reglab/statecodes huggingface dataset:
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2109 - External Corrosion Control: Buried or Submerged Pipelines Installed before August 1, 1971 [49 CFR 192.457]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Except for buried piping at compressor,
				  regulator, and measuring stations, each buried or submerged transmission line
				  installed before August 1, 1971, that has an effective external coating must be
				  cathodically protected along the entire area that is effectively coated, in
				  accordance with this Chapter. For the purposes of this Chapter, a pipeline does
				  not have an effective external coating if its cathodic protection current
				  requirements are substantially the same as if it were bare. The operator shall
				  make tests to determine the cathodic protection current requirements. [
				49
				  CFR 192.457(a)]
B. Except for cast iron or ductile iron, each
				  of the following buried or submerged pipelines installed before August 1, 1971,
				  must be cathodically protected in accordance with this Chapter in areas in
				  which active corrosion is found: [
				49
				  CFR 192.457(b)]
1. bare or ineffectively coated transmission
				  lines; [
				49
				  CFR 192.457(b)(1)]
2. bare or coated pipes at compressor,
				  regulator, and measuring stations; [
				49
				  CFR 192.457(b)(2)]
3. bare or coated distribution lines. [
				49
				  CFR 192.457(b)(3)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2111 - External Corrosion Control: Examination of Buried Pipeline When Exposed [49 CFR 192.459]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Whenever an
				  operator has knowledge that any portion of a buried pipeline is exposed, the
				  exposed portion must be examined for evidence of external corrosion if the pipe
				  is bare, or if the coating is deteriorated. If external corrosion requiring
				  remedial action under
				  §2135 is
				  found, the operator shall investigate circumferentially and longitudinally
				  beyond the exposed portion (by visual examination, indirect method, or both) to
				  determine whether additional corrosion requiring remedial action exists in the
				  vicinity of the exposed portion. [
				49
				  CFR 192.459]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2113 - External Corrosion Control: Protective Coating [49 CFR 192.461]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each external
				  protective coating, whether conductive or insulating, applied for the purpose
				  of external corrosion control must: [
				49 CFR
				  192.461(a)]
1. be applied on a properly prepared surface;
				  [
				49 CFR
				  192.461(a)(1)]
2. have sufficient adhesion to the metal
				  surface to effectively resist underfilm migration of moisture; [
				49 CFR
				  192.461(a)(2)]
3. be sufficiently ductile to resist
				  cracking; [
				49 CFR
				  192.461(a)(3)]
4. have sufficient strength to resist damage
				  due to handling and soil stress; and [
				49 CFR
				  192.461(a)(4)]
5. have properties compatible with any
				  supplemental cathodic protection. [
				49 CFR
				  192.461(a)(5)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2115 - External Corrosion Control: Cathodic Protection [49 CFR 192.463]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each cathodic
				  protection system required by this Chapter must provide a level of cathodic
				  protection that complies with one or more of the applicable criteria contained
				  in §5107, Appendix D of this Subpart. If none of these criteria is
				  applicable, the cathodic protection system must provide a level of cathodic
				  protection at least equal to that provided by compliance with one or more of
				  these criteria. [
				49 CFR
				  192.463(a)]
B. If amphoteric metals are included in a
				  buried or submerged pipeline containing a metal or different anodic potential:
				  [
				49 CFR
				  192.463(b)]
1. the amphoteric metals must be electrically
				  isolated from the remainder of the pipeline and cathodically protected; or [
				49 CFR
				  192.463(b)(1)]
2. the entire buried or submerged pipeline
				  must be cathodically protected at a cathodic potential that meet the
				  requirements of §5107, Appendix D of this Subpart for amphoteric metals. [
				49 CFR
				  192.463(b)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2117 - External Corrosion Control: Monitoring [49 CFR 192.465]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each pipeline
				  that is under cathodic protection must be tested at least once each calendar
				  year, but with intervals not exceeding 15 months, to determine whether the
				  cathodic protection meets the requirements of §2115 However, if tests at
				  those intervals are impractical for separately protected short sections of
