000000000001014759 assessment of impacts of retrofit nox controls on gasoil boilers
TRANSCRIPT
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Assessment of Impacts of Retrofit NOx Controlson Gas/Oil Boilers
1014759
Effective December 6, 2006, this report has been made publicly available in accordance
with Section 734.3(b)(3) and published in accordance with Section 734.7 of the U.S. Export
Administration Regulations. As a result of this publication, this report is subject to only
copyright protection and does not require any license agreement from EPRI. This notice
supersedes the export control restrictions and any proprietary licensed material notices
embedded in the document prior to publication.
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EPRI Project ManagerA. Facchiano
ELECTRIC POWER RESEARCH INSTITUTE3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA
800.313.3774 ▪ 650.855.2121 ▪ [email protected] ▪ www.epri.com
Assessment of Impacts of RetrofitNO
x Controls on Gas/Oil Boilers
1014759
Technical Update, February 2007
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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES
THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS ANACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCHINSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THEORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:
(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I)WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, ORSIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESSFOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON ORINTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUALPROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'SCIRCUMSTANCE; OR
(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER(INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVEHAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOURSELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD,PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.
ORGANIZATION(S) THAT PREPARED THIS DOCUMENT
Energy and Environmental Strategies
Electric Power Research Institute
This is an EPRI Technical Update report. A Technical Update report is intended as an informal report ofcontinuing research, a meeting, or a topical study. It is not a final EPRI technical report.
NOTE
For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 ore-mail [email protected].
Electric Power Research Institute, EPRI, and TOGETHER…SHAPING THE FUTURE OF ELECTRICITYare registered service marks of the Electric Power Research Institute, Inc.
Copyright © 2007 Electric Power Research Institute, Inc. All rights reserved.
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Citations
This report was prepared by
Energy and Environmental Strategies50 Old Faith RoadShrewsbury, MA 01545
Principal InvestigatorR. Afonso
Electric Power Research Institute3420 Hillview AvenuePalo Alto, CA 94304
Principal InvestigatorA. Facchiano
This report describes research sponsored by the Electric Power Research Institute (EPRI).
This publication is a corporate document that should be cited in the literature in the following
manner:
Assessment of Impacts of Retrofit NO x Controls on Gas/Oil Boilers. EPRI, Palo Alto, CA: 2007.
1014759.
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Abstract
In 1997, when EPRI issued the version 2 of its Retrofit NO x Control Guidelines for Gas- and Oil-
Fired Boilers (EPRI report TR-108181), it was thought the most common NOx controls installed
on gas and oil-fired boilers would include low NOx burners; selective catalytic reduction (SCR);
and other vendor supplied, hardware-intensive approaches. In the years that followed, however,most of the gas and oil power generating fleet opted for less hardware intensive, more cost-effective approaches, with Induced Flue Gas Recirculation (IFGR) being the most popularapproach. In addition, a number of other promising technologies have since been proposed,including Selective Non-Catalytic Reduction (SNCR) Trim and Partial Air Heater Bypass
(PAHB). These approaches have been successful, but they have operational impacts, the mostprominent being fan limitations at peak loads. This document, based on data and informationgathered directly from operating units including members of the EPRI Gas & Oil Boiler InterestGroup (GOBIG), revisits the guidelines to document experience from plants and units using thenewer techniques. While IFGR is the main focus, the report also summarizes information onPAHB and Forced Internal Recirculation (FIR) from earlier EPRI documents.
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Acknowledgements
Throughout this project, the authors sought direct communication and information from variouscompanies and individuals to augment and/or confirm the available information.
Specifically, we would like to acknowledge the help and feedback from the followingorganizations:
• Consolidated Edison (Con Ed)
o Mr. Brian Manzino
• Entergy
o Mr. Jim Schott
• Dynegy
o Mr. Mike Ascenzi
• Texas Genco
o Mr. Ben Carmine
• CCA
o Mr. Gifford Broderick
• ETEC
o Mr. Steve Wood
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Acronyms
List of Acronyms.
o LEA – Low Excess Air
o BOOS - Burners-out-of-Service
o LNB – Low NOx Burner
o OFA – OverFire Air
o IFGR – Induced Flue Gas Recirculation
o FGR – Flue Gas Recirculation
o FIR – Fuel Induced Recirculation
o PAHB – Partial Air Heater Bypass
o SNCR – Selective Non-Catalytic Reduction
o SCR - Selective Catalytic Reduction
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Contents
1 Background and Objectives ................................................................................................1-1
Background ...........................................................................................................................1-1
Objectives .............................................................................................................................1-1
2 Technical Approach..............................................................................................................2-1
3 Survey Summary...................................................................................................................3-1
Plants/Units/Technologies in Survey.....................................................................................3-1
NOx Technology Performance Summaries...........................................................................3-4
Information Obtained through the Survey.........................................................................3-4
LEA BOOS...................................................................................................................3-4
Burner Mods/LNB ........................................................................................................3-5
OFA .............................................................................................................................3-5
IFGR ............................................................................................................................3-6
SCR .............................................................................................................................3-6
Additional Data Obtained..................................................................................................3-7
FIR and PAHB..................................................................................................................3-9
O&M Survey Responses.....................................................................................................3-10
IFGR...............................................................................................................................3-10
Boiler Upgrades .........................................................................................................3-10
Impacts on Boiler Operations.....................................................................................3-10
Capital and O&M Costs.......................................................................................................3-13
LEA/BOOS .....................................................................................................................3-13 LNB.................................................................................................................................3-14
OFA ................................................................................................................................3-14
Burner Mods ...................................................................................................................3-15
SCR................................................................................................................................3-15
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4 References.............................................................................................................................4-1
A O&M Survey Responses.....................................................................................................A-1
IFGR..................................................................................................................................... A-1
LEA ...................................................................................................................................... A-8 BOOS................................................................................................................................. A-10
LNB .................................................................................................................................... A-13
OFA.................................................................................................................................... A-16
Burner Mods....................................................................................................................... A-21
SCR.................................................................................................................................... A-25
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List of Figures
Figure 3-1 Burner Modifications (Source – CCA) ......................................................................3-8
Figure 3-2 OFA Performance (Source – CCA) ..........................................................................3-8
Figure 3-3 PH Robinson Unit 2 Reheat Temperature vs. IFGR (Source: EPRI 100450)........3-11
Figure 3-4 PH Robinson Unit 3 Reheat Temperature vs. IFGR (Source: EPRI 1000450)......3-12
Figure 3-5 PH Robinson Unit 2. Heat Rate Impact vs. IFGR (Source: EPRI 1000450).........3-12
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List of Tables
Table 3-1 Overall Summary of NOx Control Technologies with the Survey Group ...................3-1
Table 3-2 Entergy Plant/Unit/Technologies ...............................................................................3-2
Table 3-3 Con Ed Plant/Unit/Technologies................................................................................3-3
Table 3-4 Dynegy Plant/Unit/Technologies................................................................................3-3
Table 3-5 NOx Control Performance for LEA/BOOS .................................................................3-4
Table 3-6 NOx Control Performance for Burner Mods/LNB.......................................................3-5
Table 3-7 NOx Control Performance for OFA............................................................................3-5
Table 3-8 NOx Control Performance for IFGR...........................................................................3-6
Table 3-9 NOx Control Performance for SCR............................................................................3-6
Table 3-10 NOx Performance and Capital Costs Provided by Texas Genco for IFGR andSCR....................................................................................................................................3-7
Table 3-11 PH Robinson Units 2 and 3. IFGR Installation Cost Comparison (Source:EPRI 1000450).................................................................................................................3-13
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1-1
1 Background and Objectives
Background
In 1993, EPRI issued the original version of the Retrofit NOx Control Guidelines for Gas- andOil-Fired Boilers. In 1997 , Version 2 of this document was issued. At that time, it wasanticipated that the most common NOx controls to be installed on gas and oil-fired boilers wouldinclude low NOx burners, SCR, and other vendor supplied, hardware-intensive approaches.However, subsequent to the issuance of these documents, most of the gas and oil power
generating fleet opted for less hardware intensive, more cost-effective approaches, with InduceFlue Gas Recirculation (IFGR) becoming the most popular approach. In addition, a number ofother promising technologies have since been proposed, including SNCR Trim and Partial AirHeater Bypass (PAHB).
