Oilsands industry needs ‘game-changers’ that dramatically reduce greenhouse gas emissions, COSIA summit hears

Author: Mark Lowey

Source: http://envirolinenews.ca

Publish Date: Monday, April 24, 2017

First of two stories by EnviroLine from the Canada’s Oil Sands Innovation Alliance Innovation Summit 2017. The second story will be posted on May 5, 2017.



Alberta’s oilsands industry is making incremental progress on reducing greenhouse gas emissions but needs to achieve some game-changing advances, the Canada’s Oil Sands Innovation Alliance Innovation Summit 2017 heard.

“If we don’t innovate and deploy, we’re not going to move the dial,” Steve MacDonald, CEO of Emissions Reduction Alberta (ERA), told the summit held March 21-22 in Calgary.

The oil and gas industry is notorious for being “the first to second,” and it needs much quicker adoption of new technologies, MacDonald said in a keynote talk on “Bold Innovation.” Industry CEOs will lose interest if companies don’t show early wins, he added.

Some environmental problems have been talked about for decades, he noted, adding: “We need to deliver results . . . We need to fail fast, fail cheaply, but fail forward and get on with things.”

ERA (previously the Alberta Climate Change Emissions Management Corporation) has invested more than $300 million in about 100 projects, and leveraged this investment into a total project value of $2.2 billion, creating some 15,000 jobs, MacDonald said.

All the projects to date will reduce greenhouse gas (GHG) emissions by more than 7 million tonnes by 2020, he said.

However, more innovation is still required across several areas, including policy, technology, business development and finance, MacDonald said. Such innovation requires partnership, collaboration and aligning existing strengths, he added.

Oilsands projects involving new technology are typically large and capital-intensive, usually costing hundreds of millions of dollars. So industry needs more financial incentives, such as loans and tax breaks, to be able to scale up technologies to the demonstration and commercialization stages, he said.

Government, industry and other stakeholders need to pick a few winners and not spread a limited amount of available funding too thinly, MacDonald said during a Q&A session. “The option is to do nothing, so someone has to make some choices.”

Todd Pugsley, integrated lead on decarbonization, enterprise technology at Suncor Energy, said field trials are needed for a promising technology called “direct contact steam generation” or DCSG.

DCSG technology has the potential to reduce GHG emissions from generating steam for in situ, steam-assisted gravity drainage (SAGD) oilsands projects to “almost zero,” while increasing thermal efficiency of steam generation, reducing total water volume used and producing a solid waste stream, Pugsley said. The technology also would eliminate or drastically reduce the need to treat SAGD process water so it doesn’t foul boilers and pipes, he said.

With DCSG, water used to make steam is in direct contact with the products of oxygen-fuel combustion – essentially a flame. This creates a mixture of steam and carbon dioxide which replaces steam generated using conventional boiler technology. The CO2 can be used to aid in bitumen extraction or for enhanced oil recovery.

“It is a very promising technology, but there’s still quite a bit of work to be done,” Pugsley said.

In early 2014, a COSIA project led by Suncor completed testing of DCSG technology under pressurized conditions. COSIA’s member-companies received the results on steam generator performance in the spring of 2014. “The results indicated no significant technical hurdles and identified the further development work that will be needed to scale-up the technology,” according to COSIA’s website.

Suncor is currently working with the federal CanmetENERGY agency to design the pilot for the next development phase. Commercial deployment is probably four to five years away, Pugsley said.

Since late December last year, Suncor has been doing steam-CO2 injection field trials at its MacKay River SAGD operation near Fort McMurray. The company is using isotopic tracking to distinguish CO2 already present in the reservoir from the CO2 being injected. So far, more than 200 tonnes of CO2 have been injected with only 20 tonnes coming back, which indicates the technology’s potential for geological sequestration or storage of CO2, Pugsley said.

To use CO2 generated in the oilsands region for enhanced oil recovery, a pipeline would be needed to transport the CO2 to networks of wells that are farther south, he said during a Q&A session.

Jonathan Matthews, director of COSIA’s GHG Environmental Priority Area, said in an update that COSIA’s member-companies have invested $208 million to date in 154 projects aimed at reducing GHG emissions – including 18 projects launched last year. Forty-two projects have been completed, at a cost of $25 million.

“There has been no backing away from the technology agenda,” despite tough economic times for the oil and gas industry, Matthews said. Some of the projects he highlighted included:

Emerging new challenges include how to quantify area fugitive emissions, and post-combustion CO2 capture from natural gas, Matthews said.


Company develops ‘industrial lung’ for carbon capture

In a panel session on “CO2 Capture Technology,” Richard Surprenant, chief technology officer for CO2 Solutions, told the COSIA summit about the Québec-based company’s patented, non-toxic enzyme-enabled solvent process – in essence an ‘industrial lung’ for carbon capture. The process captures carbon dioxide from effluent gases and produces pure CO2 for utilization.

Surprenant said existing amine-based carbon capture technology has several challenges. They include high cost ($60 to $90 per tonne for flue gas application), use of unstable solvents and production of toxic waste.

CO2 Solutions’ process uses a safe enzyme that naturally occurs in people’s bodies, is stable in process conditions, catalyzes CO2 hydration reactions, and can be mass produced, he said. The process uses salt, water and an enzyme solution with standard gas-treatment equipment. The enzyme catalyzes CO2 capture using low levels of energy, in a “benign and stable” non-chemical absorbing solution, Surprenant said.

