EPRI Power Plant Optimization Guidelines

Power Plant OptimizationGuidelines

TR-110718

Final Report, December 1998

EPRI Project ManagerJ. Stallings

EPRI 3412 Hillview Avenue, Palo Alto, California 94304 PO Box 10412, Palo Alto, California 94303 USA800.313.3774 650.855.2121 [email protected] www.epri.com

Effective December 6, 2006, this report has been made publicly available in accordancewith 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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ORDERING INFORMATIONRequests for copies of this report should be directed to the EPRI Distribution Center, 207 Coggins Drive, P.O. Box23205, Pleasant Hill, CA 94523, (925) 934-4212.Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc.EPRI. POWERING PROGRESS is a service mark of the Electric Power Research Institute, Inc.

Copyright 1998 Electric Power Research Institute, Inc. All rights reserved.

iii

CITATIONS

This report was prepared by

Energy Technologies Enterprises Corp.7722 Desdemona CourtMcLean, Virginia 22102

Principal InvestigatorS. Tavoulareas

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in thefollowing manner:

Power Plant Optimization Guidelines, EPRI, Palo Alto, CA: 1998. TR-110718.

vREPORT SUMMARY

During the last five years, new software products have become available that usestatistical analysis or neural network techniques to optimize power plant performancebased on multiple objectives. The growing impetus to reduce costs of NOx complianceand electricity production has accelerated deployment of these applications in theutility industry.

BackgroundOptimization software was being implemented in approximately 130 boilers as ofSeptember 1998 (of these applications, more than half were one-time efforts; after anoptimized list of set points had been given to the plant, the optimization software wasremoved). Reported NOx emission reduction has ranged from 5 to 40% and heat ratereduction from 0.5 to 3%. In the combustion area, key objectives are reduction of NOxemissions, heat rate, and unburned carbon. While some U.S. utilities have gainedexperience with software tools, the majority of utilities need more information on howto select the most appropriate software for their plant optimization programs.

Objectives To determine the potential improvement in plant performance and emissionreduction through use of power plant optimization software.

To select the most appropriate optimization type among stand-alone, on-line/advisory, and closed-loop.

To evaluate various options by carrying out a cost-benefit analysis.

ApproachThe Power Plant Optimization (PPO) Guidelines were developed with the expertise ofthe contractor and EPRI, as well as advice from the Power Plant Optimization InterestGroup (consisting of EPRI members interested and involved in plant optimization). Theproject teams approach was to lead utility planners through a five-step process, whichmethodically would set appropriate optimization objectives, identify projectedperformance improvements, and estimate costs and benefits of various optimizationtypes. To facilitate this analysis, the team included two Excel spreadsheets with theprogram. A beta version of these Guidelines was distributed to 40 utility engineers,many of whom provided feedback on how to improve them further. Version 1.0, whichaccompanies this report, incorporates the comments of these utility users.

vi

ResultsForty utility engineers have already used the beta version of these Guidelines. Many ofthese engineers have used them to make decisions on how to structure optimizationprograms and how to improve efficiency and cost-effectiveness of plant operations. Useof optimization software is expected to grow significantly, and these Guidelines willplay a critical role in this growth. Two case studies carried out by Allegheny Power andNorthern State Power are included in this document and provide a good example ofhow the Guidelines can be used.

EPRI PerspectivePower plant optimization software has become more widespread as a result of theindustrys attempt to find less expensive ways to comply with NOx emissionregulations. Optimization products are of strategic importance to the utility industry,which soon will operate in a deregulated market in which key economic parametersand operating objectives change continuously. Optimization tools will allow utilities toadjust to such dynamic environments. EPRI has played and will continue to play aleading role in this technical area by supporting utility demonstration of alloptimization tools, disseminating relevant information, and developing softwareevaluation guidelines.

AP-110718Interest CategoriesFossil steam plant performance optimizationAir emissions controlEmissions monitoringFossil steam plant O&M cost reduction

KeywordsHeat rateNitrogen oxidesEmission controlPerformance testingComputer applicationsComputer applicationsCost Reduction

EPRI Licensed Material

vii

INTRODUCTION/ HOW TO USE THIS DOCUMENT

As of September 1998, approximately 50 utilities in the U.S. have utilized optimizationsoftware in 92 units, mainly to reduce NOx emissions and heat rate. Approximately 40more optimization projects are planned to be completed by the end of 1998. Industryexperience to date suggests that moderate NOx reduction (5-40%) and heat rateimprovement (0.5-1.5 percentage points) can be achieved with optimization software.

Detailed description of the various software available and the industry experience areprovided in EPRIs Power Plant Optimization Web Site (http://www.epriweb.com/gg/98funders/ppo/index.html) and the proceedings from EPRIs Workshops onPower Plant Optimization in 1997 and 1998 (TR-108687 and TR-111316, respectively).The web site is updated monthly and is a good source of information on ongoingprojects and key industry developments. Key definitions associated with power plantoptimization are provided in Box I.

The purpose of this document is to build upon these sources of information andprovide utilities with a step-by-step guide on how to:

x determine the potential power plant performance improvement if an optimizationpackage were used,

x select the most cost effective optimization type among: stand-alone1, on-line/advisory, and closed-loop, and

x evaluate alternative optimization software packages.

The approach followed in this document emphasizes:

x low-cost options; it starts from a simple (quick) tuning and moves to moreexpensive optimization and potential hardware changes (e.g. NOx control retrofitoptions) only as needed or supported by sound economic justification;

1 Stand-alone type optimization projects were referred to as Off-line/One-time type projects duringthe EPRI/ESEERCO Conference and in the conference proceedings (EPRI TR-108687).


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x setting baseline performance after quick tuning to assess the real potential ofoptimization; tuning and baseline performance are described in detail in EPRIsNOx Emissions Testing and Optimization for Coal-fired Utility Boilers (TR-105109) to which the reader is referred frequently;

x establishing clear objectives for the optimization project; and

x identifying the type of optimization and the specific software package which is mostappropriate and cost-effective.

Box I Definitions

Power plant optimization is a process which involves changes in operating variablesand equipment settings to achieve a set of objectives. Optimization software may beused in the following three modes:

x Stand-alone: while the optimization system may obtain data electronicallyfrom the DCS or other data sources, one or more variables are often providedmanually for each iteration; in most cases, this optimization is performedonce and then the system is maintained at the same operating conditions.Optimization may be repeated periodically

x On-line/advisory: all the data required for optimization (variables whichchange with operation) are obtained electronically; the system providesadvice to the plant operator who makes the final decision whether or not theproposed optimum should be implemented

x Closed-loop: fully integrated into the power plant controls; the optimizationsystem feeds control biases directly into the control system causing the fieldequipment to change without human intervention.

More information on typical optimization systems, as well as specific software availablein the market, is provided in EPRI publications TR-108687 and TR-111316.

While this document uses the terms power plant optimization, most experience so faris with boiler optimization. However, the same software may be used for powerplant optimization.


ix

These guidelines consist of 5 basic steps (see the figure on the following page) whichare described in the first five sections of the report (one section devoted to each step).

x Step 1: Tune unit and establish baseline performance,

x Step 2: Establish clear needs and objectives,

x Step 3: Determine optimization potential/Can optimization alone meet establishedobjectives?

x Step 4: Identify the most cost-effective type of optimization, and

x Step 5: Select the best optimization product for your application.

Quick tuning and establishment of baseline performance is recommended as the firststep, before establishing objectives for the power plant optimization project.Alternatively, objectives may be set first (especially when the boiler is tuned recently),but they should be re-assessed after the quick tuning is done and baseline performanceis established.

There are three appendices:

x Appendix A: Software Users Guide provides guidance on how to use the spreadsheetswhich accompany this report on a floppy disk. Guidance is also included for theapplicable sections (Steps 3, 4, and the case studies in Appendix B).

x Appendix B: Case Studies provides two examples which illustrate how the guidelinesmay be applied to specific power plants.

x Appendix C: Formulas provides all the formulas used for estimating the costs andbenefits of power plant optimization in the guidelines and spreadsheets.