Although IFGR and other more cost-effective approaches to NOx compliance have beensuccessful, they have not been without operational impacts, the most prominent being fanlimitations at peak loads. Accordingly, EPRI determined that a need existed to revisit the“guidelines” and develop a new document concentrating on the most popular controltechnologies, while emphasizing the consequences of NOx controls on boiler operability andperformance.
Objectives
EPRI’s vision for this Technical Update was to rely as much as possible on data and informationdirectly from operating units – primarily from within the members of the EPRI Gas & Oil BoilerInterest Group (GOBIG), – as well as other sources willing to share such experience andinformation. The emphasis of the report is on documenting actual experience from plants/unitsutilizing the various technologies, as opposed to general technology descriptions, performanceand projected costs. The previous Guidelines, as well as numerous other EPRI publications (seereferences) address these quite extensively.
This document is, therefore, essentially a compilation of information gathered through surveys,mainly from within GOBIG, but also from other sources as applicable and possible. Given theinterest on IFGR and other lower cost techniques (i.e., PAHB), more focus is devoted there.
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2-1
2 Technical Approach
Given the nature and objectives of this project, a process that aimed at gathering as much directinformation and experience from actual operating units, while minimizing the time consumptionof utility/plant personnel, was undertaken. After several initial conference calls, two surveyswere prepared for completion by the GOBIG members. The first survey was organized to gathergeneral information on plant/unit/NOx technologies; the second was designed to request as muchrelevant information as possible on the performance of the respective NOx control technologiesemployed throughout their generation fleets, with a focus on O&M impacts.
In the next section the results of these surveys are presented. In addition, additional efforts weremade to obtain data from other gas/oil plants. In most instances these were limited to onlygeneric discussions. However, Texas Genco, provided some NOx performance data for severalof their plants (IFGR and SCR), which is included in this report.
Finally, contacts with vendors/consultants such as ETEC (IFGR) and CCA (BurnerModifications and OFA) were fruitful to the extent that summary application lists were provided.Follow up contacts with selected sites did not yield the detailed information desired but theperformance data gathered is presented in the next section as well.
While IFGR was the main focus of this investigation, the following control technologies were
initially included in this effort. Not all were available at plants/units within the GOBIG group.However, EPRI has reported on some of these technologies separately and results for FIR andPAHB from previous documents are summarized.
o LEA
o BOOS
o Burner Modifications
o LNB
o OFA
o IFGR
o FGR
o FIR (e.g., COOLfuel®)
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Technical Approach
2-2
o PAHB
o SNCR
o SCR
No information was available for the application of Reburn technology, recently employed atFlorida Power & Light’s (FPL) Manatee Station. Previous EPRI reports address this technology,which has been more widely utilized in Europe.
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3-1
3 Survey Summary
This section presents the data and information gathered through the process described inSection 2. It is organized in two major areas as follows:
1. NOx performance data
o Summary of plants/units/technologies in the survey of the major participants.
o NOx performance summaries for each available technology from the survey.
o NOx performance summaries for vendor-provided information.
2. Operational Impacts
o This is the main/original focus of the project. The information provided by theGOBIG members in response to the survey is included here.
Plants/Units/Technologies in Survey
Table 3-1 summarizes the distribution of plants/units and applicable NOx control technology .
Table 3-1Overall Summary of NOx Control Technologies with the Survey Group
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Survey Summary
3-2
As can be seen three of the technologies (SNCR, FIR and PAHB) are not in use at any of thefacilities, although both FIR was tested at TXU’s Collins Station and PAHB was tested at TXU’sNorth Lake 3 as discussed later in this section. Two other points seem relevant. First the growingacceptance/popularity of IFGR as a choice technology (as stated by EPRI in developing thisproject); second, the relatively wide differences in performance amongst the various technologies(exception to SCR) emphasizing the reality that site specific conditions dictate to a great extentto final performance achievable by like technologies.
For additional ease of reference, Tables 3-2 through 3-4 present the technology distribution foreach of the three surveyed utilities.
Table 3-2Entergy Plant/Unit/Technologies
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Survey Summary
3-3
Table 3-3Con Ed Plant/Unit/Technologies
Table 3-4Dynegy Plant/Unit/Technologies
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Survey Summary
3-4
NOx Technology Performance Summaries
Information Obtained through the Survey
The NOx performance data provided by the survey respondents is summarized in this section foreach technology. An effort is made to clarify/qualify questionable or uncertain data asappropriate.
LEA BOOS
Table 3-5NOx Control Performance for LEA/BOOS
BASE NOx CONTROLLED NOx %REDUCTIONUTILITYGAS OIL GAS OIL GAS OIL
ENTERGY
Sabine 1Sabine 2Sabine 3
DYNEGY
Roseton 1Roseton 2
0.20.2
0.26
NANA
NANANA
NANA
0.150.170.2
0.22*0.22*
* data
point
includesFGR
NANANA
NANA
25%15%23%
NANA
NANANA
NANA
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Survey Summary
3-5
Burner Mods/LNB
Table 3-6NOx Control Performance for Burner Mods/LNB
BASE NOx CONTROLLED NOx %REDUCTIONUTILITYGAS OIL GAS OIL GAS OIL
ENTERGY
Sabine 4Sabine 5
ConEd
E. River 60E. River 70
ERSSS 115-119
0.260.15
NANANA
NANA
NANANA
0.200.09
NANA0.1*
*w/IFGR(guarantee)
NANA
NANA
0.35**
**w/o IFGR(guarantee)
30%40%
NANANA
NANA
NANANA
OFA
Table 3-7NOx Control Performance for OFA
BASE NOx CONTROLLED NOx %REDUCTIONUTILITYGAS OIL GAS OIL GAS OIL
ENTERGY
Sabine 3
ConEd
E. River 60E. River 70
74th St. PB3
0.22
0.370.33
NA
NA
0.270.31
0.4-0.45
0.07
0.170.24
(guarantee)
NA
NA
0.20.24
(guarantee)0.27
68%
54%21%
NA
NA
NA16%
33%-40%
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Survey Summary
3-6
IFGR
Table 3-8NOx Control Performance for IFGR
BASE NOx CONTROLLED NOx %REDUCTIONUTILITYGAS OIL GAS OIL GAS OIL
ENTERGY
Sabine 4Louisiana 1Louisiana 2Louisiana 3
ConEd
E. River 70
ERSSS 115-119
59th St. 118
0.26NANANA
0.17*
NA
0.26
NA0.40.40.4
0.2**
NA
0.39
0.20NANANA
0.11
0.06(guarantee)
0.15
NA0.20.20.2
0.19
0.3(guarantee)0.31
30%NANANA
35%
NA54%
42%
NA50%50%50%
5%
NA
21%
*baseline w/o OFA/IFGR=0.39**baseline w/o OFA/IFGR=0.3
SCR
Table 3-9NOx Control Performance for SCR
BASE NOx CONTROLLED NOx %REDUCTIONUTILITYGAS OIL GAS OIL GAS OIL
ENTERGY
Lewis Creek 1Lewis Creek 2
0.20.2
NANA
0.030.03
NANA
85%85%
NANA
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Survey Summary
3-7
Additional Data Obtained
As mentioned, additional information was provided by Texas Genco, summarizing theperformance on several of their operating units.
