Independence Day

Now that America's presidential race is decided, Canada's need to seek energy markets beyond the U.S. has never been more urgent.

 This article appears in the January, 2013 issue of Oilweek; photo from here

By Peter McKenzie-Brown

The day after America’s presidential election, the Calgary-based Canadian Defence and Foreign Affairs Institute (CDFAI) hosted a panel discussion on the political and economic significance of President Obama’s second term.

Some of the most interesting observations came from Jonathan Baron, an American lobbyist with a primarily Republican clientele. “What you need to know about Republicans and Democrats is that they hear different things when they hear the word energy. Say ‘energy’ to a Republican, and he will think about increasing energy production. Say ‘energy’ to a Democrat, and she will think about mitigating environmental impacts. It’s like another world.”

Now he was on a roll. “When a Republican thinks about Canada’s energy resources,” he added, “they really do think that these resources belong to America. There isn’t a strong sense that they are a sovereign asset for Canadians. For Republicans, the idea of North American energy security is a no-brainer.”

The irony is that the International Energy Agency issued its annual report a few days after this panel discussion – a report which seemed to put the cat among the pigeons. According to the IEA, “The global energy map is changing, with potentially far-reaching consequences for energy markets and trade. It is being redrawn by the resurgence in oil and gas production in the United States and could be further reshaped by a retreat from nuclear power in some countries, continued rapid growth in the use of wind and solar technologies and by the global spread of unconventional gas production.” According to this respected agency, the US will become the world’s top oil producer by 2017, and could be nearing energy self-sufficiency two decades later.

A bearish outlook for Canada’s oil producers, is this report worth long-term worry? Probably not. Since the 1972 publication of The Limits to Growth, a book which forecast shortages of virtually every commodity by the end of the 20^th Century, a good rule of thumb has been that long-term natural resource forecasts are always wrong.

To a large extent, this is because major forecasts are political. IEA member governments and some oil companies vet them before they go public. In the highly likely case that the United States reviewed the IEA forecast before it hit the streets, they would have wanted the agency’s report to justify fracking, Keystone, perhaps, and the West’s embargo of Iranian oil. As one commentator observed, “Forecasters test scenarios – they assess economic and energy trends to produce numbers. Among the enormous range of possibilities, one forecast is chosen for public purposes.” Also, of course, since Adam Smith published The Wealth of Nations in the 18^th century, economies have shown repeatedly that markets eventually equilibrate.

If you focus instead on the near-term implications of the recent US election, there is a lot of good news.

·         Before campaigning began, global warming environmentalists developed traction by opposing Keystone. Notwithstanding their public protests, sources Oilweek spoke to believe the project has a good likelihood of getting State Department approval. An okay would increase the integration of Canadian oil and bitumen production into US markets and provide tidewater access to overseas buyers.

·         On the gas side, this commodity will expand its market for power generation, and Canadians will perhaps gain an advantage in the export of this commodity overseas.

Keystone

President Obama’s re-election was a near-term good news story for Canada’s oil patch. If approved, he Keystone Pipeline will move bitumen to the 7.6 million barrel-per-day Gulf Coast market. It is worth remembering that the Department of State originally deferred its decision on the pipeline as a political gesture, so as not to alienate environmentalists during the election. The reason given was concern about a proposed segment of the pipeline route through environmentally sensitive sand hills in Nebraska.

According to Maryscot (“Scotty”) Greenwood, a left-leaning Democrat, “There is awareness in the United States about the importance of energy from Canada and I believe that awareness was heightened during the campaign. There is a renewed appreciation of the importance of North American energy independence.” She is reasonably confident the project will go ahead, using TCPL’s revised route. In a separate interview, AJM Deloitte’s geoscience director Dave Russum enumerated the reasons the State Department might stand behind Keystone: “Job creation, economy boost in the US, secure supply.”

For Canada, the benefits are different. Keystone would provide Canadian oil sands producers with direct access to America’s single biggest oil market. Thus that pipeline’s throughput would not be subject to the price differentials that have become chronic – especially for the oilsands sector. More importantly, the project would provide Canadian producers with access to tidewater. This would mean overseas markets and international prices. Meanwhile “we are in for a rocky time in the Canadian industry regardless of who is in the White House,” according to Russum. “When oil prices were more than $100, many projects looked pretty attractive, but current prices in the $85 range make the economics much less robust.”

Carbon emissions kept coming up during the CDFAI forum, and Greenwood stressed the political importance of the environmental constituency. “During the second term of the Obama administration (president Obama) has an imperative to deal with some new legislation which covers coal ash, soot and other environment-related questions. This will affect core constituencies. However, there is not necessarily a conflict between these two. You can look after these regulatory issues, and also do Keystone.”

Right-leaning Jonathon Baron disagreed. “The environmental community feels frustrated, so (their protests) have moved down to the state level. The president is going to have to do quite an interesting balancing act to deal with fracturing and Keystone.”

A master of Realpolitik, Baron offered hope for crude oil prices – but hope with a bitter taste. “There’s going to be more instability in the Middle East during an Obama presidency,” he said; after all, the president campaigned on having ended “a decade of war.” If the president is not willing to use American might in response to Iran’s apparent nuclear build-up, Baron argued, there will be mischief in the Middle East. “That volatility means high prices going forward. That has important implications in American markets for Canadian oil sands and natural gas.”

