La. Admin. Code tit. 43 § XIII-2914

Current through Register Vol. 50, No. 11, November 20, 2024

Section XIII-2914 - Transmission Lines: Repair Criteria for Onshore Transmission Pipelines [49 CFR 192.714]

A. Applicability. This section applies to onshore transmission pipelines not subject to the repair criteria in subpart O of this part, and which do not operate under an alternative MAOP in accordance with §§912, 1728, and 2720. Pipeline segments that are located in high consequence areas, as defined in §3303, must comply with the applicable actions specified by the integrity management requirements in Chapter 33. Pipeline segments operating under an alternative MAOP in accordance with §§912, 1728, and 2720 must comply with §2720.D.k [49 CFR 192.714(a)]

B. General. Each operator must, in repairing its pipeline systems, ensure that the repairs are made in a safe manner and are made to prevent damage to persons, property, and the environment. A pipeline segment's operating pressure must be less than the predicted failure pressure determined in accordance with §2912 during repair operations. Repairs performed in accordance with this section must use pipe and material properties that are documented in traceable, verifiable, and complete records. If documented data required for any analysis, including predicted failure pressure for determining MAOP, is not available, an operator must obtain the undocumented data through §2707 Until documented material properties are available, the operator must use the conservative assumptions in either §2912.E.2 or, if appropriate following a pressure test, in §2912.D.3 [49 CFR 192.714(b)]

C. Schedule for evaluation and remediation. An operator must remediate conditions according to a schedule that prioritizes the conditions for evaluation and remediation. Unless Subsection D of this Section provides a special requirement for remediating certain conditions, an operator must calculate the predicted failure pressure of anomalies or defects and follow the schedule in ASME/ANSI B31.8S (incorporated by reference, see §507), section 7, Figure 4. If an operator cannot meet the schedule for any condition, the operator must document the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety. Each condition that meets any of the repair criteria in Subsection D of this Section in an onshore steel transmission pipeline must be: [49 CFR 192.714(c)]

1. removed by cutting out and replacing a cylindrical piece of pipe that will permanently restore the pipeline's MAOP based on the use of §905 and the design factors for the class location in which it is located; or [49 CFR 192.714(c)(1)]

2. repaired by a method, shown by technically proven engineering tests and analyses, that will permanently restore the pipeline's MAOP based upon the determined predicted failure pressure times the design factor for the class location in which it is located. [49 CFR 192.714(c)(2)]

D. Remediation of certain conditions. For onshore transmission pipelines not located in high consequence areas, an operator must remediate a listed condition according to the following criteria: [49 CFR 192.714(d)]

1. immediate repair conditions. An operator's evaluation and remediation schedule for immediate repair conditions must follow section 7 of ASME/ANSI B31.8S (incorporated by reference, see §507). An operator must repair the following conditions immediately upon discovery: [49 CFR 192.714(d)(1)]

a. metal loss anomalies where a calculation of the remaining strength of the pipe at the location of the anomaly shows a predicted failure pressure, determined in accordance with §2912 B, of less than or equal to 1.1 times the MAOP. [49 CFR 192.714(d)(1)(i)]

b. a dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) that has metal loss, cracking, or a stress riser, unless an engineering analysis performed in accordance with §2912.C demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(1)(ii)]

c. metal loss greater than 80 percent of nominal wall regardless of dimensions. [49 CFR 192.714(d)(1)(iii)]

d. metal loss preferentially affecting a detected longitudinal seam, if that seam was formed by direct current, low-frequency or high-frequency electric resistance welding, electric flash welding, or has a longitudinal joint factor less than 1.0, and the predicted failure pressure determined in accordance with §2912.D is less than 1.25 times the MAOP. [49 CFR 192.714(d)(1)(iv)]

e. a crack or crack-like anomaly meeting any of the following criteria: [49 CFR 192.714(d)(1)(v)]

i. crack depth plus any metal loss is greater than 50 percent of pipe wall thickness; [49 CFR 192.714(d)(1)(v)(A)]

ii. crack depth plus any metal loss is greater than the inspection tool's maximum measurable depth; or [49 CFR 192.712(d)(1)(v)(B)]

iii. the crack or crack-like anomaly has a predicted failure pressure, determined in accordance with §2912 D, that is less than 1.25 times the MAOP. [49 CFR 192.712(d)(1)(v)(C)]

f. an indication or anomaly that, in the judgment of the person designated by the operator to evaluate the assessment results, requires immediate action. [49 CFR 192.714(d)(1)(vi)]

