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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3325 - What Are the Requirements for Using External Corrosion Direct Assessment (ECDA)? [49 CFR 192.925]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Definition.
				  ECDA is a four-step process that combines preassessment, indirect inspection,
				  direct examination, and post assessment to evaluate the threat of external
				  corrosion to the integrity of a pipeline. [
				49
				  CFR 192.925(a)]
B. General Requirements. An operator that
				  uses direct assessment to assess the threat of external corrosion must follow
				  the requirements in this Section, in ASME/ANSI B31.8S (incorporated by
				  reference, see §507), section 6 4, and in NACE SP0502 (incorporated by
				  reference, see §507). An operator must develop and implement a direct
				  assessment plan that has procedures addressing pre-assessment, indirect
				  examination, direct examination, and post-assessment. If the ECDA detects
				  pipeline coating damage, the operator must also integrate the data from the
				  ECDA with other information from the data integration (§3317.B) to evaluate
				  the covered segment for the threat of third party damage, and to address the
				  threat as required by
				  §3317.E.1 [
				49
				  CFR 192.925(b)].
1. Pre-assessment. In addition to the
				  requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 3, the
				  plan's procedures for pre-assessment must include: [
				49
				  CFR 192.925(b)(1)]
a. provisions for applying more restrictive
				  criteria when conducting ECDA for the first time on a covered segment; and [
				49
				  CFR
				  192.925(b)(1)(i)]
b. the basis on which an operator selects at
				  least two different, but complementary indirect assessment tools to assess each
				  ECDA Region. If an operator utilizes an indirect inspection method that is not
				  discussed in appendix A of NACE SP0502, the operator must demonstrate the
				  applicability, validation basis, equipment used, application procedure, and
				  utilization of data for the inspection method. [
				49
				  CFR 192.925(b)(1)(ii)
				  ]
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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3329 - What Are the Requirements for Using Direct Assessment for Stress Corrosion Cracking (SCCDA) ? [49 CFR 192.929]

