Design and Initial Operating Experience of a 150 MWe Utility Boiler Upgrade To Optimize Carbon Capture and Storage

Technical PaperBR-1926

Authors:B.E. Jordan Babcock & Wilcox Power Generation Group Canada Corp.Cambridge, Ontario, Canada

D. HoldernessSaskatchewan Power Corporation

Presented to:Proceedings of the ASME 2015 Power Conference

Date:May 31 - June 4, 2015

Location:Clearwater, Florida, U.S.A.

Design and Initial Operating Experience of a 150 MWe Utility Boiler Upgrade To Optimize Carbon Capture & Storage

BR-1926

Brian Jordan P.Eng., Project Engineer, Babcock & Wilcox Power Generation Group Canada Corp.

Darcy Holderness P.Eng., Sr. Mechanical Engineer, Integrated Carbon Capture and Sequestration, Saskatchewan Power Corporation

ABSTRACT

The energy requirements of a carbon capture facility added to an existing coal-fired power plant significantly reduce plant power output when heat input is limited by the capacity of the fuel delivery system and overall steam generator sizing. The plant output reduction can be minimized by improving boiler and turbine steam cycle efficiency. Babcock & Wilcox Power Generation Group Canada Corp. (B&W PGG Canada) designed, supplied and installed boiler components with this objective as part of Saskatchewan Power Corporation's (SaskPower’s) Integrated Carbon Capture & Storage (ICCS) demonstration project at the Boundary Dam Power Station in Estevan, Saskatchewan. The redesigned boiler heating surfaces were selected to improve boiler and overall plant efficiency by reducing stack temperature and increasing boiler outlet steam temperatures within the constraints of the original furnace and fuel delivery systems which were re-used. The optimized boiler configuration was successfully placed into service in 2014 with SaskPower’s Clean Coal Facility.

The superheater, reheater, economizer, and primary air heater surfaces were redesigned and replaced completely. New superheater and reheater components were redesigned to increase steam temperatures to a new steam turbine from the original 1000 to 1050F, (538 to 566C) thus improving turbine efficiency. The economizer, and tubular primary and secondary air heaters were replaced with heating surfaces selected to maximize boiler heat absorption and improve boiler efficiency. In addition, a new combustion system with separated overfire air (SOFA) was installed to reduce nitrogen oxides (NOx) emissions by approximately 50%.

This paper outlines the objectives, optimization process, design, construction, and final performance of the boiler refurbishment project as required to support the SaskPower ICCS initiative.

SASKPOWER ICSS PLANT OVERVIEW

The Boundary Dam station located near Estevan, Saskatchewan, consists of four operating units. Three units are rated at 150 MWe each and one at 300 MWe. All four of the operating units are based on an 1800 psig (12.41 MPa), 1000F (538C) steam cycle with a single stage of reheat. Babcock & Wilcox Canada executed major refurbishment projects on all of the Boundary Dam units through the 1990s and early 2000s.

The plant location is ideally situated for a CO2 capture and sequestration demonstration project due to:

- its close proximity to large lignite coal deposits, - oil production areas which can utilize CO2 for enhanced oil recovery, and - underground saline reservoirs which are suitable for CO2 sequestration.

Figure 1 illustrates the CO2 separation and sequestration process selected by SaskPower. The plant steam and water cycle is affected by the relatively large amount of low pressure steam required by the amine type CO2 and SO2 strippers.

Figure 1: Carbon Capture Utilization and Storage

ICSS HOST BOILER (UNIT #3) BACKGROUND

Unit #3 was originally commissioned in 1969. The steam generator is a tangentially-fired tower type originally supplied by Combustion Engineering Canada. Babcock & Wilcox Canada replaced the superheater and reheater heating surfaces in 1994 due to chronic tube attachment weld cracking in the original design.

Pulverized coal is delivered to the furnace from six (6) Raymond bowl mills. Flue gas passes upwards from the furnace across drainable superheater and reheater surfaces and then to the gas down pass which consists of economizer heating surface arranged in parallel with two tubular primary air heaters. Mixed flue gas leaving the primary air heaters and economizer enters two Ljungström type horizontal regenerative air heaters and proceeds to an electrostatic precipitator, induced draft (ID) fans, and stack. Figure 2 illustrates the boiler in its original configuration and in the current configuration. A schematic of the heat transfer surface arrangement is shown in Figure 3.