The material provided in this report includes both general guidance and step-by-stepinstructions to evaluate the various options for a specific power plant underconsideration. In steps 3 and 4, detailed instructions (highlighted in shaded boxes)provide for using these spreadsheet tools (Tables 3-1 and 4-1).


x

Guidelines Process to Evaluate Power Plant Optimization Options

NO

YES

Step 3 Determine optimization potential/

Can optimization alone meet established objectives?

Step 1 Tune unit &

Establish baseline performance

Step 2 Establish clear needs

& objectives

Step 4 Identify the most cost-effective

type of optimization

Step 5 Select the best optimization product for your application

Consider optimization in combination with other options such as:

z NOx controls (Low NOx burners, SNCR, reburning, and SCR)

z Hardware modifications for heat rate improvements


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ABBREVIATIONS AND ACRONYMNS

ABB/CE Asea Brown Boveri/Combustion EngineeringBOOS Burner out of serviceCAAA Clean Air Act Amendment of 1990CO2 Carbon dioxideCO Carbon monoxideDAS Data acquisition systemDCS Digital control systemEPA U.S. Environmental Protection AgencyESP Electrostatic precipitatorI/O Input/outputI&C Instrumentation and controlskWh Kilowatts per hourLbs/MBtu Pounds per million British thermal unitsLNCFS-III ABB/CE Low NOx Concentric Firing Systems-IIILOI Loss on ignitionMOOS Mills-out-of-serviceMW MegawattNOx Nitrogen oxidesNPV Net present valueNSP Northern States PowerO&M Operating and maintenanceO2 OxygenOEM Original equipment manufacturerOFA Overfire airPA Primary airPEPCO Potomac Electric Power Companyppm Parts per millionPPO Power plant optimizationPV Present valueSNCR Selective non-catalytic reductionSCR Selective catalytic reductionSO2 Sulfur dioxideTVA Tennessee Valley AuthorityUBC Unburned carbon


xiii

CONTENTS

1 STEP ONE: TUNE UNIT AND ESTABLISH BASELINE PERFORMANCE ........................ 1-1A. Perform Diagnostic Testing ............................................................................................ 1-2B. Perform Quick Tuning..................................................................................................... 1-5

What is Quick Tuning? .................................................................................................... 1-5C. Establish Baseline Performance..................................................................................... 1-7

2 STEP TWO: ESTABLISH CLEAR NEEDS AND OBJECTIVES ......................................... 2-1B. Differentiate between firm requirements and desirable outcomes ............................. 2-3C. Articulate project objectives............................................................................................ 2-4

3 STEP THREE: DETERMINE OPTIMIZATION POTENTIAL/CAN OPTIMIZATIONALONE MEET ESTABLISHED OBJECTIVES?..................................................................... 3-1

Can Optimization Alone Meet Established Objectives? ...................................................... 3-2Background and Instructions for Completing Table 3-1 ...................................................... 3-4

Information on the Last Unit Tune Up ............................................................................. 3-4Unit Operating Flexibility (at full load).............................................................................. 3-5

Fuel Flow Biasing........................................................................................................ 3-5Air Flow Biasing........................................................................................................... 3-7Excess O2 (baseline vs. minimum O2 level) ................................................................. 3-8Operating Flexibility of Burner Tilts (only in the case of T-fired boilers)..................... 3-10Operating Range of Air and Gas Dampers................................................................ 3-12Primary Air to Fuel Ratio (PA/Fuel) ........................................................................... 3-12Other Control Variables............................................................................................. 3-13

Ability to Change Equipment Settings........................................................................... 3-14Burner Settings ......................................................................................................... 3-14Pulverizer Settings (in case of coal-fired power plants)............................................. 3-16Other Equipment Settings ......................................................................................... 3-16


xiv

Air Distribution Modifications ..................................................................................... 3-17Coal Pipe Orificing..................................................................................................... 3-18Mill Modifications ....................................................................................................... 3-21

Expected Performance Improvements .......................................................................... 3-23Project Classification.............................................................................................. 3-24

4 STEP FOUR: IDENTIFY THE MOST COST-EFFECTIVE TYPE OF OPTIMIZATION ........ 4-1Types of Optimizations: ...................................................................................................... 4-2

A. Availability of DCS and DAS....................................................................................... 4-2B. Continuous vs. One-time or Periodic Optimization...................................................... 4-2C. Performance Improvement Objectives........................................................................ 4-3D. Cost-Benefit of Alternative Optimization Types .......................................................... 4-3

Background and Instructions for Completing Table 4-1 ...................................................... 4-7COSTS ............................................................................................................................... 4-7

UP FRONT COSTS......................................................................................................... 4-7Up Front License Fees................................................................................................ 4-7Additional Computer Software and Hardware ............................................................. 4-8Installation and Calibration.......................................................................................... 4-8Training ..................................................................................................................... 4-11Power Plant Hardware Modifications......................................................................... 4-11

ANNUAL COSTS (O&M Including Recalibration).......................................................... 4-11Annual Software License and Maintenance Fees ..................................................... 4-12Technical Support ..................................................................................................... 4-12

OPTIMIZATION BENEFITS.............................................................................................. 4-14UP FRONT (ONE TIME) BENEFITS............................................................................. 4-14

NPV of Deferred Costs.............................................................................................. 4-14NPV of Avoided Costs............................................................................................... 4-14

ANNUAL BENEFITS ..................................................................................................... 4-15Annual Avoided Costs............................................................................................... 4-15Fuel Cost Savings ..................................................................................................... 4-16O&M Impacts ............................................................................................................ 4-17Value of Change in Unit Availability .......................................................................... 4-18Value of Change in Unit Output ................................................................................ 4-18Benefits Due to Emission Reductions ....................................................................... 4-19


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Cost-Benefit Analysis Results ........................................................................................... 4-22

5 STEP FIVE: SELECT THE BEST OPTIMIZATION PRODUCT FOR YOURAPPLICATION........................................................................................................................ 5-1

Selecting an Optimization Package .................................................................................... 5-2Key Factors......................................................................................................................... 5-2Comments on the Key Factors for Evaluating Optimization Software................................. 5-3

A. Demonstrated track record of the optimization product in similar applications............ 5-3B. Experience of the software vendor in supporting product deployment ....................... 5-6C. Total cost of applying the optimization product........................................................... 5-7D. Benefits from the utilization of the optimization product.............................................. 5-9

A SOFTWARE USERS GUIDE .............................................................................................A-1System Requirements.........................................................................................................A-1

Hardware Requirements .................................................................................................A-1Software Requirements...................................................................................................A-1

Installation...........................................................................................................................A-1Using the Software .............................................................................................................A-2

Table 3-1.........................................................................................................................A-3Table 4-1.........................................................................................................................A-3Tables B-3, B-5, B-7, B-8, B-9, and B-11 ........................................................................A-4

User Tutorial .......................................................................................................................A-4

B CASE STUDIES..................................................................................................................B-1Case Study 1: Allegheny Powers Armstrong 1 Unit ...........................................................B-1

Background.....................................................................................................................B-1Armstrong Unit 1 .............................................................................................................B-2Evaluation of Alternative Power Plant Optimization Options ...........................................B-7

Case Study 2: Northern States Power Riverside 7 Unit ....................................................B-17Background...................................................................................................................B-17

NSPs NOx Compliance Plans and Future Needs.....................................................B-17Description of Riverside 7 .............................................................................................B-18Evaluation of Power Plant Optimization Software .........................................................B-18

C FORMULAS........................................................................................................................C-1


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LIST OF FIGURES

Figure 1-1 Impact of Auxiliary Air Register Settings on NOx Emissions and Heat Rateat PEPCOs Potomac River Power Plant ........................................................................ 1-6

Figure 3-1 Effect of air biasing on NOx emissions--400 MW tangential-fired Boiler............... 3-5Figure 3-2 BOOS results for a 365 MW single-wall-fired boiler.............................................. 3-6Figure 3-3 Effect of Coal Quality on NOx Emissions Typical Uncontrolled ............................ 3-9Figure 3-4 Hypothetical NOx Reduction with Balanced Combustion .................................... 3-9Figure 3-5 Effect of Burner Tilt Position on NOx Emissions for Baseline (Uncontrolled)

and Low-NOx (Controlled) Operation--400 MW Tangential-Fired Boiler ....................... 3-11Figure 3-6 Effect of Burner Tilt Position on NOx--105 MNW Tangential-Fired Boiler ........... 3-11Figure 3-7 Effect of Varying the Ratio of Primary Air to Coal on NOx Emissions--105

