Part 192

Subpart O—Gas Transmission Pipeline Integrity Management

1. § 192.901What do the regulations in this subpart cover?
2. § 192.903What definitions apply to this subpart?
3. § 192.905How does an operator identify a high consequence area?
4. § 192.907What must an operator do to implement this subpart?
5. § 192.909How can an operator change its integrity management program?
6. § 192.911What are the elements of an integrity management program?
7. § 192.913When may an operator deviate its program from certain requirements of this subpart?
8. § 192.915What knowledge and training must personnel have to carry out an integrity management program?
9. § 192.917How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program?
10. § 192.919What must be in the baseline assessment plan?
11. § 192.921How is the baseline assessment to be conducted?
12. § 192.923How is direct assessment used and for what threats?
13. § 192.925What are the requirements for using External Corrosion Direct Assessment (ECDA)?
14. § 192.927What are the requirements for using Internal Corrosion Direct Assessment (ICDA)?
15. § 192.929What are the requirements for using Direct Assessment for Stress Corrosion Cracking?
16. § 192.931How may Confirmatory Direct Assessment (CDA) be used?
17. § 192.933What actions must be taken to address integrity issues?
18. § 192.935What additional preventive and mitigative measures must an operator take?
19. § 192.937What is a continual process of evaluation and assessment to maintain a pipeline's integrity?
20. § 192.939What are the required reassessment intervals?
21. § 192.941What is a low stress reassessment?
22. § 192.943When can an operator deviate from these reassessment intervals?
23. § 192.945What methods must an operator use to measure program effectiveness?
24. § 192.947What records must an operator keep?
25. § 192.949[Reserved]Reserved
26. § 192.951Where does an operator file a report?