Figure 2 : Original Boiler Configuration, 1968 (Left); New Boiler Configuration, 2014 (Right)

Figure 3: Boundary Dam Unit #3 Boiler Heating Surface Schematic Arrangement

SaskPower selected Unit #3 as the host unit for the carbon capture facility in 2008 based on the results of a condition assessment study which indicated that a major maintenance outage would be required on this unit coinciding with the proposed timing of the carbon capture project. The project was also driven by new Canadian Federal regulations requiring reduced CO2 emissions from existing coal-fired plants at 50 years of operation. The condition assessment study indicated that all of the boiler pressure part convective heating surfaces and air heater heating surfaces would require replacement. The major concern for the boiler convective heating surfaces was sootblower and flyash erosion associated with the severe slagging and fouling characteristics and high ash content lignite coal. The regenerative secondary air heater was generally in good condition but the heat transfer elements (baskets) required replacement. The steam drum, water/steam circulation system, furnace enclosure, pulverized coal delivery system, and ash collection system were deemed suitable for the extended plant life.

The goal of the boiler refurbishment project was to maximize boiler efficiency (minimize unit heat rate) and reliability over the planned minimum 30 years of future unit operation, while staying within the limitations of a project budget that was cost effective during this time frame.

DESIGN OPTIMIZATION PROCESS

Engineering Study

SaskPower awarded Babcock & Wilcox Canada a contract to perform an engineering study in 2008. The objectives of the study were to develop a design which would deliver a required 30-year boiler life extension and maximize unit efficiency. Babcock & Wilcox Canada worked closely with SaskPower to develop a design which balanced the capital costs with the requirements for reliability and plant efficiency. Two ongoing performance related problems were to be addressed in the unit refurbishment.

a) The existing reheater surface required burner tilts above horizontal to maintain the design reheat outlet temperature. The resulting high furnace exit gas temperature increased slagging tendencies of the convective surfaces at the furnace exit. The heating surface of the new reheater was to be selected such that full load burner tilts were maintained below horizontal while maintaining the design hot reheat temperature.

b) A tendency toward steaming in the top (water outlet) economizer bank leading to overheating of the top horizontal tubes. Localized fouling leading to partial tube bank plugging and flue gas flow imbalances were occurring in the hot end of the economizer and tubular air heaters.

The CO2 capture process selected provides no reduction in the emissions of nitrogen oxides (NOx). Changes to the combustion system were thus required to maintain NOx emissions at or below current levels on a lb NOx per MWe output basis. The anticipated reduction in net unit output thus necessitated a reduction in NOx for the fixed fuel input. SaskPower elected to implement a completely new low NOx combustion system which would help reduce future NOx emissions well below pre retrofit levels.

Engineering Study Constraints

The SaskPower condition assessment study concluded that the existing furnace enclosure, steam drum, and circulation systems were in good condition and adequate to provide the planned unit life extension. As such, the replacement superheater and reheater surfaces in the boiler up-pass were designed to fit within the existing boiler enclosure.

Building steel limitations dictated that the redesigned boiler down-pass (economizer and primary air heaters) must fit within the ‘footprint’ of the existing components. It was also desirable to maintain the existing routing and location of the high energy piping between boiler and turbine. The existing sootblower elevations were to be retained wherever possible.

Past operating experience with this unit and its sister units (Boundary Dam #4 and #5) indicated that a maximum continuous boiler heat input of 1535 X 106 Btu/h (450 MWt) can be accommodated, as limited by:

- The capability of the existing fuel delivery system with one pulverizer out of service. - The sizing of the existing furnace.

o Heat input / plan area limited due to fuel ash slagging characteristic o Furnace exit gas temperature limited to 2200F (1204C) to prevent superheater/reheater

slagging.

