Lucky Guy

Ralph Klein had a knack for being in the right place at the right time – especially for the oilsands 

This article appears in the June issue of Oilsands Review  

By Peter McKenzie-Brown

Former Premier Ralph Klein’s death at the end of March was greeted quite differently from that of Peter Lougheed, who had also been premier and had died six months earlier. Lougheed was seen as an elder statesman, and his passing was mourned across Canada. The mourning that followed Klein’s death – caused by a rare lung disease, and complicated by an uncommon early-onset dementia – was shorter in duration and more provincial in scope.

It seemed as though everyone in Alberta had a great “Ralph story” to tell, and as often as not people would refer to him affectionately as Ralph or, reflecting his political style, sometimes King Ralph. A man celebrated for his common touch who on occasion tearfully acknowledged that he drank too much, he was well known at favourite watering holes like the bar at the run-down King Edward Hotel in Calgary. He was a political fixture in Alberta for a quarter century, beginning with his election as the mayor of Calgary in 1980. His illnesses prevented him from experiencing much retirement; they were diagnosed soon after he left office. Klein was 70 years of age.

Klein was not a good planner or a gifted thinker. However, during his term he was endowed with good luck – especially in respect to the oilsands.  Three of Alberta’s 14 premiers have played major roles in oilsands development. The other two were Ernest Manning (1943-68) and Peter Lougheed (1971-1985). On Premier Klein’s watch (1992-2006), however, the industry grew into an economic giant. One reason is that government and the oilsands industry prepared for growth. The other is that during the reign of King Ralph, as he was also known, oil and gas prices tripled.

The early part of the Klein era was just awful for Canada’s petroleum industry in general and the oilsands business in particular. Shortly after Klein took office both the federal and Alberta governments withdrew financial support from the OSLO oil sands plant, which would have relied on loan guarantees and tax and royalty concessions to become profitable. Klein famously described his government as being “out of the business of business” – an early indicator of what the Klein era would look like.

The Surge

When he took over from Premier Don Getty, Klein inherited “a bloated bureaucracy and an angry electorate,” as one commentator put it.. Alberta faced large and growing deficits and was desperate for a more balanced budget. Desperate for more jobs across Canada, Prime Minister Jean Chretien (1993-2003) had just handily won an election in Ottawa. The major plank in his election platform? Economic opportunity. Oil prices were in the tank and the industry was desperate for investment opportunities.

Thus was the stage set for the industry’s great surge forward.

Klein had barely moved into his new office when the Edmonton-based Alberta Chamber of Resources formed a Task Force on National Oil Sands Strategies in 1993. Eighteen months later the multi-stakeholder task force issued a report titled “The Oil Sands: A New Energy Vision for Canada.” In clear and compelling prose, the report outlined eight areas where players in the emerging oil sands industry could help the industry grow – by developing new markets and more, for example, a pipeline system that better served areas where bitumen was being produced.

However, the key to growth was a better fiscal regime. According to the task force, “The Federal and Alberta governments…should develop a generic set of harmonized tax and royalty measures based on economic profits. Such a system will provide a consistent fiscal framework for all oil sands projects and result in a balanced sharing of profits. These common fiscal terms are necessary for the future development of Canada’s oil sands.”

After the release of the task force report, Klein’s government immediately began looking for ways to implement its suggestions, and in September approved a generic oilsands royalty and tax regime that would apply to all new projects. New projects would pay the province a 1% royalty on production until net project revenue had paid out all start-up costs. At that point, the royalty would rise to 25%, although all capital costs, including operating, research and development, were fully deductible in the year they were incurred. This was radical, and the free-market Klein government deserves credit for stepping up to the plate without hesitation.

Historian William Wylie once described how the key players in the oilsands have changed over time. “The federal government was the principal actor between 1875 and 1918,” he said, “at first from a sense of responsibility for regional development, and near the end of the period from strategic considerations.”

In the 1920s, though, “the government of Alberta became the major force, in part in order to assert its claim to control provincial resources. In the 1930s, two private companies showed signs of promise and the two governments pulled back in deference to private development and in order to cut costs. The 1940s were years of increased involvement on the part of both levels of government due partially to strategic considerations, and to the power struggle between them. In the 1950s, the conventional oil boom in the province took attention away from the oil sands and delayed their development until the 60s and 70s when the long run decline of the conventional reserves was finally anticipated. When commercial development occurred, private industry was the major agency, but with considerable governmental backing as well.”

