Technical Committee on LP-Gases at Utility Gas PlantsTechnical Committee on LP-Gas at Utility Gas Plants Minutes Sheraton Denver Downtown 1550 Court Place Denver, CO 80202 August 7-8,

Technical Committee on LP-Gases at Utility Gas

Plants

Date: September 22, 2015 To: Technical Committee on LP-Gases at Utility Gas Plants From: Eric Nette, Staff Liaison/Engineer Re: NFPA 59 A2017 First Draft Meeting Agenda – October 28-30, 2015

Enclosed is the agenda package for NFPA 59 First Draft Meeting. Please ensure that you have reviewed the public input and the other agenda items in advance to prepare for discussion. The agenda and public input will be posted on the document information pages (www.nfpa.org/59next). Some items to have available during the meeting include:

Agenda package with public input A copy of NFPA 59 (visit the NFPA 59 Document information pages for your free committee

copy) previous copies of the standard

Optional items that are sometimes useful include:

Review of NFPA’s Process, www.nfpa.org/regs If you have any questions or comments, please feel free to reach me at (617) 984-7434 or by e-mail at [email protected]. I look forward to our meeting to begin the revision cycle!

Technical Committee on LP-Gases at Utility Gas Plants

AGENDA

NFPA 59 A2017 First Draft Meeting October 28-30, 2015

Crown Plaza Hotel & Suites Minneapolis Int’l Airport – Mall of America http://nfpa.adobeconnect.com/nette/

8:00 a.m. to 5:00 p.m. (Central Time Zone)

1. Meeting opening, introduction and attendance

2. Approval of Second Draft Meeting Minutes of August 7-8 and October 10, 2013 (Attachment A.

August 7-8 and October 10, 2013 Meeting Minutes).

3. Chair's remarks, Kevin Ritz

4. Staff Liaison update:

a. A2017 Schedule (Attachment B. A2017 Revision Cycle)

b. Committee Membership Update (Attachment C. LPU-AAA Membership)

c. Standards Process Review (Attachment D. NFPA Process – Quick Reference Guide)

5. New Business

a. Public Input for NFPA 59 (Attachment E. NFPA 59 - A2017 Public Input)

b. Development of First Revisions (Attachment D. NFPA Process – Quick Reference Guide)

6. Technical Committee Field Trip – Xcel Energy Plant, October 29, 2015 8:00 AM- 12:00 PM

7. Other business

8. Date/Location of Next Meeting. (Second Draft Meeting between June 1, 2016 and October 31, 2016)

9. Adjournment

Attachments:

A. August 7-8 and October 10, 2013 Meeting Minutes

B. A2017 – Revision Cycle

C. LPU-AAA Committee Membership

D. NFPA Process – Quick Reference Guide

E. NFPA 59 - A2017 Public Input

Attachment A: August 7-8

and October 10, 2013 Meeting Minutes

Technical Committee on LP-Gas at Utility Gas Plants

Minutes

Sheraton Denver Downtown

1550 Court Place Denver, CO 80202 August 7-8, 2013

Follow-up Teleconference: October 10, 2013

Part I, Attendance: Principal Members and Staff:

Kevin Ritz, Chairman, Baltimore Gas & Electric, MD Denise Beach, NFPA, MA Randy Ervin, Algas-SDI, WA (Aug 7-8 only) Adam Farnham, Exponent, Inc., WA (Aug 7-8 only) Richard Fredenburg, State of North Carolina, NC James Goodchild, Xcel Energy (rep AGA), MN Richard Hoffmann, Hoffmann & Feige, NY Stanley Kastanas, US Department of Transportation, MA (Aug 7-8 only) Ilona Korb, Duke Energy, OH Thomas Macdissi, Metropolitan Utilities District, NE (via teleconference) Charlie McDaniel, XL Global Asset Protection Services (via teleconference) Michael Osmundson, Lexicon Propane Group, AR (Aug 7-8 only) Nancy Pehrson, CenterPoint Energy, Inc., MN (via teleconference) John Ritzmann, VA (Aug 7-8 only) Steven Ruffcorn, Standby Systems, Inc., MN (Aug 7-8 only) Eric Smith, Nevada LP-Gas Board, NV David Stainbrook, Engineered Controls International Inc., NC (via teleconference) Michael Stroud, Vectren Energy Delivery, Inc., IN Bruce Swiecicki, National Propane Gas Association, IL Stephen Warren, Warren Mechanical LLC, SC (Aug 7-8 only) William Young, Superior Energy Systems, Ltd., OH (Aug 7-8 only) Rufus Youngblood, Ferrellgas LP, MO

Alternates, Non-voting members, and guests:

David Cook, Standby Systems, Inc., MN (Aug 7-8 only) John Heer, CenterPoint Energy, Inc. MN (via teleconference) Meghan Housewright, NFPA, DC (via teleconference) (Aug 7 only) Andrew Melville, Metropolitan Utilities District, NE (via teleconference) (Aug 7-8 only)

Part II, Minutes:

1. The meeting was called to order at 9:00 a.m. MDT. Chairman Ritz welcomed the committee members to the meeting and thanked them for their service.

2. The committee members and guests introduced themselves.

3. The minutes of the First Draft meeting held in September 2012 in Memphis, TN were accepted as written.

4. NFPA Staff reviewed the changes in membership that have occurred since August 2012 and gave a brief presentation on NFPA policies and procedures.

5. New Business. The chair changed the order of the agenda to address two items of new business first. Mr. Youngblood gave a brief update on the recent incident at a cylinder filling plant in Florida. Mr. Youngblood stated that new information would not be available until witness statements could be taken. Mr. Kastanas then gave a brief update on activities at the US Department of Transportation.

6. Old Business

A. Vaporizer distances task group. James Goodchild (chair), Randy Ervin, Adam Farnham, Charlie McDaniel, Kevin Ritz, and Bruce Swiecicki. NFPA Staff reported that a Code Fund project proposal had been submitted to the Fire Protection Research Foundation (FPRF). The project was approved as a “student project,” eligible for any grad student to apply for, but the project was not picked up. The task group will develop a more comprehensive research proposal to submit to the FPRF by Dec 15. The task group identified PHMSA as a possible source of co-funding for a more comprehensive study.

B. Relief valve sizing task group. The members are Steve Ruffcorn, David Cook, John Hoch, and Bill Young. The task group recommendations were reviewed and revisions were made to NFPA 59 as deemed appropriate by the committee. The Second Revisions will be available in the Second Draft Report, published no later than January 3, 2014 and available for download from www.nfpa.org/59.

C. Corrosion protection task group. The members are Richard Hoffmann (chair), Stanley Kastanas, Mike Stroud, Steve Warren, and Bill Young. As a result of the discussion on use of non-mandatory reference standards, specifically NACE SP-01-69, a task group was established on August 8 to recommend minimum mandatory standards that could be adopted in NFPA 59. The task group looked at NFPA 59-2012, NFPA 58-2014, and PHMSA regulations. The task group recommendations were reviewed in the follow-up teleconference on October 10, 2013, and revisions were made as deemed appropriate by the committee. The Second Revisions will be available in the Second Draft Report, published no later than January 3, 2014 and available for download from www.nfpa.org/59.

http://www.nfpa.org/59�


7. New Business

A. The committee reviewed the public comments and revised the document. The Second Revisions will be available in the Second Draft Report, published no later than January 3, 2014 and available for download from www.nfpa.org/59.

B. Scope and application task group. A task group was established to review the applications of NFPA 59. The committee notes that there are many plants with capacity greater than 4000 gal wc, but with no vaporizer. The task group should review these applications to determine if NFPA 58 requirements would be appropriate, and if so, what changes would be required in NFPA 59 to enable such plants to be built to NFPA 58. The committee recommended that the task group reach out to members of NARUC for participation. The members of the task group are Randy Ervin, John Heer, Tom Macdissi, Bruce Swiecicki, and Rufus Youngblood. No chair was identified for this task group.

C. Chairman Ritz offered a proposed dedication for Jim Stannard to be included in the next edition of the NFPA 59 Standard. The dedication was supported with minor revisions by the committee, Similar dedications for Mr. Stannard will be included in the NFPA 58 and NFPA 59A Standard based on the

8. Other Items. There were no other items to discuss.

9. Date/Location of Next Meeting. This concludes the committee work for the Annual 2014 revision cycle. The next meeting will be scheduled as needed.

10. Adjournment. The meeting was suspended at 3:00 pm MDT on August 8, reconvened at 10:00 am on October 10, and adjourned at 12:30 pm EDT on October 10, 2013.


Attachment B: A2017 Revision Cycle

NFPA 59 Revision Cycle KEY DATES Annual 2017

Public Input Closing July 6, 2015 (DONE)

Posting of First Draft March 7, 2016

Public Comment Closing May 16, 2016

Posting of Second Draft January 12, 2017

Notice of Intent to Make Motion (NITMAM) February 20, 2017

Issuance of Consent Standards May 12, 2017

NFPA Tech Session for standards with CAMS June 4-7, 2017

Issuance of Standards with CAMs August 10, 2017

Attachment C: LPU-AAA Committee

Membership

Address List No PhoneLP-Gases at Utility Gas Plants LPU-AAA

Eric Nette09/22/2015

LPU-AAA

Kevin L. Ritz

ChairBaltimore Gas & Electric Company1699 Leadenhall StreetBaltimore, MD 21230Alternate: Leo Dobbs

U 7/19/2002LPU-AAA

David G. Black

PrincipalBaker Engineering and Risk Consultants, Inc.11011 Richmond Avenue, Suite 700Houston, TX 77042

SE 07/29/2013

LPU-AAA

Mark Brownstein

PrincipalDuke Energy139 E 4th Street, Room 460ACincinnati, OH 45202

U 10/28/2014LPU-AAA

Randy Ervin

PrincipalAlgas-SDI151 South Michigan StreetSeattle, WA 98108Alternate: Mike Zimmer

M 1/10/2008

LPU-AAA

Adam Farnham

PrincipalUnified Investigations & Sciences, Inc.9316 Lakeview Avenue, Bldg. 21-CPO Box 98887Lakewood, WA 98496

SE 08/09/2012LPU-AAA

Richard G. Fredenburg

PrincipalState of North CarolinaDepartment of Agriculture & Consumer Services2 West Edenton Street (27601)1050 Mail Service CenterRaleigh, NC 27699-1050

E 1/15/1999

LPU-AAA

James R. Goodchild

PrincipalXcel EnergyWescott Gas Plant414 Nicollett AvenueMinneapolis, MN 55401American Gas AssociationAlternate: Richard Todd Rogers

U 4/14/2005LPU-AAA

Richard A. Hoffmann

PrincipalHoffmann & FeigeCroton River Executive Park3 Fallsview LaneBrewster, NY 10509

SE 1/1/1993

LPU-AAA

Stanley T. Kastanas

PrincipalUS Department of TransportationPipeline & Hazardous Materials Safety AdministrationPO Box 945Lowell, MA 01853-0945

E 4/3/2003LPU-AAA

Thomas J. Macdissi

PrincipalMetropolitan Utilities DistrictGas Production and Distribution1723 Harney StreetOmaha, NE 68102-1960Alternate: Andrew S. Melville

U 4/14/2005

LPU-AAA

Chris Mastrup

PrincipalBlue Star Gas880 North Wright RoadSanta Rosa, CA 95407

U 08/17/2015LPU-AAA

Charlie G. McDaniel

PrincipalGlobal Asset Protection ServicesRR1, Box 66, Hobbits GlennMasontown, WV 26542

I 7/16/2003

LPU-AAA

Michael H. Osmundson

PrincipalLexicon Propane Group185 Carmel RoadFlippin, AR 72634

SE 11/2/2006

1



LPU-AAA

Nancy C. Pehrson

PrincipalCenterPoint Energy, Inc.700 West Linden AvenuePO Box 1165Minneapolis, MN 55440Alternate: John Heer

U 4/4/1997LPU-AAA

James A. Petersen

PrincipalPetersen Engineering1301 Spruce StreetTexarkana, TX 75501-4327

SE 08/11/2014

LPU-AAA

John L. Ritzmann

PrincipalConsultant220 East Spring StreetAlexandria, VA 22301

SE 1/1/1993LPU-AAA

Steven D. Ruffcorn

PrincipalStandby Systems, Inc.1313 Plymouth Avenue NorthMinneapolis, MN 55411Alternate: David N. Cook

M 10/6/2000

LPU-AAA

Eric C. Smith

PrincipalNevada LP-Gas BoardPO Box 338Carson City, NV 89702

E 03/07/2013LPU-AAA

David J. Stainbrook

PrincipalEngineered Controls International, LLC100 RegO DriveElon, NC 27244

M 7/29/2005

LPU-AAA

Michael Lee Stroud

PrincipalVectren Energy Delivery Inc.640 Industrial DriveFranklin, IN 46131

U 3/21/2006LPU-AAA

Bruce J. Swiecicki

PrincipalNational Propane Gas Association21200 South LaGrange Road, Suite 353Frankfort, IL 60423National Propane Gas Association

IM 3/21/2006

LPU-AAA

Stephen Evans Warren

PrincipalWarren Mechanical LLCPO Box 70Summerton, SC 29148

IM 8/2/2010LPU-AAA

William J. Young

PrincipalSuperior Energy Systems, Ltd.13660 North Station RoadColumbia Station, OH 44028-9538Alternate: Mike Walters

M 1/1/1990

LPU-AAA

Rufus Youngblood

PrincipalFerrellgas LPOne Liberty PlazaLiberty, MO 64068

U 8/9/2011LPU-AAA

Todd M. Hetrick

Voting AlternateExponent, Inc.4580 Weaver Parkway, Suite 100Warrenville, IL 60555Voting Alt. to Exponent Rep.

