49 CFR Subpart O - Gas Transmission Pipeline Integrity Management
- § 192.901 What do the regulations in this subpart cover?
- § 192.903 What definitions apply to this subpart?
- § 192.905 How does an operator identify a high consequence area?
- § 192.907 What must an operator do to implement this subpart?
- § 192.909 How can an operator change its integrity management program?
- § 192.911 What are the elements of an integrity management program?
- § 192.913 When may an operator deviate its program from certain requirements of this subpart?
- § 192.915 What knowledge and training must personnel have to carry out an integrity management program?
- § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program?
- § 192.919 What must be in the baseline assessment plan?
- § 192.921 How is the baseline assessment to be conducted?
- § 192.923 How is direct assessment used and for what threats?
- § 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)?
- § 192.927 What are the requirements for using Internal Corrosion Direct Assessment (ICDA)?
- § 192.929 What are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)?
- § 192.931 How may Confirmatory Direct Assessment (CDA) be used?
- § 192.933 What actions must be taken to address integrity issues?
- § 192.935 What additional preventive and mitigative measures must an operator take?
- § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity?
- § 192.939 What are the required reassessment intervals?
- § 192.941 What is a low stress reassessment?
- § 192.943 When can an operator deviate from these reassessment intervals?
- § 192.945 What methods must an operator use to measure program effectiveness?
- § 192.947 What records must an operator keep?
- § 192.949 [Reserved]
- § 192.951 Where does an operator file a report?
68 FR 69817, Dec. 15, 2003, unless otherwise noted.