Economic Analysis of Advanced Ultra-Supercritical Pulverized Coal Power Plants: A Cost-Effective CO2 Emission Reduction Option?

Jeffrey N. Phillips and John M. Wheeldon Electric Power Research Institute

Charlotte, NC, USA

Abstract

A recent engineering design study conducted by the Electric Power Research Institute (EPRI) has compared the cost and performance of an advanced ultra-supercritical (A-USC) pulverized coal (PC) power plant with main steam temperature of 700ºC to that of conventional coal-fired power plant designs: sub-critical, supercritical, and current USC PC plants with main steam temperatures of 541º, 582º, and 605ºC, respectively. The study revealed that for a US location in the absence of any cost being imposed for CO2 emissions the A-USC design was a slightly more expensive choice for electricity production. However, when the marginal cost of the A-USC design is compared to the reduction in CO2 emissions, it was shown that the cost of the avoided CO2 emissions was less than $25 per metric ton of CO2. This is significantly lower than any technology currently being considered for CO2 capture and storage (CCS). Additionally by lowering CO2/MWh, the A-USC plant also lowers the cost of CCS once integrated with the power plant. It is therefore concluded that A-USC technology should be considered as one of the primary options for minimizing the cost of reducing CO2 emissions from future coal power plants.

Engineering-Economic Study of Advanced USC

In 2008 EPRI published an engineering-economic evaluation that compared the cost and performance of an Advanced Ultrasupercritical (A-USC) pulverized coal (PC) power plant to that of more conventional coal-fired power plant designs.i EPRI utilized the engineering staff at WorleyParsons’ Reading, Pa office and Doosan Babcock Energy America LLC to produce the evaluation. The work was sponsored by the members of EPRI’s CoalFleet for Tomorrow® research program.

Advances in Materials Technology for Fossil Power Plants Proceedings from the Sixth International Conference August 31–September 3, 2010, Santa Fe, New Mexico, USA 05319G

Copyright © 2011 Electric Power Research Institute Distributed by ASM International®. All rights reserved. D. Gandy, J. Shingledecker, R. Viswanathan, editors

53

The A-USC plant design was based on the conditions envisioned for EPRI’s UltraGen II demonstration plant. UltraGen II is the second of three demonstration plants proposed to advance coal power generation technology with 90-percent CO2 capture to achieve thermal efficiencies comparable to those of today’s state-of-the-art coal power plants without capture.ii It would incorporate advanced nickel-based alloys in the steam system to allow temperatures of up to 700ºC. It is similar to the design envisioned for the European AD700 project.

The important design parameters for the A-USC plant used in the engineering-economic evaluation as well as those of the more conventional designs are listed in Table 1. Each plant was sized to produce 750 MW of net power and to use sub-bituminous coal from the Powder River Basin (see Table 2). The flue gas temperature exiting all four boilers was assumed to be 120°C and the boiler efficiency was 87 percent. This lower temperature was adjudged feasible because of the low SO3 production from the low sulfur coal.

Table 1 - Design Parameters for the Power Plants Examined in EPRI’s 2008 Study

Sub-critical Supercritical Current USC A-USC SH Temperature, ºC 541 582 604 680 SH pressure, bar 179 262 276 352 RH temperature, ºC 541 582 604 700 RH pressure, bar 35.9 57.9 65.5 73.5

Environmental performance criteria:

• SO2 30 mg/Nm3 (0.03 lb/MMBtu), wet flue gas desulfurization (wet FGD)

• NOX 30 mg/Nm3 (0.03 lb/MMBtu), low-NOX burners (LNB) with over-fired air (OFA), and selective catalytic reduction (SCR)

• PM2.5 13 mg/Nm3 (0.013 lb/MMBtu), wet FGD

• PM10 10 mg/Nm3 (0.01 lb/MMBtu), electrostatic precipitator (ESP)

• Mercury 90 percent reduction, CaBr2 injection into furnace to promote oxidation across the SCR followed by co-capture in the wet FGD.

