Oilsands improving on GHG emissions and could help cut emissions on Alberta’s electricity grid, researchers tell CERI symposium

(This is the second of three EnviroLine stories from the CERI symposium. The first story was posted on March 20. The third story, which reports on an “executive panel discussion,” will be posted on March 28).

 

Alberta’s oilsands industry is continuously improving on reducing greenhouse gas emissions and could help cut emissions on the province’s electricity grid by deploying more cogeneration plants, researchers told the Canadian Energy Research Institute’s (CERI) 2017 Oil & Gas Symposium in Calgary.

Some oilsands operations are performing as well as some global conventional crude production in terms of greenhouse gas (GHG) emissions per barrel of crude oil produced, Joule Bergerson, associate professor of chemical and petroleum engineering in the Schulich School of Engineering at the University of Calgary, said in a panel session titled “Examining Full Cycle Costs and Emissions Profile for Energy Projects.”

Bergerson, an expert in life cycle assessment, and her research group have done cradle to grave or “well-to-wheels” assessments of various crude oils from around the world, including those produced by Alberta’s oilsands industry. Their work contributed to the first-of-its-kind report, Know Your Oil: Creating a Global Oil-Climate Index, published by the Carnegie Endowment’s Energy and Climate Program at Stanford University and the University of Calgary.

Life cycle assessment is now being used to document GHG emission reductions in the fully supply chain, to inform funding agencies and investors and enforce policy such as California’s low-carbon fuel standard.

Bergerson and her group, who used open-source oil-climate modelling, analyzed GHG emissions throughout the entire oil supply chain, including oil extraction, crude transport, refining, marketing, and product combustion and end use. Phase 1 of their research involved assessing 30 different crude oils.

They found a more than 80-per-cent difference in total GHG emissions per barrel of the lowest GHG-emitting Phase 1 oil compared with the highest-emitting. The spread of GHG emissions among oils is expected to grow as new, unconventional oils are identified.

Crudes from Alberta’s oilsands are in the upper half of global crudes in terms of GHG emissions per barrel, Bergerson said. However, oilsands crudes are not among the world’s four highest-emitting crudes, she noted.

The research found that the variations in oils’ climate impacts “are not sufficiently factored into policymaking or priced into the market value of crudes or their petroleum products.” The most GHG-intensive oils currently identified – gassy oils, heavy oils, watery and depleted oils, and extreme oils – merit special attention from investors, oil field operators and policymakers, the researchers said.

Phase 2 of the Bergerson group’s research involved assessing 75 crude oils, representing every major global region and about 25 per cent of global oil production. Crude from Alberta’s oilsands is the best documented crude in the world when it comes to life cycle assessments, including GHG emissions per barrel, Bergerson noted. The same amount and quality of data often aren’t available for many crudes in the world.

Bergerson said an important aspect of her research is that it establishes a baseline for Alberta’s oilsands crude, while the baselines for many types of crude either haven’t been established or revealed. “Now we can start showing where we’re improving” in reducing GHG emissions per barrel, whereas other jurisdictions without a baseline are not able to do that, she told the CERI symposium.

Bergerson’s group also did a techno-economic evaluation of technologies to mitigate GHG emissions at North American refineries. Their study was published in December last year by the Environmental Science & Technology journal. Another study by the group, published in November last year by the same journal, used life cycle assessment to evaluate GHG emissions of oilsands upgrading technologies. Bergerson also served on the expert panel that produced the Council of Canadian Academies’ report, Technological Prospects for Reducing the Environmental Footprint of Canadian Oil Sands.

Bergerson said her work provides a framework, which is still being developed, for assessing various technologies early in their development cycle for reducing GHG emissions from the oilsands. The cost of technologies and the amount of CO₂e reduced aren’t the only considerations, and decisions on any technology must be made from multiple perspectives, she said.           

The Canadian Energy Research Institute today (March 24) released a study, Economic Potentials and Efficiencies of Oil Sands Operations: Processes and Technologies, which identifies the technological pathways to significantly reduce costs as well as GHG emissions. CERI says that by implementing technology configurations assessed in the study, the 100-megatonnes CO₂e per year emissions cap imposed by the Alberta government on the oilsands industry “is not reached within the study period (2016-2036).” The technology configurations that meet the minimum costs and emissions objectives also can achieve potential reduction of bitumen supply cost by 34 to 40 per cent, and reduce fuel-derived emissions from in situ oil sands production by more than 80 per cent, CERI says. “Consequently, oil sands production could grow over a longer period until the emissions cap is reached.”