				  mains or transmission lines, not in excess of 100 feet (30 meters), or
				  separately protected service lines, these pipelines may be surveyed on a
				  sampling basis. At least 10 percent of these protected structures, distributed
				  over the entire system must be surveyed each calendar year, with a different 10
				  percent checked each subsequent year, so that the entire system is tested in
				  each 10-year period. [
				49 CFR
				  192.465(a)]
B. Cathodic protection rectifiers and
				  impressed current power sources must be periodically inspected as follows:
				  [49 CFR
				  192.465(b)]
1. Each cathodic protection rectifier or
				  impressed current power source must be inspected 6 times each calendar year,
				  but with intervals not exceeding 2 1/2 months between inspections, to ensure
				  adequate amperage and voltage levels needed to provide cathodic protection are
				  maintained. This may be done either through remote measurement or through an
				  onsite inspection of the rectifier. [49 CFR
				  192.465(b)(1)]
2. After January 1, 2022, each remotely
				  inspected rectifier must be physically inspected for continued safe and
				  reliable operation at least once each calendar year, but with intervals not
				  exceeding 15 months. [49 CFR
				  192.465(b)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2119 - External Corrosion Control: Electrical Isolation [49 CFR 192.467]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each buried or
				  submerged pipeline must be electrically isolated from other underground
				  metallic structures, unless the pipeline and the other structures are
				  electrically interconnected and cathodically protected as a single unit. [
				49 CFR
				  192.467(a)]
B. One or more insulating devices must be
				  installed where electrical isolation of a portion of a pipeline is necessary to
				  facilitate the application of corrosion control. [
				49 CFR
				  192.467(b)]
C. Except for unprotected copper inserted in
				  a ferrous pipe, each pipeline must be electrically isolated from metallic
				  casings that are a part of the underground system. However, if isolation is not
				  achieved because it is impractical, other measures must be taken to minimize
				  corrosion of the pipeline inside the casing. [
				49 CFR
				  192.467(c)]
D. Inspection and electrical tests must be
				  made to assure that electrical isolation is adequate. [
				49 CFR
				  192.467(d)]
E. An insulating device may not be installed
				  in an area where a combustible atmosphere is anticipated unless precautions are
				  taken to prevent arcing. [
				49 CFR
				  192.467(e)]
F. Where a pipeline is located in close
				  proximity to electrical transmission tower footings, ground cables or
				  counterpoise, or in other areas where fault currents or unusual risk of
				  lightning may be anticipated, it must be provided with protection against
				  damage due to fault currents or lightning, and protective measures must also be
				  taken at insulating devices. [
				49 CFR
				  192.467(f)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2121 - External Corrosion Control: Test Stations [49 CFR 192.469]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each pipeline
				  under cathodic protection required by this Chapter must have sufficient test
				  stations or other contact points for electrical measurement to determine the
				  adequacy of cathodic protection. [
				49 CFR
				  192.469]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2123 - External Corrosion Control: Test Leads [49 CFR 192.471]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each test lead
				  wire must be connected to the pipeline so as to remain mechanically secure and
				  electrically conductive. [
				49 CFR
				  192.471(a)]
B. Each test lead wire must be attached to
				  the pipeline so as to minimize stress concentration on the pipe. [
				49 CFR
				  192.471(b)]
C. Each bared test lead wire and bared
				  metallic area at point of connection to the pipeline must be coated with an
				  electrical insulating material compatible with the pipe coating and the
				  insulation on the wire. [
				49 CFR
				  192.471(c)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2125 - External Corrosion Control: Interference Currents [49 CFR 192.473]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each operator
				  whose pipeline system is subjected to stray currents shall have in effect a
				  continuing program to minimize the detrimental effects of such currents. [
				49 CFR
				  192.473(a)]
B. Each impressed current type cathodic
				  protection system or galvanic anode system must be designed and installed so as
				  to minimize any adverse effects on existing adjacent underground metallic
				  structures. [
