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PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS


  • 1. The authority citation for Part 192 continues to read as follows:


Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 60116, 60118 and 60137; and 49 CFR 1.53.


  • 2. In §192.3, definitions for “Active corrosion”, “Electrical survey” and “pipeline environment” are added in alphabetical order to read as follows:



§192.3 Definitions
* * * * *

Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety.

* * * * *



Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.

* * * * *



Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.

* * * * *




  • 3. In §192.7, paragraph (c)(2) is revised to read as follows:


§192.7 What documents are incorporated by reference partly or wholly in this part?
* * * * *

(c) * * *

(2) Documents incorporated by reference.

-


Source and name of referenced material

49 CFR reference

A. Pipeline Research Council International (PRCI):

(1) AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,” (December 22, 1989). The RSTRENG program may be used for calculating remaining strength.



§§ 192.485(c);.192.933(a)(1); 192.933(d)(1)(i).

B. American Petroleum Institute (API):

(1) ANSI/API Specification 5L/ISO 3183 “Specification for Line Pipe” (44th edition, 2007), includes errata(January 2009) and addendum (February 2009).

(2) API Recommended Practice 5L1 “Recommended Practice for Railroad Transportation of Line Pipe,” (6th Edition, July 2002).


§§ 192.55(e); 192.112; 192.113; Item I, Appendix B to Part 192.

§ 192.65(a)(1).



(3) API Recommended Practice 5LW, “Transportation of Line Pipe on Barges and Marine Vessels” (2nd edition, December 1996, effective March 1, 1997).

§ 192.65(b).

(4) ANSI/API Specification 6D, “Specification for Pipeline Valves” (23rd edition (April 2008, effective October 1, 2008) and errata 3 (includes 1 and 2, February 2009)).


§ 192.145(a).

(5) API Recommended Practice 80, “Guidelines for the Definition of Onshore Gas Gathering Lines,” (1st edition, April 2000).


§§ 192.8(a); 192.8(a)(1); 192.8(a)(2); 192.8(a)(3); 192.8(a)(4).

(6) API Standard 1104, “Welding of Pipelines and Related Facilities” (20th edition, October 2005, errata/addendum, (July 2007) and errata 2 (2008)).


§§ 192.225; 192.227(a); 192.229(c)(1); 192.241(c); Item II, Appendix B.

(7) API Recommended Practice 1162, “Public Awareness Programs for Pipeline Operators,” (1st edition, December 2003).


§§ 192.616(a); 192.616(b); 192.616(c)

(8) API Recommended Practice 1165 “Recommended Practice 1165 “Recommended Practice for Pipeline SCADA Displays,” (API RP 1165) (First edition (January 2007)).


§ 192.631(c)(1).

C. American Society for Testing and Materials (ASTM):

(1) ASTM A53/A53M-07, “Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless” (September 1, 2007).




§§ 192.113; Item I, Appendix B to Part 192.

(2) ASTM A106/A106M-08, “Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service” (July 15, 2008).


§§ 192.113; Item I, Appendix B to Part 192


(3) ASTM A333/A333M-05 (2005) “Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service”.


§§ 192.113; Item I, Appendix B to Part 192.

(4) ASTM A372/A372M-03 (reapproved 2008), “Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels” (March 1, 2008).


§ 192.177(b)(1).

(5) ASTM A381-96 (reapproved 2005), “Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems” (October 1, 2005).


§§ 192.113; Item I, Appendix B to Part 192.

(6) ASTM A578/A578M-96 (re-approved 2001) “Standard Specification for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications.”.

§§192.112(c)(2)(iii).

(7) ASTM A671-06, “Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures” (May 1, 2006).


§§ 192.113; Item I, Appendix B to Part 192

(8) ASTM A672-08, “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (May 1, 2008).

§§ 192.113; Item I, Appendix B to Part 192

(9) ASTM A691-98 (reapproved 2007), “Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures” (November 1, 2007).


§§ 192.113; Item I, Appendix B to Part 192

(10) ASTM D638-03 “Standard Test Method for Tensile Properties of Plastics.”

§§ 192.283(a)(3); 192.283(b)(1).

(11) ASTM D2513-87 “Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings.”

§ 192.63(a)(1).

(12) ASTM D2513-99 “Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings.”

§§ 192.123(e)(2); 192.191(b); 192.281(b)(2); 192.283(a)(1)(i); Item 1, Appendix B to Part 192.

(13) ASTM D2517-00 “Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings.”

§§ 192.191(a); 192.281(d)(1); 192.283(a)(1)(ii); Item I, Appendix B to Part 192

(14) ASTM F1055-1998, “Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controller Polyethylene Pipe and Tubing.”.

