Louisiana Administrative Code, Chapter 304, Section V-30452 - Pipeline Integrity Management in High Consequence Areas [49 CFR 195.452] | Louisiana Administrative Code

A. Which pipelines are covered by this Section? This Section applies to each hazardous liquid pipeline and carbon dioxide pipeline that could affect a high consequence area, including any pipeline located in a high consequence area unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. (§30905, Appendix C of this Subpart provides guidance on determining if a pipeline could affect a high consequence area.) Covered pipelines are categorized as follows. [49 CFR 195.452(a)]

1. Category 1 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this Subpart. [49 CFR 195.452(a)(1)]

2. Category 2 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipeline subject to this Subpart. [49 CFR 195.452(a)(2)]

3. Category 3 includes pipelines constructed or converted after May 29, 2001, and low-stress pipelines in rural areas under §30118 [49 CFR 195.452(a)(3)]

4. Low stress pipelines as specified in § 30118 [49 CFR 195.452(a)(4)]

B. What program and practices must operators use to manage pipeline integrity? Each operator of a pipeline covered by this Section must: [49 CFR 195.452(b)]

1. Develop a written integrity management program that addresses the risks on each segment of pipeline in the first column of the following table no later than the date in the second column: [49 CFR 195.452(b)(1)]

Pipeline	Date
Category 1	March 31, 2002
Category 2	February 18, 2003
Category 3	Date the pipeline begins operation or as provided in § 30118 for low stress pipelines in rural areas.

2. include in the program an identification of each pipeline or pipeline segment in the first column of the following table not later than the date in the second column: [49 CFR 195.452(b)(2)]

Pipeline	Date
Category 1	December 31, 2001
Category 2	November 18, 2002
Category 3	Date the pipeline begins operation

3. include in the program a plan to carry out baseline assessments of line pipe as required by Subsection C of this Section; [49 CFR 195.452(b)(3)]

4. include in the program a framework that:[49 CFR 195.452(b)(4)]

a. addresses each element of the integrity management program under Subsection F of this Section, including continual integrity assessment and evaluation under Subsection J of this Section; and [49 CFR 195.452(b)(4)(i)]

b. initially indicates how decisions will be made to implement each element; [49 CFR 195.452(b)(4)(ii)]

5. implement and follow the program; [49 CFR 195.452(b)(5)]

6. follow recognized industry practices in carrying out this section, unless:[49 CFR 195.452(b)(6)]

a. this Section specifies otherwise; or [49 CFR 195.452(b)(6)(i)]

b. the operator demonstrates that an alternative practice is supported by a reliable engineering evaluation and provides an equivalent level of public safety and environmental protection. [49 CFR 195.452(b)(6)(ii)]

C. What must be in the baseline assessment plan? [49 CFR 195.452(c)]

1. An operator must include each of the following elements in its written baseline assessment plan. [49 CFR 195.452(c)(1)]

a. The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by in-line inspection tool(s) described in Subclause C.1.a.i this Section for the range of relevant threats to the pipeline segment. If it is impracticable based upon the construction of the pipeline (e.g., diameter changes, sharp bends, and elbows) or operational limits including operating pressure, low flow, pipeline length, or availability of in-line inspection tool technology for the pipe diameter, then the operator must use the appropriate method(s) in Subclause C.1.a.ii, iii, or iv of this Section for the range of relevant threats to the pipeline segment. The methods an operator selects to assess low-frequency electric resistance welded pipe, pipe with a seam factor less than 1.0 as defined in §30161.E or lap-welded pipe susceptible to longitudinal seam failure, must be capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies. [49 CFR 195.452(c)(1)(i)]

i. In-line inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges, and grooves. For pipeline segments with an identified or probable risk or threat related to cracks (such as at pipe body or weld seams) based on the risk factors specified in Subsection E, an operator must use an in-line inspection tool or tools capable of detecting crack anomalies. When performing an assessment using an in- line inspection tool, an operator must comply with §30591 An operator using this method must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or equivalent for determining uncertainties) in identifying anomalies; [49 CFR 195.452(c)(1)(i)(A)]