Then, the industry morphed into another phase. In 1992 the industry began to enter a new era of oil sands policy – one that is now two decades in duration. Call it the Klein legacy; it is a period in which financial responsibility for oil sands development lies entirely with the private sector. It has already been the longest-lasting of the major periods of oilsands policy, and in the near future seems unlikely to change.

What has made this new era so solid is that during the Klein era conventional oil prices rose from about $19 when he began his term to $63.43 on the day he retired. Gas prices also more than tripled, from $2 to $7. To a large extent driven by the US-led invasion of Iraq, these surges pulled bitumen prices along.

The outcome was a flood of oilsands spending in the province. Suncor began a series of mining and in situ expansions that made it Canada’s largest petroleum company. Syncrude also announced large expansions. Both companies introduced technologies and operations that led to huge reductions in the cost of production.

In 1999, a Shell-led consortium began its Muskeg River Mine oilsands development – better known as the Athabasca Oil Sands Project. The project went on stream in 2003. Construction of Canadian Natural Resources Limited’s Horizon project began toward the end of Klein’s term, with the first phase completed in 2009.

The Klein Legacy…

Oddly enough, as he completed his term as one of the most popular premiers in Alberta’s history, Klein held a news conference in which he essentially proclaimed himself a failure. On the matter of oilsands development, he was partly responding to general criticism by Peter Lougheed, who had called for more limited oilsands development. “What’s the hurry?” Lougheed had asked. He was concerned about the environmental and social impacts of oilsands development. “Why not build one plant at a time? I hope the new government in Alberta will reassess this and come to the conclusion that the mess, and I call it a mess, that is Fort McMurray and the tar sands will be revisited.”

In his sometimes tearful farewell, Klein said he couldn’t have imagined how forcefully the industry would respond to the royalty and tax changes of the mid-1990s. Thus, his government didn’t have a plan for how to deal with the spectacular growth that followed. Of course, any other premier would have basked in the glow of leaving behind an economic boom.

That Klein didn’t have a plan more or less characterizes the man himself. According to one biographer, his government was anything but ideological. It tended “to act first and think later, impulsively adopting elements of the neo-conservative agenda without having an overall strategy.”

Maybe that’s the best we can say about the man most Albertans still think of as Ralph. He was not a planner, but a pragmatist and an instinctive free-market conservative who happened to be in the right place at the right time – just as the oilsands sector reached maturity.   

"We Were Canadians First"

With the news of former premier Peter Lougheed’s death on September 13, aged 84, an outpouring of grief began throughout Alberta – indeed, throughout Canada. Rarely has a politician ranked so high in the esteem of the people he or she has been chosen to lead. 

This article appears in the November issue of Oilsands Review 

By Peter McKenzie-Brown

The tributes and commentaries ranged from reflections by ordinary citizens to formal commentaries from the great and the good. One of Lougheed’s biographers, Alan Hustak, observed that he was “the architect of modern Alberta” who, among many other achievements, helped turn the province’s petroleum industry into a global powerhouse. Nothing you can say about this great man seems over the top.

Lougheed’s career in the provincial Legislature began in 1967 – coincidentally, the year the Great Canadian Oil Sands (Suncor) plant was commissioned. The convergence is compelling, since several of his greatest achievements were oilsands-related. Energy issues dominated his years in power (1971 to 1985), and he was a decisive figure in what became known as Canada’s energy wars.

Among governmental issues, oilsands remained a core interest to the end of his long life. As he said in an Oil Sands Oral History Project interview 18 months ago, “After I left government in ’85 I said to my successor, Don Getty, ‘Don, I will stay out of most things you’re doing… but the one thing I am going to stay involved in is the oilsands, because I am very interested in its evolution and its development.…’ Things happened so quickly [under] Premier Klein. I have stayed involved in the oilsands in a more public way and I have discussed it frequently with Premier Stelmach as well. Perhaps more than any other, that’s the one subject I have stayed involved in since I left government.”

The Energy Wars: Lougheed’s early political battles began with a shot across the bow from Prime Minister Pierre Trudeau.

Inflation had become a national problem, oil prices were rising, and on September 4, 1973, Trudeau asked the western provinces to agree to a voluntary freeze on oil prices. Nine days later, his government imposed a 40-cent tax on every barrel of exported Canadian oil. The tax equalled the difference between domestic and international oil prices, and the revenues were used to subsidize imports for eastern refiners. At a stroke, Ottawa began subsidizing eastern consumers while reducing the revenues available to producing provinces (mostly Alberta) and the petroleum industry.