Gas Prices and Markets

Canada’s gas industry is likely to benefit from President Obama’s next term through the conversion of its power industry to natural gas. According to Scotty Greenwood, who served for two terms as a staffer in the Clinton White House, suggested that he “is looking for ways to regulate more stringently, to pivot to natural gas because it’s a cleaner burning fuel than coal. He does have a desire to build demand for natural gas and to clean up the coal industry.” Since it’s his second term, the president will find America’s powerful coal lobbies less daunting.

“During the election campaign Obama virtually did say ‘I hate coal!’” Baron told the CDFAI audience. “Cheap natural gas has given the president an opportunity that didn’t exist before. Because the United States knows that it is not going to be able to implement a carbon tax, it will instead increase the price of coal through regulation, making coal less competitive.”

North American gas markets are likely to expand at the expense of coal. In itself, this may not be cause for much celebration in Canada, since the United States is nearing self-sufficiency in this commodity, and its production and transportation costs are lower. However, Greenwood noted another area where the US political environment could unwittingly favour Canadian natural gas.

In the American political system, Congressional committees have plenty of muscle, and it matters who serves as the chair. The incoming chair of the Senate’s powerful Energy and Natural Resource Committee is Democrat Ron Wyden. Wyden believes large-scale LNG exports would raise natural gas prices in the US, harming the economy. In the past he has argued that Washington should impose a “timeout” on new LNG export facilities, pending review. “That could be the end politically for (additional) natural gas exports from United States,” said Greenwood.

“There is a gigantic and very legitimate debate about whether we should be exporting natural gas,” she added. “My observation is that in the United States it will be politically very difficult to export (gas to other countries).…This could be a big opportunity for Canada, since the same political challenges do not exist here.” Baron concurred. “There are already a number of LNG export projects in the United States. LNG exports along with hydraulic fracturing will be major issues during the president’s second term.”

While the Americans dither, Canada could approve and construct facilities for overseas markets. Eastern Canada already imports about two billion cubic feet per day of gas from the US, and “this is a cheaper source than Western Canada. We are of course a net exporter to the US, but that role is shrinking. We need alternative exports” said AJM Deloitte’s Russum. He observes that Canada is ‘way behind Australia and other countries in developing or expanding LNG facilities. While the US already has gas export facilities in operation, Canada’s first plant won’t be ready until 2019.

“To me the problem is that Canada can’t compete with gas supplies that are abundant, cheaper, and closer to market in the US – for example, Marcellus, Fayetteville, Barnett and Eagleford,” he added. “Gas is still a fossil fuel, so while it is cleaner and more environmentally friendly than coal, it still has the fossil fuel stigma and the fracking stigma. I’m unclear whether it is a problem or a solution in the US. In any case, if prices rise the US has shown it is able to drill and bring on new volumes of shale gas very quickly, which would in turn dampen prices.” Russum added that “prices for natural gas need to be considerably higher to make the industry profitable here.”

The US/Canada Alliance

Prime Minister Brian Mulroney once famously said that “the relationships (between prime ministers and presidents) are absolutely indispensable. If you don’t have a friendly and constructive personal relationship with the president of the United States, nothing is going to happen.”

According to Greenwood, the Canada/US relationship is “hugely important, writ large. It’s much bigger and more integrated than any personality. It matters who is in the White House, but in the end the relationship will do well because it has to, and because of all the history between the two countries.” She added that “the US government does not want to prevent Canadian development in any way. We have very close relationships, and those relationships are of great value on both sides of the border. I think the United States, as Canada’s most important commercial partner, wants Canada to be commercially successful in every possible way.”

Colin Robinson, a Canadian diplomat who helped broker the Canada-US Free Trade Agreement and NAFTA, stressed the importance of international cooperation to help prevent trade disputes. “The first lumber dispute between Canada and the United States goes back to the time of George Washington,” he reminded the CDFAI audience. “These kinds of things do lead to protectionism. In a lot of cases, we have to put competition aside and think of things as North American.”

“Whenever (a diplomat has) to do something in the United States you have to do it through the White House,” according to Baron. The State Department is critical for international affairs, but other parts of government are in play. Formerly Canada’s ambassador to the US, Frank McKenna once said that “The president can love you to death, but that doesn’t mean you don’t have constant harassment from Congress….The tone at the top helps, but it’s not conclusive.”

As this article went to press, there was optimism that the United States would not fall over the “fiscal cliff.” For the sake of talking about the near-term future, this article assumes a compromise that won’t suffocate North America’s economies. If America remains a house divided, though, Canada needs to declare greater independence from US commodity markets. That truth is self-evident.

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.

Books on the Oilsands: A new cottage industry

Books about the oil sands were once few and far between; today they are part of a cottage industry, and often written by people with an axe to grind.

Such is the case with the latest installments, each of which boasts a green theme. However, it would be difficult to imagine three more diverse approaches to such a challenging topic.

• Alastair Sweeny, Black Bonanza: Canada’s Oil Sands and the Race to Secure North America’s Energy Future John Wiley & Sons Canada Ltd., 2010
• Satya Das, Green Oil: Clean Energy for the 21st Century? Sextant, 2009
• Gordon Kelly, The Oil Sands: Canada’s Path to Clean Energy? Kingsley Publishing, 2009

This article appears in the August issue of Oilsands Review

By Peter McKenzie-Brown

Black Bonanza
For a rollicking good read with a clearly defined message, Sweeny’s Black Bonanza really hits the mark. To get the flavour of his offering, consider two of many questions he raises in his preface. “Why are millions of people obsessing about carbon dioxide, a trace gas in the atmosphere, 3 percent of which is due to human emissions?... Why are government officials demanding that billions of dollars be spent to control this gas that is so essential to plant growth, while real pollution concerns cry out for solution and scores of our fellow citizens starve to death or die from preventable diseases?”

