Reaching $1,000,000,000

Shell Canada marks a major milestone with its aboriginal oilsands contractors

This article appears in the October issue of Oilsands Review 

By Peter McKenzie Brown

As the CEO of no fewer than 15 companies, Phil Peddie is a pretty busy guy.He is the chief executive officer of the Fort McKay First Nation, and it's a hefty job.

Seven of the companies he leads are wholly owned by the Fort McKay First Nation. The rest are joint ventures – 51% owned by the band and the balance owned by non-aboriginal business partners. His companies specialize in doing oilsands-related work, and they couldn’t possibly be closer to their customers. Oilsands mining companies encircle the aboriginal community.

Fort McKay is smack in the middle of the cluster of mining projects now producing or under development – those operated by CNRL, Imperial (Kearl), Shell, Suncor, Syncrude, and Total (Joslyn). The community’s location and business acumen are fascinating in themselves, but to put their success in perspective it is worth noting that over the last six years, the Athabasca Oil Sands Project (AOSP) contracted more than $1 billion in services and supplies with aboriginal companies– many of them at Fort McKay. In 2008 alone, more than C$210 million local spending went towards purchasing supplies and services from such aboriginal groups as the Athabasca Chipewyan First Nation.

To put that number in perspective, Syncrude – which began operations in 1978 – couldn’t boast $1 billion of total work with aboriginal contractors until a quarter-century after start-up.

As the crow flies, the closest plant is part of Shell-operated AOSP. Owned by Shell, Chevron and Marathon, the project includes the Muskeg River and Jackpine mines and the Scotford upgrader, near Edmonton. According to the Shell consortium, more than 70 aboriginal businesses participated in the $1 billion spend. Collectively, they provided a wide range of services and products. These include facilities management, general maintenance works, technical expertise, earthmoving, health and safety services, bussing, camp construction, catering and waste management, and many others.

In terms of social and economic renewal, the rise of aboriginal business in the oilsands areas has come at a critical time. One reason is that there are chronic shortages of labour in the oilsands areas, and they are unlikely to go away. Aboriginal communities can provide reliable local labour. The oilsands industry has become Canada’s largest employer of aboriginals by far.

The other reason is that these communities have traditionally been important sources of untapped entrepreneurial talent. To help develop this area, for a quarter of a century the industry has been helping develop aboriginal entrepreneurs to meet its business needs.

Local Labour

According to Shell vice president John Rhind, this is more than a win-win. “Labour shortages are likely to be with us for a long time, and aboriginals have traditionally been an under-represented demographic for the industry. They can bring a lot of value to the oilsands producers. This not only applies to the Fort McMurray area, but to all producers throughout northeastern Alberta. There’s no question SAGD operators can benefit as well.”

According to Rhind, the surge in First Nations businesses was partly driven by the region’s big producers. “Some years ago the oilsands companies around Fort McMurray made a strong commitment to engage with the communities in the area. These included aboriginal communities – Métis and First Nations. But it included other communities as well – for example, non-aboriginals who were not recent hires, but had lived in the area for many years."

These stakeholders in the Fort McMurray area – Rhind calls them "citizens of the environment” – have “a lot to gain from this, and we thought it was important to make this commitment….It isn’t about the dollars. It’s about members of the community participating in our business.”

Until he was appointed to his present position last March, Rhind was general manager of operations for Albian Sands, the joint venture company that operates an oilsands project for the Shell consortium. I asked him to tell me about the project’s aboriginal partnerships. “We’re about developing the ability of aboriginal people in Fort McKay so that when the oilsands is done, decades or centuries in the future, we will be leaving a sustainable culture and economy behind.”

Shell and the other operators in that area have done this in a number of ways, Rhind says. For one, “we look for aboriginals to become part of our workforce.”

He says Shell’s experience is that there is “no difference at all between a First Nations employee and one from any other background….The key is that first that you have to train your employees. Be clear about what expectations the company has of them and give constructive feedback. Second, if there is any systemic racism you have to be relentless in getting it out of the system. That enables people to contribute at the level at which they’re capable, but it also removes any barriers that might stand in the way of their becoming successful in working in an oilsands business. Once you have a cohort of aboriginal workers in the company which includes people in management, then you have a sustainable system that welcomes new aboriginal employees.”

Part of that welcome arrives through Shell’s aboriginal employee network, an internal human resources system developed to support First Nations, Métis and other aboriginal employees. According to a Shell statement, it “draws together aboriginal and non-aboriginal employees and provides a diverse range of learning and social opportunities for employees.”

Local Business

According to the Athabasca Tribal Council, which represents the interests of five Treaty Eight First Nations in northeastern Alberta, there are approximately 5,000 Cree and Dene people in the region. Besides employing aboriginal workers from these communities directly, Rhind notes that his company and others in the area have “appointed people to work with aboriginal individuals to help them develop successful businesses. We want to work with local aboriginal businesses successfully and in a mutually beneficial way.”

That’s the view through the corporate window. Multiple-CEO Phil Peddie picks up the story. He operates in the world of aboriginal entrepreneurialism.

Peddie oversees a large group of companies which collectively employ nearly 1000 men and women. A Shell news release quoted him as saying that “working with Shell and the Athabasca Oil Sands Project over a number of years has enabled the Fort McKay group of companies, joint ventures and entrepreneurs to grow, and has brought significant opportunity to develop skills, establish businesses and further our community.” This reporter phoned to find out more.

The Fort McKay First Nation has seven wholly-owned companies which, collectively, provide a large number of services mostly targeted at oilsands-sector project maintenance and development. These include, for example, light earthmoving, fuel distribution, fleet maintenance and a variety of environmental services: According to the band’s business website, “Our land reclamation services encompass the entire process from start to finish.”

The Fort McKay Group also has a number of joint venture companies in which the aboriginal community forms partnerships with established non-native companies to provide specialized services. For example, Fort McKay Landing Services, which specializes in camp construction, is a partnership with modular facilities giant ATCO Structures and Logistics.

From the First Nation’s point of view, there are many reasons to like these joint ventures. For one, the community has control of a business that is adequately financed. In addition, the venture transfers managerial and technical skills to the local community and contributes to local employment. Also, of course, for their businesses the status Indian shareholders receive their earnings tax-free.

According to Peddie, each of these companies is operated by a management committee with equal representation from both sides. “It brings together the technical and management expertise of our partners plus the labour we can supply. Our unwritten goal for each of these enterprises is 30% aboriginal content. In every business we own, our goal is 30%.” Achieving that percentage of aboriginal employees isn’t easy. “It’s difficult to achieve because the unemployment rate in Fort McKay is quite low. A lot of people are employed by Shell, Syncrude, Suncor, and so on, so for some of our companies we are below that mark and for others we are above it.”

Oilsands employment has transformed the local economy, he says. “Only 30 years ago, the people of this community were primarily trappers. A European boycott of Canadian furs destroyed the trade,” and very tough times followed.

Now a hamlet of some 700 souls, Fort McKay is mainly composed of status Indians from the Fort McKay First Nation. The social fabric also includes a Métis community of perhaps 200, non-treaty aboriginals, and small numbers of individuals of other origin. The Fort McKay Group of Companies can’t strictly draw from the local community to reach its “aboriginal content” goals because most working residents hold fulltime jobs with Syncrude, Shell, Suncor or another big local producer.

According to Peddie, 13% of local people work for the Treaty Eight band’s wholly-owned companies. A similar number work for its JV partnerships. “So to try to reach our content quotas, we employ aboriginal people from all over the region.”

Being Canadian

Like representatives of other companies in the Fort McMurray area, John Rhind says that “working with aboriginal contractors is one way Shell benefits the communities where we operate. We announced our billion-dollar milestone to thank the businesses and partners we worked with during those six years.”

Shell’s achievement is impressive, and certainly something to brag about. However, it is worth remembering that Syncrude began developing business partnerships with aboriginal communities in the 1970s: During the construction of the plant, chairman and CEO Frank Spragins visited aboriginal communities, and let contracts before the plant produced its first barrel of oil. This policy was spurred by Spragins’ successors, Brent Scott and Eric Newell. The company’s ground-breaking efforts were both visionary and transformational.

