TECHNICAL COMMITTEE ON MULTIPLE BURNER BOILERS …...TECHNICAL COMMITTEE ON . MULTIPLE BURNER...

TECHNICAL COMMITTEE ON MULTIPLE BURNER BOILERS

NFPA 85 Second Draft Meeting Agenda

January 24, 2018 8:00 AM – 5:00 PM CT Entergy Corporation, 639 Loyola Avenue, New Orleans, LA

1. Call to Order. Michael Walz, Chair

2. Introductions.

3. Approval of Meeting Minutes from February 7-8, 2017. (Attachment A)

4. Staff Updates. Laura Moreno, NFPA Staff

• Committee membership update. (Attachment B)

• Fall 2018 revision cycle schedule. (Attachment C)

• Overview of NFPA Process

5. Brief overview of Public Comments, Committee Inputs, and Correlating Committee Note and Revisions.

6. Review of Fundamentals Technical Committee actions. (Attachment D)

7. Task Group Reports.

• Task Group on Interlock Functional Tests (First Revisions 163, 169, and 174): David King (Chair), Jimmie Schexnayder, James Franks, Franklin Switzer, and Marc Cropp.

• Task Group on Plasma Arc Igniters: Skip Yates, Bill Smith, Scott Matz, Edward Lightbourn, Masaaki Kinoshita, John Eibl, Denise Beach, Frank Bennett, and Carlos Santos.

• Review of Igniter Classification Tests (Committee Input 142): Bill Smith and Skip Yates

8. Review of Public Comments: NFPA 85 Chapter 6. (Attachment E)

9. Review of Committee Inputs. (Attachment F)

NFPA 85 (BCS-MBB) Second Draft Technical Committee Meeting January 24, 2018 - New Orleans, LA

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10. Review of Correlating Committee Notes and Revisions. (Attachment G)

• Review of Overpressure Protection Requirements (First Revision 155 and Committee Input 322): John Eibl

11. New Business.

12. Next Meeting.

13. Adjourn.


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Attachment A: Previous Meeting Minutes


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TECHNICAL COMMITTEE ON MULTIPLE BURNER BOILERS

NFPA 85 First Draft Meeting Minutes

February 7-8, 2017 8:00 AM - 5:00 PM MT Salt River Project PERA Club, 1 Continental Drive, Tempe, AZ

Attendees

Committee Members:

Michael Walz, Chair Burns & McDonnell Engineering Company, MO

Denise Beach FM Global, MA

Frank Bennett NRG Energy, MD

John Bollinger Babcock & Wilcox Company, OH

David Dexter* The Dow Chemical Company, LA

John Eibl The Chemours Company Inc., TN

Dale Evely Southern Company Services, Inc., AL

Joseph Fehr Sega, Inc., KS

Kenneth Joe Frazier Salt River Project, AZ

David King American Electric Power Company, Inc., OH

Daniel Lee ABB Incorporated, OH

Edward Lightbourn SmartBurn LLC, WI

W. Scott Matz Schneider Electric/Invensys, TX

John O’Rourke* General Electric/ALSTOM Power Inc., CT

Roy Reeves Emerson Automation Solutions, PA


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Alan Robertson Sargent & Lundy, LLC, IL

Jimmie Schexnayder Entergy Corporation, LA

Celso Schmidt Forney Corporation, TX

Bill Smith Exothermic Engineering, LLC, MO

Franklin Switzer* S-afe, Inc., NY

Peter Willse Global Asset Protection Services, LLC, CT

Henry Wong AECOM/URS Corporation E&C, NJ

Harold Yates Boiler Systems Consulting, LLC, MI

Donald Zissa SIS-TECH, TX

Joseph Bittinger American Electric Power Company, Inc., OH

James Franks Global Asset Protection Services, LLC, TN

Steven Graf Emerson Automation Solutions, PA

Roger Lesaca Mitsubishi Hitachi Power Systems Americas, Inc., NJ

Daniel May Burns & McDonnell Engineering Company, MO

Carlos Santos Schneider Electric/Invensys, TX

Karen Whitehead Black & Veatch Corporation, KS

Laura Moreno, Staff Liaison National Fire Protection Association, MA

Guests:

Marcus Cropp Southern Company Services, Inc.

Masaaki Kinoshita Mitsubishi Hitachi Power Systems

Gail Lance Babcock & Wilcox Company

Nando Nunziante Zeeco


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*Participated by teleconference

1. Call to Order. Michael Walz, Chair, called the meeting to order at 8:06 AM on February 7 and welcomed attendees to the meeting.

2. Introductions. Attendees introduced themselves and identified their affiliation.

3. Approval of Minutes. The minutes from March 16, 2016 were approved without revision.

4. Staff Updates. Laura Moreno provided an overview of the Fall 2018 revision cycle schedule and the NFPA process. (attached)

5. Review of Public Inputs: NFPA 85 Chapter 6. The Technical Committee reviewed Public Inputs and developed First Revisions and Committee Inputs as necessary.

A task group on interlock functional tests was formed to review testing requirements and frequency for functional tests (see First Revision 163 (section 6.6.5.2.1.1), First Revision 169 (6.7.5.2.1.1) and First Revision 174 (6.8.5.2.1.1)). The task group members are David King (Chair), Jimmie Schexnayder, James Franks, Franklin Switzer, and Marc Cropp.

The task group on Plasma Arc Igniters presented their work (attached) in conjunction with several of the Public Inputs. The group was asked to continue their work by developing annex material based on the public input language to provide guidance on how integrated burner-igniter systems should be used. The task group also intends to address the starting sequence and supervisory controls for this technology (see Committee Inputs 307, 309, and 310). There were additional volunteers for the group; for the complete list see Item 7.

6. Review of Fundamentals Technical Committee actions. The Technical Committee reviewed several items that were flagged by the Fundamentals Technical Committee for their review, and created Committee Inputs as necessary. Bill Smith and Skip Yates were tasked with reviewing igniter classification tests proposed by Committee Input 142, and John Eibl was tasked with reviewing Committee Input 322 and First Revision 155, which would remove overpressure protection requirements from 6.6.3.1.2 in favor of those added to Chapter 4.

7. Task Group Reports.

Design Pressures. B. Smith (chair), D. Evely, J. Frazier, D. King, J. Lehman, H. Wong, and A. Zadiraka. Dale Evely submitted several Public Inputs to change “test block” to “maximum head” throughout the document, but after discussion these were resolved without revision by the Multiple Burner Boiler committee. The task group was dissolved with the committee’s thanks.


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Plasma Arc Igniters. S. Yates (chair), B. Smith, K. Gamble, S. Matz, E. Lightbourn, M.

Kinoshita, J. Eibl, Denise Beach, Frank Bennett, and Carlos Santos. This task group will continue their work with a revised scope (see Item 5).

Valve Leak Testing. S. Matz, C. Schmidt, and F. Switzer. Based on committee discussion that the tightness test and the operational leak test of the header do not serve the same purpose and both sets of requirements need to be retained in the code, no changes were recommended. The task group was dissolved with the committee’s thanks.

Boiler Enclosure Definition/Purge Times. J. Franks (chair), D. King, J. O’Rourke, and J. Parker. Public Input was submitted and discussed but the Technical Committee ultimately did not make any revisions to purge time calculation methods. The task

group was dissolved with the committee’s thanks.

8. New Business. No additional new business was discussed.

9. Next Meeting. The Technical Committee agreed to hold the Second Draft meeting on January 23-24, 2018 in Phoenix, AZ or New Orleans, LA.

10. Adjournment. The meeting was adjourned at 3:25 PM on February 8.


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Attachment B: Technical Committee Roster


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Address List No PhoneMultiple Burner Boilers BCS-MBBBoiler Combustion System Hazards

Laura E. Moreno12/18/2017

BCS-MBBDaniel J. LeeABB Incorporated29801 Euclid AvenueWickliffe, OH 44092-1832

BCS-MBBMichael A. WalzChairBurns & McDonnell Engineering Company1306 State Route JFayette, MO 65248Alternate: Daniel R. May

SE 10/3/2002

BCS-MBBBarry J. BasilePrincipalBabcock Power, Inc.5 Neponset StreetWorcester, MA 01606-2714Alternate: Thomas J. Murphy

M 10/18/2011BCS-MBB

Denise BeachPrincipalFM Global1151 Boston-Providence TurnpikePO Box 9102Norwood, MA 02062-9102

I 08/17/2015

BCS-MBBFrank J. BennettPrincipalNRG Energy21200 Martinsburg RoadDickerson, MD 20842

U 7/16/2003BCS-MBB

David E. DexterPrincipalThe Dow Chemical CompanyPO Box 50Hahnville, LA 70057

U 10/29/2012

BCS-MBBJohn J. EiblPrincipalThe Chemours Company Inc.412 Fontaine DriveFranklin, TN 37064-0715

U 04/01/1994BCS-MBB

Dale P. EvelyPrincipalSouthern Company Services, Inc.42 Inverness Center Parkway(Bin B463)Birmingham, AL 35242-4809Alternate: Marcus Cropp

U 10/10/1998

BCS-MBBJoseph E. FehrPrincipalPower Engineers, Inc.16041 FosterPO Box 1000Overland Park, KS 66085

SE 03/03/2014BCS-MBB

Kenneth Joe FrazierPrincipalSalt River ProjectCoronado Generating StationPO Box 850, Mail Station NGS010Page, AZ 86040Alternate: Cyrus Allison

U 1/16/1998

BCS-MBBRichard KimballPrincipalHF Controls Corporation1624 West Crosby Road, Suite 124Carrollton, TX 75006Alternate: John A. Stevens

M 7/17/1998BCS-MBB

David W. KingPrincipalAmerican Electric Power Company, Inc.1 Riverside PlazaColumbus, OH 43215Alternate: Joseph E. Bittinger, Jr.

U း 10/28/2008

BCS-MBBMasaaki KinoshitaPrincipalMitsubishi Hitachi Power Systems, LTD.1-1 Akunoura MachiNagasaki, 850-91 Japan

M 12/06/2017BCS-MBB

Daniel J. LeePrincipalABB Incorporated29801 Euclid AvenueWickliffe, OH 44092-1832Alternate: Ronald J. Fleming

M 10/10/1990

1NFPA 85 (BCS-MBB) Second Draft Technical Committee Meeting January 24, 2018 - New Orleans, LA

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BCS-MBBEdward LightbournPrincipalSmartBurn LLC579 D'Onofrio DriveMadison, WI 53711

M 08/03/2016BCS-MBB

John P. O'RourkePrincipalGeneral Electric175 Addison RoadWindsor, CT 06095-0500

M 1/1/1990

BCS-MBBRoy ReevesPrincipalEmerson Automation Solutions200 Beta DrivePittsburgh, PA 15238-2918Alternate: Steven V. Graf

M 08/11/2014BCS-MBB

Carlos Santos, Jr.PrincipalSchneider Electric10900 Equity DriveHouston, TX 77041

M 10/27/2009

BCS-MBBJimmie J. SchexnayderPrincipalEntergy Corporation1213 West 4th StreetKaplan, LA 70548Alternate: Ronald Rispoli

U 10/27/2005BCS-MBB

Bill L. Smith, Jr.PrincipalExothermic Engineering, a Div. of EAPC20424 Missouri City RoadLiberty, MO 64068Alternate: Jack T. Lehman

SE 3/1/2011

BCS-MBBFranklin R. Switzer, Jr.PrincipalS-afe, Inc.85 Denison Parkway E #201Corning, NY 14830-2726

SE 7/16/2003BCS-MBB

James P. WalawenderPrincipalBlack & Veatch Corporation11401 Lamar AvenueOverland Park, KS 66211-1508Alternate: Karen Whitehead

SE 03/03/2014

BCS-MBBPeter J. WillsePrincipalGlobal Asset Protection Services, LLC100 Constitution Plaza, 12th FloorHartford, CT 06103Alternate: James E. Franks

I 1/1/1989BCS-MBB

Henry K. WongPrincipalAECOM/URS Corporation E&C510 Carnegie CenterPrinceton, NJ 08543

SE 1/1/1990

BCS-MBBHarold R. YatesPrincipalBoiler Systems Consulting, LLC1165 Maple Leaf DriveRochester Hills, MI 48309-3716

SE 10/1/1996BCS-MBB

Donald ZissaPrincipalSIS-TECH12621 Featherwood, Suite 120Houston, TX 77034-4905Alternate: Alberto Dib

SE 08/17/2015

BCS-MBBGail J. LanceVoting AlternateBabcock & Wilcox Company20 South Van BurenBarberton, OH 44203

M 04/04/2017BCS-MBB

Marc LemmonsVoting AlternateSargent And Lundy55 East Monroe StreetChicago, IL 60603

SE 04/04/2017


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BCS-MBBRoger LesacaVoting AlternateMitsubishi Hitachi Power Systems Americas, Inc.645 Martinsville RoadBasking Ridge, NJ 07920

M 10/29/2012BCS-MBB

Cyrus AllisonAlternateSalt River Project1521 N Project DrTempe, AZ 52025Principal: Kenneth Joe Frazier

U 04/05/2016

BCS-MBBJoseph E. Bittinger, Jr.AlternateAmerican Electric Power Company, Inc.1 Riverside PlazaColumbus, OH 43147Principal: David W. King

U 08/09/2012BCS-MBB

Marcus CroppAlternateSouthern Company42 Inverness Center ParkwayBin B463Birmingham, AL 35242Principal: Dale P. Evely

U 04/04/2017

BCS-MBBAlberto DibAlternateSIS-TECH Solutions12621 Featherwood Drive, Suite 120Houston, TX 77034Principal: Donald Zissa


Ronald J. FlemingAlternateABB Incorporated29801 Euclid AvenueWickliffe, OH 44092Principal: Daniel J. Lee

M 10/10/1998

BCS-MBBJames E. FranksAlternateGlobal Asset Protection Services, LLC855 Dogwood RoadSomerville, TN 38068Principal: Peter J. Willse

I 8/2/2010BCS-MBB

Steven V. GrafAlternateEmerson Automation SolutionsPower & Water Solutions200 Beta DrivePittsburgh, PA 15238-2918Principal: Roy Reeves

M 08/11/2014

BCS-MBBJack T. LehmanAlternateExothermic Engineering, a Div. of EAPC Industrial Services28809 100th AvenueColumbus, NE 68601Principal: Bill L. Smith, Jr.


