Transmission Lines: Assessments Outside of High Consequence Areas [49 CFR 192.710]

(A)A. Applicability#

(1)1. This Section applies to onshore steel transmission pipeline segments with a maximum allowable operating pressure of greater than or equal to 30 percent of the specified minimum yield strength and are located in: [49 CFR 192.710(a)]#

(a)a. a Class 3 or Class 4 location; or [49 CFR 192.710(a)(1)]#

(b)b. a moderate consequence area as defined in §503, if the pipeline segment can accommodate inspection by means of an instrumented inline inspection tool (i.e., "smart pig"). [49 CFR 192.710(a)(2)]#

(2)2. This Section does not apply to a pipeline segment located in a high consequence area as defined in §3303. [49 CFR 192.710(a)(3)]#

(B)B. General [49 CFR 192.710(b)]#

(1)1. Initial Assessment. An operator must perform initial assessments in accordance with this Section based on a risk-based prioritization schedule and complete initial assessment for all applicable pipeline segments no later than July 3, 2034, or as soon as practicable but not to exceed 10 years after the pipeline segment first meets the conditions of §2910.A (e.g., due to a change in class location or the area becomes a moderate consequence area), whichever is later. [49 CFR 192.710(b)(1)]#

(2)2. Periodic Reassessment. An operator must perform periodic reassessments at least once every 10 years, with intervals not to exceed 126 months, or a shorter reassessment interval based upon the type of anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety. [49 CFR 192.710(b)(2)]#

(3)3. Prior Assessment. An operator may use a prior assessment conducted before July 1, 2020 as an initial assessment for the pipeline segment, if the assessment met the Chapter 33 requirements of Part VIII for in-line inspection at the time of the assessment. If an operator uses this prior assessment as its initial assessment, the operator must reassess the pipeline segment according to the reassessment interval specified in Paragraph B.2 of this Section calculated from the date of the prior assessment. [49 CFR 192.710(b)(3)]#

(4)4. MAOP Verification. An integrity assessment conducted in accordance with the requirements of §2724.C for establishing MAOP may be used as an initial assessment or reassessment under this Section. [49 CFR 192.710(b)(4)]#

(C)C. Assessment Method. The initial assessments and the reassessments required by Subsection B of this Section must be capable of identifying anomalies and defects associated with each of the threats to which the pipeline segment is susceptible and must be performed using one or more of the following methods. [49 CFR 192.710(c)]#

(1)1. internal inspection. Internal inspection tool or tools capable of detecting those threats to which the pipeline is susceptible, such as corrosion, deformation and mechanical damage (e.g., dents, gouges and grooves), material cracking and crack- like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with §2145; [49 CFR 192.710(c)(1)]#

(2)2. pressure test. Pressure test conducted in accordance with Chapter 23 of this Subpart. The use of Chapter 23 pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms; manufacturing and related defect threats, including defective pipe and pipe seams; and stress corrosion cracking, selective seam weld corrosion, dents and other forms of mechanical damage; [49 CFR 192.710(c)(2)]#

(3)3. spike hydrostatic pressure test. A spike hydrostatic pressure test conducted in accordance with §2306. A spike hydrostatic pressure test is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; [49 CFR 192.710(c)(3)]#

(4)4. direct examination. Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non- destructive examination results and data needed to assess all applicable threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave Field Extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); [49 CFR 192.710(c)(4)]#

(5)5. guided wave ultrasonic testing. guided wave ultrasonic testing (GWUT) as described in Appendix F; [49 CFR 192.710(c)(5)]#

(6)6. direct assessment. Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in § 3323 and with the applicable requirements specified in §§ 3325, 3327 and 3329; or [49 CFR 192.710(c)(6)]#

(7)7. other technology. Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with §518. [49 CFR 192.710(c)(7)]#

(D)D. Data Analysis. An operator must analyze and account for the data obtained from an assessment performed under Subsection C of this Section to determine if a condition could adversely affect the safe operation of the pipeline using personnel qualified by knowledge, training, and experience. In addition, when analyzing inline inspection data, an operator must account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies. [49 CFR 192.710(d)]#

(E)E. Discovery of Condition. 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. 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 180 days is impracticable. [49 CFR 192.710(e)]#

(F)F. Remediation. An operator must comply with the requirements in §§2137, 2911, 2912, 2913 and 2914, where applicable, if a condition that could adversely affect the safe operation of a pipeline is discovered. [49 CFR 192.710(f)]#

(G)G. Analysis of Information. An operator must analyze and account for all available relevant information about a pipeline in complying with the requirements in Subsections A through F of this Section. [49 CFR 192.710(g)]#

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

HISTORICAL NOTE: Promulgated by the Department of Natural Resources, Office of Conservation, LR 46:1594 (November 2020), amended LR 50:1253 (September 2024).#