CO2 CAPTURE OPTIONS FOR AN EXISTING COAL FIRED POWER PLANT: O2/CO2 RECYCLE COMBUSTION vs. AMINE SCRUBBING

The existing fleet of modern pulverized coal fired power plants represents an opportunity to achieve significant greenhouse gas (GHG) emissions in the coming years providing efficient and economical CO2 capture technologies are available for retrofit. One option is to separate CO2 from the products of combustion using conventional approaches such as amine scrubbing. An emerging alternate, commonly known as O2/CO2 recycle combustion, involves burning the coal with oxygen in an atmosphere of recycled flue gas. Both approaches can be retrofitted to existing units, however they consume significant amounts of energy to capture, purify and compress the CO2 for sequestration. This paper compares the performance of the two approaches using a commercial process simulation package (HYSYS). The goal of this particular study is to preserve the net power output of the original plant. To accomplish this objective, the internal energy needs of each capture process are met by firing natural gas. The emissions produced as a by-product of supplying these additional energy needs are considered in the determination of the resulting overall plant emissions. The energy requirements needed to satisfy each approach are compared, pointing to the need to develop different energy integration strategies for each process. Finally, the goals of future research work sponsored by the CANMET CO2 Consortium in this area are described. Introduction Close to half of the electricity generated in North America comes from coal combustion. Modern pulverized coal fired power plants are also some of the largest single point emitters of greenhouse gases, in particular CO2. With such a large opportunity to impact CO2 releases to the atmosphere, there is a compelling need to explore the best near term strategy to retrofit the existing fleet to capture CO2. Retrofit options are becoming even 1 Corresponding Author more attractive with recent increases in natural gas prices emphasizing the importance of coal resources in North America’s long term energy future. This paper will compare the performance of two different technologies that can be retrofitted to capture CO2, namely O2/CO2 recycle combustion and amine scrubbing. The simulation of each process is done using HYSYS, a commercially available process simulator. This study assumes that the energy required for the CO2 separation equipment is provided by firing natural gas so that the overall plant maintains its original power output to the grid. It is further assumed that the CO2 product is delivered at a high purity (98%) to be used in Enhanced Oil Recovery operations (EOR) (McDonald et al., 1999). Simbeck and McDonald (2000) compared these two technologies and concluded that the capital and operating cost in terms of $/tonne of CO2 avoided were similar for both cases. The study presented in this paper looks at each process in more detail using a process simulator in order to develop an understanding not only of the differing energy needs of each, but also to lay the groundwork necessary to identify the most appropriate energy integration strategy for each. Technology Background The technology currently exists to design, construct and make commercial guarantees for large scale amine scrubbers. In this process the flue gas is scrubbed with an amine based solvent in an absorption column. The solvent is regenerated in a second column thereby releasing a high purity CO2 product, as shown in Figure 1. Amine scrubbing with application to CO2 capture is being studied by many groups in the world (Chakma et al., 1999; Desideri et al., 1999; Hendriks, 1994; Riemer 1993). The focus of current research is on developing more efficient solvents and packings. Innovative work is being done by Kvaerner (Herzog, 2000) to combine the use of gas absorption membranes with amine scrubbing. Because it can be argued that the technology currently exists to build large scale amine plants, it is useful to treat amine scrubbing as a benchmark for emerging retrofit technologies. O2/CO2 recycle combustion technology seeks to dramatically increase the CO2 concentration in the product flue gases, thereby facilitating CO2 recovery. This combustion technique can be used alone or in combination with other approaches, however this paper considers only the classic case involving the complete substitution of combustion air by oxygen. In applying O2/CO2 combustion to retrofit situations, it is common to consider the use of relatively large quantities of flue gas to be recycled in order to moderate the flame temperature and to establish adequate flue gas flowrates through the existing boiler passages (Croiset et al., 1999; McDonald et al., 1999). This study assumes the oxygen is produced in a dedicated on-site facility using cryogenic air separation technology, which is the only technology currently available for very large plants. It is important to note that air leakage in the boiler, as well as the purity of the oxygen significantly impacts the resulting CO2 content of the flue gases produced (Singh et al., 2000). This paper takes a conservative approach assuming the worst case assumptions of 95% oxygen purity and 3% air infiltration yielding a flue gas with a CO2 content of 80% (by volume, dry basis). The resulting flue gas is then further purified using a simple low temperature flash (LTF) process, as shown in Figure 2. It is important to note that this additional purification step may not be required for every sequestration opportunity. Approach The overall assumptions are outlined and discussed below. Overall Assumptions: The scenario is built around a typical Canadian utility scale power plant burning a low sulphur western sub-bituminous coal. The plant is equipped with electrostatic