Daniel R. MayAlternateBurns & McDonnell Engineering Company9400 Ward Parkway PO Box 419173Kansas City, MO 64141-6173Principal: Michael A. Walz

SE 10/27/2009

BCS-MBBThomas J. MurphyAlternateBabcock Power, Inc.5 Neponset StreetWorcester, MA 01615-0040Principal: Barry J. Basile

M 07/29/2013BCS-MBB

Ronald RispoliAlternateEntergy Corporation2414 West 5th StreetRussellville, AR 72801-5541Principal: Jimmie J. Schexnayder

U 10/27/2005


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BCS-MBBJohn A. StevensAlternateHF Controls Corporation1624 West Crosby Road, #124Carrollton, TX 75006Principal: Richard Kimball

M 07/28/2006BCS-MBB

Karen WhiteheadAlternateBlack & Veatch Corporation11401 Lamar AvenueOverland Park, KS 66211Principal: James P. Walawender

SE 08/03/2016

BCS-MBBLaura E. MorenoStaff LiaisonNational Fire Protection Association1 Batterymarch ParkQuincy, MA 02169-7471

1/6/2015


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Attachment C: F2018 Revision Cycle Schedule


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12/18/2017 NFPA

http://www.nfpa.org/codes-and-standards/all-codes-and-standards/list-of-codes-and-standards/popup-page?mode=schedule&rc=Fall%202018 1/1

Fall 2018 Revision Cycle

Process Stage Process Step Dates for TCDates for TC

with CC

Public InputStage (First Draft)

Public Input Closing Date* 1/05/2017 1/05/2017

Final Date for TC First Draft Meeting 6/15/2017 3/16/2017

Posting of First Draft and TC Ballot 8/03/2017 4/27/2017

Final date for Receipt of TC First Draft ballot 8/24/2017 5/18/2017

Final date for Receipt of TC First Draft ballot ‐ recirc 8/31/2017 5/25/2017

Posting of First Draft for CC Meeting 6/01/2017

Final date for CC First Draft Meeting 7/13/2017

Posting of First Draft and CC Ballot 8/03/2017

Final date for Receipt of CC First Draft ballot 8/24/2017

Final date for Receipt of CC First Draft ballot ‐ recirc 8/31/2017

Post First Draft Report for Public Comment 9/07/2017 9/07/2017

Comment Stage(Second Draft)

Public Comment Closing Date* 11/16/2017 11/16/2017

Notice Published on Consent Standards (Standards that received no Comments) Note: Date varies and determined via TC ballot.

Appeal Closing Date for Consent Standards (Standards that received no Comments)

Final date for TC Second Draft Meeting 5/17/2018 2/08/2018

Posting of Second Draft and TC Ballot 6/28/2018 3/22/2018

Final date for Receipt of TC Second Draft ballot 7/19/2018 4/12/2018

Final date for receipt of TC Second Draft ballot ‐ recirc 7/26/2018 4/19/2018

Posting of Second Draft for CC Meeting 4/26/2018

Final date for CC Second Draft Meeting 6/07/2018

Posting of Second Draft for CC Ballot 6/28/2018

Final date for Receipt of CC Second Draft ballot 7/19/2018

Final date for Receipt of CC Second Draft ballot ‐ recirc 7/26/2018

Post Second Draft Report for NITMAM Review 8/02/2018 8/02/2018

Tech SessionPreparation (&

Issuance)

Notice of Intent to Make a Motion (NITMAM) Closing Date 8/30/2018 8/30/2018

Posting of Certified Amending Motions (CAMs) and Consent Standards 10/11/2018 10/11/2018

Appeal Closing Date for Consent Standards 10/26/2018 10/26/2018

SC Issuance Date for Consent Standards 11/05/2018 11/05/2018

Tech Session Association Meeting for Standards with CAMs 6/20/2019 6/20/2019

Appeals andIssuance

Appeal Closing Date for Standards with CAMs 7/10/2019 7/10/2019

SC Issuance Date for Standards with CAMs 8/07/2019 8/07/2019

TC = Technical Committee or Panel CC = Correlating Committee

As of 1/27/2017

More NFPA.org


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http://www.nfpa.org/

Attachment D: Review of Fundamentals Technical Committee actions


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Second Revision No. 711-NFPA 85-2017 [ Chapter 2 ]

Chapter 2 Referenced Publications

2.1 General.

The documents or portions thereof listed in this chapter are referenced within this code and shall beconsidered part of the requirements of this document.

2.2 NFPA Publications.

National Fire Protection Association, 1 Batterymarch Park, Quincy, MA 02169-7471.

NFPA 30, Flammable and Combustible Liquids Code, 2018 edition.

NFPA 31, Standard for the Installation of Oil-Burning Equipment, 2016 edition.

NFPA 54, National Fuel Gas Code, 2018 edition.

NFPA 56 Standard for Fire and Explosion Prevention During Cleaning and Purging of Flammable GasPiping Systems,2017 edition.

NFPA 68 Standard on Explosion Protection by Deflagration Venting,2018 edition.

NFPA 69, Standard on Explosion Prevention Systems, 2019 edition.

NFPA 70®, National Electrical Code®, 2017 edition.

2.3 Other Publications.

2.3.1 ASCE Publications.

American Society of Civil Engineers, 1801 Alexander Bell Drive, Reston, VA 20191-4400.

ASCE 7, Minimum Design Loads for Buildings and Other Structures, 2010 2016 .

2.3.2 ASME Publications.

American Society of Mechanical Engineers, Two Park Avenue, New York, NY 10016-5990.

ASME B31.1, Power Piping, 2012 2016 .

ASME B31.3, Process Piping, 2012 2016 .

2.3.3 ASTM Publications.

ASTM International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428-2959.

ASTM D388, Standard Classification of Coals by Rank, 2012 2017 .

ASTM D396, Standard Specification for Fuel Oils, 2012 2017 .

ASTM D409, Standard Test Method for Grindability of Coal by the Hardgrove-Machine Method, 2012 2016 .

ASTM D1655, Standard Specification for Aviation Turbine Fuels, 2012 2017 .

ASTM D2880, Standard Specification for Gas Turbine Fuel Oils, 2003, reaffirmed 2010 2015 .

2.3.4 CGA Publications.

Compressed Gas Association, 14501 George Carter Way, Suite 103, Chantilly, VA 20151-2923.

ANSI/ CGA G-2.1/ANSI K61.1 , Safety Requirements for the Storage and Handling of AnhydrousAmmonia, 1999 2014.

2.3.5 FCI Publications.

Fluid Controls Institute, 1300 Sumner Avenue, Cleveland, OH 44115.

ANSI/FCI 70-2, Control Valve Seat Leakage, 2006 2013 .

National Fire Protection Association Report http://submittals.nfpa.org/TerraViewWeb/ContentFetcher?commentPara...

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2.3.6 IEC Publications.

International Electrotechnical Commission, 3, rue de Varembé, P.O. Box 131, CH-1211, Geneva 20,Switzerland.

IEC 61508, Functional Safety of Electrical/Electronic Programmable Electronic Safety-Related Systems,2010.

2.3.7 Military Specifications.

Department of Defense Single Stock Point, Document Automation and Production Service, Building 4/D,700 Robbins Avenue, Philadelphia, PA 19111-5094.

MIL-T-5624, Turbine Fuel, Aviation, Grade JP4, JP5, and JP5/JP8 ST, 1995.

2.3.8 U.S. Government Publications.

U.S. Government Publishing Office, 732 North Capitol Street, NW, Washington, DC 20401-0001

Title 29, Code of Federal Regulations, Part 1926.32, “General Safety and Health Provisions.”

2.3.9 Other Publications.

Merriam-Webster’s Collegiate Dictionary, 11th edition, Merriam-Webster, Inc., Springfield, MA, 2003.

2.4 References for Extracts in Mandatory Sections.

NFPA 13D, Standard for the Installation of Sprinkler Systems in One- and Two-Family Dwellings andManufactured Homes, 2019 edition.

NFPA 40, Standard for the Storage and Handling of Cellulose Nitrate Film, 2019 edition.

NFPA 58, Liquefied Petroleum Gas Code, 2017 edition.

NFPA 72®, National Fire Alarm and Signaling Code, 2019 edition.

NFPA 850, Recommended Practice for Fire Protection for Electric Generating Plants and High VoltageDirect Current Converter Stations, 2015 edition.

Submitter Information Verification

Submitter Full Name: Laura Moreno

Organization: National Fire Protection Assoc

Street Address:

City:

State:

Zip:

Submittal Date: Thu Nov 30 11:53:08 EST 2017

Committee Statement

Committee Statement: Updating references to most recent editions.

Response Message:


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Second Revision No. 701-NFPA 85-2017 [ New Section after 3.3.33 ]

3.3.X Combustion Turbine Normal Shutdown.

The normal sequence of events that automatically provides successful shutdown of the combustion turbinewith no abnormal conditions in the combustion system.




Street Address:

City:

State:

Zip:

Submittal Date: Wed Nov 29 10:44:48 EST 2017

Committee Statement

CommitteeStatement:

The term is used throughout Chapter 8 and in other definitions in Chapter 3, and needs tobe defined.

Response Message:

Public Comment No. 21-NFPA 85-2017 [Section No. 3.3.19]


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Deflagration. Propagation of a combustion zone at a velocity that is less than the speed of sound in theunreacted medium. [68, 2018]




Street Address:

City:

State:

Zip:


Committee Statement

Committee Statement: A definition for deflagration is being added based on the use of the term in Chapter 9.

Response Message:

Public Comment No. 33-NFPA 85-2017 [New Section after 3.3.41]


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Second Revision No. 703-NFPA 85-2017 [ Section No. 3.3.49 ]

3.3.49 Explosion Vent.

A vent to relieve explosion deflagration pressures resulting from ignition of a mixture of decompositiongases and air. [ 40, 2019]




Street Address:

City:

State:

Zip:


Committee Statement

CommitteeStatement:

"Explosion pressures" has been changed to "deflagration pressures" to correlate with the firstdraft changes to Chapter 9 and the new definition for deflagration.

ResponseMessage:



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Second Revision No. 709-NFPA 85-2017 [ Section No. 3.3.72.2 ]

3.3.72.2* Class 2 Igniter.

An igniter that is applied to ignite the fuel input through the burner under prescribed light-off conditions. It isalso used to support ignition under low load or certain adverse operating conditions stabilize the mainburner flame .

A.3.3.72.2 Class 2 Igniter.

The heat input of a Class 2 igniter is generally 4 percent to 10 percent of maximum burner heat input.




Street Address:

City:

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Zip:


Committee Statement

Committee Statement: This revision is made to be consistent with the revision on 4.7.7.6.

Response Message:


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4.3.3 The owner shall specify the lowest autoignition temperature (AIT) for all fuels fired in the boiler and/orcombustion turbine over the range of the expected operating conditions taking into consideration fuelcomposition, temperature, pressure and oxygen concentration.




Street Address:

City:

State:

Zip:


Committee Statement

CommitteeStatement:

Autoignition temperature is required information in order to design and operate a boiler and/orits combustion system and should be specified in the contract documents or equivalent.

ResponseMessage:




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Second Revision No. 706-NFPA 85-2017 [ Section No. 4.5.5 ]

4.5.5

Interlocks shall be permitted to be temporarily removed from service in accordance with the following:

(1) Removal of the interlock shall be authorized by a competent person and , documented in accordancewith operating procedures, and communicated to operations personnel .

(2) Alternate means shall be substituted to supervise the interlock in accordance with operatingprocedures.




Street Address:

City:

State:

Zip:


Committee Statement

CommitteeStatement:

Language was added to clarify that notification of operating personnel is required wheneveran interlock is bypassed.

ResponseMessage:



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Second Revision No. 710-NFPA 85-2017 [ Sections 4.7.7.4, 4.7.7.5, 4.7.7.6, 4.7.7.7 ]

Sections 4.7.7.4, 4.7.7.5, 4.7.7.6, 4.7.7.7

4.7.7.4

Class 2 igniters shall not be used to ignite the main fuel under uncontrolled or abnormal conditions.

4.7.7.5

Where Class 3 igniters are used, the igniter shall be turned off as a part of the burner light-off procedurewhen the time trial for ignition of the main burner has expired, to ensure that the main flame is notdependent on ignition support from the igniter.