As the company’s initiatives were coming to fruition, Newell addressed the triumph of Syncrude’s pioneering efforts in a speech given15 years ago. “We’ve brought two decisively different belief systems…those being business and spiritual… together in understanding and cooperation,” he said. “We’ve drawn strength from each other to leap the hurdles and head down the road side by side – on a journey not only to secure Canada’s energy future, but also to explore what it really means to be Canadian.”

One outcome of Syncrude’s initiatives is that today, Phil Peddie is a pretty busy guy.

Caught in the Net

With the growth of social networks and electronic trading systems, it's easier now than ever before to trip over insider trading prohibitions

This article appears in the August issue of Oilweek

By Peter McKenzie-Brown
If you don’t get caught, breaking the law can pay quite nicely – especially the offense of insider trading. Consider the case of William Bint. As the indexes of publicly traded oil companies were stretching toward their May 2008 peaks, he bought 38,000 shares of Canadian Quantum Energy Corporation at just under $.30 per share. At the close of trading that Friday afternoon – just after he’d bought his shares – Quantum issued a press release disclosing the acquisition of a prospective natural gas property in Québec.

When the markets opened the following Monday, Bint was richly rewarded. He liquidated his $11,110 investment from the previous Friday, netting $156,443 through a few simple trades. From beginning to end, less than a week had elapsed.

Unfortunately for his reputation and his net worth, the Alberta Securities Commission (ASC) investigated and suggested that Bint had benefitted from illegal insider trading. He had, after all, helped negotiate the deal that drove Quantum’s stock price into the stratosphere. After a hearing by an ASC tribunal, Bint agreed to pay an administrative penalty of $234,000 and $5,000 to cover investigation costs. In addition, the commission restricted his trading privileges for two years.

Now retired, Bint is one of eight Albertans listed in the Canadian Securities Administrators’ list of found to have participated in illegal insider trading last year. Six of those prosecuted traded in energy shares. Looking outside the province, last year three Quebeckers were found to have committed insider trading, and so were two Ontarians. No one else in Canada was found to be at fault. Put another way, a province with 10% of Canada’s population was responsible for 60% of the country’s infractions.

Really?
Is this tabulation credible? For example, did absolutely no one in British Columbia trade a mining stock without inside information? That seems unlikely, and it lends support to the idea that the ASC is a very effective commission.

But now consider the case from the other point of view: Forty per cent of the world’s 995 energy companies are headquartered in Calgary, and those companies represent about 30% of Canadian stocks by market value. In all of Canada, are there only six people per year, say, who use illegal insider trading to profit from this dynamic sector? Really?

To find out, I talked to Marc Arseneault – the ASC’s enforcer. As the manager for assessment, market surveillance and investigation, he is responsible for enforcing the rules that apply to this form of white-collar crime. “This is a very difficult problem to investigate” he says. The commission has an insider trading team of five, plus access to legal staff when litigation is required.

"Under our act we can prosecute these cases in provincial court or we can go before an administrative tribunal. Those are the two avenues available to us. We don’t take the case to court unless our evidence is beyond all reasonable doubt. When our evidence is simply a matter of balance of probabilities, we use an administrative tribunal. Those are important distinctions." In either case, the matter is likely to become a matter of public record. For example, tribunal decisions, which summarize evidence and agreed sanctions, are posted on the organization’s website.

Avoiding that kind of public humiliation is a big motivator for those who are caught, and the commission does offer an informal third alternative. According to Arseneault, “Sometimes we have settlement discussions that make the need for an administrative tribunal unnecessary. If we can get someone to give us an admission and agree to sanctions that would be within the proper realm, that frees up resources for us and it works for everyone. If someone says ‘Yeah, I did it’ and is willing to make amends, then we are willing to have that conversation” outside the tribunal process.

“We aren’t here to penalize people,” he says. “Criminal law penalizes. Our goal is to deter people from illegal trading. We aren’t here to punish them, but to discourage them.”

Pace of Change
Insider trading in general is not illegal. If you are a designated insider – a director or executive of a company, for example – you can trade in company shares. You just can’t do it on the basis of privileged information, and you have to report your trades to the ASC within ten days.

Illegal insider trading is different, and it’s is a surprisingly complex problem. It has two elements: first, you have access to undisclosed material information; second, you trade on that information before it is publically released. And critically, you don’t have to be an insider to be guilty of insider trading. You don’t have to be a director or officer of the company to be at fault. In fact, the people caught are rarely corporate executives or directors. They are actually more likely to be outsiders than insiders – for example, employees familiar with a deal or a new development at law firms, investment banks, geological consulting firms, drilling service companies and even printers.

Illegal insider trading and the related infraction of “tipping” are increasingly difficult to control – and part of the problem is partly that they are poorly understood. The key is that if you have access to undisclosed material information you automatically become an insider by virtue of having a “special relationship” with the company.

According to Arseneault “I can’t tip someone if I have insider information. If I (break the rules and) provide someone with that information, I put them in the category of having a special relationship with the company, and their trading would be considered illegal insider trading.” Thus, even if the information you have is fifth-hand and you’ve never even heard of the company in question before, trading on the basis of undisclosed material information makes you guilty of illegal insider trading. If you pass this information on to another person, you’ve committed the offence of “tipping,” which is also subject to fines, sanctions and, in extreme cases, jail time.

The rules are strict. However “because of the nature of the oil and gas industry in Calgary there is a lot of opportunity to trade on insider information,” acknowledges Arseneault. “That information should be contained. Once it gets out of the container, troubles begin” – and that trouble is increasingly difficult to reign in. There are many new platforms on which people can trade, and even micro-cap companies can be listed on a number of exchanges. There is computer trading, there are social networks and there are online sites that promote stocks. Also it’s increasingly easy to put smaller trades into different accounts – your own, but perhaps also those of a spouse or a trusted accomplice – to ward off suspicion.

“The system is evolving very quickly,” Arseneault concedes. “We have to respond to that, so we’re pushing harder.” As evidence of the pace of change, the legislation governing securities regulation has changed several times since receiving royal assent a decade ago. Changes through order-in-council have been even more frequent.

Penalties
Is enforcement more stringent in Alberta or are acts of commission more common? It’s possible that the ASC had more successful prosecutions than Canada’s other securities commissions in recent years because the commission is more vigilant and aggressive in combatting insider trading. It’s also possible that there are more prosecutions in the province because there is a bigger pool of offences. The answer to this conundrum is unknowable, although Gary Leach – the executive director of SEPAC – thinks senior people in the patch have powerful financial reasons not to transgress. “The oil industry is a close-knit community, and you have to have a sterling reputation to succeed. You want to go back to capital markets year after year. One offense will make it a lot harder to do that.” If caught, an offense could also get you fired or expelled from the board.

The ASC’s investigation and enforcement tools seem relatively limited, making the challenge a big one. “We work with other agencies and we have a network of contacts that help us stay informed,” Arseneault explains. “We have to stay on top of the news and the markets. We carry out market surveillance, including real-time computer surveys. We analyse trading in individual stocks, we analyse trading by individuals, we talk to people and we summon documents. This enables us to develop a case.”

Most of the ASC’s cases are generated through market surveillance conducted by the Investment Industry Regulatory Organization of Canada (IIROC) and through post-trade investigations conducted by commission staff. Arseneault is reluctant to provide details about his investigations, but a couple of red flags are obvious. If people have traded in large numbers just before a deal is announced market, share volume spikes. This sends up a flag that IIROC can easily detect. The discovery that an individual under investigation recently opened new accounts for trading is a different kind of flag – one that would greatly interest commission investigators.

Most illegal insider trading is treated under administrative law, and therefore isn’t criminal – but don’t let that lull you into complacency. In 2004 Canada created the first specific Criminal Code offences of improper insider trading and tipping. The legislation also made it a crime to threaten or retaliate against employees who blow the whistle. The legislation applies to the “most egregious cases” of illegal insider trading.

The penalties? Conviction carries up to ten years in the slammer for each offence. Tipping carries a maximum five-year term. They aren’t worth the risk.

Down the Drain: A Solution to Nepal’s Power Crisis

Photo: a vortex before the turbine is connected

A frequent contributor to this blog, the author proposes a compelling solution to power problems in a small and mountainous, beautiful but poor Himalayan Kingdom with streams and rivers in abundance. The solution isn't what you might think....