Current through Register Vol. 50, No. 6, June 20, 2024
A.
				  Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) is a process to
				  assess a covered pipe segment for the presence of SCC primarily by
				  systematically gathering and analyzing excavation data for pipe having similar
				  operational characteristics and residing in a similar physical environment. [
				49
				  CFR 192.929(a)]
B. General Requirements. An operator using
				  direct assessment as an integrity assessment method to address stress corrosion
				  cracking in a covered pipeline segment must have a plan that provides, at
				  minimum, for: [
				49
				  CFR 192.929(b)]
1. Data Gathering and Integration. An
				  operator's plan must provide for a systematic process to collect and evaluate
				  data for all covered segments to identify whether the conditions for SCC are
				  present and to prioritize the covered segments for assessment. This process
				  must include gathering and evaluating data related to SCC at all sites an
				  operator excavates during the conduct of its pipeline operations where the
				  criteria in ASME/ANSI B31.8S (incorporated by reference, see §507),
				  Appendix A3.3 indicate the potential for SCC. This data includes at minimum,
				  the data specified in ASME/ANSI B31.8S, Appendix A3 [
				49
				  CFR
				  192.929(b)(1)];
2. Assessment Method. The plan must provide
				  that if conditions for SCC are identified in a covered segment, an operator
				  must assess the covered segment using an integrity assessment method specified
				  in ASME/ANSI B31.8S, appendix A3, and remediate the threat in accordance with
				  ASME/ANSI B31.8S, appendix A3, section A3.4. [
				49
				  CFR 192.929(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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3331 - How may confirmatory direct assessment (CDA) be used? [49 CFR 192.931]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator
				  using the confirmatory direct assessment (CDA) method as allowed in
				  §3337 must have a plan that meets the
				  requirements of this Section and of §3325(ECDA) and §3327(ICDA) [
				49 CFR
				  192.931]
1.
				  Threats. An operator may only use CDA on a covered segment to identify damage
				  resulting from external corrosion or internal corrosion. [
				49 CFR
				  192.931(a)]
2. External Corrosion Plan. An operator's CDA
				  plan for identifying external corrosion must comply with
				  §3325 with
				  the following exceptions. [
				49 CFR
				  192.931(b)]
a. The procedures for indirect examination
				  may allow use of only one indirect examination tool suitable for the
				  application. [
				49 CFR
				  192.931(b)(1)]
b. The procedures for direct examination and
				  remediation must provide that: [
				49 CFR
				  192.931(b)(2)]
(i) all immediate action indications must be
				  excavated for each ECDA region; and [
				49 CFR
				  192.931(b)(2)(i)]
(ii) at least one high risk indication that
				  meets the criteria of scheduled action must be excavated in each ECDA region. [
				49 CFR
				  192.931(b)(2)(ii)
				  ]
3. Internal
				  Corrosion Plan. An operator's CDA plan for identifying internal corrosion must
				  comply with
				  §3327 except
				  that the plan's procedures for identifying locations for excavation may require
				  excavation of only one high risk location in each ICDA region. [
				49 CFR
				  192.931(c)]
4. Defects Requiring Near-Term Remediation.
				  If an assessment carried out under Paragraphs 2 or 3 of this Section reveals
				  any defect requiring remediation prior to the next scheduled assessment, the
				  operator must schedule the next assessment in accordance with NACE SP0502
				  (incorporated by reference, see §507), sections 6.2 If the defect requires
				  immediate remediation, then the operator must reduce pressure consistent with
				  §3333 until
				  the operator has completed reassessment using one of the assessment techniques
				  allowed in
				  §3337 [
				49 CFR
				  192.931(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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3333 - What Actions Must Be Taken to Address Integrity Issues? [49 CFR 192.933]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General
				  Requirements . An operator must take prompt action to address all anomalous
				  conditions the operator discovers through the integrity assessment. In
				  addressing all conditions, an operator must evaluate all anomalous conditions
				  and remediate those that could reduce a pipeline's integrity. An operator must
				  be able to demonstrate that the remediation of the condition will ensure the
				  condition is unlikely to pose a threat to the integrity of the pipeline until
				  the next reassessment of the covered segment. [
				49 CFR
				  192.933(a)]
1. Temporary Pressure Reduction. If an
				  operator is unable to respond within the time limits for certain conditions
				  specified in this Section, the operator must temporarily reduce the operating
				  pressure of the pipeline or take other action that ensures the safety of the
				  covered segment. An operator must determine any temporary reduction in
				  operating pressure required by this Section using ASME/ANSI B31G (incorporated
				  by reference, see §507); R - STRENG (incorporated by reference, see
				  §507); or by reducing the operating pressure to a level not exceeding 80
				  percent of the level at the time the condition was discovered. An operator must
				  notify PHMSA in accordance with §518 if it cannot meet the schedule for
				  evaluation and remediation required under Subsection C of this Section and
				  cannot provide safety through a temporary reduction in operating pressure or
				  through another action. [49 CFR
				  192.933(a)(1)]
2. Long-term pressure reduction. When a
				  pressure reduction exceeds 365 days, an operator must notify PHMSA under
				  §518 and explain the reasons for the remediation delay. This notice must
				  include a technical justification that the continued pressure reduction will
				  not jeopardize the integrity of the pipeline. [49 CFR
				  192.933(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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3339 - What Are the Required Reassessment Intervals? [49 CFR 192.939]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator must
				  comply with the following requirements in establishing the reassessment
				  interval for the operator's covered pipeline segments. [
				49 CFR
				  192.939]
1.
				  Pipelines operating at or above 30 percent SMYS. An operator must establish a
				  reassessment interval for each covered segment operating at or above 30 percent
				  SMYS in accordance with the requirements of this Section. The maximum
				  reassessment interval by an allowable reassessment method is 7 calendar years.
				  Operators may request a 6-month extension of the seven-calendar- year
				  reassessment interval if the operator submits written notice to OPS, in
				  accordance with §518, with sufficient justification of the need for the
				  extension. If an operator establishes a reassessment interval that is greater
				  than seven calendar years, the operator must, within the seven-calendar-year
				  period, conduct a confirmatory direct assessment on the covered segment, and
				  then conduct the follow-up reassessment at the interval the operator has
				  established. A reassessment carried out using confirmatory direct assessment
				  must be done in accordance with
				  §3331 The
				  table that follows this Section sets forth the maximum allowed reassessment
				  intervals. [49 CFR
				  192.939(a)]
a. Pressure Test or Internal Inspection or
				  Other Equivalent Technology. An operator that uses pressure testing or internal
				  inspection as an assessment method must establish the reassessment interval for
				  a covered pipeline segment by: [
				49 CFR
				  192.939(a)(1)]
i. basing the interval on the identified
				  threats for the covered segment (see §3317) and on the analysis of the
				  results from the last integrity assessment and from the data integration and
				  risk assessment required by §3317; or [
				49 CFR
				  192.939(a)(1)(i)]
ii. using the intervals specified for
				  different stress levels of pipeline (operating at or above 30 percent SMYS)
				  listed in ASME B31.8S (incorporated by reference, see §507), Section 5,
				  Table 3. [
				49 CFR
				  192.939(a)(1)(ii)]
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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3341 - What Is a Low Stress Reassessment? [49 CFR 192.941]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General. An operator of a transmission
				  line that operates below 30 percent SMYS may use the following method to
				  reassess a covered segment in accordance with §3339 This method of
				  reassessment addresses the threats of external and internal corrosion. The
				  operator must have conducted a baseline assessment of the covered segment in
				  accordance with the requirements of
				  §3319 [
				49 CFR
				  192.941(a)]
B. External Corrosion
.
An
				  operator must take one of the following actions to address external corrosion
				  on the low stress covered segment. [
				49 CFR
				  192.941(b)]
1. Cathodically Protected Pipe. To address
				  the threat of external corrosion on cathodically protected pipe in a covered
				  segment, an operator must perform an electrical survey (i.e., indirect
				  examination tool/method) at least every seven years on the covered segment. An
				  operator must use the results of each survey as part of an overall evaluation
				  of the cathodic protection and corrosion threat for the covered segment. This
				  evaluation must consider, at minimum, the leak repair and inspection records,
				  corrosion monitoring records, exposed pipe inspection records, and the pipeline
				  environment. [
				49 CFR
				  192.941(b)(1)]
2. Unprotected Pipe or Cathodically Protected
				  Pipe Where Electrical Surveys Are Impractical. If an electrical survey is
				  impractical on the covered segment an operator must: [
				49 CFR
				  192.941(b)(2)]
a. conduct leakage surveys as required by
				  §2906 at
				  4-month intervals; and [
				49 CFR
				  192.941(b)(2)(i)]
b. every 18 months, identify and remediate
				  areas of active corrosion by evaluating leak repair and inspection records,
				  corrosion monitoring records, exposed pipe inspection records, and the pipeline
				  environment. [
				49 CFR
				  192.941(b)(2)(ii)
				  ]
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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3343 - When Can an Operator Deviate from These Reassessment Intervals? [49 CFR 192.943]

