A Saudi Predator?

How market manipulation helped the kingdom become a major investor in western oil companies

By Peter McKenzie-Brown

The last twelve months have been rough for companies invested in Alberta’s oil sands. Things began rough, with Norway’s US$1 trillion sovereign wealth fund, which has its origins in the country’s offshore oilfields, announced that it would unload the US$81 billion it had invested in bitumen companies. The reason? Such an investment was out of alignment with the 2^oC global warming target set by the 2016 Paris Agreement on greenhouse-gas-emissions. “By going…oil sands free,” the Norwegian news release said, “we are sending a strong message on the urgency of shifting from fossil to renewable energy.”

A strong message it may be, but also haughty. There is a direct correlation between a nation’s oil consumption, its GDP and the quality of life its citizens enjoy. By what right could the world’s rich nations – for practical purposes, the 37 members of the Organization for Cooperation and Development, with a population of about 1.3 billion – justify denying affordable energy to other countries in the world? Well, there is the matter of the global warming emergency.  The case for developing alternative energy resources is dire. After all, the population of our planet is rapidly approaching eight billion.

Norway’s wealth fund soon sold its US$81 billion interests in Calgary-based Cenovus Energy Inc., Suncor Energy Inc., Imperial Oil Ltd. and Husky Energy Inc. From that point on, the statement said, the fund would exclude companies involved in the oil sands from consideration as appropriate investments.

The shares in those companies responded immediately by falling. Even though there is widespread concern about global warming in Alberta, many of us with backgrounds in the oil patch felt affronted. “What else could go wrong?” we wondered. We did not know it at the time, of course, but there would soon be the matter of COVID-19.

As the dangers of travel across a pandemic-stricken planet became obvious, governments imposed lockdowns around the world and global oil consumption plummeted. As international travel crumbled, oil prices dropped for an industry which cannot too quickly shut in production. The poster-child for this event came on April 20^th, when the headline price for a barrel of West Texas Intermediate oil fell into negative territory for the first time ever. For the only time in history, sellers had to pay buyers to take their oil. (See chart.)

                Why did it happen? Essentially, because of the way oil markets function in Texas. The Texas Railroad Commission is the steward of the oil-rich state’s natural resources and the environment, and its regulations led to the reality of oil prices crashing from US$18 a barrel to -US$38 in a matter of hours. Rising stockpiles of crude threatened to overwhelm storage facilities and forced producers to pay buyers to take the barrels they could not store. Was this the doing of big oil – such vast publicly-traded oil companies as ExxonMobil, British Petroleum and Royal Dutch Shell, which are so often characterized as villains when pump prices rise at your local gas station.

In fact, the world’s 13 largest energy companies, measured by the reserves they control, are government-owned and operated – by name, Saudi Aramco, Gazprom (Russia), China National Petroleum Corp., National Iranian Oil Co., Petróleos de Venezuela, Petrobras (Brazil) and Petronas (Malaysia). These state-owned companies and their smaller siblings control more than 75 percent of global production. By contrast, the multinationals produce only ten percent.

Markets, manipulated

In early March, OPEC officials presented an ultimatum to Russia to cut production by 1.5 percent of world supply. For her part, the Eurasian giant foresaw continuing cuts in her market share: after all, America’s shale oil production, which uses fairly new technology, was making the country both the world’s largest consumer of oil and the largest producer. Anxious about this concern, Putin’s government rejected the demand – in effect ending a three-year partnership between OPEC and major non-OPEC producers, widely known as the OPEC Plus cartel. Another factor was weakening global demand resulting from the COVID-19 pandemic. This also resulted in OPEC Plus failing to extend the agreement cutting 2.1 million barrels per day that was set to expire at the end of March. Saudi Arabia, which has absorbed a disproportionate amount of the cuts to convince Russia to stay in the agreement, notified its buyers on March 7^th that they would raise output and discount their oil in April. This prompted a Brent crude price crash of more than 30 percent before a slight recovery and widespread turmoil in financial markets.

Perhaps this Saudi-Russian price war was a game of chicken to see who would blink first. But neither of the major players had much reason to blink. In March 2000, the Saudis had US$500 billion in foreign exchange reserves; Russia had US$580 billion. More to the point, the Saudi cost of production, depending on the grade produced, is three dollars per barrel, compared to US$$30 per barrel in Russia.