Since the existing steam drum and water/steam-side circulation system were to be re-used, the existing boiler and superheater design pressure of 2160 psig (14.89 MPa) could not easily be increased. The plant steam cycle and new boiler components were designed around this limitation which dictated that the turbine inlet steam pressure could not be increased. The existing steam drum safety valves were retained.

The boiler auxiliary systems directly affected by boiler modifications to improve efficiency imposed additional constraints on these components:

1) Primary air heater: Maximum air outlet temperature is limited to approximately 760F (404C) by design temperature of existing hot air ducting, ducting expansion joints, and pulverizers. Primary air temperatures below 670F (364C) will not meet the requirements for drying high moisture fuels.

2) Secondary air heater: Limited to a maximum outlet air temperature of 500F (260C) by existing hot air ducting and expansion joints. Minimum flue gas outlet temperature is limited by cold-end corrosion rate.

3) Economizer: Limited to a maximum outlet water temperature of 583F (306C) to prevent steaming caused by flue gas unbalances and subsequent tube overheating/drum level instability.

The boiler, air heater and economizer heating surfaces must be selected in a coordinated fashion to maintain the operating conditions within the above constraints.

The minimum flue gas temperature leaving a regenerative air heater is a function of the corrosion potential of the flue gas, which is primarily dependent on the sulphur content of the fuel. For Saskatchewan Lignite (less than 1% sulphur) the minimum recommended average cold-end temperature is 155F (68C) to provide reasonable service life of the heat transfer elements. For 80F (27C) combustion air, this correlates to a minimum flue gas temperature of 230F (110C). Based on operating and maintenance experience of their existing units, SaskPower advised a minimum secondary air heater outlet target temperature of 300F (149C).

Design Conditions

The design of fossil-fired steam generators is governed by the combustion and fouling characteristics of the fuel and the steam/water boundary conditions which are defined by the design of the turbine and feedwater system.

Fuel Design Conditions

Accurate boiler heat transfer performance predictions of coal-fired boilers require an understanding of the coal ash slagging (high temperature) and fouling (low temperature) deposition characteristics. B&W PGG Canada has extensive experience with boiler design for Saskatchewan lignite spanning over 50 years. SaskPower provided a fuel analysis database including the characteristics of past fuel burned and analysis of core samples from areas to be mined in the future. These fuel analyses were characterized for their slagging, fouling, and erosion potential using B&W PGG Canada’s correlations. It was found that the characterization of future coals were not significantly different than previously burned coals, thus allowing operating cleanliness factor data from past testing to be used in the Unit #3 heating surface selection. The database was used to develop a performance (typical) coal and range coals which bracket boiler performance. These coal analyses (Table 1), combined with surface cleanliness factors based on past unit operation were the basis for matching the new heating surfaces to the requirements of the plant steam cycle.

Table 1: Fuel Analysis and Characterization

Proximate Analysis by Wt

Perf. Coal

Range Coal #1

Range Coal #2

Moisture % 33.50 32.55 38.07

Ash % 12.80 18.31 8.56

Volatile Matter % 25.60 23.45 25.74

Fixed Carbon % 28.10 25.69 27.63

Total % 100.00 100.00 100.00

HHV Btu/lb (kJ/kg)

6373 (14,824)

5710 (13,281)

6563 (15,266)

B&W PGG Canada Coal and Ash Characterization Fouling Potential - SEVERE SEVERE SEVERE Slagging Potential - SEVERE SEVERE HIGH

Max. Recommended Flue Gas Velocity

ft/s (m/s)

60 (18.3)

45 (13.7)

65 (19.8)

Steam and Water Design Conditions

The new turbine and feedwater heater system was designed to minimize changes to the boiler steam and water boundary conditions (cold reheat and feedwater) with the capture plant either in or out of service. This was primarily accomplished by extracting the required capture plant steam downstream of the intermediate pressure (IP) turbine, minimizing the effect on ratio of boiler main steam to reheat steam flow. Some reconfiguration of the feedwater heater system was required to minimize changes in boiler feedwater temperature with and without the capture plant in service.

