000000000001014759 assessment of impacts of retrofit nox controls on gasoil boilers

8/17/2019 000000000001014759 Assessment of Impacts of Retrofit NOx Controls on GasOil Boilers

1/70

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.


2/70


3/70

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


4/70

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.


5/70

iii

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.


6/70


7/70

v

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.


8/70


9/70

vii

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


10/70


11/70

ix

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


12/70


13/70

xi

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


14/70

xii

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


15/70

xiii

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


16/70


17/70

xv

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


18/70


19/70

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.


20/70


21/70

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®)


22/70

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.


23/70

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


24/70

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


25/70

Survey Summary

3-3

Table 3-3Con Ed Plant/Unit/Technologies

Table 3-4Dynegy Plant/Unit/Technologies


26/70

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


27/70

Survey Summary

3-5

Burner Mods/LNB

Table 3-6NOx Control Performance for Burner Mods/LNB


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


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%


28/70

Survey Summary

3-6

IFGR

Table 3-8NOx Control Performance for IFGR


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


ENTERGY

Lewis Creek 1Lewis Creek 2

0.20.2

NANA

0.030.03

NANA

85%85%

NANA


29/70

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.


30/70

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)


31/70

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.


32/70

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


33/70

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)


34/70

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)


35/70

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


36/70

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


37/70

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.


38/70


39/70

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.


40/70


41/70

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.


42/70


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.


43/70


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.


44/70


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.


45/70


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.


46/70


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.


47/70


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.


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.


48/70


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


NO NO NO


NO NO NO

WAS BMS MODIFIED TO ALLOWLEA OPERATION? NO NO NO

ADDITIONAL REMARKS


49/70


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


BOILER EFFICIENCY IMPACT

ADDITIONAL REMARKS

O&M LABOR IMPACT?


50/70


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


NO YES


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.


51/70


A-11

BOOS


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


52/70


A-12

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?


COMPONENT



ADDITIONAL REMARKS

O&M LABOR IMPACT?


53/70


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.


54/70


A-14

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.


55/70


A-15

LNB

CAPITAL COST [$/Kw]ERSSS UNIT 115 - 119


$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.


56/70


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


57/70


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.


58/70


A-18

OFA


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


59/70


A-19

OFA CAPITAL COST[$/Kw] EAST RIVER

UNIT 70 EAST RIVER

UNIT 60 74TH

STREETUNIT PB3

SABINE #3


$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


60/70


A-20

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.


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.


BOILER EFFICIENCY IMPACT not quantified, if any. not quantified, ifany.

not quantified, ifany.

ADDITIONAL REMARKS


61/70


A-21

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.


62/70


A-22

BURNERMODS


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.


63/70


A-23

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.


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


64/70


A-24

BURNERMODS

CAPITAL COST[$/Kw] EAST RIVERUNIT 70

EAST RIVERUNIT 60

59THSTREETUNIT 118

SABINE #5


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


65/70


A-25

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.


66/70


A-26

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.


67/70


A-27

SCR O&M COST

ADJUSTMENT [$/YR] LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2

O&M LABOR IMPACT?


COMPONENT



ADDITIONAL REMARKS

SCR CAPITAL COST[$/Kw]

LEWIS CREEK UNIT #1 LEWIS CREEK UNIT #2


$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.


68/70


69/70


70/70

Export Control Restrictions

Access to and use of EPRI Intellectual Property is

granted with the specific understanding and

requirement that responsibility for ensuring full

compliance with all applicable U.S. and foreign export

laws and regulations is being undertaken by you and

your company. This includes an obligation to ensurethat any individual receiving access hereunder who is

not a U.S. citizen or permanent U.S. resident is

permitted access under applicable U.S. and foreign

export laws and regulations. In the event you are

uncertain whether you or your company may lawfully

obtain access to this EPRI Intellectual Property, you

acknowledge that it is your obligation to consult with

your company’s legal counsel to determine whether

this access is lawful. Although EPRI may make

available on a case-by-case basis an informal

assessment of the applicable U.S. export classification

for specific EPRI Intellectual Property, you and your

company acknowledge that this assessment is solely

for informational purposes and not for reliance

purposes. You and your company acknowledge that it

is still the obligation of you and your company to make

your own assessment of the applicable U.S. export

classification and ensure compliance accordingly. You

and your company understand and acknowledge your

obligations to make a prompt report to EPRI and the

appropriate authorities regarding any access to or use

of EPRI Intellectual Property hereunder that may be in

violation of applicable U.S. or foreign export laws or

regulations.

The Electric Power Research Institute (EPRI)

The Electric Power Research Institute (EPRI), with

major locations in Palo Alto, California, and Charlotte,

North Carolina, was established in 1973 as an

independent, nonprofit center for public interest energy

and environmental research. EPRI brings together

members, participants, the Institute’s scientists andengineers, and other leading experts to work

collaboratively on solutions to the challenges of electric

power. These solutions span nearly every area of

electricity generation, delivery, and use, including

health, safety, and environment. EPRI’s members

represent over 90% of the electricity generated in the

United States. International participation represents

nearly 15% of EPRI’s total research, development, and

demonstration program.

Together…Shaping the Future of Electricity

© ( )

000000000001014759 assessment of impacts of retrofit nox controls on gasoil boilers

Documents