CFR
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SUBPART O—Gas Transmission Pipeline Integrity Management (§192.901 to §192.951)
- 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—How does an operator notify PHMSA?
- 192.951—Where does an operator file a report?
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