A historian by education and a writer by occupation, his chapters on the development of the oil sands are particularly worth reading. He captures people’s lives well, and has quite the instinct for the compelling quote.

Sweeny is on a mission, however. His message is that the oil sands present a tremendous strategic advantage to North American energy security, and they should be developed immediately. Canada would benefit enormously as it became an energy superpower, and North America would remain an ascendant geopolitical entity as it used a combination of crude oil security, economic strength and technical expertise to develop the inexhaustible energy of the sun. While the text is riveting, as the book winds up its message begins to fall apart. To make his case convincing, Sweeny must destroy the foundations of the climate change and peak oil debates.

He does pick holes in the conventions of climate change theory. Some of his arguments are historical: the Little Ice Age of around 1600, which followed the Medieval Warm Period of a millennium ago – and neither of which was connected to greenhouse gases. Others are statistical: carbon dioxide makes up 391 parts per million of atmospheric gases, of which 12 parts per million come from human activity. Other arguments use conspiracy theories to explain the sources of public concern: to a certain extent, he pooh-poohs climate change science as the work of people with vested interests in government grant machines. This is not exactly respectful of the scientific method and scientists, who together have contributed so much to contemporary civilization.

Sweeny’s efforts to dismiss peak oil are equally dicey. The gist is that there is plenty of oil in the world’s unconventional oil deposits, which of course is true. The point at issue is whether those deposits can be developed in time to replace depleting supplies of conventional production. On that question, the jury is still out.

The author successfully argues that Alberta’s oilsands have been demonized because environmental NGOs need easy, controversial targets to use in their annual fund-raising campaigns. Similarly, celebrities and politicians know they can get press by visiting Fort McMurray and proclaiming that the mines and plants look like something out of J.R.R Tolkien’s fictional Mordor, so they do.

The statistics Sweeny uses to defend the oil sands from the critics are compelling. He claims that each year America’s single-biggest coal-fired electrical generating plant spews forth 25.3 million tons of carbon dioxide contaminated with sulphur dioxide. That compares to about 40 million annual tons of relatively clean CO2 emissions from the Athabasca oil sands. Furthermore, Canada – the world’s poster child for dirty oil and GHG emissions – is responsible for 1.9% of global greenhouse gases. By comparison, green Europe emits 13.8%, the US 20.2% and China 21.5%. And so the argument goes.

Sweeny’s book is worth the read. As a gadfly, he counterbalances much of today’s conventional wisdom. Of equal interest for the bookworm, it’s an entertaining read from start to finish. The same cannot be said of the effort by Satya Das.

Green Oil
“Beyond a few purblind ravers,” says Das, “no rational person denies the reality of climate change.” Given the author’s background in journalism (notably with the Edmonton Journal), this mess of a book is particularly surprising.

He does not have a coherent message. In the absence of such a message, he parrots endless buzz-word laden passages from provincial government and ENGO reports – mostly on the importance of provincial stewardship of its resources, and strategies for governmental success. Painful to read, this book offers little except a sense of what higher-echelon bureaucrats conclude in their strategic planning meetings.

Self-published by the consultancy Das helped to found, this book’s main purpose is probably to drum up business. In fact, it is only in the context of his understanding of the roles of the public and private sectors that this publication makes much sense. “The principal role of government is to set a strong and effective policy framework,” he proclaims. However, “in every instance, the private sector role is to proceed robustly and vigorously to create wealth and value within the direction set by government.” As a private-sector entity advising government on policy issues, it’s safe to assume his firm is proceeding robustly and vigorously in the aforementioned direction.

This book is a stinker. Buyer, beware.

The Oil Sands

Gordon Kelly’s book is long, sometimes dry and technical, occasionally rambling. However, it’s also the most comprehensive and current study of the oilsands available. For anyone wanting a crash course in the oilsands, it’s a godsend. For anyone wanting a complete and current reference, it’s the only game in town.Kelly draws deeply from technical reports without taking shrill or ideological positions. For the most part he reflects the industry’s collective wisdom about the state of the oil sands. Fortunately, he also offers innovative ideas worth serious consideration.

Well into his 70s, Gordon Kelly had a long and diverse career in the petroleum industry – much of it as an ex-pat – and still works as a consultant. An engineer with an MBA by training, his understanding of the petroleum sector runs deep. It is therefore worth noting that his review of peak oil is comprehensive, and that he takes the issue quite seriously.

“A major theme of this book,” he says, “is that the world could run short of oil before new sources of mobile power are available. That is why the oil sands are needed and why it is important that Canada start the search for new alternative power sources now.”

Unlike most peak oil advocates, Kelly doesn’t see a probable decline in oil production as a function of scarcity. Rather, he sees it as a social problem. “Environmentalists are becoming more aggressive against oil and nuclear power because they really believe biofuels, windmills and solar panels can save the planet from GHG climate change. Politicians demand GHG curtailment because it makes them look ‘green’” he writes, “but it adds to the cost and time to build projects. Adding ‘Cap and Trade’ penalties to curb GHG emissions has reduced the money available for adding more capacity in Europe and may be expanded to North America. Project approval hearings drag on for months or years. Court challenges add to the delay....The world has lots of oil, but politics (will) block the (industry’s) ability to develop it fast enough.”