SE 10/29/2012

LPU-AAA

David N. Cook

AlternateStandby Systems Inc.1313 Plymouth Avenue NorthMinneapolis, MN 55411Principal: Steven D. Ruffcorn

M 10/29/2012LPU-AAA

Leo Dobbs

AlternateBaltimore Gas & Electric Company10650 Harford RoadGlen Arm, MD 21057Principal: Kevin L. Ritz

U 7/23/2008

2



LPU-AAA

John Heer

AlternateCenterPoint Energy, Inc.700 West Linden AvenueMinneapolis, MN 55403Principal: Nancy C. Pehrson

U 10/29/2012LPU-AAA

Andrew S. Melville

AlternateMetropolitan Utilities District1723 Harney StreetOmaha, NE 68102-1907Principal: Thomas J. Macdissi

U 10/20/2010

LPU-AAA

Richard Todd Rogers

AlternateAGL Resources12860 East Cherokee DriveBall Ground, GA 30107American Gas AssociationPrincipal: James R. Goodchild

U 10/29/2012LPU-AAA

Mike Walters

AlternateSuperior Energy Systems Ltd.13660 Station RoadColumbia Station, OH 44028-9538Principal: William J. Young

M 04/08/2015

LPU-AAA

Mike Zimmer

AlternateAlgas-SDI151 South Michigan StreetSeattle, WA 98108Principal: Randy Ervin

M 10/28/2008LPU-AAA

Eric Nette

Staff LiaisonNational Fire Protection Association1 Batterymarch ParkQuincy, MA 02169-7471

01/06/2015

3

Attachment D: NFPA Process – Quick

Reference Guide

New Process – Quick Reference Guide For additional information on the Regulations visit: www.nfpa.org/Regs

There are only three actions a TC can take at the First Draft (ROP) meeting:

1. Resolve a Public Input (no change to the document) 2. Create a First Revision (change to the document) 3. Create Committee Input

Resolve Public Input (no change to the document)

TC must provide a response (Committee Statement/CS) to ALL Public Input (proposal).

CS for not doing what is suggested

Sample Motion: “I make a motion to resolve PI#_ with the following committee statement__.” Approval by meeting vote (simple majority). Not subject to Ballot.

Create a First Revision (change to the document)

TC must create a First Revision (FR) for each change they wish to make to the document, either using Public Input for the basis of the change or not using a Public Input for the basis. One or more Public Input can be considered for the FR.

All Public Input requires a response

TC can use a Public Input for basis i. Sample Motion: “I make a motion to revise section __ using PI#_ as the

basis for change.” Approval by meeting vote (simple majority) and final approval through ballot.

TC develops revision without a Public Input for basis i. Sample Motion: “I make a motion to revise section __ as follows___.”

Approval by meeting vote (simple majority) and final approval through ballot.

First Revisions require a committee statement Committee Input

TC may create a Committee Input (CI). This replaces the old system “rejected” Committee Proposals. CIs will get printed in the report but will not be balloted or shown as a change in the draft. CIs are used to solicit public comments and/or as a placeholder for the comment stage.

i. Sample Motion: “I make a motion to create a CI with a proposed revision to section__ as follows___.” Approval by meeting vote (simple majority). Not subject to ballot.

Requires a committee statement to explain the intent of making a CI.

Comparison to Previous Process:

PREVIOUS ACTIONS CURRENT PROCESS ACTIONS SAMPLE MOTION Accept or any variation of Accept (APA, APR, APP) on a public proposal

1) Committee generates a First Revision and Substantiation (CS) for change 2) Committee provides response (CS) to each PI that is associated with the revision

1) “I make a motion to revise section __ using PI#_ as the basis for change.”

2) “ I make a motion to resolve PIs#_ through ## with the following statement__”

Rejected Public Proposal Committee provides response (CS) to PI

“I make a motion to resolve PI#_ with the following committee statement__.”

Accepted Committee Proposal Committee generates a First Revision and Substantiation (CS) for change

“I make a motion to revise section __ as follows___.” Committee generates a statement for reason for change

Rejected Committee Proposal Committee generates a Committee Input (CI) and reason (CS) for proposed change

“I make a motion to create a CIwith a proposed revision to section__ as follows___.” Committee generates a statement for reason for CI.

Notes: 1) All meeting actions require a favorable vote of a simple majority of the members present. 2) All First Revisions will be contained in the ballot and will require a 2/3 affirmative vote to

confirm the meeting action. 3) Only the First Revisions will be balloted. PIs and CIs will be contained in the report but will

not be balloted. 4) Comments may be submitted on all PIs, FRs and CIs

Term Comparison between Current and Old:

CURRENT TERM OLD TERM

Input Stage ROP Stage

Public Input (PI) Proposal

First Draft Meeting ROP Meeting

Committee Input Committee Proposal that Fail

Ballot

Committee Statement (CS)

Committee Statement

First Revision (FR) Committee Proposal or Accepted

Public Proposal

First Draft Report ROP

First Draft ROP Draft

Comment Stage ROC Stage

Public Comment Public Comment

Second Draft Meeting ROC Meeting

Committee Comment Committee Comment that Fail

Ballot

Committee Action Committee Action

Second Revision Committee Comment or Accepted

Public Comment

Second Draft Report ROC

Second Draft ROC Draft

Note: The highlighted terms are the ones that will be most applicable at the First Draft Meeting.

Attachment E: NFPA 59 – A2017 Public

Input

Public Input No. 1-NFPA 59-2015 [ Global Input ]

Throughout standard remove references to the following and replace with thefollowing:

(1) ANSI/API and replace with API.

(2) ANSI/UL and replace with UL.

(3) API # and replace with API SPEC, STD, or RP #.

Statement of Problem and Substantiation for Public Input

Correlates with PI-2 and PI-3

Related Public Inputs for This Document

Related Input Relationship

Public Input No. 2-NFPA 59-2015[Section No. 2.3]

Referenced current SDO names, addresses, standard names,numbers, and editions.

Public Input No. 3-NFPA 59-2015[Section No. F.1.2]


Submitter Information Verification

Submitter Full Name: Aaron Adamczyk

Organization: [ Not Specified ]

Street Address:

City:

State:

Zip:

Submittal Date: Sat Feb 07 19:49:55 EST 2015

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

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Public Input No. 5-NFPA 59-2015 [ Section No. 1.1.2 ]

1.1.2

Installations Utility Gas Plant installations that have LP-Gas storage containers having an aggregate water

capacity of 4000 gal (15.14 m3) or less, or of any size that do not have a vaporizer, shall conform to NFPA58, Liquefied Petroleum Gas Code.

Additional Proposed Changes

File Name Description Approved

PC_9_Held.pdf PC No. 9 - A2014


NOTE: This Public Input appeared as Public Comment No. 9 which was "rejected but Held" in the Second Draft Report for NFPA 59 and per the regs at 4.4.8.3.1.

Most small installations of reticulated gas systems serving small networks or housing clusters have been installed under NFPA 58 which has adequate provisions for safety and protection for such systems. Adifferent factor is introduced into systems utilizing a vaporizer because of the possibility of liquid entering the distribution system. This factor necessitates a person with special knowledge to oversee the installation, operation and maintenance of the system. In vapor only systems this same level of expertise is not necessary and adequate safety is provided for under NFPA 58.


Submitter Full Name: TC on LPU-AAA

Organization: Technical Committee on LP-Gases at Utility Gas Plants

Street Address:

City:

State:

Zip:

Submittal Date: Thu Apr 09 11:27:07 EDT 2015


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Public Input No. 2-NFPA 59-2015 [ Section No. 2.3 ]

2.3 Other Publications.

2.3.1 API Publications.

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

API SPEC 6FA, Specifications for Fire Tests for Valves, 2008 3rd edition, 1999, Reaffirmed 2011 .

API STD 607/ISO 10497 , Fire Test for Soft-Seated Quarter-Turn Valves , 2005 and ValvesEquipped with Nonmetallic Seats, 6th Edition, 2010 .

API STD 620, Design and Construction of Large, Welded, Low-Pressure Storage Tanks, 2008 with 2009addendum 1, 2010 addendum 2, and 2012 addendum 3 2013, Amendment 1, 2014 .

2.3.2 ASCE Publications.

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

ASCE 7–05 7– 10 , Minimum Design Loads for Buildings and Other Structures, 2005 with Supplement #110th edition, 2010, Errata, 2011, and Revised Commentary 2013 .

2.3.3 ASME Publications.

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

ASME Boiler and Pressure Vessel Code, 1949 and 2010 editions with July 2011 supplements 2015 .

ASME B31.3, Process Piping,2010 2014 .

2.3.4 ASTM Publications.

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

ASTM A 47 A47 /A47M , Standard Specification for Ferritic Malleable Iron Castings, 2009 1999,Reapproved 2014 .

ASTM A 395 A395 /A395M , Specification for Ferritic Ductile Iron Pressure-Retaining Castings for Use atElevated Temperatures,2009 1999, Reapproved 2014 .

ASTM A 536 A536 , Specifications for Ductile Iron Castings,2009 1984, Reapproved 2014 .

2.3.5 UL Publications.

Underwriters Laboratories Inc., 333 Pfingsten Road, Northbrook, IL 60062-2096.

ANSI/ UL 132, Standard on Safety Relief Valves for Anhydrous Ammonia and LP-Gas, 2007, with Revised2010 amendment .

2.3.6 U.S. Government Publications.

U.S. Government Printing Government Publishing Office, Washington, DC 20402.

Title 49, Code of Federal Regulations, Part 192, “Pipeline Safety Law.”

2.3.7 Other Publications.

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


Referenced current SDO names, addresses, standards names, numbers, and editions.



Public Input No. 1-NFPA 59-2015 [Global Input]


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Public Input No. 3-NFPA 59-2015 [Section No. F.1.2]




Street Address:

City:

State:

Zip:



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Public Input No. 10-NFPA 59-2015 [ New Section after 2.3.1 ]

2.3.1 ACI Publications. American Concrete Institute, P.O. Box 9094, Farmington Hills, MI48333.

ACI 376 Code requirements for Design and Construction of Concrete Structures for the Containment ofRefrigerated Gases First Edition 2010 with Addendum 1, July 2013


Insert ahead of 2.3.1 and renumber remaining. This new incorporated by reference standard is necessary to align with PI 6.3.4 which requires the application of this standard for the construction of foundations for refrigerated LPG storage tank systems.


Submitter Full Name: Michael Bellman

Organization: American Gas Association

Street Address:

City:

State:

Zip:

Submittal Date: Mon Jun 22 08:47:28 EDT 2015


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2.3.1 API Publications.


API 6FA, Specifications for Fire Tests for Valves, THIRD EDITION, APRIL 1999, ERRATA 1: DECEMBER2006 ERRATA 2: DECEMBER 2008 , REAFFIRMED, SEPTEMBER 2011 .

API 607/ISO 10497, Fire Test for Soft-Seated Quarter-Turn Valves, 2005 Sixth Edition, September 2010 .