This outraged Premier Lougheed, who understood how long and hard the province had fought for control of its natural resources; resource ownership had not been conferred upon the province until 1930. In response, Lougheed announced that his government would revise its royalty policy in favour of a system linked to international oil prices.

His timing was impeccable. Two days later, on October 6, 1973, the Yom Kippur War broke out – a nail-biting affair between Israel and its Arab neighbours. OPEC used the conflict to double the posted price for a barrel of Saudi Arabian light oil to US$5.14. The Saudis and the other Arab states then imposed embargoes on countries supporting Israel, and oil prices rose quickly to $12. These events aggravated tensions among provincial, federal and industry leaders.

The rest of the 1970s were marked by rapid-fire, escalating moves and counter-moves by Ottawa, the western provinces and even Newfoundland. From 1974 to 1985, Ottawa imposed an export tax on conventional crude oil – a move Lougheed called “the most discriminatory action taken by a federal government against a particular province in the entire history of Confederation.”

Lougheed strongly asserted and ultimately resolved, beyond question, Alberta’s ownership of most hydrocarbon and other mineral resources within its provincial borders, and he made it clear to industry itself that the government was in charge. “It was obvious that the oilsands were owned by the people of Alberta,” he explained in the Oral History interview. “We consistently and constantly made sure that the industry understood that the Government of Alberta was the owner, and we weren’t just there in a supervisory or regulatory way. We were extensively involved because we were the owners.”

Canada’s political conflicts over energy climaxed with the introduction of the National Energy Program (NEP) in 1980. Lougheed led negotiations on significant modifications a year later, mainly exempting “new oil,” but the contentious policy was not fully removed until 1986. As the policy collapsed due to severe recession and wrong assumptions about global oil prices, Lougheed played a key role in negotiating a new constitutional agreement for Canada, then retired from office.

Syncrude: One of the positive developments of the energy wars era was the rescue of Syncrude in 1975. The oilsands project’s costs had soared, and one of its partners had pulled out. To a certain extent, that rescue involved a different way of looking at royalties. Lougheed’s interest in petroleum royalties began early in his years in power, before the events of the early 1970s embargo drove oil prices to historically high levels. “We were in a fairly experimental period with the oilsands,” he said, “we had the Great Canadian Oil Sands [project] which was struggling. When Syncrude came along and we got into the negotiations, it was clear we could not approach [the owner’s share] from the perspective of gross revenue….We had inherited from [Ernest Manning’s] Social Credit Government, a good system of royalties for the conventional oil and gas system, which was a percentage of gross revenue. We modified it from time to time in government, but the conventional oil and gas business was based on a percentage of the gross revenue.”

The oilsands were a different kettle of fish. Lougheed continued, “Right from the start it was clear that it wasn’t really fair because of the risk element that came with being involved in such a new process. You know, a lot of people wondered, was it going to work? Would it be economic?” All of those questions led to a discussion between the owner – the Government of Alberta – and Syncrude. ‘What kind of royalty scheme should we have?’ [The discussion] evolved into the whole question of a net profits approach. It was completely different than [the policy used for] the conventional oil and gas industry.”

The 1975 Winnipeg Agreement, which saved the Syncrude project, was one of the few moments of cooperation among governments during the energy wars. Always a savvy negotiator, during those 12 hours of meetings on February 1st, Lougheed committed the province to take a 10 per cent interest in the project for the then-mind-numbing sum of $200 million (about $1 billion in 2012 dollars). Alberta would provide loans that the province could convert into equity, would construct no-risk utilities for the project, and would purchase an ownership interest for cash. This proved to be an extraordinary investment for the people of Alberta, “the owners of the resource.”

AOSTRA: Through the formation of a government agency, Peter Lougheed created a scientific and technical environment that unlocked the secrets of producing bitumen from the deposits too deep for mining, and fundamentally transformed the industry itself.

At the time, work on the deeply buried oilsands reservoirs, which represent about 90 per cent of the resource, had stalled. Imperial had made progress on the Cold Lake deposit, but there were no demonstrated technologies that could commercially unlock deep oil from the Peace River, Athabasca or Wabasca (now seen as an extension of Athabasca) deposits. At the time, there was little likelihood things would improve. Few companies were actively developing oilsands leases outside the mineable area.

