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.

In-situ Step-change

How underground shafts and tunnels changed the future of the oilsands

This article appears in the December issue of Oilsands Review

By Peter McKenzie-Brown

The year was 1976 and the place was a small town called Yarega – about 600 miles northeast of Moscow, near the Arctic Circle. A group of Albertans had gone there to observe a Soviet “oil mine.”

The Soviets had constructed shafts and tunnels into a heavy oil reservoir. Local workers were pumping steam into the reservoir through angled drill holes and production was taking place within the mine. A mining engineer among the Canadians, Gerry Stephenson, describes the project: “The wells that were injecting steam were drilled from an upper level of tunnel, which was above the heavy oil reservoir. So the injection wells were drilled from above but from tunnels. The recovery wells were drilled from tunnels below.”

According to Maurice Carrigy, vice-chair of the Alberta Oil Sands Technology and Research Agency (AOSTRA), “They had a tap, you know like a tap you would see in plumbing, a bathroom tap, and they would turn that on and off to get the oil out.”

Chronically short of cash, the USSR was hoping to sell the technology to the Canadian oil industry. The visit in part reflected a 1972 technology-sharing agreement between Canada and the USSR – one that collapsed in ‘78 when Canada expelled 13 Soviet officials for trying to infiltrate national security services.

The Canadians were not impressed with the oil mine, but they were intrigued. According to Carrigy, it led to a “total revolution in the concept of what you could do with bitumen that you couldn’t do in a traditional reservoir.… You got (the bitumen) into a form where it was either emulsified or liquefied so that you could produce it.”

At least one other group of Canadians had visited a Soviet oil mine. Hugh Lieper, who chaired Canada’s petroleum committee for the technology sharing agreement, also visited one in 1976. He describes being hoisted 800 feet into the mine in an elevator that swung wildly from side to side. At the bottom of the shaft, he found the oil being collected in a large open pit on the operations floor. “When I asked whether the electrical motors on the site were explosion-proof, no one knew what I was talking about.”

AOSTRA’s Carrigy puts the impact of his group’s visit to the Yarega oil mine in perspective. While Canada didn’t use the primitive Soviet technology, it gave credibility to “the idea that we could go below (an oilsands reservoir) instead of working from above.” That way “we could use gravity as the driver in getting the oil out. That would be natural. It would come down and flow in and then we’d take it from below rather than pulling it up to the surface.”

Adds Stephenson, “the system was definitely working, but the mine was very, very primitive. The tunnels were tiny. They weren’t mechanized at all. The piping systems were not much better than you would find in your garden. But it demonstrated that if you heat heavy oil, it will mobilize, it will be possible then to drain it, and if you put in wellheads below the reservoir, you will get production without pumping.”

The Mac of SAGD
A few years after the Canadian expeditions to the USSR, the legendary Roger Butler began developing the two-well SAGD concept, which eventually took the form in use today: injecting steam into a horizontal well and collecting oil through a parallel well below. Clem Bowman, who worked at Imperial Oil with Butler, says he actually developed the theoretical model for SAGD in the early 1970s. However Chi-Tak Yee, who was Butler’s first graduate student at the University of Calgary, says he once saw a document dated 1969 in which Butler had sketched out his preliminary ideas.

Whatever the facts of the matter, in the early 1980s the time was ripe for radical experimentation.

The AOSTRA’s first chairman, Bowman picks up the story. According to him, one day Gerry Stephenson came into his office and said “The oil companies have got it all wrong. The idea of drilling vertical wells into the oilsands and only contacting the pay zone for the few metres where there’s bitumen and having to put multiple wells down in these grid patterns just doesn’t make sense. I’m a mining man and the logical thing to do in a mine is to put down a shaft and to drill horizontal wells from that shaft and then every foot of well that’s drilled is in the pay zone.” Stephenson added that he had gone to the oil companies with this idea without success.

“And so he came to my office and sat there and made his plea that we should build a facility, put down a shaft and he had worked out what the costs would be,” Bowman continued. “According to his numbers, drilling a shaft into the deposit is not an expensive operation and the coal companies know how to handle methane in spades. So we put together a concept called the Underground Test Facility. No oil company would put any money into it but (petroleum executives on AOSTRA’s board) said they would support it technically and they’d have people help us on it.” For the only time in its history, the government agency paid full fare – and for what seemed a most speculative idea. Total budget for shafts, tunnels and infrastructure was about $30 million.