Table 3-10NOx Performance and Capital Costs Provided by Texas Genco for IFGR and SCR
Separately, vendor/consultant CCA provide generic information on the performance of several of
their technology applications (Burner Mods/OFA). As a result and due to the large number ofdata provided, the information is presented in graph format, subdivided into boiler type and fuelgroupings.
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Survey Summary
3-8
CCA - Burner Modifications
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 100 200 300 400 500 600 700 800 900 1000
MW
% N
O x R e d u c t i o n
gas - wall-fired
gas - T-fired
oil - wall-fired
oil - T-fired
OFA only
Figure 3-1Burner Modifications (Source – CCA)
CCA - OFA
0%
10%
20%
30%
40%
50%
60%
70%
0 100 200 300 400 500 600 700 800 900 1000
MW
% N
O x R e d u c t i o n
oil - T-fired
oil wall-fired
gas - wall-fired
Figure 3-2OFA Performance (Source – CCA)
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Survey Summary
3-9
FIR and PAHB
Lastly, it is important to reference technologies not directly addressed in the survey, butnevertheless previously reported by EPRI. Specifically, FIR (COOLfuel®) and PAHB have beentested and documented in EPRI publications.
COOLfuel® is a fuel dilution technology, essentially inducing flue gas into the burner nozzle,thereby creating the equivalent of a lower heating value (BTU) fuel. This is accomplished byusing the inherent kinetic energy of the natural gas supply to “induce” the flue gas into theburner nozzle. The result is a “new” fuel that exhibits lower peak flame temperature andassociated lower NOx emissions. The technology has been used in utility as well as largeindustrial applications with results. At TXU’s Collins Station, the technology indicated NOxreductions of up to about 65% (~0.05 lb/MBtu).
For applications where further NOx reductions may be required, the technology can be utilizedwith high-pressure steam to increase the quantity of induced flue gas. This has two benefits asthe steam not only increases the amount of FGR, but also further dilutes the fuel gas. Of course,
this needs to be considered in light of the added steam related cost. At Collins, this furtherdecreased NOx levels to about 0.03 lb/MBu. However, the plant does not operate in this modedue to stack appearance (haze). Finally, care is needed to address lower furnace CO levels, andthe case of Collins Station, the lowest level of burners do not use COOLfuel®. Reported costsfor the technology by J. Zink Co. range from about $10 - $20/KW for smaller units (less than300 MW) and about $7 - $13/KW for larger units. Reference: “ Assessment of Advanced Low- NOx Burners for Gas-Fired Applications”, EPRI, Palo Alto, CA: 2002. 1004126.
PAHB is an EPRI-developed technique used in conjunction with IFGR, to help mitigate apotential limitation associated with IFGR – load reduction due to FD fan capacity. The concept issimple and is predicated on the fact that the APH is one of the largest pressure loss components
for the air/gas flows. Therefore, by alleviating this pressure loss, it may be possible to get higherlevels of IFGR at a given load, and possibly more importantly, the ability to utilize IFGR athigher loads than without the PAHB.
As with all technologies, trade-offs are part of the decision-making process. The very nature ofbypassing the APH yields lower air temperatures, which help minimized NOx formation (inaddition to the reductions due to the IFGR). At the same time, an efficiency penalty is associatedwith the reduced combustion air temperature. Site-specific conditions and objectives will dictatethe appropriateness of the application.
The technology was tested at TXU Electric’s North Lake 3 Station. In summary, these tests
successfully allowed the unit to operate at the NOx limit of 0.2 lb/MBtu at close to 350 MW, anincrease of about 20 MW over the previous highest load (without PAHB). The full results aredocumented in “Partial Air Heater Bypass – Field Demonstration Results”, EPRI, Palo Alto,CA: 2001. 1004052.
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Survey Summary
3-10
O&M Survey Responses
This section presents a summary and brief discussion of the major responses obtained from theO&M impacts survey. This was the original main focus of this technical update. As expected, thelevel of detail obtained varied from unit to unit. The survey was organized to be consistent with
the main areas of interest presented in EPRI report TR-108181 (Boiler upgrades, Impact onOperations, Capital and O&M Cost). The complete set of information is grouped by NOx controltechnology for all of the plants/units applicable to each technology and presented in Appendix A.
IFGR
Boiler Upgrades
The reported information indicates that several levels of upgrades associated with IFGR retrofitshave been implemented.
In all cases, ductwork and dampers/controls were installed typically between the ID fansdischarge and the FD fan inlets. In at least one system dual (East and West) IFGR ducts wereinstalled. Conversely, there were no reports of heat transfer surface modifications with any ofthese installations. With respect to measurement and controls, the range of applications includeflow meters and dedicated O
2 analyzers to using windbox O
2 for safety only (e.g., shut off at
some setpoint), as well as potential damper control. No special mixing devices were reported asthe IFGR is introduced upstream of the FD fans and as accordingly the FD fans themselves serveas the mixing chamber.
Also reported in two cases were upgrades to the combustion control systems, including BMSupgrades and reprogramming as well as the additional of a dedicated controller for the IFGR
loop.
Impacts on Boiler Operations
No instances of flame stability and/or vibration were reported. Load restrictions due to systemlimitations were noted with both gas and oil firing, ranging from approximately 80% to 90% offull load (although one unit reported no load restriction with the IFGR in operation). Reasonsgiven for load restrictions included FD/ID fan limitations, RH temperatures, as well as opacityconcerns when firing oil.
Steam temperatures impacts were reported for two units while firing gas. In one case the impacton steam temperature was reported as “higher than in the past”, and was being managed at highload (95%) with the RH bypass open 100% and the IFGR damper backed off from about 70% toabout 45%. On oil firing one unit experienced no impact on steam temperatures, while a secondunit was unable to reach full load due to a steam atomization issue and was therefore, not fullytested.
Previous experience has shown the potential impact of IFGR on steam temperatures and FDfan/load limitations. Management of these parameters is crucial in optimizing the IFGR system
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Survey Summary
3-11
throughout the load range. Examples of this reported in EPRI 1000450 for AEP’s BarneyDavis 1, Nueces Bay 6 and Lon Hill 3, showed that these units required more SH attemperationto maintain steam temperature with increasing IFGR flow. FD fan capacity was a limiting factoron the amount of IFGR at Barney Davis and Nueces Bay.
Data from PH Robinson units 2 (490 MW) and 3 (575 MW) provides another example ofvarying impacts due to unit specific conditions. Figures 3-3 and 3-4 show the impact of IFGR onRH temperature. On Unit 2 the excessive temperatures presented some limitations to theutilization of IFGR, while in Unit 3 no adverse steam temperature impacts were noted and theIFGR was only limited by FD fan capacity at high load (above 450 MW).
RH TEMPERATURE - 350 MW
998
1000
1002
1004
1006
1008
1010
1012
1014
0 20 40 60 80 100
IFGR DAMPER POSITION (%0)
R H T
E M
P E R A T U R
E
[ d e g F ]
Figure 3-3PH Robinson Unit 2 Reheat Temperature vs. IFGR (Source: EPRI 100450)
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Survey Summary
3-12
RH TEMPERATURE
996
998
1000
1002
1004
1006
1008
1010
1012
1014
0 20 40 60 80 100
IFGR DAMPER POSITION %
R H
T E M P E R A T U R E ( d e g
F )
Figure 3-4
PH Robinson Unit 3 Reheat Temperature vs. IFGR (Source: EPRI 1000450)
Heat rate impacts on PH Robinson Unit 2 are shown in Figure 3-5. Clearly in this case the largerimpact occurred at the lower load points.