				49 CFR
				  192.473(b)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2127 - Internal Corrosion Control: General [49 CFR 192.475]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Corrosive gas may not be transported by
				  pipeline, unless the corrosive effect of the gas on the pipeline has been
				  investigated and steps have been taken to minimize internal corrosion. [
				49 CFR
				  192.475(a)]
B. Whenever any pipe is removed from a
				  pipeline for any reason, the internal surface must be inspected for evidence of
				  corrosion. If internal corrosion is found: [
				49 CFR
				  192.475(b)]
1. the adjacent pipe must be investigated to
				  determine the extent of internal corrosion; [
				49 CFR
				  192.475(b)(1)]
2. replacement must be made to the extent
				  required by the applicable Subsections of §§2137, 2139, or 2141; and
				  [
				49 CFR
				  192.475(b)(2)]
3. steps must be taken to minimize the
				  internal corrosion. [
				49 CFR
				  192.475(b)(3)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2128 - Internal Corrosion Control: Design and Construction of Transmission Line [49 CFR 192.476]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Design and
				  construction. Except as provided in subsection B of this section, each new
				  transmission line and each replacement of line pipe, valve, fitting, or other
				  line component in a transmission line must have features incorporated into its
				  design and construction to reduce the risk of internal corrosion. At a minimum,
				  unless it is impracticable or unnecessary to do so, each new transmission line
				  or replacement of line pipe, valve, fitting, or other line component in a
				  transmission line must: [
				49
				  CFR 192.476(a)]
1. be configured to reduce the risk that
				  liquids will collect in the line; [
				49
				  CFR 192.476(a)(1)]
2. have effective liquid removal features
				  whenever the configuration would allow liquids to collect; and [
				49
				  CFR 192.476(a)(2)]
3. allow use of devices for monitoring
				  internal corrosion at locations with significant potential for internal
				  corrosion. [
				49
				  CFR 192.476(a)(3)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2129 - Internal Corrosion Control: Monitoring [49 CFR 192.477]

Current through Register Vol. 50, No. 6, June 20, 2024
A. If corrosive gas
				  is being transported, coupons or other suitable means must be used to determine
				  the effectiveness of the steps taken to minimize internal corrosion. Each
				  coupon or other means of monitoring internal corrosion must be checked two
				  times each calendar year, but with intervals not exceeding seven and one-half
				  months. [
				49 CFR
				  192.477]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2131 - Atmospheric Corrosion Control: General [49 CFR 192.479]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each operator must clean and coat each
				  pipeline or portion of pipeline that is exposed to the atmosphere, except
				  pipelines under Subsection C of this Section. [
				49 CFR
				  192.479(a)]
B. Coating material must be suitable for the
				  prevention of atmospheric corrosion. [
				49 CFR
				  192.479(b)]
C. Except portions of pipelines in offshore
				  splash zones or soil-to-air interfaces, the operator need not protect from
				  atmospheric corrosion any pipeline for which the operator demonstrates by test,
				  investigation, or experience appropriate to the environment of the pipeline
				  that corrosion will: [
				49 CFR
				  192.479(c)]
1. only be a light surface oxide; or [
				49 CFR
				  192.479(c)(1)]
2. not affect the safe operation of the
				  pipeline before the next scheduled inspection. [
				49 CFR
				  192.479(c)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2133 - Atmospheric Corrosion Control: Monitoring [49 CFR 192.481]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each operator
				  must inspect each pipeline or portion of pipeline that is exposed to the
				  atmosphere for evidence of atmospheric corrosion, as follows. [49 CFR
				  192.481(a)]
If the pipeline is located:
Then the frequency of inspection
								is:
Onshore other than a service line
At least once every 3 calendar years, but with
								intervals not exceeding 39 months.
Onshore service line
At least once every 5 calendar years, but with
								intervals not exceeding 63 months, except as provided in Subsection D of this
								Section.
Offshore
At least once each calendar year, but with
								intervals not exceeding 15 months.
B.
				  During inspections the operator must give particular attention to pipe at
				  soil-to-air interfaces, under thermal insulation, under disbonded coatings, at
				  pipe supports, in splash zones, at deck penetrations, and in spans over water.
