and operating environments, there’s a triangle of areas where industry players need to look for improvements.

According to Dr. Doug James, who with Bob Taylor facilitated the workshop, one is “inside the plant fence.” Individual operations need to seek out better processes for cleaning up or eliminating waste generation. These could include capturing and using waste heat, for example, and using waste materials for gasification. Joy Romero, Canadian Natural’s vice president of bitumen production, cited a process at Horizon which “purchases waste CO2 to add to our tailings. This undoes the effect of caustic soda, allowing fines and clays to settle, and water is released for reuse almost immediately from the tailings ponds.”

There are also “across the plant fence” opportunities, by which different companies work together to make their combined operations more efficient. For example, they could build joint facilities for water treatment and waste water handling or develop joint hydrogen production facilities – perhaps using gasification of coal and biomass – for use in upgraders.

And there are opportunities from “across-the-region coordination” – the construction of common pipelines and other transportation infrastructure. One possibility would be regional landscape planning with Alberta-Pacific Forest Industries, which has forestry rights covering most of the oil sands area. This “might reduce the joint forestry-SAGD footprint by 30%,” said James.

Tragedy of the Commons
In a presentation, Dr. Eddy Isaacs of Alberta Innovates described a 90-year pattern of oil sands development. His essential argument was that oil sands development periodically goes into crisis before being rescued by a visionary. Sunoco Chairman J. Howard Pew saved a floundering Suncor, for example, and Frank Spragins, the first president of Syncrude, brought that project back from a near-death experience.

The oil sands are now in crisis because of public perceptions. According to one academic, “Perception is reality and the perception is that you guys are making a mess up there. You’ve got a problem.” Dr. Soheil Asgarpour, president of the Petroleum Technology Association of Canada, agreed. “We aren’t communicating what we are doing properly,” he said, “and we aren’t doing enough.”

According to facilitator Bob Taylor, industrial symbiosis is a key part of the solution, since it harnesses economic forces to reduce waste and save energy. The best part of this system, though, is that it develops naturally. Symbiotic relationships began forming long before the idea was coined.

In Alberta, the classic example is the Industrial Heartland, north of Edmonton. That industrial region has grown organically since the late 1940s, when Imperial Oil brought a tin-pot World War II refinery down from Whitehorse in response to the discovery of oil near Edmonton. Not until recently was the idea of industrial symbiosis even whispered there. Now reflecting more than $25 billion in investment, this 582-square-kilometre region hosts forty large companies and many small ones. Together they operate numerous refineries and plants, pipelines, fabricating facilities, service companies and other interdependent businesses.

For the oil sands, there is no reasonable alternative to greater and continually evolving industrial symbiosis. In a background document, Bob Taylor and Doug James suggested that the extreme alternative to a sensibly industrial ecology is reflected in a notion known as “the tragedy of the commons.” The phrase was first articulated in an influential 1968 article by the late Dr. Garrett Hardin, an academic whose First Law of Ecology proclaims, “You cannot do only one thing.”

In his famous article, Hardin described a situation in which individuals act independently and rationally in their own self-interest. Collectively, however, they deplete a shared, limited resource even when it is clear that it is in no one’s long-term interest to do so.

To illustrate his point, Hardin proposed a hypothetical and simplified situation based on land tenure in medieval Europe. The picture he drew was one of herders sharing a common pasture for their cows. It is in each herder’s personal interest to put the next (and succeeding) cows he acquires onto the land, even if this means exceeding its carrying capacity and temporarily or permanently damaging the land. The herder receives all of the benefits from an additional cow, while the damage to the common is shared by the entire group. If all herders make this individually rational economic decision, the common pasture will be depleted to the detriment of everyone.

Society is now much more complex than in medieval times, of course, and today’s petroleum sector clearly understands that permission to produce Alberta’s resources requires public approval. Oil sands people at the workshop frequently mentioned the need to “preserve your social license.”

“The implication for the oil sands industry,” wrote the two workshop facilitators, “is that, in the absence of a higher guiding principle, each company will tend to act in its own interests, ultimately resulting in degradation of the environment. Of course, the government through regulations imposes such higher guiding principles. However, it appears at this time that the rapid expansion of the industry operating on an individual basis reaches sub-optimal results regarding environmental stewardship.”

