§192.933. What actions must be taken to address integrity issues? — Inbound Citations

(c) Unless otherwise specified, if an operator submits, pursuant to § 192.8, § 192.9, § 192.13, § 192.179, § 192.319, § 192.461, § 192.506, § 192.607, § 192.619, § 192.624, § 192.632, § 192.634, § 192.636, § 192.710, § 192.712, § 192.714, § 192.745, § 192.917, § 192.921, § 192.927, § 192.933, or § 192.937, a notification for use of a different integrity assessment method, analytical method, compliance period, sampling approach, pipeline material, or technique (e.g., “other technology” or “alternative equivalent technology”) than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using the other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submitting the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposal or that PHMSA requires additional time and/or more information to conduct its review.

(6) Anomalies detected by ILI assessments must be remediated in accordance with applicable criteria in §§ 192.713 and 192.933.

(10) If the dent or mechanical damage is suspected to have cracks, then a crack growth rate assessment is required to ensure adequate life for the dent with crack(s) until remediation or the dent with crack(s) must be evaluated and remediated in accordance with the criteria and timing requirements in § 192.713, § 192.714, or § 192.933, as applicable.

(e) Provisions meeting the requirements of § 192.933 for remediating conditions found during an integrity assessment.

(ii) Remediate all anomalies identified in the more recent assessment according to the requirements in § 192.933, and incorporate the results and lessons learned from the more recent assessment into the operator's data integration and risk assessment.

(5) If an operator identifies corrosion on a covered pipeline segment that could adversely affect the integrity of the line (conditions specified in § 192.933), the operator must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics. An operator must establish a schedule for evaluating and remediating, as necessary, the similar segments that is consistent with the operator's established operating and maintenance procedures under part 192 for testing and repair.

(e) An operator may use a prior integrity assessment conducted before December 17, 2002 as a baseline assessment for the covered segment, if the integrity assessment meets the baseline requirements in this subpart and subsequent remedial actions to address the conditions listed in § 192.933 have been carried out. In addition, if an operator uses this prior assessment as its baseline assessment, the operator must reassess the line pipe in the covered segment according to the requirements of § 192.937 and § 192.939.

(i) Evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with § 192.933 if the condition is in a covered segment, or in accordance with §§ 192.485 and 192.714 if the condition is not in a covered segment;

(d) If an assessment carried out under paragraph (b) or (c) 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 § 192.7), section 6.2 and 6.3. If the defect requires immediate remediation, then the operator must reduce pressure consistent with § 192.933 until the operator has completed reassessment using one of the assessment techniques allowed in § 192.937.

(iv) If an operator finds physical evidence of encroachment involving excavation that the operator did not monitor near a covered segment, an operator must either excavate the area near the encroachment or conduct an above ground survey using methods defined in NACE SP0502 (incorporated by reference, see § 192.7). An operator must excavate, and remediate, in accordance with ASME B31.8S and § 192.933 any indication of coating holidays or discontinuity warranting direct examination.

(b) An operator must conduct a periodic evaluation as frequently as needed to assure the integrity of each covered segment. The periodic evaluation must be based on a data integration and risk assessment of the entire pipeline as specified in § 192.917. For plastic transmission pipelines, the periodic evaluation is based on the threat analysis specified in 192.917(d). For all other transmission pipelines, the evaluation must consider the past and present integrity assessment results, data integration and risk assessment information (§ 192.917), and decisions about remediation (§ 192.933) and additional preventive and mitigative actions (§ 192.935). An operator must use the results from this evaluation to identify the threats specific to each covered segment and the risk represented by these threats.

(f) Schedule required by § 192.933 that prioritizes the conditions found during an assessment for evaluation and remediation, including technical justifications for the schedule.

(3) ASME B16.40-2019, Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems, issued February 11, 2019, (ASME B16.40); IBR approved for appendix B to this part.

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

(b) Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. For the purposes of this section, a condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. In cases where a determination is not made within the 180-day period, the operator must notify PHMSA, in accordance with § 192.18, and provide an expected date when adequate information will become available. Notification to PHMSA does not alleviate an operator from the discovery requirements of this paragraph (b).

(b) Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. For the purposes of this section, a condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. In cases where a determination is not made within the 180-day period, the operator must notify PHMSA, in accordance with § 192.18, and provide an expected date when adequate information will become available. Notification to PHMSA does not alleviate an operator from the discovery requirements of this paragraph (b).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(b) Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. For the purposes of this section, a condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. In cases where a determination is not made within the 180-day period, the operator must notify PHMSA, in accordance with § 192.18, and provide an expected date when adequate information will become available. Notification to PHMSA does not alleviate an operator from the discovery requirements of this paragraph (b).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).

(C) Use a factor 1.39 times the maximum allowable operating pressure when determining the predicted failure pressure on any Class 1 design pipe in an eligible Class 3 segment for one-year conditions in accordance with § 192.933(d)(2)(iv) through (vii) and monitored conditions in accordance with § 192.933(d)(3)(v) through (vi).