When we pass the peak in oil production (Kelly guesses the year will be 2015), “the shortages will be only a small percentage of demand, but for those who do not get the oil, it will be a crisis. History suggests it will be the poorest countries.”

Besides acknowledging peak oil as a reality, Kelly sees climate change from greenhouse gases as a threat. In that context, he puts forward some refreshing proposals on making Canada a leader in alternative energy.

In effect, he argues in his concluding chapter that Alberta should diversify from an energy-based economy into an energy-based economy. The oilsands and Alberta’s existing energy infrastructure provide a formidable base from which province and country can constitute a global clean energy superpower.

Concerned about the need to develop new sources of energy, Kelly conjures up the ghost of a creation of Alberta’s Lougheed years. Introduced in 1975, the Alberta Oil Sands Technology Research Authority invested $670 million over a 15-year period – all of those funds matched by private dollars. “AOSTRA was not government research but private research supported by the Alberta government,” says Kelly. “There is a big difference between the two. The private sector (had) to be willing to invest 50% of the cost in a project before Alberta (would commit) to the investment.”

According to Kelly, the program was so successful that it led to the construction of more than $100 billion in oilsands plants, so far. That is a stretch, perhaps. However, even if he is off by 75% (with rising commodity prices and associated inflation being mostly responsible for Alberta’s recent oilsands investment), the province’s AOSTRA investments generated highly leveraged results.

Today, he says, the province should introduce an AOSTRA-style program (Kelly calls it the Alberta Energy Research Project, or EARP) to encourage investment in alternative energy, arguing that research incentives could take advantage of the province’s existing expertise to create next-generation technologies. This is not far-fetched, he argues. BP is already “a large supplier of solar energy, while Chevron is the largest supplier of geothermal energy. Shell has a hydrogen division. Suncor has windmills and a biofuel operation.”

If you are interested in Alberta’s and Canada’s energy future, this is a fine tome. It’s too long, perhaps, and in some places could use a bit of cosmetic surgery. Even so, it is worth the time you invest in reading it.

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The Carbonate Question

This article appears in the November, 2008 issue of Oilsands Review. Graphic shows Alberta oilsands in yellow, major heavy oil deposits in blue, Grosmont bitumen carbonate formation in red and bitumen triangle within dashed line. Source of map here.

By Peter McKenzie-Brown

According to one view, planet Earth has two energy super-provinces – one in the Old World, the other in the New. The Old World super-province stretches from North Africa through the Middle East into Siberia. Rich with conventional oil, it’s the source of most of the petroleum traded on global markets.

The New World super-province reaches from northern Alaska and the Beaufort Sea through Alberta’s oil sands down to Venezuela’s Orinoco heavy oil belt, and continues south between the Atlantic coast and the eastern Andes. Richer in oil than its Old World sibling, its conventional resources are mostly in decline. However, this vast region has great volumes of untapped unconventional resources – notably Alberta’s oilsands, Venezuela’s Orinoco heavy oil belt and America’s oil shales.

This article focuses on the least known of those unconventional resources. Bitumen carbonates are common reservoir rocks totally saturated with very heavy oil. They are also the hydrocarbon resource in which Canada leads the world by an almost incomprehensible margin.

Canadian deposits contain 96% of the entire world’s supply of this black, barely mobile oil. That would be just a statistical oddity if not for the volumes of hydrocarbons involved. There are nearly 450 billion barrels in the ground in Alberta. Seventy-one percent of that total (318 billion barrels) is in the Grosmont formation – a massive structure underlying much of the Athabasca oilsands deposit. Another 65 billion barrels of bitumen can be found in the Nisku carbonate, which is associated with the Grosmont. In Peace Country, the bitumen-saturated carbonates contain as much oil as the Peace River oilsands deposit – once again, about 65 billion barrels.

Here’s another way to put those numbers in perspective. Alberta’s bitumen deposits comprise the largest petroleum resource in the world. One fourth of that resource is in carbonate reservoirs.

There is a catch, of course. Like the oilsands many years ago, there are no economic ways to produce oil from these deposits yet. However, in early 2006 a numbered company shelled out C$465 million for oilsands leases in the Grosmont. When the owner of that mystery company turned out to be Shell – not known for taking high risks when large amounts of cash are at stake – many previously skeptical observers began to see these carbonates as a resource whose time was nigh. Is that optimism justified?

Nature of the resource: Carbonates are minerals that contain the carbonate ion, CO3. Probably most of the world’s conventional oil resources are in traps made of these rocks. While the most common reservoir carbonates are limestone (a calcium carbonate) and dolomite (a magnesium and calcium carbonate), reservoirs typically include many other carbonate minerals.

On the surface, Alberta’s bitumen carbonates have the makings of an oil producer’s nightmare. The rocks themselves are full to saturation with huge volumes of highly viscous, heavily biodegraded bitumen – the most viscous bitumen carbonate in the world, in fact. The resource is thicker than molasses. In general, the carbonates have little permeability so the bitumen is in a reservoir that won’t easily let it escape, and for other reasons the reservoir rocks can yield as much trouble as oil. The resource is in the middle of the bush. Once you get the bitumen out of the rock, it isn’t transportable without lots of diluent, and it isn’t commercial without extensive upgrading. For all this Shell paid nearly half a billion dollars?!