API 620, Design and Construction of Large, Welded, Low-Pressure Storage Tanks, 2008 with 2009addendum 1, 2010 addendum 2, and 2012 addendum 3. Twelth Edition October 2013 with Addendum 1November 2014 .

API 625, Tank Systems for Refrigerated Liquefied Gas Storage, First Edition, 2010, with addendum 1, July 1,2013


The new is necessary to support the PI on 6.1 and 6.1.1 that identified the API 625 standard and updates to latest editions of API 6FA, API 607, and API 620.



Public Input No. 58-NFPA 59-2015 [Chapter 6]




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2.3.2 ASCE Publications.

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

ASCE 7–05 7–10 , Minimum Design Loads for Buildings and Other Structures, 2005 with Supplement#1 2010 Third Printing; Incorporated Errata : January 11, 2011; Includes Supplement 1, and revisedcommentary, 2013 .


Recognizes the latest edition of the ASCE 7 standard




Street Address:

City:

State:

Zip:



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2.3.3 ASME Publications.

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

ASME Boiler and Pressure Vessel Code, 1949 and 2010 and 2013 editions with July 2011supplements 12/8/2014 Section VIII Errata .

ASME B31.3, Process Piping,2010 2014 .


Recognizes the latest editions of the ASME standards




Street Address:

City:

State:

Zip:



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2.3.4 ASTM Publications.

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

ASTM A 47, Standard Specification for Ferritic Malleable Iron Castings, 2009 1999, Reapproved 2014 .

ASTM A 395, Specification for Ferritic Ductile Iron Pressure-Retaining Castings for Use at ElevatedTemperatures,2009. 1999, Reapproved 2014

ASTM A 536, Specifications for Ductile Iron Castings,2009 1984, Reapproved 2014 .


Recognizes the latest editions of the ASTM standards




Street Address:

City:

State:

Zip:



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ANSI/UL 132, Standard on Safety Relief Valves for Anhydrous Ammonia and LP-Gas, 2007, with 2010amendment Seventh Edition; Reprint with Revisions Through and Including February 9, 2015 .


Recognizes the latest editions of the UL standard




Street Address:

City:

State:

Zip:



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ANSI/UL 132, Standard on Safety Relief Valves for Anhydrous Ammonia and LP-Gas, 2007, with 2010amendment revised 2015 .


The proposed change reflect revisions/update to the UL Standard.


Submitter Full Name: RONALD FARR

Organization: UL LLC

Street Address:

City:

State:

Zip:



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3.XXX Component

Component. A uniquely identifiable part, piece, assembly or subassembly that performs a distinctive andnecessary function in the operation of a LP-Gas facility or system. Components are usually removable inone piece and are considered indivisible for a particular purpose or use.


Adding the definitions of Component incorporates terminology commonly used in the CFR 49 Part 192 code. Orienting the reader towards a hierarchy of definitions that include Component, Facility, and Plant provides clear understanding of the intent of the standard.



Public Input No. 22-NFPA 59-2015 [Section No. 4.8.2.2]




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Public Input No. 20-NFPA 59-2015 [ New Section after 3.3.11.2 ]

3.3.XXX Facility

Facility: A number of components, installed and designed to function as an independent process part of aLP-Gas plant.


Adding the definition will orient the reader towards a hierarchy of definitions that include Component, Facility, and Plant provides clear understanding of the intent of the standard.



Public Input No. 21-NFPA 59-2015 [Section No. 4.8.2 [Excluding any Sub-Sections]]

Public Input No. 35-NFPA 59-2015 [Section No. 7.8.1]









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3.3.XX Plant

A "Plant" is the entirety of facilities, buildings and related structures co-located on a single property.


Part 192 does not have a definition for “Plant”. The existing definition is being modified since it does not define what a “plant” is, but instead defines only what a Utility LP-Gas Plant is. Defining the plant as a collection of facilities, buildings and property provides conciseness in the application of code requirements. Adding the definitions of Plant incorporates terminology commonly used in the CFR 49 Part 192 code. Orienting the reader towards a hierarchy of definitions that include Component, Facility, and Plant provides clear understanding of the intent of the standard.




Street Address:

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3.3 Process Pressure Vessel

A vessel other than those used as a container for LPG (as defined in 3.3.9) that operates at pressuresexceeding 15 psig which is used as but not limited to part of the LPG loading/unloading process or forseparation, filtering, mixing/blending in the propane/propane-air supply process.


The new definition supports new text proposed for Chapter 7 header and PI on 7.9




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3.3.30 Refrigerated Storage Tank System.

3.3.30 Refrigerated Storage Tank System. Low pressure (less than 15 psi) equipment designed for the purposeof storing refrigerated LPG consisting of one or more containers, together with various accessories, appurtenances, andinsulation


The new definition is necessary to support the PI on 6.1 and 6.1.1 that identified the API 625 standard







Street Address:

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3.3.36* Utility Gas Plant.

A plant that stores and vaporizes LP-Gas for distribution that supplies either LP Gas or LP -Gas gas–airmixtures to a gas distribution system of 10 or more customers.


This change would eliminate the applicability of the code to Undiluted LP Gas systems. Historically, the regulatory agencies have never recognized NFPA 59 to be applicable to these systems until just recently. The systems were not built to be compliant with 59 and the industry itself is experiencing an unnecessary burden by being made to comply. This proposal will provide a clear delineation of the scopes of NFPA 58 and NFPA 59 and as a result will allow the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) to easily adopt the new editions of both NFPA 58 and NFPA 59, thereby addressing the major stumbling block to consistent enforcement of 49 CFR Part 192.


Submitter Full Name: RUFUS YOUNGBLOOD

Organization: FERRELLGAS LP

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Submittal Date: Mon Jul 06 11:44:57 EDT 2015


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Public Input No. 57-NFPA 59-2015 [ Section No. 4.5.2.2 ]


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4.5.2.2 *


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Fixed electrical equipment and wiring installed within the classified areas specified in Table 4.5.2.2 shallcomply with Table 4.5.2.2 and shall be installed in accordance with NFPA 70, National Electrical Code.

Table 4.5.2.2 Electrical Area Classification

Part Location Extent of Classified Area a

Equipment Shallbe Approved for

NationalElectrical Code,

Class I a , Group

D b

A

Unrefrigerated containersother than cylinders andASME vertical containers ofless than 1000 lb (454 kg)water capacity

Within 15 ft (4.6 m) in all directions fromconnections, except connections otherwisecovered in Table 4.5.2.2

Division 2

B

Refrigerated storagecontainers

Within 15 ft (4.6 m) in all directions fromconnections otherwise covered in Table 4.5.2.2

Division 2

Area inside dike to the level of the top of thedike

Division 2

C c

Tank vehicle and tank carloading and unloading

Within 5 ft (1.5 m) in all directions fromconnections regularly made or disconnectedfor product transfer

Division 1

Beyond 5 ft (1.5 m) but within 15 ft (4.6 m) inall directions from a point where connectionsare regularly made or disconnected and withinthe cylindrical volume between the horizontalequator of the sphere and grade (see FigureA.4.5.2.2)

Division 2

D

Gauge vent openings otherthan those on cylinders andASME vertical containers ofless than 1000 lb (454 kg)water capacity

Within 5 ft (1.5 m) in all directions from point ofdischarge

Division 1

Beyond 5 ft (1.5 m) but within 15 ft (4.6 m) inall directions from point of discharge

Division 2

E Relief device discharge

other than those on cylinders and ASME vertical containers of less than 1000 lb (454 kg) water capacityand vaporizers

Within direct path of discharge

Within 5 feet (1.5m) in all directionsform point of discharge

Beyond 5 feet (1.5m) but within 15feet (4.5m) in all directions form pointof discharge

Division 1 ( Note: Fixed electrical equipment shouldpreferably not be installed ) .

Division 1

Division 2

F c

Pumps, vapor compressors, gas–airmixers and vaporizers (other thandirect-fired or indirect-fired with anattached or adjacent gas-fired heatsource)

Indoors without ventilationEntire room and any adjacent room not separated by agastight partition

Division1

Within 15 ft (4.6 m) of the exterior side of any exteriorwall or roof that is not vaportight or within 15 ft (4.6 m)of any exterior opening

Division2


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Indoors with ventilationEntire room and any adjacent room not separated by agastight partition

Division2

Outdoors in open air at or abovegrade

Within 15 ft (4.6 m) in all directions from this equipmentand within the cylindrical volume between thehorizontal equator of the sphere and grade (seeFigure A.4.5.2.2)

Division2

G

Pits or trenches containing or locatedbeneath LP-Gas valves, pumps,vapor compressors, regulators, andsimilar equipment

Without mechanical ventilation Entire pit or trenchDivision

1

Entire room and any adjacent room not separated by agastight partition

Division2

Within 15 ft (4.6 m) in all directions from pit or trenchwhen located outdoors

Division2

With mechanical ventilation Entire pit or trenchDivision

2

Entire room and any adjacent room not separated by agastight partition

Division2

Within 15 ft (4.6 m) in all directions from pit or trenchwhen located outdoors

Division2

H

Pipelines and connections containingoperational bleeds, drips, vents, ordrains

Within 5 ft (1.5 m) in all directions from point ofdischarge

Division1

Beyond 5 ft (1.5 m) from point of discharge, same aspart F of this table

I Piers and wharvesWithin 5 ft (1.5 m) in all directions from connectionsregularly made or disconnected for product transfer

Division1

Beyond 5 ft (1.5 m) but within 15 ft (4.6 m) in alldirections from a point where connections are regularlymade or disconnected and within the cylindricalvolume between the horizontal equator of the sphereand the vessel deck (see Figure A.4.5.2.2)

Division2

aThe classified area shall not extend beyond an unpierced wall, roof, or solid vaportight partition.

bSee Article 500 Hazardous (Classified) Locations, in NFPA 70, National Electrical Code, for definitions ofclasses, groups, and divisions.

cSee A.4.5.2.2.


Changing only Table 4.5.2.2 Para E: The rationale for not identifying an electrical arear classification near safety relief valves has been based on the annex information in A.10.1 that states based on details in API 521 6.3.2.2, (2007 edition w/May 2008 Addendum) that during the discharge from a safety relief valve that the discharge velocity is such that sufficient volumes of air is entrained in the discharge stream and therefor dilutes the mixture to below the LEL. While this is stated in API 521, it is only applicable to safety relief valves discharging vapor. API 521 6.3.2.3, and 6.3.2.4 additionally describes the discharges of mists and liquids and goes onto state that the same air entrainment activity is not expected to occur and flammable concentrations in the area near the valves should be further evaluated. Safety relief valves in NFPA 59 facilities can be either in vapor or liquid service and for this reason the table has been changes to reflect the minimum hazardous area classifications. A PI for editing the annex material in A.10.1 shall also be submitted to clarify that the dilution phenomenon is only applicable to vapor service valves.



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Public Input No. 55-NFPA 59-2015 [Sections A.10.1, A.11.2.3]




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Public Input No. 21-NFPA 59-2015 [ Section No. 4.8.2 [Excluding any Sub-Sections] ]

Each new and modified plant modified facility shall retain records of materials of construction for processequipment piping systems containing LP-Gas and other flammable fluids, including their supporting systemand foundations.


Standardizing the definitions of plant and facility see 20-NFPA 59-2015



Public Input No. 20-NFPA 59-2015 [New Section after 3.3.11.2]




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4.8.2.2

Components such as pumps, compressors, valves, or similar assemblies components are not required tohave records of materials of construction. These records shall document that the assembled componenthas been designed and constructed per design with materials appropriate for the duty they serve.


standardizing the definition of components



Public Input No. 19-NFPA 59-2015 [New Section after 3.3.8]




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4.9 Corrosion Protection

4.9.1 All metallic components carrying flammable fluids and gases that could have theirintegrity or reliability adversely affected by external, internal, or atmospheric corrosionduring their intended service life shall be protected from corrosion.

4.9.2 Components whose integrity or reliability could be adversely affected by corrosionshall be either of the following:

(1) Protected from corrosion in accordance with 4.9.1 through 4.9.5 as applicable

(2) Inspected and replaced under a program of scheduled maintenance

4.9.3 Atmospheric Corrosion Control.

Each exposed component that is subject to atmospheric corrosive attack shall be protectedfrom atmospheric corrosion by either of the following:

(1) A material that has been designed to resist the corrosive atmosphere involved

(2) Coating or jacketing

4.9.4 External Corrosion Control: Buried or Submerged Components.

4.9.4.1 Each buried or submerged component that is subject to external corrosive attackshall be protected from external corrosion by:

(1) Material that has been designed to resist the corrosive environment involved; or

(2) Either of the following means:

(a) * An external protective coating designed and installed to prevent corrosion attack

(b) * A cathodic protection system designed to protect components in their entirety

4.9.4.2 Where cathodic protection is applied, components that are electricallyinterconnected shall be protected as a unit.