By David DuByne
Nepal faces a load-shedding crisis: each year at certain times, electrical authorities cut off electric current on certain lines when power demand becomes greater than supply. As Ratna Sansar Shrestha explains in Hydro Nepal magazine, large-scale hydro projects can’t keep up with 10.7% annual increases in power demand. This is because of Nepal Electricity Authority’s (NEA) delayed completion of projects, system mismatches in the seasonal variation of water and inadequacies in much of this mountainous country’s infrastructure. As a result, severe load-shedding will continue at least into the dry season of 2017.

Economic losses from these planned interruptions include liquid fuel shortages as households and businesses burn fuel in generators that was destined for the transportation sector.

Solutions
These are the problems. Where are the solutions? Perhaps the best way to answer the question is to pose another one: If large-scale doesn’t work, what about small-scale?”

I have worked with renewable energy concepts over the last several years, and I think Gravitational Vortex Power (GVP) is a solution that could work for Nepal. Let me explain how it works.

You will notice when you pull the plug from a sink that when the water gets low it starts to spin into the drain hole. It actually makes a mini-whirlpool as the last of the water drains out. Scale that round hole up from something that is 12 cm in diameter to something with a 5-meter diameter and you create a larger amount of spinning water with a larger amount of kinetic energy. Gravity does all the work as water flows. Now add curved blades to dig into the spinning water, attach an electrical power generator and you have GVP. The rotational movement of water in the shallow circular basin creates a stable continuous gravitational vortex, 24 hours per day, seven days a week.

Viktor Schauberger from Austria was one of the first to make use of vortex dynamics from 1929-1936, and his has work influenced others. Zotloterer’s current design needs a 0.8 meter water drop and two cubic meters per second of water flow. That doesn’t sound like a lot of water to produce power, but these GVP plants produce 57,000 kWh per year. For comparison, per capita usage of electricity in Nepal was 78.5 kWh per year in 2010.

How can GVP be a Solution?
Kathmandu faces its own set of challenges, while in the countryside another set of variables limits the availability and supply of power. So how does using small hydro affect change in the national power grid? It boils down to economics and scale of raw material input for targeted output.

Let’s look a single Large Scale Project first, the Upper Tamakoshi Hydroelectric Project. The project, which will have a maximum output of 456 MW per day during the monsoon, will cost an estimated US$441 million, excluding interest. Maximum output will drop by 60% or more during the dry season.

Additional costs will include 132 kV high voltage transmission lines for future grid extension: between $8000–10,000 per kilometre, rising to $22,000 in difficult terrain. Then there is the cost of sub-station construction and additional road building at $20,000 per km. So assuming that everything is on budget (unlikely, based on past performance), let’s round off to $500 million. And one more thing: most of the new lines will by-pass rural communities in Nepal as they wend their way to India to serve Power Purchase Agreements (PPA’s).

By comparison, small GVP plants can use local materials, can cost as little as $10,000 and do not need to dam the water to operate. The GVP plant merely uses the water for a few seconds as it flows on its way down stream. Just the environmental advantages to its usage warrant further investigation as a solution. GVP is designed to be installed in remote areas that would never see grid expansion into local villages and is designed to electrify a small community of up to 200 homes per plant under Nepali consumption patterns.

If we use the same figure of $500 million for one large project that provides diminishing electrical output as rains decrease from October to May each year, you could build 50,000 GVP plants. These plants generating 57 MWh per year would equal 2,850,000MWh or 2,850 GWh annually fed directly to the local communities in remote locations that need it most. Here is where the shocking part comes in: the forecast annual energy output from the Upper Tamakoshi Project is 2,281 GWh. You generate more power from GVP, save on the amount of construction materials and do not need to dam an entire river!

With Nepal’s special set of circumstances we must think in inverse terms. The usual train of thought is to electrify from major population centers out to the countryside, but in Nepal’s case it needs to be the opposite to reduce load-shedding. This country needs to electrify from the countryside back into the cities, as most cottage industries are located outside large urban areas. The economy is stagnating from lack of power in these areas. If rural communities can generate their own power locally off the main grid, then excess power not consumed in smaller outlying districts can be diverted back into Kathmandu or other cities languishing in the dark.

Another benefit beyond revitalization of the rural economy would be that materials used for local construction will be bought locally and those living close to the GVP plants can maintain and repair the generators themselves, not relying on German engineers being flown in to Nepal to work on a damaged large-scale generator. Under this system electrical lines are local, minimizing their cost. The can be bought from local vendors and strung up on already existing electrical poles. This means revenue circulates throughout a local area and the community sees a direct economic benefit.

These ideas sprang to mind while I was walking home and saw a sign that proudly stated “load-shedding solutions.” The solutions in this little store included batteries, inverters and so on.

No way. GVP is the solution to Nepal’s load-shedding crisis. My hope is that a Rotary Club or some other humanitarian organization will work with us to help lead the way.

David DuByne is Advisor and Director of Foreign Co-operation with Energy Research Nepal. He can be contacted at David.DuByne@ERN.org.np

Heavy Oil for Tomorrow

An illustration of the SAGD process; source: Value Creation Group of Companies.

Conventional production benefits from technology innovation; this article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown

The notion that since conventional oil production has peaked and the world will soon face a crisis of inadequate supply has a lot of true believers, but they seem to be in short supply in the heavy oil sector.

According to Cenovus vice president Dave Goldie, “Technology is opening up new frontiers for oil production – not just in heavy oil and oilsands, but also in light oil. Given everyone’s ingenuity, we are finding ways to access more oil.” The numbers seem to back him up: there are major heavy oil deposits on every continent, and global heavy oil and oilsands deposits embrace more than five trillion barrels in situ – at least potentially, enough supply to meet market demand for a long time yet to come.

At least two technologies developed in Canada that have become familiar in the oilsands sector are being deployed in conventional heavy oil to expand production and increase recovery rates.

Steam Assisted Gravity Drainage
The late Dr. Roger Butler’s steam assisted gravity drainage (SAGD) originated as a procedure for producing bitumen from the oilsands, and the technology has a huge impact on oilsands production. Recently, it has begun to change production economics at some conventional heavy oil reservoirs – notably Baytex Corp.’s Kerrobert project, Husky’s Pikes Peak operation and Senlac in Saskatchewan, owned by Southern Pacific Resources.

Baytex purchased its project from True Energy (now Bellatrix Exploration) in 2009. At present, Baytex Kerrobert produces 2,000 barrels per day, and those volumes are increasing. “We placed a new SAGD well pair on production late in the third quarter of 2010,” says Baytex spokesman Brian Ector. “Subsequent to the end of the quarter, this well pair produced at a 30-day average rate of approximately 1,000 barrels per day. We believe that, through the remaining life of this project, we can drill 11 additional SAGD well pairs. For 2011, we will likely drill two new pairs on the property.”

For Southern Pacific, the Senlac property in many ways was a company maker. The company acquired it from Cenovus for $90 million, and it enabled the company to move to the Toronto Stock Exchange by providing cash flow. “As soon as we had that we were a going concern,” according to company president Byron Lutes. “It enabled us to advance (from Venture) to the TSX. That means more due diligence, but a lot more investors now will put their money into the company.”

Since acquiring the property last spring, Southern Pacific has begun to face the reality of having to develop the property. The company has done some infill drilling, and at the end of last year drilled a SAGD well pair. The previous well pair produced about 1,300 to 1,500 barrels per day, according to Lutes. “From a rate perspective, (the new pair) won’t do better than our other wells (even though they include 650-metre horizontal wellbores) because we are not going to put on bigger pumps. However, we expect better recovery over the life of the well than if the well pairs had a smaller horizontal section.”

Southern Pacific is planning to spend about $10 million a year on the project. That will tie in one SAGD pair a year and will keep field production in the 4,000-5,000-barrel per day range, although he is optimistic that production will occasionally oscillate above 5000 barrels per day. “We estimate that this project will continue to produce at those levels for 10 to 15 years” he adds, and he is extremely optimistic about field economics. “The oil quality is better (12° API) than Athabasca (8° to 9° API), so the steam/oil ratios are typically lower and it takes less diluent to bring your oil up to spec. We will get a $39 per barrel netback on $77 per barrel WTI.”