2. two-year conditions. An operator must repair the following conditions within 2 years of discovery: [49 CFR 192.714(d)(2)]

a. a smooth dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6 percent of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), unless an engineering analysis performed in accordance with §2912.C demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(2)(i)]

b. a dent with a depth greater than 2 percent of the pipeline diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal or helical (spiral) seam weld, unless an engineering analysis performed in accordance with §2912.C demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(2)(ii)]

c. a dent located between the 4 o'clock and 8 o'clock positions (lower 1/3 of the pipe) that has metal loss, cracking, or a stress riser, unless an engineering analysis performed in accordance with §2912.C demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(2)(iii)]

d. for metal loss anomalies, a calculation of the remaining strength of the pipe shows a predicted failure pressure, determined in accordance with §2912.B at the location of the anomaly, of less than 1.39 times the MAOP for Class 2 locations, or less than 1.50 times the MAOP for Class 3 and 4 locations. For metal loss anomalies in Class 1 locations with a predicted failure pressure greater than 1.1 times MAOP, an operator must follow the remediation schedule specified in ASME/ANSI B31.8S (incorporated by reference, see §507), section 7, Figure 4, as specified in Subsection C of this Section. [49 CFR 192.714(d)(2)(iv)]

e. metal loss that is located at a crossing of another pipeline, is in an area with widespread circumferential corrosion, or could affect a girth weld, and that has a predicted failure pressure, determined in accordance with §2912 B, less than 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe that has been uprated in accordance with §2711 or less than 1.50 times the MAOP for all other Class 2 locations and all Class 3 and 4 locations. [49 CFR 192.714(d)(2)(v)]

f. metal loss preferentially affecting a detected longitudinal seam, if that seam was formed by direct current, low-frequency or high-frequency electric resistance welding, electric flash welding, or has a longitudinal joint factor less than 1.0, and the predicted failure pressure determined in accordance with §2912.D is less than 1.25 times the MAOP. [49 CFR 192.714(d)(2)(vi)]

g. a crack or crack-like anomaly that has a predicted failure pressure, determined in accordance with §2912 D, that is less than 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe that has been uprated in accordance with §2711, or less than 1.50 times the MAOP for all other Class 2 locations and all Class 3 and 4 locations. [49 CFR 192.714(d)(2) (vii]

3. monitored conditions. An operator must record and monitor the following conditions during subsequent risk assessments and integrity assessments for any change that may require remediation: [49 CFR 192.714(d)(3)]

a. a dent that is located between the 4 o'clock and 8 o'clock positions (bottom 1/3 of the pipe) with a depth greater than 6 percent of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12), and where an engineering analysis, performed in accordance with §2912 C, demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(3)(i)]

b. a dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6 percent of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12), and where an engineering analysis performed in accordance with §2912.C determines that critical strain levels are not exceeded. [49 CFR 192.714(d)(3)(ii)]

c. a dent with a depth greater than 2 percent of the pipeline diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or longitudinal or helical (spiral) seam weld, and where an engineering analysis of the dent and girth or seam weld, performed in accordance with §2912 C, demonstrates critical strain levels are not exceeded. These analyses must consider weld mechanical properties. [49 CFR 192.714(d)(3)(iii)]

d. a dent that has metal loss, cracking, or a stress riser, and where an engineering analysis performed in accordance with §2912.C demonstrates critical strain levels are not exceeded. [49 CFR 192.714(d)(3)(iv)]