				  [49 CFR
				  192.481(b)]
C. If atmospheric corrosion is found during
				  an inspection, the operator must provide protection against the corrosion as
				  required by
				  §2131 [49 CFR
				  192.481(c)]
D. If atmospheric corrosion is found on a
				  service line during the most recent inspection, then the next inspection of
				  that pipeline or portion of pipeline must be within 3 calendar years, but with
				  intervals not exceeding 39 months. [49 CFR
				  192.481(d)]
AUTHORITY
					 NOTE: Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2135 - Remedial Measures: General [49 CFR 192.483]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each segment of metallic pipe that
				  replaces pipe removed from a buried or submerged pipeline because of external
				  corrosion must have a properly prepared surface and must be provided with an
				  external protective coating that meets the requirements of §2113 [
				49 CFR
				  192.483(a)]
B. Each segment of metallic pipe that
				  replaces pipe removed from a buried or submerged pipeline because of external
				  corrosion must be cathodically protected in accordance with this Chapter. [
				49 CFR
				  192.483(b)]
C. Except for cast iron or ductile iron pipe,
				  each segment of buried or submerged pipe that is required to be repaired
				  because of external corrosion must be cathodically protected in accordance with
				  this Chapter. [
				49 CFR
				  192.483(c)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2137 - Remedial Measures: Transmission Lines [49 CFR 192.485]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General Corrosion. Each segment of
				  transmission line with general corrosion and with a remaining wall thickness
				  less than that required for the MAOP of the pipeline must be replaced or the
				  operating pressure reduced commensurate with the strength of the pipe based on
				  actual remaining wall thickness. However, corroded pipe may be repaired by a
				  method that reliable engineering tests and analyses show can permanently
				  restore the serviceability of the pipe. Corrosion pitting so closely grouped as
				  to affect the overall strength of the pipe is considered general corrosion for
				  the purpose of this Subsection. [
				49 CFR
				  192.485(a)]
B. Localized Corrosion Pitting. Each segment
				  of transmission line pipe with localized corrosion pitting to a degree where
				  leakage might result must be replaced or repaired, or the operating pressure
				  must be reduced commensurate with the strength of the pipe, based on the actual
				  remaining wall thickness in the pits. [
				49 CFR
				  192.485(b)]
C. Under Subsections A and B of this Section,
				  the strength of pipe based on actual remaining wall thickness may be determined
				  by the procedure in ASME/ANSI B31G (incorporated by reference, see §507)
				  or the procedure in PRCI PR 3-805 (R-STRENG) (incorporated by reference, see
				  §507). Both procedures apply to corroded regions that do not penetrate the
				  pipe wall, subject to the limitations prescribed in the procedures. [
				49 CFR
				  192.485(c)
				  ]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2139 - Remedial Measures: Distribution Lines Other Than Cast Iron or Ductile Iron Lines [49 CFR 192.487]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General
				  Corrosion. Except for cast iron or ductile iron pipe, each segment of generally
				  corroded distribution line pipe with a remaining wall thickness less than that
				  required for the MAOP of the pipeline, or a remaining wall thickness less than
				  30 percent of the nominal wall thickness, must be replaced. However, corroded
				  pipe may be repaired by a method that reliable engineering tests and analyses
				  show can permanently restore the serviceability of the pipe. Corrosion pitting
				  so closely grouped as to affect the overall strength of the pipe is considered
				  general corrosion for the purpose of this Subsection. [
				49
				  CFR 192.487(a)]
B. Localized Corrosion Pitting. Except for
				  cast iron or ductile iron pipe, each segment of distribution line pipe with
				  localized corrosion pitting to a degree where leakage might result must be
				  replaced or repaired. [
				49
				  CFR 192.487(b)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2141 - Remedial Measures: Cast Iron and Ductile Iron Pipelines [49 CFR 192.489]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General
				  Graphitization. Each segment of cast iron or ductile iron pipe on which general
				  graphitization is found to a degree where a fracture or any leakage might
				  result, must be replaced. [
				49 CFR
				  192.489(a)]
B. Localized Graphitization. Each segment of
				  cast iron or ductile iron pipe on which localized graphitization is found to a
				  degree where any leakage might result, must be replaced or repaired, or sealed
				  by internal sealing methods adequate to prevent or arrest any leakage. [
				49 CFR
				  192.489(b)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2142 - Direct Assessment [49 CFR 192.490]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each operator that uses direct assessment
				  as defined in
				  §3303 on an
				  onshore transmission line made primarily of steel or iron to evaluate the
				  effects of a threat in the first column must carry out the direct assessment
				  according to the standard listed in the second column. These standards do not
				  apply to methods associated with direct assessment, such as close interval
				  surveys, voltage gradient surveys, or examination of exposed pipelines, when
				  used separately from the direct assessment process [
				49 CFR
				  192.490].