Netback notwithstanding, Lutes pauses to brag about a recent field acquisition. “We were planning to replace a boiler this year, and the guys found it on Kijiji of all places. It was the exact boiler we needed, unused. It needed a few parts, but we bought it for about $90,000. When you factor in installation we saved ourselves maybe $700,000.”

Toe to Heel Air Injection
If Southern Pacific is a junior producer on the rise, PetroBank is one with global growth aspirations. The company’s THAI production technology involves using a vertical injector to feed air into a horizontal producer to keep underground ignition going. “There’s nothing magic about it,” according to company spokesman David McLellan, although the system has the potential to transform production from heavy oil deposits around the world.

PetroBank is developing its first commercial application of this process in Kerrobert, Saskatchewan. “We’ve had two wells on production there since November 2009, and this year we’re expanding to a 12-well total” says McClellan. “We’ve done the reservoir simulations and modelling and we feel as though each well will be capable of producing about 600 barrels per day. When you go through the pre-ignition cycle you’re trying to establish communication between the injector well and the producing wells. We think it will take 12 to 15 months to get up to full production.”

If the company’s calculations are right, when the project is up and running Kerrobert will be a 7,200 barrel per day facility. “What is really interesting about this project is that existing cold flow production is in the single-digit range – six, seven, maybe ten barrels per day per well.” With that kind of production the recovery factor for the pools would be only 4-7%. On the other hand, “with the THAI system we can recover between 70 to 80% (of oil in place). Five years ago, this was just theoretic. Today we have corroborated that we can do all this.”

McClellan says the Kerrobert project will produce an additional 7,200 barrels per day for capital cost of only $75 million. “That’s capex of only $10,400 per flowing barrel. Even if we got only half the production that we anticipate from those wells that would be a pretty good investment.”

Of particular interest to the company and its licensees is that the THAI process actually upgrades the oil underground, creating an oil with lower viscosity which therefore needs less diluent when it’s pumped into the pipeline. “It’s the heat that does this,” according to McClellan. The process takes 11° API heavy oil that underground and alters it to about 16°. “It is the heat that does this. The system cokes the oil underground, burning the heaviest asphaltines in the reservoir as fuel. The lighter stuff that’s mobilized out in front of ignition drains out into our production wells.”

He adds, “We have every conviction that this is going to be a game changer in heavy oil recovery. Once we have completely proven this technology, then the world will start to change.” Polymer Flooding

Polymer Flooding
Southern Pacific and PetroBank are medium-sized companies. Cenovus and Canadian Natural Resources aren’t. Respectively Canada’s third-largest and largest conventional heavy oil producers, each company has assets at Pelican Lake which exemplify how large producing properties are being used as laboratories. Experimentation in heavy oil production in this area receives important incentives from the province, which has designated it an oilsands production area. This means for royalty purposes the company equalizes production across all wells.

Cenovus initially began producing conventional heavy at Pelican Lake in 1997 from a series of horizontal wells; the field now produces about 24,000 barrels per day. According to Dave Goldie, who has executive responsibility for his company’s Pelican Lake assets, “The main method we’re using right now is polymer flood” – a technique partially pioneered by the Alberta Research Council, and which found one of his first commercial applications at Pelican Lake.

“The injection of polymers creates a more powerful piston effect, and it enables us to better push the oil out of the reservoir,” says Goldie. “Polymer is a pretty benign petrochemical – one of its uses is for disposable baby diapers. It turns water into a thick, viscous fluid which is great for heavy oil production. Over half our wells here at Pelican Lake are now based on polymer flood. We’ve applied this to over 170 wells.” Eventually, the entire field will use polymer flood.

It takes a while for the field to respond to the polymer. “After a period of time you see an increase in production which is associated with this extra push from the polymer flood.” Originally developed as a cold waterflood using horizontal wells, Pelican Lake’s original infrastructure included wells 200 metres apart. With that kind of spacing “it takes up to two years before you see a response. Now we’re infilling those patterns, and that’s increasing production rates. We’re constantly looking at new formulations of the polymer, adapting the well spacings to increase production. With cold waterflood we can get maybe a 12% recovery factor, but with polymer flooding we can more than double that. We keep on experimenting and it’s getting better.”

While polymer flood is the workhorse at the Pelican Lake project, Cenovus is testing a lot of other ideas on the property. According to field superintendent Gary Tebb, “Greater Pelican assets include the Pelican Lake project, which produces from the Wabiskaw. We’re also doing collaborative work with our Ventures team in the Grand Rapids (formation). We have an experimental project to access what we call the immobile Wabiskaw – an area where the oil is extremely viscous. We are also doing some work in the Grosmont zone, which is bitumen carbonate, and one part of the property we are experimenting with polymers plus surf it's actants.”

Dave Goldie clarifies that the Grand Rapids project will involve “in situ combustion using natural gas from a gas cap over the field in another formation. We have a patent pending on that particular scheme,” he adds. “Other companies are doing similar things; there’s a lot of experimentation going on. In these reservoirs different things work in different places.”

Canadian Natural Resources has a similar project at Pelican Lake/Britnell, where the company estimates original oil in place at 4.1 billion barrels. Like the Cenovus project, CNRL began with primary production, shifted to waterflood and, in 2005, to polymer flood. Now producing 38,000 barrels per day, the company expects project production to peak in 2015. It should plateau at more than 80,000 barrels per day – an amount equal to today’s total production from the company’s 10 largest conventional heavy oil projects along the Alberta/Saskatchewan border.

The Next Step

An image from Qingcheng mountain, near Chengdu, in Western China

One of the most under-appreciated alternatives to crude oil is biofuel from lowly algae. Algal oil is more than a good alternative. It’s good business.

By David DuByne
Media organizations continue to feed us down-turning economic news. That’s fine for now, but why isn’t anyone talking about the problems we will encounter as the global economy starts to strengthen and recover?

Economists and energy traders are increasingly coming to the same conclusion: When the economy begins to get back on its feet again, there will be an immediate ceiling of resistance due to high energy prices which will once again crash the markets. This recurring cycle will continue until world population begins to decline, the economy permanently contracts to keep step with falling oil supply, or we develop energy alternatives and environmental solutions. Of these choices, developing alternatives is better than standing in a soup line during a prolonged worldwide depression and fighting wars for the world’s remaining energy reserves.

Biofuels
We need substitutes for liquid fossil fuel and it looks as if the current options will have to be combined as a multi-solution approach with each part contributing to the whole. Biofuels are part of the solution.

We have all witnessed dramatic food price increases as our world first produced biofuel using corn, sugar cane, sorghum, canola and palm oil instead of putting that on our plates. Plus, many of these crops could only be harvested twice or three times a year. This led most governments to quickly realize that non-edible feedstock crops were needed on non-arable lands. Second-generation biofuels included jatropha, castor beans and Chinese tallow. Those products have important limitations: multi-year long “seed to harvest” growth times, high transportation costs and the need for additional seed treatment to get refined product.

Problem is, by next year when there are 80 million more mouths to feed on our planet, the availability of farm grown biofuel will diminish even further. The market for fuel is growing with our growing population. But so is the demand for food.

Now we have entered the third generation of biofuel. Algae bio-crude is stepping out in front as a real contender to make a difference as energy demand continues to increase. According to one authority, “In the beginning, there were algae, but there was no oil. Then, from algae came oil. Now, the algae are still there, but oil is fast depleting. In the future, there will be no oil, but there will still be algae.” We argue that common sense dictates that algae biodiesel will become one of the most important biofuels.

Profitability
Alternative methods are great in theory, but in our world “profit is king”. Projects must show a return so investors will seed the investment. Until the solution itself is profitable there will be no change-over. In this area, algae have important advantages. It has multiple product revenue streams from the bio-crude and associated by-products, and it qualifies for carbon tax credits.

As worldwide energy reserves dwindle, the Chinese government has had a serious wake up call and is now aggressively pursuing renewable energy projects including algae biodiesel. Newspapers around the country carry stories of how China is moving down the green path of development. If it’s true, China’s move in a new direction toward algae-derived liquid fuel may leave the west far behind in the number of installed hectares. Since the world’s manufacturing is done in China all they have to do is manufacture and install, the infrastructure is already there.