What Shell paid for was the potential. The volumes in the ground are so huge that a relatively small amount of production from a sweet spot in the Grosmont could be hugely profitable. In a number of cases worldwide, some bitumen carbonates have gone on production with reasonable results – notably Iran’s offshore Zaqeh field (no longer producing) and France’s Lacq Superieur. As we shall see, Shell’s ace in the hole is technology.

In the 1970s and 1980s, a number of companies conducted experiments on the Grosmont formation, mostly in cooperation with the long-defunct Alberta Oil Sands Recovery and Technology Authority (AOSTRA). Although no commercial oil resulted from these experiments (production was pumped back underground), the technical community began to understand the resource, and to dream about bringing it into production.

According to Roy Coates of the Alberta Research Council (ARC), bitumen carbonates are now at the place where non-mineable oilsands were some decades ago. Commercial development is in the future – maybe 20 years. “That’s when carbonates will be at the stage where SAGD developments are now,” he said. “I don’t consider SAGD really commercial yet. (Producers) are still trying to optimize the process.”

Coates is program manager for the Carbonate Research Program, a 3-year, $2.3 million per year initiative of major companies plus two agencies of the Alberta government. He seems fascinated by the challenges of the Grosmont bitumen carbonate, beginning with the matter of where the stuff came from. “That’s something we’re looking at. I would venture to say that it is the same oil as in the oil sands. We don’t know where the bitumen originated. It could have originated in the carbonates and flowed to the oilsands or vice versa. We don’t know the answer to that. But the properties are so similar that you should consider them to be the same oil.”

Matrix, vugs and fractures: The fact that it is the same oil as the oilsands is one of many problems presented by this resource. Its viscosity is such that it doesn’t flow naturally. Like bitumen from the oilsands, you have to make it thinner to make it flow. That is only the beginning of the problems, however. For example, the bitumen formations are 200 to 1,000 metres deep, which means they are not mineable. Gas drive in the reservoirs is insignificant. The problems get even worse when you consider reservoir permeability and porosity.

According to Coates, the Grosmont carbonate “almost has three systems of permeability and porosity.” The matrix of carbonate rock is very tight, with low permeability. Yet over eons it has somehow become saturated with bitumen. That’s the first system: low-permeability, low porosity rock full of bitumen so viscous it won’t flow without treatment.

The second system harbours other problems. Within those carbonate rocks are large cavities, called vugs – often the diameter of your arm or bigger. For the most part, these structures are leftovers from eras when water ran through the rock, dissolving caverns and other crevasses in it. They fill with rock debris (often overburden), but they also fill with bitumen. These structures can have good permeability and porosity, but they do not always form good producing reservoirs and they cause drilling problems. According to one report, during drilling “the drill bit has been observed to drop several feet as it passed through a large tunnel filled with bitumen...and these irregular tunnels...lead to a loss of mud circulation during drilling.”

The third permeability/porosity system consists of long fractures in the rock. “When you try to heat a reservoir or inject a fluid into it,” said Coates, “because of the fractures you can’t be sure where the steam is going to go.”

These difficulties notwithstanding, in the early years of experimentation on the Grosmont, there were some great successes. According to an AOSTRA report, in the late 1970s Unocal (since absorbed into Chevron) and Canadian Superior (absorbed into Exxon Mobil) conducted a series of field tests to assess steam stimulation, steam drive and combustion on the structure. In one instance, “results were spectacular. Bitumen production rates from a single steam stimulation well of up to 550 barrels per day were obtained”.

Despite these results and those from further trials, the companies abandoned these pilots in the mid-1980s, for two reasons. One was the problem of logistics-related high costs (the Grosmont is in a remote area, without roads and other infrastructure). More importantly, the companies had serious technical concerns about the viability of production – especially in the lower-price environment that followed the oil price shock of 1986.

In situ refining: Of course, that was then and this is now – a world of high prices and improved technologies. In recent years, other companies have been testing Alberta’s bitumen carbonates. One notable player is Husky Energy, which has accumulated substantial holdings in the Grosmont, for relatively small amounts of cash. Husky estimates its Saleski bitumen carbonate properties contain 19.5 billion barrels of original oil in place. You don’t need to coax a large percentage of that oil from the rock to find yourself with a valuable asset. Husky’s tests so far have used technologies that are advances on the methods tested long ago by Unocal and Canadian Superior, but similar in concept.

Shell, however, is different. When Shell made its startling $465 million bid for part of the Grosmont, the company clearly had in mind substantial production volumes. The industry wondered what was going on, until a hint of company thinking came out in a recent interview with Jan van der Eijk, Royal Dutch Shell’s chief technology officer (CTO). The occasion was a wide-ranging discussion of technology, but largely centred on Shell tests at a bitumen carbonate deposit in the Peace River area. New Technology magazine reported the story.

According to journalist Pat Roche, “In what could lead to one of the most revolutionary innovations in the history of the oil and gas industry, Shell has been testing a way to upgrade bitumen in the reservoir for more than two years. Electric heaters raise the subsurface temperature to the point where the reservoir, in effect, acts as a refinery. ‘The product that you produce is almost water white, and it is as mobile as water,’ says van der Eijk.”