ii. pressure test conducted in accordance with Chapter 303. of this Subpart; [49 CFR 195.452(c)(1)(i)(B)]

iii. external corrosion direct assessment in accordance with §30588; or [49 CFR 195.452(c)(1)(i)(C)]

iv. other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days before conducting the assessment, by sending a notice to the addresses or facsimile numbers specified in Subsection M of this Section [49 CFR 195.452(c)(1)(i)(D)].

b. a schedule for completing the integrity assessment; [49 CFR 195.452(c)(1)(ii)]

c. an explanation of the assessment methods selected and evaluation of risk factors considered in establishing the assessment schedule; [49 CFR 195.452(c)(1)(iii)]

2. an operator must document, prior to implementing any changes to the plan, any modification to the plan, and reasons for the modification. [49 CFR 195.452(c)(2)]

D. When must operators complete baseline assessments? [49 CFR 195.452(d)]

1. All Pipelines. An operator must complete the baseline assessment before a new or conversion-to-service pipeline begins operation through the development of procedures, identification of high consequence areas, and pressure testing of could- affect high consequence areas in accordance with §30304 [49 CFR 195.452(d)(1)]

2. Newly Identified Areas. If an operator obtains information (whether from the information analysis required under Subsection G of this section, Census Bureau maps, or any other source) demonstrating that the area around a pipeline segment has changed to meet the definition of a high consequence area (see §30450), that area must be incorporated into the operator's baseline assessment plan within one year from the date that the information is obtained. An operator must complete the baseline assessment of any pipeline segment that could affect a newly identified high consequence area within 5 years from the date an operator identifies the area. [49 CFR 195.452(d)(2)]

Pipeline	Date
Category 1	January 1, 1996
Category 2	February 15, 1997

E. What are the risk factors for establishing an assessment schedule (for both the baseline and continual integrity assessments)? [49 CFR 195.452(e)]

1. An operator must establish an integrity assessment schedule that prioritizes pipeline segments for assessment (see Paragraphs D.1 and J.3 of this Section). An operator must base the assessment schedule on all risk factors that reflect the risk conditions on the pipeline segment. The factors an operator must consider include, but are not limited to: [49 CFR 195.452(e)(1)]

a. results of the previous integrity assessment, defect type and size that the assessment method can detect, and defect growth rate; [49 CFR 195.452(e)(1)(i)]

b. pipe size, material, manufacturing information, coating type and condition, and seam type; [49 CFR 195.452(e)(1)(ii)]

c. leak history, repair history and cathodic protection history; [49 CFR 195.452(e)(1)(iii)]

d. product transported; [49 CFR 195.452(e)(1)(iv)]

e. operating stress level; [49 CFR 195.452(e)(1)(v)]

f. existing or projected activities in the area; [49 CFR 195.452(e)(1)(vi)]

g. local environmental factors that could affect the pipeline (e.g., seismicity, corrosivity of soil, subsidence, climatic); [49 CFR 195.452(e)(1)(vii)]

h. geo-technical hazards; and [49 CFR 195.452(e)(1)(viii)]

i. physical support of the segment such as by a cable suspension bridge. [49 CFR 195.452(e)(1)(ix)]

2. Section 30905, Appendix C, of this Subpart provides further guidance on risk factors. [49 CFR 195.452(e)(2)]

F. What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: [49 CFR 195.452(f)]

1. a process for identifying which pipeline segments could affect a high consequence area; [49 CFR 195.452(f)(1)]

2. a baseline assessment plan meeting the requirements of Subsection C of this Section; [49 CFR 195.452(f)(2)]

3. an analysis that integrates all available information about the integrity of the entire pipeline and the consequences of a failure (see Subsection G of this Section); [49 CFR 195.452(f)(3)]

4. criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis (see Subsection H of this Section); [49 CFR 195.452(f)(4)]

5. a continual process of assessment and evaluation to maintain a pipeline's integrity (see Subsection J of this Section); [49 CFR 195.452(f)(5)]

6. identification of preventive and mitigative measures to protect the high consequence area (see Subsection I of this Section); [49 CFR 195.452(f)(6)]

7. methods to measure the program's effectiveness (see Subsection K of this Section); [49 CFR 195.452(f)(7)]

8. a process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information (see Subsection H.2 of this Section). [49 CFR 195.452(f)(8)]

9. procedures for providing (when requested), by electronic or other means, a copy of the operator's risk analysis or integrity management program to Office of Conservation, Pipeline Division for intrastate jurisdictional facilities.

G. What is an information analysis? In periodically evaluating the integrity of each pipeline segment (see Subsection J of this Section), an operator must analyze all available information about the integrity of its entire pipeline and the consequences of a possible failure along the pipeline. Operators must continue to comply with the data integration elements specified in §30452.G that were in effect on October 1, 2018, until October 1, 2022. Operators must begin to integrate all the data elements specified in this section starting October 1, 2020, with all attributes integrated by October 1, 2022. This analysis must: [49 CFR 195.452(g)]

1. integrate information and attributes about the pipeline that include, but are not limited to: [49 CFR 195.452(g)(1)]

a. pipe diameter, wall thickness, grade, and seam type; [49 CFR 195.452(g)(1)(i)]

b. pipe coating, including girth weld coating; [49 CFR 195.452(g)(1)(ii)]

c. maximum operating pressure (MOP) and temperature; [49 CFR 195.452(g)(1)(iii)]

d. endpoints of segments that could affect high consequence areas (HCAs); [49 CFR 195.452(g)(1)(iv)]

e. hydrostatic test pressure including any test failures or leaks, if known; [49 CFR 195.452(g)(1)(v)]

f. location of casings and if shorted; [49 CFR 195.452(g)(1)(vi)]

g. any in-service ruptures or leaks, including identified causes; [49 CFR 195.452(g)(1)(vii)]

h. data gathered through integrity assessments required under this Section; [49 CFR 195.452(g)(1)(viii)]

i. close interval survey (CIS) survey results; [49 CFR 195.452(g)(1)(ix)]

j. depth of cover surveys; [49 CFR 195.452(g)(1)(x)]

k. corrosion protection (CP) rectifier readings; [49 CFR 195.452(g)(1)(xi)]

l. CP test point survey readings and locations; [49 CFR 195.452(g)(1)(xii)]

m. AC/DC and foreign structure interference surveys; [49 CFR 195.452(g)(1)(xiii)]

n. pipe coating surveys and cathodic protection surveys. [49 CFR 195.452(g)(1)(xiv)]

o. results of examinations of exposed portions of buried pipelines (i.e., pipe and pipe coating condition, see §30569; [49 CFR 195.452(g)(1)(xv)]

p. stress corrosion cracking (SCC) and other cracking (pipe body or weld) excavations and findings, including in- situ non-destructive examinations and analysis results for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipeline; [49 CFR 195.452(g)(1)(xvi)]

q. aerial photography; [49 CFR 195.452(g)(1)(xvii)]

r. location of foreign line crossings; [49 CFR 195.452(g)(1)(xviii)]

s. pipe exposures resulting from repairs and encroachments; [49 CFR 195.452(g)(1)(xix)]

t. seismicity of the area; and [49 CFR 195.452(g)(1)(xx)]

u. other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this Part; [49 CFR 195.452(g)(1)(xxi)]

2. consider information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline; [49 CFR 195.452(g)(2)]

3. consider how a potential failure would affect high consequence areas, such as location of a water intake; [49 CFR 195.452(g)(3)]