Originally called “Project Energy Breakthrough,” the idea was to speed up the development of new in situ oilsands technologies. When legislated into existence in June 1974, the Alberta Oil Sands Technology Research Agency (AOSTRA) became one of the largest research and development programs ever launched in Canada. The act originally limited AOSTRA’s activities to oilsands, but an amendment to the legislation soon gave the agency the authority to fund heavy crude oil research. In 1979, the Crown corporation’s mandate was expanded again to include enhanced recovery of conventional crude. Over its lifetime, AOSTRA funded about $1 billion (1980 currency) in oilsands extraction research.

Initially, the Alberta government agreed to invest $100 million in this technology development fund. During the active life of the corporation, however, AOSTRA spurred the petroleum industry to undertake numerous demonstration projects, representing some $2 billion of research and development spending. In most cases, the authority essentially agreed to match the amount of money a company or industry partnership was willing to invest in oilsands projects.

During the AOSTRA years, the industry launched in-situ demonstration projects in all the major oilsands deposits. These included cyclic steam stimulation (CSS); steam flooding; forward combustion; reverse combustion; and combined forward combustion and water injection (COFCAW). However, AOSTRA’s crowning achievement occurred 25 years ago, when its Underground Test Facility proved the effectiveness of steam-assisted gravity drainage (SAGD.)

Premier Lougheed got excited when he talked about SAGD.  “I think SAGD…should be encouraged by the owner and is being encouraged by the owner. It’s the longer-term asset for the province. Surface mining has its limitations, and involves more environmental and water concerns. So, there is a clear and important distinction when you get into oilsands and that’s what the Alberta Oil Sands Technology and Research Authority had been focusing on….Throughout all of our discussions here, let’s make sure that we are drawing a distinction between SAGD and in situ [those words can be used interchangeably] and surface mining.” Lougheed served on the board of MEG Energy, which was one of the first companies to develop a commercial SAGD operation.

Ideal Model: AOSTRA spurred oilsands experimentation and development, although prospects for further development diminished in early 1986 when a precipitous collapse in oil prices, once again, threatened commercial development. While AOSTRA did not have a mandate to undertake projects on its own, in the 1980s it took a significant risk by constructing the now-legendary Underground Test Facility. The UTF proved steam-assisted gravity drainage (SAGD), which has since emerged as the most important system for developing deep underground oilsands reservoirs.

A noteworthy footnote to this discussion is that the 2009 Summit of the Americas held AOSTRA up as an ideal model for energy development. According to the Centre of International Governance Innovation (CIGI), which sponsored the summit, AOSTRA “engaged the private sector and the university research community in developing technology related to the oilsands, while the government retained the rights to the technology.” A government endowment allowed the organization “to function independently of the electoral cycle. A dedicated expert and respected seven-member board of directors helped secure the private sector’s buy-in.” In addition, “control by the government helped maintain continuity over downturns in the economic cycle.”

CIGI also noted with approval that, before AOSTRA determined its goals, “it conducted two years of extensive consultations with many stakeholders. Only after determining exactly where the technology gaps existed did AOSTRA put out a call for proposals.” Furthermore, “aside from successfully developing new technology, AOSTRA fostered and financed a new generation of academic and scholarly expertise in many aspects of oilsands development. The investment in human resources is often discounted, but has been fundamental for the sector’s success in Alberta.”

Afterword: Much has been said about Lougheed’s impact on the province of Alberta. However, out of the seemingly endless stream of tributes that followed his death came this from former Prime Minister Brian Mulroney, whose government finally dismantled the National Energy Program. “Peter built the modern Alberta: schools, universities, hospitals, highways and whole communities [like modern Fort McMurray]. He always defended Alberta’s interests brilliantly around the federal-provincial table. At the same time, he would be the first to say…‘We were Canadians first.’”

Where it All Began

Equipment in the Underground Test Facility proved the effectiveness of  SAGD 

A quarter-century after the first Canadian horizontal well was drilled, the technology is the cornerstone of today's industry.

This article appears in the June issue of Oilweek

By Peter McKenzie-Brown
The world of oil and gas was quite a different place a quarter century ago. Production mostly came straight up out of vertical holes. Though the Texans had drilled the first horizontal well in 1929, in Canada horizontal drilling was still mostly an esoteric, unproved and untested technology.

In 1987, all that began to change – so much so that, during the last 25 years, it simultaneously emerged as a standard production technique and revolutionized production. One result is that many petroleum resources have become technology-driven plays. Another is that reserves are way, way up.