This “in situ upgrading process”, as the company calls it, has been more than a decade in the making. It began with tests on oil shale in Colorado. In its oil shale tests, Shell recovered 1,700 barrels of light oil from a 10 by 13 metre area at its Mahogany test site. The company used underground electric heaters like those introduced at Peace River to induce chemical pyrolysis underground. This “in situ conversion process” distilled shale-bound kerogen (a precursor to oil) into synthetic crude oil. A by-product of the tests was shale gas.

The Peace River test was the first to use electric heaters to upgrade oil in the ground.

Journalist Pat Roche continued, “As happens in a refinery, the lighter products are boiled off, leaving the heavier components behind in the reservoir. The upgraded oil can be further refined into products such as gasoline and jet fuel. ‘The product is really impressive,’ [says van der Eijk].

“‘In a refinery,’ he explains, ‘you need to have a certain throughput through a vessel. And that drives you to a certain reaction rate; otherwise, you just don't have enough productivity.’ But in the subsurface, the reservoir serves as a gigantic vessel. ‘And in that sense you can allow much lower reaction rates. The vessel is much larger and you can let it go for a year rather than a minute throughput [in a refinery].’”

Late last year, Shell filed a regulatory application to test its in situ upgrading process in the Grosmont bitumen carbonates. Perhaps its tests in that massive formation will help transform Alberta’s bitumen carbonates from vast stores of puzzling gunk to one of the hydrocarbon jewels of the New World. You can never tell.

Shell's Take on Carbon Sequestration

This article appears in the November, 2008 issue of Oilsands Review. The generic graphic comes from here.

By Peter McKenzie-Brown

Is human activity influencing climate change or not? Indeed, is global warming even taking place? There is widespread disagreement within academia about the causes of increased global average air temperature, especially since the mid-20th century.

Some argue that the observed “trend” is a normal climatic fluctuation. Others claim it isn’t even happening. These issues are the source of rip-roaring arguments in Alberta. Perhaps because of the impact of geological thinking on a province with a petroleum-based economy, the arguments here are both heated and informed.

Geologists, who think in terms of Earth’s periods and epochs rather than its decades, are well aware that climate always changes. Perhaps they also have an innate scepticism about whether human behaviour can meaningfully alter the powerful natural forces continually changing our planet. While the debates rage, the scientific “consensus”, as it is delicately called, supports the idea that greenhouse gas emissions from human activity are increasing Earth’s temperatures and thus speeding up climate change.

For many environmental groups the problem seems critical, and they call for urgent action. Increasingly, so do many corporations. For example, Royal Dutch Shell’s position on climate change is unequivocal. According to Jeroen van der Veer, the corporation’s CEO, “For us, as a company, the scientific debate about climate change is over. The debate now is about what we can do about it. Businesses, like ours, should turn CO2 management into a business opportunity and lead the search for responsible ways to manage CO2, use energy more efficiently and provide the extra energy the world needs to grow. But that also requires concerted action by governments to create the long-term, market-based policies needed to make it worthwhile to invest in energy efficiency, CO2 mitigation and lower carbon fuels. With fossil fuel use and CO2 levels continuing to grow fast, there is no time to lose.”

Carbon Capture and Sequestration: So what’s a company to do? Over the last decade, global think tanks have increasingly focused on CCS – the common abbreviation for carbon dioxide capture and sequestration (more colloquially, “storage”) as a technologically simple way to remove CO2 at some large processing plants. The most prospective targets for this technology include coal-fired electricity generators and oil sands upgraders.

Problem is, such ventures are not profit-driven enterprises. They are climate-driven – initiated in response to concerns about climate change and related regulation. On its own, CCS doesn’t make sense. It requires government intervention. In that context, the CCS climate changed profoundly last July when Alberta premier Ed Stelmach announced that his government would provide $2 billion to advance these technologies in the province. That is the biggest sum available for CCS anywhere.

Often (unfairly) derided elsewhere in Canada as a Johnny-come-lately to the environmental table, Alberta’s involvement follows a gestation period of deep study. Last January a provincial policy paper observed that “Alberta has a unique opportunity to implement carbon capture and storage to substantially reduce our greenhouse gas emissions. CO2 emissions can be captured where they are produced, transported and stored in geological formations (such as depleted oil and gas reservoirs, coal beds, and deep saline aquifers) that may be located hundreds of kilometres away.... Ultimately, CO2 capture and storage technologies provide the province with the greatest potential to substantially reduce greenhouse gas emissions while, at the same time, retaining our ability to produce and provide energy to the rest of the world.” Alberta is counting on CCS to meet 70% of its long-term GHG reduction targets.

When the September deadline for submitting expressions of interest to the Alberta government arrived, the Department of the Environment received “more than a dozen” proposals, according to government representatives. The province is now narrowing those proposals down to the few with the greatest potential to be built quickly and significantly reduce greenhouse gases. The province hopes to reduce emissions by up to five million tonnes annually through this program.

The names of the contenders have not been publicly disclosed, although the rumour mill is speculating on the usual suspects – big players with interests in oilsands or enhanced oil recovery. Devon, Imperial, Syncrude, a Husky/BP partnership, ConocoPhillips, ARC, Petro-Canada, Enbridge and Total E&P come to mind. One player, however, has been quite public in its enthusiasm for CCS. Shell Canada has long been studying a CCS project connected to its Scotford Upgrader, and a story on that project accompanied a great deal of the coverage of Alberta’s CCS incentives.