One way for industry to demonstrate better stewardship is to collectively develop good will by sharing new, lower-waste technologies. It is important for companies to secure intellectual property rights for their ideas. If they didn’t, someone else could secure the patent and demand royalties on the technology. However, producers have little reason not to share them within the oil sands community. After all, said Doug James, “in the oil sands once you acquire your land the competition is over. Compared to the revenue stream from oil sands production, any income you might derive from licensing production technology is peanuts.”

Moving toward zero as a goal will reduce waste products, he said, but it will also reduce “wasted opportunities, wasted human capital, wasted funds and wasted reputations.”

He Rocks

 Former "coker rat" Byron Lutes plays the guitar, rides a longboard and - oh, yeah - is leading a serious oilsands contender

This article appears in the August issue of Oilweek.

By Peter McKenzie-Brown
I didn’t expect the answer Byron Lutes gave me when I asked what kinds of books he reads. “I read a lot,” he said. “Just last night I finished When Giants Walked the Earth, by Mick Wall. It’s a biography of Led Zeppelin. It was great.” The choice surprised me. As we talked, however, the title seemed increasingly fitting. Surely if there’s an industry dominated by giants it’s the oilsands, yet here’s a guy leading a small company who wants to become a leader in the game.

Lutes has a ready smile and a lot of confidence in what he’s doing – turning the two-bit shell of a VSX (Venture Stock Exchange) company into a serious oilsands contender.

A chemical engineer by background, the athletic president and chief executive officer of Southern Pacific Resource Corp. graduated from the University of Calgary in mid-1986, just as oil prices collapsed from $30 per barrel to $10 and layoffs within the industry became the order of the day. “Only two of about 50 graduates in my chemical class got jobs after graduation.” Byron Lutes was one of them. As a student he’d worked at Suncor during previous summers, and the company wanted to keep him on.

Instead of getting the typical new hire’s tour of the company, though, he found himself working for Suncor just as it became immersed in labour strife. Employees at the oilsands plant had gone on strike, and he was shipped off to Fort McMurray to help operate the upgrader. “I was a coker rat,” he says. “I was swinging valves and cutting coke. It was a dirty job – all-night shifts – but I loved it because I got to learn a lot coming right out of school. I spent eight years at Suncor, doing various things. I did reservoir engineering and a year and a half stint in marketing. It was a terrific company to work for, and I got a lot of great experience.”

When he was 30, Lutes’ romance with junior oils was about to begin. “One of my former bosses, Sid Dykstra, had set up a company called Newport Energy and he asked me to join him. The company was making about 2,200 barrels of oil a day. Over the next seven years we grew it to about 30,000 and then sold out to Hunt Oil.” He stayed with Hunt for the next three years, running their Canadian operations. “That was a complete change, going from a grassroots, publically traded Canadian company to a private, very large American one. I knew I wasn’t going to stay.”

In 2002 he went to work for ManCal Energy, a privately-held company owned by Calgary’s Mannix family. “We were always growing stuff, developing it and selling it to take a profit. That was part of our game plan. We didn’t want to build up the staff complement, which was about 20 people. ManCal was another really good company to work for.”
 
Food chain
After five years with ManCal, Dave Antony – the chair of Southern Pacific Resource Corp – approached Lutes “out of the blue” to run the company. “It’s been quite a ride. (The company) had a bunch of land in the oilsands and some exploration programs, and they needed someone to come in and lead it.”

Though the oilsands are an area where giants generally do walk the earth, Lutes sees a lot of opportunity for junior oilsands companies. “Smaller companies can move their projects forward faster, from a regulatory, financial, and execution standpoint,” he says. “They can exploit areas that a larger company may have overlooked. They (can) attract and retain top entrepreneurial expertise. There will always be room for different sizes, as in any industry, and the food chain will also likely always be there.”