Current through Register Vol. 50, No. 6, June 20, 2024
A. Waiver from
				  Reassessment Interval in Limited Situations. In the following limited
				  instances, OPS may allow a waiver from a reassessment interval required by
				  §3339 if OPS
				  finds a waiver would not be inconsistent with pipeline safety. [
				49
				  CFR 192.943(a)]
1. Lack of Internal Inspection Tools. An
				  operator who uses internal inspection as an assessment method may be able to
				  justify a longer reassessment period for a covered segment if internal
				  inspection tools are not available to assess the line pipe. To justify this,
				  the operator must demonstrate that it cannot obtain the internal inspection
				  tools within the required reassessment period and that the actions the operator
				  is taking in the interim ensure the integrity of the covered segment. [
				49
				  CFR 192.943(a)(1)]
2. Maintain Product Supply. An operator may
				  be able to justify a longer reassessment period for a covered segment if the
				  operator demonstrates that it cannot maintain local product supply if it
				  conducts the reassessment within the required interval. [
				49
				  CFR 192.943(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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3345 - What Methods Must an Operator Use to Measure Program Effectiveness? [49 CFR 192.945]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General. An
				  operator must include in its integrity management program methods to measure
				  whether the program is effective in assessing and evaluating the integrity of
				  each covered pipeline segment and in protecting the high consequence areas.
				  These measures must include the four overall performance measures specified in
				  ASME/ANSI B31.8S (incorporated by reference, see
				  §507 of this
				  Subpart), section 9. 4, and the specific measures for each identified threat
				  specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four
				  overall performance measures as part of the annual report required by
				  §317 of this
				  Part. [
				49
				  CFR 192.945(a)].
B. External Corrosion Direct Assessment. In
				  addition to the general requirements for performance measures in Subsection A
				  of this Section, an operator using direct assessment to assess the external
				  corrosion threat must define and monitor measures to determine the
				  effectiveness of the ECDA process. These measures must meet the requirements of
				  §3325 [
				49
				  CFR 192.945(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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3347 - What Records Must an Operator Keep? [49 CFR 192.947]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator must maintain, for the useful
				  life of the pipeline, records that demonstrate compliance with the requirements
				  of this Chapter. At minimum, an operator must maintain the following records
				  for review during an inspection: [
				49 CFR
				  192.947]
1.
				  a written integrity management program in accordance with §3307; [
				49 CFR
				  192.947(a)]
2. documents supporting the threat
				  identification and risk assessment in accordance with §3317; [
				49 CFR
				  192.947(b)]
3. a written baseline assessment plan in
				  accordance with §3319; [
				49 CFR
				  192.947(c)]
4. documents to support any decision,
				  analysis and process developed and used to implement and evaluate each element
				  of the baseline assessment plan and integrity management program. Documents
				  include those developed and used in support of any identification, calculation,
				  amendment, modification, justification, deviation and determination made, and
				  any action taken to implement and evaluate any of the program elements; [
				49 CFR
				  192.947(d)]
5. documents that demonstrate personnel have
				  the required training, including a description of the training program, in
				  accordance with §3315; [
				49 CFR
				  192.947(e)]
6. schedule required by
				  §3333 that
				  prioritizes the conditions found during an assessment for evaluation and
				  remediation, including technical justifications for the schedule; [
				49 CFR
				  192.947(f)]
7. documents to carry out the requirements in
				  §3323 through
				  §3329 for a
				  direct assessment plan; [
				49 CFR
				  192.947(g)]
8. documents to carry out the requirements in
				  §3331 for
				  confirmatory direct assessment; [
				49 CFR
				  192.947(h)]
9. verification that an operator has provided
				  any documentation or notification required by this Chapter to be provided to
				  OPS, and when applicable, a state authority with which OPS has an interstate
				  agent agreement, and a state or local pipeline safety authority that regulates
				  a covered pipeline segment within that state. [
				49 CFR
				  192.947(i)]
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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3349 - How Does an Operator Notify PHMSA and the Louisiana Commissioner of Conservation? (Repealed)

