The Best of the Best

Imperial Oil's Kearl project is poised to open, bringing "green" bitumen to the world. This article appears in the September issue of Oilweek 

By Peter McKenzie-Brown

Imperial Oil has been a big player since Canada’s petroleum industry began. With roots that go back to southwestern Ontario’s 19^th century oil boom, in 1947 the company kick-started the industry’s modern era with its Leduc discovery.

Not so well known is that Imperial has been the consummate pioneer in the oil sands business. In the middle of the last century, the company joined the Syncrude consortium, which in 1962 applied to the Conservation Board for approval to proceed with the Syncrude project. The final decision to proceed with Syncrude didn’t take place until 1975. By that time Imperial had developed the cyclic steam stimulation, which now drives its Cold Lake project. Not so well known is that, as part of its early Cold Lake experimentation, the company conducted the first tests on steam-assisted gravity drainage – the technology of choice for in situ recovery in the Athabasca deposit. Today, SAGD is the source of about half of Canada’s bitumen production.

The folks at Imperial are getting ready to do it again. When commissioned at the end of this year, the Imperial-operated Kearl oilsands project will process oil from a mine 70 kilometres from Fort McMurray. Unlike all the other mine-based projects up there, however, Kearl won’t produce high-carbon oil. Indeed, the product flowing into American refineries will produce no more carbon emissions than those produced by the average barrel now refined in the United States.

The Kearl project is huge. When it reaches full capacity of 345,000 barrels per day around 2020, it will be one of the world’s largest sources of crude. And it will produce low-carbon bitumen for 40-50 years. It will achieve this apparent industrial miracle through advanced oil sand processing techniques and the production of diluted bitumen which doesn’t need to be upgraded. A significant later add-on will be power from energy-saving cogeneration for the provincial power grid.

Imperial’s long experience in oil sands development and management – not least as a charter member of the Syncrude consortium – means the company has depth and breadth of experience. According to Kearl’s designated media spokesman, Pius Rolheiser, “The project will use the best of the best technology.” One of those “best technologies” is high-temperature paraffinic froth treatment (HT-PFT).

Paraffinic Froth: To understand the oil sands revolution Kearl represents, you have to understand froth treatment. “After oilsand is mixed with hot water to liberate the bitumen from the matrix of sand, water, silt, and clays, the bitumen is separated from the resulting slurry,” science and technology writer Diane Cook explained. “In a flotation vessel, the bitumen is removed as a highly viscous mixture of oil, mineral solids, and water called bitumen froth. The froth is then diluted with a hydrocarbon solvent to reduce its viscosity and enhance separation from the emulsified water and solids.”

The earliest plants mixed oilsands with hot water and naphtha in a separation vessel to separate the bitumen from the water, sand and other wastes associated with the ore. The facility skims the froth from the top of the vessel to get a product for further processing. The problem with this approach is that the resulting bitumen blend can contain as much as 3.5 percent sediments and other impurities, which require further processing and upgrading before they can be transported in a regular pipeline.

The key to Kearl’s low-carbon achievement is to use paraffin rather than naphtha. Originally developed by Syncrude in partnership with NRC’s CANMET Energy Technology Centre in Devon, Alberta, high-temperature paraffinic froth treatment removes only lighter hydrocarbons from oil sands ore, leaving undesirable asphaltenes behind. Asphaltenes carry most of the very fine solid particles (“fines”) that create tailings pond nightmares for older plants. According to Rolheiser, through this process “we can return them as waste to the mine.”

Asphaltenes consist primarily of carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium and nickel. Heavy, gunky hydrocarbons, they contain almost as much carbon as hydrogen. Thus, in the typical refinery, asphaltenes are a low-end product with few uses beyond road pavement and roofing tar. The fewer asphaltenes you pipe into the refinery, the more high-end products the refiner can ship out after processing.

As Cook explained when a Shell-patented version of the process went into use at its Athabasca Oil Sands Project, paraffinic froth treatment “produces a much cleaner, diluted bitumen product that contains less than 0.1 per cent residual water and solids. In this process, the contaminants are readily separated by gravity, without the need for energy-intensive centrifugation, and the light aliphatic solvent is easily recovered from the diluted bitumen without the use of a lot of heat…. As a result, the bitumen has a lower viscosity, which allows the bitumen to be transported by pipeline to upgraders or directly to market with a small amount of diluent added.”

