Escaping energy silos

Emissions reductions are possible by integrating the twin energy silos of thermal bitumen production and thermal power generation

A University of Calgary (U of C) energy and environmental professor and researcher believes oil and gas prices will stay low for many years, making it necessary for industry and Canadian policy makers to view energy in a new way and maximize the efficiency of both energy and power production.

David Layzell heads a new U of C–based body called the Canadian Energy Systems Analysis Research (CESAR) initiative, which develops sophisticated computer models that measure past and current energy systems in Canada and project possible energy futures based on technological, policy and behavioural choices. A recent projection foresees a radically different future for the Alberta oilsands than has been assumed by policy makers in the past, he says.

That projection points to the need for a new, more integrated approach to oilsands and energy development overall in Canada, says Layzell, a former Queen’s University professor, a fellow of the Royal Society of Canada and a former executive director of the Alberta-based Institute for Sustainable Energy, Environment and Economy (ISEEE).
“We’re saying that by 2020 oilsands production [growth] stops.”

While production would still grow from existing plants beyond that time frame to about 3.6 million bbls/d by 2040, up about 1.4 million bbls/d from current total production, it’s far below past projections by organizations such as the Canadian Association of Petroleum Producers (CAPP), which the Alberta government largely relies on for its forecasts.

In June, CAPP lowered its outlook significantly from past expectations in its annual production forecast, cutting in situ production by 835,000 bbls/d, mining output by 33,000 bbls/d and conventional crude production by 260,000 bbls/d.

Overall, that led to a forecast that Alberta oil production would rise to 5.3 million bbls/d by 2030 (including conventional production), up from current production of about 3.7 million bbls/d. But that was well below its June 2014 forecast, which suggested production in 2030 would average 6.4 million bbls/d.

Oilsands production will reach about 3.95 million bbls/d by 2030, according to CAPP’s normal case projection.

CESAR’s low oilsands projection of 3.6 million bbls/d by 2040 could have deep implications for both the Alberta and the Canadian economies, Layzell says. Gross provincial economic output will stagnate and population growth will slow, and it’s all largely because of the high cost of oilsands production and growing concerns about the high carbon footprint of bitumen development.

“We’re saying the oilsands is the high-cost producer,” Layzell says. “It’s the high capital cost [of oilsands production] that is at the root of the lower forecast. Our models say there would continue to be high oilsands growth [at oil prices of $100/bbl], based on the ability to get it to market.”

However, that isn’t the most likely scenario.

He says the big problem oilsands producers face will be reduced worldwide demand for crude. That will be caused by a shift to electrical vehicles and greater fuel efficiency in all parts of the global economy.

Low for longer
“Our projection is that oil prices stay in the $50–$60-[WTI] range for many years,” Layzell says. “At that price it’s hard to imagine capital being invested in oilsands projects.”

Greg Stringham, vice-president of markets and oilsands for CAPP, says that even though the group did provide a more pessimistic low case estimate that somewhat matches the CESAR estimate, projecting oilsands production will reach 2.97 million bbls/d by 2030, it’s unlikely North American crude prices will remain in the US$50–US$60/bbl-[WTI] range for decades, as the CESAR forecast suggests.

“[Layzell’s] biggest assumption is that prices stay low [for many years],” Stringham says, a projection that CAPP views as unlikely. Its most likely scenario has WTI averaging around US$80/bbl by 2020.

At US$50 WTI, CAPP sees no new oilsands projects, but existing ones would likely expand. At the US$80-and-up range, new projects would be built, which is why a much higher production forecast is more likely.

Stringham says few forecasters agree with CESAR’s extended low price forecast through 2060, and the group is making a mistake by suggesting that oilsands production is the costliest crude oil source. In fact, ultra-deep offshore production and gas-to-liquids production are both more costly than most oilsands production.

And CESAR doesn’t take into account the importance of oilsands reserves to major producers, with the long-lived nature of the oilsands being seen as their biggest asset.

Breaking down silos
Layzell and his colleagues at CESAR, mostly unpaid researchers from universities across Canada, developed the oilsands forecast using the Canadian Energy System Simulator (CanESS), a computer modelling software developed jointly by the U of C and Ottawa-based whatIf? Technologies because there was no agency in Canada that looked at energy use in a holistic manner.

The problem has long been that energy and power production and use has operated in silos, he says. Forecasts of either never stray too far outside each silo for factors influencing those forecasts.

The CESAR model, by contrast, digests data from Transport Canada, Statistics Canada, Agriculture Canada, other federal agencies and variou provincial bodies and develops scenarios that were never before considered.

“We have 800 variables that we can analyze,” Layzell says, and that range of inputs yields potential energy system adjustments that have never before been considered.

One such adjustment is a scenario that would see the heat generated to produce steam for SAGD production in the oilsands captured on a massive scale to produce cogenerated power (cogen).

Cogen is already used extensively in the oilsands to generate steam for use at SAGD projects, but Layzell and Manfred Klein, a CESAR associate, argue that much of that steam is wasted. Meanwhile, Alberta’s power grid relies overwhelmingly on coal-fired power plants and combined-cycle and single-cycle natural gas–fired power plants for its electricity.