Current through Register Vol. 50, No. 6, June 20, 2024
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 33 - Gas Transmission Pipeline Integrity Management [49 CFR Part 192 Subpart O] › Section XIII-3351 - Where Does an Operator File a Report? [49 CFR 192.951]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator must file any report required
				  by this Chapter electronically to the Pipeline and Hazardous Materials Safety
				  Administration in accordance with
				  §
											307 of this Part. [
				49 CFR
				  192.951]
B. Any report required by §3351. A, for
				  intrastate facilities subject to the jurisdiction of the Office of
				  Conservation, must be sent concurrently to the Commissioner of Conservation,
				  Office of Conservation, Pipeline Safety Section, P.O. Box 94279 Baton Rouge, LA
				  70804-9275.
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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3501 - What definitions apply to this chapter? [49 CFR 192.1001]

Current through Register Vol. 50, No. 6, June 20, 2024
A. The following
				  definitions apply to this Subpart. [
				49 CFR
				  192.1001]
Excavation Damage
-any impact that results
					 in the need to repair or replace an underground facility due to a weakening, or
					 the partial or complete destruction, of the facility, including, but not
					 limited to, the protective coating, lateral support, cathodic protection or the
					 housing for the line device or facility.
Hazardous Leak
-a leak that represents an
					 existing or probable hazard to persons or property and requires immediate
					 repair or continuous action until the conditions are no longer
					 hazardous.
Integrity Management Plan
or
IM
					 Plan
-a written explanation of the mechanisms or procedures the
					 operator will use to implement its integrity management program and to ensure
					 compliance with this chapter.
Integrity Management Program
or
IM
					 Program
-an overall approach by an operator to ensure the integrity of
					 its gas distribution system.
Mechanical Fitting
-a mechanical device
					 used to connect sections of pipe. The term "Mechanical fitting" applies only
					 to:
a. stab type fittings;
b. nut follower type fittings;
c. bolted type fittings; or
d. other compression type fittings.
Small LPG Operator
-an operator of a
					 liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100
					 customers from a single source.
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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3503 - What do the Regulations in this Chapter Cover? [49 CFR 192.1003]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General. Unless
				  exempted in Subsection B of this Section this Chapter prescribes minimum
				  requirements for an IM program for any gas distribution pipeline covered under
				  this Subpart, including liquefied petroleum gas systems. A gas distribution
				  operator must follow the requirements in this Chapter. [49 CFR
				  192.1003(a)]
B. Exceptions. This subpart does not apply
				  to: [49 CFR
				  192.1003(b)
1. Individual service lines directly
				  connected to a production line or a gathering line other than a regulated
				  onshore gathering line as determined in §508; [49 CFR
				  192.1003(b)(1)]
2. Individual service lines directly
				  connected to either a transmission or regulated gathering pipeline and
				  maintained in accordance with
				  §2940.A and B; and
				  [49 CFR
				  192.1003(b)(2)]
3. Master meter systems. [49 CFR
				  192.1003(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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3505 - What must a Gas Distribution Operator (other than a Small LPG Operator) do to Implement this Chapter? [49 CFR 192.1005]

