Capturing CO2 From A Coal-Fired Plant
March 1, 2009
By David Cameron, P. Eng. , Mike Richard, P. Eng. , Stantec
the search for cost effective, near zero emission technologies for coal-fired electrical power plants is gaining momentum in many parts of the world and Canada is no exception. One ambitious project u...
the search for cost effective, near zero emission technologies for coal-fired electrical power plants is gaining momentum in many parts of the world and Canada is no exception. One ambitious project under way is a $1.4 billion partnership between the Government of Canada, the Government of Saskatchewan, SaskPower and private industry to demonstrate the technical, economic and environmental merits of carbon capture and sequestration technology. If successful, the project will lead to sustainable options for generating power using coal and other fossil fuels.
Under the partnership, SaskPower is leading the development of one of the first and largest clean coal/carbon capture demonstrations in the world at the Boundary Dam Power Station in Estevan, Saskatchewan.
Acting as prime consultant to the SaskPower initiative, Stantec completed a number of pre-commitment engineering studies to evaluate clean coal power options between January 2005 and the present. An early study for SaskPower’s Shand station was based on a new 350 to 450-MW unit using either Oxyfuel or post-combustion CO2 capture. The project was placed on hold in 2007 when it was found to be uneconomical for SaskPower’s short-term supply needs.
Attention then focused on the current project at the Boundary Dam Unit 3, a unit scheduled for retirement in 2013. This project is called the “Boundary Dam Integrated Carbon Capture and Sequestration Demonstration Project,” or “BD3 ICCS.” In this case, the unit will be re-powered and fitted with post-combustion CO2 capture technology in two stages. Starting in 2013, 50% of the flue gas will be treated, then the remaining 50% will be processed starting in 2015. The demonstration project was included as part of the federal government’s carbon capture and sequestration funding for Saskatchewan in the 2008 budget. Ultimate development will be contingent on, among other things: capital costs remaining competitive with other power options, an agreement to use the captured CO2 for enhanced oil recovery (EOR), and the required environmental approvals.
The project has included a thorough assessment of existing and emerging post-combustion capture technologies. The studies are being done in the absence of accepted clean coal benchmarks, or CO2 purity guidelines, for enhanced oil recovery sequestration. Projecting forward, environmental standards, expected benchmarks and legislative risks are being researched.
At the end of the assessment period, SaskPower will make a decision on whether or not to proceed with the project.
There are a number of competing post-combustion CO2 capture technologies available in various stages of commercial development. A majority depend on amine-based solution chemistry for carbon absorption and can be expected to capture at least 90% of the CO2 in the flue gas.
Capturing The Post-Combustion C02 — How It’s Done
The technical challenges for post combustion capture of CO2 begin with the flue gas. Flue gas contaminants such as sulphur dioxide, and other acidic species like chlorine and fluorine, can degrade the carbon absorption chemicals. These species are typically removed through Flue Gas Desulphurization (FGD) systems.
Following the FGD process, the flue gas is usually cooled to between 30-60C to maximize the CO2 mass transfer rate with most amine-based absorption solutions. The cooled flue gas enters the bottom of an absorber vessel, where it is counter-currently contacted with a spray of aminewater solution. Depending on the technology vendor, the absorber may contain internals to enhance mass transfer. The CO2 chemically reacts with the lean amine solution and is removed from the flue gas. This reaction is exothermic, and leads to increasing temperatures in the absorber, which is countered through supplementary cooling.
The amine solution, now rich in CO2, is pumped from the absorber to the stripper vessel for regeneration. The amine solution is first pre-heated in a lean/rich heat exchanger with heat transferred from hot, regenerated amine leaving the stripper and returning to the absorber. This process recovers otherwise lost energy, and increases the system’s overall thermal efficiency. The rich pre-heated amine solution is then distributed to the stripper, a vertical tower with internals to enhance mass transfer, through a series of nozzles. The stripper acts as a distillation column, heating the rich amine solution, reversing the absorption reactions and liberating the captured CO2. Heat is supplied by steam powered reboilers at the bottom of the vessel. Steam for the reboilers is diverted from the unit’s turbine-generator, reducing the amount of electrical power the unit can produce. This part of the process represents the biggest single energy requirement for carbon capture.
The liberated CO2 rises through the stripper column and exits the top, where it cools and condenses to moisture and small amounts of amine. The CO2 is then directed to a compression plant prior to being sent off site via a pipeline. In the Boundary Dam plant demonstration, the CO2 will be directed to depleted oil reservoirs for enhanced oil recovery.
The hot, regenerated amine is pumped back to the absorber via the lean/rich heat exchanger where it is cooled. Further cooling with water may also be necessary before the lean amine is reintroduced to the absorber, to begin the cycle again. The overall CO2 capture process is extremely energy intensive, with typical parasitic loads requiring up to 30% of the unit’s gross energy output. Improvements are continuously being sought through process and amine advancements, and improved heat integration.
CO2 capture at the scale needed for electricity generating plants relies on new, not fully commercialized technologies, or on designs that have only been proven at much smaller facilities. Therefore, a detailed risk assessment forms a critical part of any CO2 capture project. Technical specialists conducted both a qualitative and quantitative risk analysis on the Boundary Dam demonstration project.
Another project challenge is the layout of the facilities and equipment on the existing site. Adding CO2 capture equipment to the retrofitted unit results in increased congestion. The operation of an amine capture system requires access to both the flue gas and the turbine, which in a typical plant such as Boundary Dam are in separate areas. This means that long lengths of ductwork and piping are required to both capture CO2 and regenerate the amine. In addition, carbon capture technology usually requires that additional reagents such as amine, or ammonia makeup and limestone, are brought to site and that additional waste material is removed. Facilities for receiving and removing these materials must be included in the layout.
Efficient and cost effective, CO2 capture will be critical to the future large scale use of coal for power generation. SaskPower’s BD3 ICCS project is on the cutting edge of this effort. If the demonstration project is successful and the 100-MW plant is fully operational in 2015, it would capture approximately one million tonnes of carbon dioxide annually, showing that power can be generated in an economic and environmentally safe manner from domestic fuels that are in abundant supply.
David Cameron, P. Eng. is a senior principal with Stantec, based in Fredericton, N. B.; Mike Richard, P. Eng. is a process engineer with Stantec, based in Regina, Sask.