4.9.5 Internal Corrosion Control.

Each component that is subject to internal corrosive attack must be protected from internalcorrosion by one of the following:

(1) Material that has been designed to resist the corrosive fluid involved

(2) Coating, inhibitor, or other means

4.9.6 Interference Currents.

4.9.6.1 Each component that is subject to electrical current interference shall be protectedby a continuing program to minimize the detrimental effects of interference currents.

4.9.6.2 Each cathodic protection system shall be designed and installed so as tominimize any adverse effects it might cause to adjacent metal components.

4.9.6.3 Each impressed current power source shall be installed and maintained to preventadverse interference with communications and control systems.



PC_14_held.pdf PC 14 (A2014)


NOTE: This PI appeared as "rejected but held" on Comment No. 9 in the A2014 Second Draft report and for NFPA 59


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Sections 12.2 to 12.2.6.3 in chapter 12 specify requirements for installation of corrosion protection and therefore should not be placed in the Maintenance chapter. Move these paragraphs to a new 4.9 in chapter 4.


Submitter Full Name: TC on LPU-AAA

Organization: Technical Committee on LP-Gases at Utility Gas Plants

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Submittal Date: Thu Apr 09 11:41:17 EDT 2015


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5.6.1

Containers once installed underground or aboveground that have been out of service for more than 1 yearshall not be reinstalled aboveground or underground unless they withstand , without distortion, hydrostaticpressure retests a successful hydrostatic pressure retest at the pressure specified for the originalhydrostatic test as required by the code under which they were constructed.


There is no practical way to verify "distortion" of the storage tank, and this text is not common language for these types of tests




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5.6.1

Containers once installed underground or aboveground that have been out of service for more than 1 yearshall not be reinstalled aboveground or underground unless they withstand, without distortion, hydrostaticpressure retests at the pressure specified for the original hydrostatic test as required by the code underwhich they were constructed are given a thorough inspection in accordance with the ANSI/NB23 NationalBoard Inspection Code .


The requirement is too restrictive and should be revised. Many ASME tanks in the propane industry are left out of service for long periods of time with no adverse effect.




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5.8.1

Point of transfer shall be at least 75 ft (23 m) from uncontrolled sources of ignition, process areas, and 25 ft(7.62 m) from control buildings, offices, shops, and other occupied or important plant structures, other thanequipment directly associated with the transfer operation.


The distance requirement is too restrictive and should be revised. NFPA 58 allows Point of Transfer spacing of 25 to buildings with other than at least 1 hour fire rated walls.




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Chapter_6_for_attachment.doc

SUGGESTED Reorganization and rewrite of NFPA 59 Chapter 6 from American Gas Association, Supplemental Gas Committee


In the 1998 edition of NFPA 59, NFPA 59 began extracting the entire refrigerated container section from NFPA 58. Prior to the 1998 edition of NFPA 59, the NFPA 59 standard included very similar text that was in NFPA 58 but it was not officially extracted from NFPA 58. Over the last several years, the standards development organizations have developed a series of including one new standard (API 625) and revising two existing standards (API 620 and ACI 376) such that a low pressure refrigerated storage container must apply all three standards to design, engineer, construct, examine and test a new storage tank.









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Submittal Date: Thu Jun 25 07:23:46 EDT 2015


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kshea

Text Box

Public Input No. 58-NFPA 59-2015 [ Chapter 6 ] See the Following Pages for Recommendation

kshea

Text Box

SUGGESTED Reorganization and rewrite of NFPA 59 Chapter 6 from American Gas Association, Supplemental Gas Committee

Public Input Recommends (check one): X new text X revised text X deleted text

3. Proposed Text of Public Input (include proposed new or revised wording, or identification of wording to be deleted): [Note:

Proposed text should be in legislative format; i.e., use underscore to denote wording to be inserted (inserted wording) and strike-

through to denote wording to be deleted (deleted wording).]

Chapter 6 Refrigerated Containers 6.1 Scope. This Chapter presents the requirements for the design, engineering, construction, marking, inspection, testing, and operation of

stationary low pressure API 625 LPG refrigerated storage tanks systems and refrigerated ASME LPG storage containers

6.2 Refrigerated Containers Designed to Operate below 7 psi (103KPa) and Greater than 5000 bbls (800 cubic meters)[KLR1]

6.2.1 Container Design, Material, and Construction, Examination, Tank Commissioning Testing, and Monitoring Requirements.

[58:12.1.1]

6.2.1.1 Storage tank systems designed to operate below 7 psi (103 KPa) and greater than 5000 bbls shall be in accordance with the requirements of

API 625, Tank Systems for Refrigerated Liquefied Gas Storage, and the additional provisions of this chapter and,

6.2.1.2 Based on requirements of API 625 the metal containers that are part of an refrigerated storage tank system shall comply with API 620,

Design and Construction of Large,Welded, Low-Pressure Tanks and any additional provisions of this chapter.

6.2.1.3 Should any conflict exist between the above requirements and others in this Chapter, the most stringent requirement shall apply.[KLR2]

6.2.1.4 Materials used in refrigerated metallic containers shall be selected from those included in the following:

(1) ASME Boiler and Pressure Vessel Code, Section VIII (materials that maintain their integrity at the boiling temperature of the liquid stored)

(1) API 625 Tank Systems for Refrigerated Liquefied Gas Storage requires that API Standard 620, Design and Construction of Large, Welded,Low-

Pressure Storage Tanks, Appendix R or Appendix Q be utilized [58:12.1.1.2]

(A) Containers designed to operate below 15 psi (103 kPa) shall be in accordance with API Standard 620, Design and Construction of Large,

Welded, Low-Pressure Storage Tanks, including Appendix R. [58:12.1.1.3]

(B) Where austenitic stainless steels or nonferrous materials are used, API Standard 620, Design and Construction of Large, Welded, Low-Pressure

Storage Tanks, Appendix Q, shall be used in the selection of materials. [58:12.1.1.4]

6.2.2 Container Design Temperature and Pressure. [58:12.1.2]

6.2.2.1 The design pressure/vacuum maximum/minimums allowable working pressure shall include a margin above/below the operating pressure.

6.2.2.2 The design pressure of ASME containers shall include a minimum 5 percent of the absolute vapor pressure of the LP-Gas at the design

storage temperature. The margin (both positive and vacuum) for low-pressure API Standard 620, Design and Construction of Large, Welded, Low-

Pressure Storage Tanks, vessels shall include the following:

(1) Control range of the boil-off handling system

(2) Effects of flash or vapor collapse during filling operations

(3) Flash that can result from withdrawal pump recirculation

(4) Normal range of barometric pressure changes

[58:12.1.2.1]

6.2.2.3 The design temperature for those parts of a refrigerated LP-Gas container that are in contact with the liquid or refrigerated vapor shall be

equal to or lower than the boiling point of the product to be stored at atmospheric pressure. A temperature allowance shall be made for the

composition of

the liquid to be stored when it is flashed into the vapor space of a tank. [58:12.1.2.2]

6.2.3 Design Load and Load Combinations

6.2.3.1 Design load and load combinations shall be based upon requirements in API 625 and API 620 which include but are not limited to;

1) dead load - the weight of the tank or tank component, including any insulation, lining, 2) hydrostatic and pneumatic tests - the load due to conducting the tank commissioning tests 3) loads from connected piping 4) loads from platforms and stairways 5) minimum roof live load - 20 lb/ft2 on the horizontal projected area of the roof. 6) pressure - the maximum positive gauge pressure 7) pressure - the maximum partial vacuum given. The maximum partial vacuum shall be at least 1 in. wc. 8) stored liquid- gauge pressure (lb/in.2) resulting from the liquid head of the liquid including maximum product density. All liquid levels from empty to the maximum liquid level shall be considered. 9) snow - The ground snow load (lb/ft2) shall be determined from ASCE 7. 10)Wind Loading. [58:12.3.1] - 6.3.1.1 The design wind loading on refrigerated LP-Gas containers shall be in accordance with the projected area at

various height zones above ground in accordance withASCE 7, Minimum Design Loads for Buildings and Other Structures and based on a mean

occurrence interval of 100 years. [58:12.3.1.1]

6.3.1.2 Design wind speeds shall be based on a mean occurrence interval of 100 years. [58:12.3.1.2]

11) 6.3.2 Seismic Loading. [58:12.3.2]

(A) 6.3.2.1 The design seismic loading on refrigerated LP-Gas containers shall be in accordance with API 625, API 620 and ASCE 7, Minimum

Design Loads for Buildings and Other Structures. [58:12.3.2.1]

B) 6.3.2.2 A seismic analysis of the proposed installation shall be performed as required by API 625 Section 6.6 and made that meets the approval of

the authority having jurisdiction. [58:12.3.2.2]

6.1.1.52.4 All new construction shall incorporate on any bottom or side penetrations that communicate with the liquid space of the container either an

internal emergency shutoff valve or a back check valve in-tank valves . Any emergency shutoff valve shall be incorporated into a facility emergency

shutdown system and be capable of being operated remotely. [58:12.1.1.5]See API 625 specific design and installation of penetrations including in-

tank valve and nozzle criteria.

6.3.42.5 Foundations. [58:12.3.4]

6.3.42.5.1 Foundations for refrigerated Refrigerated aboveground containers shall be designed and constructed per API 625 shall be designed

installed on foundations that have been engineered for site soil conditions and loadings. [58:12.3.4.1] which requires foundations be designed,

constructed and inspected based on ACI 376 Code requirements for Design and Construction of Concrete Structures for the Containment of

Refrigerated Gases in addition to foundation requirements in this code.

6.3.4.2 Prior to the start of design and construction of the foundation, a subsurface investigation shall be conducted by a soils engineer. Foundations

shall be designed by an engineer who is experienced in foundations and soils. [58:12.3.4.2]

6.3.4.3 Where product storage is at less than 30°F (1.1°C), the foundation and the container bottom shall comply with the following:

(1) The foundation design and the container bottom insulation shall prevent damage to the container from frost heave.

(2) If the refrigerated LP-Gas container under bottom foundation and insulation are in contact with the soil, and the soil temperature can be less than

32°F (0°C), a heating system shall be installed to prevent the soil temperature from falling below 32°F (0°C).

(3) The under-container heating system shall be designed to allow both functional and performance monitoring.

(4) The under-container temperature shall be observed and logged at least weekly.

(5) Where the foundation has a discontinuity, such as bottom piping, the heating system in that zone shall be designed for the discontinuity.

(6) The under-container heating system shall be installed so that any heating elements or temperature sensors used for control can be replaced while

the container is in service.

(7) Provisions shall be incorporated to minimize the effects of moisture accumulation in the conduit and other forms of deterioration within the

conduit or heating element.

[58:12.3.4.3]

6.3.4.42.5.2 The r Refrigerated LP-Gas container foundation shall be periodically monitored for settlement during the life of the facility.

[58:12.3.4.4]

6.3.4.4.1 Monitoring of the foundation shall be per ACI 376 Foundation Settlement Monitoring requirements in ACI 376

6.3.4.5 The monitoring shall include construction, hydrostatic testing, commissioning, and operation. [58:12.3.4.5]

6.3.4.6 4.2 Any settlement in excess of that anticipated predicted in the design shall be investigated, and corrective action shall be taken if

appropriate. [58:12.3.4.6]

6.3.4.72.5.3 For a container having a double wall design, the bottom of the outer wall and the refrigerated LP-Gas container under-container

insulation shall be above the groundwater table or protected from contact with groundwater at all times. It shall also be protected from floodwaters.

