PHMSA Gas Integrity Management Protocols
Explanation of Protocol Format
Each protocol element will have top-tier protocols that address the high level requirements. The regulatory requirement upon which the protocol is based is contained in brackets; e.g., [§192.905(a)]
Each top-tier protocol will have detailed "sub-tier" protocols which collectively lead the inspector to draw overall conclusions about compliance with the top-tier protocol. The regulatory requirement, upon which each sub-tier protocol is based, is also contained in brackets.
Notes on protocols:
- The typical sentence structure used in the protocols follows the form of "Verify that [describe the requirement]." The use and meaning of the term "verify" is expanded upon below.
- PHMSA will "verify" an operator’s compliance status with respect to each requirement. In order to perform this verification, PHMSA will inspect the operator’s documented processes and procedures in order to determine if a program has been established that complies with rule requirements. In addition, PHMSA will inspect an operator’s implementation records to determine if the operator is effectively implementing its programs and processes. The purpose of the PHMSA verification/inspection is not to perform a quality check of every integrity related activity. The PHMSA inspection is conducted in the form of an audit. As a result, the PHMSA inspection will typically perform an inspection of selected operator records sufficient in breadth and depth to give the inspection team adequate understanding regarding the degree of an operator's commitment to compliance with applicable requirements and/or the degree to which the operator's program has been effective with respect to achieving compliance. PHMSA may use any number of inspection or audit techniques to identify potential compliance issues. Program documents may be inspected to determine if adequate processes have been developed and documented to the degree necessary for competent professionals to understand and effectively implement the process with results that are consistent and repeatable. For example, one technique that might be used by the inspection team is a "vertical slice" in which a specific covered segment or pipeline system is selected to perform a detailed inspection of every aspect of integrity management, thus following a specific example through the entire process of integrity management. Based on those reviews, OPS will identify potential non-compliances with rule requirements. PHMSA can not and will not certify nor conclude that an operator is in full compliance with rule requirements, even if the inspection does not identify any areas of non-compliance. Operators are wholly responsible for compliance with regulations.
- References to regulatory requirements may include references to specific rule sections/paragraphs and/or to industry standards that are invoked in the rule. As specified in §192.7, any requirement invoked by reference is a requirement of the rule as though it were set out in full in the regulation.
- Protocols are subject to change without notice.
- Protocols are an initial guide for use by OPS inspectors during Integrity Management inspections. Inspectors will develop additional questioning during the course of the inspection to investigate the specifics of an operator's program. Protocols are not to be construed as an exhaustive list of questions that may be presented to operators during an inspection.
- Protocols are made publicly available as a courtesy to operators as they develop their Integrity Management program, as well as other stakeholders.
- F.01 Periodic Evaluations
- F.02 Reassessment Methods
- F.03 Low Stress Reassessment
- F.04 Reassessment Intervals
- F.05 Deviation from Reassessment Requirements
- F.06 Waiver from Reassessment Interval
F.01 Periodic Evaluations
Verify the operator conducts a periodic evaluation of pipeline integrity based on data integration and risk assessment to identify the threats specific to each covered segment and the risk represented by these threats. [§192.917 and §192.937(b)]
Verify that periodic evaluations are conducted based on a data integration and risk assessment of the entire pipeline as specified in §192.917. The evaluation must consider the following: [§192.937(b) and 192.917]
- Past and present assessment results
- Data integration and risk assessment information [§192.917]
- Decisions about remediation [§192.933]
- Additional preventive and mitigative actions [§192.935]
F.01.b. Verify that periodic evaluations of data are thorough, complete, and adequate for establishing reassessment methods and schedules. [§192.937(b)]
F.01.c. Verify that an appropriate interval is established for performing required periodic evaluations of threats and pipeline conditions following completion of the baseline assessment. [§192.937(b)]
F.01.d. Verify that the operator periodically reviews the evaluation results to determine if the new information warrants changes to reassessment intervals and/or methods, and makes changes as appropriate. [§192.937]
F.02 Reassessment Methods
Verify that the approach for establishing the reassessment method is consistent with the requirements in §192.937(c). [§192.937(c) and §192.941]
Verify that one or more of the following assessment methods (depending on the applicable threats) are specified:
- An internal inspection tool(s) capable of detecting corrosion and any other threats that the operator intends to address using this tool(s). The process must follow ASME B31.8S-2004, Section 6.2, in selecting the appropriate inspection tool. [§192.937(c)(1)]
- A pressure test conducted in accordance with Subpart J. An operator must use the test pressures specified in ASME B31.8S-2004, Section 5, Table 3, to justify an extended reassessment interval in accordance with §192.939. Pressure test is appropriate for threats as defined in ASME B31.8S-2004, Section 6.3. [§192.937(c)(2)]
- Direct assessment – refer to Protocol D. [§192.937(c)(3)]
- Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the pipe. If other technology is the method selected, the process should require that the operator notify OPS at least 180 days before conducting the assessment, in accordance with §192.949. Also, verify that notification to a State or local pipeline safety authority is required when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. [§192.937(c)(4)]
- Confirmatory direct assessment when used on a covered segment that is scheduled for a reassessment period longer than seven years. Refer to Protocol G. [§192.937(c)(5)]
- If the operator is using "low stress reassessment" method, evaluate the process using Protocol F.03.
