- Seminar Edmonton, Alberta, May 8-10/12
Cogeneration, Gas & Steam Turbines, Alberta Elect. System, micro-turbines, fuel cells, absorption chillers, oil sands & nat. gas energy systems, industrial waste recovery, case studies of cogens and tour of cogeneration plant
- Inject Some Energy Into Your Employment Lands
Light House and COGENCanada
- Cogeneration Technology March 6-8/12, Las Vegas, NV
Sponsor: University of Wisconsin-Madison, Department of Engineering Professional Development
|  This Transalta Combined Cycle Cogeneration System provides reject heat for both heating and cooling (google aborption air conditioning) to the Ottawa General Hospital on Smyth Road, the Ottawa Rehabilitation Centre, and the Eye Institute, the Children’s Hospital of Eastern Ontario (CHEO) , the National Defence Medical Center, the Perley and Rideau Veteran’s Health Centre and a part of the University of Ottawa Medical School. It also supplies electricity to the Ontario grid. It started up in 1992. It has a GE LM6000 gas turbine Gas Turbine. It is an ideal example of an Eco-Institutional Network. The technical advisor was Joe Zanyk, a member of the COGENCanada Board of Advisors and the Board of Directors.
 This cogeneration plant was part of a $1.8-billion expansion at NOVA Chemicals’ Joffre site that included additional ethylene, polyethylene and linear alpha olefin production capacity. ATCO Power, NOVA Chemicals Ltd. and Capital Power Corporation (formerly EPCOR) built a 480-megawatt natural gas-fired cogeneration plant to meet the substantial steam and electric energy needs of NOVA’s world-class petrochemical facility at Joffre in central Alberta near Red Deer. The plant also sells electric energy into the Power Pool of Alberta and delivers 530 tonnes of steam per hour. The cogeneration plant was jointly constructed and is currently owned by ATCO Power, NOVA Chemicals and Capital Power. ATCO Power leads the operation of the facility and, along with Capital Power, markets surplus power from the facility. This is an excellent example of an ECO-Industrial Network
Using Recovered Heat to Displace Fossil Fuel
In Cogeneration-based Eco-Industrial Networks, heat rejected by the Cogeneration system and other processes in the Network is used by other processes in the network. This provides Environmental & Economic Benefits – Clean Energy as well as other benefits as explained
USING RECOVERED HEAT TO DISPLACE FOSSIL FUEL
Cogenerated Electricity is as Green as wind or solar but delivers electricity whether or not the wind is blowing or the sun is shining
Single purpose thermal electric power plants reject some 50% of the fuel heat to water bodies or the atmosphere. Cogeneration systems recover this heat which is rejected by the electric power cycle and use it to displace fossil fuel
There is a Need for an Incentive To Buy Cogenerated Electricity, particularly at night, thus to facilitate making recovered heat available for use in industrial processes or for space heating to displace fossil fuel day and night
Alberta’s Best Hope
© Enerhope.com 2010
This article will be published on the web sites www.Enerhope.com and www.cogencanada.org in May, 2012.
The battle lines are drawn! The Canadian Province of Alberta is locked in battle with environmental protesters over Alberta’s fabulous Oil Sands. Movie celebrities are shuttling back and forth between Hollywood and Washington, complaining to their congressional representatives that the USA is buying “dirty” oil from the “Tar” Sands to fuel their white stretch limousines and private jet aircraft. In the USA and Europe, leaders are now considering various new regulations, to prevent or seriously impair any imports of Canadian Oil Sands products into those countries. Despite its fabulous energy and economic potential, the development of the Oil Sands may be prevented by opposition to greenhouse gas emissions.
On the other side, Alberta narrowly avoided electing a belligerent climate change denier government in the provincial general election on April 23rd.
According to the Canadian Energy Research Institute, in 2011, the Oil Sands produced 1.6 million barrels per day of bitumen (heavy oil) (1 Barrel = 159 litres) and emitted 53 megatonnes of CO2 equivalent into the atmosphere (about 7 or 8% of Canada's total). With unchecked growth and no reductions in greenhouse gas emissions, the industry will produce between 4.0 and 6.0 million barrels per day in 2030, and emit between 127 and 174 megatonnes per year of greenhouse gases.
Canadian Oil Sands Supply Costs and Development Projects (2011-2045)
Can the industry sustain growth in production, while reducing its greenhouse gas emissions?
The Alberta Government acknowledges the importance of reducing Alberta’s greenhouse gas emissions. Alberta’s Climate Change Strategy (2008) states:
“Alberta has both a responsibility and an opportunity to take decisive action to reduce greenhouse gas emissions.”
Alberta Climate Change Strategy
According to the Strategy, Alberta will reduce its greenhouse gas emissions, even with massive growth in the oil and gas industry. Alberta’s target for total emissions in 2050 is only 157 megatonnes, which is much less than the 226 megatonnes emitted in 2010.
According to the Strategy, the major activity for emission reductions will be Carbon Capture and Storage (“CCS”), wherein carbon dioxide is separated from the exhaust streams of fossil fuel combustion, compressed to high pressure, piped to specific locations, and pumped into permanent storage in the ground at great depth. Demonstration projects have proven CCS to be a technical success, especially where the pressure of the injected carbon dioxide forces petroleum to the surface.