 

Technology “moving fast” in the oilsands

Technology development “is moving fast” in the oilsands and could usher in a “new birth” of the industry, Ian Gates, professor and head of the chemical and petroleum engineering department in the Schulich School of Engineering at the University of Calgary, said in a luncheon talk at the CERI symposium.

The industry’s most pressing issues today are cost, GHGs and other environmental impacts, social acceptance, market access and technology, he said.

The key for producers is using technologies such as reservoir imaging and improved well bore design to achieve the lowest steam-to-oil (SOR) ratio possible, which indicates effective extraction of bitumen and optimal well utilization, Gates said. A lower SOR means lower energy and water use, reduced GHG emissions and lower cost per unit of volume bitumen. Some producers are achieving “excellent” SORs ranging from 1.7 to 2.2, while other companies have “good” SORs of 3.3 to 4.5, and others are lagging at 4.5-plus. The “theoretical” SOR is approximately 0.7, he noted.

“We need to get it [oilsands production] as clean as conventional [oil production] or better,” as near to zero emissions as possible, Gates said.

He noted that the University of Calgary’s Energy Research Strategy includes a global research initiative in sustainable low carbon unconventional resources. The initiative includes $75 million from the Canada First Research Excellence Fund and has three research themes: heavy oil and bitumen; tight oil and gas; and low CO₂ energy technologies, utilization and conversion. Each of the themes has several “Grand Challenges” or research priorities.

The initiative, which has 10 projects to date, has a “solution-centric focus,” Gates said. “We want to take technology to the field.”

As for the future, Gates said he expects to see faster new technology adoption and acceleration, including in data analytics, “digital oil field” and real-time optimization/artificial intelligence. New injectants for analyzing reservoirs, optimizing well bores and extracting bitumen could include nano-sensors, nano-reporters, nano-characterizers and smart particles. Electricity, in combination with steam or water or solvents, could be used for extraction.

Potential new products from the industry include:

• power from heavy oil and oilsands reservoirs;

• in situ gasification of oilsands reservoirs to produce hydrogen; and

• carbon products and metals.

Gates said he also expects advances in bioenergy, including production of biomaterials and microbially-generated energy.

 

Oilsands could help reduce GHGs on Alberta’s grid

At the “Examining Full Cycle Costs and Emissions Profile for Energy Projects” session, panelist David Layzell, professor and David Layzell, professor and director of the Canadian Energy Systems Analysis (CESAR) initiative at the University of Calgary, said 81 per cent of Canada’s GHG emissions are associated with energy systems. Of that, 34 per cent or 274 megatonnes are emitted by Alberta’s energy sector.

Canada is not on track to meet its GHG emissions-reduction target for 2020, Layzell said. In Alberta, he added, the big challenge is what can be done over the next 13 years to help meet the 2030 target.

In the province, about 50 to 65 per cent of energy in the form of heat is essentially “thrown away” in generating electricity, Layzell noted. To generate electricity, Alberta relies on burning coal and natural gas, emitting more than 46 million tonnes of carbon dioxide a year, or more than 11 tonnes per capita. However, most of this thermal power generation uses technologies, such as coal- and natural gas-fired power, that capture only 30 to 50 per cent of the fossil fuel energy in the electricity product. The rest of the energy is lost as heat, being dumped to either the atmosphere or water. In Alberta, this discarded heat adds up to 393 petajoules (PJ) per year – more than the energy used each year by all residential, commercial and institutional buildings in the province, according to two major studies by CESAR on SAGD-integrated cogeneration.

            In most jurisdictions in the world that rely on thermal power generation, there are no industries that could possibly use the discarded heat energy from power generation, so this loss is typically considered part of the price for a reliable electricity supply. Alberta is different, Layzell said, and it is because of the oilsands. Steam assisted gravity drainage (SAGD) for extracting bitumen requires 408 PJ of heat energy a year to make the steam, and that process alone generates about 24 million tonnes of carbon dioxide a year, or six tonnes for each Albertan.

            Alberta has a huge and unique opportunity to integrate the SAGD and thermal electricity sectors for the benefit of the province’s environment and the economy, Layzell said. The time to do it is now, he added, with the government redesigning the electricity market and phasing out coal-fired power.

            Large-scale cogeneration integrated with steam assisted gravity drainage operations offers a “made-in-Alberta” opportunity to accelerate the phase-out of coal while removing an additional 142 million tonnes of CO₂e emissions or more between now and 2030, while supporting the province’s renewable energy objectives, Layzell said. Some or all of the GHG reductions could be allocated to the oilsands industry on a temporary basis, to help reduce the sector’s carbon footprint, he said. This would also provide more time for oilsands producers to develop and deploy more carbon-efficient extraction and production technologies.