MW Tangential-Fired Boiler........................................................................................... 3-13Figure 3-8 Union Electric/Meramec Unit 4: Unburned Carbon vs. Coal Fineness, Coal

Flow Imbalance and Coal Blend.................................................................................... 3-20Figure 3-9 PEPCos Potomac River 4/Effect of Mill Maintenance on LOI ........................... 3-21Figure 3-10 Smith 2/Relationship Between LOI, NOx and Coal Fineness ........................... 3-22Figure 3-11 Typical Particle Size Distribution with Static and Dynamic Classifiers .............. 3-23Figure 3-12 Utility Experience with Combustion Tuning & Optimization NOx Reduction

Achieved ....................................................................................................................... 3-24Figure 4-1 Optimization Cost Effectiveness ........................................................................... 4-3Figure A-1 A Portion of Table 3-1 Before and After a Change is entered..............................A-6Figure A-2 A Portion of Table 3-1 Before and After a Second Input is Entered.....................A-7Figure A-3 A Portion of Table 4-1 Applied to Boiler XYZ; Before Use and After a

Change is Entered ..........................................................................................................A-9Figure A-4 A Portion of Table 4-1 Applied to Boiler XYZ; After a Second Group of

Changes is Entered.......................................................................................................A-11Figure B-1 Armstrong Units 1 & 2 Boiler Arrangement ..........................................................B-4Figure B-2 Burner and Mill Arrangement ...............................................................................B-5Figure B-3 Armstrong Unit 1 NOx Emissions After IFS Burner Installation ............................B-6Figure B-4 Armstrong Unit 1 Boiler Efficiency After IFS Burner Installation ...........................B-6Figure B-5 Alternative Coal Pipe Arrangements for Improved NOx Control.........................B-20


xix

LIST OF TABLES

Table 1-1 References and Guidance Documents.................................................................. 1-2Table 1-2 Comparison of Three Measurement Approaches .................................................. 1-3Table 1-3 Suitability of Measurement Approaches for NOx Test Elements (Phases) ............ 1-4Table 3-1 Project Classification to Determine Potential Performance Improvements

Due to Optimization......................................................................................................... 3-3Table 3-2 Expected Performance Improvements................................................................. 3-23Table 3-3 Previous Tuning Objective Safe Operation....................................................... 3-24Table 3-4 Previous Tuning Objective Heat Rate Improvement ......................................... 3-24Table 3-5 Previous Tuning Objective NOx Reduction...................................................... 3-25Table 3-6 Previous Tuning Objective NOx Reduction & Heat Rate Improvement ............ 3-25Table 4-1 Power Plant Optimization Cost-Benefit Analysis.................................................... 4-5Table B-1 Allegheny's Experience with Power Plant Optimization........................................B-2Table B-2 Characteristics of Eastern Bituminous Coal Burned in Armstrong 1......................B-3Table B-3 Project Classification to Determine Potential Performance Improvements

Due to Optimization Armstrong 1/Advanced Control for Coal Flow Distribution ..............B-9Table B-4 Expected Performance Improvements with Optimization (Case 1)......................B-10Table B-5 Project Classification to Determine Potential Performance Improvements

due to Optimization Armstrong 1/ No Coal Flow Distribution Control ............................B-11Table B-6 Expected Performance Improvements with Optimization (Case 2)......................B-12Table B-7 Power Plant Optimization Cost-Benefit Analysis--Armstrong 1 Advanced

Control for Coal Flow Distribution..................................................................................B-13Table B-8 Power Plant Optimization Cost-Benefit Analysis--Armstrong 1 Without Coal

Distribution Control........................................................................................................B-15Table B-9 Project Classification to Determine Potential Performance Improvements

Due to OptimizationRiverside 7 .................................................................................B-23Table B-10 Expected Performance Improvements with Optimization (Case 1)....................B-24Table B-11 Power Plant Optimization Cost-Benefit AnalysisRiverside 7..........................B-25


1-1

1 STEP ONE: TUNE UNIT AND ESTABLISH BASELINE

PERFORMANCE

NO

YES



Step 1 Tune unit &



& objectives








Step One: Tune Unit and Establish Baseline Performance

1-2

Unit performance deteriorates with time and requires periodic retuning andoptimization. Before optimization is carried out, tuning is recommended because:

x it may be adequate to satisfy low-to-moderate performance improvementrequirements (e.g., NOx emission reduction less than 15%),

x it is important even if other performance improvement options are implemented,because it reduces the magnitude of improvement needed and costs associated withit. For example, if a 15% NOx reduction improvement is achieved through tuning,low NOx burners may be adequate to meet NOx regulations instead of low NOxburners with overfire air, potentially saving $5-10 per kW.

Before tuning is performed, diagnostic testing is recommended. After tuning, baselineperformance should be established to serve as the reference point for evaluatingperformance improvement alternatives. The following table provides references toguidance documents which will prove helpful in planning and implementing suchprograms.

Table 1-1References and Guidance Documents

Key Actions Sources/Support Material

Perform diagnostic testing to identify problemsand areas of potential performanceimprovement

Section 5 of EPRIs NOx Emissions Testingand Optimization for Coal-fired Utility Boilers(TR-105109)

Perform Quick Tuning; in most cases, quicktuning improves performance without any out-of-pocket costs

Section 7 of EPRIs NOx Emissions Testingand Optimization for Coal-fired Utility Boilers(TR-105109)

Establish Baseline Performance Section 4 of EPRIs NOx Emissions Testingand Optimization for Coal-fired Utility Boilers(TR-105109)

A. Perform Diagnostic Testing

Diagnostic testing is beneficial because it helps to:

x verify proper functioning of plant components,

x identify off-design operating conditions and problem areas,

x identify site-specific constraints and practices which may preclude the unit fromachieving better performance, and



1-3

x identify potential improvements which can be achieved with minimum effort andbudget.

Detailed guidance on how to carry out a diagnostic program is provided in Section 5,Table 3-1 of EPRIs NOx Emissions Testing and Optimization for Coal-fired UtilityBoilers (TR-105109). In most cases, Type 1 testing (types of testing are shown inTables 1-2 and 1-3) is sufficient. Type 2 or 3 testing should be performed only in caseone or more of the following conditions exist:

x relatively high performance improvement is being sought; for example, NOxemission reduction in the 20-35% range with simultaneous improvement in one ormore of the following: heat rate, unburned carbon, outlet steam temperatures,and/or opacity,

x there are indications of non-uniform air and coal flow distribution in the coal pipesand flue gas in backpass ducts, which may require multiple gas sampling and coalpipe measurements, and/or

x past operating experience and maintenance records suggest high corrosion rateand/or malfunctioning equipment.

Table 1-2Comparison of Three Measurement Approaches

Measurement ApproachElement Type 1 Type 2 Type 3Scope Quick NOx Emissions

assessment with minimalperformance data

Emissions characterization withappropriate combustiondiagnostics

Emissions characterizationwith comprehensivecombustion diagnostic andperformance testing

Instrumentationand sampling andanalyticalprocedures

See Table 1-2 ofTR-105109

See Table 1-2 ofTR-105109

See Table 2 ofTR-105109

Applicability ofResults

Provides quick, inexpensiveassessment of NOx emissions;potentially inadequate for NOxretrofit assessment

Provides sufficient data toidentify emissions range anddominant parameters and toassess NOx retrofit options

Provides instrumentation andmeasurements suitable forcombustion tuning andoptimization of combustionsystem for reduced NOxemissions

Emissionsmeasurementprecision

r25% r10-15% r5-10%

Relative Cost Low Moderate High

Source: TR-105109



1-4

Table 1-3Suitability of Measurement Approaches for NOx Test Elements (Phases)

Measurement ApproachElement Type 1 Type 2 Type 3Baseline Testing X X XCombustion Equipmentdiagnostic testing

X X

Parametric Testing(preliminary and detailed)

X X

Combustion Tuning XSource: TR-105109

Diagnostic testing may include the following inspections and measurements:

x visual inspection of combustion equipment,

x measurement of gas composition uniformity at economizer exit,

x measurement of excess O2 before and after the air heater to estimate air in-leakagethrough the boiler casing and the air heater,

x measurement of unburned carbon in the flyash and combustion efficiency,

x measurement of coal fineness,

x determination of uniformity of air and fuel distribution to the burners,

x inspection of air heaters for potential plugging, and

x inspection of plant instrumentation to ensure proper calibration.