Current through Register Vol. 50, No. 6, June 20, 2024
A. No later than August 2, 2011 a gas
				  distribution operator must develop and implement an integrity management
				  program that includes a written integrity management plan as specified in
				  §3507 [49
				  CFR 192.1005]
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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3507 - What are the Required Elements of an Integrity Management Plan? [49 CFR 192.1007]

Current through Register Vol. 50, No. 6, June 20, 2024
A. A
				  written integrity management plan must contain procedures for developing and
				  implementing the following elements. [
				49
				  CFR 192.1007]
1. Knowledge. An operator must demonstrate an
				  understanding of its gas distribution system developed from reasonably
				  available information. [
				49
				  CFR 192.1007(a)]
a. Identify the characteristics of the
				  pipeline's design and operations and the environmental factors that are
				  necessary to assess the applicable threats and risks to its gas distribution
				  pipeline. [
				49
				  CFR
				  192.1007(a)(1)]
b. Consider the information gained from past
				  design, operations, and maintenance. [
				49
				  CFR
				  192.1007(a)(2)]
c. Identify additional information needed and
				  provide a plan for gaining that information over time through normal activities
				  conducted on the pipeline (for example, design, construction, operations or
				  maintenance activities). [
				49
				  CFR
				  192.1007(a)(3)]
d. Develop and implement a process by which
				  the IM program will be reviewed periodically and refined and improved as
				  needed. [
				49
				  CFR
				  192.1007(a)(4)]
e. Provide for the capture and retention of
				  data on any new pipeline installed. The data must include, at a minimum, the
				  location where the new pipeline is installed and the material of which it is
				  constructed. [
				49
				  CFR
				  192.1007(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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3509 - What must an operator report when compression couplings fail? [49 CFR 192.1009] (Repealed)

Current through Register Vol. 50, No. 6, June 20, 2024
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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3511 - What records must an operator keep? [49 CFR 192.1011]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator must maintain records
				  demonstrating compliance with the requirements of this chapter for at least 10
				  years. The records must include copies of superseded integrity management plans
				  developed under this chapter. [
				49 CFR
				  192.1011]
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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3513 - When may an operator deviate from required periodic inspections under this subpart? [49 CFR 192.1013]

Current through Register Vol. 50, No. 6, June 20, 2024
A. An operator
				  may propose to reduce the frequency of periodic inspections and tests required
				  in this Subpart on the basis of the engineering analysis and risk assessment
				  required by this Chapter. [
				49
				  CFR 192.1013(a)]
B. An operator must submit its proposal to
				  the PHMSA Associate Administrator for Pipeline Safety or, in the case of an
				  intrastate pipeline facility regulated by the State, the appropriate state
				  agency. The applicable oversight agency may accept the proposal on its own
				  authority, with or without conditions and limitations, on a showing that the
				  operator's proposal, which includes the adjusted interval, will provide an
				  equal or greater overall level of safety. [
				49
				  CFR 192.1013(b)]
C. An operator may implement an approved
				  reduction in the frequency of a periodic inspection or test only where the
				  operator has developed and implemented an integrity management program that
				  provides an equal or improved overall level of safety despite the reduced
				  frequency of periodic inspections. [
				49
				  CFR 192.1013(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 35 - Gas Distribution Pipeline Integrity Management (IM) [49 CFR Part 192 Subpart P] › Section XIII-3515 - What must a Small LPG Operator do to Implement this Chapter? [49 CFR 192.1015]