China can ramp up production on a scale to convert our existing liquid energy production within the next three to five years. It has the resources and motivation. Additionally, since many pollution and environmental problems exist in Asia, solutions could emerge from countries like China to tackle both issues in the energy production chain.

When we look back in history, production follows the same model. First a product is introduced but it is extremely expensive and there is no centralized manufacturing of that product. As more companies start to come out with the same product, than larger scale production begins and the price drops slightly. In the last stage many businesses are manufacturing in a centralized location with prices driven down to the lowest levels that make it affordable for the average person or family. The DVD player is a perfect example. It cost $1500 in the 1980s; now you can buy one for $50.

Algae growing equipment is still in the beginning stage where machinery is expensive and not readily available for the average person or family. DAO Energy intends to change that. I am one of the principals in this company.

Global Solutions
DAO Energy, LLC is an algae bio-diesel company registered in Texas. However, our staff live in Chengdu, in Western China. Our market research has led us to the opinion along with most others in the algae industry that manufacturing cost for photo bio-reactors and grow-out units is the major stumbling block on the way to viable mass production globally.

Our solution is to help algae bio-diesel companies worldwide to inexpensively source, manufacture and commercialize growing systems. This will provide a cheaper alternative for algal production in every country. We seek to cooperate and partner with international companies that wish to reduce material costs by manufacturing in China. These algae growth systems can then be maintained domestically in any country to create local jobs and support energy independence. Additionally, we will produce high quality, inexpensive “off-the-shelf” photo bio-reactors for schools, universities, and private individuals. I personally hope schools will use these as educational tools for students to see where we are heading with renewable energy and solutions that already exist. We are not out to reinvent the wheel, we want to offer basic photo bio-reactors. We want to seed the concept of “algae growth for everyone” at the individual level into the mind of the populace, because if we are going to convert systems for energy production it will take an effort from everyone, individually, not just at the corporate and governmental levels.

Dao Energy is in the process of designing, modeling and building algae bio-fuel prototype equipment with the purpose of lowering material costs and advising on materials sourcing and logistics in China. Local extrusion and injection molding factories already have everything we need right now for production of our “off-the-shelf photo bio-reactor”. There is a tremendous amount of overproduction and idle factories that are looking for different higher value chain products to manufacture. This is the consequence of the economic recession in China.

Our near-term plans are to build a grow-out photo bio-reactor next to an ammonia plant, sequester their excess CO2 and then harvest and process algae on site at the plant. In the future when algae production does evolve into a global industry this model of local production, local usage can be mimicked everywhere. Eventually, installation of mass grow-out units will increase and as with everything else over time the single dots will connect into a massive web that should cover the planet and provide some assistance as a liquid fuel replacement.

The Sichuan Trump Card
We have been courted by local business owners that have connections to Sichuan government officials who want us to conduct our project in Sichuan province. The reasons include earthquake reconstruction, job creation, environmental cleanup, carbon sequestration and energy production all in one program. Not surprisingly with mandatory CO2 emission compliance just around the corner, carbon credits have been one of the main subjects talked about in our discussions along with oil production.

Sichuan province remained one of the only electrical generation carbon neutral provinces in China as of 2008. In fact, provincial authorities sold all of 2008’s hydroelectric carbon credits to Saudi Arabia in early 2009. As we have been told, the current Chinese time line is three years before emissions controls take effect on a compulsory level and all carbon credit trading or sales go through China Construction Bank (CCB) in Sichuan. There has also been quite a bit of talk about a “Carbon Credit Trading Floor” being started in Sichuan to cover the western part of China. These are the reasons we have chosen Chengdu.

It’s all about Cost
Consider for a moment that we would be squandering our remaining energy reserves and commodities by building new facilities in every country to produce algae growing equipment while existing factories in Asia are unused. If we choose to go down that path it will be one of the greatest wastes of commodities, energy and investment in human history. During the last 15 years investment poured into Asia for this very purpose; centralizing world production of consumer goods. We should use that investment wisely in a way that benefits every nation.

I need to reiterate to everyone that although our system is manufactured in China for a lower cost, the installation, upkeep and repair of the grow-out and bio-reactors units will be done in each individual country along with growing, harvesting, de-watering and pressing of the algae. Refinement of the oil and processing of algae press cake by-products will be handled by companies in the local community. Local and interstate truck drivers will be driving on fuels produced as a supplement to existing nationwide supply chains. This idea of locality can be replicated everywhere.

At the end of the day, whoever manufactures the most affordable equipment will have the ability to produce oil at a lower cost than anyone else. Manufacturing algae bio-fuel equipment in China utilizing existing infrastructure should ultimately lower the cost of machinery, which in turn will lead us to our main objective; the production of inexpensive crude oil and local job creation in every country.

You can contact Dave Dubyne through his website.

Star Power

As fusion power progresses, the Alberta Council of Technologies urges the province to take a leading role in developing the power of the sun This article appears in the August 2009 issue of Oilweek; graphic from here

By Peter McKenzie-Brown
During the Second World War, celebrity physicist Albert Einstein suggested in a now-famous letter to American President Roosevelt that nuclear chain reactions in large masses of uranium could release “vast amounts of power and large quantities of new radium-like elements.” And, he speculated, “Extremely powerful bombs of a new type may thus be constructed.”

While America had only poor-quality uranium, Einstein noted, “There is some good ore in Canada.” The ore used to create the first atomic bombs came from a rich deposit of uranium and radium along the shores of Great Bear Lake, in the Northwest Territories.

During the long days of summer, a wartime mining company hired local Indian men to carry 40-kilo burlap bags of ore from the mine to the Mackenzie River. They carried those loads for long hours, for months on end. When the bags ripped apart, they shifted the spilled ore off the trail, but took the contaminated bags to their temporary village. Years later, the ore-carriers began dying of cancer, and the community now known as Deline became a village of widows.

Canada was thus an important contributor to the first nuclear age, which was born of the fission of radioactive elements. Within a decade, the United States had made tentative steps toward a different kind of nuclear age – one based on nuclear fusion. This system smashes together light atoms like those of hydrogen. As it turns lighter elements into heavier ones, fusion releases vast amounts of energy.

This is the principle behind the hydrogen bomb. It is star power – the fuel that keeps the Sun and the countless other stars alight. As a human invention, its only practical use has been as an unused weapon of violence and terror. Until now.

"[Fusion ignition] is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.”

On March 10, the National Ignition Facility at Lawrence Livermore Labs in California trained 192 high-power lasers onto a point the size of a couple of match-heads. The ensuing reaction generated more than a million joules of energy – enough energy to theoretically light up 10,000 100-watt light bulbs.

The American effort was costly, but its implications were huge. That step suggests the birth of a nuclear age in which virtually limitless amounts of inherently safe and environmentally attractive will be cheaply available.

Compared with carbon or uranium fuels, fusion generates little radiation and no greenhouse gases or air pollution. Since it uses small amounts of fuel, it is likely to have little impact on land and habitat. The day before this extraordinary American achievement, a standing committee of the Alberta Legislature met to consider a proposal by which Canada would become involved in these revolutionary technologies.

Canada would not supply ore, as we do for nuclear fission. After all, the fuels needed for fusion are abundant around the world. Instead, we would help develop technological expertise for the second nuclear age.

Visionaries: The proposal came from a small, minimally-funded and loosely-organized group of visionaries provincially chartered as the Alberta Council of Technologies. Clearly, the goal of the media relations surrounding the meeting with the legislature was maximum public awareness. In this, they certainly succeeded.

The idea is to prove that controlled nuclear fusion can become the world’s energy future. Theoretically, it could provide clean and nearly limitless electrical power for humankind, with everything that implies. It could mean a reversal of global warming and the reversal of policies by which agricultural products are transformed into fuel. According to Dr. Perry Kinkaide, the group’s chairman, his council was asking the province to contribute to a demonstration of fusion ignition.