It is in this area that the Kearl project is revolutionary. Although Shell recently applied this process at existing project, Kearl will be the first oilsands mine constructed entirely without reference to an upgrader. According to Rolheiser, “Kearl bitumen will be somewhat lighter than the other marketed diluted bitumen produced in the oil sands.” This is possible because of the higher-quality oil produced through paraffinic processing.

Proposal, Budget, Expansion: This project has been a long time coming. Mobil Canada acquired Lease 36 – the oldest of the leases – in 1952. Imperial acquired lease 87 in 1989. A decade later Imperial and Husky Energy bought lease 6. Once the two companies had the property in their collective hands, Imperial took the lands amenable to surface mining while Husky took the sections that were better developed through in situ technologies.

 Mobil made the first proposal for a Kearl mining and upgrading project in 1997, to be based on lease 31A – an adjacent lease that plays a smallish role in today’s Kearl project. After the 1999 merger of the two majors that gave ExxonMobil its name, the international giant holds 100% of the mining rights to leases 36 and 31A and a 30% interest in the project.

Rolheiser said his company’s affiliation with ExxonMobil has played a key role in project development. Through that storied giant, “Imperial has access to global technologies, assets and expertise. They have executed multibillion-dollar projects all over the world. They have an unprecedented research capability. Our affiliation with them gives us a lot.” Not only did ExxonMobil bring patents and engineering ideas to the table. “It also enabled us to leverage our own expertise.”

Imperial originally conceived Kearl as a three-phase development in its original proposal, with each phase producing about 110,000 barrels per day. It was that project that Imperial began scoping out in 2004/5, with the company then presenting its regulators with a cost estimate of $8 billion for phase one. Estimated costs later rose to $10.9 billion for that phase.

According to Rolheiser that’s because “As we got into the execution of the project (in 2011) we realized that there were some facilities that we didn’t need to duplicate, and in fact we could make the surface footprint somewhat smaller. So we re-configured the project into two phases (instead of three). So, what we’re building today for $10.9 billion is a different development than what we had envisioned building for $8 billion. It includes additional investments in things like tailings management to meet ERCB Directive 74, and regional pipelines (that we hadn’t originally planned for).”

The company plans to begin construction of the expansion phase, for which it has budgeted $8.9 billion, in 2015. After construction and debottlenecking, the full project will be on stream at the end of this decade. The project encompasses a 4.6 billion barrel resource, and Imperial expects initial development costs to total about $6.20 per barrel.

Rolheiser added, “We can now get to our license capacity of 345,000 barrels per day, which was our target when we originally envisioned the project. We’re just going to get there in a different way.” Kearl will operate near capacity for 40 to 50 years, so “commodity prices are likely to have a minimal impact on our planning. For projects like Kearl we really do take a very long view of things. We aren’t even thinking about year-to-year prices. Our current expansion plans are not contingent upon approval of any particular pieces of pipeline infrastructure. They aren’t dependent on whether Gateway goes ahead.”

Well-to-Wheels: According to a 2010 report by IHS CERA, a highly respected American think tank, the Kearl project will result in life-cycle greenhouse gas emissions similar to the average of oil refined in the United States. In Brussels last year, the Jacobs Consultancy, an international firm, gave a report to the Centre for European Policy Studies in which it reached the same conclusion.

These reports differ so markedly from those used by environmentalists because they compare full lifecycle emissions. If you want to make apple-to-apple comparisons of crude oil sources, this is an important concept. True well-to-wheels, calculations account for GHG emissions associated with every stage of a product’s life: extraction, processing, refining, distribution, and use. The IHS CERA and Jacob’s reports add those emissions, for example, to the product’s total. Adding these factors into the equation dramatically changes the GHG estimates.

The case of Nigeria’s Bonny Light oil is dramatic example. During refining, this high-quality oil (35° API with negligible sulphur content) produces relatively low levels of GHG emissions. However, the country’s practice of flaring associated gas during oil production hugely increases the lifecycle emissions of its exports. According to the Jacobs report, in recent years Nigeria has flared 27 cubic metres of natural gas for every barrel of crude it produced. This is the main reason that Jacobs’ full cycle calculation showed Nigerian light crude producing 7% more GHG emissions than the average slate of oils refined in the US.