precipitators and low NOx burners. The turbine condenser is cooled using evaporative cooling. The steam cycle remains unchanged. Although some previous amine studies have modified the steam cycle to extract the steam to be used in the CO2 separation (Desideri et al., 1999; Hendriks, 1994) this study avoids this complication which is judged too capital intensive for most retrofits. Natural gas is used to maintain the power output of the plant. Natural gas is chosen to provide the additional energy requirements of the CO2 capture process. This energy may be required in the form of low pressure steam and/or shaft power and will be provided using the most efficient combination of gas turbines and steam generators. The CO2 generated by the combustion of natural gas will not be captured in this study, however the quantity will be reflected in the calculation of the net plant emissions. This approach avoids the complexity of addressing these dilute emissions and is thought to be acceptable in retrofit situations provided that the total amount of CO2 avoided represents a significant proportion of the original plant emissions. CO2 product purity of 98% @ 150 bar. Near term sequestration opportunities for CO2 captured from large coal fired power plants favours EOR applications which require relatively high CO2 purity leading to the selection of a target purity of 98% for this study. A final product pressure of 150 bar was chosen to facilitate transport and sequestration of the CO2. Amine Case Assumptions: Capture 90% of the CO2 from the combustion of coal. Use a gas turbine to provide shaft power. In this case a natural gas fired gas turbine is used to provide power for all the compression and electrical power needs. Use a supplementary fired HRSG and an additional natural gas fired boiler to provide the steam load. The amine process requires a significant amount of low pressure steam for the regeneration of the solvent which is by far the largest energy consumer in this process. A gas turbine sized to provide the necessary shaft power coupled with a fully fired HRSG was found to provide insufficient steam thus dictating the need for an auxiliary natural gas fired boiler. O2/CO2 Recycle Combustion Assumptions: Oxygen Purity limited to 95%. Commercially available cryogenic air separation plants are capable of providing oxygen at up to 99.5% purity, however since the cost begins to escalate as the purity exceeds 95%, this study limits the purity to 95% in order to take a conservative approach with respect to the performance of the low temperature flash process required for final purification of the CO2 stream. 3% Air infiltration into boiler. Air infiltration in a well maintained balanced draft boiler is typically 3% of the total combustion air requirement. This value can be improved through the incorporation of improved sealing, however this study has taken a conservative approach and assumed an air infiltration value of 3%. The combination of the 95% oxygen purity and the 3% air infiltration value represents the “worst case” for nitrogen content in the flue gas (~20% N2 by vol. dry basis). Because a flash process will be used for final purification of the CO2, the presence of nitrogen in the flue gas will consequently limit the amount of CO2 that can be captured at any fixed CO2 purity level (Singh et al.; 2000). Power the ASU & Flash using a GTCC. The most efficient way to generate the power required by the Air Separation Unit (ASU), the flue gas flash process and the final flue gas compression is by firing natural gas in a gas turbine combined cycle. The dilute emissions from the GTCC will not be captured in this study, however the quantity will be reflected in the net plant emissions. Capture the maximum amount of CO2 at a purity of 98%. Thermodynamics limit the capture of CO2 using the flash process. This study will optimize the flash process for the maximum capture of CO2 while maintaining a CO2 purity of 98%. Case Studies The two cases selected for comparison are outlined in more detail below. In each case the energy required is quantified in terms of energy per tonne of CO2 avoided. Case A: Amine Scrubbing The amine case is shown in Figure 1. In this process five areas of energy consumption have been identified. A1.Re-boiler Duty: Low pressure (LP) steam is required to provide the heat necessary to separate the CO2 from the solvent in the re-boiler of the regeneration column. A2.Flue Gas Compression: The flue gas must be compressed slightly to facilitate the absorption of CO2 into the solvent. A3.CO2 Compression: The CO2 must be compressed to 150 bar in a multi-stage compressor to facilitate transport and sequestration. A4.Solvent Cooling: The solvent must be cooled (with cooling water) before being reused in the absorption column. A5.Partial Condenser: The vapour from the regeneration column must be partially condensed (with cooling water) to allow reflux back to the regeneration column. Figure 1: Amine Scrubbing Plant Case B: O2/CO2 Recycle Combustion TheO2/CO2 recycle combustion process flowsheet is shown in Figure 2. There are four major areas where energy is consumed in this process. B1. ASU Shaft Power: The ASU requires shaft power for air compression/separation. B2. Flue Gas Compression: The flue gas must be compressed before the flash step. B3. Refrigeration Compression: Cooling for the flash is provided by a mechanical refrigeration system. B4.Cooling Duty: The ASU, flue gas compressor and refrigeration system require cooling water in order to reject heat. Figure 2: O2/CO2 with ASU and Low Temperature Flash (LTF) CO2 Product (98+% Purity) Stack Gas Flue Gas Regeneration Column Make-up Water + MEA Absorption Column A4. Solvent Cooling A5. Partial Condenser A1. Re-boiler Duty A2. Flue Gas Compression A3. CO2 Compression CO2 Product (98% Purity) 95% O2