As Bowman continues, “It seemed this was the obvious time to test (Roger Butler’s) principle of gravity drainage.” Butler had left Imperial oil to become part of AOSTRA, and he became a member of the technical team. Maurice Carrigy was the project executive. Today a vice president of MEG Energy, Chi-Tak Yee says that “one of the most fortunate things that I was involved with was the Underground Test Facility project that was essentially the birthplace of SAGD. Think of (the UTF) as the Mac of SAGD development.”

First photo taken under the oilsands;
Stephenson in centre

According to Carrigy, “although we did contemplate going right into the oil sands, we thought it would be better to go down below the oil sands, put the tunnels in a secure and safe place” – a layer of limestone – “and then drill upwards” into the reservoir.

The magnitude of the UTF is hard to imagine. Sinking the shafts was done with a drill bit almost four metres in diameter weighing 230 tonnes. The two shafts were 223 metres deep and neither one deviated from the vertical by more than an inch. As a safety measure, AOSTRA constructed two parallel tunnels through the limestone. More than a kilometre in length, the tunnels were five metres wide by four metres high.

A Subway to the Wellhead

At the UTF’s official opening on June 29th 1987, a senior executive at Shell Canada – up to that time he had been a critic of the project – went to Stephenson and said, “It’s really not a mine, Gerry, is it? This is really impressive. It’s like a subway to the wellhead.”

Then came the tests. The Phase A pilot involved three well pairs 70 metres in length, each with 40-50 metres of exposure to the McMurray formation. According to Stephenson, “steam was injected and the first experiment with SAGD wells began. After a year or so, it was obvious the system was working.”

That was the beginning of a turnaround within the industry, which soon decided to get financially involved. Ten companies each contributed $16 million to the project. That funding enabled the test crew to complete Phase A and to move on to Phase B. It also funded several years of additional experimentation.

Phase B involved another three well pairs, 70 metres apart. According to Stephenson, “the effective length in the reservoir was 500 or 550 metres. They resembled a commercial development” despite having only three producing well pairs. Project engineers expected production to reach about 1,800 barrels a day.

What was the result? “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place,” he says. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area that we’d expected, so obviously we didn’t need to drill the well pairs as close together on Phase B as we did on Phase A, so we opened them up. Anyway, on Phase A the figures were 65 percent recovery – way beyond what we’d estimated. Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The petroleum industry soon began to develop SAGD projects from well pads. According to Stephenson, however, there are many reasons why SAGD is better done from tunnels underground. “You don’t disturb the surface to the same extent. You can use gravity to your full advantage.” And, he adds, surface schemes require a high-capacity, expensive pump for each producing well. They cost a lot to buy and a lot to service.

Also, he says, “it costs more to pump through a multitude of  8-inch pipelines than it does through a single 18-inch pipeline in a shaft. Another advantage is that you can drill more accurately from underground, and you get better recovery because you can use lower steam pressures. Your production might not be quite as high, but your recovery of the bitumen is going to be better, because you’re allowing a slow process of heat soaking upwards by thermal conductivity.”

He claims still other advantages for the system. “You’re operating in an underground climate in a tunnel. You're doing all your drilling and completion of wells as well as your process manipulation work in a safe working environment at a temperature of 58 F year round and with no snow and ice to hinder and delay your work. You can operate 24 hours a day, 365 days a year, instead of being confined with your drilling and your completions to those periods when you can drill on the muskeg and so on. You can do all these things in a safe environment that allows you to work all year long.”

A visionary but not a dreamer, Stephenson acknowledges that the system also has disadvantages. One is the need for upfront capital: until you’ve constructed the shafts and tunnels you can’t do any drilling at all. Also, of course, some reservoirs simply don’t have the geological features needed to make the system work.

In the latter 1990s the UTF was acquired by Devon Energy, which then sold it to Petro-Canada. When Suncor Energy acquired Petro-Canada, it also acquired the UTF – now known internally as its “Devon Project.” Petro-Canada developed abandonment plans for the facility, and unconfirmed reports say the ERCB approved them. It’s still intact, ‘though its future is in question. 

A Numbers Game

Photo from here; this article appears in the September issue of Oilweek

For Devon Canada's Cal Watson, coaxing maximum output from heavy oil and bitumen deposits is all about optimizing your operating metrics

By Peter McKenzie-Brown

For Cal Watson, it’s all about the numbers, but here’s one number he doesn’t mention. Devon Energy Canada is number 3 on the 2011 list of Canada’s Best Workplaces (those with more than 1,000 employees). It’s the third year in a row Devon’s been on the list, and it’s the only oil company to be found there. The numbers for this list are crunched by an international research and management consultancy.

The articulate and motivated vice president of thermal operations at Devon Canada is more concerned about other numbers: “In every measurable metric – land use, water use, air, operating expenditures, plant on-stream time, production – our focus and philosophy is to be a top-decile company.” He then cautions, “You can focus on one or two (numbers) and sacrifice the others. We aren’t willing to do that.”