However, the economics of CCS have been disappointing. On April 27th, the Edmonton Journal reported that three major energy companies have abandoned their plan to build the $1.4 billion(Canadian) Pioneer CCS plant beside the Keephills 3 coal-fired electricity generating station. The project was expected to capture one megatonne of carbon dioxide every year for the next 10 years.
TransAlta Cancels CCS Project
Although Pioneer will not go ahead, three other demonstrations in Alberta are still proceeding.
The financial incentive for greenhouse gas emission reductions does not appear to justify the cost of building and operating a CCS plant.
Alberta’s emissions trading system, the Specified Gas Emitters Regulation, allows large direct emitters to pay for their excess emissions by contributing $15.00 per tonne of excess CO2 to the Alberta Climate Change and Emissions Management Fund.
In contrast, the cost of disposing of CO2 by CCS is quoted at from $70.00 to more than $150.00 per tonne, according to the Final Report (2009) of the Alberta Carbon Capture and Storage Development Council.
Accelerating Carbon Capture and Storage
Implementation in Alberta
At this point, Carbon Capture and Storage, the central activity of Alberta’s Climate Change Strategy, appears to be doubtful for major reductions in greenhouse gas emissions.
Without Carbon Capture and Storage, how can Alberta reduce greenhouse gas emissions from its growing Oil Sands industry?
Cogeneration, and Emissions Trading
What is cogeneration? Please see Enerhope’s January, 2011 article, Cogeneration and Emissions Trading
http://enerhope.advancedwebsites.ca/_blog/January_2011_-_Cogeneration_and_Emissions_Trading
Currently, in the Oil Sands, natural gas boilers produce large quantities of steam, which is used to separate the bitumen from the sand, or to recover bitumen from underground. These steam boilers are a large source of greenhouse gases.
Another fact: In Alberta, most electrical energy is generated by coal-fired generators, with high greenhouse gas emissions.
If 50% of the existing natural gas boilers in the Oil Sands were replaced by natural gas-fired cogeneration units, and the generated electricity were sold to the Alberta grid, replacing coal-generated electricity. Alberta’s greenhouse gas emissions would drop by 23 megatonnes per year, or 10% of Alberta’s 2010 total. The total generated power would be about 5100 megawatts, which is less than Alberta’s minimum base load of about 7000 MW. (calculations available on request) The total greenhouse gas emissions per barrel of fuel product would actually be lower than the emissions for fuel from conventional petroleum sources. This calculation is based on 2010 data. Future savings would be even more impressive.
This cogeneration opportunity in the Oil Sands was identified in Life Cycle Assessment Comparison of North American and Imported Crudes, a report to the Alberta Energy Research Institute, in 2009.
The opportunities for cogeneration in the Oil Sands were also identified by Dr. Eddy Isaacs, of Energy and Environment Solutions, in The Oil Sands in a Low Carbon Fuel Economy, a presentation at the University of Alberta in 2010. Isaacs identified the opportunity for cogeneration to reduce greenhouse gas emissions, but admitted, “The methodology for cogen credits is uncertain.”
The Oil Sands in a Low Carbon Fuel Economy
The Oil Sands industry itself is aware of the possibilities of cogeneration. The Oil Sands Developers Group, Cogeneration and Power Infrastructure Group has surveyed the industry on the current extent of cogeneration and the prospects for future expansion. Here is the URL of the 2011 Report of this group:
2011 Oil Sands Co-Generation Report
According to the 2011 Report, Oil Sands developers in 2010 and earlier were planning to build only sufficient cogenerating capacity to supply their own on-site power needs. The industry currently has installed about 1,800 megawatts of cogeneration capacity. The industry appears to be cautious about future cogeneration. Industry members reported some concerns about the cost of paying for standby capacity from the Alberta Grid. Another concern is that any surplus power that a cogenerator might want to sell to the Alberta Grid would be at disappointing low price. A strong financial incentive for cogeneration does not appear to be in place. The Report predicts that by 2020, installed cogeneration capacity will be between 3,100 and 3,800 MW, which is small, considering the forecast of total bitumen production in 2020. Clearly, a price mechanism to reward cogeneration is needed, in order to promote wide-scale use of cogeneration in the Oil Sands industry. (Remember that this report was compiled in late 2010, when
natural gas prices were higher than today.)
The opportunities for cogeneration in the Oil Sands are now greater than in the past, because:
1) Alberta is under great pressure to reduce greenhouse gas emissions.
2) Natural gas prices have fallen, and show no sign of increasing.
3) The competing technology for emission reductions, carbon capture and storage, appears to be economically unfeasible.
In order to facilitate a transformation from base load coal to base load cogeneration, Alberta needs:
1) A new, high-voltage transmission line between the Oil Sands area and southern Alberta. (currently planned)
2) An emissions trading system, that would discourage high-emission electricity, reward low-emission electricity, and allow credit for cogenerated steam. (Alberta’s current Specified Gas Emitters Regulation will expire in 2014, and should be replaced by a well-designed cap-and-trade system.) See Enerhope’s September, 2011 article, Alberta’s Baseline and Credit Emissions Trading System.
3) The necessary infrastructure for electricity, natural gas and steam within the Oil Sands area. (an opportunity for government – utilities - industry collaboration)
4) A cooperative agreement among cogenerators, to insure individual cogenerators against the extra costs of power outages.
5) A positive regulatory attitude toward environmentally beneficial cogeneration projects.
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