Threat
Standard1
External corrosion
§33252
Internal corrosion in pipelines that transport dry
								gas.
§3327
Stress corrosion cracking
§3329
1 For lines not subject to
					 Chapter 33 of this Subpart, the terms "covered segment" and "covered pipeline
					 segment" in §§3325, 3327, and 3329 refer to the pipeline segment on
					 which direct assessment is performed.
2 In §3325B, the provision
					 regarding detection of coating damage applies only to pipelines subject to
					 Chapter 33 of this Subpart.
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2143 - Corrosion Control Records [49 CFR 192.491]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each operator shall maintain records or
				  maps to show the location of cathodically protected piping, cathodic protection
				  facilities, galvanic anodes, and neighboring structures bonded to the cathodic
				  protection system. Records or maps showing a stated number of anodes, installed
				  in a stated manner or spacing, need not show specific distances to each buried
				  anode. [
				49 CFR
				  192.491(a)]
B. Each record or map required by Subsection
				  A of this Section must be retained for as long as the pipeline remains in
				  service. [
				49 CFR
				  192.491(b)]
C. Each operator shall maintain a record of
				  each test, survey, or inspection required by this Section in sufficient detail
				  to demonstrate the adequacy of corrosion control measures or that a corrosive
				  condition does not exist. These records must be retained for at least five
				  years with the following exceptions: [49 CFR
				  192.491(c)]
1. Operators must retain records related to
				  §2117.A and E and
				  2127.B for as long as the pipeline remains in service. [49
				  CFR 192.491(c)(1)]
2. Operators must retain records of the two
				  most recent atmospheric corrosion inspections for each distribution service
				  line that is being inspected under the interval in
				  §2133.A [49
				  CFR
				  192.491(c)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 21 - Requirements for Corrosion Control [49 CFR Part 192 Subpart I] › Section XIII-2145 - In-Line Inspection of Pipelines [49 CFR 192.493]

Current through Register Vol. 50, No. 6, June 20, 2024
A. When conducting in-line inspections of
				  pipelines required by this part, an operator must comply with API STD 1163,
				  ANSI/ASNT ILI-PQ, and NACE SP0102, (incorporated by reference, see §507).
				  Assessments may be conducted using tethered or remotely controlled tools, not
				  explicitly discussed in NACE SP0102, provided they comply with those sections
				  of NACE SP0102 that are applicable. [49 CFR
				  192.493]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2301 - Scope [49 CFR 192.501]

Current through Register Vol. 50, No. 6, June 20, 2024
A. This
				  Chapter prescribes minimum leak-test and strength-test requirements for
				  pipelines. [
				49 CFR
				  192.501]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2303 - General Requirements [49 CFR 192.503]

Current through Register Vol. 50, No. 6, June 20, 2024
A. No person may operate a new segment of
				  pipeline, or return to service a segment of pipeline that has been relocated or
				  replaced, until: [
				49 CFR
				  192.503(a)]
1. it has been tested in accordance with this
				  Chapter and
				  §2719 to
				  substantiate the maximum allowable operating pressure; and [
				49 CFR
				  192.503(a)(1)]
2. each potentially hazardous leak has been
				  located and eliminated. [
				49 CFR
				  192.503(a)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2305 - Strength Test Requirements for Steel Pipeline to Operate at a Hoop Stress of 30 Percent or More of SMYS [49 CFR 192.505]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Except for service lines, each segment of
				  a steel pipeline that is to operate at a hoop stress of 30 percent or more of
				  SMYS must be strength tested in accordance with this Section to substantiate