4.7.7.6 *

Class 2 igniters shall not be used to extend the turndown range but shall be permitted to be used tosupport ignition under low-load or adverse operating conditions stabilize the main burner flame.

A.4.7.7.6 There are situations when a class 2 igniter can be returned to service to stabilize the main burnerflame, such as minor excursions from normal operating conditions. Temporary minor excursions include theintroduction of a slug of off-spec fuel, such as wet coal or noncombustibles. However, a class 2 ignitershould not be returned to service to avoid a load-based trip of a burner or mill, or if adding additional fuelcould lead to an unsafe operating condition .

4.7.7.7

Class 3 igniters shall not be used to support ignition stabilize the main burner flame or to extend the burnerturndown range.




Street Address:

City:

State:

Zip:


Committee Statement

CommitteeStatement:

The text is updated to more accurately describe the purpose of bringing a class 2 igniter back intoservice under load. The annex text is intended to provide guidance on the appropriate use of class2 igniters to stabilize the main burner flame. Text on class 3 igniters is updated to be consistentwith the previous revision.

ResponseMessage:


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Second Revision No. 707-NFPA 85-2017 [ Section No. 4.10.1 [Excluding any Sub-

Sections] ]

Fuel gas piping shall be minimum schedule 40, and material and system design shall be in accordance withNFPA 54 (for fuel gas piping inside industrial and institutional buildings), ASME B31.1, Power Piping (forfuel gas piping in power applications), or ASME B31.3, Process Piping (for fuel gas piping in processapplications).




Street Address:

City:

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Committee Statement

CommitteeStatement:

The 2018 edition of NFPA 54 will permit schedule 10 piping. This revision is enforcing thecurrent NFPA 85 requirement of minimum schedule 40 which was based on earlier editions ofNFPA 54.

ResponseMessage:

Public Comment No. 9-NFPA 85-2017 [Section No. 4.10.1 [Excluding any Sub-Sections]]


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Second Revision No. 708-NFPA 85-2017 [ Section No. 4.10.1.2 ]

4.10.1.2 Overpressure Protection.

4.10.1.2.1

Overpressure protection shall be provided in either of the following cases:

(1) When the supply pressure exceeds the design pressure rating of any downstream component

(2) When the failure of a single upstream line regulator or service pressure regulator results in a supplypressure exceeding the design pressure rating of any downstream component

4.10.1.2.2

Overpressure protection shall be provided by any one of the following:

(1) A series regulator in combination with a line regulator or service pressure regulator

(2) A monitoring regulator installed in combination with a line regulator or service pressure regulator

(3)

(4) An overpressure cutoff device, such as a slam-shut valve or a high-pressure switch in combination withan adequately rated shutoff valve

4.10.1.2.3

When a relief valve is used to comply with 4.10.1.2.1, the relief valve shall be a full-capacity relief type.

4.10.1.2.4

Token relief valves and internal token relief valves shall not be permitted to be used as the onlyoverpressure protection devices.

4.10.1.2.5* Set Point of the Overpressure Protection Device.

The overpressure protection device shall be set to provide a maximum downstream pressure as follows:

When the rated pressure of any component is less than 83 kPa (12 psig), the set point of the overpressureprotection device shall not exceed 150 percent of the rated pressure of the lowest rated component.

When the rated pressure of any component is equal to or greater than 83 kPa (12 psig) but less than 414kPa (60 psig), the set point of the overpressure protection device shall not exceed 41 kPa (6 psig) abovethe rated pressure of the lowest rated component.

When the rated pressure of any component is equal to or greater than 414 kPa (60 psig), the set point ofthe overpressure protection device shall not exceed 110 percent of the rated

(s) shall be set not higher than the design pressure of the lowest rated downstream component.

* A full-capacity pressure relief valve

A.4.10.1.2.2(3)

Upon upstream pressure regulation failure, a full-capacity pressure relief valve (versus token reliefvalves) will limit the downstream pressure. Token relief valves only provide minimum pressure reliefin cases where ambient temperatures increase the pressure inside the gas piping, which can occurduring shutdown periods, or relieve small increases of pressure due to high lockup pressures thatoccur during a shutdown.


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A.4.10.1.2.5

The pressure limits in this section are consistent with 49 CFR 192.201, “Required Capacity of PressureRelieving and Limiting Stations.” An example of design pressure for a safety shutoff valve would be theopen and close rating.




Street Address:

City:

State:

Zip:


Committee Statement

CommitteeStatement:

The design pressure is that at which components will continue to operate safely and properly, andwithout damage, and the intent is that the overpressure protection setpoint is lower than thedesign pressure of all downstream components.

ResponseMessage:

Public Comment No. 8-NFPA 85-2017 [Section No. 4.10.1.2]


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Second Revision No. 704-NFPA 85-2017 [ Section No. A.3.3.75 ]

A.3.3.75 Interlock.

An interlock can consist of a sensing function, a control function, and an output or a final control element.The interlock can be accomplished with the use of any combination of electrical devices, mechanicaldevices, or logic. An action by an operator is not considered to be an interlock.




Street Address:

City:

State:

Zip:


Committee Statement

Committee Statement: It was not previously clear that an operator action is not considered to be an interlock.

Response Message:

Public Comment No. 7-NFPA 85-2017 [Section No. 3.3.75 [Excluding any Sub-Sections]]


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Second Revision No. 712-NFPA 85-2017 [ Chapter K ]

Annex K Informational References

K.1 Referenced Publications.

The documents or portions thereof listed in this annex are referenced within the informational sections ofthis code and are not part of the requirements of this document unless also listed in Chapter 2 for otherreasons.

K.1.1 NFPA Publications.

National Fire Protection Association, 1 Batterymarch Park, Quincy, MA 02169-7471.

NFPA 30, Flammable and Combustible Liquids Code, 2018 edition.

NFPA 31, Standard for the Installation of Oil-Burning Equipment, 2016 edition.

NFPA 51, Standard for the Design and Installation of Oxygen–Fuel Gas Systems for Welding, Cutting, andAllied Processes, 2018 edition.

NFPA 51B, Standard for Fire Prevention During Welding, Cutting, and Other Hot Work, 2019 edition.

NFPA 54, National Fuel Gas Code, 2018 edition.

NFPA 56, Standard for Fire and Explosion Prevention During Cleaning and Purging of Flammable GasPiping Systems, 2017 edition.

NFPA 58, Liquefied Petroleum Gas Code, 2017 edition.

NFPA 68, Standard on Explosion Protection by Deflagration Venting, 2018 edition.


NFPA 70®, National Electrical Code®, 2017 edition.

NFPA 77, Recommended Practice on Static Electricity, 2019 edition.

NFPA 85, Boiler and Combustion Systems Hazards Code, 2007 edition.

NFPA 85, Boiler and Combustion Systems Hazards Code, 2011 edition.

NFPA 241, Standard for Safeguarding Construction, Alteration, and Demolition Operations, 2018 edition.

NFPA 497, Recommended Practice for the Classification of Flammable Liquids, Gases, or Vapors and ofHazardous (Classified) Locations for Electrical Installations in Chemical Process Areas, 2017 edition.

NFPA 499, Recommended Practice for the Classification of Combustible Dusts and of Hazardous(Classified) Locations for Electrical Installations in Chemical Process Areas, 2017 edition.

NFPA 850, Recommended Practice for Fire Protection for Electric Generating Plants and High VoltageDirect Current Converter Stations, 2015 edition.

K.1.2 Other Publications.

K.1.2.1 ABMA Publications.

American Boiler Manufacturers Association, 8221 Old Courthouse Road, Suite 202, Vienna, VA22182–3839.

ABMA 203, A Guide to Clean and Efficient Operation of Coal-Stoker-Fired Boilers, 2002.

ABMA 307, Combustion Control Guidelines for Single Burner Firetube and WatertubeIndustrial/Commercial/Institutional Boilers, 1999.

K.1.2.2 AlChE Publications.

American Institute of Chemical Engineers, 120 Wall Street, FL 23, New York, NY 10005-4020.

Guidelines for Hazard Evaluation Procedures, 2008.


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K.1.2.3 API Publications.

American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005-4070.

API 620, Standard for Design and Construction of Large, Welded, Low-Pressure Storage Tanks,2009 2013 .

API 650, Standard for Welded Steel Tanks for Oil Storage, 2008 2013 .

API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at PetroleumFacilities Classified as Class I, Division 1 and Division 2, 1998 (reaffirmed 2002).

API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at PetroleumFacilities Classified as Class I, Zone 0, Zone 1, and Zone 2, 1997 (reaffirmed 2002 2013 ).

API RP 2003, Recommended Practice for Protection Against Ignitions Arising Out of Static, Lightning, andStray Currents, 2008 2015 .

K.1.2.4 ASME Publications.

American Society of Mechanical Engineers, Two Park Avenue, New York, NY 10016-5990.

ASME Boiler and Pressure Vessel Code, 2007 2017 .

K.1.2.5 ASTM Publications.

ASTM International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 19428-2959.

ASTM D396, Standard Specification for Fuel Oils, 2009 2017 .

ASTM D409, Standard Test Method for Grindability of Coal by the Hardgrove-Machine Method, 2012 2016 .

ASTM E1226, Standard Test Method for Explosibility of Dust Clouds, 2010 2012 .

K.1.2.6 EEMUA Publications.

The Engineering Equipment and Material Users Association, 63 Mark Lane, London UK EC3R 7NQ.

EEMUA 191, Alarm Systems — A Guide to Design, Management, and Procurement, 2007 2013 .

K.1.2.7 IEC Publications.

International Electrotechnical Commission, 3, rue de Varembé, P.O. Box 131, CH-1211 Geneva 20,Switzerland.

IEC 61511, Functional Safety — Safety Instrumented Systems for the Process Industry Sector, 20032016 .

K.1.2.8 ISA Publications.

International Society of Automation, 67 T. W. Alexander Drive, PO Box 12277, Research Triangle Park, NC27709.

ANSI/ISA 18.2, Management of Alarm Systems for the Process Industries, 2009 2016 .

ANSI/ISA 77.41.01, Fossil Fuel Power Plant Boiler Combustion Controls, 2005 2015 .

ANSI/ISA 77.42.01, Fossil Fuel Power Plant Feedwater Control System — Drum Type, 1999(R2006 R2011 ).

ANSI/ISA 77.43.01, Fossil Fuel Power Plant Unit/Plant Demand Development — Drum Type, 2002(R2008) 2014 .

ANSI/ISA 77.44.01, Fossil Fuel Power Plant — Steam Temperature Controls, 2007 (R2013) .

ANSI/ISA 84.00.01, Application of Safety Instrumented Systems for the Process Industry, 2004.

ISA TR18.2.4, Enhanced and Advanced Alarm Methods, 2012

ISA TR18.2.5, Alarm System Monitoring, Assessment, and Auditing, 2012.

K.1.2.9 Government Publications.

U.S. Government Publishing Office, 732 North Capitol Street, NW, Washington, DC 20401-0001.

Title 49, Code of Federal Regulations, Part 192.201, "Required Capacity of Pressure Relieving and LimitingStations."


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K.1.2.10 Other Publications.

Noronha, J. A., J. T. Merry, and W. C. Reid. "Deflagration Pressure Containment (DPC) for Vessel SafetyDesign." Plant/Operations Progress 1, no. 1 (January 1982): 1–6.

K.2 Informational References.

The following documents or portions thereof are listed here as informational resources only. They are not apart of the requirements of this document.

K.2.1 Additional HRSG References.

The following documents provide additional information on iron fires.

Johnson, A. A., J. A. Von Franuhofer, and E. W. Jannett, “Combustion of Finned Steel Tubing During StressRelief Heat Treatment,” Journal of Heat Treating, Vol. 4, No. 3, June 1986, pp. 265–271.

McDonald, C. F., “The Potential Danger of Fire in Gas Turbine Heat Exchangers,” ASME 69-GT-38.

Theoclitus, G., “Heat Exchanger Fires and the Ignition of Solid Metals,” Journal of Engineering for GasTurbines and Power, Vol. 107, July 1985, pp. 607–612.

K.3 References for Extracts in Informational Sections.

NFPA 58, Liquefied Petroleum Gas Code , 2017 edition.





Street Address:

City:

State:

Zip:


Committee Statement

Committee Statement: Updating references to most recent editions.

Response Message:


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Attachment E: NFPA 85 (BCS-MBB) Public Comment Report


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12/18/2017 National Fire Protection Association Report

http://submittals.nfpa.org/TerraViewWeb/ViewerPage.jsp?id=85-2015.ditamap&toc=false&draft=true 4/54

Public Comment No. 30-NFPA 85-2017 [ Global Input ]

The MBB Committee should review the substantiation and reconsider the revision toaddress the ballot comments received on this First Revision.

Additional Proposed Changes

File Name Description ApprovedCCN_23.pdf 85 CC Note 23

Statement of Problem and Substantiation for Public Comment

This Public Comment appeared as Correlating Committee Note 23 in the First Draft Report.

Related Item85 CC Note 23


Submitter FullName: CC ON BCS-AAC

Organization: NFPA

Affilliation: Correlating Committee on Boiler Combustion SystemsHazards

Street Address:City:State:Zip:Submittal Date: Wed Nov 08 14:26:24 EST 2017


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Correlating Committee Note No. 23-NFPA 85-2017 [ Detail ]


Submitter Full Name: Laura MorenoOrganization: National Fire Protection AssocStreet Address:City:State:Zip:Submittal Date: Thu Jun 22 09:39:51 EDT 2017

Committee Statement and Meeting Notes

CommitteeStatement:

The MBB Committee should review the substantiation and reconsider the revision to address theballot comments received on this First Revision.