F.02.b. Review the methods selected for reassessments and verify that they are appropriate for the identified threats.
F.03 Low Stress Reassessment
For pipelines operating at < 30% SMYS, the operator may choose to use a "low stress reassessment" method to address threats of external and internal corrosion. If this method is used, verify that the operator addresses the following requirements [§192.941]:
F.03.a. Verify that the operator completes a baseline assessment on the covered segment prior to implementing the "low stress reassessment" method. [§192.941(a)]
If used to address external corrosion, verify that the operator has incorporated the following:
- If the pipe is cathodically protected, electrical surveys (i.e., indirect examination tool/method) must be performed at least every 7 years. The operator must use the results of each survey as part of an overall evaluation of the cathodic protection and corrosion threat for covered segments. This evaluation must consider, at a minimum, the leak repair and inspection records, corrosion monitoring records, exposed pipe records, and the pipeline environment. [§192.941(b)(1)]
- If the pipe is unprotected or cathodically protected where electrical surveys are impractical, the operator must require (1) the conduct of leakage surveys as required by §192.706, at 4-month intervals; and (2) the identification and remediation of areas of active corrosion every 18 months by evaluating leak repair and inspection records, corrosion monitoring records, exposed pipe records, and the pipeline environment. [§192.941(b)(1)]
If used to address internal corrosion, verify that the operator has incorporated all of the following:
- Gas analysis for corrosive agents must be performed at least once each calendar year. [§192.941(c)(1)]
- Periodic testing of fluids removed from the segment must be conducted. At least once each calendar year the operator must test the fluids removed from each storage field that may affect a covered segment. [§192.941(c)(2)]
- At least every seven (7) years, the operator must integrate data from the analysis and testing required by c.i and c.ii above with applicable internal corrosion leak records, incident reports, and test records, and define and implement appropriate remediation actions. [§192.941(c)(3)]
F.04 Reassessment Intervals
Verify that the requirements for establishing the reassessment intervals are consistent with section §192.939 and ASME B31.8S-2004. [§192.937(a), §192.939(a), §192.939(b), §192.913(c), and ASME B31.8S-2004, Section 5, Table 3]
F.04.a. Verify that the operator reassesses covered segments on which a baseline assessment was conducted during the baseline period specified in subpart 192.921(d) by no later than seven years after the baseline assessment of that covered segment unless the reassessment evaluation (refer to Protocol F.01) indicates an earlier reassessment. [§192.937(a)]
For pipelines operating at or above 30% SMYS, verify that the operator meets the following requirements:
- If the operator establishes a reassessment interval greater than seven (7) years, a confirmatory direct assessment (refer to Protocol G) must be performed at intervals not to exceed seven (7) years followed by a reassessment at the interval established by the operator (refer below). [§192.939(a)]
- Unless a deviation is permitted under §192.913(c), the maximum reassessment interval shall not exceed the values listed in the §192.939(b) table. [§192.937(a)]
- If the reassessment method is a pressure test, ILI, or other equivalent technology, the interval must be based on either: (1) the identified threat(s) for the covered segment (see §192.917) and on the analyses of the results from the last integrity assessment, and a review of data integration and risk assessment; or (2) using the intervals specified for different stress levels of pipeline listed in ASME B31.8S-2004, Section 5, Table 3. An operator must use the test pressures specified in ASME B31.8S-2004, Section 5, Table 3, to justify an extended reassessment interval in accordance with §192.939. [§192.939(a)(1)]
- If the reassessment method is external corrosion direct assessment, internal corrosion direct assessment, or SCC direct assessment refer to Protocol D for evaluating the operator's interval determination.
