Repowering Options for Complying with Canadian CO2 Emission Intensity Limits on Existing Coal Plants

• Published in: Energy procedia Vol. 114; pp. 6386 - 6402
• Main Authors: Butler, David, Hume, Scott, Scott, Stephen, Lamprecht, Dieter
• Format: Journal Article
• Language: English
• Published: Elsevier Ltd 01.01.2017
• Subjects: CO2 capture; post combustion capture; Power plant repowering; techno-economics; Power plant repowering; CO2 capture; techno-economics; post combustion capture
• ISSN: 1876-6102; 1876-6102
• DOI: 10.1016/j.egypro.2017.03.1775

The Canadian federal government has introduced carbon dioxide emission intensity limits of no greater than 420 kg/MWh net for new coal plants and existing coal plants more than 50 years of age. Many operating coal plants in Canada will be impacted by this legislation in the near future, requiring operators to plan a compliance strategy. The Canadian Clean Power Coalition (CCPC) investigated the performance and economics of a number of options for existing plants that could deliver compliant solutions. These options included strategies in which natural gas is available and some in which only coal firing is feasible due to cost or logistical issues. Repowering and post-combustion capture (PCC) options were studied using an eastern Canadian power plant firing bituminous coal. The base-case (BC) option was a new combined-cycle gas turbine (CCGT) plant, against which all other options were compared. The following cases were investigated:1.PCC using:a.Monoethanolamine MEA solvent with crossover steam regenerationb.Commercial advanced solvent with crossover steam regenerationc.Commercial advanced solvent with a small gas turbine (GT) and a low-pressure steam generatord.Commercial advanced solvent with a GT, triple-pressure heat recovery steam generator (HRSG) and a back pressure steam turbinee.Commercial advanced solvent with a natural gas boiler and a back pressure steam turbine2.Repowering of existing steam turbines with new a GT and HRSG3.Repowering of existing steam turbines with fuel cellsa.New solid oxide fuel cell (SOFC) topping unitb.New molten carbonate fuel cell (MCFC) topping unit4.Expanded PCC approach with:a.Third unit with full LP steam turbine bypass supplying steam to PCCb.Circulating fluidized bed (CFB) boiler and back pressure steam turbine One of the issues with incorporating PCC in an existing facility is delivering the thermal regeneration energy to the PCC reboilers in an efficient and cost-effective manner. This can involve significant integration with the low-pressure stages of the steam turbine, a duty for which the turbine was not designed. Because turbine modifications (to deliver partially expanded steam to the PCC plant) can be costly and would require significant down time, alternative strategies were investigated in which the PCC facility would effectively be a “standalone” facility, with the main plant interfaces being the flue gas to be treated and some shared services. The costing analysis was carried out on the following basis: 30-year plant design life (with life-extension costs included for existing plant), 90% capacity factor for the first year cost of electricity (COE), and a coal cost of $4.73/GJ and a natural gas cost of $10.00/GJ (based on 2013 forecasted costs). Case 2 (repowering existing steam turbines with new natural gas combined-cycle plant) without any additional CO2 abatement, delivered both the lowest capital costs and cost of electricity. If the existing coal boiler plant remains operational, the lowest costs were achieved by installing a molten carbonate fuel cell (Case 3b) followed closely with an advanced solvent PCC unit with solvent regeneration thermal energy being delivered by an efficient, small, dedicated gas turbine with a triple pressure HRSG (Case 1d). Where there is no existing infrastructure to deliver natural gas, the traditional methodology of extracting crossover steam from the unit for PCC solvent regeneration proved to be the lowest-cost option.