Fusion ignition, he said, “is imminent and will be one of the most extraordinary technologies discovered by mankind. We will be reproducing the physics of the sun.” When you get into the physics of this “imminent” technology, which talks about creating temperatures so hot (up to 100 million degrees Celsius) that they can only be enclosed by magnetic fields or lasers, it’s like tripping forward through a time-warp. Yet new technologies – demonstrated by the test at the Lawrence Livermore Laboratories – have changed the picture.

Adds Allan Offenberger, a retired University of Alberta engineering professor and another program proponent, it is the new technology of “inertial confinement” of the heat of fusion that is changing everything. Inertial confinement uses laser beams to quickly heat to ignition a “fuel pellet” of simple atoms like the commonplace hydrogen isotope deuterium and the much less stable hydrogen isotope tritium. Because this process rapidly induces fusion, you don’t have to confine the fuel at all. The advantage: a relatively simple reaction chamber design.

Even so, this is a long-term proposition. A demonstration project isn’t likely for 25 years, say, with commercial facilities following a decade after that. However, the promise is great. Once the bugs have been worked out, the fusion energy could be very cheap.

To begin to develop expertise in this area, the proposal suggested that the province pony up $4 million this year and commit to another $17 million, total, in the two fiscal years following. The proponents argued that if Alberta scientists don’t get in on the ground floor, they will fall behind in expertise. Joining the project later, they argue, will be more expensive Once the province got its foot in the door, the proponents call for an intensive program of R&D “to develop inertial fusion as a viable energy technology.”

This phase would cost perhaps $40 million per year. Eventually, according to the council, having expertise within the province could lead to commercialization of the technologies. Perhaps the province could become “a provider of high power lasers, reactor systems engineering and related technologies for fusion energy and other applications.”

According to Offenberger, the aim is to create a safe, relatively cheap and clean method of producing electricity based on fusion. One attraction of this form of energy, he says, is that huge amounts of energy could be created with less than a kilogram a day of two types of hydrogen fuel. Also, there is no chance of meltdowns from this form of nuclear energy, which produces no hazardous wastes. The only waste products are heat and, from the size plant the group visualizes, about a kilo of helium per day.

The proposal also points out that there could be huge savings on transmission costs “because (fusion) plants can be located close to electricity users.” Canada is the only major industrial country without a fusion research presence. Given the country’s energy wealth, proximity to the United States and trade surpluses, perhaps that’s not unreasonable. I put the question to someone with the broadest imaginable view of electricity supply and demand within Alberta.

Technological Dominance: At the time of our interview, Martin Merritt was completing his term as the Alberta government’s Market Surveillance Administrator. His job was to make sure electricity and natural gas markets within the province were free and fair. Although he was quick to say he had no expertise in nuclear fusion, he surmised that “The best place to do this would be in the US, where the problems of energy supply, environmental problems, worries about global warming and the need to remain technologically dominant are so powerful. Europe also has those problems. In that sense, the timing seems perfect” to be developing these technologies.

By contrast, he opined, “Alberta’s main reason (to become involved) is that as an important energy power, we have many reasons to have an oar in developing energy technology.” He added that “Alberta needs to get around the (environmental) brush we’ve been tarred with. Perhaps adopting this form of energy could earn us green credits.”

Perry Kinkaide’s Council of Technologies, however, sees an urgent need for Canadian involvement. In a document on the council’s website, the group argues that “The window of opportunity is closing fast for Alberta and Canada to participate in a global partnership for developing ‘fusion,’ the ideal solution for meeting the world’s primary energy requirements – forever! Participation will secure our position as an energy superpower as the world transitions to fusion, with significant socio-economic and environmental spin-off benefits.” In this compelling commentary, the organization addressed “the need for fusion energy and the prospects of a revolutionary new technology for its achievement.”

Citing significant environmental, health and safety implications, it also noted that “the strategic fit of fusion technology with the demands of North America’s coal-based electric power industry as plants reach end-of-service and require replacement.” What is needed immediately, they insist, is an action plan “to ensure Alberta’s and Canada’s place in the emerging fusion-energy economy.” While the notion of fusion energy is closely tied to the generation of electricity, perhaps it could meet an oilsands challenge which went untried during the optimistic early years of the first nuclear age.

Fifty years ago, Richfield Oil Company proposed an experimental plan to release liquid hydrocarbons from the oilsands through the expedient of an underground nuclear explosion. The company proposed detonating a nine-kiloton explosive device below the oil sands at a site 100 kilometres south of Fort McMurray.

Thermonuclear heat would create a large underground cavern and simultaneously liquefy the oil. The cavern could serve as a collection point for the now-fluid bitumen, enabling the company to produce it. This idea came remarkably close to actually taking place. The project received federal approval in Canada, and America’s Atomic Energy Commission agreed to provide the device. But before the pilot could take place, public pressure for an international ban on nuclear testing had mounted.

As the late Ernest Manning once told me, when he was premier the federal government withheld approval and thus killed the plan. Perhaps in the second nuclear age, energy from nuclear fusion could become a safe and realistic heat source for producing and refining the dense oils Canada is famous for. This idea may sound far-fetched until you consider that in Peace River Shell is already testing the use of electric heaters to refine bitumen carbonates in situ, deep inside underground formations. When you start talking about a second nuclear age, nothing seems impossible.

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.

Keeping Electricity Competitive

Alberta’s Market Surveillance Administrator, Martin Merritt is head of an independent agency developed to ensure that the province’s electric markets operate in a fair, efficient and competitive fashion. The MSA also monitors the retail natural gas market. This article was carried in The Calgary Herald September 12, 2008.

By Martin Merritt A few weeks ago, The Calgary Herald carried an item reporting that Alberta had just set a new summer record for power consumption, eclipsing last summer’s record by 2.3 per cent. The good news is that we had plenty of supply to meet this record. The concern is that as we continue to post records we may not have the transmission to ensure that the lowest cost supplies reach us as consumers.

As a consumer, I get the best deal for myself if I can buy things – cars, groceries, gasoline and other forms of energy – freely on the open market. In a market economy, our choices as consumers give a great incentive for sellers to keep their costs low. If we were constrained to buy from only a few sellers, we would have less choice and prices would likely be higher.

I also wear another hat. As Alberta’s Market Surveillance Administrator – the guy responsible for making sure our electricity market functions competitively – I understand that constrained markets can prevent low-cost sellers from prevailing in the marketplace. In the case of electrical power, we need more than the supply necessary to meet Alberta’s needs. We need a system that allows electricity to flow freely around the province. That requires adequate transmission capacity.

Alberta’s electricity market provides consumers with secure supplies and competitive pricing, but the transmission system is becoming undersized for the job in some places. Whether for home appliances or running business operations, consumers will only get the best deal on power when the transmission system can transport electricity from (almost) any generator in Alberta to (almost) any consumer in Alberta. This is why I am concerned about the tremendous hurdles facing new transmission projects these days.

Electricity generators are like stores, and the transmission system is like the network of roads that enables us to get to and from the supermarket. If major roadways became so congested that we had to buy all of our groceries from the local convenience store we all know what would happen to our family’s food bill.

This isn’t just theory. It’s already affecting us. Today we are moving a lot more electricity through the transmission system than we did when it went through its last major upgrade over 20 years ago. In constrained areas of our grid, this has dramatically pushed up the energy losses from transportation.

For example, between the Lake Wabamun area where about 40% of Alberta’s generation is located and the Calgary area, losses average over 10%. According to the Alberta Electric System Operator, additional transmission capacity would save enough energy to power half the City of Red Deer. Losses on that scale are pure economic and environmental waste. More recently, in the five years from 2002-2007, Albertans paid almost $300 million in subsidies to electricity generators for helping us get around our transmission bottlenecks. The subsidization rate is presently $40-$50 million annually.

Some advocate expanding this practice – paying generators to locate in sub-optimal places in order to avoid investing in transmission infrastructure that the province badly needs. This amounts to renting band-aids rather than fixing the root problem. This band-aid approach might work well for the band-aid vendors but it’s certainly not in the best interest of Albertans if we expect to continue to realize the larger benefits of a broadly competitive electricity market.

In Alberta today, the wholesale electricity market is worth about $5 billion a year, less than 10% of this represents the cost of transmission. The economic challenge of trying to avoid or defer transmission investment beyond what we have already realized is that you put the competitive efficiency of a $5 billion market at risk, in order to chase questionable savings in the 10% piece – penny-wise, but pound-foolish.

