Ramped up to its full potential in the oil sands, cogeneration could be an environmental game changer
BY NICK WILSON
ATCO power has built 608MW of cogeneration power capacity in the oil sands with plants similar to this one
Combined heat and power generation, or “cogeneration,” is clean power’s unsung hero. And the oil sands are its ground zero, supplying about 50 percent of Alberta’s 4,821 megawatts of electrical capacity, and pushing the province to the top of Canada’s “cogen” table. It’s not just ultra-efficient; it can be lucrative too. Oil sands operators have earned as much as $2.43 per barrel from power sales to the electricity grid. They have in their hands a powerful tool to slash the power sector’s greenhouse gas (GHG) emissions by 46 percent if cogen is used to its full potential, according to a report by the Oil Sands Community Alliance (OSCA). They could do so by displacing dirtier coal-fired power. Although market uncertainty and a lack of supporting infrastructure are currently holding them back from upping their game, new carbon pricing and regulations are giving this old technology a shove in the back.
Alberta started championing cogen decades ago. Oil sands companies invested heavily in cogen and transmission lines in the 1970s as the northeast region severely lacked infrastructure. The deregulation of the power market in the late 1990s provided further stimulus. Suncor, for example, sells about 250 MW into the power pool. According to one analysis, cogen helped reduce electricity generation-related GHG emissions in Alberta by 50 percent between 1996 and 2006. Cogen plants really come into their own when they’re built next to a host building that needs both power and heat, the latter of which is lost in conventional gas-fired plants. The most efficient gas-fired power plant is a combined cycle plant, which operates at up to 60 percent efficiency compared to a coal-fired plant at 40 percent, typically. Still, gas-fired cogen plants surge past both, hitting 80 to 90 percent efficiency.
A typical oil sands cogen plant captures exhaust heat from the gas turbine in a boiler or steam generator, sending low-pressure steam to a neighboring bitumen plant. The electricity generated is transmitted more efficiently than standard utility power plants as proximity to the source avoids the line losses that plague long-distance power generation. Furthermore, the host building and power plant can share cooling water, compressed air and water treatment, boosting efficiency even more.
Terry Abel, the oil sands director at the Canadian Association of Petroleum Producers (CAPP), says both mining and in situ operations need a lot of heat for their processes, especially if they’re connected to an upgrader. “They need way more heat than power, and it’s this heat that creates the surplus power potential that could be exported to the grid,” Abel says.
Most oil sands cogen units connect to the power grid to provide backup electricity during maintenance. Others, however, lack transmission lines and distributors’ permission to hook up. The report from OSCA, a group of 25 industry and community organizations that develop infrastructure, communities and workforces in the oil sands, says unreliability of the grid is the prime driver behind oil sands operators building cogen plants, followed by the planned eye-watering price hikes in buying power from it.
The grid operator, Alberta Electric System Operator (AESO), projects the cost of electricity—the commodity plus the transmission charges—for large industrial users will rise an average of five percent per year for the next 10 years. The previous government planned these hikes to pay for its buildout of power capacity and transmission infrastructure. The transmission tariff is the part that’s squeezing buyers the most as it soars from $21 per megawatt hour in 2013 to $37 by 2023—a leap of almost 75 percent. “If on-site cogeneration can be developed and operated for a lower [dollars-per-megawatt-hour] rate than the delivered price of power, projected to reach almost $135/MWh by 2023, there would be an economic incentive to build cogeneration,” the OSCA report says. Furthermore, by 2020 there will be a significant transmission build, including two new 500kV lines from the Edmonton area to Fort McMurray, widening the export gateway.
The current government’s carbon levy hike and cap on carbon emissions from the oil sands collectively can produce are a powerful push to cash in on carbon offsets. “The previous $10/ton carbon levy on oil sands producers wasn’t enough to drive development,” says Bradford Griffin, executive director of the Vancouver-based Canadian Industrial Energy End-Use Data and Analysis Centre.