Boiler And Primary Air Heater Heating Surface Design Optimization

The base scope which was considered was defined as replacement in kind of the existing convective heating surfaces with modifications made only to correct the current operating issues (i.e., reheater under absorption and economizer fouling/overheating). Alternate arrangements were considered in a series of options progressing from lowest efficiency improvement to highest efficiency improvement.

Boiler efficiency is a strong function of flue gas temperature leaving the final heat trap, in this case the secondary air heaters. Modifications above base were thus focused on reducing outlet flue gas temperature. Lower boiler outlet flue gas exit temperatures also reduced the cost/sizing of downstream flue gas coolers which reduce flue gas temperatures to less than 185F (85C) as required by the CO2 capture plant.

The primary boiler operating parameters which improve overall steam cycle efficiency are higher steam temperatures and higher steam pressures. Smaller improvements can be made by minimizing steam-side pressure drops and by sourcing superheater attemperating spray water from the outlet of the final feedwater heater as opposed to the more conventional source at the boiler feedwater pump outlet.

Figure 4 illustrates the changes in unit heat rate corresponding to the boiler modification options which were considered relative to the pre refurbishment operating conditions. The final design modification incorporated most of the modifications in Option 4 with an increase in superheater/reheater surfaces to provide an increase in turbine inlet steam temperature from the existing 1000F/1000F (538C/538C) to 1050F/1050F (566C/566C).

Figure 4

The options outlined in Figure 4 are discussed below.

Base

This boiler configuration involved minimal changes to the existing boiler configuration. The primary objective was to correct the pre rebuild low reheat temperature condition and correct the economizer fouling/overheating. Both reheater and economizer heating surfaces were increased. An economizer bank with wider tube spacing was added to the hot-end of the economizer. The heat rate improvement is due to improved boiler efficiency (reduced flue gas outlet temperature) and restoration of the reheat outlet steam temperatures to design.

BOILER MODIFICATION OPTIONS AND CORRESPONDING UNIT HEAT RATE IMPROVEMENTS

BASE OPTION 1 OPTION 2 OPTION 3 OPTION 4 OPTION 5FINAL

DESIGN

BOILER HEATING SURFACES MODIFIED PER U5Reheater/Superheater Surface To Correct Low RH Temps X X X X X X X

Economizer Surface To Correct Fouling and Overheat X X X X X X X

SECONDARY AIR HEATER SURFACE ADDITION X X X X X X

SUPERHEATER/REHEATER MODIFICATIONSIncrease S/H and R/H Heating Surface in Uppass X X X X X

Superheater Attemperation Water From #6 Heater Outlet X X X X XAdd Pendant Superheat Surface above ECO XUpgrade Metallurgy For 1050 / 1050 F Cycle X

PRIMARY AIR HEATER SURFACE ADDITIONIncrease Primary A/H Heating Surface X X X X

6 Pass Primary A/H X

ECONOMIZER SURFACE ADDITION X X X

(600)

(500)

(400)

(300)

(200)

(100)

-

BASE OPTION 1 OPTION 2 OPTION 3 OPTION 4 OPTION 5 FINALDESIGN

Chan

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Uni

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t Ra

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To P

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ebui

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(Btu

/kw

)

Modification Option

Boiler Efficiency Improvements Superheat Spray Water Flow From Top FW Heater Outlet

Increased Steam Temperature to 1050/1050 F Correct Past Low Hot Reheat Temperature

Option 1

In addition to the Base modifications, this option maximized the secondary air heater heating surface utilizing a high efficiency heating element profile. This option returned a significant increase in boiler efficiency with relatively low capitol cost.

Option 2

The modifications in Option 1 were retained, and superheater surface was added to reduce the gas temperature leaving the superheater/reheater. To achieve an efficiency improvement similar to the air heater modifications in Option 1, the costs are much higher. The superheater attemperator (spraywater) source was changed from the boiler feed pump outlet to the top feedwater heater outlet. With this modification, all of the boiler feedwater flows through the HP feedwater heaters, thus improving unit heat rate.