Heat Rate vs. IFGR
0
50
100
150
200
250
300
0 20 40 60 80 100
IFGR Damper, %
D e l t a H R - ( B T U / K W -
H R )
350 MW
250 MW
150 MW
80 MW
Figure 3-5PH Robinson Unit 2. Heat Rate Impact vs. IFGR (Source: EPRI 1000450)
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Survey Summary
3-13
Capital and O&M Costs
Capital costs are always difficult to estimate or provide general guidance, due to applicationspecific items that may distort generalizations. It should be noted that cost information providedis also complicated by the simultaneous inclusion, for certain plants, of system up-grades such as
combustion control (Con Ed plants) or modulating dampers (Entergy Sabine #4). This is truethroughout the industry and applies to most power plant equipment. Competitive concerns or thefact that equipment is often purchased as part of larger turnkey projects are a few of the morecommon reasons why cost comparisons often prove difficult. The responses received from onecompany during this survey included some indication of costs and while here too some combinedcosts were provided, the capital costs were in range of $1.5/KW – 3/KW for the technologyequipment and no additional hardware was typically involved in the refurbishments reported, andtesting and tuning service costs associated with these modifications were, in general, seen to berelatively minor (under $100,000). Although not to be ignored, these costs did not appear toimpact the final investment in any significant manner $5/KW for installation costs. Thesenumbers are higher than those reported previously in EPRI 1000450, which indicated totalinstalled costs in the range of $1.5/KW.
O&M costs proved more difficult to quantify. In one case, it was indicated that increased costswere not anticipated, although no formal assessment had been completed. Other respondentsanticipated some costs associated with the need to inspect and test IFGR equipment on a periodicbasis. As shown previously, (reference Figure 3-5) heat rate impacts, although applicationspecific, would need to be considered as well, along with incremental maintenance/laborimpacts.
Information documented in “Guidelines for Induced Flue Gas Recirculation – Volume 2: Roadmap for Application of IFGR”, EPRI, Palo Alto, CA: 2002. 1004050, provides costs for twounits at PH Robinson Station (Unit 2, gas-fired, supercritical 490 MW and Unit 3, gas-fired,
supercritical 575 MW). Table 3-11 compares these units side-by-side and indicates the variationexpected in these types of projects, where site specific considerations have a significant impacton final costs ($1.30/kW for Unit 2 vs. $0.78/kW for Unit 3):
Table 3-11PH Robinson Units 2 and 3. IFGR Installation Cost Comparison (Source: EPRI 1000450)
UNIT #2 UNIT #3
COST COMPONENT COST COST
MATERIALS $201,659 $122,908LABOR $302,014 $205,773DESIGN $112,810 $122,430
TOTAL $616,483 $451,111
LEA/BOOS
In the case of Low Excess Air (LEA) and Burners Out-of-Service (BOOS), the respondentsindicated that essentially these applications were absent additional new hardware (e.g., O
2
monitors). In most cases no outside dedicated test program/tuning was performed, and no
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Survey Summary
3-14
operational impacts were observed. In one instance, in-house “minor” tuning was conducted, butno associated costs were reported. Also, two units reported that minor modifications to theirBMS were implemented. Finally, one unit required some modifications to the fuel piping toisolate individual burner cells.
Impacts on boiler operations such as flame impingement, load restrictions, steam temperatures,CO/opacity was not observed.
Capital costs provided indicated installed costs of about $0.6/KW for the implementation ofBOOS and an associated $0.95/KW for the BMS modification.
LNB
Todd Dynaswirl oil/gas burners were installed in five units previously capable of oil firing only.The retrofits included new windbox internal baffles, front wall and burner throats. Additionally,atomizing steam and gas balancing valves were also installed.
The major comment received emphasized the fact that the oil-to-gas change required operators toincorporate new procedures, which presented a significant learning curve. Gas firing emissionsseemed to be consistent with expected performance.
Capital costs were estimated at $25/KW for equipment and $75/KW for installation. These costsincluded BMS and combustion controls upgrades, as well as the installation costs associated withthe concurrent installation of the IFGR system. It should be noted that these are smaller boilers(5 x 150Klb/hr), which may explain the initial appearance of higher than expected costs. Fullcharacterization of the O&M impacts was not completed and therefore not quantified. Anyimpacts however, were expected to be minor.
OFA
Four units reported OFA installations. All included multi stage (two and three) ports designswith individual control dampers/actuators. Designs included direct air supply from the winbox aswell as from the APH outlet. In all cases new tube wall panels were installed. In one application,the front wall is the super heater, and accordingly, tube panels were fabricated of stainless steel.In three units the OFA ports included a dedicated flow measurement probe.
Most comments indicated that the OFA installations have not yielded major concerns. Minorinitial CO increases have been solved. No concerns were noted regarding opacity, flame stability,
vibration, system temperatures or load restrictions. One report of the fire ball being higher in thefurnace and closer to the sidewalls seems consistent with general experience with OFAexperience.
Capital costs were reported in the $5/KW – $8/KW range for equipment and about $10/KW forinstallation. These costs include combustion control system upgrades in some cases.Engineering, field testing/tuning costs were reported between $250K and $270K. No informationregarding potential maintenance/O&M labor impacts was reported and expectations were that no
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Survey Summary
3-15
significant O&M impacts would be found. One comment made on the unit where the higher fireball was observed was that this higher flame location exacerbated a previous overheatingproblem with the flue gas bypass at the junction of the furnace rear and side walls.
Burner Mods
“Burner Modifications”, often an alternative to full LNB retrofit, were installed in four units.These included oil and steam upgrades (balancing valves), and airflow management (swirlers). Inthese cases no ignitors/scanners were retrofit. Modifications to the fuel supply were limited togas pressure balancing (orifices being considered if necessary), as well as minor changes to thefuel tips.
As these modifications were often installed concurrent with other technologies (OFA, IFGR),performance testing specific to the burner modification technology was not possible. In oneinstallation with the Burner Modifications only, no changes in operating conditions were noted(O
2, PM, opacity). However, CO was observed to increase to about 100 ppm from a baseline of
0 – 10 ppm.
Costs for the burner modifications were reported from one source at $1.10/KW (equipment) and$0.40/KW (installation). In the other installations they were part of the larger project andaccordingly could not be identified.
SCR
Two SCR installations were included in the survey. These were typical installations on gas unitswith sufficient space between the economizer and the APH to accommodate the catalyst. As aresult, added pressure loss imposed a 30 MW load restriction due to FD fan limitation. This was
anticipated and deemed economically viable prior to the installation. No additionalmaintenance/O&M labor impacts noted. Catalyst disposal had not yet been experienced. Reagent(ammonia) costs were $0.56/KW-yr.
Capital costs reflected a smaller, gas unit retrofit at $13/KW for the SCR equipment, and$12/KW installation.
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4-1
4 References
“Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers – Version 2.0”, EPRI PaloAlto, CA: 1997. TR-108181.
“Assessment of Advanced Low-NOx Burners for Gas-Fired Applications”, EPRI, Palo Alto, CA:2002. 1004126.
“Partial Air Heater Bypass – Field Demonstration Results”, EPRI, Palo Alto, CA: 2001.1004052.
“Induced Flue Gas Recirculation Performance Tests”, EPRI, Palo Alto, CA, and AmericanElectric Power, Columbus, OH: 2000. 1000208.
“Guidelines for Induced Flue Gas Recirculation – Volume 2: Roadmap for Application ofIFGR”, EPRI, Palo Alto, CA: 2002. 1004050.
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A-1
A O&M Survey Responses
The survey was organized to be consistent with the main areas of interest presented in EPRIreport TR-108181. The complete set of information is grouped by NOx technology, for all of theplants/units applicable to each technology.