For pipelines operating < 30% SMYS, verify that the operator selects one of the following reassessment approaches:
- Reassessment by pressure test, internal inspection or other equivalent technology following the requirements in §192.939(a)(1) except that the stress level referenced in §192.939(a)(1)(ii) would be adjusted to reflect the lower operating stress level. However, if an established interval is more than seven (7) years, the operator must conduct at seven (7) year intervals either a confirmatory direct assessment in accordance with §192.931, or a low stress reassessment in accordance with §192.941. An operator must use the test pressures specified in ASME B31.8S-2004, Section 5, Table 3, to justify an extended reassessment interval in accordance with §192.939.[§192.939(b)(1)]
- Reassessment by external corrosion direct assessment, internal corrosion direct assessment, or SCC direct assessment. Refer to Protocol D for evaluating the operator's interval determination. [§192.939(b)(2), §192.939(b)(3) and §192.939(b)(4)]
- Reassessment by confirmatory direct assessment at seven year intervals in accordance with subpart 192.931, with reassessment by one of the methods listed in §192.939(b)(1) – §192.939(b)(3) by year 20 of the interval. [§192.939(b)(4)]
- Reassessment by the "low stress method" at 7-year intervals in accordance with §192.941 with reassessment by one of the methods listed in §192.939(b)(1) through §192.939(b)(3) by year 20 of the interval. [§192.939(b)(5)]
F.04.d. Verify that a covered segment on which a prior assessment was credited as a baseline assessment under subpart §192.921(e) is required to be reassessed by no later than December 17, 2009. [§192.937(a)]
F.04.e. Verify that reassessment intervals are appropriate and that adequate documentation and technical bases support the intervals selected.
F.05 Deviation from Reassessment Requirements
If the operator elects to deviate from certain requirements listed in §192.913(c), verify that the operator uses a performance based approach that satisfies the requirements for exceptional performance as follows: [§192.913 and ASME B31.8S-2004]
Verify that the operator has a performance based integrity management program that meets or exceeds the performance-based requirements of ASME B31.8S-2004 and includes, at a minimum, the following elements: [§192.913(a)]
- A comprehensive process for risk analysis;
- All risk factor data used to support the program;
- A comprehensive data integration process;
- A procedure for applying lessons learned from assessment of covered pipeline segments to pipeline segments not covered by this subpart;
- A procedure for evaluating every incident, including its cause, within the operator's sector of the pipeline industry for implications both to the operator's pipeline system and to the operator's integrity management program;
- A performance matrix that demonstrates the program has been effective in ensuring the integrity of the covered segments by controlling the identified threats to the covered segments (Refer to Protocol I);
- Semi-annual performance measures beyond those required in §192.943 that are part of the operator's performance plan. [See §192.911(i)] Refer to Protocol I.
- An analysis that supports the desired integrity reassessment interval and the remediation methods to be used for all covered segments.
F.05.b. Verify that the operator has completed at least two integrity assessments on each covered pipeline segment the operator is including under the performance-based approach and is able to demonstrate that each assessment effectively addressed the identified threats on the covered segments. [§192.913(b)(2)(i)]
F.05.c. Verify the operator has remediated anomalies identified in the more recent assessment per the requirements of §192.933. [§192.913(b)(2)(ii)]
F.05.d. Verify the operator has incorporated the results and lessons learned from the more recent assessment into the operator's data integration and risk assessment. [§192.913(b)(2)(ii)]
F.05.e. Verify that deviations are allowed only for the timeframe for reassessment as provided in §192.939 except that reassessment by some method allowed by Subpart O (e.g., confirmatory direct assessment) must be completed at intervals not to exceed seven (7) years. [§192.913(c)(1)]
F.06 Waiver from Reassessment Interval
Verify that the operator's program requires that it apply for a waiver, should it become necessary, from the required reassessment interval. The waiver request must demonstrate that the waiver is justified as specified in the rule. Such a waiver request may only be made in the following limited situations: [§192.943]
F.06.a. Lack of internal inspection tools. [§192.943(a)(1)]
F.06.b. Cannot maintain local product supply. [§192.943(a)(2)]
F.06.c. Application must be made at least 180 days before the end of the required reassessment interval. (Exception: If local product supply issues make the 180 day submittal impractical, an operator must apply for the waiver as soon as the need for waiver becomes known). [§192.943(b)]