The story of the resurrection of Southern Pacific illustrates two quite different business models that are part of the industry’s food chain. The company, which has an undistinguished pedigree, was first traded on the old Vancouver Stock Exchange as New Wellington Mines Limited, in 1953. According to Lutes, “Dave (Antony) and his associates find shell companies, clean them up, recapitalize them and put in a management team.” That’s one part of the food chain.

A private company known as Bounty Developments Ltd. illustrates another. Bounty’s “modus operandi is to get land positions and turn them over to another company, keeping an override on the land. They’ve been very successful with that. We made a deal with them, met some work commitments and acquired 219 square miles of land (sections) in the oilsands, most of it raw acreage. We earned an 80 per cent interest in the property.” Southern Pacific has since expanded its oilsands acreage, and now has an average 81 per cent working interest in 301 sections.

To play in the oilsands you need lots of money, and institutional investors in particular won’t touch a company listed on the Venture Exchange – too much risk. Southern Pacific needed to move to the Toronto Stock Exchange, and that required cash flow.

To get there, the company issued equity and took on debt to acquire Senlac, a Saskatchewan heavy oil property producing 5,000 barrels per day. The price was $90 million. “As soon as we had that we were a going concern, and it enabled us to advance to the TSX. That means more due diligence, but a lot more investors now will put their money into the company.” The company began trading on the TSX in June.

SAGD-able
To look to the company’s future, you need to first look a bit deeper into its recent past. When Lutes took on the president’s role at the beginning of 2008, the boom was still around, although it had been soured by Premier Stelmach’s ill-considered and now largely defunct “fair share” royalty revisions.

“When I first joined we were getting ready to start up a major winter drilling program. The company had in the neighbourhood of $60 million in the bank, and we had a lot of core holes to drill but the market was getting choppy. So we were lucky enough – and (chairman) Dave (Antony) was smart enough – to realize it may not be easy to raise equity in the market, so we really conserved our cash.” Lutes pulls out a map. “We cut back on our drilling program but were lucky enough to find in this McKay block a significant resource that we thought could support a good SAGD project. We focused and drilled into this area and found ourselves a project.”

The company’s first oilsands production will come from two pieces of land separated by the McKay River. Especially when he talks about the first of these properties, Lutes gets visibly excited. “It’s a great property to sink our teeth into as our first green-field Athabasca bitumen SAGD project. The reservoir has all the properties you need to make SAGD work, no complications like top gas or bottom water or shale compartments, and this one can use a proven technology.”

He stresses that you shouldn’t “risk the company by using unproven technology. Let the big guys figure that stuff out. We know that SAGD will work. Reservoir thickness ranges from 15 metres to about 30 metres. It’s definitely SAGD-able.” Oil saturation in the reservoir ranges from 70-80 per cent with an average of 75 per cent, he says. The reservoir “is not as thick as some properties further south” like Suncor’s Firebag project. “However, it’s a great property.”

At the low point in the financial crisis, last year Lutes’ team prepared a SAGD proposal for submission to the ERCB. “We designed a 12,000 barrel per day project for two reasons. From a regulatory perspective, it’s the fastest way to get onstream. If you make a proposal for more than 12,600 barrels (2,000 cubic metres) per day, approval takes another year. That’s the first reason. The second is that if you develop a smaller project, you can use standard equipment. Other companies are using the same pots and pans as we’ll be using. That gives us better control of our capital costs, since that equipment is made locally. We don’t have to go to international manufacturers.”

As for expansion and timing, Lutes is characteristically optimistic. “We think we’ve got enough resource to expand. We have contingent resources, and we think we can grow our capacity up to the 36,000 barrel per day range” within two years of construction of the first project. “Our first project is going to be steaming up at the end of 2011, and on full production by 2013. We think we can expand to the east side of the McKay River and also expand the original project on the west side. We hope to have applications in by the middle of 2011. Based on our recent experience, the applications take about 14 months to process.”

The cost of the initial project will be about $428 million. For Phases 2 and 3, Lutes estimates $380 million. “The difference is that infrastructure costs for the next phases will be lower once we are in the area.” Southern Pacific will use cash flow from Senlac in Saskatchewan and from McKay to fund growth in other oilsands leases.