Ballot Results

This item has passed ballot

20 Eligible Voters3 Not Returned

17 Affirmative All0 Affirmative with Comments0 Negative with Comments0 Abstention

Not Returned

Basile, Barry J.

Dexter, David E.

Schexnayder, Jimmie J.

Affirmative All

Buckingham, Fred P.

Cannon, David Paul

Chappell, Timothy

Evely, Dale P.

Fleming, Ronald J.

Franks, James E.

King, David W.

Kinoshita, Masaaki

Lance, Gail J.

Mason, Dennis P.

National Fire Protection Association Report http://submittals.nfpa.org/TerraViewWeb/FormLaunch?id=/TerraView/C...

1 of 2 11/8/2017, 9:56 AM


Page 34 of 81

May, Daniel R.

Schmidt, Celso G.

Steen, Lloyd E.

Voss, Justin D.

Wolff, Marc A.

Wong, Henry K.

Yates, Harold R.


2 of 2 11/8/2017, 9:56 AM


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Public Comment No. 22-NFPA 85-2017 [ New Section after 6.4.1 ]

The MBB Committee should review the title of 6.4.1.2.9 to clarify the intent, as it seemsinterlocks refers to the direct fired furnace, not the individual pulverizer subsystem.


File Name Description ApprovedCCN_24.pdf 85 CC Note 24


This Public Comment appeared as Correlating Committee Note 24.

Related Item85 CC Note 24


Submitter FullName: CC ON BCS-AAC

Organization: NFPA

Affilliation: Correlating Committee on Boiler Combustion SystemsHazards

Street Address:City:State:Zip:Submittal Date: Wed Nov 08 13:40:36 EST 2017


Page 36 of 81

Correlating Committee Note No. 24-NFPA 85-2017 [ Section No. 6.4.1 ]




CommitteeStatement:

The MBB Committee should review the title of 6.4.1.2.9 to clarify the intent, as it seems interlocksrefers to the direct fired furnace, not the individual pulverizer subsystem.

Ballot Results




Not Returned

Basile, Barry J.

Dexter, David E.


Affirmative All

Buckingham, Fred P.

Cannon, David Paul

Chappell, Timothy

Evely, Dale P.

Fleming, Ronald J.

Franks, James E.

King, David W.

Kinoshita, Masaaki

Lance, Gail J.

Mason, Dennis P.


1 of 2 11/8/2017, 9:58 AM


Page 37 of 81

May, Daniel R.

Schmidt, Celso G.

Steen, Lloyd E.

Voss, Justin D.

Wolff, Marc A.

Yates, Harold R.

Affirmative with Comment

Wong, Henry K.

Correlating committee intent is correct but committee statement is not correct. Paragraphs 6.4.1.2.9.1 through6.4.1.2.9.3 clearly refer to Pulverizer Subsystem Trips not furnace trips. Should it be moved to Chapter 9?


2 of 2 11/8/2017, 9:58 AM


Page 38 of 81



Public Comment No. 38-NFPA 85-2017 [ Section No. 6.4.1.2.7.6 ]

6.4.1.2.7.6* Before main fuel firing and following a master fuel trip, FD fans shall be tripped if the furnacepressure exceeds the maximum pressure value recommended by the manufacturer.

Exception: For units where the maximum head of the FD fans is less than the continous designpressure of the boiler enclosure, b efore main fuel firing and following a five minuteperiod following a master fuel trip (furnace postpurge) , FD fans shall be tripped if the furnacepressure exceeds the maximum pressure value recommended by the manufacturer.


Revisions made in the First draft were completed without reference to any actual operational experience or events that would dictate a need to revise the code. The text deleted from the paragraph has been a part of the NFPA 85 document since the development of the NFPA 85G standard published in 1978. Removal of the text from the code does not address the basic desire of completing a post trip purge prior to shutting down FD fans. For balanced draft units and in cases where the FD fan(s) are tripped due to a high furnace pressure condition, the ID fan will remain in controlled operation but airflow through the boiler and associated air and flue gas duct work will be significantly reduced.

Related ItemFirst Draft Report revision to paragraph 6.4.1.2.7.6


Submitter Full Name: John ORourkeOrganization: General ElectricStreet Address:City:State:Zip:Submittal Date: Tue Nov 14 17:05:56 EST 2017


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Public Comment No. 36-NFPA 85-2017 [ New Section after K.3 ]

X.1 Concentrated Flame Igniters General Considerations and DefinitionsX1.1 New igniter technologies, to be referred to as “Concentrated Flame (CF) Igniters”, havebeen developed which can reduce, or even eliminate, the consumption of igniter Fuel Oil or FuelGas used in coal fired boiler warm up, mill group ignition, and low load support. A burner with anintegral ignitor assembly specifically designed and fabricated for the initial combustion to takeplace within the burner barrel as opposed to outside the burner in the furnace cavity, as is donefor traditional igniters, is an example of this new technology. For CF igniters, with the igniter inservice, combustion may extend into the furnace cavity, however the initial point of combustion isdesigned to be inside the burner.These systems can be beneficial for at least the following reasons 1) the initial combustion iscontrolled within the burner barrel, where there is a high level of contact between the ignitionsource and the Primary Air stream, and 2) in the case of the plasma based form, the very highboundary temperature (much higher than adiabatic flame temperature of coal, oil or gas)promotes fracturing and devolatilization of the coal particles, leading to prompt ignition.CF igniters may take multiple forms based on the heat energy source by which the coal streamis ignited. The most common form of CF igniters uses an ionic plasma gas to ignite the coal andprimary air mixture. However, other designs may use Fuel Oil, and less commonly Fuel Gas forthe initial ignition. Generally, but not universally, only a subset of the Primary Air/Fuel stream isinitially ignited. Some designs utilize successive concentric annular combustion zones inside theburner barrel to stage the mixing of the Primary Air/Fuel stream to control the ignition of theremaining portions of the Primary Air/Fuel stream. When the igniter is no longer required to be inservice, the igniter is de-energized, and the ignition point quickly propagates to the front of thebarrel tip as in traditional burner operation.CF igniters have been deployed on both wall and tangentially fired furnaces on a wide variety ofcoal ranks. The plasma form of CF igniters is designed to require no support fuel consumption. The Fuel Oiland Fuel Gas forms claim reduced consumption of the igniter fuel compared to a conventionalClass 1 igniter. For both forms with a boiler in a cold state separate equipment and energy source to heat theprimary air to the required temperatures are required as energy cannot be recovered from thecold flue gas.X1.2 Side Sectional Views of Common Forms of Concentrated Flame Igniters

Figure AX.X.X: Axial ConfigurationFigure A.X.X Tangential Configuration

X1.3 Plasma Definition . Plasma is a gaseous mixture of negatively charged electrons andhighly charged positive ions which can conduct large and sustained electric current andgenerates very high temperatures. In common forms of plasma igniters, the plasma isgenerated when a strong electric potential is applied between anode and cathode elements. Plasmas respond to electromagnetic forces and the plasma gas may be controlled usingmagnetic induction coils.X.2 Technology OverviewThe CF igniter is designed to be an integral part of the burner barrel, while a conventional igniterin some furnace designs may be physically independent of the burner. Because of its integraldesign feature, a CF igniter would not properly function in a different burner barrel, and aconventional igniter would not properly function in a burner barrel designed for a CF igniter. Thetechnology can be compared with conventional coal burner igniters as follows.For a conventional igniter:


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· The coal (Primary Air) stream is not ignited until it flows just outside the burner tip andcombustion occurs in the open furnace cavity· Coal devolatilization and pyrolysis occur relatively slowly as coal particles heat up andthen ignite· The maximum flame temperature (adiabatic, equivalence ratio ideal) 2,100 ° C (oil) &1,960 ° C (natural gas) For CF igniters:· A portion of the coal is ignited at the inlet of the burner barrel when the igniter is in service.The initial ignition propagates through successive stages inside the burner barrel. · When the igniter is turned off, the flame then moves to outside the burner tip· In plasma based forms the concentrated 5,000 ° C (typ.) plasma arc rapidly initiates thecombustion process and devolatilizes the coal particles

· Up to 5% of full load burner heat input is generally sufficient to ensure combustion,subject to required testing

The configuration and installation of CF igniters vary widely between manufacturers andapplication. In a retrofit case involving some furnace designs where the igniter is separate fromthe associated burner, the current igniters may be either completely or partially replaced or evenfully retained. Retrofits would require a clear understanding of the retrofit purpose and anexperienced designer for a successful installation.X.3 Igniter Classification DiscussionSection 3.3.73 of the existing NFPA 85 code both specifies the functional requirements ofigniters as well as generalizes igniter classifications by igniter heat input. Class 1 igniters arerequired “to raise any credible combination of burner inputs of both fuel and air above theminimum ignition temperature”, which is then required to be tested to verify they meet thesefunctional requirements.The Code permits operation of the main burner without proof of main burner flame if a Class 1igniter flame is proven. Classification of CF igniters based on the heat input definitions in theexisting NFPA code may not be appropriate when the heat input guideline is applied verbatim. For CF igniters the heat inputs as a percentage of the full load burner heat input are generallyless than 1% for plasma igniters and up to 5% for oil and gas CF igniters. Although functionallythey may be designed and operate as a Class 1 or 2 igniter, they would be considered Class 3based on the current heat input generalization.Therefore, it is critical that igniter classification be determined by design and verified by test tomeet their functional definitions in Section 3.3.73. The heat input guideline which is appropriatefor conventional igniters is not appropriate for CF igniters.The ability of igniters to support flame under varying conditions determine their applicationprofile. Due to their robust ability to support flame under challenging conditions, Class 1 igniterscan be used to prove the main burner flame whereas Class 2 and Class 3 igniters may not. Class 2 igniters may be used to maintain a stable burner flame, however Class 3 igniters are notsufficiently effective to do so. CF igniters may also be designed to function as Class 2 or Class 3igniters with their respective functional requirements as well as application profiles. The currentcode also requires that all of these classifications are to be proven by test as specified inSections 6.8.3.2.2 and 6.8.3.2.3. Satisfaction of the “any credible combination of burner inputsof both fuel and air” requirement for class 1 igniters needs careful consideration. Suchconsideration should include:· Variation in coal blends· Coal pipe coal and primary air imbalances· Normal variation in coal properties (i.e. volatile mater and moisture)· Variation in ambient air conditions including moisture and temperature· Transient conditions due to mill stopping and starting· Variation in coal finenessMany of the above parameters are difficult to control for a representative test. However, testingshould be performed using controllable parameters which give guidance to the designer, user


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and AHJ on how well the system performs in fulfilling its intended classification requirements.It is important that the designer recognize potential hazards due to changes in the igniter andburner system and perform tests as specified in Sections 6.8.3.2.2 and 6.8.3.2.3.1 to determinethe limits of flame stability under these new operating conditions.X.4 Igniter ProvingTraditional igniter flame proving techniques may be difficult to apply to plasma based CF ignitersdue to the high temperatures and location of the igniter flame inside the burner barrel. Proof ofignition for plasma based igniters has typically been achieved by monitoring a combination ofplasma operating conditions (i.e. low voltage and high current across the plasma generator,absence of other system faults) and operator observation through furnace cameras, etc. Safeoperations of the main burner would still require conventional flame scanner technology forproving flame after initial startup conditions with or without the CF igniter in service. CF igniters using Fuel Oil or Fuel Gas are fully capable of being proven using conventional flamescanner technology (albeit applied in a non-traditional location, with the flame being sensedinside the burner barrel). Observation cameras aimed at individual burners are typically part of a CF igniter installation. They provide general information and guidance to both the commissioning team as part of theinitial installation as well as to the operations team with on-going operation. While historicallyfurnace observation cameras suffered from high failure rates, current generation technology ismore reliable.The use of furnace cameras for observation of the igniter and coal flame and the adjustment ofigniter parameters based on operator observation constitutes manual operation. The codeprohibits the use of manual systems in at least the following operations: 1) Section 4.5.1 “Operating Procedures with a minimum number of manual operations shallbe established.”2) Section 6.6.6 Boiler Front Control. “Supervised manual operation shall not apply to newconstruction.”3) Section 6.7.6 Boiler Front Control. “Supervised manual operation shall not apply to newconstruction.”However, as CF ignition is new and unproven technology in the US, the use of furnace camerasfor visual observation and other information gathering systems (e.g. in-furnace combustionanalyzers) is strongly recommended.The required interlocks for Multiple Burner Boilers is shown in Figure 6.4.1.2.1 of this code.X.5 Recommended Start Up Sequence.The startup sequence for CF igniters should follow the established process in Section 6.8.5.2.1.3for coal fired units. Fuel Oil or Fuel Gas fired units should follow their respective processes inSections 6.6.5.2.1.3 (Gas) and 6.7.5.2.1.3 (Oil) Additional start-up sequences for Plasma or CF Igniters, as required by the manufacturer, shouldbe included.X.6 Supervisory Controls and Mechanical ConsiderationsThe following supervisory controls and equipment features should be included with CF igniterinstallations:1) For all forms of CF igniters, a furnace camera system capable of providing visual feedbackof each burner should be provided and be operational. This is a key operating technique andcan lead to a manual MFT, but cannot be the sole means of flame safety.2) The furnace camera system shall be capable of simultaneously displaying images anddigitally storing video signals for playback.3) At least 120 hours of observation history shall be maintained.4) Furnace cameras shall be designed to correctly function with concentrated flame igniters.5) In-furnace combustion analyzers are recommended as industry in the US gainsexperience.6) Pulverizer Airflow measurement for all mills.