§ 192.283(a)(1)(iii).

D. ASME International (ASME):

(1) ASME/ANSI B16.1-2005, “Gray Iron Pipe Flanges and Flanged Fittings: (Classes 25, 125, and 250)” (August 31, 2006).



§ 192.147(c).

(2) ASME/ANSI B16.5-2003, “Pipe Flanges and Flanged Fittings.” (October 2004).

§§ 192.147(a); 192.279.

(3) ASME/ANSI B31G-1991 (Reaffirmed, 2004), “Manual for Determining the Remaining Strength of Corroded Pipelines.”.

§§ 192.485(c); 192.933(a).

(4) ASME/ANSI B31.8-2007, “Gas Transmission and Distribution Piping Systems” (November 30, 2007).

§ 192.619(a)(1)(i).

(5) ASME/ANSI B31.8S-2004, “Supplement to B31.8 on Managing System Integrity of Gas Pipelines.”

§§ 192.903(c); 192.907(b); 192.911 Introductory text; 192.911(i); 192.911(k);192.911(l); 192.911(m);192.913(a) Introductory text; 192.913(b)(1); 192.917(a) Introductory text; 192.917(b); 192.917(c); 192.917(e)(1); 192.917(e)(4); 192.921(a)(1); 192.923(b)(1);192.923(b)(2); 192.923(b)(3); 192.925(b) Introductory text; 192.925(b)(1);192.925(b)(2);192.925(b)(3);192.925(b)(4); 192.927(b); 192.927(c)(1)(i); 192.929(b)(1); 192.929(b)(2); 192.933(a); 192.933(d)(1); 192.933(d)(1)(i); 192.935(a); 192.935(b)(1)(iv); 192.937(c)(1); 192.939(a)(1)(i); 192.939(a)(1)(ii); 192.939(a)(3); 192.945(a).

(6) 2007 ASME Boiler & Pressure Vessel Code, Section I, “Rules for Construction of Power Boilers 2007” (2007 edition, July 1, 2007).

§ 192.153(b).

(7) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, “Rules for Construction of Pressure Vessels 2” (2007 edition, July 1, 2007).

§§ 192.153(a); 192.153(b); 192.153(d); 192.165(b)(3).

(8) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 2, “Alternative Rules, Rules for Construction of Pressure Vessels” (2007 edition, July 1, 2007).


§§ 192.153(b); 192.165(b)(3).

(9) 2007 ASME Boiler & Pressure Vessel Code, Section IX, “Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators” (2007 edition, July 1, 2007).


§§ 192.227(a); Item II, Appendix B to Part 192.

E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS):

(1) MSS SP-44-2006, Standard Practice, “Steel Pipeline Flanges” (2006 edition).

(2) [Reserved]


§ 192.147(a).

F. National Fire Protection Association (NFPA):

(1) NFPA 30 (2008 edition, August 15 2007), “Flammable and Combustible Liquids Code” (2008 edition; approved August 15, 2007).



§ 192.735(b).

(2) NFPA 58 (2004), “Liquefied Petroleum Gas Code(LP-Gas Code)”

§§ 192.11(a); 192.11(b); 192.11(c).

(3) NFPA 59 (2004), “Utility LP-Gas Plant Code.”

§§ 192.11(a); 192.11(b); 192.11(c).

(4) NFPA 70 (2008), “National Electrical Code” (NEC 2008) (Approved August 15, 2007).

§§ 192.163(e); 192.189(c).

G. Plastics Pipe Institute, Inc. (PPI):

(1) PPI TR-3/2008 HDB/HDS/PDB/SDB/MRS Policies (2008), “Policies and Procedures for Developing Hydrostatic Design Basis (HDB), Pressure Design Basis (PDB), Strength Design Basis (SDB), and Minimum Required Strength (MRS) Ratings for Thermoplastic Piping Materials or Pipe” (May 2008).




§ 192.121.

H. NACE International (NACE):

(1) NACE Standard SP0502-2008, Standard Practice, “Pipeline External Corrosion Direct Assessment Methodology” (reaffirmed March 20, 2008).


§§ 192.923(b)(1); 192.925(b) Introductory text; 192.925(b)(1); 192.925(b)(1)(ii); 192.925(b)(2) Introductory text; 192.925(b)(3) Introductory text; 192.925(b)(3)(ii); 192.925(b)(3)(iv); 192.925(b)(4) Introductory text; 192.925(b)(4)(ii); 192.931(d); 192.935(b)(1)(iv); 192.939(a)(2).