In a sense, the most important uses of horizontal drilling technologies are reverse images of each other. “What makes horizontal drilling for nonconventional resources (like shale gas and tight oil) so attractive to the financial community is the very high initial rate of return. In the beginning, production rates are extremely high, although they quickly taper off. You have to remember that these applications enable you to get highly desirable hydrocarbons out of really poor reservoirs,” according to Dave Russum, who is director of geosciences at AJM Deloitte, a consultancy.

The oilsands represent the mirror image of this situation. “You are drilling into tremendous reservoir rocks – highly porous and very permeable, so there’s plenty of oil in there. But until you process the stuff it isn’t a particularly attractive commodity.”

The Bitumen Story

It’s true that in April 1978 Imperial Oil drilled Canada’s first horizontal well into the Clearwater formation at Cold Lake – a storied well overseen by Dr. Roger Butler in an early test of a system of oilsands production now known as steam-assisted gravity drainage (SAGD). After that test and a less interesting effort by Texaco a couple of years later, in Canada the technique mostly languished until 1987.

Then the advent of improved down-hole drilling motors and the invention of other necessary supporting equipment, materials, and technologies – particularly down-hole telemetry equipment, which enabled rigs to drill straight on target – led to an explosion of new applications for this technology. Producers and the drilling and service firms that support them found endless new uses for directional drilling – especially as it is used for horizontal wells.

Appropriately, in Canada the first horizontal wells drilled after Imperial’s early test were part of the Underground Test Facility (UTF), which celebrated its official opening on June 29^th, 1987. Developed by the Alberta Oil Sands Technology and Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into limestone 15 metres below the reservoir.

Within those tunnels, AOSTRA constructed large well chambers. “Pairs of injection and production wells were drilled upwards from the well chambers at a 17⁰ slant,” according to the mining engineer behind the project, Gerry Stephenson, “and deflected horizontally into the base of the reservoir. The mobilized bitumen drained by gravity from the steam chamber in the reservoir to the well head in the tunnel and all of the production was pumped from a central location.” Those tests proved Butler’s theories about SAGD beyond any possible doubt.

Over its 15-year life, the UTF also evaluated other recovery strategies, but nothing compared to its SAGD results. “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place” during the Phase A tests, according to Stephenson. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area we’d expected….Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The tests at the UTF forever transformed Canada’s oilsands industry. Today, SAGD is responsible for more than half of Canada’s bitumen production.

Ironically, Sceptre Resources drilled the first horizontal well in Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests. Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive application of a form of SAGD illustrated the kinds of problems horizontal drilling could overcome. With an active aquifer below and a gas cap above, the reservoir’s pay thickness was about 27 metres. The oil was heavy: about 13^o API. Primary production from the field had been meagre (0.6% of the oil in place), and the use of cyclic steam stimulation, which uses vertical production wells, had flopped when they tapped the aquifer and started producing 99% water.

That was when the company decided to try SAGD – not the technique we use today, but the primitive version Imperial had tried out nine years earlier. Sceptre injected steam through four vertical wells near the gas-oil contact, draining the mobilized oil through a horizontal well. At the industry’s leading edge, the company found itself with a technical and economic success.

Fast Production from Tight Reservoirs

More than any other series of innovations, the technology-intensive processes that now surround directional drilling have enabled the industry to get production out of otherwise unproductive rock. In August of that same transformational year, Alberta Energy drilled the first horizontal well into the Glauconitic formation at Suffield. This was the first time a Canadian operator drilled horizontally into a conventional oilfield.

Things then quickly sped up. In February 1998 alone, three significant projects based on horizontal drilling took off. Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at Ansell (Alberta) into the Cardium formation and at Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant to connect isolated small reservoirs or improving contact within heterogeneous rocks to enhance the sweep efficiency.

“In the 1990s the big push was to explore conventional carbonate rocks, especially from the Mississippian in Saskatchewan,” according to AJM Deloitte’s Russum. “The idea was to develop known reservoirs where the rock quality was variable, using horizontal wells to extract more oil from those formations…. Many different companies hopped on to the horizontal drilling band wagon in Saskatchewan with more than 500 wells drilled into the Mississippian in 1997 alone.  In that year more than 1300 horizontal oil wells were drilled across the basin – a tally that was not beaten until 2007.”

Horizontal drilling also began to tap the heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there was a lot of experimentation in other reservoirs. Also, of course, in that decade SAGD began to be developed in its modern form.

As horizontal drilling became more commonplace, the petroleum industry began combining it with innovations in both drilling and well completion technologies and ideas. The result has been like a snowball rolling downhill. Horizontal drilling has been enhanced by geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new bit design, for example. Also, producers can now drill multilateral horizontal wells from a single drilling pad.