IFGR
IFGR
BOILER UP-GRADES
ENTERGYSABINE #4
LOUISIANAUNIT 1A
LOUISIANAUNIT 2A
LOUISIANAUNIT 3A
FGR FANS, DUCTWORK,DAMPERS, CONTROLS
New ductwork, dampers& damper controls.
GAS MIXING DEVICES No
GAS MEASUREMENT AND CONTROL DEVICES
Modulating damper
HEAT TRANSFERSURFACE
MODIFICATIONS?
No
ADDITIONAL REMARKS
Recirculate gas comesoff APH gas outlet atbottom of stack andenters into FD Fan inletplentums.
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O&M Survey Responses
A-2
IFGR
BOILER UP-
GRADES
CONEDEAST RIVER 70
CONEDERSSS 115-119
CONED59TH STREET - 118
FGR FANS, DUCTWORK,DAMPERS, CONTROLS
Two IFGR ducts runs installed;East and West. Ductwork fromID fan discharge (after IDcontrol damper) to FD fanintake. Control damper withBeck actuator, manual shutoffdamper and x-joints installed.
Duct work front the ID fandischarge (between the fan andthe control damper) to the FDfan inlet. Expansion jointinstalled just off each fanhousing. Control damper withactuator and manual shut offdamper are installed in eachIFGR system.
Duct work from the ID fandischarge (between the fanand the control damper) tothe FD fan inlet. Expansion joint installed just off each fanhousing. Control damper withactuator was installed.
GAS MIXING DEVICES FD fan acts as themixing device.
FD fan acts as the mixingdevice.
FD fan acts as the mixingdevice.
GAS MEASUREMENT ANDCONTROL DEVICES
O2 analyzer for E & W windbox
air inlet ducts for safetypurposes. IFGR flow meter ineach run for indication only.
Windbox O2, for safety not
control (closes IFGR damperbelow set point).
IFGR flow meter for use in
control system. Windbox O2,for safety and potentialcontrol use.
HEAT TRANSFERSURFACE
MODIFICATIONS?
n/a n/a
ADDITIONAL REMARKS
Combustion Control systemwas upgraded; new I/O andprogramming.Platforms were installed toreach the control dampers.
Minor modifications andre-programming to existingboiler airflow meters.BMS upgrade required. Addition of a single loopcontroller for IFGR control.Programming for both.
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O&M Survey Responses
A-3
IFGR
IMPACT ONBOILEROPERATIONS
ENTERGYSABINE #4
LOUISIANAUNIT 1A
LOUISIANAUNIT 2A
LOUISIANAUNIT 3A
POTENTIAL FLAMEINSTABILITY AND
BOILER VIBRATION
No
LOAD RESTRICTIONSDUE TO FURNACE,
FD FAN, ORWINDBOX PRESSURE
LIMITATIONS
No
EFFECT ON STEAMTEMPERATURE
CONTROLNo
FGR FAN POWERNo FGR Fansrequired.
ADDITIONALREMARKS
At approximately 80%load, recirculationdamper is closed dueto FD Fan capacityand Reheattemperatures.
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O&M Survey Responses
A-4
IFGR
IMPACT ONBOILEROPERATIONS
CONEDEAST RIVER 70
CONEDERSSS 115-119
CONED59TH STREET -
118
POTENTIAL FLAMEINSTABILITY AND
BOILER VIBRATION
None noted None noted None noted
LOAD RESTRICTIONSDUE TO FURNACE,
FD FAN, ORWINDBOX PRESSURE
LIMITATIONS
Boiler air in leakage is limitingthe ID fan, particularly on oilfiring. On oil firing the boiler iscurrently not doing more than~87% to 90% load. Theshutting down of the IFGRdampers happens at about83% load. Gas firing is not asmuch of an issue and the unitis doing about 95% load withthe IFGR dampers still partiallyopen.
Currently can't usewith oil at high loadsdue to the runningout of fans andopacity issues.
Can't use with oilat high loads dueto the running outof fans andopacity issues.
EFFECT ON STEAMTEMPERATURE
CONTROL
When on gas firing the RHtemperatures are runninghigher than in past. At 95%load the RH bypass dampersare open 100% and the IFGRdampers have to be partiallyclosed (down to 45% from ahigh of 70% open at lowerloads).
FGR FAN POWERn/a Having scanner
trouble when firingoil and IFGR systemin service.
n/a
ADDITIONALREMARKS
RH temperatures are not anissue during oil firing. SHtemperatures have also notbeen a problem, reason isprobably two fold. 1. Theattemperation system canhandle the increase intemperature (haven't checkedfor increased usage). 2. Thefirst stage of the superheater isthe furnace front wall (radiantSH). Thus since IFGR usuallyincrease back endtemperatures we believe thatless absorption in the furnacecombined with more
absorption in the back passare essentially balancing eachother out.
Couldn’t make full loadon oil due to an atmstm issue, so not fullytested.
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O&M Survey Responses
A-5
IFGR
CAPITAL COST[$/Kw]
CONEDEAST RIVER 70
CONEDERSSS 115-119
CONED59TH STREET - 118
TECHNOLOGYEQUIPMENT
$500K loaded capital cost.Engineering and equipment byB&W.
~$150K loaded capital cost butwas included in burner materialpurchase. This is for all fiveboilers. IFGR system wasdesigned and supplied by Todd.
$140K loaded capital cost. Theengineering and equipment ofthe IFGR system was by Coen.
INSTALLATION
$900K loaded capital cost. ~$500K loaded capital cost butwas included in burner installationcost. This is for all five boilers.
$360K loaded capital cost.
SYSTEM UP-GRADES
Combustion Control systemupgrades were included with these
costs.
BMS and combustion controlprogramming of the IFGR system
was included with burner projectcosts.
BMS and CC upgradesincluded with these costs.
ADDITIONAL HARDWAREPlatforms were included with thesecosts.
TEST/TUNING SERVICES$35K additional loaded capital cost. $60K loaded capital cost.
ADDITIONAL REMARKS
This was a DEC consent ordermandated project.
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O&M Survey Responses
A-6
IFGR
CAPITAL
COST [$/Kw]
ENTERGY
SABINE #4
LOUISIANA
UNIT 1A
LOUISIANA
UNIT 2A
LOUISIANA
UNIT 3A
TECHNOLOGYEQUIPMENT
New ductwork, dampers &damper controls.
INSTALLATION No
SYSTEM UP-GRADES
Modulating damper
ADDITIONALHARDWARE
No
TEST/TUNINGSERVICES
Recirculate gas comes off APHgas outlet at bottom of stack andenters into FD Fan inletplentums.
ADDITIONALREMARKS
IFGR O&M COSTADJUSTMENT[$/YR]
ENTERGY
SABINE #4
LOUISIANA
UNIT 1A
LOUISIANA
UNIT 2A
LOUISIANA
UNIT 3A
O&M LABOR IMPACT?No
TECHNOLOGYMAINTENANCE
COMPONENTNo
B.O.P. ADDITIONALMAINTENANCE No
BOILER EFFICIENCYIMPACT
No FGR Fansrequired.
ADDITIONAL REMARKS At approximately
80% load,recirculation damperis closed due to FDFan capacity andReheattemperatures.
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O&M Survey Responses
A-7
IFGR O&M COSTADJUSTMENT[$/YR]
CONED
EAST RIVER70
CONED
ERSSS 115-119
CONED
59TH STREET -118
O&M LABOR IMPACT? Installed in fall 2002so we haven't hadto deal with it yet.In general it isadditionalequipment that willneed to beinspected andtested on a periodicbasis.
Installed in fall 2004 sowe haven't had to dealwith it yet. In general it isadditional equipmentthat will need to beinspected and tested ona periodic basis.