Allowing growth in demand to outstrip the capacity of our existing transmission system puts the benefits and perhaps even the reality of a competitive electricity market at risk. Experience in other electricity markets has shown that the practice of subsidizing generators to locate in particular places can have expensive and unintended consequences. Once generation economics start to hinge on capturing subsidies rather than on efficiency and low-cost, the broader benefits of the competitive market become compromised. Consumers expect and need generators to compete with each other on the basis of efficiency and generation cost. Transmission enables this competition to occur. Subsidized generation distorts it. Unless we invest in transmission, Albertans’ bills will continue to reflect the growing cost of rented band-aids, high losses and diminished competition. The longer we take to build the transmission we need, the more rent cheques go down the drain.

In southern Alberta, we have great sites for generating electricity from the wind. Investors are willing to build there, but we have a shortage of transmission. Similarly, northern Alberta is the logical place to locate fossil fuel generators. They are most efficient (both economically and thermodynamically) when they can be located at low altitude, in cooler temperatures and near a substantial supply of water. There too, we have a shortage of transmission. By bringing all electricity supply sources to all consumers across the province, transmission provides us with choice and forces suppliers to compete with each other.

Subsidizing higher cost, less efficient generators to locate in the middle does neither.

These are powerful realities. Some advocates of gas-fired generation in southern Alberta will soon enough be asking for subsidies – for without them their projects are unlikely to be able to compete. About half of Alberta’s residential consumers live in the transmission-constrained southern part of the province, but the case for reinforcing our transmission grid is not an argument for southern consumers alone. All Albertans benefit the most from the most competitive market possible. We must find ways to enable the fair and timely development of critical transmission infrastructure. We need more transmission capacity because that – not subsidized generators – is the best way to assure the competitive market that Albertans have come to expect.

Beyond Bali

This article was first published in Oilweek; graphic from this source.

With the latest UN conference on climate change relegated to history, Canada's oil and gas industry is now ready to focus on implementing some solutions

By Peter McKenzie-Brown “Climate change is a serious threat to development everywhere”, said Rajendra Pachauri last November as he released technical reports prepared by the UN’s Intergovernmental Panel on Climate Change. “Today, the time for doubt has passed. (We have) unequivocally affirmed the warming of our climate system, and linked it directly to human activity.”

To make sure there was no doubting his message, he added that “slowing or even reversing the existing trend of global warming is the defining challenge of our age.” According to Pachauri, global warming will lead to melting icecaps and rising sea levels, the drowning of some island nations, the extinction of species, desertification of tropical forests and more frequent and deadlier storms. The world’s media soon became focused as never before on greenhouse gases (GHG) – the emissions (mainly carbon dioxide and methane) causing Earth to warm and its climates to change.

The occasion was a United Nations conference meant to negotiate national targets for reducing greenhouse gases. The venue was the Indonesian resort island of Bali. The US, Canada, and Japan became villains in the piece as they argued that the targets of the 1997 Kyoto Protocol were unrealistic. To live up to that agreement would have required Canada, for example, to cut its GHG emissions by perhaps 50 per cent during the next 12 years.

The three villains complained that Kyoto required nothing from emerging economies like China and India, which are big polluters. They and others also observed that, at the time of the original Kyoto discussions, science had little understanding of the impact on global warming of tropical deforestation. Deforestation amounts to destruction of some of the vital CO2 reservoirs often called “carbon sinks”. Factor in the loss of sinks from rainforest destruction and Brazil and Indonesia become the world’s third- and fourth -largest GHG emitters. 

Despite the sound and fury, Bali achieved little. It reinforced the global dread of carbon-induced climate change through the media, and the conference agreed to develop detailed plans for cutting emissions, with special focus on reforestation. When that is done next year, a convention of member states will negotiate GHG reduction targets in earnest – or such is the plan.

Looking for Solutions: Given the glacial pace of implementing global treaties, the first steps in managing carbon emissions need to be taken locally. An industry of national and global importance, Canada’s petroleum sector can become a leader in taking those local steps. More to the point, a group of large players in the sector have already begun to do so through an initiative called the Integrated CO2 Network (ICO2N or, more simply, ICON) – a proposed system for the capture, transport and underground storage of carbon dioxide. But before reviewing ICON’s remit, let’s take a quick look at trends in pollution control.

Just as today’s science says controlling these gases is environmentally critical, today’s higher-cost energy is combining with technological change and evolving policy to make it easier to reduce emissions. GWG reduction can take the form of finding non-hydrocarbon sources of energy. It can mean using technologies that produce fewer unwanted emissions. It can mean using lower-carbon fuels.

The good news is that a great deal can be done, and in many different ways. For example, a tried and true way of reducing air pollution is to take old automobiles off the streets. Replacing those cars with low-pollution, fuel-efficient vehicles can increase the benefits. This is the idea behind a federal initiative which encourages Canadians to go green by offering rebates ranging from $1,000 to $2,000 to people who buy fuel-efficient vehicles.

Sometimes newer technologies hark back to older times. For example, wind-assisted ships that use a computer-controlled, helium-filled kite to capture wind energy can reduce a vessel’s fuel consumption by 20 per cent or more. Fuel can represent as much as 60 percent of a merchant ship’s operating costs, so this innovation has high economic potential. Wind-assisted boats also produce less pollution, and in GHG terms this is no small matter. The world’s 50,000 or so trading vessels carry 90 per cent of global trade. Most fly flags of convenience, and their emissions are subject to little national control. In the matter of electricity generation, fuel switching – using natural gas instead of coal, for example – reduces carbon dioxide emissions by using a cleaner fossil fuel. It replaces an abundant fuel with a scarcer one, though, and is therefore not a sustainable long-term strategy. However, the Paris-based International Energy Agency says that emissions from coal-powered electricity generation can be reduced immediately, but also over the longer term.

Cost-effective CO2 emissions reductions can be achieved almost immediately by burning coal with less waste. Long-term, carbon capture and storage (CCS) offers the potential for near-zero carbon dioxide emissions from coal-based power plants. “These strategies are complementary,” says the IEA report. “Deployment of modern, efficient coal-fired electrical generation technologies in the short to medium term can enable carbon capture for less cost in the longer term, if those power units are designed to enable cost-effective carbon capture retrofitting when that technology becomes available for commercial application.” Of particular importance to the petroleum industry, carbon reduction can involve warehousing greenhouse gases in depleted oil and gas reservoirs. It is in the arcane area of CCS that Canada’s petroleum industry can make a world-class contribution to the problem.

Carbon Capture and Storage: What is carbon capture and storage? It involves capturing the carbon emissions from an electric utility or an oil sands plant and storing them, for example, in depleting oil fields. This is not new. Carbon dioxide has long been used for enhanced oil recovery, to urge incremental barrels out of elderly oil fields.

One such project has been operating in the 50-year-old Weyburn oilfield in Saskatchewan for nearly eight years. The project uses a 330-kilometre pipeline to transport carbon dioxide captured at the Great Plains Coal Gasification plant, which manufactures methane from coal near Beulah, North Dakota. This project disposes of about 1.5 million tonnes of this greenhouse gas each year, and also keeps oil flowing from this aging field. At present, Weyburn is one of only three such projects in the world, all of them about the same size.

The second is the BP-operated In Salah project in Algeria, where carbon dioxide extracted from the gas reservoir is removed and reinjected. This reduces pollution, but the injected gas also plays a role in maintaining reservoir pressure. The third is Statoil’s Sliepner project, in the Norwegian sector of the North Sea. There, carbon dioxide extracted from gas production at the Sleipner West gas field is stored in a reservoir 1,000 metres below ground instead of being released to the air. In this project, injection is strictly a waste management practice. It does not assist in field production.

Injecting carbon dioxide into old oil fields as a method of enhanced oil recovery could eventually help the petroleum industry add 1.2 billion barrels to conventional oil production in Alberta alone. This, at least, is the view of Suncor’s Stephen Kaufman, chair of the 16-member Integrated Carbon Dioxide Network (ICON). Using carbon dioxide from an industrial source for enhanced oil recovery is increasingly economic as energy prices rise. But can pumping GHGs into the ground be economically viable if it isn’t being done for a commercial purpose? According to Kaufman, this is the sticking point. “There is no value chain for CO2 capture,” he says. “It is extremely difficult from a pure market standpoint to make it profitable.”