All components which may affect measurements used for performance assessmentshould be checked. Examples of components to check include:

x Instrumentation and controls: Make sure that the existing instrumentation iscalibrated and in good working condition. In particular, accurate measurement ofexcess O2, NOx and CO are essential. Also, the controls should be able to achieverepeatable operating conditions (same control settings should result inapproximately the same plant performance).

x Air registers: Make sure that they are in good operating condition and set properly(based on operating guidelines).



1-5

x Dampers: Air and gas dampers (the latter in case of split backpass) and associateddrives may not be in good operating condition, adversely affecting combustion,NOx generation, and general unit performance. Tempering air and overfire airdampers may have similar effects.

x Burner and overfire air adjustment mechanisms: Burner tilts and yaws in T-fired boilersmay not be in good operating condition or may require tuning. Similarly, overfireair adjustment mechanisms in wall-fired boilers may not be operating properly.

Certain measurements are inherently variable (e.g., feeder speed of pulverizers) andthe appropriate average should be used. However, there may be cases in which keymeasurements are not repeatable and plant optimization may not be feasible orpractical. Such case has been observed in a couple of power plants which did not havewell-calibrated instrumentation.

B. Perform Quick Tuning

A power plant may not have been tuned recently or may have been tuned for anoperating objective different from present operating requirements. For example, theobjectives of the previous tuning could have been safe operation and heat rateimprovement, but future operation may need to focus on balancing NOx emissionsrequirements and heat rate improvement. Knowledge of the operating condition andlimitations of the specific plant equipment, NOx formation mechanisms, and powerplant engineering principles can be applied in a systematic but quick way (QuickTuning) to improve plant performance.

What is Quick Tuning?

Tuning, as defined in TR-105109, involves Type 3 testing (see Tables 1-2 and 1-3) inwhich operational modifications are made to the combustion process to achieve specificoperating objectives such as NOx emissions reduction or heat rate improvement. A keycomponent of this type of tuning is parametric testing which involves the use ofspecialized instrumentation such as multiple-point sampling system to analyze gas andunburned carbon.

Quick tuning is a simplified tuning (Type 1 instead of Type 3 testing) which can becarried out by a plant performance engineer (either from the utility staff or an outsideconsultant) in a period of 3-5 working days. The general approach followed is to checkthe operating condition of key components based on visual observation, evaluatewhatever data are already available at the plant, and attempt to improve performancethrough adjustments of control variables and changes in equipment set-points. Theavailable instrumentation is usually adequate, provided that there are O2, NOx, and COmonitors available.



1-6

Examples of components which may be tuned include:

x Adjust air registers: Very often the registers are set-up to maximize combustionefficiency (reduce unburned carbon). Sometimes they are in a sub-optimum settingeither because there is a problem with their controls (such as: broken drives and notproperly operating position sensor) or because they have not been tuned recently.Resetting of the air registers is simple and can improve both combustion efficiencyand NOx emissions. The latter can be achieved if the air register settings contributeto air staging (creating air-lean flame by distributing more air to the outside of theflame and towards the top burner elevations). Tuning of Potomac Electric PowerCo.s (PEPCO) Potomac River power plant (see Figure 1-1) is a good example ofhow the auxiliary air register settings affect NOx emissions and heat rate. If NOxreduction is a key operating objective, setting the air registers as shown in Figure 1-1 could be a good starting point.

OriginalSetting(Baseline)

Tuned forNOxMinimization

Burner Elevation

Burner Elevation

Source: PEPCo

Aux AirFuel Air

5

5 1 1

1 1Air Flow

Air Flow

O2 (%)

O2 (%)

NOx (lb/MBtu)

NOx (lb/MBtu)

' Heat Rate (%)

' Heat Rate (%)

0 0 0

0 0 0

Figure 1-1Impact of Auxiliary Air Register Settings on NOx Emissions and Heat Rate atPEPCOs Potomac River Power Plant

x Adjust damper set-points: Changes in damper settings may improve air or gas non-uniformities and enhance combustion.



1-7

x Assess low excess air operation: Lowering excess air is desirable because it reducesNOx emissions and improves boiler efficiency. However, below a certain excess airlevel, unburned carbon and CO emissions start increasing and counter-balance thebenefits of low excess air operation. It is therefore desirable to identify the optimumexcess air level and operate as close to this level as possible. The optimum excessair level can be identified by reducing the excess air and monitoring CO emissionsand unburned carbon.

x Assess combustion staging: Creating fuel-rich and fuel-lean combustion zones in theboiler has been proven to reduce NOx emissions. Within certain limits, suchchanges do not adversely affect combustion efficiency. Techniques which have beenwell documented in the literature (EPRIs TR-105109 provides good guidance oncombustion staging) include:

fuel staging (biasing fuel distribution among the burner elevations),

air staging (see above example from PEPCos Potomac River plant),

burners out of service (BOOS), sometimes called mills out of service(MOOS), and

simulated overfire air (OFA).

x Improve pulverizer performance: Air-to-fuel ratio and quick tuning of the pulverizer(e.g., adjustment of spring tension and outlet temperature) can improve coalfineness, combustion efficiency, and general plant performance. Balancing of airand coal flows is very important, especially for wall-fired boilers, but it may not bepart of quick tuning because it requires more extensive effort to assess the level ofbalancing needed and to implement the necessary modifications (e.g., coal pipeorificing).

Changes made under quick tuning may have adverse impacts on unburned carbon, COemissions, slagging, fouling corrosion, unit generating capacity, rate of load change andunit heat rate. More information regarding assessment of adverse impacts of tuning(combustion tuning trade-offs) is provided in Section 7 of TR-105109.

C. Establish Baseline Performance

It is essential to establish baseline performance which reflect what can be achieved by awell-tuned unit with reasonable effort of the plant staff. Baseline performance then canbe used as a reference point to decide what improvements need to be made and howwell the performance improvements will perform.



1-8

Depending on the dispatch profile (cycling duty) of the unit, baseline tests may involvetesting only at full load or at various loads. Detailed guidance on how to plan andimplement baseline testing is provided in Section 4 of EPRIs NOx Emissions Testingand Optimization for Coal-fired Utility Boilers (TR-105109)..


2-1

2 STEP TWO: ESTABLISH CLEAR NEEDS AND

OBJECTIVES

NO

YES










& objectives

Step 1 Tune unit &



Step Two: Establish Clear Needs and Objectives

2-2

A. Identify desired performance improvements relative to baseline performance

Performance improvements are usually dictated by regulatory requirements (e.g.,reduction of NOx emissions or opacity) and/or driven by economics (e.g., need toreduce heat rate or unburned carbon to make it easier to sell the flyash). Indetermining the units performance improvement needs, the following options shouldbe investigated:

x Reduce NOx emissions:

What are the unit, plant, and system NOx reduction requirements?

Are these requirements clear or might future regulations demandadditional NOx reductions? Is there adequate information to identifyhow NOx requirements may change over time (covering the life of theunit under consideration)?

Is there flexibility in terms of NOx averaging?

Is NOx emission banking an option in case the unit overcomplies?

Is buying NOx emission allowances an option? If yes, at what cost?

x Lower heat rate: This objective is usually driven by economics; there are no specificrequirements, but targets may be set based on the historical records and theassessment of potential heat rate improvement. Depending on how well the unit istuned, heat rate improvements due to optimization may range from 0.5 to 1.5percentage points at full load or up to 5 percentage points at low loads.

x Reduce unburned carbon (UBC):

Are there any unburned carbon requirements, such as maximum UBC (orLOI), to sell the flyash?