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7) Inner burner barrel temperature measurements to monitor the combustion process with theigniter in operation and the barrel temperature should be controlled to be within the acceptablerange specified by the manufacturer. This is especially critical during system commissioning.8) Inner barrels should be designed for periodic inspection, cleaning and maintenance due totheir exposure to high temperatures and potential for coking, soot buildup, slagging andplugging.9) For plasma CF igniters, plasma generator voltage and current should be measuredmeasurements and should be confirmed to be within the acceptable range specified by themanufacturer and verified by testing prior to allowing admission of main fuel.10) For plasma igniters, anode and cathode run time totalizers to enable preventative systemmaintenance.11) Any manufacturer required igniter lance cooling fluid (water or air) flows and temperaturesshould be monitored with the igniters in service to make sure they stay below criticaltemperatures.12) For fuel oil CF igniters, the atomizing equipment for liquid fueled igniter subsystems shouldbe designed for periodic removal, cleaning and maintenance due to their exposure to hightemperatures and potential for ‘coking’X.7 Safety ConsiderationsCF igniter technology has been successfully applied outside the US with installations in over1,000 coal fired boilers in both the plasma and oil igniter form; and is available from multiplesuppliers/manufacturers. These installations have demonstrated the capability of the technologyto an extent that application in US coal plants can be considered. However, the specific safetyprofile of this technology is difficult to ascertain. There is little publicly available informationregarding incidents, and much of the experience has been in places with a different safetyculture and operations team experience than the US. It is clear that there have been safetyincidents, but the cause of the incidents, as well as the opportunity to learn from those incidents,is missing in the general record. However, it should be noted, whenever poor combustion of CFigniters is observed through the furnace cameras, careful action should be taken to minimize theaccumulation of unburnt pulverized coal in the furnace and downstream equipment and toprevent the possible fire and deflagration incidents in those areas.The design of the CF igniter is highly fuel dependent. Therefore, any changes to the existingigniter system and or coal properties should be considered and documented as part of aManagement of Change process. CF igniters should be only used for the coal property rangespecified by the igniter manufacturer.Extensive operator training should be required as part of any CF igniter installation. Trainingshould include operating procedures, checklists, required interlocks, information on how the newsystem was integrated into the existing Combustion Control System, Burner ManagementSystems, flame proving equipment and operation including at a minimum the use of furnacecameras and in-furnace combustion analyzers. X.8 Technical ReferencesThere are multiple standards and guidelines published by regulatory authorities and equipmentsuppliers that are available to assist with the application of this technology. As of 2017 theseresources include:1) DL/T 1127 — 2010 "Guideline for Design and Operation of Plasma Ignition Systems"2) DL/T 435 “Standard of the Prevention of Pulverized Coal-firing FurnaceExplosions/Implosions in Power Plant Boilers”3) Plasma Ignition Safety Precautions, Yantai Longyuan Power Technology Co., Ltd.


File Name Description ApprovedFigure_1_-_Axial.docx Drawing of Axial Configuration Figure_2_-_Tangential.docx Drawing of Tangential Configuration


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Provides Annex material for Concentrated Flame Igniters as developed by the Task Group. The document objectives are as follows: • Develop the proposed NFPA 85 CODE Annex Materials governing use of concentrated flame igniters in the US and overseas • Facilitate feedback from NFPA Plasma task force members and other industry experts • Document additional resources for system designers and other interested parties • Provide a means of review and development of future text material

Related ItemResponse to discussion at First Draft meeting - 188-NFPA 85-2016


Submitter Full Name: Edward LightbournOrganization: SmartBurn, LLCAffilliation: Guodian Longyuan Technologies Co.Street Address:City:State:Zip:Submittal Date: Thu Nov 09 10:26:28 EST 2017


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Proposed NFPA Annex X for Concentrated Flame Igniters Page 1


Page 45 of 81


November 9, 2017

NFPA 85 Annex XX Concentrated Flame Igniter Supplemental Information

Document Objectives

Develop the proposed NFPA 85 CODE Annex Materials governing use of concentrated

flame igniters in the US and overseas

Facilitate feedback from NFPA Plasma task force members and other industry experts

Document additional resources for system designers and other interested parties

Provide a means of review and development of future text material

Annex Preamble:

This annex is not part of the requirements of this NFPA document but is included for informational

purposes only.

X.1 Concentrated Flame Igniters General Considerations and Definitions

X1.1 New igniter technologies, to be referred to as “Concentrated Flame (CF) Igniters”, have

been developed which can reduce, or even eliminate, the consumption of igniter Fuel Oil or

Fuel Gas used in coal fired boiler warm up, mill group ignition, and low load support. A

burner with an integral ignitor assembly specifically designed and fabricated for the initial

combustion to take place within the burner barrel as opposed to outside the burner in the

furnace cavity, as is done for traditional igniters, is an example of this new technology. For CF

igniters, with the igniter in service, combustion may extend into the furnace cavity, however the

initial point of combustion is designed to be inside the burner.

These systems can be beneficial for at least the following reasons 1) the initial combustion is

controlled within the burner barrel, where there is a high level of contact between the ignition

source and the Primary Air stream, and 2) in the case of the plasma based form, the very high

boundary temperature (much higher than adiabatic flame temperature of coal, oil or gas)

promotes fracturing and devolatilization of the coal particles, leading to prompt ignition.

CF igniters may take multiple forms based on the heat energy source by which the coal stream

is ignited. The most common form of CF igniters uses an ionic plasma gas to ignite the coal and

primary air mixture. However, other designs may use Fuel Oil, and less commonly Fuel Gas

for the initial ignition. Generally, but not universally, only a subset of the Primary Air/Fuel


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stream is initially ignited. Some designs utilize successive concentric annular combustion zones

inside the burner barrel to stage the mixing of the Primary Air/Fuel stream to control the

ignition of the remaining portions of the Primary Air/Fuel stream. When the igniter is no longer

required to be in service, the igniter is de‐energized, and the ignition point quickly propagates

to the front of the barrel tip as in traditional burner operation.

CF igniters have been deployed on both wall and tangentially fired furnaces on a wide variety

of coal ranks.

The plasma form of CF igniters is designed to require no support fuel consumption. The Fuel

Oil and Fuel Gas forms claim reduced consumption of the igniter fuel compared to a

conventional Class 1 igniter.

For both forms with a boiler in a cold state separate equipment and energy source to heat the

primary air to the required temperatures are required as energy cannot be recovered from the

cold flue gas.

X1.2 Side Sectional Views of Common Forms of Concentrated Flame Igniters

Figure AX.X.X: Axial Configuration


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Figure A.X.X Tangential Configuration

X1.3 Plasma Definition. Plasma is a gaseous mixture of negatively charged electrons and

highly charged positive ions which can conduct large and sustained electric current and

generates very high temperatures. In common forms of plasma igniters, the plasma is

generated when a strong electric potential is applied between anode and cathode elements.

Plasmas respond to electromagnetic forces and the plasma gas may be controlled using

magnetic induction coils.

X.2 Technology Overview

The CF igniter is designed to be an integral part of the burner barrel, while a conventional

igniter in some furnace designs may be physically independent of the burner. Because of its

integral design feature, a CF igniter would not properly function in a different burner barrel,

and a conventional igniter would not properly function in a burner barrel designed for a CF

igniter. The technology can be compared with conventional coal burner igniters as follows.

For a conventional igniter:

The coal (Primary Air) stream is not ignited until it flows just outside the burner tip and

combustion occurs in the open furnace cavity


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Coal devolatilization and pyrolysis occur relatively slowly as coal particles heat up and

then ignite

The maximum flame temperature (adiabatic, equivalence ratio ideal) 2,100 °C (oil) &

1,960 °C (natural gas)

For CF igniters:

A portion of the coal is ignited at the inlet of the burner barrel when the igniter is in

service. The initial ignition propagates through successive stages inside the burner

barrel.

When the igniter is turned off, the flame then moves to outside the burner tip

In plasma based forms the concentrated 5,000°C (typ.) plasma arc rapidly initiates the

combustion process and devolatilizes the coal particles

Up to 5% of full load burner heat input is generally sufficient to ensure combustion,

subject to required testing

The configuration and installation of CF igniters vary widely between manufacturers and

application. In a retrofit case involving some furnace designs where the igniter is separate from

the associated burner, the current igniters may be either completely or partially replaced or

even fully retained. Retrofits would require a clear understanding of the retrofit purpose and

an experienced designer for a successful installation.

X.3 Igniter Classification Discussion

Section 3.3.73 of the existing NFPA 85 code both specifies the functional requirements of

igniters as well as generalizes igniter classifications by igniter heat input. Class 1 igniters are

required “to raise any credible combination of burner inputs of both fuel and air above the

minimum ignition temperature”, which is then required to be tested to verify they meet these

functional requirements.

The Code permits operation of the main burner without proof of main burner flame if a Class 1

igniter flame is proven. Classification of CF igniters based on the heat input definitions in the

existing NFPA code may not be appropriate when the heat input guideline is applied verbatim.

For CF igniters the heat inputs as a percentage of the full load burner heat input are generally

less than 1% for plasma igniters and up to 5% for oil and gas CF igniters. Although functionally


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they may be designed and operate as a Class 1 or 2 igniter, they would be considered Class 3

based on the current heat input generalization.

Therefore, it is critical that igniter classification be determined by design and verified by test to

meet their functional definitions in Section 3.3.73. The heat input guideline which is

appropriate for conventional igniters is not appropriate for CF igniters.

The ability of igniters to support flame under varying conditions determine their application

profile. Due to their robust ability to support flame under challenging conditions, Class 1

igniters can be used to prove the main burner flame whereas Class 2 and Class 3 igniters may

not. Class 2 igniters may be used to maintain a stable burner flame, however Class 3 igniters

are not sufficiently effective to do so. CF igniters may also be designed to function as Class 2 or

Class 3 igniters with their respective functional requirements as well as application profiles.

The current code also requires that all of these classifications are to be proven by test as

specified in Sections 6.8.3.2.2 and 6.8.3.2.3. Satisfaction of the “any credible combination of

burner inputs of both fuel and air” requirement for class 1 igniters needs careful consideration.

Such consideration should include:

Variation in coal blends

Coal pipe coal and primary air imbalances

Normal variation in coal properties (i.e. volatile mater and moisture)

Variation in ambient air conditions including moisture and temperature

Transient conditions due to mill stopping and starting

Variation in coal fineness

Many of the above parameters are difficult to control for a representative test. However, testing

should be performed using controllable parameters which give guidance to the designer, user

and AHJ on how well the system performs in fulfilling its intended classification requirements.

It is important that the designer recognize potential hazards due to changes in the igniter and

burner system and perform tests as specified in Sections 6.8.3.2.2 and 6.8.3.2.3.1 to determine the

limits of flame stability under these new operating conditions.

X.4 Igniter Proving

Traditional igniter flame proving techniques may be difficult to apply to plasma based CF

igniters due to the high temperatures and location of the igniter flame inside the burner barrel.

Proof of ignition for plasma based igniters has typically been achieved by monitoring a

combination of plasma operating conditions (i.e. low voltage and high current across the


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plasma generator, absence of other system faults) and operator observation through furnace

cameras, etc. Safe operations of the main burner would still require conventional flame scanner

technology for proving flame after initial startup conditions with or without the CF igniter in

service.

CF igniters using Fuel Oil or Fuel Gas are fully capable of being proven using conventional

flame scanner technology (albeit applied in a non‐traditional location, with the flame being

sensed inside the burner barrel).

Observation cameras aimed at individual burners are typically part of a CF igniter installation.

They provide general information and guidance to both the commissioning team as part of the

initial installation as well as to the operations team with on‐going operation. While historically

furnace observation cameras suffered from high failure rates, current generation technology is

more reliable.

The use of furnace cameras for observation of the igniter and coal flame and the adjustment of

igniter parameters based on operator observation constitutes manual operation. The code

prohibits the use of manual systems in at least the following operations:

1) Section 4.5.1 “Operating Procedures with a minimum number of manual operations

shall be established.”

2) Section 6.6.6 Boiler Front Control. “Supervised manual operation shall not apply to new

construction.”

3) Section 6.7.6 Boiler Front Control. “Supervised manual operation shall not apply to new

construction.”

However, as CF ignition is new and unproven technology in the US, the use of furnace cameras

for visual observation and other information gathering systems (e.g. in‐furnace combustion

analyzers) is strongly recommended.

The required interlocks for Multiple Burner Boilers is shown in Figure 6.4.1.2.1 of this code.

X.5 Recommended Start Up Sequence.

The startup sequence for CF igniters should follow the established process in Section 6.8.5.2.1.3

for coal fired units. Fuel Oil or Fuel Gas fired units should follow their respective processes in

Sections 6.6.5.2.1.3 (Gas) and 6.7.5.2.1.3 (Oil)

Additional start‐up sequences for Plasma or CF Igniters, as required by the manufacturer,

should be included.