Thus, the OPEC plus price war was designed to take advantage of a weak global economy, infected by COVID-19. It Saudi Arabia's case, it assaulted the Western petroleum sector – especially America’s. To ward off from the oil exporters price war which can make shale oil production uneconomical, US may protect its crude oil market share by passing the NOPEC bill.

In April 2020, OPEC and a group of other oil producers, including Russia, agreed to extend production cuts until the end of July. The cartel and its allies agreed to cut oil production in May and June by 9.7 million barrels a day, equal to around 10 percent of global output, to prop up prices, which had previously fallen to record lows.

The Russia/Saudi Arabia oil price war, which had begun the previous month, had a huge impact – probably by design – on the ownership of large oil companies in Europe and North America. Saudi Arabia’s sovereign wealth fund saw nothing but opportunity in the global oil price plunge. During the battle, the kingdom scooped up billions of dollars’ worth of shares in downtrodden energy companies, including Canadian firms.

Filings with U.S. Securities and Exchange Commission indicate the kingdom’s Public Investment Fund (PIF), which has an estimated US$320 billion in assets under management, bought stakes worth US$481 million and US$408 million in Suncor and Canadian Natural Resources, respectively, during the first quarter of 2020. That month, the values of the Canadian producers and three other energy stocks PIF bought — Royal Dutch Shell plc, Total SA and BP plc — had all more than halved from their 52-week highs at the time the kingdom made its acquisitions. The illustration shows the prototypical Royal Dutch share price after the crash. It also shows the quick return the kingdom made from the package of acquisition of these five stocks as markets rebounded: more than US$182.6 million since the end of March.

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.

The Big Five

Canada's top conventional heavy oil producers in profile. This article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

The five largest conventional heavy oil fields are roughly synonymous with the names of towns and hamlets along Alberta’s border with Saskatchewan. In order, they are Provost, Suffield, Lloydminster, Wainwright and Hayter – no surprise there. However, when you list the five biggest conventional heavy producers a big surprise does surface. The companies are CNRL, Husky Energy, Cenovus, Baytex and…Northern Blizzard.

CNRL (121,000 barrels per day): The biggest Canadian oil company, Canadian Natural Resources is also Canada’s single biggest conventional heavy oil producer. Any one of its top 10 producing fields – two of them produce 14,000 barrels per day each; six produce 9,000 barrels per day each – would make most companies happy. As the company’s website explains, its “crude oil is produced from very distinct assets, using different recovery technologies that are tailored to fit each unique reservoir.” Like Husky, most of CNRL’s conventional heavy oil properties and production are centred on the border town of Lloydminster. The 10 largest of these properties, which individually produce from 4000 to 14,000 barrels per day, collectively contribute 80,000 daily barrels to Canadian Natural's production.

Those projects are being dwarfed, however, by the company's polymer flood operation at Pelican Lake/Britnell which, like the Cenovus property, began life as a cold production operation before converting to waterflood. The company expects production from this field to soon plateau at 80,000 barrels per day.

Husky: At 75,000 barrels per day, Husky Energy is just off the top of the conventional heavy oil hit parade. The pioneer in Canadian heavy oil production – the company has been involved in the area since the 1940s – nearly 80 percent of Husky’s heavy oil production uses primary “cold” production in the Lloydminster area, where the company has a land position of more than 8,000 square kilometres. The remaining 20 percent of Husky’s heavy oil production comes from thermal recovery projects – notably its Pikes Peak SAGD operation. Also located near Lloydminster, the Pikes Peak project is in Saskatchewan.

Cenovus (36,000 barrels per day): The middle company in the line-up is Cenovus. The company has two producing properties which between them account for all of the company’s heavy oil assets. One is at Suffield, which produces about 12,000 barrels per day through conventional methods. More interesting is the companies Pelican Lake property, which produces about 24,000 barrels per day using polymer flood.

Baytex Energy (29,000 barrels per day): Number four in the line-up is Baytex, which generates the bulk of its revenue from heavy oil. According to corporate publications, heavy oil accounts for more than 60% of production and more than 70% of oil-equivalent reserves.