You need to be wary of this kind of statement; it’s often the voice of a company delivering its “messages” to a reporter. Indeed, at the risk of presenting an unpardonable groaner you might say, “elementary, my dear Watson.” However, as we discuss the details of Devon’s Jackfish SAGD projects, it soon becomes clear that in the area of thermal operations Watson is serious indeed. The exciting part is that his numbers represent a sophisticated integration of production into a shrinking environmental footprint.

Background

Born near the heavy oil centre of Lloydminster on a mixed farm in Saskatchewan, fifty-year-old Watson seems almost destined to find himself operating in heavy oil and the oilsands. He earned his B.Sc. in engineering in 1985. On graduation he soon found himself doing reservoir engineering for Husky Energy – far and away Lloydminster’s largest oil industry employer and at the time the largest conventional heavy oil producer in Canada.

As part of a move toward greater centralization, after Husky’s acquisition of Canterra Energy he was transferred to Calgary in the 90s. His new assignments included more work in reservoir engineering (including duties in deep Foothills gas) and three years as a gas marketer.

He was then lured into the employ of Ulster Petroleum, a junior, but found his career buffeted onward by still more corporate acquisitions. Anderson Petroleum bought Ulster. Then Devon bought Anderson. He thus found himself working for one of the relatively few North American oil producers not headquartered in Houston or Calgary. Devon is based in Oklahoma City.

As these events unfolded, Watson began receiving promotions into managerial positions – Central and Southern Plains with Anderson; then, with Devon, combined responsibility for the Foothills Division and a highly technical reservoir engineering group. In 2008, he moved into thermal heavy oil. For the first time, he shifted from exploitation into an operations role with appointments as thermal heavy oil operations manager and, recently, vice president.

He focused on the interrelated issues of “increased operability and reliability.” To illustrate his concern, he notes that in Calgary “we take reliable power for granted because we are part of a grid. (In northeastern Alberta) you have one power line to a facility. The line goes down and that’s all you’ve got; the facility may need to shut down. We are constantly looking at ways to increase reliability. Improved reliability and operability are the fundamental building blocks of a more efficient process. They increase efficiency.”

Jackfish

As an operations guy, Watson found himself with responsibility for Jackfish 1 – a SAGD project that started steaming in August 2007 and began producing at the end of that year. For the first five months of this year, the project’s uptime was a remarkable 98%.

Designed to produce 35,000 barrels per day, in recent months for brief periods it has produced up to 37,500 barrels per day. Until that happened, did he actually think the equipment used in that project could exceed design capacity? Of course. “The equipment is subject to whatever SOR (steam/oil ratio) you can achieve. If you can get an SOR lower than 2.65, you have the opportunity to produce more barrels. The front-end capacity of our facilities is up to 50,000 barrels per day. If we can get the SOR down to the 2.4 range for example, we could certainly hit 40,000 barrels per day production.”

As always, it’s all about the numbers.

When Jackfish 1 went on production it quickly became a big part of the company’s production portfolio. At this writing, Devon Canada produces about 195,000 barrels of oil equivalent (BOE) per day. Jackfish production contributes about 18% of the total. Capital expenditures for the project (including start up) were $620 million – about $18,000 per daily flowing barrel. Today those numbers seem pretty bargain basement.

Consider, for example, that Devon’s sister project, Jackfish 2, involved capital spending of $1 billion. Jackfish 2 started steaming in May of this year. When production reaches design capacity next year, the facility will represent another big piece of Devon’s production portfolio. With Jackfish 2 on stream, Devon Canada’s total production will be 230,000 BOEs per day, and the combined Jackfish projects will represent 30% of the total.

The disparity in costs notwithstanding, Watson says the major components of the two Jackfish projects “are exactly the same. However, for Jackfish 2 we took 1,100 changes into the design – changes related to instrumentation and valving, for example, and measurement points.” Those changes were clearly not made to cut costs; their aim was to “increase operability and reliability.”

While capital costs are up, other expenses are down – notably fuel gas prices since Jackfish 1 went on stream. Even so, the company is constantly focused on better heat integration. “That means you conserve heat, putting it at the end of the plant where you can preheat the water going into the boilers. That way you need less fuel gas to generate steam; it gives you a better fuel efficiency number.”

Fuel prices excluded, operating costs for these projects are only $7 per barrel of production. In addition, there are some economies of scale in having two similar projects 5 miles apart on stream at the same time. There is little sharing of labour at the field level. Each facility has 85 dedicated staff in its own camp. From a district level, however, the two projects benefit from shared services. Watson rattles him off: “Camp (the company will soon house most staff in a single camp), safety, asset integrity, transportation and procurement.”

