(b)Data gathering and integration. To identify and evaluate the potential threats to a covered pipeline segment, an operator must gather and integrate existing data and information on the entire pipeline that could be relevant to the covered segment. In performing data gathering and integration, an operator must follow the requirements in ASME/ANSI B31.8S, section 4. Operators must begin to integrate all pertinent data elements specified in this section starting on May 24, 2023, with all available attributes integrated by February 26, 2024. An operator may request an extension of up to 1 year by submitting a notification to PHMSA at least 90 days before February 26, 2024, in accordance with § 192.18 . The notification must include a reasonable and technically justified basis, an up-to-date plan for completing all actions required by this paragraph (b), the reason for the requested extension, current safety or mitigation status of the pipeline segment, the proposed completion date, and any needed temporary safety measures to mitigate the impact on safety. An operator must gather and evaluate the set of data listed in paragraph (b)(1) of this section. The evaluation must analyze both the covered segment and similar non-covered segments, and it must:
(1) Integrate pertinent information about pipeline attributes to ensure safe operation and pipeline integrity, including information derived from operations and maintenance activities required under this part, and other relevant information, including, but not limited to: (i) Pipe diameter, wall thickness, seam type, and joint factor;(ii) Manufacturer and manufacturing date, including manufacturing data and records;(iii) Material properties including, but not limited to, grade, specified minimum yield strength (SMYS), and ultimate tensile strength;(iv) Equipment properties;(v) Year of installation;(vii) Joining method, including process and inspection results;(ix) Crossings, casings (including if shorted), and locations of foreign line crossings and nearby high voltage power lines;(x) Hydrostatic or other pressure test history, including test pressures and test leaks or failures, failure causes, and repairs;(xi) Pipe coating methods (both manufactured and field applied), including the method or process used to apply girth weld coating, inspection reports, and coating repairs;(xiii) Construction inspection reports, including but not limited to: (A) Post backfill coating surveys; and(B) Coating inspection ("jeeping" or "holiday inspection") reports;(xiv) Cathodic protection installed, including, but not limited to, type and location;(xviii) Normal maximum and minimum operating pressures, including maximum allowable operating pressure (MAOP);(xx) Leak and failure history, including any in-service ruptures or leaks from incident reports, abnormal operations, safety-related conditions (both reported and unreported) and failure investigations required by § 192.617 , and their identified causes and consequences;(xxii) Cathodic protection (CP) system performance;(xxiii) Pipe wall temperature;(xxiv) Pipe operational and maintenance inspection reports, including, but not limited to: (A) Data gathered through integrity assessments required under this part, including, but not limited to, in-line inspections, pressure tests, direct assessments, guided wave ultrasonic testing, or other methods;(B) Close interval survey (CIS) and electrical survey results;(C) CP rectifier readings;(D) CP test point survey readings and locations;(E) Alternating current, direct current, and foreign structure interference surveys;(F) Pipe coating surveys, including surveys to detect coating damage, disbonded coatings, or other conditions that compromise the effectiveness of corrosion protection, including, but not limited to, direct current voltage gradient or alternating current voltage gradient inspections;(G) Results of examinations of exposed portions of buried pipelines (e.g., pipe and pipe coating condition, see§ 192.459 ), including the results of any non-destructive examinations of the pipe, seam, or girth weld (i.e. bell hole inspections);(H) Stress corrosion cracking excavations and findings;(I) Selective seam weld corrosion excavations and findings;(J) Any indication of seam cracking; and(K) Gas stream sampling and internal corrosion monitoring results, including cleaning pig sampling results;(xxv) External and internal corrosion monitoring;(xxvi) Operating pressure history and pressure fluctuations, including an analysis of effects of pressure cycling and instances of exceeding MAOP by any amount;(xxvii) Performance of regulators, relief valves, pressure control devices, or any other device to control or limit operating pressure to less than MAOP;(xxxii) Audits and reviews;(xxxiii) Industry experience for incident, leak, and failure history;(xxxiv) Aerial photography; and(xxxv) Exposure to natural forces in the area of the pipeline, including seismicity, geology, and soil stability of the area.(2) Use validated information and data as inputs, to the maximum extent practicable. If input is obtained from subject matter experts (SME), an operator must employ adequate control measures to ensure consistency and accuracy of information. Control measures may include training of SMEs or the use of outside technical experts (independent expert reviews) to assess the quality of processes and the judgment of SMEs. An operator must document the names and qualifications of the individuals who approve SME inputs used in the current risk assessment.(3) Identify and analyze spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings or evidence of pipeline damage where overhead imaging shows evidence of encroachment).(4) Analyze the data for interrelationships among pipeline integrity threats, including combinations of applicable risk factors that increase the likelihood of incidents or increase the potential consequences of incidents.