In some ways, Baytex is the odd man out in its conventional heavy oil production. Like the other companies, it has important assets in the heavy oil belt along the Alberta/Saskatchewan border – Ardmore/Cold Lake and Lindbergh on the Alberta side; Carruthers, Tangleflags, and Celtic in Saskatchewan. According to company spokesman Brian Ector, “Development in these areas consists of mainly vertical and horizontal cold drilling, as well as waterflooding at Carruthers.”

However, Baytex also produces conventional heavy from a property in the Peace River Oil Sands. This is unusual. According to Ector, “we developed Seal (the Peace River property) through the use of multi-lateral horizontal wells, and production in the third quarter of last year averaged 10,100 barrels per day. In addition to cold primary development, this year we are embarking on our first commercial cyclic steam stimulation (CSS) project at Seal – a 10-well module scheduled for start-up late in the year.”

Production is approximately 11° API, and the oil flows through “mile-long multi-lateral horizontal wells” from the Bluesky formation at depths of 600-700 metres. Given where it’s located in Alberta, “technically, this is an oilsands lease,” he observes; “it therefore qualifies for the oilsands royalty regime,” which much more attractive to the producer, since it equalizes royalties across all wells.

Northern Blizzard (15,000 barrels per day): A private company, Northern Blizzard pierced the top ranks of heavy oil producers by acquiring assets belonging to Nexen Energy last summer. The price was $975 million; the properties have proved reserves of 39 million barrels of oil equivalent.

The company doesn’t use waterflood or other specialized techniques to produce. According to the company’s chairman, John Rooney, production consists entirely of “cold flow production” – mostly in the Lloydminster area, and mostly from Saskatchewan.

The Outlook
For much of last year, the differential between the prices of Canadian heavy oil and Edmonton par, Canada’s standard for light oil, was very narrow. Indeed, for a brief period last May heavy oil producers were actually able to sell their heavy oil for almost the same price as light oil. This was an extraordinary event – very profitable for producers –and it wasn’t likely to last. It didn’t. At the beginning of 2011, the average difference between light and heavy oil prices had expanded greatly, to about $23. This significantly changed the economic outlook for the sector.

A number of factors have contributed to the widening of the differential. Most importantly, Canadian heavy oil differentials respond to competition at a small number of specialized US refineries. Other heavy oil producers – think Venezuela – also compete in those markets, and competition has picked up in recent months.

Canadian competition has been hamstrung by transportation problems: expanding pipelines to American markets has been slow, and Enbridge’s problems in Michigan have resulted in pipeline shutdowns for maintenance. This is curtailing existing capacity. The rise of the Canadian dollar to parity with that of the US has also contributed to a change in outlook for the Canadian heavy oil producer. The bottom line is that these producers are unlikely to find their conventional heavy oil operations as rewarding in the first half as they were a year ago.

Low-Carbon Recovery

CO2 based theories of global warming need to be balanced by consideration of other ideas. This chart, which came off the Internet, illustrates an important opposing idea.

By Peter McKenzie-Brown

There are a number of people like Harold Nikipelo out there. The president of Edmonton-based Lifeview Oil and Gas Management Services, Nikipelo thinks he’s developed a better mousetrap – a new tool for heavy and conventional enhanced oil recovery. He joins such innovators as Sonic Technology Solutions Companies and N-Solv Corporation in his efforts to create practical, low-carbon recovery systems.

When you get him started, Nikipelo begins by enumerating the competing systems. Steam-assisted gravity drainage (SAGD) has been advancing for more than 20 years. More recent approaches include Petrobank’s toe-to-heel air injection (THAI) and its CAPRI system, which places a nickel-based catalyst bed in a horizontal wellbore. Other companies are experimenting with pulsed wave-front technology, solvent injection, electrical down-hole heating, steam flooding and the injection of solvent gases like carbon dioxide.

By no means is Lifeview alone in its efforts to find the holy grail of low-carbon recovery. One of the most important trends in bitumen recovery is the drive to produce the stuff with lower emission ratios. In the best of all possible worlds, this means better environmental credentials and lower cost of recovery. For environmental and economic reasons this is the wave of the future. Increasingly, production systems will have to respond to demands for reduced pollution – especially the emission of greenhouse gases (GHGs).