				  the proposed maximum allowable operating pressure. In addition, in a Class 1 or
				  Class 2 location, if there is a building intended for human occupancy within
				  300 feet (91 meters) of a pipeline, a hydrostatic test must be conducted to a
				  test pressure of at least 125 percent of maximum operating pressure on that
				  segment of the pipeline within 300 feet (91 meters) of such a building, but in
				  no event may the test section be less than 600 feet (183 meters) unless the
				  length of the newly installed or relocated pipe is less than 600 feet (183
				  meters). However, if the buildings are evacuated while the hoop stress exceeds
				  50 percent of SMYS, air or inert gas may be used as the test medium. [
				49
				  CFR 192.505(a)]
B. In a Class 1 or Class 2 location, each
				  compressor station, regulator station, and measuring station, must be tested to
				  at least Class 3 location test requirements. [
				49
				  CFR 192.505(b)]
C. Except as provided in Subsection D of this
				  Section, the strength test must be conducted by maintaining the pressure at or
				  above the test pressure for at least eight hours. [
				49
				  CFR 192.505(c)]
D. For fabricated units and short sections of
				  pipe, for which a post installation test is impractical, a pre-installation
				  strength test must be conducted by maintaining the pressure at or above the
				  test pressure for at least four hours. [
				49
				  CFR 192.505(d)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2306 - Transmission Lines: Spike Hydrostatic Pressure Test [49 CFR 192.506]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Spike Test
				  Requirements. Whenever a segment of steel transmission pipeline that is
				  operated at a hoop stress level of 30 percent or more of SMYS is spike tested
				  under this part, the spike hydrostatic pressure test must be conducted in
				  accordance with this Section. [49
				  CFR 192.506(a)]
1. The test must use water as the test
				  medium. [49 CFR
				  192.506(a)(1)]
2. The baseline test pressure must be as
				  specified in the applicable Paragraphs of
				  §2719.A.2 or
				  §2720.A 2, whichever
				  applies. [49 CFR
				  192.506(a)(2)]
3. The test must be conducted by maintaining
				  a pressure at or above the baseline test pressure for at least eight hours as
				  specified in
				  §2305 [49 CFR
				  192.506(a)(3)]
4. After the test pressure stabilizes at the
				  baseline pressure and within the first two hours of the eight-hour test
				  interval, the hydrostatic pressure must be raised (spiked) to a minimum of the
				  lesser of 1.5 times MAOP or 100 percent SMYS. This spike hydrostatic pressure
				  test must be held for at least 15 minutes after the spike test pressure
				  stabilizes. [49 CFR
				  192.506(a)(4)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2307 - Test Requirements for Pipelines to Operate at a Hoop Stress Less Than 30 Percent of SMYS and At or Above 100 psi (689 kPa) Gauge [49 CFR 192.507]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Except for
				  service lines and plastic pipelines, each segment of a pipeline that is to be
				  operated at a hoop stress less than 30 percent of SMYS and at or above 100 psi
				  (689 kPa) gage must be tested in accordance with the following. [49
				  CFR 192.507]
1. The pipeline operator must use a test
				  procedure that will ensure discovery of all potentially hazardous leaks in the
				  segment being tested. [49
				  CFR 192.507(a)]
2. If, during the test, the segment is to be
				  stressed to 20 percent or more of SMYS and natural gas, inert gas, or air is
				  the test medium: [49
				  CFR 192.507(b)]
a. a leak test must be made at a pressure
				  between 100 psi (689 kPa) gage and the pressure required to produce a hoop
				  stress of 20 percent of SMYS; or [49
				  CFR 192.507(b)(1)]
b. the line must be walked to check for leaks
				  while the hoop stress is held at approximately 20 percent of SMYS.