Longboarding
Outside the office, Lutes is both musical and athletic. He’s had an interest in rock music since he and some friends started up a rock band in high school: “I played bass and sang.” The guitar playing is something his three sons – Cory, 19, who is studying engineering at UBC; 11-year-old Kyle; 9-year-old Dylan – have all taken up.
His wife Kathy and he are heavily involved with soccer with the younger boys. Formerly an accountant with TransCanada, she is now a full-time mum and treasurer of her kids’ soccer club. I ask about hockey. “We absolutely love hockey. We watch it religiously but we don’t play it. The reason is that we have a genetic problem,” he deadpans. “We can’t turn right on skates.”

He can turn right on the longboard, however. Essentially a surfboard with wheels, these long skateboards can measure 1.5 metres in length, and good riders can perform complex tricks on them. “I took up longboarding this summer,” he says. “Longboards really cruise. My kids have them, and they are a lot of fun. I figure if the kids want to use them, I might as well go boarding with them. I play basketball with them, too.”

How do you sum up Byron Lutes? A guitar-playing businessman, a longboarding engineer, an executive hooked on rock concerts. Too bad he can’t turn right on his ice skates.

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Unconventional Challenges

There's nothing unconventional about shale gas in western Canada, but the technology to get at it? Now that's a different story

Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide

By Peter McKenzie-Brown

In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.

The most important of these is horizontal drilling. Since the technology became widespread in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors.

Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.

Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.

Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.

Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.

Microseismic
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.

Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.

According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.

“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.

What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.

Coil Tubing
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.

The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.

Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.

Fractious
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.

Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.

Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. 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 rock than you would ever be able to reach with a vertical well.”

In the 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 – although a well that required so much work would likely have a horizontal reach of 3,000 metres or more.

To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” said Kevin Lo of FirstEnergy Capital in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.

Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.

Because so much water is required, 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 actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “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.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.

The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.

To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.

Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”

In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”

What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.

If Nobody Hears a Blowout, Did it Really Happen?

Canada’s worst-ever blowout wasn’t a celebrity, and despite the passage of more than a decade the regulator has never formally investigated the event. Is that a good thing?

This article appears in the July issue of Oilweek

By Peter McKenzie-Brown

Klua d-27-J blew out near Fort Nelson BC. No neighbours were under threat, and the blowout took place in the sticks as most Canadians were getting ready for Christmas. No one was injured and, except for an incinerated rig, there was no damage to property. The media didn’t get wind of the disaster, so Klua was relegated to the world of “incidents.”

The blowout began on December 6, 1999 and took 12 days to shut in. But what an incident it was! Chairman Mike Miller of Safety Boss was part of a team of petroleum industry experts who prepared an important paper on Klua for a conference in Texas two years later. “Eyewitnesses reported that the drill string was lowered the last fraction of a meter with no resistance,” the paper says, “as if the bit had entered an underground cavern….” Then all hell broke loose.

According to Miller, at its peak the well spewed an estimated 250 million cubic feet of natural gas per day plus 5,000 barrels of condensate and 45,000 barrels of salt water. After ten days, crews ignited the well, which was flowing mildly sour gas. After pulling the incinerated substructure of the rig from the well, the hole was shut in and a control BOP installed.

When Oilweek recently contacted BC’s Oil and Gas Commission (OGC) for the formal report on this blowout, there was none. The Ministry of Environment would lead clean-up efforts, but otherwise the file is still open.

It’s a Matter of Safety

With oil leaking in the Gulf of Mexico, Canada is well-positioned to deal with the heightened risks - and reap the bountiful rewards - of frontier exploration.

Photo: Chevron Canada, which is drilling the ultra-deepwater Lona O-55 well in the Orphan Basin off Newfoundland with the Stena Carron Drillship, must meet several new requirements stemming from the Deepwater Horizon tragedy.

This article appears in the July issue of Oilweek.

By Peter McKenzie-Brown

As the United States administration and BP plc struggled to deal with what could turn out to be the largest-ever offshore oil spill, the Canadian oil and gas industry could look back in admiration at a frontier drilling history that has been relatively free of stains.