54

Table 2 - Powder River Basin Coal Properties for EPRI’s 2008 Study

Proximate Analysis Weight Percent As Received Moisture 30.24 Ash 5.32 Volatile 31.39 Fixed Carbon 33.05 Ultimate Analysis Weight Percent As Received

Carbon 48.18 Hydrogen 3.31 Nitrogen 0.70 Chlorine 0.01 Sulfur 0.37 Oxygen 11.87 Ash 5.32 Moisture 30.24

Heating Value As Received HHV, kJ/kg (Btu/lb) 19,400 (8,340) LHV, kJ/kg (Btu/lb) 17,900 (7,710)

Key performance results from the study are presented in Table 3. Because the coal consumption decreases by over 15% between the sub-critical and A-USC cases while the power output remains constant, there is automatically a similar reduction in the CO2 emissions rate on a kg/MWh basis. It should also be noted that the amount of flue gas to be processed by the air quality control equipment also decreases as the thermal efficiency increases. This allows for capital cost savings in the emission control equipment.

Table 3 Key Performance Results from A-USC Study

Sub-critical Supercritical Current USC A-USC Thermal efficiency, %(HHV) 36.2 38.5 39.2 42.7 Net heat rate, Btu/kWh (HHV)

9,430 8,860 8,700 7,990

Coal feed rate, kg/hr 384,000 361,000 355,000 326,000 Flue gas mass flow, kg/hr 3,420,000 3,151,000 3,098,000 2,827,000 Volume at boiler outlet, actual m3/min

66,700 61,400 60,400 55,100

NOX and SO2, kg/MWh 0.127 0.121 0.118 0.109 PM10, kg//MWh 0.0422 0.0399 0.0395 0.0363 PM2.5, kg/MWh 0.0535 0.0508 0.0499 0.0458 CO2, kg/MWh 900 851 836 763

55

EPRI is a member of a US research collaborative which is developing and testing advanced alloys which would make it possible to design an A-USC that could operate with main steam temperatures of 732ºC and reheat temperature of 760ºC.iii The collaborative receives the majority of its funding from the US Department of Energy (DOE) and receives significant co-funding from the Ohio Coal Development Office (OCDO) as well the industrial participants. As part of that project EPRI has estimated that at these higher steam conditions the thermal efficiency is 44.7% on an HHV basis (7,630 Btu/kWh). This would provide another 5% reduction in CO2 emissions. Heat rate improvement measures, such as enhanced back-end heat recovery, would lower the CO2 emissions still further.

Important results from the economic analysis in the 2008 EPRI evaluation are presented in Table 4. The capital costs quoted in the Table are based on costs in mid 2007 for a plant site in Kenosha, Wisconsin and would probably be higher today. The costs are also based on EPRI’s definition of “total plant costs” which is often referred to as “overnight cost” and does not include owner’s costs such as land acquisition, financing and permitting as well as initial start-up expenses.iv Costs for things outside the plant’s boundary limits such as transmission lines and water pipelines are also excluded. It should also be noted that the A-USC cost is an estimate for an “Nth-of-a-kind” plant and therefore has the same project contingency percentage as the other cases.

Table 4 Key Economic Results from A-USC Study – Assumes No Cost Penalty for CO2

Emissions

Sub-critical Supercritical Current USC

A-USC

Capital cost, $/kW 1780 1800 1840 1990 Coal cost, $/GJ 1.71 1.71 1.71 1.71 Cost of Electricity* Capital, $/MWh 28.9 29.3 29.9 32.3 O&M, $/MWh 8.1 8.1 8.2 8.6 Fuel, $/MWh 17.0 15.9 15.7 14.4 Total, $/MWh 54.0 53.3 53.7 55.3 Dispatch cost, $/MWh**

18.6 17.4 17.1 15.7

*Mid-2007 dollars, 30-year book life, carrying charge 0.121, capacity factor 85 percent **Fuel cost plus variable O&M

56

From the data in Table 4 it is clear that at the relatively low delivered cost for Powder River Basin coal and with no charges for CO2 emissions, the A-USC design does not have a cost-of-electricity advantage over the other cases. In fact, the results help explain why in recent years US developers of new coal power plants have chosen designs that are similar to the “Supercritical” case in the table. Meanwhile in regions with relatively high coal prices such as Japan and Germany and in China where coal delivery constraints have put a premium on higher efficiency, power plant builders have predominantly selected designs similar to the “Current USC” case in the Table. The higher cost of electricity from the A-USC design is due primarily to its higher capital costs. Our engineering study showed that while the A-USC had lower costs for emission control systems as well as “balance of plant” systems such as coal handling and cooling towers, this was not sufficient to overcome the increased cost of the boiler and steam turbine. The use of nickel alloys which cost significantly more than ferritic steels on a per kg basis is the primary reason for the higher boiler and steam turbine costs. The cost of the A-USC boiler and steam turbine systems was 26% more than the cost of those systems for the SCPC design, and overall the A-USC plant was 10% more expensive than the SCPC design.