e. metal loss preferentially affecting a detected longitudinal seam, if that seam was formed by direct current, low-frequency or high-frequency electric resistance welding, electric flash welding, or that has a longitudinal joint factor less than 1.0, and where the predicted failure pressure, determined in accordance with §2912 D, is greater than or equal to 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe that has been uprated in accordance with §2711, or is greater than or equal to 1.50 times the MAOP for all other Class 2 locations and all Class 3 and 4 locations. [49 CFR 192.714(d)(3)(v)]

f. a crack or crack-like anomaly for which the predicted failure pressure, determined in accordance with §2912 D, is greater than or equal to 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe that has been uprated in accordance with §2711, or is greater than or equal to 1.50 times the MAOP for all other Class 2 locations and all Class 3 and 4 locations. [49 CFR 192.714(d)(3)(vi)]

E. Temporary Pressure Reduction [49 CFR 192.714(e)]

1. Immediately upon discovery and until an operator remediates the condition specified in Paragraph D.1 of this Section, or upon a determination by an operator that it is unable to respond within the time limits for the conditions specified in Paragraph D.2 of this Section, the operator must reduce the operating pressure of the affected pipeline to any one of the following based on safety considerations for the public and operating personnel: [49 CFR 192.714(e)(1)]

a. a level not exceeding 80 percent of the operating pressure at the time the condition was discovered; [49 CFR 192.714(e)(1)(i)]

b. a level not exceeding the predicted failure pressure times the design factor for the class location in which the affected pipeline is located; or [49 CFR 192.714(e)(1)(ii)]

c. a level not exceeding the predicted failure pressure divided by 1.1. [49 CFR 192.714(e)(1)(iii)]

2. An operator must notify PHMSA in accordance with §518 if it cannot meet the schedule for evaluation and remediation required under Subsection C or D of this Section and cannot provide safety through a temporary reduction in operating pressure or other action. Notification to PHMSA does not alleviate an operator from the evaluation, remediation, or pressure reduction requirements in this section. [49 CFR 192.714(e)(2)]

3. When a pressure reduction, in accordance with Subsection E of this Section, exceeds 365 days, an operator must notify PHMSA in accordance with §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 192.714(e)(3)]

4. An operator must document and keep records of the calculations and decisions used to determine the reduced operating pressure and the implementation of the actual reduced operating pressure for a period of 5 years after the pipeline has been repaired. [49 CFR 192.714(e)(4)]

F. Other conditions. Unless another timeframe is specified in Subsection D of this Section, an operator must take appropriate remedial action to correct any condition that could adversely affect the safe operation of a pipeline system in accordance with the criteria, schedules, and methods defined in the operator's operating and maintenance procedures. [49 CFR 192.714(f)]

G. In situ direct examination of crack defects. Whenever an operator finds conditions that require the pipeline to be repaired, in accordance with this section, an operator must perform a direct examination of known locations of cracks or crack-like defects using technology that has been validated to detect tight cracks (equal to or less than 0.008 inches crack opening), such as inverse wave field extrapolation (IWEX), phased array ultrasonic testing (PAUT), ultrasonic testing (UT), or equivalent technology. "In situ" examination tools and procedures for crack assessments (length, depth, and volumetric) must have performance and evaluation standards, including pipe or weld surface cleanliness standards for the inspection, confirmed by subject matter experts qualified by knowledge, training, and experience in direct examination inspection for accuracy of the type of defects and pipe material being evaluated. The procedures must account for inaccuracies in evaluations and fracture mechanics models for failure pressure determinations. [49 CFR 192.714(g)]

H. Determining predicted failure pressures and critical strain levels. An operator must perform all determinations of predicted failure pressures and critical strain levels required by this Section in accordance with §2912 [49 CFR 192.714(h)]

La. Admin. Code tit. 43, § XIII-2914

Promulgated by the Department of Natural Resources, Office of Conservation, Pipeline Division, LR 501254 (9/1/2024).

AUTHORITY NOTE: Promulgated in accordance with R.S. 30:501 et seq.