Oil and gas continues to be pumped from fields off the East Coast. Crude oil has been produced and shipped from the Arctic Islands. And natural gas from the Mackenzie Delta region is poised to supply southern markets, pending completion of a long-awaited natural gas pipeline from Inuvik. And in the Queen Charlotte basin, off the coast of British Columbia, where a moratorium has barred drilling since 1971, there lies a “new, rich petroleum province waiting to be explored,” says widely-respected petroleum geologist Henry Lyatsky.

He has been actively promoting lifting the moratorium even while the media were buzzing about the Gulf of Mexico blowout, believes there are excellent prospects in Canada’s west coast basins. Opening them up for drilling would reward the industry for decades of nearly incident-free frontier exploration.

Those sentiments would alarm most people outside the oilpatch, and they would alarm Canadian environmental activists to the point of apoplexy. That, however, is exactly the point: There is widespread concern around Canada that rapid growth in the petroleum sector would pose environment, health and safety (EHS) dangers. Those concerns illustrate how profoundly EHS has become part of our national DNA. And that is a very good thing.

The Three-legged Stool
The EHS stool has three legs: customs and social attitudes; regulatory and industrial codes; technical skills and operating environments. If the legs aren’t the same length, the stool wobbles. Since the three legs of the Canadian stool are level and strong, there are good reasons to encourage the industry to reach out to new operating environments.

Consider reality in much of the developing world, for example. “We do a lot of work out of Third World countries where clearly life is cheaper,” says Mike Miller, the chairman of Calgary-based Safety Boss Inc. “We were doing safety management on a huge construction project in Iran, and we just had a hell of a time to get people on board with it. One of the comments we heard was that if they killed someone it would just cost fifteen hundred bucks. You’d take $1500 to the family and that would be the end of it. So how much money are you going to spend on safety? Our contract was about enforcing Canadian safety standards, and we found so much resistance that at the end of the day we just said ‘This isn’t going to work, guys, because you aren’t going to stand behind us.’” In the end, Safety Boss got out of its contract.

Miller’s example illustrates the social attitude leg of the stool in much of the Third World. By contrast, in Canada the legal resources applied to safety and safe working environments are huge. Apart from representing personal tragedy, injury and loss of life are expensive propositions.

On the matter of the second leg of the stool, regulation, rich countries like Canada are increasingly focused on stringent EHS rules. The Canadian experience illustrates how regulation has saturated public opinion so deeply that environment, health and safety have become essential parts of the social fabric. According to Dale Dusterhoft, the chief executive officer of well service company Trican, there is a “continued focus on safety, environment and hazard issues and it comes from all levels, it comes from government, it comes from our customers who are the oil companies, it comes from the public at large and it comes internally from within the service industry. It now affects everything we do, and it is helping us make real progress.”

Operating environments represent the third leg of the stool, and they reflect the industry’s collective experience. The sector has a wealth of experience in the Western Canada Basin and is increasingly knowledgeable about the frontiers. The industry’s technical knowledge and skill-sets are formidable.

Safety Costs
Although serious industrial incidents have become rare, as long as there is an oil industry there will probably be kicks and blowouts. The story of Canada’s oil patch is full of these events, some of which have become legend: Royalite #4 at Turner Valley (1924); Atlantic Leduc #3 (1948); Amoco’s second sour gas blowout at Lodgepole (1982-83). The most blowout-prone exploration program in Canadian history was probably Panarctic’s 1969-70 effort in the High Arctic. Of 17 holes, two were spectacular gas blowouts and three were relief wells drilled to bring those blowouts under control.

To some extent because of the disasters of its cowboy years, Canada’s safety record is now excellent– especially since the high-profile Lodgepole event. In years of high drilling activity the industry now sinks three times as many wells as it did in ’82 and drills four times as many metres, yet blowout rates have substantially declined. In 2008, for example, the ERCB recorded 0.118 blowouts per 1,000 non-abandoned wells.

This partly reflects technological advance. “Almost all blowouts occur because of human error,” says Mike Miller of Safety Boss. “Fewer than 5% occur because of corrosion. It’s almost always when there’s a rig over the hole – whether it’s a drilling rig, a service rig or a snubbing unit. That’s where the human error takes place. Today we can put holes down in half to a quarter of the time it used to take so there’s less exposure of time to risk. That’s one reason we have fewer blowouts: we can drill wells so much faster.”