Perhaps the important recent development on the drilling side is the monobore. Monobore drilling involves running a casing string, then forcing a steel cone down the well to expand it in the hole. This process is repeated with identical casing strings. Thus, monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom. “These are making a huge difference,” said Russum. “In the past you had to drill a vertical well, then run the casing to the bottom and wait for the casing to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.”

Although technologies like microseismic are also making a difference, the most important developments on the completion side have involved the increasing power and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you proceeded to the next one. Today it’s a continuous process.”

These clusters of technological breakthroughs first created the shale gas revolution. Pioneered by an American, George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began yielding highly economic volumes of natural gas – and, not incidentally, drove down the price of gas. Some observers now describe natural gas as a low-value by-product encountered in shale reservoirs in the quest for natural gas liquids.

From a production perspective, the other great outcome from this cluster of technologies has been the development of tight oil from shale – what Russum prefers to call “conventional oil from more shaley, low-permeability reservoirs.” One outcome is that both western Canada and the US are experiencing growing light oil production for the first time in decades – much of it coming from the Bakken play in North Dakota and Montana. After decades of decline in Alberta, for example, light oil production has recently risen to ten year highs.

An Explosion of Uses

These new technologies are changing almost everything about Canada’s petroleum industry. For example, horizontal wells are now a huge part of gas storage. “You can store gas very quickly into those wells,” said Russum, “and you can extract it quickly, too. Then there is the whole area of trying to reduce surface impact. I think we’re going to see more and more of that. Surface owners are more and more reluctant to have pumpjacks and other surface equipment on their land, and horizontal wells are less likely to disturb natural habitat. There is also extended reach, so you can reach under lakes and towns and cities. You can use it to reduce water production in a thin reservoir located over an aquifer.”

The economics of the horizontal well are also greatly improved, especially when you are planning production from a narrow reservoir – ten metres thick, for example. Horizontal wells provide much greater contact with the reservoir per dollar of drilling than do their vertical kin. And when they are drilled in search of unconventional resources like shale gas and tight oil, the producer gets a quick payback because initial production rates are so high.

Still not convinced? Then let the numbers tell the tale. According to an AJM Deloitte study which is complete to late 2011, more than 30,000 horizontal wells have produced conventional oil or gas in Western Canada over the past twenty five years.  Of that tally, 4,300 were completed in 2011.  This set a record for horizontal oil drilling: nearly 3,500 wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly attracted by the high liquids content in the Montney and Middle Mannville. Today, half of Western Canada’s wells are being drilled horizontally.

Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite.

Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling.

Oilsands companies in particular, but also other companies involved in modern resource plays are basing their business plans on step-by-step, decades-long development of vast and well-defined resources. This means traditional wheeling-and-dealing is at least partly on the decline – to a large extent replaced by courting cash-rich foreign companies with deep pockets and the desire to support these capital-intensive activities.

Tallying the Oil Reserves

How Canada made it to number three in the world

This article appears in the April issue of Oilsands Review

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Selling the Brand

Dene National Chief Bill Erasmus addresses Keystone XL pipeline protesters 

Earning the public trust has become an industry responsibility, not a corporate exercise in public relations

This article appears in the February issue of Oilweek

By Peter McKenzie-Brown

Operating an oil and gas company in western Canada has become a much more complicated endeavour in recent years – in large part traceable back to the rise of the Internet and the age of instant communication. Those living on the periphery of the industry are becoming increasingly vocal about the impact of drilling and pipelines and fracking and trucking are having on the quality of their lives.

In such a fishbowl existence, then, gaining a social license to operate becomes not just a one-off exercise for an operator dealing with a landowner, but an industry-wide commitment requiring coordinated and cooperative efforts by producers, industry associations and regulators to develop cohesive consultation plans with a broad range of stakeholders.

“We are all out there operating in the land base, but we are also in people’s neighbourhoods. Regardless of your company’s size, people see us as the industry,” according to Patsy Vik, who is EnCana’s Group Lead, Community Relations. Collectively, “we are painting a picture that all of us are going to be branded with. If we (in the industry) all work responsibly and respectfully, we will reflect positively on other companies. We should all behave in such a way that we garner respect from our neighbors.”