Option 3

In addition to the modifications in Option 2, the heating surface of the primary air heaters was increased. The reduced gas temperature entering the primary air heater due to up-pass surface addition in Option 2 permitted more primary air heater surface to be installed without exceeding the maximum primary air temperature. Efficiency improvements were relatively minor, but the relatively small cost of this modification made it economically justifiable.

Option 4:

With the Option 3 modifications in place, and lower gas temperature entering the economizer, the economizer surface could be increased while maintaining outlet water temperature below the maximum as limited by steaming criteria. Efficiency gains were relatively minor, but the relatively small cost of this modification made it economically justifiable.

Option 5

This option included all of the modifications of Option 4 and added a pendant primary superheater surface in the boiler down pass above the economizer. The reduction in flue gas temperature entering the primary air heater made additional primary air heater surface necessary to maintain acceptable drying air temperature for the lignite coal. The flue gas temperature leaving the secondary air heater approached the 300F (149C) minimum recommended by SaskPower, thus the boiler efficiency in this configuration was considered the maximum achievable with conventional heat transfer surfaces. In addition, primary air heater metal temperatures at partial loads dropped below recommended values, necessitating installation of steam coil air preheaters for partial load operation. The capital costs for this configuration were higher than what could be justified by the unit efficiency gains it provided.

Final Design

The final design, as illustrated in Figure 2, incorporated the heating surface changes made up to and including the Option 4 configuration. A minor increase in reheater heating surface combined with upgraded superheater/reheater outlet tube and header metallurgy allowed an increase in final steam temperatures to 1050F/1050F (566C/566C). The cost of these modifications and the required steam piping/turbine metallurgy upgrades were relatively minor relative to the substantial improvement in unit heat rate.

Other Options Considered

The new CO2 capture plant required flue gas temperature below the minimum 300F (149C) achievable by conventional boiler heat transfer surfaces. Arrangements which utilized preheated boiler combustion air by means of low grade heat exchangers located downstream of the secondary air heater were considered. These heat exchangers would operate below the flue gas acid dewpoint. The cost of these systems were high relative to the improvements in boiler efficiency that they provided.

SaskPower elected to achieve the required additional flue gas temperature reductions by installing these low grade heat exchangers closer to the capture process where the lower temperatures are required. The recovered heat is used to replace conventional low pressure feedwater heaters and the excess heat is rejected to atmosphere via cooling towers.

Combustion System Design

A reduction in NOx was required to maintain plant specific NOx emissions. A separated overfire air (SOFA) system was installed as part of the boiler refurbishment project. This system stages the introduction of secondary combustion air into the furnace by injecting a portion through corner mounted SOFA ports located above the main burners. New burners and burner windboxes were also provided to accommodate the reduction in secondary air to the corner burners. NOx production is reduced by reducing oxygen availability in the hottest region of the combustion zone where fuel-bound and airborne nitrogen most readily combine with O2 to produce NOx. The combustion system was designed to provide a NOx reduction of at least 50%.

Non-Boiler Related Unit Efficiency Improvements

Replacement of the unit turbine-generator with high efficiency components provided additional heat rate improvements.

CONSTRUCTION

Construction crews were mobilized in the spring of 2013 and boiler construction was completed in September of 2013. Work in the boiler up-pass (superheater, reheater, burners) and down-pass (economizer and air heaters) could be carried out in parallel due to the physical separation of work zones.

Removal and installation of up-pass tube elements and headers was via large access holes cut into the mid and lower furnace sidewall panels. Working platforms were installed at two furnace elevations to facilitate the rigging. Elements were transferred to monorails routed to an outside wall location where an element elevator was constructed to move them to and from trucks at ground level. Figure 5 shows the top of the element elevator with a superheater element ready to transfer onto the monorail system. Header assemblies, burners, front wall panels, and SOFA port components were moved in and out of the building from ground level. To minimize field labor and address building access limitations, the new downpass boiler components were supplied in large modules. Similarly, the existing components were modularized as much as possible for removal. Removal and installation of the down-pass heating surface was accomplished by opening the boiler house roof and utilizing a 660 ton Demag CC2800 crane. Figure 6 shows the crane in place.