Well-to-wheels GHG emissions for oil sands and conventional crude oils (kgCO2e per barrel refined products)
Crude	Well-to-retail pump	Well-to-wheels	% difference from average US crude consumed
Canadian oil sands: mining dilbit (Kearl)*	103.6	487.6	0
Average US barrel consumed	103.1	487.1	0
Average oil sands imported to US (2009)	133.5	517.5	6 %
California heavy oil	165.6	549.6	13 %
Nigerian light crude	135.2	519.2	7 %
Canadian heavy oil	82.6	466.6	-4 %
Venezuelan partial upgrader	157.6	541.6	11 %
West Texas Intermediate	54.6	438.6	-10 %

(Source: IHS CERA.)

By contrast, the Kearl project will produce GHG emissions that are virtually identical to those of the average barrel refined in the US, whether you are measuring those emissions at the retail pump or a vehicle’s exhaust (both marked in red on the table).

If you take the chart too seriously, it may seem that only WTI and Canadian heavy oil are greener sources of oil from a GHG perspective among the crudes listed in the table. However, it is worth noting that Canadian and Brent light oils, for example, are not listed. This illustrates the importance of comparing Kearl production to the average slate of oils refined in the US.

Of course, if it is fair game to add emissions from flaring natural gas in the Nigerian calculation, it is also reasonable to deduct them if a producer can make a credible case that its production practices actually offset GHG emissions. The Kearl project does this in two ways.

For one, it was designed without an upgrader – traditionally, a major source of GHG emissions for oil sands mines. Using paraffinic processing makes this possible: just mix the higher-grade bitumen with diluent and ship it by pipeline to an existing refinery. To put the significance of this innovation into context, consider that exports to the US from many countries will become more carbon-intensive as national oil companies export increasingly lower-grade crude – a phenomenon known as “the blackening of the barrel.”

The IHS CERA study forecast that “new mining projects without upgraders (like Kearl) will increase (American) imports of lower-carbon oil blends.” In 2030, the report suggested, “the average carbon intensity of oil sands blends (will) remain about the same as today.” This could mean that Kearl oil will become less carbon-intensive than the average refined in the US.

Kearl’s other big carbon-lowering tool will be the use of cogeneration. Environmentally and economically efficient, cogen involves the simultaneous production of electrical power and heat from a single fuel source. The oil sands industry has used cogen during bitumen production since the 1970s, so the practice is not new. In the quest for reliable self-sufficiency in power, all new mining facilities since then have used cogeneration, though generally aimed at little more than supplying their own projects.

Imperial will also install gas-fired cogeneration units at Kearl, selling some of its production into the grid, though details are still sketchy. According to Rolheiser “They will be added to the operation as a separate project (before 2020), but not as part of initial plant development.”

As the Kearl project moved through the approval and construction phases, most media discussed the project in the context of an anti-Kearl lawsuit from an environmental coalition (Imperial won the case), and concerns within the US about transporting huge modules on state highways. The pity is that, in general, they are unlikely to cover Kearl as an environmental triumph.

Leaving Libya

A hot Arab Spring and civil turmoil spreading throughout the Middle East left Canadian expats scrambling to get out

This article appears is the July issue of Oilweek; photo: CBC

By Peter McKenzie-Brown

Want to appreciate the risks facing oil-producing regions in the Arab World? Consider this: With few exceptions, companies with assets there won’t discuss business or operating conditions; they refer reporters to sanitized news releases. Expatriate workers will often talk only if guaranteed anonymity.

That said, most of the people contacted for this story confirmed an undercurrent of brutality in Libyan society. Take the case of a geologist working in Tripoli, who received a call at the office warning of a home invasion that could put his family at risk. He had received a tip from a neighbour, and immediately headed home. “I locked myself in the apartment,” he explains. “My wife had already been sent away by one of other tenants who had seen what was going on. My children were at school.”

Soon a large group of uniformed and plainclothes people arrived at the complex demanding access to the apartments, and he heard automatic rifle fire coming from the road. After breaking through the main complex gate, they managed to get security keys to the complex, and then pilfered apartments belonging to the mostly western residents. “The invaders carried side arms and automatic weapons,” he says. “This was most disconcerting for me.”

The invasion clearly had government support. His apartment seized, he and his family returned to Alberta in disgust. He soon accepted another job as a petroleum geologist in the Persian Gulf.