Current through Register Vol. 50, No. 6, June 20, 2024
A. General.
				  No later than August 2, 2011 a small LPG operator must develop and implement an
				  IM program that includes a written IM plan as specified in Subsection B of this
				  Section. The IM program for these pipelines should reflect the relative
				  simplicity of these types of pipelines. [49 CFR
				  192.1015(a)]
B. Elements. A written integrity management
				  plan must address, at a minimum, the following elements. [
				49
				  CFR 192.1015(b)]
1. Knowledge. The operator must demonstrate
				  knowledge of its pipeline, which, to the extent known, should include the
				  approximate location and material of its pipeline. The operator must identify
				  additional information needed and provide a plan for gaining knowledge over
				  time through normal activities conducted on the pipeline (for example, design,
				  construction, operations or maintenance activities). [
				49
				  CFR
				  192.1015(b)(1)]
2. Identify Threats. The operator must
				  consider, at minimum, the following categories of threats (existing and
				  potential): corrosion(including atmospheric corrosion), natural forces,
				  excavation damage, other outside force damage, material or weld failure,
				  equipment failure, and incorrect operation. [49 CFR
				  192.1015(b)(2)]
3. Rank Risks. The operator must evaluate the
				  risks to its pipeline and estimate the relative importance of each identified
				  threat. [
				49
				  CFR
				  192.1015(b)(3)]
4. Identify and Implement Measures to
				  Mitigate Risks. The operator must determine and implement measures designed to
				  reduce the risks from failure of its pipeline. [
				49
				  CFR
				  192.1015(b)(4)]
5. Measure Performance, Monitor Results, and
				  Evaluate Effectiveness. The operator must monitor, as a performance measure,
				  the number of leaks eliminated or repaired on its pipeline and their causes. [
				49
				  CFR
				  192.1015(b)(5)]
6. Periodic Evaluation and Improvement. The
				  operator must determine the appropriate period for conducting IM program
				  evaluations based on the complexity of its pipeline and changes in factors
				  affecting the risk of failure. An operator must re-evaluate its entire program
				  at least every five years. The operator must consider the results of the
				  performance monitoring in these evaluations. [
				49
				  CFR
				  192.1015(b)(6)]
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 51 - Appendices › Section XIII-5101 - Reserved

Current through Register Vol. 50, No. 6, June 20, 2024
Editor's Note: The text of this Section (§5101) has
						been moved to
						§507 of this
						Part.
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 51 - Appendices › Section XIII-5103 - Appendix B-Qualification of Pipe

Current through Register Vol. 50, No. 6, June 20, 2024
I.
Listed Pipe Specifications
A. Listed Pipe Specifications
1. API Spec 5L-Steel pipe, "API Specification
				  for Line Pipe" (incorporated by reference, see § 507).
2. ASTM A53/A53M-Steel pipe, "Standard
				  Specification for Pipe, Steel Black and Hot-Dipped, Zinc-Coated, Welded and
				  Seamless" (incorporated by reference, see § 507).
3. ASTM A106/A-106M-Steel pipe, "Standard
				  Specification for Seamless Carbon Steel Pipe for High Temperature Service"
				  (incorporated by reference, see § 507).
4. ASTM A333/A333M-Steel pipe, "Standard
				  Specification for Seamless and Welded Steel Pipe for Low Temperature Service"
				  (incorporated by reference, see § 507).
5. ASTM A381-Steel pipe, "Standard
				  Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure
				  Transmission Systems" (incorporated by reference, see § 507).
6. ASTM A671/A671M-Steel pipe, "Standard
				  Specification for Electric-Fusion- Welded Pipe for Atmospheric and Lower
				  Temperatures" (incorporated by reference, see § 507).
7. ASTM A672/A672M-09-Steel pipe, "Standard
				  Specification for Electric-Fusion- Welded Steel Pipe for High-Pressure Service
				  at Moderate Temperatures" (incorporated by reference, see §
				  507).
8. ASTM A691/A691M-09-Steel
				  pipe, "Standard Specification for Carbon and Alloy Steel Pipe,
				  Electric-Fusion-Welded for High Pressure Service at High Temperatures"
				  (incorporated by reference, see § 507).
9. ASTM D2513"Standard Specification for
				  Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings" (incorporated by
				  reference, see § 507).
10.
				  ASTM D 2517-00-Thermosetting plastic pipe and tubing, "Standard Specification
				  for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by
				  reference, see § 507).
11.
				  ASTM F2785-12 "Standard Specification for Polyamide
12 Gas Pressure Pipe, Tubing, and Fittings"
				  (PA-12) (incorporated by reference, see § 507).
13. ASTM F2817-10 "Standard Specification for
				  Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or
				  Repair" (incorporated by reference, see § 507).
14. ASTM F2945-12a "Standard Specification
				  for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings" (PA-11) (incorporated
				  by reference, see § 507).
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 51 - Appendices › Section XIII-5105 - Appendix C-Qualification of Welders for Low Stress Level Pipe