When the industry fails in matters of common courtesy, terrible things can happen. Consider the Keystone Pipeline, which was constantly in the headlines last fall. In an interview, the University of Alberta’s Andrew Leach suggests that “it’s important not to take this decision (to postpone a ruling on Keystone until after America’s presidential election) as an anti-oilsands measure. At least in part, it’s a reaction to high-profile oil spills in the United States by Canadian pipeline companies.” Also, he suggested, project proponent TransCanada Corporation may have been “a bit high-handed” when it planned the line.

TransCanada spokesman Shawn Howard disagrees. “Across the entire TCPL system, we deal with some 60,000 landowners,” he said. “We understand that we need good stakeholder relations to earn our social license to operate….We have held more than 300 community consultation meetings” as part of stakeholder relations for Keystone, for example.

Howard believes “a well-financed, well-organized group of anti-hydrocarbon environmental groups have taken on the project. The original Keystone pipeline was approved without any problem. For them this is a very important symbolic victory.” Clearly frustrated, he blusters that “A lot of the information (these groups) submitted to the hearings was simply not true and certainly not scientific. They would submit each other’s news releases instead of scientific studies….”

Worst Case Scenario

While Keystone is the most celebrated recent example of a project at risk because of public engagement issues, it has many predecessors. For example, a decade ago Shell was seeking a permit to develop a sour gas field at its Farrier location near Rocky Mountain House.

A consultant specializing in community engagement, Gay Robinson picks up the story. “Shell put in an application to drill this well but in the hearings they began with their emergency plan rather than starting in a positive manner,” she says.

The result was a classic: the locals became frightened and upset and TV personality David Suzuki got wind of the controversy. “He came in and did a documentary called Worst Case Scenario, which aired on CBC-TV. The license was denied and the hearing alone cost Shell many millions.” The mega-corporation also had to forgo the Farrier property’s profit potential, and its reputation suffered.

Robinson continues, “A number of years later, Shell had another significant (sour gas) discovery fairly close to Rocky Mountain House, at Tay River. That time, they realized they had to work in a different way to develop it. They had a different attitude about how to engage the community. They talked to people, asking ‘What do you think we need to do?’” The outcome was a license to operate.

Having focused the last 15 years of her career in public consultation, Robinson is passionate about both the process and the reasons behind it. “There is a need for it. I think there are opportunities for this, and I enjoy sitting down at the kitchen table with people in the community and talking about how we can do things better.”

She adds, “Good stakeholder relations are based on the belief that stakeholders have a right to be involved in decisions that will affect their lives. If companies don’t believe that, we have a basic disconnect from the beginning. People remember the mistakes the industry made in the past, and they don’t want them to see them repeated.”

What they see is a truck

Whether companies are large or small, “they face exactly the same problems,” according to Terry Bachynski, a vice president of emerging oilsands producer Athabasca Oil Sands Corp. (AOSC). “When local people see a truck driving by, they don’t know or care who the truck belongs to. What they see as a truck. If any company is unresponsive to the needs of the people, then we as the industry can all be affected.”

While in one sense stakeholder relations is fundamentally the same for every company, local factors to make a difference. “We have a wide network of stakeholders we have to deal with,” according to EnCana’s Patsy Vik.” These include the media, community leaders, organizations we provide community investment support to, synergy groups, different industry groups and interested environmental groups. Our contractors are another really important stakeholder. They are out there representing us on a daily basis.” EnCana’s interests stretch across the continent.

By contrast, Bachynski works primarily with aboriginal groups. “Because we are up in northeastern Alberta, most of the stakeholders we have to deal with are aboriginal communities. They have deep concerns: how will oilsands development affect their land treaty rights? Will it interfere with their use and enjoyment of their traditional lands? When we talk to them, one of the areas we talk about is how they can benefit from our efforts – for example, through employment and business development. “There are some cases where it’s really important for all the operators to work together – road building, for example. People in those areas really don’t want a lot of roads going through their traditional territory. What’s important is for the industry to work as one on these projects, making sure they meet the needs of local communities.

“New operators do have particular challenges in some ways,” he concedes. “The companies that are already established have a reputation among the local people. If it’s a good reputation, they do have an advantage. New operators have to go in and prove themselves.”

Unlike Bachynski’s AOSC, gas giant EnCana mostly produces from more populated parts of the Western Canada Basin – thus, different constituents with different issues. According to Patsy Vik, “A lot of the issues are related to dust, noise and traffic. We try to identify the impacts of our developments on our neighbours so we can be proactive and manage them. We need to talk to people and listen to people and create some kind of awareness and understanding around what we’re doing. It depends on the scope and scale of the project. We have different groups in our company that address different parts of the issues. A lot of people work with landowners on issues like gathering lines, for example, that might affect them.”

