Thursday, August 30, 2012

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 19th 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.
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