I. Gas Technology Institute (GTI):

(1) GRI 02/0057 (2002) “Internal Corrosion Direct Assessment of Gas Transmission Pipelines Methodology.”.



§ 192.927(c)(2).







  • 4. In §192.63, paragraph (a)(1) is revised to read as follows:


§192.63 Marking of materials.

(a) Except as provided in paragraph (d) of this section, each valve, fitting, length of pipe, and other component must be marked--

(1) As prescribed in the specification or standard to which it was manufactured, except that thermoplastic fittings must be marked in accordance with ASTM D2513-87 (incorporated by reference, see §192.7);

* * * * *




  • 5. Section 192.65 is revised to read as follows:


§192.65 Transportation of pipe.

(a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by railroad unless:

(1) The transportation is performed in accordance with API Recommended Practice 5L1 (incorporated by reference, see §192.7).

(2) In the case of pipe transported before November 12, 1970, the pipe is tested in accordance with Subpart J of this Part to at least 1.25 times the maximum allowable operating pressure if it is to be installed in a class 1 location and to at least 1.5 times the maximum allowable operating pressure if it is to be installed in a class 2, 3, or 4 location. Notwithstanding any shorter time period permitted under Subpart J of this Part, the test pressure must be maintained for at least 8 hours.

(b) Ship or barge. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API Recommended Practice 5LW (incorporated by reference, see §192.7).
§192.121 [Amended].


  • 6. In §192.121, under “S=“, the words “PPI TR-3/2004” are removed and the words “PPI TR-3/2008” are added in their place.




  • 7. In §192.123, paragraphs (e) introductory text, (e)(1) and (2) are revised to read as follows:



§192.123 Design limitations for plastic pipe.
* * * * *

(e) The design pressure for thermoplastic pipe produced after July 14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided that:

(1) The design pressure does not exceed 125 psig (862 kPa);

(2) The material is a PE2406 or a PE3408 as specified within ASTM D2513-99 (incorporated by reference, see §192.7);

* * * * *


  • 8. In §192.145, the first sentence in paragraph (d) introductory text and paragraph (e) are revised to read as follows:


§192.145 Valves.
* * * * *

(d) No valve having shell (body, bonnet, cover, and/or end flange) components made of ductile iron may be used at pressures exceeding 80 percent of the pressure ratings for comparable steel valves at their listed temperature. * * *

(e) No valve having shell (body, bonnet, cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations.


  • 9. Section 192.191 is revised to read as follows:


§192.191 Design pressure of plastic fittings.

(a) Thermosetting fittings for plastic pipe must conform to ASTM D 2517, (incorporated by reference, see §192.7).

(b) Thermoplastic fittings for plastic pipe must conform to ASTM D 2513-99, (incorporated by reference, see §192.7).


  • 10. In §192.281, paragraphs (a) and (b) are revised to read as follows:


§192.281 Plastic pipe
(a) General. A plastic pipe joint that is joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint.

(b) Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following:

(1) The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint.

(2) The solvent cement must conform to ASTM D2513-99, (incorporated by reference, see §192.7).

(3) The joint may not be heated to accelerate the setting of the cement.

* * * * *




  • 11. In §192.283, paragraph (a) is revised to read as follows:



§192.283 Plastic pipe: Qualifying joining procedures.
(a) Heat fusion, solvent cement, and adhesive joints. Before any written procedure established under §192.273(b) is used for making plastic pipe joints by a heat fusion, solvent cement, or adhesive method, the procedure must be qualified by subjecting specimen joints made according to the procedure to the following tests:

(1) The burst test requirements of--

(i) In the case of thermoplastic pipe, paragraph 6.6 (sustained pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or paragraph 8.9 (Sustained Static pressure Test) of ASTM D2513-99 (incorporated by reference, see §192.7);

(ii) In the case of thermosetting plastic pipe, paragraph 8.5 (Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static Pressure Test) of ASTM D2517 (incorporated by reference, see §192.7); or

(iii) In the case of electrofusion fittings for polyethylene (PE) pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation F1055 (incorporated by reference, see §192.7).

(2) For procedures intended for lateral pipe connections, subject a specimen joint made from pipe sections joined at right angles according to the procedure to a force on the lateral pipe until failure occurs in the specimen. If failure initiates outside the joint area, the procedure qualifies for use; and

(3) For procedures intended for non-lateral pipe connections, follow the tensile test requirements of ASTM D638 (incorporated by reference, see §192.7), except that the test may be conducted at ambient temperature and humidity If the specimen elongates no less than 25 percent or failure initiates outside the joint area, the procedure qualifies for use.