4. identify spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings; evidence of pipeline damage where aerial photography shows evidence of encroachment). Storing the information in a geographic information system (GIS), alone, is not sufficient. An operator must analyze for interrelationships among the data. [49 CFR 195.452(g)(4)]

H. What actions must an operator take to address integrity issues? [49 CFR 195.452(h)]

1. General Requirements. An operator must take prompt action to address all anomalous conditions in the pipeline that the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity, as required by this part. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An operator must comply with all other applicable requirements in this part in remediating a condition. Each operator must, in repairing its pipeline systems, ensure that the repairs are made in a safe and timely manner and are made so as to prevent damage to persons, property, or the environment. The calculation method(s) used for anomaly evaluation must be applicable for the range of relevant threats. [49 CFR 195.452(h)(1)]

a. Temporary Pressure Reduction. An operator must notify PHMSA, in accordance with Subsection M of this section, if the operator cannot meet the schedule for evaluation and remediation required under Paragraph H.3 of this section and cannot provide safety through a temporary reduction in operating pressure. [49 CFR 195.452(h)(1)(i)]

b. Long-Term Pressure Reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA in accordance with Subsection M of this section and explain the reasons for the delay. An operator must also take further remedial action to ensure the safety of the pipeline. [49 CFR 195.452(h)(1)(ii)]

2. Discovery of Condition. Discovery of a condition occurs when an operator has adequate information to determine that a condition presenting a potential threat to the integrity of the pipeline exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate the 180-day interval is impracticable. If the operator believes that 180 days are impracticable to make a determination about a condition found during an assessment, the pipeline operator must notify PHMSA in accordance with Subsection M of this Section and provide an expected date when adequate information will become available. [49 CFR 195.452(h)(2)]

3. Schedule for Evaluation and Remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety or environmental protection. [49 CFR 195.452(h)(3)]

4. Special Requirements for Scheduling Remediation [49 CFR 195.452(h)(4)]

a. Immediate Repair Conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formulas referenced in Clause H.4.a.ii of this Section. If no suitable remaining strength calculation method can be identified, an operator must implement a minimum 20 percent or greater operating pressure reduction, based on actual operating pressure for two months prior to the date of inspection, until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions: [49 CFR 195.452(h)(4)(i)]

i. metal loss greater than 80 percent of nominal wall regardless of dimensions; [49 CFR 195.452(h)(4)(i)(A)]

ii. a calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (incorporated by reference, see §30107) and PRCI PR-3-805 (R-STRENG) (incorporated by reference, see §30107). [49 CFR 195.452(h)(4)(i)(B)]

iii. a dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser; [49 CFR 195.452(h)(4)(i)(C)]

iv. a dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6 percent of the nominal pipe diameter; [49 CFR 195.452(h)(4)(i)(D)]

v. an anomaly that in the judgement of the person designated by the operator to evaluate the assessment results requires immediate action. [49 CFR 195.452(h)(4)(i)(E)]

b. 60-Day Conditions. Except for conditions listed in Subparagraph H.4.a of this Section, an operator must schedule evaluation and remediation of the following conditions within 60 days of discovery of condition: [49 CFR 195.452(h)(4)(ii)]

i. a dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3 percent of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12); [49 CFR 195.452(h)(4)(ii)(A)]

ii. a dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. [49 CFR 195.452(h)(4)(ii)(B)]

c. 180-Day Conditions. Except for conditions listed in Subsection H.4.(a) or (b) of this Section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition: [49 CFR 195.452(h)(4)(iii)]

i. a dent with a depth greater than 2 percent of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld; [49 CFR 195.452(h)(4)(iii)(A)]

ii. a dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2 percent of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12); [49 CFR 195.452(h)(4)(iii)(B)]

iii. a dent located on the bottom of the pipeline with a depth greater than 6 percent of the pipeline's diameter; [49 CFR 195.452(h)(4)(iii)(C)]

iv. a calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G and PRCI PR-3-805 (R-STRENG).[49 CFR 195.452(h)(4)(iii)(D)]