Current through Register Vol. 50, No. 6, June 20, 2024
I.
Basic
				  Test
The test is made on pipe 12 inches (305 millimeters) or
					 less in diameter. The test weld must be made with the pipe in a horizontal
					 fixed position so that the test weld includes at least one section of overhead
					 position welding. The beveling, root opening, and other details must conform to
					 the specifications of the procedure under which the welder is being qualified.
					 Upon completion, the test weld is cut into four coupons and subjected to a root
					 bend test. If, as a result of this test, two or more of the four coupons
					 develop a crack in the weld material, or between the weld material and base
					 metal, that is more than 1/8-inch (3.2 millimeters) long in any direction, the
					 weld is unacceptable. Cracks that occur on the corner of the specimen during
					 testing are not considered. A welder who successfully passes a butt-weld
					 qualification test under this Section shall be qualified to weld on all pipe
					 diameters less than or equal to 12 inches.
II.
Additional Tests for Welders of
				  Service Line Connections to Mains
A service line connection fitting is welded to a pipe
					 section with the same diameter as a typical main. The weld is made in the same
					 position as it is made in the field. The weld is unacceptable if it shows a
					 serious undercutting or if it has rolled edges. The weld is tested by
					 attempting to break the fitting off the run pipe. The weld is unacceptable if
					 it breaks and shows incomplete fusion, overlap, or poor penetration at the
					 junction of the fitting and run pipe.
III.
Periodic Tests for Welders of
				  Small Service Lines
Two samples of the welder's work, each about 8 inches (203
					 millimeters) long with the weld located approximately in the center, are cut
					 from steel service line and tested as follows.
1. One sample is centered in a guided bend
				  testing machine and bent to the contour of the die for a distance of 2 inches
				  (51 millimeters) on each side of the weld. If the sample shows any breaks or
				  cracks after removal from the bending machine, it is unacceptable.
2. The ends of the second sample are
				  flattened and the entire joint subjected to a tensile strength test. If failure
				  occurs adjacent to or in the weld metal, the weld is unacceptable. If a tensile
				  strength testing machine is not available, this sample must also pass the
				  bending test prescribed in Subparagraph 1, of this Paragraph.
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 51 - Appendices › Section XIII-5107 - Appendix D-Criteria for Cathodic Protection and Determination of Measurements

Current through Register Vol. 50, No. 6, June 20, 2024
I.
Criteria for Cathodic Protection
A.
				  Steel, Cast Iron, and Ductile Iron Structures
1. A negative (cathodic) voltage of at least
				  0.85 volt, with reference to a saturated copper-coppersulfate half cell.
				  Determination of this voltage must be made with the protective current applied,
				  and in accordance with Sections II and IV of this Appendix.
2. A negative (cathodic) voltage shift of at
				  least 300 millivolts. Determination of this voltage shift must be made with the
				  protective current applied, and in accordance with Sections II and IV of this
				  Appendix. This criterion of voltage shift applies to structures not in contact
				  with metals of different anodic potentials.
3. A minimum negative (cathodic) polarization
				  voltage shift of 100 millivolts. This polarization voltage shift must be
				  determined in accordance with Sections III and IV of this Appendix.
4. A voltage at least as negative (cathodic)
				  as that originally established at the beginning of the Tafel segment of the
				  E-log-I curve. This voltage must be measured in accordance with Section IV of
				  this Appendix.
5. A net protective
				  current from the electrolyte into the structure surface as measured by the
				  earth current technique applied at predetermined current discharge (anodic)
				  points of the structure.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 4 - Drug and Alcohol Testing › Chapter 61 - General [Part 199-Subpart A] › Section XIII-6101 - Scope [49 CFR 199.1]

Current through Register Vol. 50, No. 6, June 20, 2024
A. This
				  Subpart requires operators of pipeline facilities subject to LAC 43:XIII or LAC
				  33:V.Subpart 3 ( 49 CFR Part 192 and 195) to test covered employees for the
				  presence of prohibited drugs and alcohol. [
				49 CFR
				  199.1]
AUTHORITY NOTE:
					 Promulgated in accordance with R.S. 30:751-757, redesignated as R.S. 30:701-707
					 and
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 4 - Drug and Alcohol Testing › Chapter 61 - General [Part 199-Subpart A] › Section XIII-6102 - Applicability [49 CFR 199.2]