[58:12.3.4.7]

6.3.4.82.5.4 Where two or more containers are sited in a common dike, the container foundations shall be constructed of material resistant to the

effects of refrigerated LP-Gas and the temperatures to which they will be exposed. [58:12.3.4.8]

6.3.4.92.5.5 If the foundation of a refrigerated LP-Gas container is designed to provide air circulation in lieu of a heating system, the foundation and

insulating material under the bottom of the container shall be constructed of materials that are resistant to the effects of refrigerated LP-Gas and the

temperatures to which they will be exposed. [58:12.3.4.9]

6.3.4.10 The material in contact with the bottom of the container shall be selected to minimize corrosion. [58:12.3.4.10]

6.2.6 Marking on Refrigerated LP-Gas Containers. 6.2.6.1 Each refrigerated LP-Gas container shall be identified by the attachment of a nameplate directly on the container in a visible location in

accordance with API 625 Chapter 11 requirements

6.2.6.2 The nameplate shall be in accordance with API Standard API 625, Tank Systems for Refrigerated Liquefied Gas Storage, Section 11.

[58:12.2.2]

6.3.32.7 Piping. [58:12.3.3]

6.3.32.7.1 All piping that is part of a refrigerated LP-Gas container and refrigerated LP-Gas systems, including transfer and process piping, shall be

in accordance with ASME B31.3, Process Piping. [58:12.3.3.1]

6.3.32.7.2 The container piping shall include the following:

(1) All piping internal to the container

(2) All piping within the insulation spaces

(3) All external piping attached or connected to the container up to the first circumferential external joint of the piping [58:12.3.3.2]

6.3.3.3 Inert gas purge systems wholly within the insulation spaces shall be exempt from the provision in 6.3.3.1. [58:12.3.3.3]

6.2.8 Relief valve (pressure and vacuum) requirements shall be in accordance with API 625 Section 7.4 in addition to requirements in this standard in

Chapter 10.3 through 10.6.

6.2.9 Provision shall be made for purging and removal of the storage tank system from service[KLR3]

6.2.10 Container Siting[KLR4]

6.2.10.1 Spacing of refrigerated LP-Gas containers that operate at below 15 psi (103 kPa) from occupied buildings, storage containers for flammable

or combustible liquids, and lines of adjoining property that can be built upon shall be in accordance with Table 6.2.10

Table 6.2.10 Minimum Distances for Refrigerated LP-Gas Containers That Operate Below 15 psi (103 kPa)

Water Capacity per Container Aboveground Containers

gal m3 ft m

INSERT old Table 6.7.2 and renumber to 6.2.10 Table unchanged]

6.2.10.2 The edge of a dike, impoundment, or drainage system that is intended for a refrigerated LP-Gas container shall be 100 ft (31 m) or more

from a property line that can be built upon, a public way, or a navigable waterway. [58:12.7.3]

6.2.10.3 Nonrefrigerated LP-Gas containers or flammable liquid tanks shall not be located within dikes or impoundments enclosing refrigerated LP-

Gas containers. [58:12.7.4]

6.2.10.4 The minimum distance between aboveground refrigerated LP-Gas containers shall be one-half the diameter of the larger container.

[58:12.7.6]

6.2.10.5 The ground within 25 ft (7.6 m) of any aboveground refrigerated LP-Gas container, and all ground within a dike, impoundment, or drainage

area, shall be kept clear of readily ignitable materials such as weeds and long, dry grass. [58:12.7.7]

6.2.11 Instruments and Controls.

6.2.11.1 Gauging Devices 1) Each refrigerated LP-Gas container shall be equipped with at least two independent liquid level gauging devices as required by API 625 7.5.1.

2) Liquid level gauging devices shall be designed and installed so that they can be maintained or replaced without taking the container out of service

as required by API 625 7.5.1.4 .

3) The refrigerated LP-Gas container shall be provided with an audible and visual high–liquid level alarm. [58:12.4.1.3]

4) The alarm shall be set so that the operator will have sufficient time, based on the maximum allowable filling rate, to stop the flow without

exceeding the maximum permissible filling height. [58:12.4.1.4]

5) The alarm shall be located so that it is visible and audible to the personnel who control the filling. [58:12.4.1.5]

6) A high–liquid level flow cutoff device shall not be a substitute for the alarm. [58:12.4.1.6]

6.2.11.2 High–Liquid Level Device.

1) The refrigerated LP-Gas container shall be equipped with a high-high-liquid level flow cutoff device that is independent from all gauges.

[58:12.4.1.7]

2) Where refrigerated LP-Gas containers of 70,000 gal (265 m3) or less are attended during the filling operation, they shall be equipped with either

liquid trycocks or a high– liquid level alarm, and manual flow cutoff shall be permitted. [58:12.4.1.8]

3) Each refrigerated LP-Gas container shall be provided with temperature-indicating devices that assist in controlling cooldown rates when placing

the tank in service and monitoring product temperatures during operations. [58:12.4.1.9]

6.2.11.3 Pressure and Vacuum Control. [58:12.4.2]

1) Each refrigerated LP-Gas container shall be equipped with at least two independent pressure indicating instruments as required by API 625 7.5.5

2) Provisions shall be made to maintain the container pressure within the limits set by the design specifications by releasing or admitting gas as

needed. Provision for admission and release of gas shall be by any means compatible with the gas-handling facilities in the plant. [58:12.4.2.1]

3) The option of gas admission (or other gas or vapor if so designed) through the vacuum relief valves provided in API Standard 620, Design and

Construction of Large, Welded, Low- Pressure Storage Tanks, paragraph 7.2.3, shall not be permitted.

6.2.12 Impoundment. [58:12.5]

6.2.12.1 Each refrigerated LP-Gas container shall be located within an impoundment that complies with Section 6.5. Section 6.3.8

6.2.12.2 Enclosed drainage channels for LP-Gas shall be prohibited.

6.2.12.3 Impoundment for refrigerated LP-Gas containers shall have a volumetric holding capacity, with an allowance made for the displacement of

snow accumulation, other containers, or equipment that is equal to the total liquid volume of the largest container served, assuming that container is

full to the high–liquid level flow cutoff device.

6.2.12.4 Where more than one container is installed in a single impoundment and if an outside container wall is used as a spill containment dike, the

material shall be selected to withstand exposure to the temperature of refrigerated LP-Gas liquid.

6.2.12.5 Impoundment structures and any penetrations thereof shall be designed to withstand the full hydrostatic head of the impounded LP-Gas and

the effects of the product composition and the resulting autorefrigeration temperatures.

6.2.12.6 Impoundment structures shall also be nonporous and resistant to natural forces such as wind, rain, and fire.

6.2.12.7 Provisions shall be made to clear rain or other water from the impounding area.

1) Where automatically controlled sump pumps are used, they shall be equipped with an automatic shutoff device that prevents their operation when

either of the following occurs:

(A) They are exposed to the flash temperature of the liquid LP-Gas.

(B) Flammable vapors in excess of 25 percent of the lower flammable limit are detected within the impoundment area.

2) Gravity drainage utilizing piping penetrations through or below impoundment dikes shall not be permitted.

6.2.12.8 If the container impounding area is an earthen dike system, the area topography of the impounding area floor shall be graded away from the

container to prevent the accumulation of liquid under or around the container.

1) The grading shall move the spilled liquid to the toe of the dike system and as far away from the container as possible.

2) The grading shall move the spilled liquid to a subimpoundment basin that is capable of holding the quantity of liquid spilled from a line rupture, a

flange leak, or a source other than container failure.

3) The duration of the incident shall be the amount of time that automatic systems or plant personnel could affect emergency procedures and stop the

leak. The subimpoundment basin shall be located as far away from the container as possible.

6.2.13 Inspection and Testing of Refrigerated LP-Gas Containers and Systems 6.2.13.1 During construction and prior to the initial operation or commissioning, each refrigerated LP-Gas container and system shall be inspected or

tested in accordance with the provisions of this code and the API 625, API 620, ACI 376, and ASME B31.3 codes and standards referenced herein.

6.2.13.2 The inspections or tests required shall be conducted by the operator or a third-party engineering, scientific, recognized insurance, or

inspection organization.

6.2.13.3 Each inspector shall be qualified in accordance with the code or standard that is applicable to the test or inspection being performed. [

6.2.13.4 After acceptance tests are completed, there shall be no field welding on the LP-Gas containers except where allowed by the code under

which the container was fabricated.

6.2.13.5 Retesting shall be required only if the retest tests the element affected and is necessary to demonstrate the adequacy of the repair or

modification.

6.3 Refrigerated Containers Designed to Operate above 15 psi (103KPa)

6.13.1 Containers designed to operate at greater than 15 psi (103 kPa) shall be designed and constructed in accordance with the ASME Boiler and

Pressure Vessel Code, Section VIII, except that construction using joint efficiencies listed in Table UW 12, Column C, shall not be permitted and any

additional provision of this chapter. [58:12.1.1.1]

6.3.12 Construction and Design of Refrigerated Containers.

[58:12.1]

6.1.13.2.1 Container Material and Construction Requirements.

[58:12.1.1]

6.1.13.2.2 Materials used in refrigerated containers shall be selected from those included in the following:

(1) ASME Boiler and Pressure Vessel Code, Section VIII (materials that maintain their integrity at the boiling temperature of the liquid stored)

(2) API Standard 620, Design and Construction of Large, Welded,Low-Pressure Storage Tanks, Appendix R or Appendix Q [58:12.1.1.2]

6.1.1.3 Containers designed to operate below 15 psi (103 kPa) shall be in accordance with API Standard 620, Design and Construction of Large,

Welded, Low-Pressure Storage Tanks, including Appendix R. [58:12.1.1.3]

6.1.1.4 Where austenitic stainless steels or nonferrous materials are used, API Standard 620, Design and Construction of Large, Welded, Low-

Pressure Storage Tanks, Appendix Q, shall be used in the selection of materials. [58:12.1.1.4]

6.1.1.53.2.3 All new construction shall incorporate on any bottom or side penetrations that communicate with the liquid space of the container either

an internal emergency shutoffinternal valve or a back check valve. Any emergency shutoff valve shall be incorporated into a facility emergency

shutdown system and be capable of being operated remotely. [58:12.1.1.5]

6.1.23.3 Container Design Temperature and Pressure. [58:12.1.2]

6.1.23.3.1 The maximum allowable working pressure shall include a margin above the operating pressure.

6.1.23.3.2 The design pressure of ASME containers shall include a minimum 5 percent of the absolute vapor pressure of the LP-Gas at the design

storage temperature. The margin (both positive and vacuum) for low-pressure API Standard 620, Design and Construction of Large, Welded, Low-

Pressure Storage Tanks, vessels shall include the following:

(1) Control range of the boil-off handling system

(2) Effects of flash or vapor collapse during filling operations

(3) Flash that can result from withdrawal pump recirculation

(4) Normal range of barometric pressure changes

[58:12.1.2.1]

6.1.23.3.3 The design temperature for those parts of a refrigerated LP-Gas container that are in contact with the liquid or refrigerated vapor shall be

equal to or lower than the boiling point of the product to be stored at atmospheric pressure. A temperature allowance shall be made for the

composition of

the liquid to be stored when it is flashed into the vapor space of a tank. [58:12.1.2.2]

6.2 3.4 Marking on Refrigerated LP-Gas Containers. [58:12.2]

6.23.4.1 Each refrigerated LP-Gas container shall be identified by the attachment of a nameplate located either on the container or in a visible

location. [58:12.2.1]

6.2.2 The nameplate shall be in accordance with API Standard 620, Design and Construction of Large, Welded, Low-Pressure Storage Tanks,

Section 6 8. [58:12.2.2]

6.3.5 Container Installation. [58:12.3]

6.3.5.1 Wind Loading. [58:12.3.1]

6.3.1.1) The design wind loading on refrigerated LP-Gas containers shall be in accordance with the projected area at various

height zones above ground in accordance withASCE 7, Minimum Design Loads for Buildings and Other Structures. [58:12.3.1.1]

6.3.1.22) Design wind speeds shall be based on a mean occurrence interval of 100 years. [58:12.3.1.2]

6.3.5.2 Seismic Loading. [58:12.3.2]

6.3.2.11) The design seismic loading on refrigerated LP-Gas containers shall be in accordance with ASCE 7, Minimum Design Loads for Buildings

and Other Structures. [58:12.3.2.1]

6.3.2.22) Aseismic analysis of the proposed installation shall be made that meets the approval of the authority having jurisdiction. [58:12.3.2.2]

6.3.5.3 Piping. [58:12.3.3]

6.3.5.3.1 All piping that is part of a refrigerated LP-Gas container and refrigerated LP-Gas systems, including transfer and process piping, shall be in

accordance with ASME B31.3, Process Piping. [58:12.3.3.1]

6.3.5.3.2 The container piping shall include the following:

(1) All piping internal to the container

(2) All piping within the insulation spaces

(3) All external piping attached or connected to the container up to the first circumferential external joint of the piping [58:12.3.3.2]

6.3.3.3 Inert gas purge systems wholly within the insulation spaces shall be exempt from the provision in 6.3.3.1. [58:12.3.3.3]

6.3.4 6 Foundations. [58:12.3.4]

6.3.46.1 Foundations for refrigerated Refrigerated aboveground containers shall be designed installed on foundations that have been engineered for

site soil conditions and loadings. [58:12.3.4.1]

6.3.46.2 Prior to the start of design and construction of the foundation, a subsurface investigation shall be conducted by a soils engineer. Foundations

shall be designed by an engineer who is experienced in foundations and soils. [58:12.3.4.2]

6.3.46.3 Where product storage is at less than 30°F (1.1°C), the foundation and the container bottom shall comply with the following:

(1) The foundation design and the container bottom insulation shall prevent damage to the container from frost heave.