v. an area of general corrosion with a predicted metal loss greater than 50 percent of nominal wall; [49 CFR 195.452(h)(4)(iii)(E)]

vi. predicted metal loss greater than 50 percent of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld; [49 CFR 195.452(h)(4)(iii)(F)]

vii. a potential crack indication that when excavated is determined to be a crack; [49 CFR 195.452(h)(4)(iii)(G)]

viii. corrosion of or along a longitudinal seam weld; [49 CFR 195.452(h)(4)(iii)(H)]

ix. a gouge or groove greater than 12.5 percent of nominal wall. [49 CFR 195.452(h)(4)(iii)(I)]

d. Other Conditions. In addition to the conditions listed in Subparagraphs H.4.a through c of this Section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could impair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. §30905, Appendix C of this Subpart contains guidance concerning other conditions that an operator should evaluate. [49 CFR 195.452(h)(4)(iv)]

I. What preventive and mitigative measures must an operator take to protect the high consequence area? [49 CFR 195.452(i)]

1. General Requirements. An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. These measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protection. Such actions may include, but are not limited to, implementing damage prevention best practices, better monitoring of cathodic protection where corrosion is a concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment, modifying the systems that monitor pressure and detect leaks, providing additional training to personnel on response procedures, conducting drills with local emergency responders and adopting other management controls. [49 CFR 195.452(i)(1)]

2. Risk Analysis Criteria. In identifying the need for additional preventive and mitigative measures, an operator must evaluate the likelihood of a pipeline release occurring and how a release could affect the high consequence area. This determination must consider all relevant risk factors, including, but not limited to: [49 CFR 195.452(i)(2)]

a. terrain surrounding the pipeline segment, including drainage systems such as small streams and other smaller waterways that could act as a conduit to the high consequence area; [49 CFR 195.452(i)(2)(i)]

b. elevation profile; [49 CFR 195.452(i)(2)(ii)]

c. characteristics of the product transported; [49 CFR 195.452(i)(2)(iii)]

d. amount of product that could be released; [49 CFR 195.452(i)(2)(iv.)]

e. possibility of a spillage in a farm field following the drain tile into a waterway; [49 CFR 195.452(i)(2)(v)]

f. ditches along side a roadway the pipeline crosses; [49 CFR 195.452(i)(2)(vi)]

g. physical support of the pipeline segment such as by a cable suspension bridge; [49 CFR 195.452(i)(2)(vii)]

h. exposure of the pipeline to operating pressure exceeding established maximum operating pressure. [49 CFR 195.452(i)(2) (viii)]

i. seismicity of the area. [49 CFR 195.452(i)(2)(ix)]

3. Leak Detection. An operator must have a means to detect leaks on its pipeline system. An operator must evaluate the capability of its leak detection means and modify, as necessary, to protect the high consequence area. An operator's evaluation must, at least, consider, the following factors-length, and size of the pipeline, type of product carried, the pipeline's proximity to the high consequence area, the swiftness of leak detection, location of nearest response personnel, leak history, and risk assessment results. [49 CFR 195.452(i)(3)]

4. Emergency Flow Restricting Devices (EFRD). If an operator determines that an EFRD is needed on a pipeline segment that is located in, or which could affect, a high-consequence area (HCA) in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, evaluate the following factors: the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain within the HCA or between the pipeline segment and the HCA it could affect, and benefits expected by reducing the spill size. An RMV installed under this Paragraph must meet all of the other applicable requirements in this part, provided that the requirement of this sentence does not apply to gathering lines. [49 CFR 195.452(i)(4)]