* * * * *




  • 12. In §192.465, paragraph (e) is revised to read as follows:


§192.465 External corrosion control: Monitoring
* * * * *

(e) After the initial evaluation required by Sec. §192.455(b) and (c) and 192.457(b), each operator must, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator must determine the areas of active corrosion by electrical survey. However, on distribution lines and where an electrical survey is impractical on transmission lines, areas of active corrosion may be determined by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.




  • 13. Section 192.711 is revised to read as follows:


§192.711 Transmission lines: General requirements for repair procedures.
(a) Temporary repairs. Each operator must take immediate temporary measures to protect the public whenever:

(1) A leak, imperfection, or damage that impairs its serviceability is found in a segment of steel transmission line operating at or above 40 percent of the SMYS; and

(2) It is not feasible to make a permanent repair at the time of discovery.

(b) Permanent repairs. An operator must make permanent repairs on its pipeline system according to the following:

(1) Non integrity management repairs: The operator must make permanent repairs as soon as feasible.

(2) Integrity management repairs: When an operator discovers a condition on a pipeline covered under Subpart O-Gas Transmission Pipeline Integrity Management, the operator must remediate the condition as prescribed by §192.933(d).

(c) Welded patch. Except as provided in §192.717(b)(3), no operator may use a welded patch as a means of repair.
Sec. §192.923, 192.925, 192.931, 192.935, and 192.939 [Amended]


  • 14. In 49 CFR part 192 the words “NACE RP0502-2002” or “NACE RP 0502-2002” are removed and the words “NACE SP0502-2008” are added in their place in the following places:

  • a. Section 192.923(b)(1);

  • b. Section 192.925(b) introductory text, 192.925(b)(1), 192.925 (b)(1)(ii), 192.925 (b)(2) introductory text, 192.925 (b)(3) introductory text, 192.925(b)(3)(ii), 192.925(b)(iv), 192.925(b)(4) introductory text, and 192.925(b)(4)(ii);

0

  • c. Section 192.931(d);

  • d. Section 192.935(b)(1)(iv); and

  • e. Section 192.939(a)(2).


Appendix B to Part 192 [Amended]


  • 15. In Appendix B to Part 192, in section I, the phrase “ASTM D2513” is revised to read “ASTM D2513-99”


PART 193--LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY STANDARDS


  • 16. The authority citation for Part 193 continues to read as follows:


Authority: 49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 60110, 60113, 60118; and 49 CFR 1.53.


  • 17. In §193.2013, paragraph (c) is revised to read as follows:


§193.2013 Incorporation by reference.

(c) Documents incorporated by reference.




Source and name of referenced material

49 CFR Reference

A. American Gas Association (AGA):

(1) “Purging Principles and Practices” (3rd edition, 2001).



§§ 193.2513; 193.2517; 193.2615.

B. American Petroleum Institute (API):

(1) API Standard 620 “Design and Construction of Large, Welded, Low-Pressure Storage Tanks” (11th edition February 2008, addendum 1, March 2009)


§§ 193.2101(b); 193.2321(b)(2).



C. American Society of Civil Engineers (ASCE):

(1) ASCE/SEI 7-05 “Minimum Design Loads for Buildings and Other Structures” (2005 edition, includes supplement No. 1 and Errata).


§ 193.2067(b)(1).



D. ASME International (ASME):

(1) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, “Rules for Construction of Pressure Vessels” (2007 edition, July 1, 2007).

(2) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 2, “Alternative Rules, Rules for Construction of Pressure Vessels” (2007 edition, July 1, 2007).

§ 193.2321(a).

§ 193.2321(a).


E. Gas Technology Institute (GTI) formerly the Gas Research Institute (GTI):

(1) GTI-04/0032 LNGFIRE3: A Thermal Radiation Model for LNG Fires (March 2004).

(2) GTI-04/0049 (April 2004) “LNG Vapor Dispersion Prediction with the DEGADIS 2.1: Dense Gas Dispersion Model For LNG Vapor Dispersion”.

§ 193.2057(a).

§ 193.2059.


(3) GRI-96/0396.5 “Evaluation of Mitigation Methods for Accidental LNG Releases, Volume 5: Using FEM3A for LNG Accident Consequence Analyses” (April 1997).

§ 193.2059.

F. National Fire Protection Association (NFPA):

(1) NFPA 59A, (2001) “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)”.


§§ 193.2019; 193.2051; 193.2057; 193.2059; 193.2101(a); 193.2301; 193.2303; 193.2401; 193.2521; 193.2639; 193.2801



(2) NFPA 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)” (2006 edition, Approved August 18, 2005).