Figure 5: Element Elevator and Monorail Figure 6: 660 Ton Crane used for down-pass modules removal/installation

INITIAL OPERATING EXPERIENCE

The unit was commissioned during the summer of 2014 and achieved full rated load in July. The CO2 capture plant was placed into service in the fall of 2014. Boiler performance testing was completed in December of 2014. The boiler performance tests demonstrated that the boiler is operating very close to design conditions. All of the boiler performance guarantees were achieved.

Table 2 illustrates key performance parameters from actual plant operating data in the pre and post refurbishment boiler configurations.

The combination of cycle efficiency improvement and the new low NOx combustion system resulted in an approximately 50% reduction in unit NOx emissions on a per MW (net) basis.

Table 2: Pre and Post Refurbishment Operating Data

Copyright © 2015 Babcock & Wilcox Power Generation Group Canada Corp, Inc. and Saskatchewan Power Corporation. All rights reserved.

No part of this work may be published, translated or reproduced in any form or by any means, or incorporated into any information retrieval system, without the written permission of the copyright holder. Permission requests to B&W PGG Canada should be addressed to: Marketing Communications, Babcock & Wilcox Power Generation Group, Inc., P.O. Box 351, Barberton, Ohio, U.S.A. 44203-0351. Permission requests to SaskPower should be addressed to: Clean Coal Business Unit, SaskPower, 2025 Victoria Avenue, Regina, SK, Canada, S4P 0S4.

Disclaimer Although the information presented in this work is believed to be reliable, this work is published with the understanding that Babcock & Wilcox Power Generation Group Canada Corp. (B&W PGG Canada) and Saskatchewan Power Corporation (SaskPower) and the authors and contributors to this work are supplying general information and are not attempting to render or provide engineering or professional services. Neither B&W PGG Canada nor SaskPower or any of their employees make any warranty, guarantee, or representation, whether expressed or implied, with respect to the accuracy, completeness or usefulness of any information, product, process, method, or apparatus discussed in this work, including warranties of merchantability and fitness for a particular or intended purpose. Neither B&W PGG Canada nor SaskPower or any of their officers, directors, or employees shall be liable for any losses or damages with respect to or resulting from the use of, or the inability to use, any information, product, process, method, or apparatus discussed in this work.

Pre Refurbishment

Post Refurbishment

Post Refurbishment

Units Operating DataOperating Data

Dec 13, 2014

Operating Data (Feb,28- Mar 2,

2015)Coal Burned Perf Coal Perf Coal Perf CoalCO2 Capture Plant In service - - No Yes

Btu/hr/106 1526 1520 1501(MWt) (447) (445) (440)

Feedwater Temperature F (C) 438 (225) 450 (232) 446 (230)Main Steam Temperature F (C) 999 (537) 1055 (568) 1049 (565)Cold Reheat Steam Temperature F (C) 634 (335) 701 (372) 689 (365)Hot Reheat Steam Temperature F (C) 983 (528) 1052 (567) 1049 (565)

Lb/hr/103 1016 987 982(kg/hr) (461) (448) (445)

Lb/hr/103 895 880 841(kg/hr) (406) (399) (381)

Main Steam Pressure at Turbine psig (Mpa) 1800 (12.41) 1800 (12.41) 1800 (12.41)Flue Gas Temperature Entering Economizer

F (C) 1078 (581) 989 (532) 960 (516)

Flue Gas Temperature Entering Secondary Air Heater

F (C) 599 (315) 548 (287) 507 (264)

Flue Gas Temperature Leaving Secondary Air Heater (Undiluted)

F (C) 409 (209) 375 (191) 358 (181)

Generator Output (MW Gross) MW 147 163 148Boiler Efficiency (O.2 % U/M) % 81.30 82.40 82.80

Btu/kWhr 10381 9325 10142(MWt/Mwe) (3.042) (2.733) (2.972)

Btu/kWhr - 1056 239(MWt/Mwe) - (0.309) (0.070)

Nox Emissions Lb/106 Btu 0.41 0.18 0.18

Heat Rate (Gross)

Heat Rate Improvement (Gross)

Main Steam Flow

Reheater Steam Flow

Heat Input (HHV)