Are there any other adverse impacts from high UBC such as reducedcollection efficiency of the ESP?

If there are no specific requirements to reduce or keep UBC to below a certain level,economics should dictate the optimum level.

x Lower opacity

x Lower CO emissions:



2-3

What is the maximum level of CO emissions set by the manufacturer orthe plant operator?

Is the unit exceeding it on the average? occasionally?

x Requirements and constraints associated with outlet steam temperatures: Are boiler outletsteam temperatures below design levels? If yes, is it required to increase thesetemperature for safe operation? If operating safety is not jeopardized, determine therelationship between steam temperature (both superheat and reheat) and improvedheat rate (% improvement in heat rate per degree steam temperature increase).

x Other requirements: While not easy to quantify, other unit performanceimprovements are not uncommon, for example:

improve operating safety; this may suggest increasing the excess O2(keeping it above a lower limit) or reducing UBC,

reduce potential for waterwall corrosion by increasing excess O2 above acertain level, or

reduce maintenance requirements and improve equipment reliability.

B. Differentiate between firm requirements and desirable outcomes

As already indicated in the above questions, it is very important to differentiatebetween firm requirements and desirable outcomes. Firm requirements mayinclude:

x Annual average NOx of the unit to comply with CAAA requirements; for example:340 ppm (0.45 lbs/MBtu) for T-fired and 375 ppm (0.50 lbs/MBtu) for wall-firedboilers burning coal,

x NOx cap at plant and/or system level; for example: specified numbers of tons peryear from a multi-unit power plant or a power system,

x UBC (or LOI) below a certain level for selling the flyash, if flyash disposal is anavailable option, keeping UBC below a certain level may not be a firm requirement,

x Maximum opacity as specified by local or federal regulations, for example, 15%opacity may be set as a maximum,

x Maximum CO emissions; maximum daily average and/or instantaneous valuesmay be specified, and



2-4

x Also, minimum steam temperature level or maximum superheat-reheat temperaturedifferential may be specified.

Desirable outcomes may include:

x Lower NOx emissions than required by regulations to allow more expensive unitsin the system to operate at higher NOx levels (NOx averaging or trading); therefore,reducing system compliance costs,

x Lower heat rate, and

x Higher steam temperatures.

To the extent possible, firm requirements should be minimized, so that optimizationmay determine the best operating conditions. The fewer firm requirements, the greaterthe operating efficiency that can be achieved through optimization.

C. Articulate project objectives It is important that clear objectives are articulated which reflect:

x firm requirements,

x desirable outcomes, and

x references to important factors and key assumptions.

Examples of project objectives:

x Reduce annual average NOx emissions from the present baseline level of 390 ppm(0.52 lbs/MBtu) to 320 ppm (0.43 lbs/MBtu) without adverse operating impacts onheat rate, LOI, CO, and opacity. NOx reductions beyond this target are not of anyvalue to the utility at this point in time.

x Reduce annual average NOx emissions from the present baseline level of 390 ppm(0.52 lbs/MBtu) to 320 ppm (0.43 lbs/MBtu). Further NOx reduction and heat rateimprovement are desirable to the extent that these improvements are economic.Also, adverse O&M impacts are acceptable provided that they result in loweroverall production cost and do not jeopardized plant safety. (Notes: value ofadditional NOx reduction tothe system is worth 400-500 $/ton of NOx removed; marginal cost of power is 8cents/kWh).



2-5

x Reduce heat rate while keeping annual average NOx emissions below 360 ppm(0.48 lbs/MBtu). Additional NOx reductions are not of any value to the utility atthis point in time.


3-1

3 STEP THREE: DETERMINE OPTIMIZATION

POTENTIAL/CAN OPTIMIZATION ALONE MEET

ESTABLISHED OBJECTIVES?

NO

YESStep 4

Identify the most cost-effective type of optimization



z

NOx controls (Low NOx burners, SNCR, reburning, and SCR)

z

Hardware modifications for heat rate improvements

Step 1 Tune unit &





& objectives


Step Three: Determine Optimization Potential/Can Optimization Alone Meet Established Objectives?

3-2

Can Optimization Alone Meet Established Objectives? Deciding whether optimization alone can meet the established objectives involves:

x estimating the level of performance improvement to be expected throughoptimization, and

x comparing this level to the desirable level of performance improvement establishedin Step 2; optimization is adequate if it meets the firm requirements.

If optimization is not adequate to meet the established objectives, it is still a very cost-effective option and should be evaluated in combination with other options such as lowNOx burners, SNCR, or SCR.

Estimating the potential performance improvement requires consideration of site-specific factors and requirements, as well as the performance improvement potential ofthe various types of optimization software. Table 3-1 provides a structure throughwhich the user may determine the potential performance improvement achievedthrough optimization by considering site-specific factors (see printout of Table 3-1 onthe next page and the text Box 3-1 which describes the software version of Table 3-1.

Box 3-1 Software Guidance on Table 3-1

For system requirements, installation and loading of the Excel files included onthe floppy disk, see Appendix A. The Excel file Table 3-1.xls provided on thefloppy disk should be used to carry out Step 3 of the guidelines. A print out ofthe table appears in these guidelines on page 3-3. The user should answer thequestions about the technical circumstances of the boiler in question by enteringthe appropriate score from 1 to 3 based on the instructions given in this section.The table then automatically calculates a Total Score between 100 and 300which indicates the degree to which optimization can improve boilerperformance. Tables 3-2 and 3-2a to 3-2d on pages 37-39 of the guidelines (theyare not included on the disk) provide the performance improvements that canbe expected based on the score generated in Table 3-1.

The main criteria for estimating the level of performance improvement are groupedinto the following four categories:

1. time since last tuning and its objective (weighting: 30%),



3-3

Table 3-1Project Classification to Determine Potential Performance Improvements Due to Optimization



3-4

2. unit operating flexibility (weighting: 20%),

3. ability to change equipment settings (weighting: 20%), and

4. ability to modify hardware (weighting: 30%).

As shown in parentheses (above), a weighting factor is applied to each categoryreflecting its importance relative to potential performance improvement. While someof the weighting factors for these categories may seem arbitrary, they reflect actualindustry experience (the authors have participated in 10-12 optimization projects) andprovide an effective way to categorize each project. As such, Table 3-1 could be usedeither as an analytical tool or as a general guideline.

In each category, a number of questions are presented. By responding to thesequestions (in shaded boxes), the spreadsheet automatically provides a Total Scorewhich classifies the project into one of three categories (A, B or C). The expectedperformance improvements (mainly NOx reduction and heat rate improvement) areshown in Tables 3-2 and 3-2a through 3-2d. Table 3-2 shows performanceimprovement for each of the three project classifications. Tables 3-2a through 3-2dfurther narrow down the expected performance improvement based on the objectivesof the last tuning.

Background and Instructions for Completing Table 3-1

Information on the Last Unit Tune Up

Combustion system tuning here refers to systematic checking and adjustment of controlvariables and equipment settings to ensure that unit operating objective are met. Suchtuning may be done by the boiler manufacturer, a service company (engineeringconsultant), or plant personnel. The longer the time since the last tuning, the higher thepossibility and potential for performance improvement.

When was the unit last tuned?

x Enter 1 if less than a year,

x Enter 2 if between 1-2 years, or

x Enter 3 if more than 2 years,



3-5

Tuning Objective?

x Enter 1 if the goal was to ensure safe operation (stable flame andcomplete combustion),

x Enter 2 if the goal was to improve heat rate,

x Enter 3 if the goal was to reduce NOx emissions, or

x Enter 4 if the goal was to reduce both heat rate and NOx emissions.