§§ 193.2101(b); 193.2321(b).




  • 18. In §193.2057, paragraph (a) is revised to read as follows:


§193.2057 Thermal radiation protection.
* * * * *

(a) The thermal radiation distances must be calculated using Gas Technology Institute's (GTI) report or computer model GTI-04/0032 LNGFIRE3: A Thermal Radiation Model for LNG Fires (incorporated by reference, see §193.2013). The use of other alternate models which take into account the same physical factors and have been validated by experimental test data may be permitted subject to the Administrator's approval.

* * * * *


  • 19. In §193.2067, paragraph (b)(1) is revised to read as follows:


§193.2067 Wind forces.
* * * * *

(b) * * *

(1) For shop fabricated containers of LNG or other hazardous fluids with a capacity of not more than 70,000 gallons, applicable wind load data in ASCE/SEI 7-05 (incorporated by reference, see §193.2013).

* * * * *




  • 20. Section 193.2101 is revised to read as follows:



§193.2101 Scope.
(a) Each LNG facility designed after March 31, 2000 must comply with requirements of this Part and of NFPA 59A (2001) (incorporated by reference, see §193.2013). If there is a conflict between this Part and NFPA 59A, this Part prevails. Unless otherwise specified, all references to NFPA 59A in this Part are to the 2001 edition.

(b) Stationary LNG storage tanks must comply with Section 7.2.2 of NFPA 59A (2006) (incorporated by reference, see §193.2013) for seismic design of field fabricated tanks. All other LNG storage tanks must comply with API Standard 620 (incorporated by reference, see §193.2013) for seismic design.




  • 21. Section 193.2321 is revised to read as follows:


§193.2321 Nondestructive tests.
(a) The butt welds in metal shells of storage tanks with internal design pressure above 15 psig must be nondestructively examined in accordance with the ASME Boiler and Pressure Vessel Code (Section VIII Division 1) (incorporated by reference, see §193.2013), except that 100 percent of welds that are both longitudinal (or meridional) and circumferential (or latitudinal) of hydraulic load bearing shells with curved surfaces that are subject to cryogenic temperatures must be nondestructively examined in accordance with the ASME Boiler and Pressure Vessel Code (Section VIII Division 1) (incorporated by reference, see §193.2013).

(b) For storage tanks with internal design pressures at 15 psig or less, ultrasonic examinations of welds on metal containers must comply with the following:

(1) Section 7.3.1.2 of NFPA 59A (2006) (incorporated by reference, see §193.2013);

(2) Appendices Q and C of API 620 Standard (incorporated by reference, see §193.2013);

(c) Ultrasonic examination records must be retained for the life of the facility. If electronic records are kept, they must be retained in a manner so that they cannot be altered by any means; and

(d) The ultrasonic equipment used in the examination of welds must be calibrated at a frequency no longer than eight hours. Such calibrations must verify the examination of welds against a calibration standard. If the ultrasonic equipment is found to be out of calibration, all previous weld inspections that are suspect must be reexamined.


PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE


  • 22. The authority citation for Part 195 continues to read as follows:


Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 60118 and 60137; and 49 CFR 1.53.


  • 23. In §195.3, paragraph (c) is revised to read as follows:


§195.3 Incorporation by reference.
* * * * *

(c) The full titles of publications incorporated by reference wholly or partially in this part are as follows. Numbers in parentheses indicate applicable editions:




Source and name of referenced material

49 CFR reference

A. Pipeline Research Council International, Inc. (PRCI):

(1) AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,” (December 22, 1989). The RSTRENG program may be used for calculating remaining strength.


§§ 195.452(h)(4)(i)(B); 195.452(h)(4)(iii)(D); 195.587.



B. American Petroleum Institute (API):

(1) ANSI/API Specification 5L/ISO 3183, “Specification for Line Pipe” (44th edition, October 2007, including errata (January 2009) and addendum (February 2009)).


§§ 195.106(b)(1)(i); 195.106(e).



(2) API Recommended Practice 5L1, “Recommended Practice for Railroad Transportation of Line Pipe” (6th edition, July 2002).

§ 195.207(a).

(3) API Recommended Practice 5LW, “Transportation of Line Pipe on Barges and Marine Vessels” (2nd edition, December 1996, effective March 1, 1997).

§ 195.207(b).

(4) ANSI/API Specification 6D, “Specification for Pipeline Valves” (23rd edition, April 2008, effective October 1, 2008) and errata 3 (includes 1 & 2 (2009).

§ 195.116(d).

