By Jared P. Ciferno, US DOE/ National Energy Technology Laboratory and Timothy J. Skone and Massood Ramezan, Science Applications International Corp.
DOE conducted a study evaluating the technical and economic feasibility of retrofitting an existing coal-fired electric power plant with CO2 capture using “advanced amine-based” scrubbing at various levels of CO2 capture (30 percent, 50 percent, 70 percent and 90 percent). The present study is based on an advanced monoethanolamine (MEA) process similar to the process being developed by Fluor Corp.
The power plant analyzed in this study was American Electric Power’s Conesville Unit #5. This unit has been in commercial operation since 1976 and is currently operated using Midwestern bituminous coal (11,293 Btu/lbm) with around 2.7 percent sulfur. The unit is a tangentially fired, subcritical pressure, controlled circulation, radiant heat wall unit with five levels of burner elevations. It is a “conventional arch” type design, representative of a large number of coal-fired units in use throughout the United States. The unit is designed to generate 3,131,619 lbm/hr of steam at 2,400 psia and 1,005 F with reheat steam at 1,005 F, which is considered representative of the most common steam cycle conditions for the existing U.S. fleet. The generator produces around 433 MWnet (463 MWgross) of electric power at maximum continuous rating.
The plant is equipped with an electrostatic precipitator (ESP) for particulate control and a wet lime-scrubbing process gas desulfurization unit (FGD) with an SO2 removal efficiency of 94.9 percent–corresponding to a value of 104 ppmv of SO2 in the flue gas at the absorber outlet.
Adding amine scrubbing CO2 capture did not require modification of the boiler island, coal milling process and ESP. Therefore, the operation and performance of the existing boiler (base case scenario) and ESP systems were identical for all CO2 capture cases. The modifications started with the FGD unit. As designed, the flue gas leaves the modified FGD unit and is ducted to the amine CO2 capture unit. There, the desired level of CO2 is recovered, compressed and liquefied in preparation for pipeline transport. The remaining flue gas (consisting primarily of nitrogen, oxygen, water vapor, a relatively small amount of SO2 and unrecovered CO2) is discharged to the atmosphere.
The FGD unit is modified by adding a secondary absorber to reduce the SO2 content to 6.5 ppmv (<10 ppmv SO2 is required by the amine system downstream), equivalent to an overall SO2 removal efficiency of 99.7 percent. The new secondary absorber is a single 42-ft diameter vessel, adjacent to the current lime preparation and scrubber equipment building.
For the 90 percent CO2 capture case (known as case 1), the entire flue gas stream is treated in the absorber. For the cases with less than a 90 percent CO2 recovery (referred to as cases 2, 3 and 4) it was more economical to treat part of the flue gas in the absorber (which remove 90 percent CO2 in the treated stream) and bypass the remainder of the flue gas directly to the stack.
A detailed analysis of the modified steam turbine was completed to optimize the system at various levels of CO2 recovery. The two main modifications were to: (1) add a new letdown steam turbine generator (LTSG) and (2) add a steam extraction point and a control valve to the crossover piping between the intermediate pressure (IP) turbine outlet and the low pressure (LP) turbine inlet.
For the 90 percent CO2 removal case (case 1), approximately 50 percent of the steam flow exiting the IP is required in the MEA plant (specifically, the reboiler). Before the steam is sent to the reboiler, it is expanded in the new LDST. This 50 percent reduction in steam flow also results in about a 50 percent reduction in IP exit and LP inlet steam pressures. To compensate for the IP exit pressure loss (and to prevent excess mechanical loading on the IP blades), a pressure control valve was added to the crossover pipe. No other modifications were required to compensate for the low LP inlet pressure, since operating the LP turbine at half flow was within the operational range.
Adding MEA scrubbing affected power plant performance in two ways. First, steam used for CO2 regeneration never had a chance to generate power; thus, the gross power generated was decreased from 463 MWgross to between 331 to 441 MWgross. Second, large amounts of additional auxiliary power were required by the CO2 capture and compression systems which produce liquid CO2 at 2,015 psia. The combined capture and compression systems consume between 19 and 55 MWe.
Net plant heat rate and thermal efficiency were degraded relative to the base case. The thermal efficiency loss ranges between 3 and 15 percentage points. There was a nearly linear relationship between the level of CO2 capture and net efficiency–meaning no performance ”sweet-spot” exists for capture levels less than 90 percent.
Specific CO2 emissions were reduced from 2 lbm/kWh for the base case to between 0.13-1.55 lbm/kWh–equivalent to a 7 to 93 percent reduction in CO2 emissions. “Avoided CO2 emissions” ranged between 1.87 lb/kWh (at 90 percent capture) and 0.45 lb/kWh (at 30 percent capture).
The project capital costs for all five cases include engineering, procurement and construction (EPC) and project and process contingencies and were estimated in July 2006 dollars. Capital costs encompassed the following equipment: new advanced MEA-based CO2 capture system, new CO2 compression, dehydration and liquefaction system, modified FGD system, new letdown steam turbine generator and corresponding steam cycle modifications. Plant capacity factor is 85 percent. Operating and maintenance costs include the incremental cost of operating labor (fixed O&M expense); cost of waste handling, chemicals, maintenance and make-up power–that is, loss of revenue from reduction in net power–(variable O&M expense); and natural gas to regenerate the desiccant in the carbon capture systerm (feedstock O&M expense).
The net power output of the retrofitted plant varies depending on the change in parasitic load required to operate the carbon capture system. The coal feed rate was held constant at the base plant rate for each case, because the boiler and other plant equipment cannot be economically changed to accommodate the increased parasitic load. As a result, a portion of the steam produced was diverted from the primary steam turbine to a let-down steam turbine and then to the carbon capture system. This, in turn, affected the plant’s parasitic load.
The let-down steam turbine produces only a fraction of the total carbon capture system power requirement while reducing the steam pressure. The reduction in power produced and sold by the plant is accounted for as a variable O&M expense in the form of a make-up power cost (MUPC) at a rate of 6.40 ¢/kWh–equivalent to the levelized cost of electricity from a new subcritical pulverized (bituminous) coal power plant without carbon capture. The selection of “equivalent” MUPC can vary depending on regional differences in power supply and analytical approaches to determining marginal power supply off-sets. For this study, MUPC was set to the retrofitted plant type, new greenfield plant design, without carbon capture.
The incremental cost of carbon capture and CO2 mitigation cost were evaluated across a range of CO2 capture rates at constant solvent regeneration energy of 1,550 Btu/lbm-CO2. The results show an almost linear relationship between CO2 capture rate and incremental cost of electricity and CO2 mitigation cost. The incremental COE ranged from 6.92 to 2.31 ¢/kWh, a 67 percent decrease as the CO2 capture rate was lowered from 90 percent to 30 percent. The cost of CO2 mitigation increases 30 percent from $54 to $70/ton when the capture rate is decreased from 90 percent to 30 percent.
The analysis determined that no significant technical barriers exist to retrofitting AEP Conesville Unit #5 for up to 90 percent CO2 capture using current state-of-the-art amine-based scrubbing technology. Based on the study’s technical and economic analysis, there is approximately a linear relationship between the CO2 capture rate (30 percent to 90 percent) and the net thermal efficiency, incremental COE and CO2 mitigation cost.
This article is part of a study conducted for DOE/NETL. The full report can be found at http://www.netl.doe.gov/energy-analyses/ref-shelf.html.