Unit Operating Flexibility (at full load)

Fuel Flow Biasing

The capability to bias fuel flow relative to the baseline setting presents the potential toreduce NOx emissions by up to 20-25%. More fuel is typically directed to the lowerburner elevations than the upper elevations with the possibility of no fuel in the topburner. Figure 3-1 shows the NOx reduction achieved at Kansas Power & LightsLawrence #5 unit due to biased firing

0.6

0.4

0.2

0.00 1 2 3 4 5 6 7

Excess O2 (%)

NO

x E

mis

sio

ns

(Lb/

MB

tu)

Source: Kansas Power & Light Co, Lawrence Unit 5; EPRI Report TR-102906

Biased Firing(minimum fuel a ir,maximum auxiliary air to top elevations)

Baseline

450

300

150

0

NO

x E

mis

sio

ns

(ppm

)

Figure 3-1Effect of air biasing on NOx emissions--400 MW tangential-fired Boiler



3-6

When there is adequate fuel supply system capacity, burners out of service (BOOS)may be used to reduce NOx emissions. Figure 3-2 shows the impact of BOOS on NOxemissions in a 365 MW front wall-fired boiler.

1.0

0.8

0.6

0.0

Burner Firing Pattern

NO

x E

mis

sio

ns

(Lb

/MB

tu)

Source: Energy Technology Consultants, Inc.

Range in NOx emissions for each pattern reflects differences in excess O2 levels

Top pulverizer

Bottom pulverizer

Burner in Service Burner Out Of Service

750

600

450

0.0

NO

x E

mis

sio

ns

(pp

m)

Figure 3-2BOOS results for a 365 MW single-wall-fired boiler

Fuel biasing may have an impact on combustion efficiency, because it affects the fueldistribution along the height of the combustion zone and the residence time of the fuelparticles in the furnace.



3-7

Fuel Flow Biasing

Specify the level of fuel flow biasing capability at full load as follows:

x Enter 1 for no biasing; i.e. if the fuel feed system (or mills in the case ofcoal-fired power plants) are operating at or near maximum capacity,

x Enter 2 if some fuel biasing is available, but not enough to have onemill or row of burners out of service, or

x Enter 3 if there is enough fuel feed system capacity to have one mill orrow of burners out of service at full load.

Air Flow Biasing

Air flow biasing is similar to fuel biasing in that the air distribution along the height ofthe combustion zone can be altered relative to baseline conditions. Introducing moreair through the top burner elevations and less through the lower elevations delayscombustion and reduces NOx emissions. Examples of air flow biasing are shown inFigure 1-1 and 3-1.

Air flow biasing can be used independently from other control changes or may becombined with fuel biasing. The highest level of biasing is achieved when the topburner elevation is out of service and more air flow is biased towards the upper burnerelevations. This type of operation very often is referred to as simulated overfire airand achieves the highest NOx reduction.

Non-uniform air flow distribution is usually indicated by different excess O2measurements from one side of the boiler backpass (flue gas duct) to the other. 1-3percentage points difference is not unusual in many boilers. Reducing this differenceallows the total excess air to be reduced as well.



3-8

Air Flow Biasing

Specify the level of air flow biasing capability at full load as follows:

x Enter 1 for no biasing; this is the case in which the air supply system(fans) are operating at or near maximum capacity,

x Enter 2 if air biasing is possible and can increase or decrease air flowrate through each air compartment by up to 20% relative to baselineconditions, or

x Enter 3 if more than 20% air flow biasing can be achieved.

Excess O2 (baseline vs. minimum O2 level)The impact of excess O2 (excess air) on NOx emissions and combustion efficiency hasbeen well documented: Figure 3-3 shows how excess O2 impacts NOx for various typesof coals. Lower excess O2 results in lower NOx and higher boiler efficiency. However,below a certain level of excess O2, the combustion efficiency (more specifically, theunburned carbon and CO emissions) is adversely affected. Figure 3-4 illustrates therelationship between excess O2, NOx, and unburned carbon. Maximum O2 is alsolimited by equipment capacity constraints.

1.6

1 .4

1 .0

0 .00 1 2 3 4 5 6 7

E xcess O 2 (% )

NO

x E

mis

sio

ns

(L

b/M

Btu

)

S o urc e: EE R

B itum inous

0.6

1 .2

0 .8

0 .4

S ubbitum inous

Lignite

1200

1050

900

750

600

450

300

0

NO

x E

mis

sio

ns

(p

pm)

Figure 3-3Effect of Coal Quality on NOx Emissions Typical Uncontrolled



3-9

Excess O2

NOx

Source: EPRI/TR-105109

Avg

. O2-

Bal

.

Avg

. O2-

Unb

al.

Avg. UBC (b

UBC

NOx Reductionwith Bal. Comb.

oth cases)

UnbalancedBalanced

Note: Points on curves represent average operating conditions for each burner mill group (assumes 3 mills total).

Figure 3-4 Hypothetical NOx Reduction with Balanced Combustion

The maximum excess O2 and the level of excess O2 at which combustion efficiencystarts decreasing define an operating range. The wider this range, the higher thepotential for performance improvements.

The excess O2 operating range changes with load and operating conditions. If thisoperating range has not been established, it is recommended that it be established, atleast at full load, by reducing the excess O2 until CO emissions and/or unburned carbonstart increasing significantly. For such measurements, a CO monitor and LOI analysisare required.



3-10

Excess O2 (baseline vs. Minimum O2 level)

Indicate the excess O2 operating range at full load as follows:

x Enter 1 if the baseline excess O2 is within 0.5 percentage point from theminimum excess O2,

x Enter 2 if the baseline excess O2 is within 0.5 and 1.5 percentage pointfrom the minimum excess O2, or

x Enter 3 if the baseline excess O2 is at least 1.5 percentage points higherthan the minimum excess O2.

Operating Flexibility of Burner Tilts (only in the case of T-fired boilers)Burner tilt has an impact on NOx emissions. While in most cases increasing tiltincreases NOx (see Figure 3-5), under certain circumstances, (see Figure 3-6), theopposite may be true. Also, tilt affects combustion efficiency (up tilt reduces the coalparticle residence time) and boiler outlet steam temperatures. The higher the flexibilityto change burner tilt the higher the potential for performance impacts.

0 .8 0

0 .4 0

0 .0 0

B urne r T ilt A ng le (de g )

NO

x E

mis

sio

ns

(L

b/M

Btu

)

S o u rce : U ta h P o w e r & L ig ht C o m pa ny , H u n te r U n it 2

0 .6 0

0 + 1 5 + 2 0-5-1 5 -1 0 + 1 0 + 2 5+ 5

U n co n tro lled

C o n tro lled

6 0 0

4 5 0

3 0 0

0

NO

x E

mis

sio

ns

(p

pm

)



3-11

Figure 3-5Effect of Burner Tilt Position on NOx Emissions for Baseline (Uncontrolled) andLow-NOx (Controlled) Operation--400 MW Tangential-Fired Boiler

Operating Flexibility of Burner Tilts (only in the case of T-fired boilers)

Indicate the burner tilt operating range at full load as follows:

x Enter 1 if the burner tilts are not operational (e.g., stuck),

x Enter 2 if the burner tilts are operational, but over a limited range(e.g., -15 to +10 degrees), or

x Enter 3 if the burner tilts are operational over the full operating range,typically -30 to +30 degrees.

0.70

0.66

0.62

0.60

Burner Tilt Angle (deg)

NO

x E

mis

sio

ns

(L

b/M

Btu

)

Source: Potomac Electric Power Company, Potomac River Station

0.68

0.64

0 +10 +20-10-20

525

510

495

480

465

455

NO

x E

mis

sio

ns

(p

pm)

Figure 3-6Effect of Burner Tilt Position on NOx--105 MNW Tangential-Fired Boiler



3-12

Operating Range of Air and Gas Dampers

The more flexibility to adjust gas and air dampers, the higher the potential forperformance improvements, for example:

x Air dampers which control the air flow rate to the four corners of T-fired boilers orto front versus rear wall of opposed wall-fired boilers,

x Air dampers which control the air flow to individual burners, or

x Gas dampers in split backpass boilers.

Operating Range of Air and Gas Dampers

Indicate the level of flexibility of air and/or gas dampers as follows:

x Enter 1 if adjustable dampers do not exist or the dampers can not beadjusted, either because they are not operational (e.g., stuck) orbecause they can not be controlled remotely,

x Enter 2 if the dampers can be adjusted, but to a limited extent (e.g.,half operating range), or

x Enter 3 if the dampers can be adjusted over the full operating range.