(5) API Specification 12F, “Specification for Shop Welded Tanks for Storage of Production Liquids” (11th edition, November 1, 1994, reaffirmed 2000, errata, February 2007).

§§ 195.132(b)(1); 195.205(b)(2); 195.264(b)(1); 195.264(e)(1); 195.307(a); 195.565; 195.579(d).

(6) API Standard 510, “Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration” (9th edition, June 2006).

§§ 195.205(b)(3); 195.432(c).

(7) API Standard 620, “Design and Construction of Large, Welded, Low-Pressure Storage Tanks” (11th edition, February 2008, addendum 1 March 2009).


§§ 195.132(b)(2); 195.205(b)(2); 195.264(b)(1); 195.264(e)(3); 195.307(b).

(8) API Standard 650, “Welded Steel Tanks for Oil Storage” (11th edition, June 2007, addendum 1, November 2008).

§§ 195.132(b)(3); 195.205(b)(1); 195.264(b)(1);195.264(e)(2); 195.307(c) 195.307(d); 195.565; 195.579(d).

(9) ANSI/API Recommended Practice 651, “Cathodic Protection of Aboveground Petroleum Storage Tanks” (3rd edition, January 2007).

§§ 195.565; 195.579(d).

(10) ANSI/API Recommended Practice 652, “Linings of Aboveground Petroleum Storage Tank Bottoms” (3rd edition, October 2005).

§ 195.579(d).

(11) API Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction” (3rd edition, December 2001, includes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)).

§§ 195.205(b)(1); 195.432(b).

(12) API Standard 1104, “Welding of Pipelines and Related Facilities” (20th edition, October 2005, errata/addendum (July 2007), and errata 2 December 2008)).

§§ 195.222(a); 195.228(b); 195.214(a).

(13) API Recommended Practice 1130, “Computational Pipeline Monitoring for Liquids: Pipeline Segment” (3rd edition, September 2007).

§§ 195.134; 195.444.

(14) API Recommended Practice 1162, “Public Awareness Programs for Pipeline Operators” (1st edition, December 2003).

§§ 195.440(a); 195.440(b); 195.440(c).

(15) API Recommended Practice 1165, “Recommended Practice for Pipeline SCADA Displays,” (API RP 1165) First Edition (January 2007).

§ 195.446(c)(1).

(16) API Standard 2000, “Venting Atmospheric and Low-Pressure Storage Tanks Nonrefrigerated and Refrigerated” (5th edition, April 1998, errata, November 15, 1999).

§§ 195.264(e)(2); 195.264(e)(3).

(17) API Recommended Practice 2003, “Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents” (7th edition, January 2008).

§ 195.405(a).

(18) API Publication 2026, “Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service” (2nd edition, April 1998, reaffirmed June 2006).

§ 195.405(b).

(19) API Recommended Practice 2350, “Overfill Protection for Storage Tanks In Petroleum Facilities”' (3rd edition, January 2005).

§ 195.428(c).

(20) API 2510, “Design and Construction of LPG Installations” (8th edition, 2001).

§§ 195.132(b)(3); 195.205(b)(3); 195.264(b)(2); 195.264(e)(4); 195.307(e); 195.428(c); 195.432(c).

(21) API Recommended Practice 1168 “Pipeline Control Room Management,” (API RP1168) First Edition (September 2008).

§ 195.446(c)(5), (f)(1).

C. ASME International (ASME):

(1) ASME/ANSI B16.9-2007, “Factory-Made Wrought Buttwelding Fittings” (December 7, 2007).



§ 195.118(a).

(2) ASME/ANSI B31.4-2006, “Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids” (October 20, 2006).

§ 195.452(h)(4)(i).

(3) ASME/ANSI B31G-1991 (Reaffirmed; 2004), “Manual for Determining the Remaining Strength of Corroded Pipelines.”

§§ 195.452(h)(4)(i)(B); 195.452(h)(4)(iii)(D).

(4) ASME/ANSI B31.8-2007, “Gas Transmission and Distribution Piping Systems” (November 30, 2007).

§ 195.5(a)(1)(i); 195.406(a)(1)(i).

(5) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 1 “Rules for Construction of Pressure Vessels” (2007 edition, July 1, 2007).

§ 195.124; 195.307(e).

(6) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 “Alternate Rules, Rules for Construction of Pressure Vessels” (2007 edition, July 1, 2007).

§ 195.307(e).

(7) 2007 ASME Boiler & Pressure Vessel Code, Section IX: “Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators,” (2007 edition, July 1, 2007).

§ 195.222(a).

D. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS):

(1) MSS SP-75-2004, “Specification for High Test Wrought Butt Welding Fittings.”.