However, if an A-USC plant were built it would be at the top of the merit order and be dispatched ahead of all other units. Table 4 shows the dispatch cost to be 10 percent lower than that for the supercritical unit.

Including Costs for CO2 Emissions Changes the Preferred Design

Based on the results in Table 4 one could conclude that there is little incentive to work on development of 700ºC or higher A-USC technology. However, if one assumes that a relatively modest cost of $25/metric ton is imposed for CO2 emissions, the economics shift in favor of the A-USC design (see Table 5). In fact, when a calculation of the cost of avoided CO2 emissions is made, one can see that moving to the higher efficiency provided by A-USC may be one of the lower cost options for decreasing CO2 emissions.

Table 5 Levelized Cost of Electricity in $/MWh as a Function of CO2 Emission Cost

CO2 Emission Cost, $/metric ton

Sub-critical Supercritical Current USC A-USC

0 54.0 53.3 53.7 55.3 25 76.5 74.6 74.6 74.4 50 99.0 95.9 95.5 93.5

57

The cost of avoided CO2 emissions is calculated based on the following formula: Avoided emissions cost ($/metric ton) = [($/MWh) – ($/MWh)base]/ [(kg CO2/MWh) base – (kg CO2/MWh)]/1000

where the “base” subscript represents the baseline condition.

If the Supercritical case is taken as the baseline condition, which seems sensible since it is the lowest cost option for evaluated location without CO2 emission costs, then the avoided CO2 emissions cost for the A-USC case is:

Avoided cost = [55.3-53.3]/[851 – 763]/1000 = $22.7/metric ton CO2

This is a very low cost compared to estimates for the cost of avoiding CO2 emissions by installing a post-combustion capture system and storing the CO2 in deep geologic strata. An estimate for that cost based on using monoethanolamine (MEA) solvent published in mid-2007 by the US Dept. of Energy was $62 per metric tonv, so moving to A-USC technology would yield CO2 emission reductions from coal power plants at a cost which is less than half that of commercial post-combustion capture technology integrated with geologic storage.

Higher Efficiency Decreases CO2 Capture Costs

Not only does higher thermal efficiency provide cost-effective CO2 emission reductions by itself, it also opens the door to lowering the cost of CO2 capture and storage from coal power plants. Because more efficient coal plants produce less CO2 per MW of net output, less energy is required to capture and compress the CO2 in the flue gas of those plants, again on a per MW output basis. In addition to energy savings, there would also be capital cost savings as the amount of flue gas being scrubbed of CO2 would be less and therefore the equipment would be smaller.

This effect of thermal efficiency was demonstrated in an earlier evaluation of the impact of adding an amine-based, post-combustion CO2 capture system onto coal power plants.vi The results of that study are summarized in Figure 1. The evaluation showed that if a PC power plant with a thermal efficiency of only 35% (HHV basis) without CO2 capture is then equipped with an MEA system capable of capturing 90% of the CO2 from the flue gas, the levelized cost of electricity would increase by almost 50%. (It should be noted that this analysis did not include the impact of geologic storage costs.) However, if an A-USC plant with a thermal efficiency of 45% without CO2 capture was equipped with a similar MEA system, its cost of electricity could increase by less than 40%.