Miller also commends the ERCB’s strict regulations for sour gas drilling. “We now classify wells with significant sour gas content as critical wells, for which a whole new set of rules apply, including the requirement for emergency response plans. That’s made a huge difference.” So big, reports the Energy Resources Conservation Board’s Bob Cullan, that “there hasn’t been a single sour gas blowout since Lodgepole. That’s because we have the toughest sour gas drilling regulations in the world.”

The cost of safety is huge, and it has meant big changes in operating procedures. Mike Miller describes dramatic changes in the safety business since his father founded the company. “People (doing safety turnarounds at gas plants) now have fall-arrest equipment. They don’t do anything without fire protection and breathing air equipment. A friend of mine tells me that at the plant he works at, the safety bill used to be $20,000. Now it’s like $300,000 to $400,000. Every time someone goes into a vessel someone has to be there to watch. They may need to have specialized safety equipment or even specially trained personnel to watch that person in the vessel.”

He adds, “I appreciate the safer work environment, but the paperwork can be simply overwhelming. Now on blowouts we have to take a safety certified officer, and their job is simply to do the safety recording – to record every detail of the safety meetings we have. ‘We met at such-and-such a time, these are the hazards we discussed, people have to wear such-and-such protection equipment, here’s what we said and did.’”

To put costs in perspective it is worth noting that, according to an ERCB report, the direct costs of the 1982 Lodgepole disaster (lost production, lost drilling rig, operations and remediation) totalled $200 million. In a technical presentation nearly ten years ago, Mike Miller estimated that indirect costs – more stringent critical sour gas well procedures, equipment and emergency response planning, which can amount to a quarter to a half million dollars for a deep test – had been in the order of $1 billion. The cost of EHS is high, but Canadians are clearly prepared to pay it.

So is Canadian business. Chief executive officer Dale Dusterhoft of Trican, which is a key player in hydraulic well fraccing, describes the safety issues his employees face as long-distance driving (often over rough terrain); controlling high-pressures and chemicals; and working with moving parts and equipment. “Whenever you have those elements, you have safety issues,” he says. While he acknowledges that there is more paperwork than ten years ago, he says “It’s just part of the process. It doesn’t hinder our operations. We have a safety meeting prior to each job, and we have to document every one. What’s more, every individual there has to sign off that they were in attendance and heard it and understood it. But these are just good business practices. They take a bit more time, but they save money in the long run because you don’t have as many incidents.”

High Arctic
Canada’s early experience in the High Arctic – a 17-well drilling program that included three relief wells to control two major blowouts – illustrates how bad things can be when you don’t properly prepare for drilling in new exploration territory. The stool becomes wobbly, and the risk of an uncontrolled release of hydrocarbons – the fancy phrase for blowout – becomes greater.

In that context consider that the EHS stool is shaky in most Third World countries, yet there are big increases in deep water drilling off the shores of Africa, Brazil, China and India. “Aside from the oil sands,” ARC Energy’s Peter Tertzakian pointed out in a recent research note, “offshore drilling is where most of the world’s incremental oil barrels now come from, and it’s those higher-cost marginal barrels that set price. Indeed, a large fraction of the world’s growing oil needs since the early 1990s has come from the discovery of new, deep offshore reservoirs.” In North America, much of that oil has come from the American sector of the Gulf of Mexico.

Notwithstanding the BP-operated Macondo well disaster, it is rich-world companies that are best suited to drilling the world’s offshore petroleum basins. Because of our national attitudes and far-flung technical expertise, environment, health and safety are well served when Canada-based companies drill offshore fields. This reality applies as much to basins in Canada as to those in the Third World.

The Beaufort Sea and the East Coast Offshore
In Canada’s Beaufort and East Coast basins there have been important EHS developments in recent months.

Going to the ends of the earth is nothing new for the Canadian oil and gas industry. Beginning in 1976, drilling expeditions in the Beaufort Sea were innovative and daring and continued for nearly a decade. The wells were in shallow water, however – often using equipment that sat on the sea floor.