Those coal-fired and natural gas–fired plants produce 46 million tonnes/year of CO2, which is more than 11 tonnes/capita. But because the thermal power generation is inefficient, it captures only about 30–50 per cent of the fossil fuel energy to produce power. The rest of the energy is lost as heat, ending up in the atmosphere or in water. In Alberta, this discarded heat adds up to 393 petajoules (PJ) a year, more than the energy used every year by all residential, commercial and institutional buildings in the province.

The CESAR researchers argue that most global jurisdictions that rely heavily on thermal power generation don’t have industries that could use all the discarded heat energy from power generation. It’s part of the price of having a reliable electricity supply.

But Alberta is different, thanks to all that SAGD production, which requires 408 PJ/year of heat energy to raise steam but also generates 24 million tonnes/year of CO2, or about six tonnes for each Albertan.

SAGD and power generation
Because SAGD producers and the electricity grid don’t talk to one another—almost all of the cogen capacity is used for steam and power production for specific plants—CESAR argues that it is an opportunity lost.

Layzell says it’s illogical to have one industry burning fossil fuel for power generation and essentially throwing away 393 PJ/year of heat energy, while another sector—those SAGD plants—burns more fossil fuels to generate 408 PJ/year of heat energy. He argues that in a world concerned about energy efficiency and climate change, this makes no sense.

“We need to integrate the SAGD and thermal electricity sectors in the province for the benefit of the environment and the economy,” Layzell says.

He says it would likely take cooperation between power generators and SAGD plant operators in Alberta to create an integrated system to use the cogen.

“Either that or they’d have to compete with one another,” he says.

However, oil companies aren’t comfortable entering the power sector, and it hasn’t been an attractive opportunity for them in the past. But in a world of continuing low oil prices, the companies might be interested in the option.

“That will be the case, especially if there’s a [higher] price on carbon,” he says.

Stringham says other industry groups, such as the Oil Sands Community Alliance, have taken a serious look at the prospect for widespread use of oilsands-based cogen as a power source in Alberta, and in fact, it is entirely possible that such integration will start to occur. What is needed, however, is policy direction from the provincial government.

CESAR isn’t the only forecasting group that has studied the potential of oilsands-related cogen. Calgary-based economics consultant EDC Associates reached basically the same conclusion in a study produced in May 2014.

Steaming toward efficiency
Its report, Full Steam Ahead, points out that Alberta’s power system already has about 4,500 megawatts (MW) of cogen capacity, representing about 35 per cent of the more than 16,000 MW of installed power capacity in the province. It argues that cogen achieves about 90 per cent energy efficiency, thanks to its creation of steam and power simultaneously, but that cogen is massively underutilized, even though most growth projections suggest installed cogen capacity in Alberta could grow to about 5,500 MW in the next seven years.

The EDC report argues electricity costs in the province would drop if cogen was more fully used, since cogen has an approximately 25 per cent cost advantage over combined-cycle gas power, which will gradually replace the province’s 6,271 MW of coal-fired generating capacity.

Layzell says CESAR’s integrated, analytical approach can lead to other higher-value energy uses.

For instance, Alberta’s large natural gas reserves could come to the aid of the oilsands sector.

“We could extract hydrogen from natural gas, which could be used along with oxygen for bitumen upgrading,” he says.

Layzell argues that it makes little sense from an economic and environmental standpoint to dilute bitumen with higher-value lighter fuels and send it by pipeline to U.S. upgraders.

“We’re losing $10–$15 a barrel because 30 per cent of the pipelines are filled with dilbit for transporting the bitumen,” he says. “Couldn’t we develop an integrated system [to use locally-produced hydrogen]?”

Smart cities
There are other ways for Canadians and their country to become energy efficient and to reduce their greenhouse gas (GHG) emissions beyond the kinds of changes envisioned by CESAR. One of them is to move toward smarter communities.

Brent Gilmour, executive director of Ottawa-based Quality Urban Energy Systems of Tomorrow (QUEST), says a shift to more public transit use, more concentrated urban design and the use of district energy systems are among the solutions his organization advocates.

“Half of our total GHGs in Canada and 60 per cent of our energy use occurs in communities,” he said. “Over 80 per cent of us live in and around urban communities.”

Despite the impression that industrial processes, such as energy production, and commercial farming are responsible for most energy use and GHG production, it’s actually the end users who are the biggest energy consumers and emitters, he says.

But that energy consumption is often hidden from the public eye.

“For example, 50–60 per cent of energy use [in urban centres] is from pumping and treating water,” said Gilmour.

QUEST helps communities develop energy plans, concentrating on shifts in municipal energy use that save money. It works with the Federation of Canadian Municipalities to promote more energy efficiency.

While the U.S. and many European countries have developed a similar approach, Gilmour says there’s no need for Canadians to feel they have failed to build smarter communities since there are many success stories.

In downtown Toronto, for instance, much of the air conditioning is provided in the summer by cold water wdrawn from Lake Ontario and circulated through downtown buildings.

In Hamilton, Ont, the city has designed a system that captures methane gas from its wastewater treatment plant, which is then mixed with natural gas for heating and vehicle fuel.

There are hundreds of such examples across the country, Gilmour says, but QUEST hasn’t yet been able to measure the total energy savings and GHG reductions, but it is working on a project that will do so.

Calgary and Edmonton have recently started down a path that could lead to smart city developments in both major centres, and with another 54,000 communities in Canada, large and small, the potential opportunities are huge, Gilmour says.

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