58

110%

120%

130%

140%

150%

30 35 40 45 50

Efficiency of PC plant without CO2 capture, % (HHV)

CO

E R

elat

ive

to N

on-C

CS

Cas

ePittsburgh #8 PRB

COE based on KS-1 solvent, but oxy-combustion considered similar

Increase in Levelized Cost of Electricity due to CCS is

Significantly Decreased with Increased Efficiency

DOE Target of 35% Increase

110%

120%

130%

140%

150%

30 35 40 45 50

Efficiency of PC plant without CO2 capture, % (HHV)

CO

E R

elat

ive

to N

on-C

CS

Cas

ePittsburgh #8 PRB

COE based on KS-1 solvent, but oxy-combustion considered similar

COE based on KS-1 solvent, but oxy-combustion considered similar

Increase in Levelized Cost of Electricity due to CCS is

Significantly Decreased with Increased Efficiency

DOE Target of 35% Increase

Figure 1 - Impact of base plant thermal efficiency on the increased cost of electricity when

adding post-combustion capture (does not include impact of geologic storage costs).vi

If an A-USC plant replaced an older coal-fired power plant that had a thermal efficiency equal to that of the average US coal power plant (33% HHV basis), this new design would reduce CO2 emissions by at least 25% per MWh even without employing any CO2 capture and storage. Including 50% CO2 capture would lower the emissions to those of a modern natural gas fired power plant (381 kg/MWh). As seen from Table 6, the amount of CO2 captured and sent to storage would be 26 percent lower than for a sub-critical unit trying to reach the same kg/MWh emissions level. In addition to reducing the size of the equipment needed to capture and compress the CO2, the A-USC design would also require less CO2 transportation and storage capacity.

Table 6 Reduction in CO2 emissions required to match emissions of NGCC

Sub-critical Supercritical Current USC A-USC CO2 emissions, kg/MWh 900 851 836 763 Reduction required, kg/MWh 519 470 455 381

Percent reduction to match NGCC 58 55 54 50

59

Other Options for Increasing Thermal Efficiency

It should be noted that pushing the steam cycle to higher pressures and temperatures may not be the only cost-effective method to decrease CO2 emissions in a new coal power plant. Other options which in the past may have been ruled out as uneconomic may offer CO2 reductions at costs far less than current CO2 capture and storage technology. Examples of these include coal drying technologies which utilize low level heat from the steam cycle to remove moisture from the coal before it enters the boiler and natural draft cooling towers. Both Great River Energy in the USvii and RWEviii in Germany have recently installed innovative coal drying systems on power plants burning low-rank, high-moisture coal, and many coal power plants in Europe have been built with low-temperature flue gas heat recovery and natural draft cooling towers which also improve thermal efficiency while requiring more capital investment.

Advanced USC Materials Development Efforts

Efforts to verify the suitability of materials for use in A-USC designs have been progressing in both Europe and the United States. The European effort has aimed at demonstrating a power plant with main steam conditions at 365 bar and 700ºC.ix A key step in the European development program was the operation of a component test facility (Comtes700) at E.ON AG’s Scholven power plant in Gelsenkirchen, Germany (see Figures 2 and 3). Comtes700 included an evaporative wall panel and a superheater assembly which operated under realistic conditions in the boiler as well as headers, piping, and valves. The superheater panel was fabricated with tubes made from several different materials including the nickel alloys 617 and 740. The equipment accumulated more than 16,000 thousand hours of operation with superheated steam temperatures ranging from 600 to 705ºC with more than 11,000 hours at superheated steam temperatures above 680ºC.x The Comtes700 facility completed its testing campaign in 2009.

60

Figure 2 - View of E.ON’s Scholven Power Station (left) which hosts the Comtes700 facility

and a view of some of the Comtes700 piping (right).

Figure 3 – Schematic Diagram of the Comtes700 facilities at E.ON’s Scholven Power Station

61

In the USA, a consortium funded primarily by the US DOE and with significant co-funding from the state of Ohio’s OCDO has been working since 2002 to develop and test materials that would allow coal-fired power plants to operate with steam temperatures up to 760ºC. Separate projects have been initiated for the development of boiler materials and steam turbine materials. The participants in each project are summarized in Table 7.