Atrocities
Of course, what happens to Western expatriates is less severe than what can happen to rebellious Libyan nationals. A video on CBC’s website describes a recent outrage through the voice of eyewitness Arif Pervez.

Pervez was working on a horizontal drilling project for Waha Oil Company – a joint venture owned by Libya’s National Oil Company, ConocoPhillips, Marathon and Amerada Hess. Shortly after fighting began in other parts of Libya, a military plane landed at the airstrip near Jalu, a small oasis village. Soldiers rounded up oil workers and locals, according to Pervez, then randomly selected two villagers and beat them to death.

Here is how one of them met his end: “Four men were there to torture him” said Pervez. “One was holding his hands, one was holding his feet, and they started beating him with a piece of wood, and he was shouting, screaming and crying. Then they poured benzene or gasoline on him and started burning him. He started shouting a lot, so they continued beating him. Then he died.”

Another Canadian witness to that atrocity was Rick Souther of Taber, Alberta. This was Souther’s second revolution: he had been working in Iran when that country’s revolution began in 1979. When the fighting in Libya started, he was well-site supervisor for two horizontal development wells – 2,700 metres deep with a horizontal length of maybe 1,000 metres with the potential to produce 4,000 to 5,000 barrels per day.

He and Pervez were living in the Waha complex at Jalu – 200 kilometres from the Mediterranean and another hundred kilometres from the oilfield, which is in the burning desert sands. Souther says he and Pervez both witnessed the Jalu murders. Sickened and aware of the gathering danger, they began making plans to leave. Souther first called Canada’s foreign affairs bureau which advised him not to leave the village because Tripoli was too dangerous. “‘Lady, we’ve got no food, no water.’ I told her. ‘If we stay here the villagers are going to make us fight. There’s no sitting on the fence.’” They boarded a plane to Tripoli, but it took a week of bedlam before they could get out of the country.

A study in contrast
Compare these experiences to those of employees working for Canadian companies in Libya – Suncor’s expat workers, for example.

The Canadian energy giant operates a Libyan joint venture company in the Sahara. The company evacuated its own expat employees – about 100 people – quite early after the turmoil began. It then elected to evacuate contractors who worked directly for the company and expatriates who worked for contractors within the joint venture company. The company was quite focused on keeping its people safe and out of harm’s way. There were no questions about the financial resources required for pulling out.

“We had plans in place and contingencies,” according to Suncor’s Kelli Stevens, “but we had hoped we would never have to use them. This wasn’t a Suncor thing. It was a huge exercise in cooperation between Suncor and the (Canadian) government, other companies and other embassies. We ended up evacuating more than 200 people of more than 20 nationalities.”

Libyan nationals working for the joint venture remain in the country. However, with the exodus of Suncor staff and its joint venture contractors, field operations stopped. Suncor’s share of production was 34,700 barrels per day last year – about 6% of the company’s total production and 2% of total Libyan oil production.

Suncor’s Libyan assets are operated by a joint venture with the country’s National Oil Company along the lines of the Waha Oil Company model. Acquired through its merger with Petro-Canada, the company’s Libyan assets are technically known as “Exploration and Production Sharing Agreements.” Having invested $1.4 billion in its Libyan operations, the company acknowledged in May that it might have to write down some or even much of its investment.

Another Canadian company active in Libya also acted quickly to get its employees out. Calgary-based Pure Technologies Ltd was providing pipeline monitoring systems for what is known as the Great Man-Made River water supply project. The largest underground network of pipes and aqueducts in the world, this project consists of more than 1,300 wells supplying six and a half million cubic metres of fossil water each day to Libyan cities. Qaddafi once described the Great Man-Made River as the “eighth wonder of the world.” Like Suncor, Pure Technologies had safely evacuated its expat personnel by the end of February.

The business case for Libya
There isn’t much of a Canadian presence in Libya. As the turmoil began, only six Canadian companies had established themselves in the country. These included Montréal-based SNC-Lavalin, which is heavily involved with engineering and construction of the Great Man-Made River and other projects; Hyduke Energy Services and Caradan Chemicals (both based in Nisku, Alberta); Calgary-based Pure Technologies and producers Suncor Energy and Verenex Energy. Verenex sold out to a government-owned company two years ago, after a bitter dispute with the regime over a property the company had acquired in 2005 – a property with crude potential of some two billion barrels, as it turned out.