            The oilsands is the fastest-growing industrial source of GHG emissions in Canada. So reducing emissions in the sector is more important to Alberta and the Canadian economy than reducing carbon on Alberta’s electricity grid (although that would also be accomplished), Layzell said.

            He urged that Alberta government to consider requiring all new baseload power generation capacity to be at least 67-per-cent efficient. SAGD-cogeneration, by capturing the residual heat to make steam for SAGD, is at least 80-per-cent efficient in using the fuel energy.

That means lower fuel use – a major input cost for both SAGD and power generation – and lower overall GHG emissions. Cogeneration’s high efficiency offers a cost advantage over combined-cycle gas power, an advantage that would make the transition away from coal less costly and help stabilize electricity prices, according to CESAR’s studies.

During a Q&A session, Layzell acknowledged that more electricity transmission lines would need to be built to accommodate SAGD-integrated cogeneration, although he pointed out that a 500-kilovolt line currently under construction into the oilsands region could be reversed to carry cogen power from the region.

           

B.C.’s LNG potential assessed

Panelist Amit Kumar, professor of mechanical engineering at the University of Alberta, and colleagues assessed the full life cycle cost structure and the entire supply chain, including GHG emissions, of British Columbia’s planned LNG development. One of his studies focused on B.C. exporting LNG from a terminal in Kitimat, B.C. to China, India and Japan.

He noted that B.C. has 376 trillion cubic feet (tcf) of remaining natural gas reserves, more than Alberta’s 247 tcf. More than half of Canada’s gas is exported to the U.S., but this is forecast to decline over the next 20 years, whereas China and India have a lot of potential for importing LNG, he said.

Kumar and colleagues’ research found that the full life cycle cost, including shipping, liquefaction, pipeline and well head costs, of delivering B.C. LNG to India would be an estimated $9.99 per gigajoule, $9.28 to China and $9.15 to Japan.

Their research found that the “well-to-wire” GHG emissions for four different Canadian shale gas reserves ranged from 538 grams of CO₂e per kilowatt-hour to 640 g CO₂e/kWh. This included electricity transmission, power plant (combined cycle natural gas), re-gasification, LNG shipping, liquefaction facility, pipeline transmission, processing and recovery.

 In comparison, well-to-wire GHG emissions for combined cycle electricity generation in Canada were 530 g/CO₂e/kWh, while GHG emissions for China’s overall coal power generation were 980 CO₂e/kWh. “Implementing CCS technologies can significantly reduce power plant emissions,” according to his slide presentation.

            Kumar and colleagues’ research is published in these journals:

• Sustainable Technology and Assessments (2016, 18): Techno-economic Assessment of the Liquified Natural Gas (LNG) Production Facilities in Western Canada;

• Natural Gas Science and Engineering (2016, 34): A Techno-economic Study of Shipping LNG to Asia-Pacific from Port of Kitimat, Canada by LNG Carriers; and

• Energy (2016, 111): The Well-to-Wire Life Cycle Assessment of Canadian Shale for Electricity Generation in Canada.

The B.C. government has committed to reduce methane emissions by 45 per cent from oil and gas infrastructure built before 2015. However, the province’s planned LNG infrastructure will add millions of tonnes of GHG emissions to the atmosphere. A study, released in November last year by the Canadian Energy Research Institute, said “significant residual effects related to greenhouse gas emissions” have been identified for seven out of 18 proposed natural gas pipeline and LNG projects which have undergone government environmental assessments. The Canadian Environmental Assessment Agency found that just one project – the Pacific NorthWest LNG terminal and associated upstream natural gas development – could emit up to 11.4 million tonnes of CO₂e per year, although the B.C. government insists this can be significantly reduced through provincial actions.

David Karn, senior public affairs officer at the B.C. Ministry of the Environment, said in an email to EnviroLine that the province’s LNG facilities “will be the cleanest in the world,” and “emissions will be reduced as actions are introduced, including those linked to the LNG industry and natural gas sector.” Actions to date include setting a ‘global standard’ for greenhouse gas intensity of 0.16 tonnes of CO₂e emitted per tonne of LNG produced. However, LNG companies will have the option to buy carbon offsets and pay into a technology fund rather than reduce emissions at their facilities.

The government also offers a reduced “eDrive” electricity rate – which critics call a subsidy – of about $60 per megawatt-hour versus the original rate of $83 per MWh for LNG developers that use electricity rather than natural gas in the liquefaction process. There is also a royalty credit program to attract private-sector funding for technologies that reduce GHG emissions from oil and gas exploration and production.

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