Table 7 – Participants in the US DOE – Ohio Coal Development Office USC Materials Projects

Boiler Materials Steam Turbine Materials Administrative Lead & Prime Contractor

Energy Industries of Ohio

Administrative Lead & Prime Contractor

Energy Industries of Ohio

Technical Lead EPRI Technical Lead EPRI Research Tasks Leaders

Alstom, Babcock & Wilcox, Foster Wheeler, Riley Power

Research Tasks Leaders

Alstom, General Electric, Siemens

Team Leaders for Metallurgical Support

Oak Ridge National Lab, National Energy Technology Lab – Albany Research Center

Team Leaders for Metallurgical Support

Oak Ridge National Lab, National Energy Technology Lab – Albany Research Center

A detailed description of the scope and results of the DOE-OCDO materials research projects is provided elsewherexi; so only a brief summary will be given here.

The project has subjected a number of candidate materials for both boiler and turbine components to a thorough testing program and has identified several materials that are suitable for the targeted main steam conditions of 760ºC and 350 bar including Inconel 740 and Haynes 282. The program has developed fabrication and joining technologies for these new materials and is accumulating the long-term exposure data that will be needed to support ASME code approval.

Next Steps for A-USC Technology

The DOE-OCDO consortium has identified additional steps needed to prepare for a full-scale 760ºC demonstration plant based on the materials tested to date. One important task is to develop the supplier base so that piping, forgings and castings of the desired size and quantity can be produced in an economically attractive manner. Another important step will be a component test facility similar to the Comtes700 to test commercial scale boiler and superheater tubing, headers, and steam valves in real coal-fired power plant conditions. Ideally such a facility would accumulate up to 15,000 hours of operation over a three-year period to show that the materials and their fabrication techniques are able to perform in a commercial operating environment. The consortium is currently seeking an owner of a coal-fired power plant to host such a test facility.

62

Parallel to the boiler component test facility, a steam turbine component development program would be carried out. That program would include the detailed design of the full turbine and fabrication of key components followed by testing in a simulated operating environment.

Based on the success of the boiler and steam turbine materials characterization and supporting design activities, the next step would be to build an A-USC PC demonstration plant operating with main steam temperature in excess of 700ºC. Because of first-of-a-kind costs associated with such a unit, federal support from a program such as DOE’s Clean Coal Power Initiative will be required. It is projected that design and materials information would be available in 2015, and the plant could be operating by 2020 after which the technology would be offered commercially by boiler and turbine suppliers.

References

1. i Engineering and Economic Evaluation of 1300°F Series Ultra-Supercritical Pulverized Coal Power Plants: Phase 1. EPRI, Palo Alto, CA: 2008. 1015699.

2. ii Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision, EPRI, Palo Alto, CA: 2008. 1016877.

3. iii Viswanathan, R., J. Shingledecker, and J. Phillips, “In Pursuit of Efficiency in Coal Power Plants”, International Clearwater Coal Conference, Clearwater, Fl, June 2010.

4. iv Program on Technology Innovation: Integrated Generation Technology Options. EPRI, Palo Alto, CA: 2009. 1019539.

5. v Klara, J. M., “Fossil Energy Power Plant Desk Reference”, National Energy Technology Laboratory, DOE/NETL-2007/1282, May 2007.

6. vi Program on Technology Innovation: Evaluation of Amine-Based, Post-Combustion CO2 Capture Plants. EPRI, Palo Alto, CA: 2008. 1011402

7. vii Bullinger, C., “Implementing Coal Drying”, Int’l Symposium on Low Rank Coal, Melbourne, Australia, April 27-30, 2010.

8. viii Dr. Johannes Ewers, Dipl.-Ing. Hans-Joachim Klutz, Dipl.-Ing. Werner Renzenbrink & Dr. Gunther Scheffknecht, The Development of Pre-Drying and BoA-Plus Technology, VGB Conference – PowerPlants in Competition – Technology, Operation and Environment, Cologne, Dorint Kongress Hotel, March 19-20, 2003.

9. ix Meier, H.-J., “Pre-Engineering Study for a 700ºC High-efficiency Power Plant”, VGB Powertech, 10/2009, pp 71-77, 2009.

63

10. x Gierschener, G., “COMTES700”, presented to EPRI CoalFleet Technical Meeting,Gelsenkirchen, Germany, 29 October, 2008.

11. xi Viswanathan, V., and J. Shingledecker, “U.S. Program for Ultra-supercriticalPulverized Coal Power Plants”, Sixth Int’l Conf. on Advances in Materials Technologyfor Fossil Power Plants”, Santa Fe, NM, 31 August, 2010.

64