Formerly president and CEO of Caradan Chemicals, Dale Clemmer recently resigned that position. He is now president of the company’s international division, which he owns. His company provides oilfield chemicals for production and transportation – “chemicals for treating oil from well to tanker,” says Clemmer.

When the trouble began, he says, “We had employees there from Britain, Bosnia, and the Philippines” in addition to Libyan nationals. “My manager was in the desert at the time. He despatched the expats out of the country, and he was the last to leave. The Filipino had a wife and child there, but he was out of the country getting his visa renewed, so getting the family back together was a real challenge.” Although he stopped doing business in the country when the turmoil began, he kept his staff on small retainers.

“I think there will be regime change,” says Clemmer. “Everybody seems to want it, and there is great potential in that country. I have assets there, like computers and trucks, but (when things settle down) they will need chemicals to get restarted. The world needs the oil. We have been working there getting set up for two years. We’ve made sales, but we now have new systems and ideas in place. We were all ready to take new orders, but I’m really glad they didn’t come in before this started, because we would have a hard time collecting receivables.”

Clemmer believes in the country’s future. “Libya has a lot of potential,” he says, “thousands of kilometres of great beaches and not a single hotel on any of them.” Then he adds with a flourish, “I love the international side of operations. There’s so much potential there. Canadians are really appreciated and welcomed with open arms. There’s a lot we can do.”

Canada may have a small presence in Libya, but it isn’t for lack of trying. As the Arab Spring began, 70 Canadian companies were trying to develop business there. One of those companies is Calgary-based Western Petroleum Management (WPM).

“Before we made the decision to go into Libya we did our in-country evaluation of Libya,” according to Dennis Besler, president of WPM International Inc.’s Libyan branch. “We could see since 1998 a steady progression of change. Twelve years of progress was a major contributing factor to our decision.”

“I was in Canada when the revolution started,” he adds. “We were basically in the marketing mode, building contracts in Libya. Under Libyan law you have to hire Libyan staff. Practically speaking, you need Libyan staff to negotiate your way through the difficulties of working in the country.” Besler stays in touch with his staff in Tripoli by Skype or cell phone. “I know these people personally and consider them friends so my interest extends well beyond business.”

“We’re very busy in Canada, so I was lucky. When I left Libya I had a lot of work to do here. (Before the uprising began) there were maybe a million expats Libya-wide, and many of them had good jobs. Now those people, a lot of them, are out of work.”

Besler looks forward to returning to Libya. “We first need to see stability within the government and the country overall,” he says. “WPM does wish to share in the future of Libya but for now we wait, hoping for a quick resolution to the conflict. It is difficult to hear about the loss of life when you have spent time there. To a large degree we look forward to going back because Libyans are such a gracious people.”

The real surprise
One Canadian interviewed for this article works for a Libyan company based on western models. The Trans-Sahara Group is a Tripoli-based oil services and IT company owned by prominent western-educated Libyan business people; chairman Naaman el-Bouri, who formerly worked for a Swiss bank, is based in Logan, Switzerland.

Gamal Ghobrial’s story is an unusual one – not least because his wife Samia, who had been living with family in Egypt during that country’s insurrection, moved to Libya for relief from the stress. She arrived just before the Libyan upheaval began. “There was supposed to be a peaceful march in two days’ time” says Ghobrial, “but that wasn’t what it turned out to be. It quickly became an uprising.

Calgary-based Tarco International had hired Ghobrial to develop business in Libya, but closed the operation when the 2008 financial crisis hit. Fluent Arabic and a lifetime of experience in the energy service industry were both assets, and Ghobrial soon found himself working for Trans-Sahara.

“I personally have not witnessed brutality,” he says, “but Libya is not a reasonable place to live in for many reasons. Normal day-to-day life is very difficult; quality of life is poor for an oil-rich country. We lived in what was supposed to be a nice area, but the roads were dirt, the water came from a well and there was no sewer. We experienced power cuts. To live in a compound where you can have everything to a North American standard would cost you $7,000 to $10,000 per month.”