Sequestration or Storage? The name of that project, Shell Quest, refers to the notion of sequestration. According to Rob Seeley, Shell’s general manager of sustainable development, the idea of sequestration is quite different from storage. “Sequestration implies permanence,” he said. “Storage seems temporary. (In a CCS project) the carbon would be sequestered, not stored. It will be there forever.” In his world, CCS refers to carbon capture and sequestration, not storage.

The venture manager for Quest, Seeley is upfront about the global warming issue. “We (at Shell) are seriously concerned about man-made CO2 emissions in the atmosphere. We know that global warming is a natural process that has been going on for 10,000 years, but we believe that man-made emissions could be accelerating the process. Whatever the science ultimately finds, we believe in the precautionary principle. We need to take action on reducing CO2 now.”

The Scotford Upgrader is part of a complex dating back to 1984, when Shell constructed there the first refinery to exclusively process synthetic crude from Alberta’s oil sands. Located northeast of Edmonton, Shell’s Scotford complex has often been expanded. It, and was augmented with an upgrader in 2003.

The upgrader receives bitumen from the Albian oil sands plant, and transforms it into two types of synthetic oil – Albian premium synthetic oil and Albian heavy synthetic oil. Synthetic oil is bitumen with the impurities removed and hydrogen added. Adding hydrogen yields upgraded oil that can more readily be refined into high-quality products like gasoline, diesel and other types of fuel. The Scotford plant processes 155,000 barrels per day of raw bitumen.

The upgrader is now undergoing a third expansion which, when completed in 2010, will include the commissioning of a third hydrogen plant. Hydrogen plants combine steam and natural gas (methane) to produce hydrogen for upgrading and by-product CO2 that is vented to the air.

The key to Shell Quest would be a facility that captured the CO2 from all three of the upgrader’s hydrogen plants. “We will use a patented Shell process that uses amine solvents to scrub H2S and CO2 from our gas stream,” Seeley said. Once the gas stream was cleaned up, compressors would prepare the CO2 for transport to underground storage sites. Compressing CO2 transforms it into a supercritical liquid – a form of matter which has the properties of gas and liquid simultaneously. Once liquefied, Shell would pipe the CO2 to field facilities, where it would be injected into deep, underground rock formations.

How it would work: CO2 will remain in supercritical form if stored more than 800 metres below ground. Shell is targeting structures 2,000 or more metres deep. The injection wells would use several casings of steel pipe to ensure the CO2 entered the deep rock formations alone, and would not enter shallower areas of the ground. This would prevent leakage to the surface or into drinking water aquifers.

Cap rocks would trap the CO2 underground. In addition, however, several technical down-hole traps would keep the CO2 permanently in the reservoir. For example, CO2 can eventually combine with chemicals within the reservoir to form carbonate rock – limestone, for example. These traps plus the cap rock mean there is little likelihood the CO2 would ever leave the injection sites.

According to Rob Seeley, “We believe CCS is an important piece of the toolkit to reduce CO2 emissions. We think it’s a great opportunity within an oilsands operation to reduce our greenhouse gas footprint.” He notes that capture, compression, transport and sequestration themselves require energy, and that these energy needs will partly offset the benefits of CCS. “If we capture and sequester 1.2 million tonnes of CO2 per year, the net result of putting that away would be roughly 1 million. It depends on where the energy comes from for the capture and sequestration processes and how effectively it’s integrated into the whole process.” All in all, though, “CCS is a great opportunity to reduce CO2 emissions and to help move us on the path to greater sustainability.”

The Role of Government: Seeley was unwilling to discuss the cost of these ventures, but suggested that Alberta’s $2 billion would be distributed among only five CCS projects, each of which would capture at least one million tonnes per year. The simple math says the projects would each receive a $400 million subsidy. Why should they?

“We believe governments should take action on regulation to control CO2 emissions,” Seeley said. “If they do that, it will create a level playing field in which big industrial polluters can innovate to reduce emissions.” Seeley thinks big: “If we can have regulation that is complementary from country to country then we have a better chance of reducing these emissions internationally.” Seeley noted that CCS faces numerous risks that will require government involvement. These projects “are sitting waiting for regulation. The rules for greenhouse gas regulation in Canada are still not certain. You have to settle regulatory issues such as Canada and Alberta harmonisation before those projects can go forward.”

In his view, “The beauty of (CCS) is that it can capture very large from industrial sources. However, prices of $80-100 per ton are well beyond the prices that have set for CO2 in the near time. If the price of carbon is $15-20 per ton, it will be cheaper for companies to pay into a government tech fund than to actually sequester CO2.” Thus, if governments see CO2 emissions as a problem, helping fund CCS is a way for them to this important CO2 mitigation opportunity started.

“Capital costs will be in the hundreds of millions of dollars, but operating costs will also be high. It could be that over the life of a project the operating costs (present value basis) would be about the same as the capital costs. There are also technological costs.” Although CO2 has long been used in enhanced oil recovery, Seeley observed that “EOR doesn’t save the day on this. Historically, for EOR you get paid maybe $20 per ton for CO2. With higher oil prices, maybe you will get $30 to $40 per tonne. This is still well short of the $100/tonne cost to capture, compress and transport CO2. Only higher carbon pricing (by government) or the market will make this viable.”

Six Pathways: He adds, “The price of this technology will come down, but first we need some demonstration projects. That’s what Quest is all about – a large-scale demonstration of fully integrated CCS. We need to build this first round of projects so that we can learn from them. As these projects go ahead we will go from using amines to capture the CO2, then move on to cryogenics and other approaches that are more sophisticated.”