(2) If the refrigerated LP-Gas container under bottom foundation and insulation are in contact with the soil, and the soil temperature can be less than

32°F (0°C), a heating system shall be installed to prevent the soil temperature from falling below 32°F (0°C).

(3) The under-container heating system shall be designed to allow both functional and performance monitoring.

(4) The under-container temperature shall be observed and logged at least weekly.

(5) Where the foundation has a discontinuity, such as bottom piping, the heating system in that zone shall be designed for the discontinuity.

(6) The under-container heating system shall be installed so that any heating elements or temperature sensors used for control can be replaced while

the container is in service.

(7) Provisions shall be incorporated to minimize the effects of moisture accumulation in the conduit and other forms of deterioration within the

conduit or heating element.

[58:12.3.4.3]

6.3.46.4 The r Refrigerated LP-Gas container foundation shall be periodically monitored for settlement during the life of the facility. [58:12.3.4.4]

6.3.46.5 The monitoring shall include construction, hydrostatic testing, commissioning, and operation. [58:12.3.4.5]

6.3.4.6 4.2 Any settlement in excess of that anticipated in the design shall be investigated, and corrective action shall be taken if appropriate.

[58:12.3.4.6]

6.3.46.7 For a container having a double wall design, the bottom of the outer wall and the refrigerated LP-Gas container under-container insulation

shall be above the groundwater table or protected from contact with groundwater at all times. It shall also be protected from floodwaters.

[58:12.3.4.7]

6.3.46.8 Where two or more containers are sited in a common dike, the container foundations shall be constructed of material resistant to the effects

of refrigerated LP-Gas and the temperatures to which they will be exposed. [58:12.3.4.8]

6.3.46.9 If the foundation of a refrigerated LP-Gas container is designed to provide air circulation in lieu of a heating system, the foundation and

insulating material under the bottom of the container shall be constructed of materials that are resistant to the effects of refrigerated LP-Gas and the

temperatures to which they will be exposed. [58:12.3.4.9]

6.3.46.10 The material in contact with the bottom of the container shall be selected to minimize corrosion. [58:12.3.4.10]

6.3.74 Refrigerated LP-Gas Container Instruments and Controls. [58:12.4]

6.43.7.1 Gauging Devices. [58:12.4.1]

6.4.1.1)1 Each refrigerated LP-Gas container shall be equipped with at least two independent liquid level gauging devices. [58:12.4.1.1]

6.4.1.22) Liquid level gauging devices shall be designed and installed so that they can be maintained or replaced without taking the container out of

service. [58:12.4.1.2]

6.4.1.33) The refrigerated LP-Gas container shall be provided with an audible and visual high–liquid level alarm. [58:12.4.1.3]

6.4.1.44) The alarm shall be set so that the operator will have sufficient time, based on the maximum allowable filling rate, to stop the flow without

exceeding the maximum permissible filling height. [58:12.4.1.4]

6.4.1.55) The alarm shall be located so that it is visible and audible to the personnel who control the filling. [58:12.4.1.5]

6.4.1.66) A high–liquid level flow cutoff device shall not be a substitute for the alarm. [58:12.4.1.6]

6.43.7.2 High–Liquid Level Device.

6.4.2.11) The refrigerated LP-Gas container shall be equipped with a high-high-liquid level flow cutoff device that is independent from all gauges.

[58:12.4.1.7]

6.4.2.22) Where refrigerated LP-Gas containers of 70,000 gal (265 m3) or less are attended during the filling operation, they shall be equipped with

either liquid trycocks or a high– liquid level alarm, and manual flow cutoff shall be permitted. [58:12.4.1.8]

6.4.2.33) Each refrigerated LP-Gas container shall be provided with temperature-indicating devices that assist in controlling cooldown rates when

placing the tank in service and monitoring product temperatures during operations. [58:12.4.1.9]

6.43.7.3 Pressure and Vacuum Control. [58:12.4.2]

6.4.3.11) Provisions shall be made to maintain the container pressure within the limits set by the design specifications by releasing or admitting gas

as needed. Provision for admission and release of gas shall be by any means compatible with the gas-handling facilities in the plant. [58:12.4.2.1]

6.4.3.22) The option of gas admission (or other gas or vapor if so designed) through the vacuum relief valves provided in API Standard 620, Design

and Construction of Large, Welded, Low- Pressure Storage Tanks, paragraph 7.2.3, shall not be permitted.

6.5 3.8 Refrigerated LP-Gas Container Impoundment. [58:12.5]

6.53.8.1 Each refrigerated LP-Gas container shall be located within an impoundment that complies with Section 6.5. Section 6.3.8 [58:12.5.1]

6.53.8.2 Enclosed drainage channels for LP-Gas shall be prohibited. [58:12.5.2]

6.53.8.3 Impoundment for refrigerated LP-Gas containers shall have a volumetric holding capacity, with an allowance made for the displacement of

snow accumulation, other containers, or equipment that is equal to the total liquid volume of the largest container served, assuming that container is

full to the high–liquid level flow cutoff device. [58:12.5.4]

6.53.8.4 Where more than one container is installed in a single impoundment and if an outside container wall is used as a spill containment dike, the

material shall be selected to withstand exposure to the temperature of refrigerated LP-Gas liquid. [58:12.5.5]

6.53.8.5 Impoundment structures and any penetrations thereof shall be designed to withstand the full hydrostatic head of the impounded LP-Gas and

the effects of the product composition and the resulting autorefrigeration temperatures. [58:12.5.6]

6.53.8.6 Impoundment structures shall also be nonporous and resistant to natural forces such as wind, rain, and fire. [58:12.5.7]

6.53.8.7 Provisions shall be made to clear rain or other water from the impounding area. [58:12.5.8]

6.5.7.11) Where automatically controlled sump pumps are used, they shall be equipped with an automatic shutoff device that prevents their operation

when either of the following occurs:

(1A) They are exposed to the flash temperature of the liquid LP-Gas.

(2B) Flammable vapors in excess of 25 percent of the lower flammable limit are detected within the impoundment area.

6.5.7.23.8.8 Gravity drainage utilizing piping penetrations through or below impoundment dikes shall not be permitted. [58:12.5.8.3]

6.5.83.8.9 If the container impounding area is an earthen dike system, the area topography of the impounding area floor shall be graded away from

the container to prevent the accumulation of liquid under or around the container. [58:12.5.9]

6.5.8.11) The grading shall move the spilled liquid to the toe of the dike system and as far away from the container as possible. [58:12.5.9.1]

6.5.8.22) The grading shall move the spilled liquid to a subimpoundment basin that is capable of holding the quantity of liquid spilled from a line

rupture, a flange leak, or a source other than container failure. [58:12.5.9.2]

6.5.8.33.8.10 The duration of the incident shall be the amount of time that automatic systems or plant personnel could affect emergency procedures

and stop the leak. The subimpoundment basin shall be located as far away from the container as possible. [58:12.5.9.3]

6.6 3.9 Inspection and Testing of Refrigerated LP-Gas Containers and Systems. [58:12.6]

6.63.9.1 During construction and prior to the initial operation or commissioning, each refrigerated LP-Gas container and system shall be inspected or

tested in accordance with the provisions of this code and the codes and standards referenced herein. [58:12.6.1]

6.63.9.2 The inspections or tests required shall be conducted by the operator or a third-party engineering, scientific, recognized insurance, or

inspection organization.

6.63.9.3 Each inspector shall be qualified in accordance with the code or standard that is applicable to the test or inspection being performed.

[58:12.6.3]

6.63.9.4 After acceptance tests are completed, there shall be no field welding on the LP-Gas containers except where allowed by the code under

which the container was fabricated. [58:12.6.4]

6.63.9.5 Retesting shall be required only if the retest tests the element affected and is necessary to demonstrate the adequacy of the repair or

modification. [58:12.6.5]

6.7 3.10 Container Siting. [58:12.7]

6.73.10.1 Spacing of refrigerated LP-Gas containers designed to operate at greater than 15 psi (103 kPa) from occupied buildings, storage containers

for flammable or combustible liquids, and lines of adjoining property that can be built upon shall be in accordance with Table 6.73.10.1. [58:12.7.1]

Table 6.73.10.1 Minimum Distances for Refrigerated LP-Gas Containers That Operate at 15 psi (103 kPa) and Higher

Water Capacity per Container Aboveground Containers

Gal m3 ft m

[INSERT OLD Table 6.7.1 and renumber to 6.3.10.1 Table unchanged]

[58: Table 12.7.1]

6.7.33.10.2 The edge of a dike, impoundment, or drainage system that is intended for a refrigerated LP-Gas container shall be 100 ft (31 m) or more

from a property line that can be built upon, a public way, or a navigable waterway. [58:12.7.3]

6.7.43.10.3 Nonrefrigerated LP-Gas containers or flammable liquid tanks shall not be located within dikes or impoundments enclosing refrigerated

LP-Gas containers. [58:12.7.4]

6.7.53.10.4 Refrigerated LP-Gas containers shall not be installed one above the other. [58:12.7.5]

6.7.63.10.5 The minimum distance between aboveground refrigerated LP-Gas containers shall be one-half the diameter of the larger container.

[58:12.7.6]

6.7.73.10.6 The ground within 25 ft (7.6 m) of any aboveground refrigerated LP-Gas container, and all ground within a dike, impoundment, or

drainage area, shall be kept clear of readily ignitable materials such as weeds and long, dry grass. [58:12.7.7] STATEMENT OF PROBLEM:

In the 1998 edition of NFPA 59, NFPA 59 began extracting the entire refrigerated container section from NFPA

58. Prior to the 1998 edition of NFPA 59, the NFPA 59 standard included very similar text that was in NFPA

58 but it was not officially extracted from NFPA 58. Over the last several years, the standards development

organizations have developed a series of including one new standard (API 625) and revising two existing

standards (API 620 and ACI 376) such that a low pressure refrigerated storage container must apply all three

standards to design, engineer, construct, examine and test a new storage tank.


6.5.8.3

The duration of the incident shall be the amount of time that automatic systems or plant personnel couldeffect emergency procedures and stop the leak. The subimpoundment basin shall be located as far awayfrom the container as possible. [ 58: 12.5.9.3]


The statement on the duration of the incident is not definitive and has no value to this section.







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Public Input No. 25-NFPA 59-2015 [ Chapter 7 [Title Only] ]

Piping, Valves, Process Pressure Vessels and Equipment


The additional recognition of process pressure vessels that may be used and are not storage containers by definition







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7.1.1.5 Buried flammable liquid or gas piping shall be installed with a minimum of 30 inches of cover in normal soiland a minimum of 18 inches in consolidated rock.


This proposed text should be inserted after existing 7.1.1.4 and addresses an identified gap as a result of an AGA Supplemental Gas Committee and NFPA 59 TC member Task force to perform a detailed comparison between Part 192 and NFPA 59. The intent of the comparison was to identify gaps and reach alignment with part 192 through the normal NFPA standards development process.




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40 of 78 9/22/2015 11:20 AM


7.1.1.6 Buried flammable liquid or gas piping shall be installed with a minimum of 12 inches clearance between thepipe and any other structure not associated with the pipe to allow for proper maintenance


This proposed text should be inserted after proposed new 7.1.1.5 and addresses an identified gap as a result of an AGA Supplemental Gas Committee and NFPA 59 TC member Task force to perform a detailed comparison between Part 192 and NFPA 59. The intent of the comparison was to identify gaps and reach alignment with part 192 through the normal NFPA standards development process




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7.1.11

Piping outside buildings shall be supported and protected against physical damage and corrosion.