The company achieved bench-scale capture of 0.5 tonnes of CO2 per day in 2014, followed by a pilot project that captured one tonne of CO2 per day, and then completed a demonstration plant near Montréal that captured 10 tonnes of CO2 per day. The demonstration plant operated for 2,500 hours and produced “food grade” CO2 with a purity of 99.95 per cent, Surprenant said.

“We’ve proven that our enzyme lasts really long,” he said, noting that the entire enzyme solution volume from the demonstration plant was safe enough to dispose of in the municipal sewer. “There are no [harmful] byproducts.”

Potential applications for the technology and the CO2 produced include in enhanced oil recovery, pulp and paper processing, water treatment, greenhouses, beverage carbonization and other uses, as well as CO2 capture in oil sands production.  

Surprenant said the total cost (including fixed and variable costs and capital cost) of CO2 Solutions’ technology is $28 per tonne to capture 1,250 tonnes per day of CO2, which includes a $5-per-tonne cost for the enzyme. That is more than a 50-per-cent saving over the typical cost of an amine CO2 capture system, he noted.

“We’re ready for commercialization (of) up to 300 tonnes per day,” he said. Emissions Reduction Alberta has provided $15 million to CO2 Solutions toward a $30-million commercial project at Redwater in the Edmonton Capital Region of Alberta, and the company is now seeking consortium partners.

CO2 Solutions also plans a project at a petrochemical facility in Montreal East, to demonstrate high-potential upgrading schemes, Surprenant said.


Improving CO2 capture technologies

Panelist Vicki Lightbown, senior manager of water and environmental management at Alberta Innovates, described the development of a “facilitated transport membrane” for CO2 capture. The polyvinyl-coated membrane, which uses almost no energy input, increases the purity of the captured CO2. Using the amine groups in the polymer structure of the membrane, CO2 is converted to bicarbonate by the water vapour that’s also contained in the exhaust gas. The bicarbonate is quickly transported through the membrane, while the other substances in the flue gas are retained.

Alberta Innovates partnered with the Norwegian University of Science and Technology to do a field trial of flat sheet-facilitated transport membranes at a cement manufacturing plant in Norway in 2014. Alberta Innovates, Suncor and Cenovus Energy (both of which are interested in the technology’s application for SAGD oilsands operations), Air Products, Statoil, DNV GL, and Sintef Mc then were involved in scaling up the technology to a 10-square-metre hollow fibre membrane for testing under flue gas conditions. Tests were done in 2015-2016 at the Tiller test site in Trondheim, Norway, operated by Sintef.

There are several challenges in using facilitated transport membranes in flue gas at coal-fired power plants and cement plants, including keeping the temperature well controlled to prevent too much water condensation, preventing sulphur dioxide and nitrogen oxide from ruining the membrane over time, and ensuring the membrane process can handle outages of the power plant.

Lightbown said there is good potential for scaling up the technology for commercial application, which Air Products, an international membrane company, is pursuing. The current cost of the technology ranges from $70 to $120 per tonne of CO2 captured, but this can be reduced to $50 per tonne by using an optimized modular design to fit a low-pressure system, she said.

Panelist Niall Mac Dowell, who leads the Clean Fossil and Bioenergy Research Group at Imperial College, London in the U.K., presented his group’s work on developing software to assess the performance of chemical and physical sorbent materials to capture CO2 in power plant operations.

The group found that the capital costs of CO2 capture per megawatt-hour of power produced are higher than the operating costs for coal-fired power plants. However, the reverse was true for natural gas-fired plants: the operating costs of CO2 capture were higher than the capital costs.

Mac Dowell’s group also compared 15 ionic liquids for their potential as novel, environmentally benign solvents to capture CO2. But most of the ionic liquids would be impossible to use as processing fluids, he said, because the process tower would need to be “impossibly high.” The group’s paper, “An overview of CO2 capture technologies,” was published in Energy & Environmental Science.

The conventional approach to developing new sorbents needs to be improved, and there needs to be a deliberate and clear connection between process performance and costs, Mac Dowell concluded.

The 2017 COSIA Innovation Summit attracted about 680 people, including speakers, moderators and panelists.


  • Top-down in-situ combustion using high concentrated oxygen will be game change on bitumen and heavy oil production and this will minimize capital investment for equipment and facilities, will reduce to the maximum fresh and brackish water use. This ISC will improve oil properties, it will reduce the amount of asphaltene on bitumen produced, will reduce the need for synthetic oil, will reduce and total volumes for transportation. The ISC will increase the CO2 generated by combustion, but a part of this will remain into pore space, and the associated gas produced will have high CO2 concentration and HC and can be used on other EOR without further processing. If we like to separate the HC from gases, then gas process will be associated with high concentrated CO2 and can be used on EOR. Actual ISC technologies tested on field or on pilots have showed poor results and most of oil operators know well that actual technologies have low expectations and high risk to fail. The oil operators know that Top-down in-situ combustion work on limited feasible geological formations, mainly on formations with high deeping angle and when oil is movable, and when other feasible taboo set for this thermal EOR are appropriate. I say that all the taboo on EOR and particularly on ISC are based on old practices. The success of the EOR, including here ISC when we achieve to have high displacement efficiency on cores, depends on engineering design underground. When wells are drilled and completed properly, then the EOR success will depend on engineering job. COSIA, ERA, CanmetEnergy or oil operators who like to improve thermal EOR, being these SAGD or DCSG or hybrid thermal EOR and like to reduce the water use and to reduce CO2 emission, based mainly on their existing EOR or future EOR, they can benefit if they will privately disused for practical additional solutions which can be tested on laboratory or on their existing EOR patterns where they have low effectivity.

    Nick Gjergji - 2017-09-12T10:58:45

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