(2) [Reserved].............................................................

§ 195.118(a).



E. American Society for Testing and Materials (ASTM):

(1) ASTM A53/A53M-07, “Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless” (September 1, 2007).


§ 195.106(e).



(2) ASTM A106/A106M-08, “Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service” (July 15, 2008).

§ 195.106(e).

(3) ASTM A333/A 333M-05, “Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service”.

§ 195.106(e).

(4) ASTM A381-96 (Reapproved 2005), “Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems” (October 1, 2005).

§ 195.106(e).

(5) ASTM A671-06, “Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures” (May 1, 2006).

§ 195.106(e).

(6) ASTM A672-08, “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (May 1, 2008).

§ 195.106(e).

(7) ASTM A691-98 (reapproved 2007), “Standard Specification for Carbon and Alloy Steel Pipe Electric-Fusion-Welded for High- Pressure Service at High Temperatures.”

§ 195.106(e).

F. National Fire Protection Association (NFPA):

(1) NFPA 30, “Flammable and Combustible Liquids Code” (2008 edition, approved August 15, 2007).

(2) [Reserved]..............................................................

§ 195.264(b)(1).



G. NACE International (NACE):

(1) NACE SP0169-2007, Standard Practice, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems” (reaffirmed March 15, 2007).

(2) NACE SP0502-2008, Standard Practice, “Pipeline External Corrosion Direct Assessment Methodology” (reaffirmed March 20, 2008).

§§ 195.571; 195.573(a)(2)

§ 195.588.

* * * * *



  • 24. In §195.116, paragraph (d) is revised to read as follows:


§195.116 Valves.
* * * * *

(d) Each valve must be both hydrostatically shell tested and hydrostatically seat tested without leakage to at least the requirements set forth in Section 11 of API Standard 6D (incorporated by reference, see §195.3).

* * * * *


  • 25. Add §195.207 to subpart D to read as follows:



§195.207 Transportation of pipe.
(a) Railroad. In a pipeline operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by railroad unless the transportation is performed in accordance with API Recommended Practice 5L1 (incorporated by reference, see §195.3).

(b) Ship or barge. In a pipeline operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by ship or barge on both inland and marine waterways, unless the transportation is performed in accordance with API Recommended Practice 5LW (incorporated by reference, see §195.3).




  • 26. In §195.264, paragraph (e) is revised to read as follows:


§195.264 Impoundment, protection against entry, normal/emergency venting or pressure/vacuum relief for aboveground breakout tanks.
* * * * *

(e) For normal/emergency relief venting and pressure/vacuum-

relieving devices installed on aboveground breakout tanks after October 2, 2000, compliance with paragraph (d) of this section requires the following for the tanks specified:

(1) Normal/emergency relief venting installed on atmospheric pressure tanks built to API Specification 12F (incorporated by reference, see §195.3) must be in accordance with Section 4, and Appendices B and C, of API Specification 12F (incorporated by reference, see §195.3).

(2) Normal/emergency relief venting installed on atmospheric pressure tanks (such as those built to API Standard 650 or its predecessor Standard 12C) must be in accordance with API Standard 2000 (incorporated by reference, see §195.3).

(3) Pressure-relieving and emergency vacuum-relieving devices installed on low pressure tanks built to API Standard 620 (incorporated by reference, see §195.3) must be in accordance with section 9 of API Standard 620 (incorporated by reference, see §195.3) and its references to the normal and emergency venting requirements in API Standard 2000 (incorporated by reference, see §195.3).

(4) Pressure and vacuum-relieving devices installed on high pressure tanks built to API Standard 2510 (incorporated by reference, see §195.3) must be in accordance with sections 7 or 11 of API Standard 2510 (incorporated by reference, see §195.3).


  • 27. In §195.307, paragraphs (a) and (c) are revised to read as follows:


§195.307 Pressure testing aboveground breakout tanks.
(a) For aboveground breakout tanks built into API Specification 12F and first placed in service after October 2, 2000, pneumatic testing must be in accordance with section 5.3 of API Specification 12 F (incorporated by reference, see §195.3).

* * * * *

(c) For aboveground breakout tanks built to API Standard 650 (incorporated by reference, see §195.3) and first placed in service after October 2, 2000, testing must be in accordance with Section 5.2 of API Standard 650 (incorporated by reference, see §195.3).

* * * * *




  • 28. In §195.401, paragraph (b) is revised to read as follows:


§195.401 General requirements.
* * * * *

(b) An operator must make repairs on its pipeline system according to the following requirements:

(1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition.