Primary Air to Fuel Ratio (PA/Fuel) PA/Fuel ratio has an impact on both NOx emissions and combustion efficiency. Therelationship between NOx and primary air velocity (an indicator of PA/Fuel ratio) foran 105 MW T-fired boiler is shown in Figure 3-7 (see next page). The more flexibilitythe boiler has to adjust PA/Fuel ratio, the higher the probability of performanceimprovements. However, this flexibility is typically limited by available primary airfan capacity and pulverizer (in the case of coal-fired power plants) operatingconstraints.



3-13

Primary Air to Fuel Ratio (PA/Fuel)

Indicate the level of flexibility of PA/Fuel ratio as follows:

x Enter 1 if there is no operating flexibility; PA/Fuel ratio has to complywith predetermined settings,

x Enter 2 if some operating flexibility exists, for example, PA/Fuel ratiomay change within the range 1.8 to 2.0, or

x Enter 3 if there is more flexibility with the PA/fuel ratio, for examplePA fuel ratio may change within the range of 1.5 to 2.5.

0.45

0.30

Average Primary Air Velocity (ft/sec)

NO

x E

mis

sio

ns

(L

b/M

Btu

)

Source: Potomac Electric Power Company, Potomac River Station

0.40

0.35

90 100 1108070

Note: Tests conducted at reduced load of 35 MW

NO

x E

mis

sio

ns

(p

pm)

337.5

300

262.5

225

Figure 3-7Effect of Varying the Ratio of Primary Air to Coal on NOx Emissions--105 MWTangential-Fired Boiler

Other Control Variables

Control variables other than those discussed above may be available, depending on theconfiguration of the boiler. Control variables are defined as all the operatingparameters which can be changed remotely (from the control room). Such variablesmay include tempering air dampers and exit temperature control of the pulverizers orthe ability to mix different coals.



3-14

Other Control Variables

Indicate the level of flexibility provided by these categories of control variablesas follows:

x Enter 1 if there is no operating flexibility,

x Enter 2 if some operating flexibility exists, for example, air registersmay change by up to 30% of the original setting, or

x Enter 3 if the control variables can change throughout their designoperating range.

Ability to Change Equipment Settings

This category includes changes which cannot be made from the control room, butrequire manual adjustment of equipment. In most cases, these changes can be madewhile the boiler is operating. For example, adjustments of burner settings can be donewhile the burner is operating. Some of the pulverizer changes may require thepulverizer to be off-line, but this does not mean that the boiler must be off-line as well;adjustments could be made to one pulverizer at a time, while the boiler is operating ator near full load.

Burner Settings

Changing the original burner settings may improve boiler performance. Burnersettings which should be considered include:

x air registers,

x air sleeve dampers and coal nozzle axial position (in some wall-fired boilers),

x yaw of burners and/or overfire air ports (in the case of T-fired boilers), and

x relationship between burner tilt and overfire air tilt (in the case of T-fired boilers); inmost cases, the overfire air tilt angle is set based on the burner tilt angle; the originalsetting could be changed or the overfire air tilt may be decoupled from the burnertilt.

These parameters are usually set during combustion system tuning which is carried outby the burner vendor. While readjustment of these parameters may yield performanceimprovements, it is not always easy to do so. Constraints may relate to:



3-15

x contractual requirements specified by the burner vendor regarding operation andmaintenance of the combustion system,

x physical layout of the combustion system which makes it difficult to adjust burnersettings, and

x limited personnel with experience to make the necessary adjustments.



3-16

Burner Settings

Indicate the level of flexibility to adjust the burner settings:

x Enter 1 if there is no or very limited flexibility to adjust the burnersettings as part of an optimization program,

x Enter 2 if there is some flexibility, for example, half of the burnersettings can be adjusted, or

x Enter 3 if most of the burner settings can be adjusted.

Pulverizer Settings (in case of coal-fired power plants) Very often pulverizer performance can be improved through changes such as:

x journal spring pressure,

x adjustment of classifier blades and clearances,

x adjustment of flow straighteners, and

x changes in outlet temperature set-point.

Pulverizer Settings (in case of coal-fired power plants)

Depending on the flexibility to adjust pulverizer settings:

x Enter 1 if there is no or very limited flexibility to adjust the pulverizersettings as part of an optimization program,

x Enter 2 if there is some flexibility, for example, half of the pulverizersettings can be adjusted, or

x Enter 3 if most of the pulverizer settings can be adjusted.

Other Equipment Settings

Changes in the settings of other equipment may help improve overall plantperformance, for example, in some wall-fired boilers with low NOx burners, the burnercoal nozzle is adjustable. Changing the position of the nozzle affects NOx emissions,LOI, and boiler efficiency.



3-17

Other Equipment Settings

Depending on the flexibility to adjust the settings of other equipment:

x Enter 1 if there is no other equipment,

x Enter 2 if there is one other piece of equipment that can be adjusted, or

x Enter 3 if there are more than one piece of equipment that can beadjusted.

Hardware Modifications

This category includes hardware modifications which are not considered major interms of amount of investment, but can improve plant performance significantly.Examples of such modifications include:

x modifications of the air distribution system,

x coal pipe orificing, and

x installation of dynamic classifiers.

In most cases, hardware modifications require the equipment to be off-line. In somecases, boiler shut-down may be avoided, for example, dynamic classifiers and coal pipeorificing may be done one pulverizer at a time while the boiler is operating.

Air Distribution Modifications

Better control of air flow distribution along the height of the combustion zone and theindividual burners usually results in better performance. In many cases, the air flowdistribution can be improved through:

x addition of dampers,

x addition of turning vanes, and

x adjustment of existing directional plates/vanes.

An example of a successful application of such modifications is Potomac Electric PowerCo.s (PEPCo) Potomac River #4 optimization which is described in Box 3-2 (see nextpage).



3-18

Air Distribution Modifications

x Enter 1 if air distribution modifications will not be included in theoptimization program, or

x Enter 3 air distribution modifications will be included in theoptimization program.

Note: there is no Enter 2 option in this and several of the following boxes

Coal Pipe Orificing

In case of significant coal pipe-to-pipe flow imbalance (more than 5% from uniformflow distribution), orificing may improve the coal flow distribution, combustionefficiency, and overall plant performance. Figure 3-8 provides an example of the



3-19

Box 3-2 PEPCo Modifies the Air Distribution System for NOx Optimization

Installation of splitter dampers, tuning vanes and windbox compartmentalization at PEPCos PotomacRiver 4 balanced the air distribution from the front to the rear corners and resulted in a more uniformair distribution in each burner. While it was not possible to assess the NOx reduction achieved withthese modifications (because other modifications were made at the same time followed by optimization),they were a contributing factor to the overall NOx reduction achieved which reached 30-35%.

Hot Air from Air Heater

To Front Corners

PEPCOs Potomac River 4 Combustion Air System To Rear Corners

FurnaceHot Air from Air Heater

To Front Corners

To Rear Corners

Furnace

Splitter Damper

Turning Vane

Windbox Compartmentalization

Before Modifications

After Modifications

Source: PEPCO



3-20

beneficial impacts of improved fuel balancing, as well as higher coal fineness at UnionElectrics Meramec #4 unit (a front wall-fired 360 MW boiler retrofitted with B&WsXCL burners). Improving the coal balance from 10% to 5% from the uniform flowdistribution reduces unburned carbon in the flyash by 2-3 percentage points.

15

0

% of Coal A (Kerr McGee mine)Remaining is Coal B (Rend Lake mine)

% C

arb

on

in Fl

ysas

h

Source: Union Electric

10

5

50 75 100250

20

25

99.0% 50 Mesh70% 200 Mesh

99.9% 50 Mesh80% 200 Mesh

+/- 10% Fuel Balance

+/- 5% Fuel Balance

+/- 10% Fuel Balance

+/- 5% Fuel Balance

Figure 3-8Union Electric/Meramec Unit 4: Unburned Carbon vs. Coal Fineness, Coal FlowImbalance and Coal Blend

Coal Pipe Orificing

x Enter 1 if coal pipe orificing will not be included in the optimization program, or

x Enter 3 if coal pipe orificing will be included in the optimization program.