To illustrate Qaddafi’s frequently erratic behaviour, Ghobrial cites a 2009 diplomatic incident. Canada and many other Western countries were angry that Libya had given a hero’s welcome to the man convicted of the 1988 Lockerbie bombing. In protest, foreign minister Lawrence Cannon planned to rebuke Qaddafi when his plane landed for refuelling in St. John’s, Newfoundland. To avoid the incident, Qaddafi cancelled the stopover. “Every day under there were new rules for Canadians,” he says. For six months after that, “You couldn’t plan anything. You couldn’t even plan your visa issues. Work permits were very difficult.”

According to Ghobrial, “The leader Qaddafi and his family say ‘The oil revenue is for me and my family. You have nothing to do with it.’ Qaddafi himself looks after that. This is common knowledge for everyone living in Libya, and to people who work with international oil companies. Of course, I don’t have documents to prove it.”

When a service provider does work for the oil industry, he says, “It takes six to 12 months before you get paid. That’s because the National Oil Company produces the oil and then the revenue goes to the government, which produces a budget every year giving them less than they need to pay their bills. So they pay the bills that have to be paid immediately and just wait to pay the others.”

“Because (Libya) is a dictatorship, you mostly feel secure there,” he adds. “We only became scared when Saif al-Islam (Qaddafi’s son) gave his speech threatening everyone, and saying that everyone would be punished. Because we were foreigners with Canadian citizenship, we were afraid of being harassed by pro-Qaddafi Libyans. We didn’t live in a compound, so we were quite exposed to the public.” On February 25th he and Samia decided to leave. “Things were getting very dangerous.”

“I had registered with the Canadian government as a Canadian abroad, so they had the information they needed and we were prepared to leave. My friend who had gone to the airport with his two kids and his mother in a wheelchair called me at five the next morning to say ‘Nothing is moving, so look for an alternative.’” Only an hour later, though, the foreign office in Ottawa called to say there would be a flight. After a hair-raising ride with a driver they knew, they got to the airport, where confusion reigned. “There were two vans with Canadian flags on them. The ambassador was there, everything was extremely chaotic, and then the Canadian flight was cancelled for some reason.”

Two hundred Canadians were at the airport, but cooperation among countries contributed greatly to their evacuation. Ghobrial speaks highly of the efforts of Canadian ambassador Sandra McCardell, who left the country the same day. “Some of the people went on a Brazilian flight, some went to Gatwick (London) on a British flight and we were lucky to go to Malta on a fixed-wing plane that serves the oil teams.”

Until things settle, Ghobrial and his family are enjoying the stability of Egypt.

Where is Libya headed? Everyone interviewed for this article had a sense of optimism about the country’s future. According to another senior person who requested anonymity, “The brutality (of recent events) doesn’t surprise me, because I have seen that before. What has surprised me is the success of the uprising. The low rates of pay and Libya’s other efforts to keep these people subdued…the people just said it wasn’t right. They didn’t want to be treated as third-class citizens anymore. The successes of the Arab Spring are the real surprise.”

The Leader

Rarely ever did an individual have such a singular force on a global industry as Muammar al-Qaddafi, who began ruling Libya after a successful coup on September 1, 1969. Within months of his seizure of power he had broken the pricing power which had long been asserted by large international oil companies. The result was a petroleum world which rapidly became unlike anything anyone could have imagined before.

In The Prize, his magisterial history of the global petroleum industry, Daniel Yergin describes what was to follow. Qaddafi “would plot and campaign endlessly against Israel, Zionism, other Arab states, and the West, and – equipped with huge oil revenues – he would become banker, sponsor, and paymaster for many terrorist groups around the world.” Today he is known as “the leader,” although he doesn’t hold formal office.

Rocketing oil prices were the hallmark of the 1970s, to a very large extent because of Qaddafi’s mischief and machinations. He made Libya a key player in the 1973 Yom Kippur War and the related oil price shock. Triggered by an embargo of Arab oil to countries supporting Israel, this crisis put OPEC firmly in control of prices for a decade and led to the nationalization of the petroleum industry within OPEC and beyond.

As his rule presumably comes to an end, Qaddafi’s final gift to the world is – you guessed it – higher oil prices. By using brutality to try to retain power, he has caused great damage to the Libyan oil industry and taken 1.6 million barrels per day out of the market. Once the turmoil is over, it will take years to return the country’s production to pre-revolutionary levels. The experiences of Iran, the Soviet Union, Venezuela and Iraq all demonstrate that this is so. Don’t expect WTI prices to soon drop to $86 – the low in mid-February, before the revolution got ugly.

Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.