Canadian energy authorities have done it again. They missed their last rosy projection of future oil sands production, so they issued a new one: they merely pushed the big surge in production 5 years into the future.
On November 3 Canadian Energy Research Institute (CERI) released a study that shows Alberta oil sands production soaring to 4.5 million b/d by 2030 and growing toward a peak of 5.3 million b/d in 2041. Actual production in 2008 was 1.3 million b/d.
We’ve heard this song before. In 2005, the burr under ASPO-USA’s saddle, Cambridge Energy Research Associates (CERA), issued a similarly glowing projection that the productive capacity of Canadian oil sands (more descriptively, tar sands) would grow from 1.18 million b/d in 2005, to 2.3 million b/d in 2010, 2.7 million in 2012, and a phenomenal 4.8 million in 2020.
In April 2006 I wrote A ‘Sanity Check’ on Projections for Canadian Oil Sands Production as a Commentary in this newsletter. My conclusion was that the oil sands industry would do well to match the pace of growth they achieved during 1995-2005 when they added about 60,000 b/d of production each year. At that pace, product from Canadian oil sands would be about 1.5 million b/d in 2010. I anticipated that bottlenecks in the extremely resource-intensive train of processes would slow the growth of output to 1.6 million b/d in 2015.
The graph here summarizes the history of actual oil sands production, the 2005 projection by CERA, and the 2009 projection by CERI, the Canadian group.
CERA is fond of saying that growth of productive capacity is determined by “above-ground factors,” rather than geology (below-ground factors). For oil sands expansion, above-ground factors center on massive investments for processing and extraction infrastructure, mining equipment, and sufficient fuel to power this gigantic enterprise. However, CERA misses the point that the industry often tailors their investments to match the physical resources that are available. Companies announce grand plans for new projects, CERA gets turned on, and issues its projections based on the sum total of all announced projects. But many projects are delayed, scaled down, or dropped. Companies usually point to financing arrangements as the bottleneck, whereas an unexplained resource-based factor often leads to the breakdown in financing.
The most energy-intensive processes of the oil sands industry are summarized here:
- King Kong-sized mining equipment gobbles prodigious volumes of diesel fuel to excavate cubic kilometers of overburden and tarry rock.
- Sprawling processing plants chemically extract tar from crushed rock in house-sized vats.
- Billions of gallons of water fill the vats to separate tar from the rock.
- Fuel heats all that water to near boiling to melt out the tar.
- Rock and water are dumped into lake-sized tailings ponds.
- Cities of steam generators transfer heat to injection wells that melt bitumen out of the subsurface.
- Special processing plants (upgraders) break up oversized bitumen and tar molecules to make synthetic crude oil.
Semi-solid bitumen or tar is diluted with light oil so that it can be pumped to distant upgraders. Diluent has been in short supply for years, which limits how far and how much raw oil can be pumped to upgraders. The industry is now trying to locate upgrading plants within the oil sands region, but such revisions slow down expansions.
The horse that pulls this wagon is fuel supply. Natural gas is the fuel of choice for tar and bitumen extraction and upgrading. Heat to extract tar or bitumen from the highest quality formations requires about 1,000 cubic feet of gas per barrel of product. Upgrading consumes another 1,000 cu ft/bbl. Thus, increasing tar sands production by 1 million b/d consumes at least 2 billion cu ft more per day, about 15% of Canada’s gas production. But Canadian gas production peaked in 2004; fell by 14% in 2005, and 2% or 3%/year since then. Evidently Canada’s shale gas formations are not as productive as the Barnett, Fayetteville, and Haynesville shale formations in the southern U.S.
Another point of caution: Canada’s multi-billion dollar project to build the Mackenzie Valley pipeline is on life support. The pipeline would transport gas from the frozen tundra of the Mackenzie River delta and the ice-choked waters of the Beaufort Sea to the lower provinces, not far from the oil sands. Gas is unlikely to flow before 2020.
But never fear, nuclear is here. In mid-2007, Energy Alberta Corp. applied for a license for site preparation near Peace River in the middle of tar sands country. Four deuterium/uranium reactors would yield enough heat to generate 2.2 GW of electricity. Operation could begin as early as 2017 to turn uranium into oil.
What’s a reasonable forecast for tar sands oil production? Under favorable economic conditions the industry could maintain the annual growth rate that they achieved during 1995-2005, about 65,000
b/d per year. But they’ll need a growing supply of natural gas for fuel. Eventually the rate-limiting bottlenecks of natural gas, water, and diluent will place a ceiling on synthetic oil production. My view is that the industry will have difficulty sustaining production much beyond 2 million b/d, and will not likely reach that lofty level until 2020.
CERI has issued a projection that cleverly remains within the realm of reality through 2015, long enough for them to look credible. But for 2020, they veer off the rails. By 2030 their projection is so far off the map that it borders on being irresponsible. Political leaders and financiers with insufficient background to evaluate potential bottlenecks might be taken in by the cornucopian projection, leading to unwise economic decisions.
CERI’s scenario acknowledges that the industry may have to pay billions of dollars annually for emitting increasing levels of carbon. They also recognize that tar sands gas consumption would increase by a factor of 3 or 4. A real kick is that their scenario calls for importing natural gas from the U.S.! Who among us believes that will ever happen?
Tom Standing is an engineer with 44 years of experience in the energy sector in both chemical and civil disciplines. He continues to use his background to assess many developments taking place in the energy sector. He has contributed numerous Commentaries to Peak Oil Review.
(Note: Commentaries do not necessarily represent ASPO-USA’s positions; they are personal statements and observations by informed commentators.)