3-21

Mill Modifications

Mill modifications, including installation of exhausters, riffle distributors, and dynamicclassifiers, may result in better coal fineness and coal size distribution control, which inturn improves combustion efficiency and plant performance.

Coal fineness and size distribution have a significant effect on the combustion process,and control of size distribution can be used to reduce LOI. Generally, higher coalfineness results in better coal combustion. Coarse coal particles (usually defined to belarger than 150 microns [remaining on 100 mesh]) have been shown to be the primarysource of unburned carbon. The percentage of coal remaining on 50 mesh (300 micron)is increasingly used as the key indicator of adequate coal size distribution.

Figure 3-9 shows the effect of improved size distribution on LOI at PEPCos PotomacRiver #4, a 100 MW T-fired boiler without combustion NOx controls. Thisimprovement was the result of pulverizer maintenance and tuning. As this figureshows, the reduction of larger particles (percentage remaining on 50 mesh [300 micron]was reduced from 3% to 0.5%, resulting in lower LOI even though the percentagethrough 200 mesh (75 micron) did not change significantly. Furthermore, improvedcoal size distribution allows operation at lower excess O2, which reduces NOxemissions.

02468

101214161820

0 1 2 3 4 5 6Economizer O2 (%)

LOI (

%)

After mill maintenance

Before

AfterPlus 50 mesh 2 to 3% 0.5%Minus 200 mesh 74% 73%

Before mill maintenance

Source: PEPCo

Figure 3-9 PEPCos Potomac River 4/Effect of Mill Maintenance on LOI

The beneficial effect of higher coal fineness and improved size distribution on both LOIand NOx emissions is also demonstrated by Figure 3-10 which shows the test results



3-22

from Gulf Powers Smith #2 (a 180 MW T-fired boiler) retrofitted with ABB/CEsLNCFS III.

LOI (%)

0

0.1

0.2

0.3

0.4

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0

low fineness

medium fineness

high fineness

NOx

emis

sion

s (lb

s/M

btu)

increasing excess oxygen

Source: Southern Company Services

300

225

150

75

0

NOx

emis

sion

s (p

pm)

Figure 3-10Smith 2/Relationship Between LOI, NOx and Coal Fineness

As coal fineness improves, the same NOx emission level can be achieved with lowerLOI and excess O2. For example, 225 ppm (0.30 lbs/MBtu) NOx level can be achievedwith low fineness2 coal resulting in 10-11% LOI or with high fineness coal resulting in3% LOI. Such relationships are useful in optimizing unit performance to satisfy itsoperating objectives (e.g., NOx requirements and LOI constraints).

One of the options used to improve and control coal size distribution is dynamicclassifiers which achieve a better particle size distribution than static classifiers, (seeFigure 3-11). Additional advantages of dynamic classifiers include:

x better control of particle size distribution,

x improved flexibility which is particularly important when the coal quality varies,and

x better load response and unit turndown.

2 The low and high fineness represent the minimum and maximum fineness achievable with thepulverizers available at Smith 2; different pulverizers may achieve wider range of finenesses.



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60

70

80

90

100

60 100 140 180 220 260 300

Sieve (micron)

% P

assi

ngStatic

Dynamic

Source: EnTEC

Figure 3-11Typical Particle Size Distribution with Static and Dynamic Classifiers

Mill Modifications

x Enter 1 if mill modifications will not be included in the optimization program, or

x Enter 3 if mill modifications will be included in the optimization program.

Expected Performance Improvements

Based on the Total Score in Table 3-1, the users project falls in one of the classificationsshown in Table 3-2.

Table 3-2Expected Performance Improvements

Project Classification Total Score % NOx Reduction Heat RateImprovement

Group A 100-160 5.0 - 15.0 0.00 - 0.75Group B 160-240 15.0 - 30.0 0.50 - 1.25Group C 240-300 25.0 - 40.0 1.00 - 1.50

The NOx reduction for Groups A, B and C is shown in Figure 3-12.



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05

1015

2025

30354045

Group A

Group BGroup C

% N

Ox

Red

uctio

n

Worsening Operating Condition of Existing Equipment

Increasing Operating Flexibility

Figure 3-12Utility Experience with Combustion Tuning & Optimization NOx ReductionAchieved

The expected performance improvement should be adjusted further based on theobjective of the previous tuning as shown in Tables 3-2a through d.

x If the objective of the previous tuning was safe operation, use the upper end of theprojected performance for both NOx and heat rate, as shown in Table 3-2a.

Table 3-3Previous Tuning Objective Safe Operation

Project Classification NOx Heat RateGroup A 10.0 - 15.0 0.25 - 0.50Group B 22.5 - 30.0 0.75 - 1.25Group C 32.5 - 40.0 1.25 - 1.50

x If the objective of the previous tuning was heat rate improvement, use the upperend of the projected NOx reduction, but the lower end of the heat rateimprovement, as shown in Table 3-2b.

Table 3-4Previous Tuning Objective Heat Rate Improvement

Project Classification NOx Heat Rate Group A 10.0 - 15.0 0.0 - 0.40 Group B 22.5 - 30.0 0.50 - 0.75 Group C 32.5 - 40.0 1.00 - 1.25



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x If the objective of the previous tuning was NOx reduction, use the lower end ofthe projected NOx reduction range, but the upper end of the heat rate improvement,as shown in Table 3-2c, and

Table 3-5 Previous Tuning Objective NOx Reduction


x If the objective of the previous tuning was combined NOx reduction and heat rateimprovement, use the lower end of both NOx reduction and heat rateimprovement, as shown in Table 3-2d.

Table 3-6Previous Tuning Objective NOx Reduction & Heat Rate Improvement


The user is encourage to override the above performance predictions, if he/she has abetter understanding of expected performance improvements. For example, priorefforts to improve heat rate may have proven that the maximum heat rate reductionmay be limited to a specific level which is outside the ranges provided in Table 3-2.

LOI, CO emissions, and opacity can be kept at present levels or improved slightlydepending on the level of improvements being sought for NOx and heat rate; thehigher the NOx and heat rate improvements sought, the lower the possibility forsignificant LOI, CO and opacity improvements.

Compare potential performance improvements to project objectives and decide ifplant optimization is a feasible and suitable option.

If optimization seems to meet objectives, proceed to Step 4. If it does not, hardwaremodifications should be considered. For NOx Control Retrofit Options, see thefollowing EPRI publications: 1) Retrofit NOx Controls for Coal-Fired Utility Boilers -1996 Update Addendum (TR-102906-Addendum), and 2) Retrofit NOx ControlGuidelines for Gas- and Oil-Fired Boilers (TR-102413).


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4 STEP FOUR: IDENTIFY THE MOST COST-EFFECTIVE

TYPE OF OPTIMIZATION

NO

YES







Step 1 Tune unit &





& objectives


Step Four: Identify the Most Cost-Effective Type of Optimization

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Types of Optimizations:

x Stand-alone (previously referred to as Off-line/One-time)

x On-line/advisory

x Closed-loop

The selection of the most appropriate and cost-effective optimization type depends onthe following:

x Availability of Digital Control Systems (DCS) and Data Acquisition Systems (DAS),

x The need for continuous vs. one-time optimization,

x The performance improvement objectives, and

x The cost-effectiveness of alternatives.

A. Availability of DCS and DAS

Availability of DCS and DAS are essential for on-line/advisory and closed-loopoptimization. DCS and DAS make stand-alone optimization easier to carry out, butthey are not essential. Therefore, if the plant under consideration does not have nor is there aplan to install DAS and DCS, it is not suitable for on-line/advisory and closed-loopoptimization.

B. Continuous vs. One-time or Periodic Optimization

If continuous performance optimization is desirable, stand-alone systems are not suitable. One-time or periodically repeated stand-alone optimization may be suitable and more cost-effective in cases in which the plant needs to reach a certain performance level belowwhich there is no strong incentive to optimize further. An example is the case wherethere is a need to limit NOx emissions beyond a certain level (e.g. 0.50 lbs/MBtu), butthere is not an incentive to achieve the minimum NOx