Nikipelo is one of a number of people combining and refining low-carbon recovery technologies in the interest of greener bitumen production. His company has developed a slick experimental production configuration that combines pulsing, thermal flooding, solvent gas injection and toe-to-heel injection. “For the thermal, we are injecting hot gas using a patent-pending three-stage process. The water or wet steam may be alone or combined with a catalyst. Our thermal unit is also generating electricity for our down-hole heating system, which pre-heats the hot gases to maximize potential. All emissions are being sent down-hole. The process greatly reduces both emissions and water usage.” His low-carbon alternative to SAGD begins with the idea of mitigating environmental problems but may also be a lower-cost solution for many producers.

“Our process is focused on using less water than SAGD. When we reduce water usage, we reduce the demand for fuel to generate steam, thus reducing fuel consummation. Our process is focused on zero emissions to atmosphere. All emissions are used in the process and are injected into the bitumen.” As Nikipelo tells the story, when he took his original concept to the Alberta Research Council, Dr. Alex Turta (team leader for enhanced oil recovery) said “You’ve got something important here….it may change the way we look at heavy oil recovery and possibly enhanced conventional recovery as well.” Turta in effect invented the THAI system, and the Lifeview approach is based on a number of his ideas.

According to Nikipelo, Lifeview’s tool injects steam and a scrubbing gas intermittently into the reservoir. This eliminates the requirement for continuous injection. This brings greater buoyancy into the reservoir, Nikipelo says. “It enables the steam to go into the proper part of the reservoir, creating a mobile oil front. At the end of the day, to justify the cost of a small SAGD operation you need a tool that can produce a small, cheap and portable tool – something small and inexpensive enough that can prevent smaller oilsands reservoirs from becoming stranded.”

Whether or not Nikipelo’s idea is an answer to the industry’s low-carbon prayer, it exemplifies a grail that an almost Arthurian roundtable of entrepreneurs and companies are seeking: ways to produce heavy oil and bitumen with lower carbon output.

In the field the smaller, leading edge companies include MEG Energy (Christina Lake in the Athabasca sands), OSUM Oil Sands (Cold Lake oilsands and Grosmont bitumen carbonates at Saleski) and Laricina Energy (also at Saleski and in the Athabasca at Germain). Private companies like Drakkar and Earth Energy Resources are, respectively, testing bitumen carbonate production in Peace country and oilsands in Utah. Also, of course, big, established players like Imperial, Shell, Husky and Cenovus Energy are making good progress in lowering per-unit emissions.

As these players successfully develop low-carbon production technologies, their efforts will simultaneously contribute to both the industry’s image and to its bottom line.

The Image Disaster
Part of the reason this development has become so important is that the oilsands business is now the ultimate whipping boy for petroleum industry critics. This year, things have reached what one can only hope is the bottom of a trough.

True, the year began on a high note. At their ballyhooed meeting in Ottawa, Prime Minister Harper and US president Barack Obama agreed to begin a “clean energy dialogue.” The focus of the talks would be “a cleaner, more secure energy future for both nations”, and it would involve immediate, big investments in energy research and development.

The two countries would collaborate on energy research related to advanced biofuels, clean engines, and energy efficiency, according to the Prime Minister’s website. “To address the energy and environmental challenges that we face together, the two nations agreed to expand collaboration in these and other key areas of energy science and technology.” Suddenly, it seemed, the green agenda had caught on in Ottawa.

Then things went awry, beginning with a devastating critique of the oilsands business in National Geographic. In the autumn, environmental activists staged highly publicized demonstrations at oilsands facilities.

As activist Jordan Poppenk described one such incident, “Activists from Greenpeace successfully broke into a tar sands operation in Alberta...and held up production for hours as they chained themselves to equipment and unveiled a banner reading “Tar Sands: Climate Crime” on a major access road....”

“American, Canadian and French activists broke into Shell Canada’s Albian Muskeg River oilsands mine north of Fort McMurray,” he happily continued, “and successfully halted production at the mine for six hours. The protest lasted for 30 hours and ended with a negotiated settlement between Greenpeace and Shell with the activists leaving peacefully and Shell agreeing not to press charges. The action was timed to coincide with the release of a report by Greenpeace condemning the tar sands as well as a visit by Prime Minister Stephen Harper to U.S. President Barrack Obama. The protest leaked into coverage of the U.S./Canada summit on major U.S. networks.”