The government is targeting oil sands operators, which account for roughly one-quarter of Alberta’s annual carbon emissions, pumping out about 70 megatons per year, which the government is capping at 100 MT per year. The government is already working out provisions for cogen, another factor holding up immediate investment. The carbon levy is another weapon in the climate change armory. Introduced by the previous government, it is currently based on each individual facility’s historical emissions, and does not take into account how efficient it has been since. The NDP government is boosting the levy to $30/ton based on results already achieved by high-performing facilities. Cogen plants also earn carbon credits per MWh based on a formula established by the environment ministry.
Another opportunity comes from the phase-out of coal power. Under federal rules set by the government of former prime minister Stephen Harper in 2011, coal-fired power plants must meet GHG emissions standards matching the most efficient conventional gas-fired power plant, or retire once they’ve been operating for 50 years. So, under that law, 12 of Alberta’s 18 coal-fired generating plants will close by 2030, and the provincial government aims to close the remaining six by then too. Under Alberta’s Climate Leadership Plan, 60 percent of coal-fired capacity will be replaced by renewable energy and 40 percent by natural gas-fired electricity, opening the door for cogen. Former premier Jim Prentice, who had earlier been Harper’s environment minister, also planned to close many Albertan coal plants and replace them with renewable energy.
Energy Minister Marg McCuaig-Boyd says, “Alberta continues to look for more use of renewable energy and more efficient use of energy resources as we phase out coal fired generation. Generally, the key incentives for use of co-generation are the efficiencies and cost savings that users realize. Cogeneration will likely be one of the topics of interest as part of the government’s public and stakeholder engagement on energy efficiency through the recently formed Energy Efficiency Advisory Panel. The Panel will produce a report to the Minister Responsible for the Climate Change Office in the fall of 2016.” Subsequent policies will determine any price impact—if the cost of supporting renewables is picked up by taxpayers or consumers.
Each of the three main oil sands regions, Peace River, Athabasca, and Cold Lake, has its own supply-demand balance that determines if it’s a net importer or exporter. Athabasca has the most oil sands projects and is the biggest net exporter. Oil firms sell about a quarter of their 2,100-plus MW of cogen power into the northeast region, helping its development.
Suncor, already one of the top five power generators in the province due to its cogen plants, plans to build wind and solar farms in southern Alberta. Its facilities include five cogen systems at its Firebag in situ operations, totaling 425 MW, and 165 MW of contract cogen capacity at its Base Plant and MacKay River in situ facility. In 2015, Suncor swapped assets with TransAlta, exchanging Suncor’s 20 MW Kent Breeze plant in Ontario and its share of the 88 MW Wintering Hills facility in Alberta for TransAlta’s Poplar Creek cogen units and related infrastructure.
MEG Energy also exports cogen electricity, sending about 85 percent of the power produced from its 170 MW cogen capacity. Its power sales revenues slumped to $0.82 per barrel in Q1 2016, but have been as high as $2.43 over the past two years. “We are looking at the potential to add a new unit of similar size,” says Brad Bellows, former spokesperson for MEG. “But in the current capital-constrained environment, it is not on the immediate radar.”
Plummeting electricity prices also hang a question mark over a short-term cogen build-out. Mitchell Pomphrey, CEO of Pomphrey Industries, a technology and service provider says, “The recent AESO pool price has dropped to almost $15/MWh—there’s no incentive right now for anyone to invest in selling any kind of energy directly.”
Oil sands operators can offset that risk by signing up for long-term power contracts without investing in plants. Shell’s 170MW cogen plant provides steam and electricity to the 155,000 b/d Athabasca Oilsands upgrader at Scotford, Northeast of Edmonton in Alberta’s Industrial Heartland. ATCO Power is the operator and 100-percent owner. One third of its power goes to the grid. The upgrader is a joint venture between Shell, Chevron, CNRL and Western Oilsands. CNRL also operates 115MW and 84MW cogen units at its in situ operations at Wolf Lake, Primrose and Horizon—where this year it’s bringing on stream a second 85MW cogen plant.
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