Current through Register Vol. 50, No. 6, June 20, 2024
A. This
				  Subpart applies to pipeline operators' only with respect to employees located
				  within the territory of the United States, including those employees located
				  within the limits of the
Outer Continental Shelf
as that term
				  is defined in the Outer Continental Shelf Lands Act (43
				  U.S.C. 1331). [
				49
				  CFR 199.2(a)]
B. This Subpart does not apply to any person
				  for whom compliance with LAC 43:XIII or LAC 33:V.Subpart 3 ( 49 CFR Part 192 and
				  195) would violate the domestic laws or policies of another country [
				49
				  CFR 199.2(b)].
C. This Subpart does not apply to covered
				  functions performed on: [
				49
				  CFR 199.2(c)]
1. master meter systems, as defined in
				  §303 of this
				  Part; or [
				49
				  CFR 199.2(c)(1)]
2. pipeline systems that transport only
				  petroleum gas or petroleum gas/air mixtures. [
				49
				  CFR 199.2(c)(2)]
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 4 - Drug and Alcohol Testing › Chapter 61 - General [Part 199-Subpart A] › Section XIII-6103 - Definitions [49 CFR 199.3]

Current through Register Vol. 50, No. 6, June 20, 2024
A. As
				  used in this Chapter:
Accident
-an incident reportable under  49
					 CFR Part 191  involving gas pipeline facilities or LNG facilities, or an
					 accident reportable under CFR Part 195 involving hazardous liquid pipeline
					 facilities.
Administrator
- the Administrator, Pipeline
					 and Hazardous Materials Safety Administration or his or her delegate.
Covered Employee, Employee, or Individual to be
					 Tested
-a person who performs a covered function, including persons
					 employed by operators, contractors engaged by operators, and persons employed
					 by such contractors.
Covered Function-
an operations,
					 maintenance, or emergency-response function regulated by  49 CFR Part 192, 193,
					 or 195  that is performed on a pipeline or on an LNG facility.
DOT Procedures
-the "Procedures for
					 Transportation Workplace Drug and Alcohol Testing Programs" published by the
					 Office of the Secretary of Transportation in CFR Part 40.
Fail a Drug Test
-the confirmation test
					 result shows positive evidence of the presence under DOT procedures of a
					 prohibited drug in an employee's system.
Operator
-a person who owns or operates
					 pipeline facilities subject to CFR Part 192, 193, or 195.
Pass a Drug Test-
initial testing or
					 confirmation testing under DOT procedures does not show evidence of the
					 presence of a prohibited drug in a person's system.
Performs a Covered Function-
includes
					 actually performing, ready to perform, or immediately available to perform a
					 covered function.
Positive Rate for Random Drug Testing
-the
					 number of verified positive results for random drug tests conducted under this
					 Subpart plus the number of refusals of random drug tests required by this
					 Subpart, divided by the total number of random drug tests results (i.e.,
					 positives, negatives, and refusals) under this Subpart.
Prohibited Drug
-any of the substances
					 specified in  49 cFR part 40.
Refuse to Submit, Refuse, or Refuse to
					 Take
-behavior consistent with DOT procedures concerning refusal to
					 take a drug test of refusal to take an alcohol test.
State Agency
-an agency of any of the
					 several states, the District of Columbia, or Puerto Rico that participates
					 under the pipeline safety laws. (49 U.S.C.
					 60101 et seq.)
AUTHORITY
					 NOTE: Promulgated in accordance with R.S. 30:751-757, redesignated as R.S.
					 30:701-707 and
					 R.S. 30:501
					 et seq.
Louisiana Administrative Code › Title 43 - NATURAL RESOURCES › Part XIII - Office of Conservation-Pipeline Safety › Subpart 4 - Drug and Alcohol Testing › Chapter 61 - General [Part 199-Subpart A] › Section XIII-6105 - DOT Procedures [49 CFR 199.5]

Current through Register Vol. 50, No. 6, June 20, 2024
A. The anti-drug and alcohol programs
				  required by this Subpart must be conducted according to the requirements of
				  this Subpart and the DOT procedures. Terms and concepts used in this Subpart
				  have the same meaning as in the DOT procedures. Violations of DOT procedures
				  with respect to anti-drug and alcohol programs required by this Subpart are
				  violations of this Subpart. [
				49 CFR
				  199.5]
AUTHORITY NOTE:
					 Promulgated in accordance with R.S. 30:751-757, redesignated as R.S. 30:701-707
					 and
					 R.S. 30:501
					 et seq.