				  [49
				  CFR 192.507(b)(2)]
3. The pressure must be maintained
				  at or above the test pressure for at least one hour. [49
				  CFR 192.507(c)]
4. For fabricated units and short sections of
				  pipe, for which a post installation test is impractical, a pre-installation
				  hydrostatic pressure test must be conducted in accordance with the requirements
				  of this Section. [49
				  CFR
				  192.507(d)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2309 - Test Requirements for Pipelines to Operate below 100 psi (689 kPa) Gauge [49 CFR 192.509]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Except for
				  service lines and plastic pipelines, each segment of a pipeline that is to be
				  operated below 100 psi (689 kPa) gage must be leak tested in accordance with
				  the following. [
				49
				  CFR 192.509]
1. The test procedure used must ensure
				  discovery of all potentially hazardous leaks in the segment being tested. [
				49
				  CFR 192.509(a)]
2. Each main that is to be operated at less
				  than 1 psi (6.9 kPa) gage must be tested to at least 10 psi (69 kPa) gage and
				  each main to be operated at or above 1 psi (6.9 kPa) gage must be tested to at
				  least 90 psi (621 kPa) gage. [
				49
				  CFR 192.509(b)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2311 - Test Requirements for Service Lines [49 CFR 192.511]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each segment of
				  a service line (other than plastic) must be leak tested in accordance with this
				  Section before being placed in service. If feasible, the service-line
				  connection to the main must be included in the test; if not feasible, it must
				  be given a leakage test at the operating pressure when placed in service. [
				49 CFR
				  192.511(a)]
B. Each segment of a service line (other than
				  plastic) intended to be operated at a pressure of at least 1 psi (6.9 kPa) gage
				  but not more than 40 psi (276 kPa) gage must be given a leak test at a pressure
				  of not less than 50 psi (345 kPa) gage. [
				49 CFR
				  192.511(b)]
C. Each segment of a service line (other than
				  plastic) intended to be operated at pressures of more than 40 psi (276 kPa)
				  gage must be tested to at least 90 psi (621 kPa) gage, except that each segment
				  of the steel service line stressed to 20 percent or more of SMYS must be tested
				  in accordance with
				  §2307 of this
				  Chapter. [
				49 CFR
				  192.511(c)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2313 - Test Requirements for Plastic Pipelines [49 CFR 192.513]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Each segment of
				  a plastic pipeline must be tested in accordance with this Section. [
				49 CFR
				  192.513(a)]
B. The test procedure must insure discovery
				  of all potentially hazardous leaks in the segment being tested. [
				49 CFR
				  192.513(b)]
C. The test pressure must be at least 150
				  percent of the maximum operating pressure or 50 psi (345 kPa) gage, whichever
				  is greater. However, the maximum test pressure may not be more than 2.5 times
				  the pressure determined under §921, at a temperature not less than the
				  pipe temperature during the test. [49 CFR
				  192.513(c)]
D. During the test, the temperature of
				  thermoplastic material may not be more than 100°F (38°C), or the
				  temperature at which the material's long-term hydrostatic strength has been
				  determined under the listed specification, whichever is greater. [
				49 CFR
				  192.513(d)]
AUTHORITY NOTE:
					 Promulgated in accordance with R. S. 30:501 et
					 seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2315 - Environmental Protection and Safety Requirements [49 CFR 192.515]

Current through Register Vol. 50, No. 6, June 20, 2024
A. In conducting
				  tests under this Chapter, each operator shall insure that every reasonable
				  precaution is taken to protect its employees and the general public during the
				  testing. Whenever the hoop stress of the segment of the pipeline being tested
				  will exceed 50 percent of SMYS, the operator shall take all practicable steps
				  to keep persons not working on the testing operation outside of the testing
				  area until the pressure is reduced to or below the proposed maximum allowable
				  operating pressure. [
				49 CFR
				  192.515(a)]
B. The operator shall insure that the test
				  medium is disposed of in a manner that will minimize damage to the environment.