Installed in fall 2004so we haven't had todeal with it yet. Ingeneral it is additionalequipment that willneed to be inspectedand tested on aperiodic basis.
TECHNOLOGYMAINTENANCE
COMPONENT
Not expect muchmaintenance as only
ductwork and dampers.
Not expect muchmaintenance as only
ductwork anddampers.
B.O.P. ADDITIONALMAINTENANCE
Not expect muchmaintenance asonly ductwork anddampers.
BOILER EFFICIENCYIMPACT
not quantified, ifany.
not quantified, if any. not quantified, if any.
ADDITIONAL REMARKS System has yet tobe fully automated.
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O&M Survey Responses
A-8
LEA
LEA
BOILER UP-GRADES SABINE UNIT #1 SABINE UNIT #2 SABINE UNIT #4
WERE NEW MONITORS (I.E., O2,CO) REQUIRED AND/ORINSTALLED?
NO NO NO
WERE COMBUSTION TESTSPERFORMED?
NO NO NO
WAS BOILER TUNINGINCLUDED IN THE SCOPE?
NO NO NO
WAS BMS MODIFIED TO ALLOWLEA OPERATION? NO NO YES
ADDITIONAL REMARKS
LEA
IMPACT ON BOILEROPERATIONS
SABINE UNIT #1 SABINE UNIT #2 SABINE UNIT #4
WERE NEW MONITORS (I.E., O2,CO) REQUIRED AND/ORINSTALLED?
NO NO NO
WERE COMBUSTION TESTSPERFORMED?
NO NO NO
WAS BOILER TUNINGINCLUDED IN THE SCOPE?
NO NO NO
WAS BMS MODIFIED TO ALLOWLEA OPERATION? NO NO NO
ADDITIONAL REMARKS
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O&M Survey Responses
A-9
LEA
CAPITAL COST
[$/Kw]
SABINE UNIT #1 SABINE UNIT #2 SABINE UNIT #4
TECHNOLOGY EQUIPMENTNO NO NO
INSTALLATION NO NO NO
SYSTEM UP-GRADES NO NO NO
ADDITIONAL HARDWARENO NO NO
TEST/TUNING SERVICES
ADDITIONAL REMARKS
Minor tuning wasrequired which did nothave any costsassociated with it.
Minor tuning wasrequired which did nothave any costsassociated with it.
Only minor tuning wasrequired, therefore nocosts were associated withthis.
LEA O&M COST ADJUSTMENT
[$/YR]SABINE UNIT #1 SABINE UNIT #2 SABINE UNIT #4
O&M LABOR IMPACT?
TECHNOLOGY MAINTENANCECOMPONENT
B.O.P. ADDITIONALMAINTENANCE
BOILER EFFICIENCY IMPACT
ADDITIONAL REMARKS
O&M LABOR IMPACT?
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O&M Survey Responses
A-10
BOOS
BOOS
BOILER UP-GRADES ROSETON#1 ROSETON #2 SABINE #1 SABINE #2 SABINE #4
WERE NEW MONITORS (I.E.,O2, CO) REQUIRED AND/ORINSTALLED?
NO NO
WERE COMBUSTION TESTSPERFORMED?
NO YES
WAS BOILER TUNINGINCLUDED IN THE SCOPE?
NO YES
WAS BMS MODIFIED TO ALLOW LEA OPERATION?
YES YES
WAS FUEL SUPPLY SYSTEMMODIFIED?
NO YES
ADDITIONAL REMARKS
NO Fuel piping had tobe modified sothat each cell ineach pair could
be isolated.
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O&M Survey Responses
A-11
BOOS
IMPACT ON BOILEROPERATIONS
ROSETON#1
ROSETON #2 SABINE #1 SABINE #2 SABINE #4
DID 02 LEVEL CHANGE?YES
CHANGE IN OPACITY, CO AND PARTICULATES?
NO
FLAME IMPINGEMENTNOTED?
NO
FLAME
INSTABILITY/VIBRATION?
NO
STEAM TEMPERATURE? NO
LOAD RESTRICTIONS? NO
O&M FLEXIBILITY DUE TOLESS BURNERS IN-
SERVICE?
NO
ADDITIONAL REMARKS
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BOOS CAPITAL COST[$/Kw] ROSETON
#1 ROSETON #2 SABINE #1 SABINE #2 SABINE #4
TECHNOLOGY EQUIPMENT
$0.47/Kw
INSTALLATION$0.10/Kw
SYSTEM UP-GRADES$0.95/Kw forBMS
ADDITIONAL HARDWARE
TEST/TUNING SERVICES
ADDITIONAL REMARKS
Only minormodifications to
the BMS wasrequired,therefore therewere no costsassociated
Only minormodifications to
the BMS wasrequired,therefore therewere no costsassociated
BOOS O&M COST
ADJUSTMENT [$/YR] ROSETON#1 ROSETON #2 SABINE #1 SABINE #2 SABINE #4O&M LABOR IMPACT?
TECHNOLOGYMAINTENANCE
COMPONENT
B.O.P. ADDITIONALMAINTENANCE
BOILER EFFICIENCY IMPACT
ADDITIONAL REMARKS
O&M LABOR IMPACT?
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O&M Survey Responses
A-13
LNB
LNB
BOILER UP-GRADES ERSSS UNIT 115 - 119
BURNER ASSEMBLIES & RELATED EQUIPMENT
Original oil only Peabody burners were previously modified(by EPT) for low NOx operation. New Todd low NOxDynaswirl burners added gas firing capability while stillmaintaining the oil firing capability of the boilers.
AIR REGISTERSSecondary slide damper and a tertiary air zone. Windboxinternals and proportioning dampers were gutted. Newwindbox internal baffles were installed.
FUEL ELEMENTS Steam atomized oil gun. Gas fuel carriage is a 3-poker(trident) design around a center gas (oil gun passes throughthe center gas gun).
IGNITORS class 1 gas
SCANNERS 2 UV scanners per burner (existing)
FUEL & AIR SUPPLY SYSTEM MODIFICATIONS Oil, atm stm and gas balancing valves were installed as partof the project.
UPGRADE FD FANS n/a
POTENTIAL WATERWALL MODIFICATIONS The refractory front wall and burner throats were completelyrebuilt.
ADDITIONAL REMARKSIFGR system was designed and installed with the burners.BMS upgrade for the gas firing; minor changes for oil firing.Combustions Controls conversion from WDPF to Ovation andexpansion upgrade for gas firing.
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LNB
IMPACT ON BOILER OPERATIONS ERSSS UNIT 115 - 119
CHANGE IN EXCESS O2? The change from oil firing to gas firing is a large change forthe station operations personnel. The oil procedures changedslightly for the new burners. Operations had to learn gas firingprocedures and controls and the new combustion controlsystem in general. We do not expect the oil firing emissions tochange much from the old burners. The change from oil to gashas a significant change in the emissions for the station butthey are what you would expect for this type of change.Having some trouble reaching full load while firing oil. Not fullytested due to other issues.Having some trouble reaching full load while firing oil. Not fullytested due to other issues
CHANGE IN OPACITY
CHANGE IN CO
CHANGE IN PM EMISSIONS
FAN POWER REQUIREMENT
ADDITIONAL REMARKSWe have several issues which are still being worked out. Dueto the issues there has been very little oil firing and testing.
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LNB
CAPITAL COST [$/Kw]ERSSS UNIT 115 - 119
TECHNOLOGY EQUIPMENT
$2.5 mil loaded capital cost. This is for all five boilers. Theburners are by Todd, as well as the windbox dampers andboiler gas train valves.
INSTALLATION$7.5 mil loaded capital cost. This is for all five boilers.
SYSTEM UP-GRADESThe BMS and CC upgrades are included with these costs(material was $1 mil capital cost).