The earnestness with which Rob Seeley describes the issue of GHG emissions seems to reflect corporate culture at Royal Dutch Shell. The corporation has identified “six pathways” toward reducing carbon emissions. For the record, here they are: Increase energy efficiency within the corporation. Create technologies that increase efficiency and reduce emissions. Develop low-carbon fuels. Help customers use less energy. Work with governments on effective regulation. Implement carbon capture and sequestration.

This seems like a map other oilsands producers should study.

Colin Campbell and the Cracks of Doom

By Peter McKenzie-Brown
For many peak oil believers, this is the scariest chart you can imagine. The blue lines show historical oil discoveries. The gold lines project discoveries into the future. The line that looks like a rising serpent shows annual production up to about 2005. The chart was created by peak oil guru Colin Campbell in 2004 for a deliciously ironic article titled "The Heart of the Matter". The chart looks like a road map to the Cracks of Doom, and it has been quite influential.

In this column I have frequently provided arguments in favour of peak oil theory, and I am an unabashed admirer of Campbell and his work. However, I believe this chart, though directionally accurate, is simplistic and alarmist. It needs to be nuanced. We can do that in three ways.

• First, note that the blue lines essentially track the world’s new-field discoveries of light and medium oil. The chart suggests that these volumes are the world’s oil reserves. It doesn’t nearly reflect the reserves additions that come through infill drilling, enhanced oil recovery and other standard oilfield practices. By applying simple math to the chart (subtracting production from discoveries), you will come up with world oil reserves far short of the roughly 1.2 trillion barrels that the Energy Information Agency and other authorities have booked.

As they are developed, most discoveries prove to be much bigger than the estimates at time of discovery. This is partly because reserves are a function of economics. When you find a new field you calculate its reserves based on present conditions and price forecasts – say, in 1970, $2.50 per barrel into the foreseeable future. As prices rise relative to costs, you will get more oil out of that field – of that you can be sure.

The thinking by which M. King Hubbert forecast the year of peak oil production in the United States was incredibly successful. What is rarely discussed, though, is that Hubbert underestimated by about 50 per cent the amount of oil that would be available in the US after it reached the peak. To a large extent this was because new reserves became available through changing technologies and more favourable petroleum economics.

• Second, give heavy oil, bitumen and oil shale the credit they deserve. Because of the nature of the beast, these unconventional resources are not booked as reserves until they become economically and technically producible.

Alberta’s huge oil sands are a classic example. In 2005 America’s Energy Information Agency booked Canadian oil reserves as second in the world (after Saudi Arabia) because of the impact of higher prices and improved technologies on the oil sands. If that amount of oil – 174 billion barrels (174 gigabarrels) – were added to the gold-coloured reserves lines on Campbell’s chart, it would require a line that would tower over the rest of the chart by a factor of three. Campbell’s methodology does not account for this kind of event. And in all likelihood, much more of the oilsands will eventually be booked as reserves.

That point takes me to this chart (click to enlarge), which is also from Campbell’s article. The black wedge – characterized as “Heavy, etc.” in the legend – is his estimate of the contribution of heavy oil to the global energy liquids picture. Eyeballing suggests that he expected these unconventional resources to be about 4.5 million barrels per day by now, world-wide.

Heavy oil, synthetic oil and non-upgraded bitumen represent about two million barrels of production per day in Canada alone, and Venezuela and Mexico are also big producers. What’s more, Canada’s oil industry is working hard to develop export markets for heavy oil, because there is a great deal more production yet to develop. Indeed, Canadian producers are selling their heavy oil at a discount because they cannot get it to world markets.

According to one excellent and credible report, seven years from now Alberta alone will be producing about three million barrels per day of “Heavy, etc.” That estimate risks production for economic and environmental obstacles, so it is probably low.

• Third – and this is my main point – let’s acknowledge that the serpent-like production line in Campbell’s chart, while it is not a happy sign, is not the spectre of doom it appears. The world’s unconventional resources will greatly blunt the blow – relative to the steep declines described in Campbell’s chart, in any event.

One amazing feature of the oil sands is their incredible energy density. Imperial Oil’s Cold Lake bitumen plant, for example, is a tiny dot on the map of Alberta, yet it produces 6 per cent of Canada’s oil. The resource density of these unconventional resources is immense, and that density is what makes it such an important resource. The world is heading toward capital-intensive, technology-intensive, pollution-intensive and energy-intensive energy - bitumen from Cold Lake, for example.

The greater the capital intensity, though, the lower the geopolitical risk must be. Keep that in mind when you consider development prospects for Venezuela’s Orinoco heavy oil belt, which is so huge it rivals the resources of Canada. The geopolitical risks in that country are enormous, so the likelihood is small that new Venezuelan supplies will soon hit world markets.

Strongman Hugo Chavez is increasingly unpopular in his own country, however, and the economy is in disarray. Oil production is in decline even though the the country has the largest conventional reserves in this hemisphere. Given that situation, it is possible to imagine a post-Chavez Venezuela which will develop those resources and become a resurgent supplier to the world. If that happened, it would lead to another super spike in booked reserves.

I share the view that a global Hubbert’s peak is nigh. The world is facing serious energy supply problems, and they are related to peak oil. To too great a degree, however, the discussion has failed to recognize the immensity and importance of the world’s unconventional sources of oil. Those vital resources will radically change the shape of the chart as they are plotted into it.