				  [
				49 CFR
				  192.515(b)]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 23 - Test Requirements [49 CFR Part 192 Subpart J] › Section XIII-2317 - Records [49 CFR 192.517]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An
				  operator must make, and retain for the useful life of the pipeline, a record of
				  each test performed under
				  §2305 The record must contain at least the following information:
				  [49 CFR
				  192.517(a)]
1. the operator's name, the name of the
				  operator's employee responsible for making the test, and the name of any test
				  company used; [
				49 CFR
				  192.517(a)(1)]
2. test medium used; [
				49 CFR
				  192.517(a)(2)]
3. test pressure; [
				49 CFR
				  192.517(a)(3)]
4. test duration; [
				49 CFR
				  192.517(a)(4)]
5. pressure recording charts, or other record
				  of pressure readings; [
				49 CFR
				  192.517(a)(5)]
6. elevation variations, whenever significant
				  for the particular test; [
				49 CFR
				  192.517(a)(6)]
7. leaks and failures noted and their
				  disposition. [
				49 CFR
				  192.517(a)(7)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 25 - Uprating [Subpart K] › Section XIII-2501 - Scope [49 CFR 192.551]

Current through Register Vol. 50, No. 6, June 20, 2024
A. This
				  Chapter prescribes minimum requirements for increasing maximum allowable
				  operating pressures (uprating) for pipelines. [
				49 CFR
				  192.551]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 25 - Uprating [Subpart K] › Section XIII-2503 - General Requirements [49 CFR 192.553]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Pressure Increases. Whenever the
				  requirements of this Chapter require that an increase in operating pressure be
				  made in increments, the pressure must be increased gradually, at a rate that
				  can be controlled, and in accordance with the following. [
				49 CFR
				  192.553(a)]
1. At the end of each incremental increase,
				  the pressure must be held constant while the entire segment of the pipeline
				  that is affected is checked for leaks. [
				49 CFR
				  192.553(a)(1)]
2. Each leak detected must be repaired before
				  a further pressure increase is made, except that a leak determined not to be
				  potentially hazardous need not be repaired, if it is monitored during the
				  pressure increase and it does not become potentially hazardous. [
				49 CFR
				  192.553(a)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 25 - Uprating [Subpart K] › Section XIII-2505 - Uprating to a Pressure That Will Produce a Hoop Stress of 30 Percent or More of SMYS in Steel Pipelines [49 CFR 192.555]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Unless the requirements of this Section
				  have been met, no person may subject any segment of a steel pipeline to an
				  operating pressure that will produce a hoop stress of 30 percent or more of
				  SMYS and that is above the established maximum allowable operating pressure. [
				49
				  CFR 192.555(a)]
B. Before increasing operating pressure above
				  the previously established maximum allowable operating pressure the operator
				  shall: [
				49
				  CFR 192.555(b)]
1. review the design, operating, and
				  maintenance history and previous testing of the segment of pipeline and
				  determine whether the proposed increase is safe and consistent with the
				  requirements of this Subpart; and [
				49
				  CFR 192.555(b)(1)]
2. make any repairs, replacements, or
				  alterations in the segment of pipeline that are necessary for safe operation at
				  the increased pressure. [
				49
				  CFR 192.555(b)(2)
				  ]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 25 - Uprating [Subpart K] › Section XIII-2507 - Uprating: Steel Pipelines to a Pressure That Will Produce a Hoop Stress Less Than 30 Percent of SMYS: Plastic, Cast Iron, and Ductile Iron Pipelines [49 CFR 192.557]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Unless the
				  requirements of this Section have been met, no person may subject: [
				49
				  CFR 192.557(a)]
1. a segment of steel pipeline to an
				  operating pressure that will produce a hoop stress less than 30 percent of SMYS
				  and that is above the previously established maximum allowable operating
				  pressure; or [
				49
				  CFR 192.557(a)(1)]
2. a plastic, cast iron, or ductile iron
				  pipeline segment to an operating pressure that is above the previously
				  established maximum allowable operating pressure. [
				49
				  CFR 192.557(a)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 3 - Transportation of Natural Gas or Other Gas by Pipeline: Minimum Safety Standards [49 CFR Part 192] › Chapter 27 - Operations [49 CFR Part 192 Subpart L] › Section XIII-2701 - Scope [49 CFR 192.601]

Current through Register Vol. 50, No. 6, June 20, 2024
A. This
				  Chapter prescribes minimum requirements for the operation of pipeline
				  facilities. [
				49 CFR
				  192.601]
AUTHORITY NOTE:
					 Promulgated in accordance with
					 R.S. 30:501
					 et seq.