Vik stresses that public engagement is mostly about communities and neighbourhoods. “People are protective about their homes – that’s the one domain that they want to have influence and control over. That’s why we developed our signature Courtesy Matters program, which specifically addresses those things that affect people when they’re driving to their homes and through their neighbourhoods. Some of the things we do can make it less appealing for them to enjoy their homes and enjoy their space. We know that. We try to mitigate those impacts” through Courtesy Matters, which she describes as a policy focused on “working with the community to understand our impacts and working to resolve, mitigate and minimize them.”

She adds, “One of the things we really stress is how people utilize natural gas in their daily lives. We want it to be personally relevant to people. We also communicate with people around the different stages of our activities, and what it will mean to them.”

Moving On

Returning to Gay Robinson’s Tay River case study, “the community recommended that the partners form a synergy group. I helped them do that.” She adds that global best practices “show that public acceptance of the decision-making process is the key to implementing a public engagement program.” A strong advocate of synergy groups, she describes this relatively new approach to public consultation as a public consultation best practice.

The purpose of these groups “is to bring people together to resolve issues, lessen impacts and encourage the use of best practices in the areas of health, safety and the environment,” according to Synergy Alberta, a not-for-profit organization which promotes this form of conflict resolution. “They connect people and organizations to a particular project, facility or neighbourhood. With relevant people at the same table, true information sharing happens and projects or facilities can be tailored to meet the needs of all stakeholders including industry, residents and landowners and regulators.”

According to the organization’s website, synergy groups “form for a variety of reasons. Sometimes it’s community-driven to seek more information, provide information or rally against something the community opposes. Other times, groups are created by industry looking to proactively share information on proposed projects and gather input from the community and others with a stake in the project or area.”

Those working in the area are adamant that good stakeholder engagement is critical if you want a controversial project to move on – be it sour or shale gas, bitumen or an environmentally contentious pipeline.

According to Robinson, “There is actually a solid business case for meaningful stakeholder relations. It’s not something you do just to avoid grief. You do it to get a social license to operate.” Quoting a colleague, she says “‘the government grants the permits but the community grants the permission.’ The idea is that if the community is not in support, and you don’t have the social license to operate, you will have a lot of trouble getting the project off the ground.”

To a very large extent, those decisions reflect changes in the law. In 2004, for example, a Supreme Court decision articulated the notion that governments and industry have a “duty-to-consult.” Alberta’s recent Aboriginal Policy, Water for Life, Land Use Framework, Biodiversity Monitoring Institute and other policy-related pronouncements incorporate this notion. The same now applies in one way or another across the country.

The duty of government, public agencies and industry has simply become good practice.

The Granddaddy of them All

The granddaddy of Canada’s public consultation regulations probably comes from Alberta’s Energy Resources Conservation Board (ERCB). The Board has required public consultation for decades, thus making Alberta a leader in public engagement. According to ERCB historian Gordon Jaremko, the board’s first major public hearing involved Imperial’s proposed Cold Lake project in 1978-79, although it had done hearings on sour gas development earlier in that decade.

The ERCB and its much younger sibling, the Natural Resources Conservation Board (NRCB), have broad discretion and little legislative guidance on what “the public interest” actually means.  In practice, these organizations consider social, environmental and economic effects of development when they determine whether a project is in the public interest.

Since regulatory agencies have so much latitude, they can be very responsive to well-organized campaigns opposing a particular project. For the proponent, therefore, it is better to over-consult than to do too little.

“Companies should recognize that the regulations are just the starting point. They are the minimum requirement,” Gay Robinson stresses. “The ERCB has a document called Directive 56 which outlines the application process. It specifies that in some cases the public may require greater consultation (than the directive specifies). Unfortunately, some companies only perform to those minimums. They need to develop a principled approach to stakeholder engagement rather than just use the one that is prescribed – the regulatory minimum, as it were.”

Patsy Vik puts the matter into a continental context. In her view, EnCana’s stakeholder relations emerge out of “a reputation we have that we’re proud of, and (that reputation) is based on standard values we hold across the company. They are values that are dear and near to us, and they don’t stop at the border.”

Saving Money with Monster Trucks

HOURGLASS: Lessons from the Oil Sands Oral History Project

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

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

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

This article appears in the December Oilsands Review

By Adriana Davies

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

12 trends for 2012

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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