The ICON consortium of mostly blue chip companies with Alberta operations wants to develop a national greenhouse-gas collection, pipeline and storage grid with roots in the Alberta oil industry and branches across the country – from British Columbia to Nova Scotia (see map ). In the beginning, the network would capture carbon dioxide from sources in north-central Alberta, including Fort McMurray, Fort Saskatchewan and the coal-fired power plants near Wabamun Lake.

The carbon dioxide would be transported by pipeline to suitable geological sites for storage and to EOR loranios- for sale to oil producers. About 1,000 kilometres of main pipeline and 400 kilometres of small collector lines would ultimately be needed for this system, which would be built up over a decade or more. Longer term, carbon-capture could be done elsewhere in Canada, which has suitable geologic storagic basins in nearly every province and territory. In effect, ICON is proposing a vast network of waste treatment facilities, and the industry believes sharing of the costs of this network with energy consumers is appropriate since “it is more difficult and more expensive for consumers to make emission reductions directly.”

Noting that Canadians will be facing “increasingly stringent carbon regulations”, Kaufman says those regulations are going to force energy consumers of all types to find ways to reduce net emissions. “GHG emissions result from making fossil fuels, power and manufactured materials that benefit all Canadians. The consumer will have to pick up a share of the tab for clean-up.” If not exactly profitable, these developments will make ICON viable. “We are very interested in starting this system off”, Kaufman says. “The first GHG injections could go into storage in 2013”, he adds, stressing that the project is ambitious and the “hurdles are very substantial.” However, it “could represent perhaps the largest single carbon-dioxide reduction approach Canada takes until renewables, alternative fuels and energy conservation become very significant.”

Also known as carbon sequestration, CCS has been a topic of many reports in recent years. “When it’s not commercial to do something,” Kaufman points out, “you tend to do a lot of study. We need these technical and economic reports, and eventually we will also need public input. People need to be sure this can be done safely.” Most importantly, though, “We are looking for the right way to move this concept forward. Our first objective is to contribute to policy – it will need provincial and federal legislation to make this happen.”

The right policy will include a cost- or risk-sharing formula, clear greenhouse-gas emissions rules and government commitments to reassure ICON that the policy will not change during the one to two decades needed to develop the carbon disposal grid. Long-term policy commitments will encourage new oil sands and power plants and other large, GHG-intensive facilities to invest in carbon capture technologies during construction, so they can connect to the system when they go on stream.

Kaufman believes tax incentives will also be needed, as will carbon disposal credits. Carbon credits “will need to be as widely tradable as possible, so we can develop an efficient market”. For example, an Ontario industrias producer with a GHG emission problem could pay to capture and store carbon in Alberta, thereby using tradable credits to meet local emission regulations. This approach reflects an environmentally acceptable exchange of value. After all, global warming is a planet-wide problem precisely because carbon dioxide respects no boundaries. No matter where they take place, GHG reductions benefit everyone.

From the perspective of economic efficiency, it is important to reduce emissions wherever it is cheapest. The tropical paradise of Bali may be far from Alberta’s main centres of industrial GHG pollution, but in the big picture of energy-induced climate change there is an ironic link between the two. ICON illustrates how Canada’s oil patch could take a leadership role in mitigating the causes of global warming – and do so without waiting for the diplomats.

Who Pays the Bill? After the UN released its report on global warming, Secretary-General Ban Ki-Moon made climate change a central feature of his term of office. “Galvanising international action on global warming” he said, “is one of (my) main priorities.”

Such a commitment at the highest levels is essential. After all, air pollution doesn’t respect international boundaries. Nations routinely outsource emissions to other jurisdictions. Decision-makers often focus on short-term profits and near-term political interests.

In that context, Ban’s commanding affirmative raises some fascinating interrogatives. If the consumer must pay, how should global traders charge for GHG emissions? Will transnational customers actually pay? What’s the best way to enforce international treaties with countries whose domestic poverty trumps their environmental goodwill? Should rich countries simply pay the cost of cleaning up GHG waste in poor countries, since that is often the cheapest and simplest way to reduce emissions? Can accelerating global energy demands be met without use more and dirtier hydrocarbons?

Such questions illustrate the complexity of the problem. Take the oil sands. Oil sand development illustrates the “blackening” of the barrel of oil – the shift from higher-grade reserves to lower-quality, higher-carbon resources that are more expensive to produce.

Twenty-five years ago, US customers for Canadian oil generally processed light to medium crude. Those refineries have since been modified to process heavy oil and oil sands production from Canada. Much of that oil is upgraded, but upgrading commands a stiff carbon price. To produce synthetic oil from bitumen requires a lot of heat, much of it generated from natural gas. The synthetic oil we export is responsible for much more GHG pollution than was the light oil of yesteryear. Oil sands production generates three times the carbon emissions created by the production of conventional oil. The same logic applies to refined products. Canada’s net annual exports of gasoline, diesel and such to the United States amount to about 500,000 cubic metres – about 3.4 million barrels of product. Again, refining is energy-intensive, with the corresponding carbon price we have to pay.

Canada's GHG Ledger Consider the Canadian GHG ledger. The fuels we use to produce synthetic oil and refined products for U.S. markets amount to an outsourcing of carbon emissions from the United States. Outsourcing CO2 production to Canada in this way lowers per capita GHG emissions produced by Americans but increases those ascribed to Canadians.

Of course, this sword cuts many ways. Finished goods from China arrive in Vancouver by the container load, but none of the pollution generated in Chinese plants and factories enters Canada’s environmental ledgers. It was, after all, produced in Asia.

If Canada’s pollution ledgers accurately reflected the pollution generated by the products we consume (and fully offset all those we export), Canada’s CO2 emissions would probably be higher than they are. Canadians would still not be the world’s biggest per capita greenhouse gas polluters, though. Honours in that competition go to Australia and the United States, respectively; Canada only gets the bronze.

The main cause of our high GHG emissions is Canada’s hydrocarbon consumption – at 8,300 kilograms of crude oil equivalent per person per year, the highest in the world. If that crude oil equivalent were bottled water, at 2.2 litres per day it would take a person ten years to drink it all. By using them for fuel instead of hydration, those hydrocarbons provide us with mobility, power and heat, each of which bears an environmental cost.

Every transaction involves a measure of energy produced and then consumed. And as we consume energy – by trucking goods, extracting resources, manufacturing products and turning up the thermostat, – we create greenhouse gases.

We live in a big country, so transportation – often in cold weather, when fuel efficiency drops – is a big part of the economy. Nationwide, about 25 per cent of our GHGs come from our trucks, trains, airplanes and, especially, our cars. Commerce, residential fuel consumption and industry (excluding oil and gas) account for 24 per cent of the total, but much of those emissions come from equipment (mining trucks, front-end loaders) that don’t get recorded in the transportation ledger. Another 14 per cent come from non-energy sources. The rest come from the production and manufacture of energy and power. As Canada creates targets for GHG reductions, policymakers will zero in on the three areas – transportation, electricity generation and fossil fuel production – in which the greatest reductions are possible.

Together, these activities account for nearly two thirds of Canada’s greenhouse gases. Efficiencies can be found there. Will Canada’s pollution actually decline? Not according to Canada’s Energy Outlook, a Natural Resources Canada report on the matter.

NRCan estimates that Canada’s GHG emissions will increase by 139 million tonnes between 2004 and 2020, with more than a third of the total coming from petroleum production and refining. Upstream emissions will decline slightly, primarily from gas field depletion and from increasing production of coalbed methane, which requires less processing than conventional natural gas. Meanwhile, emissions from unconventional resources and refining will soar.

Assume these forecasts are accurate, and that in 2020 Canada’s GHG waste will be half again as large as it was in 1990. Assume also that, as the UN’s Rajendra Pachauri thundered to his audience last November, “slowing or reversing the existing trend of global warming is the defining challenge of our age!” Where do we go from here?