All piping should be protected, not just piping outside buildings.




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7.2.5

All liquid and vapor connections on containers, other than pressure relief valves, liquid level gaugingdevices, and openings not larger than No. 54 drill size 0.055 inches as covered in 7.2.6 and 7.4.3, shallbe equipped with one of the following:

(1) A back-pressure check valve and either a manual valve or an emergency shutoff valve

(2) An excess-flow valve with a fail-closed hydraulic or pneumatically actuated valve in compliance withAPI 607, Fire Test for Soft-Seated Quarter-Turn Valves; API 6FA, Specifications for Fire Tests forValves; or the equivalent, equipped for remote closure and automatic shutoff using thermal (fire)actuation where the thermal element is installed in compliance with 7.1.5

(3) A quick-acting internal valve incorporating the means of closing specified in 7.1.4


This change will provide a more universally understood dimensioning.




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7.2.6

Openings from a container or through fittings attached directly on the container to which pressure gaugeconnection is made shall not be required to be equipped with an excess-flow valve if such openings are notlarger than No. 54 drill size 0.055 inches .






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7.2.8

Excess-flow valves shall be designed with a bypass, not to exceed a No. 60 drill size 0.040 inch diameteropening, to allow equalization of pressures.






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7.4.1

Each nonrefrigerated storage system vessel shall be equipped with an approved liquid level gaugingdevice in accordance with the following:

(1) If the liquid level gauging device is a float gauge or a pressure differential gauge, the container alsoshall be provided with an auxiliary gauging device, such as a fixed liquid level gauge, slip tube, rotarygauge, or similar device.

(2) Unlisted gauge glasses of the columnar type shall not be permitted.


The vessel must be equipped with the device, not the "system".




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7.4.3

Gauging devices that require bleeding of the product to the atmosphere, such as the rotary tube, fixed liquidlevel gauge, and slip tube, shall be designed so that the bleed valve maximum opening is not larger than aNo. 54 drill size 0.055 inch diamter , unless provided with an excess-flow valve.






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7.8.1

Refrigerated storage systems Refrigeration facilities shall be provided with sufficient capacity to maintaincontainers at a pressure not in excess of the operating pressure under design ambient conditions where thetank is sited and shall be provided with additional capacity for filling or standby service.


Refrigeration facility is a better use of the Component- Facility- Plant hierarchy and retains consistency throughout the standard.







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7.9 * Process pressure vessels shall be designed and fabricated in accordance with the ASME Boiler and PressureVessel Code, Section VIII, Division 1, or Division 2, or with the CSA B51, Boiler Pressure Vessel and Piping Code, andshall be code-stamped


The additional recognition of process pressure vessels that may be used and are not storage containers by definition should be identified, defined along with their design, and fabrication requirements in the ASME BPVC. Additionally, an asterisk have been added to indicate new annex information to be included in a separate P.I.



Public Input No. 25-NFPA 59-2015 [Chapter 7 [Title Only]]




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7.10.4.3 *

The emergency shutoff valve(s) or backflow check valve(s) specified in 7.10.4.1 shall be installed in theplant facility piping so that any break resulting from a pull will occur on the hose or swivel-type piping sideof the connection while retaining intact the valves and piping on the plant facility side of the connection.

Exception: Such anchorage shall not be required for the tank car side.


Facility is more appropriate, and retains the Component-Facility- Plant hierarchy







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7.10.4.4

All new installations and, by December 31, 2005, all existing installations and existing installations shallhave at least two clearly identified and easily accessible manually operated remote emergency shutoffdevices. One shutoff device shall be located not less than 20 ft (6.1 m) nor more than 100 ft (30.5 m) in thepath of egress from the emergency shutoff valve.


Date has passed and is no longer needed – removal will add clarity to the code.




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A positive valving arrangement, such as a double-block-and-bleed, shall be installed close to the mixer toprevent backflow of gas into the air supply lines or of air into the LP-Gas system when the plant the facilityis not in operation.


consistency with component, facility, plant hierarchy







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9.5.1.3

If the heat source serving heat supplying device serving an indirect vaporizer utilizes a noncombustibleheat transfer fluid, such as steam, water, or a water–glycol mixture, it shall be is installed outdoors orshall comply with one of the following: If installed within a structure , the structure shall comply withChapter 8. If installed outdoors, the heat-supplying device or the housing in which it is installed shall belocated at least 50 ft ( 15 m 15m ) from other LP-Gas facilities and operations , or shall comply with one ofthe following:

(1) If installed within a structure, the structure shall comply with Chapter 8 .

(2) .

(3) If the heat source of an indirect vaporizer is gas fired and is located within 15 ft (4.6 m) of thevaporizer, the vaporizer and its heat source shall be installed as a direct-fired vaporizer and shall besubject to the requirements of 9.5.2 .

(4) A source of heat for an indirect vaporizer shall be permitted to be installed in an industrial occupancycomplying with Chapter 40 of NFPA 101 , Life Safety Code , and Section 9.3 of NFPA 54, NationalFuel Gas Code , where the heat transfer fluid is steam or hot water and is not recirculated and abackflow preventer is installed between the vaporizer and the heat source.

(5) If the heat transfer fluid is recirculated after leaving the vaporizer, a phase separator shall beinstalled with the gas vented to a safe location.


Deleting 9.5.1.3 (2), and incorporating the text in with the requirements for outside installations is grammatically correct and adds clarity




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9.5.2.4*

Direct gas-fired vaporizers of any capacity shall be located in accordance with Table 9.5.2.4.

Table 9.5.2.4 Separation of Vaporizers from Exposures

Exposure

Minimum Distance RequiredBetween Vaporizer and

Exposure

ft m

Container 50 15

Container shutoff valves 50 15

Point of transfer 50 15

Nearest important building or group of buildings or line of adjoiningproperty that can be built upon [except buildings in which vaporizer isinstalled (see Section 9.5)]

50 15

Building or room housing gas–air mixer 10 3

Cabinet housing gas–air mixer outdoors 0 0



Table_9.5.2.4.docx Revised distances attached


There is no justification for this being different than Table 6.22.3.6 in NFPA 58. This change would align the two codes more closely.




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10.1.4 Testing Relief Devices.

All relief devices required by this code, other than hydrostatic relief valves, shall be tested for properoperation at intervals not exceeding 5 calendar years visually inspected annually by a trained andcompetent person .


From Annex material in the 2014 Edition of NFPA 58…E.2.3 Pressure Relief Valve TestingE.2.3.1 Frequent testing of pressure relief valves on LP-Gas containers is not considerednecessary for the following reasons:(1) The LP-Gases are so-called “sweet gases” having no corrosive or other deleterious effecton the metal of the containers or relief valves.(2) The relief valves are constructed of corrosion-resistant materials and are installed so as tobe protected against the weather.(3) The variations of temperature and pressure due to atmospheric conditions are not sufficientto cause any permanent set in the valve springs.(4) The required odorization of the LP-Gases makes escape almost instantly evident.(5) Experience over the years with the storage of LP-Gases has shown a good safety recordon the functioning of pressure relief valves.




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11.2.1

Operating procedures manuals shall include operator actions to be taken if flammable concentrations offlammable liquids or gases are detected in the facility using the following:

(1) Fixed detectors

(2) Portable detectors

(3) Operating malfunctions

(4) Human senses


Operating malfunctions are not an appropriate means for the detection of flammable liquids or gases. While leaks may be found after a malfunction, this reference is not appropriate for the intent of the statement.




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12.3.6.1

Cathodic protection of buried or submerged components shall comply with the following:

(1) Cathodic protection systems installed in accordance with 12.3.3 shall be monitored by testing and theresults documented and retained per 12.10.2(3).

(2)

(3)

(4)

Producing a voltage of −0.78 volts or more negative, with reference to saturated KCl calomel half cell.

(a)

(b)

(5) Each buried or submerged component under cathodic protection shall be tested by personnelqualified to perform corrosion control monitoring at least once each calendar year, with intervals notexceeding 15 months, to determine whether the cathodic protection is performing as designed.

(6) Each cathodic protection rectifier or other impressed current power source shall be inspected bypersonnel qualified to perform corrosion control monitoring at least six times each calendar year, withintervals not exceeding 2 1⁄2 months, to ensure that it is performing as designed.

(7) Each reverse current switch, each diode, and each interference bond whose failure would jeopardizecomponent protection shall be electrically checked for proper performance at least six times eachcalendar year, with intervals not exceeding 2 1⁄2 months, by personnel qualified to perform corrosioncontrol monitoring. Each other interference bond shall be checked at least once each calendar year,with intervals not exceeding 15 months.

(8) Whenever any portion of a buried pipe is exposed, the exposed portion of the pipe shall be examinedfor evidence of external corrosion in either of the following instances:

(9) If general external or localized external pitting corrosion is identified, additional examination inthe exposed area is necessary to identify the extent of the corrosion.

(10) If damage to the component coating is observed, the coating shall be repaired in accordancewith 12.3.3.1.1.2 .


deleting repetitive wording




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* Cathodic protection system tests shall be described by one of the following:

Producing a voltage of −0.85 volts or more negative, with reference to a saturated copper–copper sulfate half cell.

* Producing a voltage of −0.78 volts or more negative, with reference to saturated KCl calomelhalf cell.

Producing a voltage of −0.80 volts or more negative, with reference to a silver–silver chloridehalf cell.


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12.3.8.1

All new plants new facilities shall meet all the requirements for corrosion control in Section 12.3 and12.10.2(3).


consistency with component, facilities, plant hierarchy







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Public Input No. 43-NFPA 59-2015 [ New Section after 12.7 ]

12.6.1 Maintenance of fire protection systems shall be in accordance with requirements in fire protectionstandards identified in Chapter 13.


New 12.6.1 clarifies that maintenance requirements for fire protection systems are located in chapter 13 and the standards identified in chapter 13.




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Fire protection shall be provided for all utility gas plants LP-Gas facilities .


consistency with component, facility, plant hierarchy







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13.1.1.3

Fire protection systems installed as a result of the evaluation in 13.1.1.1 and 13.1.1.2 shall be designed,engineered, installed , tested, and maintained based upon fire protection equipment standards identifiedand incorporated by reference within this standard .


The PI is recommended to be inserted ahead of 13.1.1.3 and renumber remaining 13.1.1. This PI further clarifies that where fire protection is installed, the requirements for design, engineering, installation, testing, and maintenance of fire protection systems must adhere to identified and incorporated by reference fire protect system standards. This PI aligns with similar requirements in the LNG standard NFPA 59A.




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13.2 Gas, Fire and Leak Detection.

13.2.1

Those areas, including enclosed buildings, that have a potential for flammable gas concentrations and fireshall be monitored as determined by the evaluation required in 13.1.1.

13.2.2

Continuously monitored flammable gas detection systems or low temperature sensors used for leakdetection purposes shall alarm at the plant site and at a constantly attended location if the plant site is notcontinuously manned.

13.2.3

Flammable gas detection systems shall alarm at not more than 25 percent of the lower flammable limit ofthe gas or vapor being monitored.

13.2.4 *

Fire detectors shall alarm at the plant site and at a constantly attended location if the plant site is notcontinually manned.

13.2.5

Where installed as determined by the evaluation required in 13.1.1, the following fire alarm componentsshall be designed, installed, documented, tested, and maintained in accordance with NFPA 72, NationalFire Alarm and Signaling Code:

(1) Initiating devices (detectors — smoke, flame, heat, etc.)

(2) Fire system monitor panels

(3) Notification appliances (strobes, sirens, etc.)

(4) Fire system activation devices on installed extinguishment/suppression systems (water deluge, fixeddry chemical systems)

(5) Field wiring between initiating, notification components, activation/suppression system, and controlpanels

(6) Power supply and backup power equipment for fire alarm system


The recognition of low temperature detection in 13.2 to compliment gas detection at facilities handling refrigerated LPG is appropriate and aligns with similar actions taken by the NFPA 59A TC at the last second draft meeting.