(2) Integrity management repairs. When an operator discovers a condition on a pipeline covered under §195.452, the operator must correct the condition as prescribed in §195.452(h).

* * * * *


  • 29. In §195.432, paragraph (b) is revised to read as follows:


§195.432 Inspection of in-service breakout tanks.
* * * * *

(b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3).

* * * * *


  • 30. In §195.452, paragraphs (h)(4)(i) introductory text is revised to read as follows:


§195.452 Pipeline integrity management in high consequence areas.
* * * * *

(h) * * *

(4) * * *

(i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see §195.3). An operator must treat the following conditions as immediate repair conditions:

* * * * *


  • 31. Section 195.571 is revised to read as follows:


§195.571 What criteria must I use to determine the adequacy of cathodic protection?
Cathodic protection required by this Subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE SP 0169 (incorporated by reference, see §195.3).


  • 32. In §195.573, paragraph (a)(2) is revised to read as follows:


§195.573 What must I do to monitor external corrosion control?

(a) * * *

(2) Identify not more than 2 years after cathodic protection is installed, the circumstances in which a close-interval survey or comparable technology is practicable and necessary to accomplish the objectives of paragraph 10.1.1.3 of NACE SP 0169 (incorporated by reference, see §195.3).

* * * * *




  • 33. In §195.588, paragraphs (b)(1), (b)(2) introductory text, (b)(2)(iii), (b)(3) introductory text, (b)(4) introductory text, (b)(4)(ii), (b)(4)(iv), (b)(5) introductory text, and (b)(5)(ii) are revised to read as follows:


§195.588 What standards apply to direct assessment?
* * * * *

(b) * * *

(1) General. You must follow the requirements of NACE SP0502 (incorporated by reference, see §195.3). Also, you must develop and implement a External Corrosion Direct Assessment (ECDA) plan that includes procedures addressing pre-assessment, indirect examination, direct examination, and post-assessment.

(2) Pre-assessment. In addition to the requirements in Section 3 of NACE SP0502 (incorporated by reference, see §195.3), the ECDA plan procedures for pre-assessment must include--

* * * * *

(iii) If you utilize an indirect inspection method not described in Appendix A of NACE SP0502 (incorporated by reference, see §195.3), you must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method.

(3) Indirect examination. In addition to the requirements in Section 4 of NACE SP0502 (incorporated by reference, see §195.3), the procedures for indirect examination of the ECDA regions must include--

* * * * *

(4) Direct examination. In addition to the requirements in Section 5 of NACE SP0502 (incorporated by reference, see §195.3), the procedures for direct examination of indications from the indirect examination must include--

* * * * *

(ii) Criteria for deciding what action should be taken if either:

(A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE SP0502 (incorporated by reference, see §195.3) provides guidance for criteria); or

(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE SP0502 (incorporated by reference, see §195.3) provides guidance for criteria);

* * * * *

(iv) Criteria that describe how and on what basis you will reclassify and re-prioritize any of the provisions specified in Section 5.9 of NACE SP0502 (incorporated by reference, see §195.3).

(5) Post assessment and continuing evaluation. In addition to the requirements in Section 6 of NACE SP 0502 (incorporated by reference, see §195.3), the procedures for post assessment of the effectiveness of the ECDA process must include--

* * * * *

(ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the pipeline segment at an interval less than that specified in Sections 6.2 and 6.3 of NACE SP0502 (see appendix D of NACE SP0502) (incorporated by reference, see §195.3).




  • 34. In Appendix C to part 195, paragraph I. A. introductory text is revised to read as follows:


Appendix C to Part 195--Guidance for Implementation of an Integrity Management Program
* * * * *

I. * * *


A. The rule defines a High Consequence Area as a high population area, another populated area, an unusually sensitive area, or a commercially navigable waterway. The Office of Pipeline Safety (OPS) will map these areas on the National Pipeline Mapping System (NPMS). An operator, member of the public or other government agency may view and download the data from the NPMS home page http://www.npms.phmsa.gov/. OPS will maintain the NPMS and update it periodically. However, it is an operator's responsibility to ensure that it has identified all high consequence areas that could be affected by a pipeline segment. An operator is also responsible for periodically evaluating its pipeline segments to look for population or environmental changes that may have occurred around the pipeline and to keep its program current with this information. (Refer to §195.452(d)(3).)

* * * * *


Issued in Washington, DC, on August 3, 2010, under authority delegated in 49 CFR part 1.

Cynthia L. Quarterman,

Administrator.
[FR Doc. 2010-19643 Filed 8-10-10; 8:45 am]

BILLING CODE 4910-60-P





Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010

Pages 48593 - 48608

/

192-114

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