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X.6 Supervisory Controls and Mechanical Considerations

The following supervisory controls and equipment features should be included with CF igniter

installations:

1) For all forms of CF igniters, a furnace camera system capable of providing visual

feedback of each burner should be provided and be operational. This is a key operating

technique and can lead to a manual MFT, but cannot be the sole means of flame safety.

2) The furnace camera system shall be capable of simultaneously displaying images and

digitally storing video signals for playback.

3) At least 120 hours of observation history shall be maintained.

4) Furnace cameras shall be designed to correctly function with concentrated flame

igniters.

5) In‐furnace combustion analyzers are recommended as industry in the US gains

experience.

6) Pulverizer Airflow measurement for all mills.

7) Inner burner barrel temperature measurements to monitor the combustion process with

the igniter in operation and the barrel temperature should be controlled to be within the

acceptable range specified by the manufacturer. This is especially critical during system

commissioning.

8) Inner barrels should be designed for periodic inspection, cleaning and maintenance due

to their exposure to high temperatures and potential for coking, soot buildup, slagging

and plugging.

9) For plasma CF igniters, plasma generator voltage and current should be measured

measurements and should be confirmed to be within the acceptable range specified by

the manufacturer and verified by testing prior to allowing admission of main fuel.

10) For plasma igniters, anode and cathode run time totalizers to enable preventative system

maintenance.

11) Any manufacturer required igniter lance cooling fluid (water or air) flows and

temperatures should be monitored with the igniters in service to make sure they stay

below critical temperatures.

12) For fuel oil CF igniters, the atomizing equipment for liquid fueled igniter subsystems

should be designed for periodic removal, cleaning and maintenance due to their

exposure to high temperatures and potential for ‘coking’

X.7 Safety Considerations


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CF igniter technology has been successfully applied outside the US with installations in over

1,000 coal fired boilers in both the plasma and oil igniter form; and is available from multiple

suppliers/manufacturers. These installations have demonstrated the capability of the

technology to an extent that application in US coal plants can be considered. However, the

specific safety profile of this technology is difficult to ascertain. There is little publicly available

information regarding incidents, and much of the experience has been in places with a different

safety culture and operations team experience than the US. It is clear that there have been

safety incidents, but the cause of the incidents, as well as the opportunity to learn from those

incidents, is missing in the general record. However, it should be noted, whenever poor

combustion of CF igniters is observed through the furnace cameras, careful action should be

taken to minimize the accumulation of unburnt pulverized coal in the furnace and downstream

equipment and to prevent the possible fire and deflagration incidents in those areas.

The design of the CF igniter is highly fuel dependent. Therefore, any changes to the existing

igniter system and or coal properties should be considered and documented as part of a

Management of Change process. CF igniters should be only used for the coal property range

specified by the igniter manufacturer.

Extensive operator training should be required as part of any CF igniter installation. Training

should include operating procedures, checklists, required interlocks, information on how the

new system was integrated into the existing Combustion Control System, Burner Management

Systems, flame proving equipment and operation including at a minimum the use of furnace

cameras and in‐furnace combustion analyzers.

X.8 Technical References

There are multiple standards and guidelines published by regulatory authorities and

equipment suppliers that are available to assist with the application of this technology. As of

2017 these resources include:

1) DL/T 1127 — 2010 ʺGuideline for Design and Operation of Plasma Ignition Systemsʺ

2) DL/T 435 “Standard of the Prevention of Pulverized Coal‐firing Furnace

Explosions/Implosions in Power Plant Boilers”

3) Plasma Ignition Safety Precautions, Yantai Longyuan Power Technology Co., Ltd.


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Attachment F: Review of Committee Inputs


Page 54 of 81


http://submittals.nfpa.org/TerraViewWeb/ViewerPage.jsp 1/3

Committee Input No. 179-NFPA 85-2017 [ Section No. A.6.4.1.2.1 ]

This was a First Revision that has been modified or deleted as the result of FirstCorrelating Revision: FCR-25-NFPA 85-2017

A.6.4.1.2.1

In block 6 of Table 6.4.1.2.1(a), high furnace pressure could be caused by tube rupture, damperfailure, or explosion.

In block 8 of Table 6.4.1.2.1(a), the partial loss of flame described is potentially more hazardous atlower load levels. The decision regarding specific requirements or implementation of this trip shouldbe a design decision based on furnace configuration, total number of burners, number of burnersaffected as a percentage of burners in service, arrangement of burners affected, interlocksystem interlocks , and load level. This trip is interlocked through flame supervisory equipment.

In block 9 of Table 6.4.1.2.1(a), the tables referenced describe the allowable differences in operatingprocedures based on the classification of igniter being used. The following descriptions of conditionsare typical for both Table 6.4.1.2.1(b) and Table 6.4.1.2.1(c).

(1) Condition 1: An event in which, after a successful boiler purge, an attempt(s) to place the firstigniter in service fails

(2) Condition 2: An event in which an igniter(s) has been proven in service and subsequently alligniters are shut down without the attempt ever having been made to place a burner orpulverizer in service

(3) Condition 3: An event in which gas and/or oil fuel burners were started or attempted to bestarted and all burner valves were subsequently closed while igniters remain proven in service

(4) Condition 4: An event in which a pulverizer system(s) was started up or attempted to be startedup and subsequently all pulverizer systems were shut down while igniters remain proven inservice

(5) Condition 5: An event in which any fuel has been placed in service and all fuel subsequentlyshut off

In the event that any main fuel is shut down while any other main fuel remains proven in service, theall-fuel-off master fuel trip requirements do not apply.

In block 10a of Table 6.4.1.2.1(a), low drum water level has been included as a master fuel trip.Although low drum water level is not a combustion-related hazard, this code is the primary resourcefor identifying BMS requirements, and not including a low drum level trip in Figure 6.4.1.2.1 hascreated confusion with users of this code. A master fuel trip based on low drum water level fordrum-type boilers is commonly recognized good engineering practice.

In block 10b 10c of Table 6.4.1.2.1(a), low waterwall flow is also not a combustion-relatedhazard. The low waterwall flow threshold could be a fixed value or a function of the boiler loadbased on the boiler manufacturer’s recommendations.


Submitter Full Name: BCS-MBBOrganization: [ Not Specified ]Street Address:City:State:Zip:Submittal Date: Tue Feb 07 13:54:41 EST 2017


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CommitteeStatement:

Changes made to coordinate with the Fundamentals Committee actions to define termsincluding "trip" and "interlock" among many other variations of those terms. The deleted sentence was restating the obvious and doesn't contribute to the understandingof the concept. Block 10b has become 10c due to the addition of a new Block 10b for forced circulationboilers.

ResponseMessage:

Public Input No. 94-NFPA 85-2016 [Section No. A.6.4.1.2.1]

Ballot Results




Not ReturnedBasile, Barry J.

Affirmative AllBeach, Denise

Bennett, Frank J.

Bollinger, John E.

Dexter, David E.

Eibl, John J.

Evely, Dale P.

Fehr, Joseph E.

Frazier, Kenneth Joe

Kimball, Richard

King, David W.

Lee, Daniel J.

Lesaca, Roger

Lightbourn, Edward

O'Rourke, John P.

Reeves, Roy

Robertson, Alan R.


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Santos, Jr., Carlos


Schmidt, Celso G.

Smith, Jr., Bill L.

Switzer, Jr., Franklin R.

Walawender, James P.

Walz, Michael A.

Willse, Peter J.

Wong, Henry K.

Yates, Harold R.

Zissa, Donald


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Committee Input No. 307-NFPA 85-2017 [ New Section after A.10.8.1 ]

New Annex XAnnex X Integrated Burner-Igniter SystemsIntegrated Burner-Igniter Systems shall be permitted to be used in pulverized coal-fired multipleburner boilers. X.1 An integrated burner-igniter system shall utilize either a concentrated flame igniter or a plasmaarc igniter as the primary ignition source.X.2* The ignition point in an integrated burner-igniter system shall be located within the burner barrel.A.X.2 When the temperature in the furnace is high enough to support stable combustion, the ignitercan be de-energized and the flame envelope will move to the outside of the burner tip and into thefurnace.X.3 An integrated burner-igniter system shall incorporate successive ignition stages within the burnerbarrel.X.3.1* Where a plasma arc igniter is used in an integrated burner-igniter assembly, the igniter flameshall be proven by the main burner scanner.A.X.3.1 Current technology does not allow a flame scanner to be installed in the high temperatureenvironment associated with plasma arc igniters.X.4 An integrated burner-igniter system shall be designed for a specific type or rank of coal.X.4.1 * Any changes to the fuel being supplied shall require review of the design basis for the affectedintegrated burner-igniter system prior to implementation of the fuel change.A.X.4.1 A review of changes due to the fuel being supplied could occur as a part of an overallmanagement of change program.


Submitter Full Name: BCS-MBBOrganization: [ Not Specified ]Street Address:City:State:Zip:Submittal Date: Wed Feb 08 10:50:51 EST 2017


CommitteeStatement:

A task group will work to develop annex material based on the language from Public Inputs165-169 and 188-192, and will ensure that the language is in the style of annex material. Thecode does not currently prohibit the use of this technology, but does not provide guidance onhow they should be used. The task group will also solicit Public Comments from other manufacturers of plasma arcignitors. Also see Committee Inputs 309 and 310. The Task Group intends to address the startingsequence and supervisory controls for this technology.

Response


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Message:

Public Input No. 165-NFPA 85-2016 [New Section after 6.3.3.7]

Public Input No. 192-NFPA 85-2016 [New Section after A.6.2.3]


Public Input No. 190-NFPA 85-2016 [New Section after 6.3]







Ballot Results

This item has not been balloted


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Committee Input No. 309-NFPA 85-2017 [ New Section after 6.3 ]

The Task Group on Plasma Arc Igniters is tasked with adding supervisory control requirements thatrelate to integrated burner systems, with the intent of adding this at the Second Draft stage.




CommitteeStatement:

The Task Group on Plasma Arc Igniters is tasked with adding supervisory controlrequirements that relate to integrated burner systems, with the intent of adding this at theSecond Draft stage. Also see Committee Inputs 307 and 310.

ResponseMessage:

Ballot Results



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Committee Input No. 310-NFPA 85-2017 [ Section No. 6.8.5.2 ]

6.8.5.2 Functional Requirements.

6.8.5.2.1 Cold Start.

This subsection shall cover the requirements for placing coal in service as the initial fuel beingfired. The requirements for placing coal in service as a subsequent fuel shall be as detailed by6.8.5.2.6.

6.8.5.2.1.1

Preparation for starting shall include a thorough inspection that shall verify the following:

(1) The furnace and flue gas passages are free of foreign material and not in need of repair.

(2)

(3) All personnel are evacuated from the unit and associated equipment, and all access andinspection doors are closed.

(4) All airflow and flue gas flow control dampers have been operated through their full range tocheck the operating mechanism and then are set at a position that allows the fans to bestarted at a minimum airflow and without overpressuring any part of the unit.

(5) All individual burner dampers or registers that are subject to adjustment during operationshave been operated through their full range to check the operating mechanism.

(6) The drum water level is established in drum-type boilers, circulating flow is established inforced circulation boilers, or minimum water flow is established in once-through boilers.

(7) The oxygen analyzer(s) and combustibles analyzer(s), if provided, are operating as designed,and a sample has been obtained. Combustibles indication is at zero, and oxygen indication isat maximum.

(8) The igniter safety shutoff valves are closed, and sparks are de-energized. Fuel gas ignitionsystems shall comply with the requirements of Section 6.6. Fuel oil ignition systems shallcomply with the requirements of Section 6.7.

(9) The pulverizing equipment is isolated effectively to prevent inadvertent or uncontrolled leakageof coal into the furnace.

(10) The pulverizers, feeders, and associated equipment are operable, not in need of repair, andadjusted to the requirements of established operating procedures that ensure their standbystart-up status. All pulverizer and feeder sensor lines are clean prior to starting.

(11) Energy is supplied to control system and to interlocks.

(12) A complete functional check of the interlocks has been made after an overhaul or modificationof the interlock system.

(13)

(14) Individual igniters or groups of igniters also have been permitted to be tested while the unit isin service. Such tests have been made with no main fuel present in the igniter's associatedburner, and the burner air register has been in its start-up or light-off position as described inthe established operating procedure.

(15)

* The bottom of the furnace, including the ash hopper, is free of accumulations of solid or liquidfuel, fuel gases, or vapors prior to each start-up.

* An operational test of each igniter has been made. The test has been integrated into thestarting sequence and has followed the unit purge and preceded the admission of any mainfuel.

* Units with a history of igniter unreliability have gone through additional test routines to verifythe continuing operating ability of igniters and ignition system components.


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6.8.5.2.1.2

Where provided, regenerative air heaters and flue gas recirculation fans shall be operated duringall operations of the unit in a manner recommended by the boiler manufacturer.

6.8.5.2.1.3 Starting Sequence.

(A) Operation of regenerative-type air heaters, precipitators, and flue gas recirculation fans shall beincluded in the start-up sequence in accordance with the manufacturer's recommendations.


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(B)


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The starting sequence shall be performed in the following order:

(1) An open flow path from the inlets of the FD fans through the stack shall be verified.