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13.2.2.1 *Where utilized, leak detection should be used to compliment fire and gas detection and is not intendedto replace fire and gas detection


The recognition of low temperature detection in 13.2 to compliment gas detection at facilities handling refrigerated LPG is appropriate and aligns with similar actions taken by the NFPA 59A TC at the last second draft meeting. The annex text recommended provides users examples of low temperature and systems that might be used to enhance gas detection



Public Input No. 45-NFPA 59-2015 [Section No. 13.2]

Public Input No. 47-NFPA 59-2015 [New Section after A.13.2.4]




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13.4.4

Fire protection water systems, where used, shall be designed, installed, and maintained in accordance withthe following NFPA standards, as applicable, considering the fire control problems in facilities covered bythis standard:

(1) NFPA 13, Standard for the Installation of Sprinkler Systems

(2) NFPA 14, Standard for the Installation of Standpipe and Hose Systems

(3) NFPA 15, Standard for Water Spray Fixed Systems for Fire Protection

(4) NFPA 20, Standard for the Installation of Stationary Pumps for Fire Protection

(5) NFPA 22, Standard for Water Tanks for Private Fire Protection

(6) NFPA 24, Standard for the Installation of Private Fire Service Mains and Their Appurtenances

(7) NFPA 25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire ProtectionSystems

(8) NFPA 1961, Standard on Fire Hose

(9) NFPA 1962, Standard for the Care, Use, Inspection, Service Testing, and Replacement of Fire Hose,Coupling, Nozzles, and Fire Hose Appliances.

(10) NFPA 1963, Standard for Fire Hose Connections


The recognition of NFPA 25 identifies maintenance requirements for water based fire protections as the maintenance requirements were removed from the specific water based system standards (NFPA 13, 14, 15, 20, 22, 24, etc) and relocated in NFPA 25 over 10 years ago. The recognition of NFPA 25 in this standard is necessary and aligns with changes being made in the LNG standard NFPA 59A







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13.5.1.1

The minimum size portable dry chemical extinguisher for gas fires shall be 18 lb (8.2 kg) with a B:Crating rated 60-B:C.

A.13.5.1.1 In areas containing common combustibles (Class A fires), a dry chemical extinguisher with arating of 4-A:60-B:C would satisfy this requirement and could also satsfy the need for extinguishers forClass A fires .


A typical 20 lb BC dry chemical extinguisher has a rating of 60-B:C. The minimum requirement should state the extinguisher rating, which relates to the listed fire fighting capacity. The minimum size portable dry chemical extinguisher for gas fires should therefore be rated 60-B:C. In areas where there are also common combustibles, a dry chemical extinguisher with a rating of 4-A:60-B:C would satisfy the need for protection of both Class A and Class B.


Submitter Full Name: Jennifer Boyle

Organization: Mark Conroy, Brooks Equipment Company

Affilliation: Fire Equipment Manufacturers Association

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Submittal Date: Fri May 22 11:33:03 EDT 2015


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13.5.3

Where fixed fire-extinguishing and other fire control systems are provided, such systems shall be designed,installed, and maintained in accordance with the following NFPA standards, as applicable:

(1) NFPA 10, Standard for Portable Fire Extinguishers

(2) NFPA 11, Standard for Low-, Medium-, and High-Expansion Foam

(3) NFPA 12, Standard on Carbon Dioxide Extinguishing Systems

(4) NFPA 12A, Standard on Halon 1301 Fire Extinguishing Systems

(5) NFPA 16, Standard for the Installation of Foam-Water Sprinkler and Foam-Water Spray Systems

(6) NFPA 17, Standard for Dry Chemical Extinguishing Systems

(7)

(8) NFPA

25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems

(9) NFPA 2001, Standard on Clean Agent Fire Extinguishing Systems


NFPA 25 is a maintenance standard for water based fire protection systems and has been recommended for placement in 13.4.4 in a separate P.I







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13.6 Maintenance of Fire Protection Equipment.

Facility operators shall prepare and implement a maintenance program for all plant fire protectionequipment.


Unnecessary modifier to the word Operator




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13.8.2.3

Such devices, when in place, shall prevent unauthorized operation of any of the container appurtenances,system facility valves, or equipment.


consistency component, facility, plant heirarchy







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Public Input No. 53-NFPA 59-2015 [ New Section after A.4.5.2.2 ]

A.4.5.2.2 When classifying the extent of an entire facility or a specific portion of the facility, considerationshould be given to increasing the extent of the hazardous area location above those stated in the NEC andNFPA 59 Table 4.5.2.2 based on higher flow rates and pressures utilized within larger facilities. Additionalguidance for extending electrical area classifications can be found in NFPA 497 Electrical Installations inChemical Atmospheres Involving Flammable Liquids, Gases, or Vapors.


The additional annex material aids users of the standard who design/engineering/construct propane facilities as well as those who own/operate these facilities that facilities operating at higher flows/pressure are at higher risk than the smaller facilities with lower flows and pressures and that consideration for possible extension of the traditional hazardous area classification area values




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Public Input No. 54-NFPA 59-2015 [ New Section after A.7.4.5 ]

A.7.9 In the United States, the Pipeline Hazardous Materials Safety Administration (PHMSA) incorporatesby reference in 49 CFR Part 192 the ASME Boiler and Pressure Vessel Code Section VIII Division 1. Thecurrent version of the ASME BPVC Section VIII at the time this NFPA Standard was issued requires testingat only 1.3 times the MAWP. PHMSA in a March 2015 Final Rule requires in 192.153 the componentsfabricated by welding (other than branch connections or assemblies of standard pipe) under ASME BPVC(Boiler Pressure Vessel Code) Section VIII, Division 1, or 2 be subject to strength testing to at least 1.5 timesthe MAOP regardless of the conflict. Owner, operators installing new equipment should gain the approval ofthe AHJ if testing at 1.3 vs. 1.5 times the MAWP.


Proposed annex material identifies conflicts in testing of new vessels, boilers, etc. between current and earlier edition of the ASME BPVC which can present substantial difficulties in purchasing of this equipment from certified manufacturers. The proposed annex material aides owner/operators ensure AHJ requirements are met.




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Public Input No. 55-NFPA 59-2015 [ Sections A.10.1, A.11.2.3 ]

Sections A.10.1, A.11.2.3

A.10.1

Experience has indicated that a vertical for safety relief valves in vapor service only and those that emit amist, vertical and unimpeded vent of high-velocity hydrocarbon gases will entrain sufficient air within a veryshort distance so that the resultant plume will be diluted below the lower flammable limit. This behavior isdocumented in ANSI/API 521, Guide for Pressure-Relieving and Depressuring Systems. This documentwas based, in part, on an API-commissioned study by Battelle Memorial Institute, “The Effect of Velocity,Temperature, and Gas Molecular Weight on Flammability Limits in Wind-Blown Jets of HydrocarbonGases.”

These reports clearly indicate that a vertical and unimpeded jet from a safety relief valve in vapor serviceonly and those that emit a mist will be diluted below its lower flammable limit within 50 pipe diameters ofthe issuing jet and that the effects of “wind-tilt” can be safely neglected if a 50 ft (15 m) horizontal clearanceis provided between the jet and a source of ignition. A high velocity jet is defined as a jet having an exitvelocity in excess of 100 ft/sec (30.5 m/sec), which is slightly more than an order of magnitude less than theacoustic velocity that can be anticipated at the throat of an operating relief valve. ANSI/API 521 alsoindicates that a partially open relief valve in vapor service will produce a velocity sufficient to achieve thenecessary dilution.

Once such a mixture from a safety relief valve in vapor service only and those that emit a mist has beendiluted below its flammable limit, there are no known natural forces (including gravitational forces) that willcause the reconcentration of the LP-Gases so as to create a flammable cloud. The application of water, aseither a fog or a heavy stream, will not hasten and can actually inhibit the dilution of the jet stream. It isrecommended that this information be included in any emergency procedure manual and that theresponding emergency services be made aware of this information.

Based on information in API 521, safety relieve valves that are in liquid service when relieving donot entrain sufficient volumes of air to dilute the mixture to below LEL levels. Additional considerationsshould be considered when establishing the electrical area classification and classification distancesnear relief valves in liquid service.

A.11.2.3

For information on purging and inerting equipment, see NFPA 326, Standard for the Safeguarding of Tanksand Containers for Entry, Cleaning, or Repair, and AGA Purging Principles and Practice.


The rationale for not identifying an electrical area classification near safety relief valves has been based on the annex information in A.10.1 that states based on details in API 521 6.3.2.2, (2007 edition w/May 2008 Addendum) that during the discharge from a safety relief valve that the discharge velocity is such that sufficient volumes of air is entrained in the discharge stream and therefor dilutes the mixture to below the LEL. While this is stated in API 521, it is only applicable to safety relief valves discharging vapor. API 521 6.3.2.3, and 6.3.2.4 additionally describes the discharges of mists and liquids and goes onto state that the same air entrainment activity is not expected to occur for liquid service valves and flammable concentrations in the area near the valves should be further evaluated. Safety relief valves in NFPA 59 facilities can be either in vapor or liquid service and for this reason the table has been changed to reflect the minimum hazardous area classifications.






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A13.2.2.1 Leak detection used to compliment gas detection systems, leak detection mayinclude but not limited to acoustic (ultrasonic)? which, detects small leak rates (mass/time), vaporcloud video surveillance cameras? which, detects gas cloud size, Low Temperature Detectors,including Resistant Temperature Detectors (RTD), and Linear Leak Detection (such as fiber opticleak detection technology).


The recognition of low temperature detection in 13.2 to compliment gas detection at facilities handling refrigerated LPG is appropriate and aligns with similar actions taken by the NFPA 59A TC at the last second draft meeting. The annex text recommended provides users examples of low temperature and systems that might be used to enhance gas detection.







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A 13.2.5 Where Fire protection systems are installed in accordance with NFPA 72 and are planned forintegration with other systems, the NFPA 3 Recommended Practice for Commissioning and IntegratedTesting of Fire Protection and Life Safety Systems may be useful in the commissioning and testing of theintegrated systems.


The additional annex material identifying NFPA 3 provides additional guidance when integrating various fire protection and life systems with other systems.




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Public Input No. 3-NFPA 59-2015 [ Section No. F.1.2 ]

F.1.2 Other Publications.

F.1.2.1 AGA Publications.

American Gas Association, 400 North Capitol Street, NW, Washington, DC 20001.

AGA XH0203, Interchangeability of Other Fuel Gases with Natural Gas, Research Bulletin 36, AGACatalog No. XH0203, 1946 (reprinted 2003). 2002.

Interchangeability — What it Means, AGA Catalog No. XL0884, 2002.

AGA XO9608, Introduction to LPG Safety for Propane Air Plant Operators, AGA Catalog No. XO9608,1996.

AGA XKO101, Purging Principles and Practice, AGA Catalog No. XKO101, 2001. 2001.

F.1.2.2 API Publications.


ANSI/ API 521 STD 521 ,Guide for Pressure-Relieving and Depressuring Systems, 2007 6th edition,2014 .

API RP 2003, Protection Against Ignitions Arising out of Static, Lightning, and Stray Currents, 2008edition .

“The Effect of Velocity, Temperature, and Gas Molecular Weight on Flammability Limits in Wind-Blown Jetsof Hydrocarbon Gases,” Battelle Memorial Institute, April 1, 1970.

F.1.2.3 ASME Publications.

American Society of Mechanical Engineers, Three ASME Internationl , Two Park Avenue, New York, NY10016-5990.

ASME Boiler and Pressure Vessel Code, 2007 edition 2015 .

F.1.2.4 NACE Publications.

NACE International 1440 South Creek Drive, , 15835 Park Ten Place , Houston, TX 77084-4906.

SP-01-69 NACE SP0169 , Control of External Corrosion of Underground or Submerged Metallic PipingSystems, 2007 2013 .

SP-0198 NACE SP0198 , Control of Corrosion Under Thermal Insulation and Fireproofing Materials — ASystems Approach, 2010.

SP-02-85 NACE SP0285 , Corrosion Control of Underground Storage Tank Systems by CathodicProtection, 2011.

F.1.2.5 U.S. Government Publications.

U.S. Government Printing Government Publishing Office, Washington, DC 20402.

Title 49, Code of Federal Regulations, Parts 171–190, “Hazardous Materials Regulations.”

Title 49, Code of Federal Regulations, Part 192, “Pipeline Safety Law.”


References current SDO name, addresses, standard names, numbers, and editions.



Public Input No. 2-NFPA 59-2015[Section No. 2.3]



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Public Input No. 1-NFPA 59-2015[Global Input]




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Documents

Technical Committee on LP-Gases at Utility Gas PlantsTechnical Committee on LP-Gas at Utility Gas Plants Minutes Sheraton Denver Downtown 1550 Court Place Denver, CO 80202 August 7-8,