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 How does an operator notify PHMSA?
192.951 Where does an operator file a report?

[Amdt. 192 95, 69 FR 2307, December 22, 2003]