(2) An ID fan, if provided, shall be started; an FD fan then shall be started. Additional ID fans orFD fans shall be started in accordance with Section 6.5, as necessary, to achieve purge flowrate.

(3) Dampers and burner registers shall be opened to purge position in accordance with the open-register purge method objectives outlined in 6.8.5.1.5.7.

(4) The airflow shall be adjusted to purge airflow rate, and a unit purge shall be performed.Special provisions shall be utilized as necessary to prevent the hazardous accumulation ofvolatile vapors that are heavier than air or to detect and purge accumulations in the furnaceash pit.

(5) For fuel gas– or fuel oil–fired igniters, the igniter safety shutoff valve(s) shall be opened, and itshall be confirmed that the igniter fuel control valve is holding the manufacturer'srecommended fuel pressure necessary to allow the igniter to operate at design capacity. Fuelgas igniter headers shall be vented in order to be filled with fuel gas and to provide a flow (ifnecessary) so that the igniter fuel control valve can function to regulate and maintain thepressure within design limits specified by the manufacturer for lighting the igniters.

(6) The air register or damper on the burners selected for light-off shall be adjusted to the positionrecommended by the manufacturer or the established operating procedure, in accordance with6.8.5.1.5.7(C) through 6.8.5.1.5.7(F).

(7) The spark or other source of ignition for the igniter(s) on the burner(s) to be lit shall beinitiated, and the following procedures shall be performed:

(a) The individual igniter safety shutoff valve(s) shall be opened.

(b) If flame on the first igniter(s) is not established within 10 seconds, the individual ignitersafety shutoff valve(s) shall be closed, and the cause of failure to ignite shall bedetermined and corrected.

(c) With airflow maintained at purge rate, repurge shall not be required, but at least 1 minuteshall elapse before a retrial of this or any other igniter is attempted.

(d) Repeated retrials of igniters without investigating and correcting the cause of themalfunction shall be prohibited.

(8) With the coal feeder off, all gates between the coal bunker and the pulverizer feeder shall beopened, and it shall be confirmed that coal is available to the feeder.

(9) The igniters shall be checked to ensure they are established and are providing the requiredlevel of ignition energy for the main burners. The pulverizing equipment shall be started inaccordance with the equipment manufacturer's instruction.

(10) The furnace airflow shall be readjusted after conditions stabilize, as necessary. Airflow shallnot be reduced below the purge rate.

(11) The feeder shall be started at a predetermined setting with the feeder delivering coal to thepulverizer, and the following shall be performed:

(a) Pulverized coal shall be delivered to the burners after the specific time delay necessary tobuild up storage in the pulverizer and transport the fuel to the burner.

(b) This time delay, which shall be determined by test, shall be permitted to be as short as afew seconds with some types of equipment or as long as several minutes with others.

(12) Ignition of the main burner fuel admitted to the furnace shall be confirmed, and the followingrequirements shall be met:

(a) Required ignition shall be obtained within 10 seconds following the specific time delaydescribed in 6.8.5.2.1.3(B)(11).

(b) The coal fuel trip shall be initiated on failure to ignite or loss of ignition on burners servedby the first pulverizer placed in operation.


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(c) Except where associated Class 1 igniters are in service, a master fuel trip shall beinitiated on failure to ignite or on loss of ignition on placing the first pulverizer into service.

(d) Where the cause of failure to ignite or loss of ignition is known to be due to loss of coal inthe pulverizer subsystem, initiation of the master fuel trip shall not be required, but allrequired conditions for light-off shall exist before coal feed is restored.

(13) For the following pulverizer and all subsequent pulverizers placed in operation, failure to igniteor loss of ignition for any reason on any burner shall cause the fuel flow to that burner to stopin accordance with the manufacturer's recommendations. All conditions required byestablished operating procedures for light-off shall exist before the burner is restarted.

(14) After stable flame is established, the air register(s) or damper(s) shall be adjusted slowly to itsoperating position, making certain that ignition is not lost in the process.

(15) The load for the operating pulverizer shall be at a level that prevents its load from beingreduced below operating limits when an additional pulverizer is placed in operation.

(16) If a pulverizer has been operating but does not have all its burners in service, the idle burnersshall be permitted to be restarted if the pulverizer-burner subsystem and its controls aredesigned specifically for such operations, and precautions are incorporated to prevent all thefollowing conditions:

(a) Accumulation of coal in idle burner lines

(b) Hot burner nozzles and diffusers that have the potential to cause coking and fires whencoal is introduced

(c) Excessive disturbance of the air-fuel ratio of the operating burners

(17) If the precautions have not been taken, the idle burner(s) shall not be restarted. Instead,another pulverizer with all burners in service shall be started, and the pulverizer with idleburners shall be shut down and emptied.

(18)

(19)

(20) The on-line metering combustion control (unless designed specifically for start-up procedures)shall not be placed into service until the following have occurred:

(a) A predetermined minimum main fuel input has been attained.

(b) All registers on nonoperating burners are closed, unless compensation is provided by thecontrol system.

(c) The burner fuel and airflow are adjusted as necessary.

(d) Stable flame and specified furnace conditions have been established.

(21) Additional pulverizers shall be placed into service as needed by the boiler load in accordancewith the procedures of 6.8.5.2.1.3(B)(6) through 6.8.5.2.1.3(B)(16).

(22) On units with an overfire air system, the overfire air control damper positions shall bepermitted to be changed only when repositioning of all burner air registers or burner airdampers is permitted.

(23) On units with an overfire air system, the boiler shall be operating in a stable manner before theoverfire air is introduced. The introduction of the overfire air shall not adversely affect boileroperation.

(24) On units with an overfire air system and a reburn system, the overfire air shall be placed inoperation before the reburn fuel sequence is started.

(25) A reburn system shall be placed in service only after the boiler is operating at such a load asto ensure that the introduction of the reburn fuel will not adversely affect continued boileroperation. The required reburn zone temperatures shall be maintained in accordance with

* The procedures of 6.8.5.2.1.3(B)(6) through 6.8.5.2.1.3(B)(16) shall be followed for placing anadditional pulverizer into service. When fuel is being admitted to the furnace, igniters shall notbe placed into service for any burner without proof that there is a stable fire in the furnace.

* Igniters shall be permitted to be shut off after exceeding a predetermined minimum main fuelinput that has been determined in accordance with 6.8.3.2.2. Verification shall be made thatthe stable flame continues on the main burners after the igniters are removed from service.


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6.8.3.5.2. The boiler shall be operating in a stable manner before the reburn start-up sequenceis initiated.

6.8.5.2.2 Normal Operation.

6.8.5.2.2.1 Firing Rate.

(A) The firing rate shall be regulated by increasing or decreasing the fuel and air supply simultaneouslyto all operating burners, maintaining the air-fuel ratio within predetermined operating limitscontinuously at all firing rates.

(B) This procedure shall not eliminate requirements for air lead and lag during changes in the fuel firingrate.

6.8.5.2.2.2

The reburn injection rate shall be regulated within the design limits of the reburn equipment.

(A) Airflow lead and lag shall be used during changes in the reburn fuel injection rate.

(B) Reburn shutoff valves shall be fully open or fully closed and shall not be placed in intermediatepositions to regulate reburn injection rate.

6.8.5.2.2.3

The firing rate shall not be regulated by varying the fuel to individual burners by means of theindividual burner shutoff valve(s).

(A) Individual burner shutoff valve(s) shall be fully open or completely closed.

(B) Intermediate settings shall not be used.

6.8.5.2.2.4

Air registers shall be set at the firing positions as determined by tests except in systems providedwith metering of air and fuel to each burner and designed specifically for individual burnermodulating control.

6.8.5.2.2.5

The burner fuel and airflow shall be maintained within a range between the maximum andminimum limits as determined by trial or, if trial results do not exist, as specified by the combustionequipment manufacturer(s).

(A) These trials shall test for minimum and maximum limits and stable flame under the followingconditions:

(1) With all coal burners in service and combustion control on automatic

(2) With different combinations of coal burners in service and combustion control on automatic

(3) With different combinations of fuel gas, fuel oil, and coal burners in service and combustioncontrols on automatic

(4) With minimum and maximum reburn flow rates

(5) With each reburn fuel injection pattern

(6) With overfire air operation at its minimum and maximum limits


Page 66 of 81



(B) Where changes occur to any of the maximum and minimum limits because of equipmentmodifications, operating practices, or fuel conditions, retesting shall be required.

6.8.5.2.2.6

If lower minimum loads are required, the pulverizer(s) and associated burners shall be removedfrom service, and the remaining pulverizers shall be operated at a fuel rate above the minimumrate needed for stable operation of the connected burners.

(A) The minimum fuel rate shall be determined by tests with various combinations of burners in serviceand with various amounts of excess air and shall reflect the most restrictive condition.

(B) These tests also shall ensure that the transient stability factors described in 6.8.3.2.2 are taken intoaccount.

6.8.5.2.2.7

The ignition system shall be tested for stable operation at the various conditions described in6.8.5.2.2.5.

6.8.5.2.2.8 Loss of Individual Burner Flame.

(A) On loss of an individual burner flame, the flow of fuel to all burners of the pulverizer subsystemshall be stopped unless furnace configuration and tests have determined that one of the threeautomatic tripping philosophies described in 6.8.4.4 is applicable.

(B) Registers of shutdown burners shall be closed if interference with the air-fuel ratio at other burnerflame envelopes occurs.

(C) Hazards in these types of situations shall be reduced by following the requirements in 6.8.5.2.10and Chapter 9, which contain procedures for clearing pulverizers tripped while full of coal.

6.8.5.2.2.9

Total airflow shall not be reduced below the minimum purge rate established by the designer inaccordance with 6.4.1.2.4.4.

6.8.5.2.3 Normal Shutdown.

The requirements in 6.8.5.2.3 shall apply to the removal of coal from service as the only mainburner fuel being fired, and the requirements in 6.8.5.2.7 shall apply to the removal of coal fromservice with other fuel remaining in service.

6.8.5.2.3.1

When the unit is taken out of service, the boiler load shall be reduced to that necessitating a purgerate airflow using the procedures outlined in 6.8.5.2.3.2 through 6.8.5.2.3.4 while maintainingoperation within the tested limits determined in 6.8.5.2.2.5.

6.8.5.2.3.2

Prior to removing coal from service and prior to loss of reburn permissives, reburn fuel shall beshut down as defined in 6.6.5.2.9, 6.7.5.2.9, or 6.8.5.2.9.


Page 67 of 81



6.8.5.2.3.3

A pulverized coal system shall be shut down in the following sequence:

(1) The fuel input, airflow, and register positions of the pulverizer shall be adjusted to valuesestablished for start-up.

(2) Igniters shall be placed into service at these burners, when required to maintain flame stability.

(3) The hot primary air shall be shut off and the cold primary air shall be opened to cool down thepulverizer in accordance with Chapter 9.

(4) The feeder shall be stopped in accordance with the manufacturer's recommendations.Operation of the pulverizer shall be continued with a predetermined airflow prescribed in anestablished operating procedure that has been proven to be sufficient to empty out thepulverizer and associated burner lines.

(5) The inerting medium shall be introduced into the pulverizer as dictated by the coalcharacteristics.

(6) The pulverizer subsystem shall be shut down when burner fires are out and the pulverizer isempty and cool.

(7) All individual burner line shutoff valves shall be closed unless otherwise directed by themanufacturer's instructions.

(8) Igniters shall be removed from service.

6.8.5.2.3.4

As the fuel is reduced, the following procedures shall be performed:

(1) The remaining pulverizers shall be shut down consecutively following the procedures of6.8.5.2.3.3(1) through 6.8.5.2.3.3(8).

(2) In cases where the next pulverizer being removed has the potential to result in flameinstability, igniters shall be placed into service on burners that are still being fired.

6.8.5.2.3.5

When all pulverizers, igniters, and the reburn system have been removed from service, the purgerate airflow shall be verified, and a unit purge shall be performed.

6.8.5.2.3.6

After completion of the unit purge, forced and induced draft fans shall be permitted to be shutdown.

6.8.5.2.3.7* After the forced and induced draft fans have been shut down, dampers in the flue gas and air pathshall be permitted to be closed.

6.8.5.2.4 Normal Hot Restart.

6.8.5.2.4.1

When restarting a hot unit, the requirements of 6.8.5.2.1.1(6) through 6.8.5.2.1.1(11) for a cold startshall be met.

6.8.5.2.4.2

The starting sequence in 6.8.5.2.1.3(B)(1) through 6.8.5.2.1.3(B)(17) shall be followed.

6.8.5.2.5 Emergency Shutdown — Master Fuel Trip.

6.8.5.2.5.1

An emergency shutdown shall initiate a master fuel trip.

6.8.5.2.5.2 Mandatory Automatic Master Fuel Trips.

(A) Interlocks shall be installed in accordance with 6.4.1.


Page 68 of 81



(B) A master fuel trip shall result from any of the following conditions:

(1) Total airflow decreases below the minimum purge rate airflow as required in 6.4.1.2.4.4(A) by5 percent of design full load airflow

(2) Loss of either all FD fans or all ID fans

(3) Loss of all flame

(4) Partial loss of flame predetermined to be likely to introduce a hazardous accumulation ofunburned fuel in accordance with Table 6.4.1.2.1(a), block 8

(5) Furnace positive or negative pressure in excess of the prescribed operating pressure by avalue recommended by the manufacturer

(6) All fuel inputs shut off in accordance with Table 6.4.1.2.1(a), block 9 (See 6.4.1.2.9 for a list ofthe required interlocks and trips for individual pulverizer subsystems.)