Last fall the National Energy Board began a safety inquiry in anticipation of a revival of drilling in the Beaufort Sea. The review was triggered by a proposal from Imperial and Exxon Mobil to start deeper Beaufort drilling, using a new vessel built on the scale of a battleship. The Board is investigating serious concerns about opening up deeper northern waters for drilling. The previous generation of regulations assumed that in the event of a blowout the operator could drill a relief well in the same season.

The Board began developing its new regulatory approach because the Arctic work season is too short to follow the old rules for the next wave of bigger wells. After the Macondo disaster began, the Board announced that it would review Arctic drilling requirements in light of findings from the American inquiries into that event. “We need to learn from what happened in the Gulf,” NEB Chair Gaétan Caron said in a statement. “The information taken from this unfortunate situation will enhance our safety and environmental oversight.” The regulator is making sure all three legs of the EHS stool are the right size for deep Beaufort drilling.

Off the east coast, the Gulf debacle created consternation for a different reason: a new, deep well was being spudded. In May, Chevron began drilling Canada’s deepest offshore oil well 430 kilometres northeast of St. John’s in the offshore Orphan Basin in the North Atlantic. Lona 0-55 was spudded in 2,500 metres of water (compared to Macondo’s 1,500 metres). Despite political calls for postponement because of the risk of an ultra-deep-water blowout, Newfoundland defended the project as critical to its economic development. The gist of the government’s argument was that oil is too crucial to the economy to call off exploration. That sounds quite a bit like damning with faint praise.

In response to public criticism, the government of Newfoundland appointed master mariner Mark Turner, an expert in marine safety and environmental management, to review the province’s ability to prevent and respond to an offshore oil spill.

It isn’t surprising that environmentalists and the political opposition sounded their respective horns on the remote prospect of a North Atlantic blowout. Serious offshore oil blowouts always attract attention, and rightly so. Injuries and fatalities are more common. They pollute, they’re hard to clean up and contamination can last for years. When dispersants are appropriate at all, they are the least bad of the available tools. And offshore oil blowouts have a disproportionate impact on wildlife: a deer can walk past a puddle of oil, but fish, whales and seals have nowhere else to go.

However, crucial facts were lost in the conversation about Lona O-55. One is that there has never been a crude oil blowout offshore Canada. Another is that only hundreds of wells have been drilled in Canada’s vast east coast, compared to tens of thousands in the much smaller US segment of the Gulf. Also lost in the debate is that all Canadian offshore wells have recently become governed by a more robust regulatory regime – one which offers greater EHS flexibility as a carrot, but bigger sticks for those who fail to perform. That means better safety and environmental protection rather than less, as the knee-jerk critics protest.

The new rules governing offshore drilling were posted in the Canada Gazette last December, and took effect at the beginning of this year. They are performance-based rather than prescriptive regulations, and the industry certainly believes that is a good thing.

According to Patrick Delaney of the Petroleum Services Association of Canada, the trend in regulation is undergoing a fundamental shift to performance-based regulation from prescriptive rules. As he explains, under the new approach the regulator essentially says, “The journey is from A to Z” – Z being a plan which meets the regulator’s EH&S goals. “We aren’t going to tell you how to get there. But before you start it’s up to you to prove that you can do it safely. This is a safer approach.”

For offshore operators, the days are now over when agencies of government specify the safety equipment the industry should use. “A lot of governments are making this shift,” adds Delaney. “Alberta recently announced that it is doing a complete review of its regulations, and that it will move away from prescriptive to performance-based regulation.”

Paul Barnes, who is Atlantic Canada manager for the Canadian Association of Petroleum Producers, is another advocate of performance-based regulation. It’s more “modern,” he says. Britain, Norway, Australia – all the advanced countries with offshore petroleum operations are adopting it. “It is part of a robust regulatory system in Canada,” he adds. “We have a strong track record of safety and environmental performance. Canada needs energy and the world needs energy, and oil’s going to be a big part of the energy mix for a long time to come. Let’s get on with it.”