At about the same time, environmental and aboriginal groups in the United States filed a federal suit against Enbridge’s proposed Alberta Clipper, on the grounds that recent approval for the bitumen pipeline goes against the public interest.

Smoke and Mirrors
Even such a knowledgeable and thoughtful observer as Jeff Rubin (formerly CIBC’s chief economist) claimed that oilsands facilities “leave an archipelago of tailings ponds – toxic by-products of oil-sand production and death-traps for migrating wildlife.”

Rubin’s tome on deglobalization – Why your world is about to get a whole lot smaller – delivers at least a few shock-jock ideas about the oilsands. “The production of a single barrel of oil pollutes 250 gallons of fresh water,” he said, “and emits over 220 (pounds) of carbon dioxide into the atmosphere.” To put the latter number in context, a barrel of bitumen weighs about 370 pounds.

Rubin does not cite the source of these figures, but they illustrate a second reason why low-carbon recovery has become so vital. The raw cost of eliminating carbon dioxide emissions from bitumen and heavy oil production is high and growing, especially because so much of those emissions are associated with increasingly expensive fuel consumption.

You can slice and dice Rubin’s numbers in many ways, especially since they make no reference to the industry’s mitigation efforts. For example, you might argue that at some point in time just about every volume of water on earth has been polluted by something or other. Natural systems have been purifying water since rain began falling in the pre-Cambrian. At oilsands plants the practice of recycling contaminated water, the use of deep-well injection and industrial evaporation are just some of the solutions that apply.

Carbon dioxide emissions, of course, are a different kind of cat. Once produced, they are devilishly costly to remove from industrial processes and inject into subterranean storage basins. Shell’s Quest carbon capture and storage project, for example, will sequester carbon dioxide from the upgrader at the company’s Scotford complex near Edmonton – an upgrader which receives bitumen from Shell’s Albian plant.

The Quest project will receive $865 million in grants from the governments of Alberta and Canada. In announcing the federal government’s $120 million contribution to the Shell project, Natural Resources Minister Lisa Raitt called carbon capture and storage “the most viable emission-reducing technology for fossil fuels.” She added, “These projects will reduce greenhouse gas emissions while creating high-quality jobs for Canadians now and benefitting our environment for future generations.”

True for mineable oilsands and bitumen upgrading processes, but the argument falls short when in situ production comes into play. Here, players like Lifeview’s Harold Nikipelo offer better, more viable solutions. Let’s begin with a look at the numbers. Under ideal conditions, Shell’s Quest project will have a lifetime cost of about $1.5 billion, including both capital costs and operating expenses. It will sequester about a million tonnes of carbon dioxide per year over its 40-year life. In nominal terms, and assuming excellent operating results, that means the cost of sequestration will be about $37.50 per tonne.

The Benchmark
Assuming these numbers are largely correct, an interesting number falls out of some simple math. If producing a barrel of oil from bitumen releases one tenth of a tonne of CO2 (Rubin’s number), then the nominal cost of eliminating greenhouse gases through carbon capture and storage would be about $3.75 per barrel. If you believe that regulators are going to get serious about eliminating emissions from bitumen production, then technologies that can reduce emissions for less than that $3.75 benchmark may be bargains.

The problem is in accountability. You can count the cost of sequestering carbon dioxide. How do you account for greenhouse gas emissions you don’t produce? This is a question environmental policy-makers can answer. The good news for industry is that as an economic question it can be good for the bottom line. For a lot less than $3.75 per barrel, clever engineers can find ways to forego the production of equivalent weights of greenhouse gases.

“Presently SAGD operations are running two to three barrels of steam to one barrel of oil. Our goal is to reduce that number (by using a different production system),” Nikipelo reiterates. “When we reduce the steam-oil ratio, we reduce both capital and operating costs for water treatment, steam generation and storage facilities. There can be huge savings.”

To calculate per barrel savings you need to plug such other factors as calendar day productivity, ultimate recovery rates and project life into your spreadsheet. Also, the system you employ must be robust (minimal downtime) and affordable. In a political climate deeply concerned about greenhouse gas emissions and water pollution, the oilsands industry’s best new mousetraps are going to trap GHGs in situ, so the industry later has less to capture and sequester.