a. Where EFRDs are installed on pipeline segments in HCAs and that could affect HCAs with diameters of 6 inches or greater and that are placed into service or that have had 2 or more miles of pipe replaced within 5 contiguous miles within a 24-month period after April 10, 2023, the location, installation, actuation, operation, and maintenance of such EFRDs (including valve actuators, personnel response, operational control centers, supervisory control and data acquisition (SCADA), communications, and procedures) must meet the design, operation, testing, maintenance, and rupture-mitigation requirements of §§30258, 30260, 30402, 30418, 30419, and 30420. [49 CFR 195.452(i)(4)(i)]

b. The EFRD analysis and assessments specified in Paragraph I.4 of this Section must be completed prior to placing into service all onshore pipelines with diameters of 6 inches or greater and that are constructed or that have had 2 or more miles of pipe within any 5 contiguous miles within any 24-month period replaced after April 10, 2023. Implementation of EFRD findings for RMVs must meet §301418 [49 CFR 195.452(i)(4)(ii)]

c. An operator may request an exemption from the compliance deadline requirements of this section if it can demonstrate to PHMSA, in accordance with the notification procedures in §30418, that installing an EFRD by that compliance deadline would be economically, technically, or operationally infeasible. [49 CFR 195.452(i)(4)(ii)]

J. What is a continual process of evaluation and assessment to maintain a pipeline's integrity? [49 CFR 195.452(j)]

1. General. After completing the baseline integrity assessment, an operator must continue to assess the line pipe at specified intervals and periodically evaluate the integrity of each pipeline segment that could affect a high consequence area. [49 CFR 195.452(j)(1)]

2. Verifying Covered Segments. An operator must verify the risk factors used in identifying pipeline segments that could affect a high consequence area on at least an annual basis not to exceed 15 months (Appendix C of this part provides additional guidance on factors that can influence whether a pipeline segment could affect a high consequence area). If a change in circumstance indicates that the prior consideration of a risk factor is no longer valid or that an operator should consider new risk factors, an operator must perform a new integrity analysis and evaluation to establish the endpoints of any previously identified covered segments. The integrity analysis and evaluation must include consideration of the results of any baseline and periodic integrity assessments (see Subsections B, C, D, and E of this Section), information analyses (see Subsection G of this Section), and decisions about remediation and preventive and mitigative actions (see Subsection H and I of this Section). An operator must complete the first annual verification under this Subsection no later than July 1, 2021. [49 CFR 195.452(j)(2)]

3. Assessment Intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the line pipe's integrity. An operator must base the assessment intervals on the risk the line pipe poses to the high consequence area to determine the priority for assessing the pipeline segments. An operator must establish the assessment intervals based on the factors specified in Subsection E of this Section, the analysis of the results from the last integrity assessment, and the information analysis required by Subsection G of this Section. [49 CFR 195.452(j)(3)]

4. Variance from the Five-Year Intervals in Limited Situations [49 CFR 195.452(j)(4)]

a. Engineering Basis. An operator may be able to justify an engineering basis for a longer assessment interval on a segment of line pipe. The justification must be supported by a reliable engineering evaluation combined with the use of other technology, such as external monitoring technology, that provides an understanding of the condition of the line pipe equivalent to that which can be obtained from the assessment methods allowed in Paragraph J.5 of this Section. An operator must notify OPS 270 days before the end of the five-year (or less) interval of the justification for a longer interval, and propose an alternative interval. An operator must send the notice to the addresses specified in Subsection M of this Section. [49 CFR 195.452(j)(4)(i)]

b. Unavailable Technology. An operator may require a longer assessment period for a segment of line pipe (for example, because sophisticated internal inspection technology is not available). An operator must justify the reasons why it cannot comply with the required assessment period and must also demonstrate the actions it is taking to evaluate the integrity of the pipeline segment in the interim. An operator must notify OPS 180 days before the end of the five-year (or less) interval that the operator may require a longer assessment interval, and provide an estimate of when the assessment can be completed. An operator must send a notice to the addresses specified in Subsection M of this Section. [49 CFR 195.452(j)(4)(ii)]