(7) Low drum water level or low feedwater flow rate in accordance with Table 6.4.1.2.1(a), blocks10a and 10b.

6.8.5.2.5.3 Mandatory Master Fuel Trips with Alarms — Not Necessarily Automatically Initiated.

A master fuel trip shall result from any of the following conditions:

(1) Failure of the first pulverizer subsystem to operate successfully under the conditions specifiedin 6.8.5.2.1.3(B)(12) and Table 6.4.1.2.1(a), block 12d

(2) Loss of energy supply for combustion control, burner control, or interlock systems

6.8.5.2.5.4

A master fuel trip that results from any of the emergency conditions tabulated in 6.8.5.2.5.2 and6.8.5.2.5.3 shall stop all coal flow to the furnace from all pulverizer subsystems by tripping theburner and reburn shutoff valves or other devices designed for emergency shutoff of all coal flow.

(A) Igniter sparks shall be de-energized, the igniter safety shutoff valve, individual igniter safety shutoffvalves, primary air fans or exhausters, recirculating fans, coal feeders, and pulverizers shall betripped, coal burner line shutoff valves shall be closed or equivalent functional action shall be takento stop coal delivery to burners.

(B) The pulverizer motor shall be permitted to run prior to master fuel trip relay reset to clear residualcoal from the pulverizer in accordance with 9.6.4.2.2.1(2).

(C) If a furnace inerting system is installed, the inerting system shall be operated simultaneously withthe master fuel trip.

(D) Master fuel trips shall operate in a manner to stop all fuel flow into the furnace within a period thatdoes not allow a dangerous accumulation of fuel in the furnace.

(E) A master fuel trip shall not initiate an FD or ID fan trip.

(F) Electrostatic precipitators, fired reheaters, or other ignition sources shall be tripped.

6.8.5.2.5.5

Following a master fuel trip, the unit shall be purged in accordance with 6.4.1.2.4.

6.8.5.2.6 Starting Sequence — Second Fuel.


Page 69 of 81



6.8.5.2.6.1

When coal is started as a second fuel, the requirements of 6.8.5.2.1.1(8) through 6.8.5.2.1.1(11)shall be satisfied, and the total heat input shall be limited as described in 6.8.5.1.4.

6.8.5.2.6.2

The starting sequence of the first fuel (gas or oil) shall be complete.

6.8.5.2.6.3

The starting sequence of second fuel (coal) shall be performed in the starting sequence in6.8.5.2.1.3(B)(5) through 6.8.5.2.1.3(B)(20).

Exception: For sequence 6.8.5.2.1.3(B)(12), where coal is the second fuel to be placed inservice, a coal fuel trip shall be initiated on failure to ignite or loss of ignition on burners served bythe first pulverizer placed in operation. A master fuel trip shall not be required.

6.8.5.2.7 Shutdown Sequence — Second Fuel.

6.8.5.2.7.1

The requirements in 6.8.5.2.7 shall apply to the removal of coal from service with other main burnerfuel remaining in service, and the requirements in 6.8.5.2.3 shall apply to the removal of coal fromservice as the only main burner fuel being fired.

6.8.5.2.7.2

When shutting off coal with fuel gas or fuel oil remaining in service, a sequential shutdown of coalshall be accomplished in accordance with 6.8.5.2.3.2 through 6.8.5.2.3.4.

6.8.5.2.8 Reburn System Start.

6.8.5.2.8.1

The reburn system shall not be started until the requirements of 6.8.3.5.2 have been met and shallfollow the prerequisites of 6.8.5.2.1.3(B)(23) and 6.8.5.2.1.3(B)(24).

6.8.5.2.8.2* The furnace temperature characteristics as a function of heat input, steam flow, or other reliablecontrol signal shall be utilized as a permissive to initiate the reburn fuel injection.

6.8.5.2.8.3

The reburn fuel preparation and transport equipment shall be started in accordance with 9.6.2 fordirect-fired systems or 9.6.3 for storage systems, and all system purging or warm-up shall becompleted before any reburn fuel feeders are started.

6.8.5.2.8.4

If the reburn system admits reburn fuel through burners, then the starting sequence shall alsofollow that specified for burners in 6.8.5.2.1.3(B)(6) through 6.8.5.2.1.3(B)(14).

6.8.5.2.8.5

If the reburn system admits fuel by means other than through burners, then the starting sequenceshall be as follows:

(1) Include all reburn operation permissives required by this chapter.

(2) Follow the procedure specified by the manufacturer of the reburn system.

6.8.5.2.9 Shutdown Sequence — Reburn Fuel.

6.8.5.2.9.1

If the reburn system admits reburn fuel through burners, the shutdown sequence shall follow thatspecified for burners in 6.8.5.2.3.


Page 70 of 81



6.8.5.2.9.2

If the reburn system admits reburn fuel by means other than through burners, the shutdownsequence for dedicated and direct-fired pulverizers shall be as follows:

(1) Transfer combustion controls from automatic to manual control unless controls are designedand tuned to bring the system down to shutdown conditions.

(2) Reduce the reburn fuel flow to minimum.

(3) Shut down the reburn fuel supply system in accordance with Chapter 9.

(4) Close individual reburn shutoff valves.

6.8.5.2.10 Hazards of Residual Coal Charges in Pulverizers and Clearing After Shutdown.

6.8.5.2.10.1* The start-up procedure in Chapter 9 shall be followed unless it is positively known that thepulverizer is not charged with coal.

6.8.5.2.10.2

If the boiler is to be restarted and brought up to load without delay, the pulverizers with a chargeand their feeders shall be started in sequence, as dictated by the load in accordance with theprocedure described in Chapter 9.

6.8.5.2.10.3

If a delay in load demand is expected or undetermined but boiler conditions, including completionof purge, allow firing, the pulverizers shall be started and cleared in sequence in accordance withChapter 9.

(A) If during this sequence it becomes possible to fire at a rate greater than the capacity of onepulverizer operating within its range of operation for stable flame, one of the pulverizers and itsfeeder shall be placed into service to help burn the coal being injected from the remainingpulverizers that are being cleared.

6.8.5.2.10.4

The inerting procedure shall be prescribed by the pulverizer equipment manufacturer inaccordance with 9.6.4.2.1.

6.8.5.2.10.5

If firing is not to be initiated for an extended time, the pulverizer shall be cleaned manually ormechanically after having been cooled to ambient temperature and inerted before opening.

(A) To avoid the danger of an explosion when opening and cleaning any pulverizer, caution shall beused.

(B) The requirements in Chapter 9 shall be followed.




Page 71 of 81




CommitteeStatement:

The Task Group on Plasma Arc Igniters is tasked with reviewing the sequences (start, restart,and shutdown) as they relate to concentrated flame systems, with the intent of revising theseat the Second Draft stage. Also see Committee Inputs 307 and 309.

ResponseMessage:

Ballot Results



Page 72 of 81



Committee Input No. 322-NFPA 85-2017 [ Section No. 6.6.3.1.2 ]

6.6.3.1.2 Fuel Gas Supply Overpressure Protection.

6.6.3.1.2.1

The portion of the fuel supply system outside the boiler room shall be arranged to prevent excessivefuel gas pressure in the fuel-burning system, even in the event of failure of the main supply constantfuel pressure regulator(s).

6.6.3.1.2.2

The requirement in 6.6.3.1.2.1 shall be accomplished by providing full relieving capacity that isdischarged to atmosphere in accordance with 4.9.1 or by providing a high fuel gas pressure tripwhen full relieving capacity is not installed. [See Figure A.6.6.5.1.5.4(b) , which shows a typical fuelgas supply system outside the boiler room.]




CommitteeStatement:

The Fundamentals Committee has added requirements for overpressure protection in section4.10.1.2. The MBB Committee will review this material and consider removing theseoverpressure requirements at the Second Draft stage.

ResponseMessage:

Ballot Results



Page 73 of 81

Attachment G: Review of Correlating Committee Notes and Revisions


Page 74 of 81



Correlating Committee Note No. 23-NFPA 85-2017 [ Detail ]




CommitteeStatement:

The MBB Committee should review the substantiation and reconsider the revision toaddress the ballot comments received on this First Revision.

Ballot Results





Dexter, David E.


Affirmative AllBuckingham, Fred P.

Cannon, David Paul

Chappell, Timothy

Evely, Dale P.

Fleming, Ronald J.

Franks, James E.

King, David W.

Kinoshita, Masaaki

Lance, Gail J.

Mason, Dennis P.NFPA 85 (BCS-MBB) Second Draft Technical Committee Meeting

January 24, 2018 - New Orleans, LA Page 75 of 81



May, Daniel R.

Schmidt, Celso G.

Steen, Lloyd E.

Voss, Justin D.

Wolff, Marc A.

Wong, Henry K.

Yates, Harold R.


Page 76 of 81



Correlating Committee Note No. 24-NFPA 85-2017 [ Section No. 6.4.1 ]




CommitteeStatement:

The MBB Committee should review the title of 6.4.1.2.9 to clarify the intent, as it seemsinterlocks refers to the direct fired furnace, not the individual pulverizer subsystem.

Ballot Results





Dexter, David E.



Cannon, David Paul

Chappell, Timothy

Evely, Dale P.

Fleming, Ronald J.

Franks, James E.

King, David W.

Kinoshita, Masaaki

Lance, Gail J.

Mason, Dennis P.NFPA 85 (BCS-MBB) Second Draft Technical Committee Meeting

January 24, 2018 - New Orleans, LA Page 77 of 81



May, Daniel R.

Schmidt, Celso G.

Steen, Lloyd E.

Voss, Justin D.

Wolff, Marc A.

Yates, Harold R.

Affirmative with CommentWong, Henry K.

Correlating committee intent is correct but committee statement is not correct. Paragraphs 6.4.1.2.9.1through 6.4.1.2.9.3 clearly refer to Pulverizer Subsystem Trips not furnace trips. Should it be moved toChapter 9?


Page 78 of 81



First Correlating Revision No. 25-NFPA 85-2017 [ Section No. A.6.4.1.2.1 ]

A.6.4.1.2.1

In block 6 of Table 6.4.1.2.1(a), high furnace pressure could be caused by tube rupture, damperfailure, or explosion.

In block 8 of Table 6.4.1.2.1(a), the partial loss of flame described is potentially more hazardous atlower load levels. The decision regarding specific requirements or implementation of this tripshould be a design decision based on furnace configuration, total number of burners, number ofburners affected as a percentage of burners in service, arrangement of burners affected, interlocksystem interlocks , and load level. This trip is interlocked through flame supervisory equipment.

In block 9 of Table 6.4.1.2.1(a), the tables referenced describe the allowable differences inoperating procedures based on the classification of igniter being used. The following descriptionsof conditions are typical for both Table 6.4.1.2.1(b) and Table 6.4.1.2.1(c).

(1) Condition 1: An event in which, after a successful boiler purge, an attempt(s) to place the firstigniter in service fails

(2) Condition 2: An event in which an igniter(s) has been proven in service and subsequently alligniters are shut down without the attempt ever having been made to place a burner orpulverizer in service

(3) Condition 3: An event in which gas and/or oil fuel burners were started or attempted to bestarted and all burner valves were subsequently closed while igniters remain proven in service

(4) Condition 4: An event in which a pulverizer system(s) was started up or attempted to bestarted up and subsequently all pulverizer systems were shut down while igniters remainproven in service

(5) Condition 5: An event in which any fuel has been placed in service and all fuel subsequentlyshut off

In the event that any main fuel is shut down while any other main fuel remains proven in service,the all-fuel-off master fuel trip requirements do not apply.

In block 10a of Table 6.4.1.2.1(a), low drum water level has been included as a master fuel trip.Although low drum water level is not a combustion-related hazard, this code is the primaryresource for identifying BMS requirements, and not including a low drum level trip in Figure6.4.1.2.1 has created confusion with users of this code. A master fuel trip based on low drumwater level for drum-type boilers is commonly recognized good engineering practice.

In block 10b of Table 6.4.1.2.1(a) , circulating flow is also not a combustion-related hazard. Thelow circulating flow threshold could be a fixed value or a function of the boiler load based on theboiler manufacturer’s recommendations.

In block 10b 10c of Table 6.4.1.2.1(a), low waterwall flow is also not a combustion-relatedhazard. The low waterwall flow threshold could be a fixed value or a function of the boiler loadbased on the boiler manufacturer’s recommendations.




Page 79 of 81




CommitteeStatement:

Block 10b was added to Table 6.4.1.2.1(a) but explanation was not added to theannex.

Committee Notes:

Date Submitted ByJun 28,2017

Barbosa The block 10b para is all new.

Committee Input No. 179-NFPA 85-2017 [Section No. A.6.4.1.2.1]

Ballot Results





Dexter, David E.



Cannon, David Paul

Chappell, Timothy

Evely, Dale P.

Fleming, Ronald J.

Franks, James E.

King, David W.

Kinoshita, Masaaki

Lance, Gail J.

Mason, Dennis P.

May, Daniel R.

Schmidt, Celso G.

Steen, Lloyd E.

Voss, Justin D.

Wolff, Marc A.

Wong, Henry K.


Page 80 of 81



Yates, Harold R.


Page 81 of 81

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