ADDITIONAL HARDWARE The material and installation of the IFGR system was includedwith these costs (material was about $100K capital cost).
TEST/TUNING SERVICES Was an additional cost to the capital costs listed.
ADDITIONAL REMARKS The front wall rebuilds were an additional $400K in loadedcapital cost.
LNB
O&M COST ADJUSTMENT [$/YR] ERSSS UNIT 115 - 119
O&M LABOR IMPACT? Installed in fall 2004 so we haven't had to deal with it yet. Ingeneral it is additional equipment that will need to beinspected and tested on a periodic basis.
TECHNOLOGY MAINTENANCE COMPONENT Routine maintenance, inspections, calibration, etc areexpected.
B.O.P. ADDITIONAL MAINTENANCE
BOILER EFFICIENCY IMPACT Not quantified, if any. Expected to be a wash with the oldburners.
ADDITIONAL REMARKS Systems have yet to be fully tuned and placed in automatic,especially for oil.
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O&M Survey Responses
A-16
OFA
OFA
BOILER UP-GRADES
EAST RIVER UNIT 70 EAST RIVER UNIT
60 74TH STREET
UNIT PB3SABINE #3
TUBE WALL PANELSFOR OFA PORTS
Six new tube panels were installedon the front wall. Since the frontwall is a superheater the panels arestainless steel tubing. Each panelwas essentially in line with acolumn of burners.
Six sidewall tube panels(three per side). The unitwas originally a downfired boiler to the OFAports are actually in thesidewall arches andpoint on a downwardangle. The burners hadbeen relocated to thevertical section of thesidewalls (below thearches) many years ago. A front wall tube panelwas also installed at thecenter of the wall.
One 6-tube panel in righthand sidewall of thepackage boiler.System was intended tobe a test system so nocontrols or damperactuators were addedand the system is notautomated from thecontrol room. Dampershave hand wheels.
Yes
OFA PORTSSix 2-stage OFA ports installed.The boiler is a cold cased unit sothere was some difficulty withdesigning a seal that would allowfor proper movement of the tubewall vs the casing/ofa port. Eachport has a 1/3 and a 2/3 openingthat is controlled by a separatedamper and actuator. The controllogic for the dampers is that eachdamper is either open or closed,they do not modulate in-betweenopen and closed positions.
Seven 2-stage portstotal. Three in eachsidewall arch and one inthe front wall. Each porthas a 1/3 and a 2/3opening that iscontrolled by a separatedamper and actuator.The control logic for thedampers is that eachdamper is either open orclosed, they do notmodulate in-betweenopen and closed.
positions.
Three ports in a verticalcolumn. The controldamper (manual handwheel) is installed in thecommon OFA ducttakeoff. Biasing dampersare installed in the threeduct split offs.Directional vanes areinstalled in each of theOFA ports.
Yes
AIR SUPPLY DUCTS OFA duct are from the air inletducts to the front wall, above thewindboxes
OFA duct are from theair inlet ducts to thesidewalls, above eachwindbox. A duct wasalso taken run from eachair inlet duct to feed theone front wall port.
Single duct takeoff thatspits to go to the threeports.
Yes
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O&M Survey Responses
A-17
OFA
BOILER UP-
GRADES(CONT’D)
EAST RIVER UNIT 70 EAST RIVER UNIT60
74TH STREET
UNIT PB3
SABINE #3
OFA MEASUREMENT &CONTROL OF EACHPORT
Each OFA duct has a flow probefor indication only.
Each OFA duct has aflow probe for indicationonly.
OFA flowmeasurement installed.
No measurementbut controlled ateach port withdampers.
AIR SUPPLY (WINDBOXVS. NEW FAN)
From the east and west air inletducts.
From the air inlet ducts. Duct take off is fromthe AH air outlet duct(windbox inlet)
Windbox
ADDITIONAL REMARKS Needed to add I/O and terminationcabinets for the WDPF CombustionControl System. Programming forthe OFA system was also
performed.
Platforms and buildingsteel had to be installedto access all seven ofthe new OFA ports.
4 expansion jointsinstalled; one at takeoffand one with each port.
New OFA ductscame off existingwindboxes.Existing
windboxes had tobe replaced withsmaller ones toallow sameamount ofsecondary air tobe distributed tonew OFA ports.
MODIFIED FUELSUPPLYSYSTEM/ATOMIZERS AND GAS?????INCREASED BURNERFUEL ????
Air and fuel balancing was alsodone as part of this project.
Air and fuel balancingwas also done as part ofthis project. A swirlerwas added to each ofthe burners.Combustion Control(WDPF) programmingfor the OFA system was
performed.
Burner barrel wassleeved to neck downthe area. Windboxproportional damperswere replaced (manualhand wheels).Existing boiler airflowmeasurement to the
boiler were replacedwith a new systemcompatible with theOFA flowmeasurementinstrument.
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O&M Survey Responses
A-18
OFA
IMPACT ON BOILEROPERATIONS
EAST RIVERUNIT 70
EAST RIVERUNIT 60
74THSTREET
UNIT PB3
SABINE #3
CHANGE IN EXCESS O2 No significantchange noted.
Not tested as ofyet but no majorproblems areexpected.Superheatertemperaturecontrol and boilerexterior BRILCissues (similar toER70) arepotential itemsthat could have to
be dealt with.
Not significant Yes
CHANGES IN OPACITY, CO,PARTICULATE
No significantchange noted.Levels are withinguaranteed limitsfrom vendor.
Some CO issuesarose during thetesting stage. Alot of this wasattributed to fluegas bypass.Once holes werepatched the COemissions camedown.
NO
FLAME IMPINGEMENT Fire ball is higherand closer to thesidewalls.
None noted NO
FLAME INSTABILITY none noted None noted NO
BOILER VIBRATION none noted None noted NO
STEAM TEMPERATURECONTROL
The IFGRsystem seems tobe having abigger effect. Orat least theproblem is beingmitigated byclosing down onthe IFGR asopposed to theOFA dampers.
No issue noted. NO
LOAD RESTRICTIONS Unit loadrestrictions wouldseem to be dueto other issueand not the OFAsystem.
Not related toOFA system
Yes
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OFA CAPITAL COST[$/Kw] EAST RIVER
UNIT 70 EAST RIVER
UNIT 60 74TH
STREETUNIT PB3
SABINE #3
TECHNOLOGY EQUIPMENT
$900K loadedcapital cost forthe equipment. Additional $250Kin capital cost forengineering ofthe system, fieldsupport, andtesting/tuning.Engineering,equipment, andtesting of OFA
system by CCA.
$1 mil loadedcapital cost for theequipment. Additional $270Kin loaded capitalcost forengineering of thesystem, fieldsupport, andtesting/tuning.Engineering,equipment, and
testing of OFAsystem by CCA.
$240K loadedcapital cost. Theengineering andequipment wasby B&W.
$7.15/Kw
INSTALLATION$2.1 mil loadedcapital cost.
$2.25 mil loadedcapital cost.
$450K loadedcapital cost.
$9.50/Kw
SYSTEM UP-GRADESWDPFCombustionControl Systemupgrade wasincluded withthese costs.
CombustionControl (WDPF)upgrades includedin these costs.
none
ADDITIONAL HARDWARE Burner balancingvalves wereincluded with
these costs.
Burner balancingvalves wereincluded with
these costs.Swirlers wereincluded withthese costs.
All additionalhardware wasincluded in these
costs.
none
TEST/TUNING SERVICES Included withengineeringservices cost.
Included withengineeringservices.
$40K loadedcapital cost.
Included intechnologyEquipment
ADDITIONAL REMARKSPlatforms andbuilding steelwere included withthese costs.