 

Devon has plans to add Jackfish 3 to its oilsands collective; the company made its submission to regulators a year ago. Today the company is in the detailed engineering and design phase. “We have done procurement for long-lead items like steam generators and long-term contracts have been let,” Watson says. “The kit’s being built. We expect approval at the end of this year or in early 2012.” If all goes according to plan, the project would start steaming in late 2014 or 2015.

Staying the Status Quo

Throughout the technical part of our discussion, Cal Watson was upbeat and focused. However, when we turned to environmental questions something new entered the discussion. It was almost as though the issues became personal. We began by talking about water policy. “Our goal is to meet and exceed regulatory thresholds,” he says, and in this there is nothing new. Then he adds, “Staying the status quo means you are falling behind. Reducing our footprint out there makes a difference.” This seems real.

On Devon’s corporate website, however, there is an article about the company’s decision to use saline water for steam generation. I find the article a bit misleading, because it neglects to mention that using potable water really isn’t an option for SAGD projects. I put the question to Watson, who confirms that using “saline water has not been a significant problem for us at all.” But, he adds, “Water usage as a whole is a sensitive issue.”

According to Watson, when Devon began planning for the project CEO Chris Seasons challenged the design team “to come up with a design that would use no potable water at all. We sent our hydro-geologist out to drill for water and he came up with good source that was saline, so our design team looked for ways to remove solids, hardness, remove magnesium and calcium and do whatever else we needed to do to make it adequate for steam gen. From the beginning, we set our minds to doing that.”

To appreciate the challenge the company faced, consider that regulators define potable water as water with dissolved solids of 4,000 ppm (parts per million) or less. That is setting the bar high for potability – water for human or agricultural use. “We have a source that’s 6,500 ppm,” Watson continues. “Our facility works fine on that. We have also found a higher concentration source (on the property. We did a 6-week test with 12,000 and 14,000 ppm, and that worked just fine, too.”

While Devon may have had little trouble with using saline water, its peers have recognized the company’s efforts. On two occasions the company received water-related CAPP awards. One was a stewardship award for its use of saline water at Jackfish. The other was the CAPP President’s Award for its elegant water policy. This masterfully concise document presents comprehensive policy in eight bullet points.

Wolf Packs

CAPP also presented the company with an environmental performance award for reducing the width of access roads in forested areas and for using waste wood in road construction. Not only has the company has reduced its seismic right-of-way in the forest. The company mulches up waste from the cuts and puts the mulch back on the right-of-way. “In a year or two you can hardly recognize we were ever there.”

This is important because traditional seismic lines present wolf packs with a combination of fast pathways through the bush and line of sight to their prey. To level the playing field, Devon “is adding a saw-tooth every 300 metres to eliminate line of sight and narrowing the right-of-way. Going to hand-cut seismic takes away the ability (of predators) to move quickly through the bush.”

Devon plans to use “less than 15% of our leases during our development – never more than 15%,” according to Watson; “Our goal is to reduce that down. (We will do that through) progressive reclamation of seismic lines and well pads over the full life of the project. As the older pads start to decline, we bring on new pads.” Using that strategy, he calculates that each Jackfish project can “hold production flat for 15 years plus.”

He has other ideas for narrowing the footprint, one of which involves the use of solvent. “We want to try injecting it with our steam. Solvent could increase the size of the steam chamber when it mixes with the bitumen. If solvent enables us to expand the size of our steam chamber, that allows us in the future to push those inter-well spacings out, so we have to drill fewer well pads, or can drill longer horizontal wells and fewer of them.” It could also increase recovery, which is already 65%.

Like the oilsands industry itself, Watson is keenly optimistic about the growing ability of technology to mitigate the environmental impacts of oilsands production. “There are a lot of bright minds out there focused on creating technological advances that simultaneously reduce the footprint and increase production,” he says, citing horizontal drilling and MWD (measurement while drilling). “These have been huge technological developments – they mean we can lower our impact by drilling out as a crow’s foot.” Then there is “a ceramic membrane technology to improve fluid separation, (thereby presenting the) opportunity to develop much greater recovery.” He would continue, but this reporter’s mind by now is overflowing.

If Cal Watson has one big idea, what is it? Perhaps it’s all about numbers. While he provides endless detail about the Jackfish projects, to explain the challenges those projects are facing he constantly comes back to simple metrics – numbers that influence both production and the footprint.

Don’t forget: “You can focus on one or two (numbers) and sacrifice the others. We aren’t willing to do that.