5. Assessment Methods. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies: [49 CFR 195.452(j)(5)]

a. In-Line Inspection tool or tools capable of detecting corrosion and deformation anomalies, including dents, gouges, and grooves. For pipeline segments that are susceptible to cracks (pipe body and weld seams), an operator must use an in-line inspection tool or tools capable of detecting crack anomalies. When performing an assessment using an in-line inspection tool, an operator must comply with § 30591; [49 CFR 195.452(j)(5)(i)]

b. pressure test conducted in accordance with Chapter 303 of this Subpart [49 CFR 195.452(j)(5)(ii)];

c. external corrosion direct assessment in accordance with §30588; or [49 CFR 195.452(j)(5)(iii)]

d. other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify OPS 90 days before conducting the assessment, by sending a notice to the addresses or facsimile numbers specified in Subsection M of this Section [49 CFR 195.452(j)(5)(iv)].

K. What methods to measure program effectiveness must be used? An operator's program must include methods to measure whether the program is effective in assessing and evaluating the integrity of each pipeline segment and in protecting the high consequence areas. See §30905, Appendix C, of this Subpart for guidance on methods that can be used to evaluate a program's effectiveness. [49 CFR 195.452(k)]

L. What records must an operator keep to demonstrate compliance? [49 CFR 195.452(l)]

1. An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a minimum, an operator must maintain the following records for review during an inspection: [49 CFR 195.452(l)(1)]

a. a written integrity management program in accordance with Subsection B of this Section; [49 CFR 195.452(l)(1)(i)]

b. documents to support the decisions and analyses, including any modifications, justifications, variances, deviations and determinations made, and actions taken, to implement and evaluate each element of the integrity management program listed in Subsection F of this Section. [49 CFR 195.452(l)(1)(ii)]

2. See §30905, Appendix C, of this Subpart for examples of records an operator would be required to keep. [49 CFR 195.452(l)(2)]

M. How does an operator notify PHMSA? An operator must provide any notification required by this section by: [49 CFR 195.452(m)]

1. sending the notification by electronic mail to InformationResourcesManager@dot.gov and Pipeline. inspectors@la.gov; or [49 CFR 195.452(m)(1)]

2. sending the notification to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., Washington, DC 20590, and to the Commissioner of Conservation, Pipeline Safety Section, P.O. Box 94275, Baton Rouge, LA 70804-9275. [195.452(m)(2)]

N. Accommodation of Instrumented Internal Inspection Devices [49 CFR 195.452(n)]

1. Scope. This Subsection does not apply to any pipeline facilities listed in §30177.B [49 CFR 195.452(n)(1)]

2. General. An operator must ensure that each pipeline is modified to accommodate the passage of an instrumented internal inspection device by July 2, 2040. [49 CFR 195.452(n)(2)]

3. Newly Identified Areas. If a pipeline could affect a newly identified high consequence area (see Paragraph D.2 of this Section) after July 2, 2035, an operator must modify the pipeline to accommodate the passage of an instrumented internal inspection device within five years of the date of identification or before performing the baseline assessment, whichever is sooner. [49 CFR 195.452(n)(3)]

4. Lack of Accommodation. An operator may file a petition under §190.9 of 49 CFR and Chapter 313 of this Subpart for a finding that the basic construction (i.e., length, diameter, operating pressure, or location) of a pipeline cannot be modified to accommodate the passage of an instrumented internal inspection device or that the operator determines it would abandon or shut-down a pipeline as a result of the cost to comply with the requirement of this section. [49 CFR 195.452(n)(4)]

5. Emergencies. An operator may file a petition under §190.9 of 49 CFR and Chapter 313 of this Subpart for a finding that a pipeline cannot be modified to accommodate the passage of an instrumented internal inspection device as a result of an emergency. An operator must file such a petition within 30 days after discovering the emergency. If the petition is denied, the operator must modify the pipeline to allow the passage of an instrumented internal inspection device within 1 year after the date of the notice of the denial. [49 CFR 195.452(n)(5)]