System setup iscurrently only formanual operation(due to this beinga test project).Remote orautomatic controlwould require
additionalengineering,equipment,materials andcost
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OFA O&M COST
ADJUSTMENT [$/YR] EAST RIVER UNIT 70 EAST RIVERUNIT 60
74TH STREETUNIT PB3
SABINE #3
O&M LABOR IMPACT? Installed in fall 2003 so wehaven't had to deal with it yet.In general it is additionalequipment that will need tobe inspected and tested on aperiodic basis.
Installed in fall2004 so wehaven't had todeal with it yet.In general it isadditionalequipment thatwill need to beinspected andtested on aperiodic basis.
Installed in Winter2004 so we haven'thad to deal with ityet. In general it isadditionalequipment that willneed to beinspected andtested on a periodicbasis.
TECHNOLOGYMAINTENANCE
COMPONENT
The higher flames areexacerbating two locations ofoverheating of the exteriorBRILC that exists on eachsidewall. Problem with flue
gas by-pass at the junction ofthe furnace rear wall tosidewall existed previously.But the OFA would seem tobe exacerbated the problemas the casing is now activelyburning through. A repaireffort of these areas will haveto be planned andundertaken at an unknowncost impact.
Not expect muchmaintenance asonly ductwork anddampers.
B.O.P. ADDITIONALMAINTENANCE
BOILER EFFICIENCY IMPACT not quantified, if any. not quantified, ifany.
not quantified, ifany.
ADDITIONAL REMARKS
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Burner Mods
BURNERMODS
BOILER UP-GRADES
EAST RIVER UNIT70
EAST RIVERUNIT 60
59TH STREETUNIT 118
SABINE #5
BURNER ASSEMBLIES& RELATEDEQUIPMENT
Oil and atomizing steambalancing valves wereinstalled.
Oil and atomizingsteam balancingvalves were installed.Swirlers wereinstalled on eachburner. The swirlerswere installed aroundthe barrel thatseparates the primaryfrom the secondaryair zones as opposedto it being located onthe end of the oil gunguide pipe.
Yes
AIR REGISTERS Airflow was balanced byadjusting / closing in on theair damper to each burnercompartment for whatwould be considered OFAfiring positions. Windbox iscompartmentalized foreach burner.
Airflow was balancedby adjusting / closingin on the air registersto each burner forwhat would beconsidered OFA firingpositions.
NO
FUEL ELEMENTS Oil and atm stm valveswere throttled to balanceand bias the flows fromburner to burner and levelto level (3 levels of 6burners).
Oil and atm stmvalves will be throttledto balance and biasthe flows from burnerto burner and level tolevel (2 levels of 3burners on eachside).
NO
IGNITORS n/a n/a NO
SCANNERS n/a n/a NO
FUEL & AIR SUPPLYSYSTEMMODIFICATIONS
Yes
CONTROL OFFUEL&AIRDISTRIBUTION TOBURNERS ?
Yes
ADDITIONAL REMARKS Gas pressures werebalanced (burner toburner) enough thatbalancing valves or orificeplates were not installed.
Gas pressures will bechecked (burner toburner). If neededorifice plates may beinstalled to balancethe fuel.
Modifications weremade to the fuel tips andfuel distribution piping.
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O&M Survey Responses
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BURNERMODS
IMPACT ON BOILEROPERATIONS
EAST RIVERUNIT 70
EAST RIVER
UNIT 60 59TH STREET
UNIT 118SABINE #5
CHANGE IN EXCESS O2Effect of the air andfuel balancing wasnot investigatedseparate from theOFA projectinstallation andtesting/tuning.
Effect of the air andfuel balancing andthe swirlers will notbe investigatedseparate from theOFA projectinstallation andtesting/tuning.
NO
CHANGES IN OPACITY, CO,PARTICULATE
NO
CHANGE IN CO Yes
CHANGE IN PM EMISSIONS NO
FAN POWER REQUIREMENT NO
ADDITIONAL REMARKS Station needs toremove the valvehandles so theOperationspersonnel do not usethe balancing valvesas shutoff valves.
Station will need toremove the valvehandles so theOperationspersonnel do notuse the balancingvalves as shutoff
valves.
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BURNERMODS
O&M COST
ADJUSTMENT [$/YR] EAST RIVER UNIT70 EAST RIVER UNIT60 59TH STREETUNIT 118 SABINE #5
O&M LABOR IMPACT? No impact expected. Downthe road the valves mayhave to be repacked orchanged.
No impact expected.Down the road thevalves may have to berepacked or changed.Inspect swirlers fordamage but none isexpected due to theirlocation.
TECHNOLOGYMAINTENANCE
COMPONENT
Freeing up the old windboxcompartment dampers hasbeen difficult.
B.O.P. ADDITIONAL
MAINTENANCE
BOILER EFFICIENCY IMPACT not quantified, if any. not quantified, if any.
ADDITIONAL REMARKS
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BURNERMODS
CAPITAL COST[$/Kw] EAST RIVERUNIT 70
EAST RIVERUNIT 60
59THSTREETUNIT 118
SABINE #5
TECHNOLOGY EQUIPMENT
The air and fuelbalancing workwas purchases,installed, tested,and tuned aspart of the OFAproject. Thevalve supply andbalancing wasprovided byCCA.
The swirlers and airand fuel balancingwork was purchases,installed, tested, andtuned as part of theOFA project. Theswirler, valve supplyand balancing wasprovided by CCA
$1.10/KW
INSTALLATION$0.40/Kw
SYSTEM UP-GRADES
ADDITIONAL HARDWARE
TEST/TUNING SERVICES Included in TechnologyEquipment cost.
ADDITIONAL REMARKS
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SCR
SCR
BOILER UP-GRADES LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2
SCR REACTOR,DUCTWORK & SUPPORTSTRUCTURE
YES YES
REAGENT UNLOADING &STORAGE EQUIPMENT
YES YES
REAGENT CONVEYING &INJECTION EQUIPMENT
YES YES
PROCESS CONTROLSYSTEM
YES YES
AIR HEATER SOOTBLOWER UP-GRADE
NO NO
UP-GRADE OOR NEWFD/ID FANS
NO NO
ADDITIONAL REMARKS Catalyst was able to be installedin area between economizerand APH.
Catalyst was able to beinstalled in area betweeneconomizer and APH.
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SCR IMPACT ON BOILEROPERATIONS LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2
INCREASED PRESSUREDROP & FAN POWERREQUIREMENTS
YES YES
POTENTIAL LOADRESTRICTION DUE FD FANDOR WINDBOX LIMITATIONS
YES YES
NH3 SLIP/AIR HEATERPLUGGING
NO NO
EFFICIENCY LOSS? NO NO
CATALYST DISPOSAL None yet None yet
REAGENT COST $145,000/yr (Anhydrous Ammonia)
$145,000/yr (Anhydrous Ammonia)
ADDITIONAL REMARKS A 30 MW restriction was takendue to FD Fan capacity. This wasevaluated prior to installation anddecision was made to takerestriction.
A 30 MW restriction was taken due toFD Fan capacity. This was evaluatedprior to installation and decision wasmade to take restriction.
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SCR O&M COST
ADJUSTMENT [$/YR] LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2
O&M LABOR IMPACT?
TECHNOLOGYMAINTENANCE
COMPONENT
B.O.P. ADDITIONALMAINTENANCE
BOILER EFFICIENCY IMPACT
ADDITIONAL REMARKS
SCR CAPITAL COST[$/Kw]
LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2
TECHNOLOGY EQUIPMENT
$13/Kw $13/Kw
INSTALLATION$12/Kw $12/Kw
SYSTEM UP-GRADES
ADDITIONAL HARDWARE
TEST/TUNING SERVICES Included in Technology Equipmentcost.
Included in Technology Equipment cost.
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