Incidents are as defined for incident reporting in 49 CFR 191.3. OPS expects, however, that operators deviating from the requirements of prescriptive programs on the basis of "exceptional performance" under 192.913(b) will evaluate events that involve unintentional release of gas but which do not reach the reporting threshold. Such events can illuminate lessons that, if acted upon, can avoid additional events, some of which may produce greater consequences. OPS expects that operators with mature programs (i.e., those demonstrating "exceptional performance") will seek to acquire and act on these lessons, and that their evaluations of such events will have a degree of transparency that allows OPS to also learn from the evaluations
Yes. The continual evaluation, preventive and mitigative actions, and information analysis requirements of the rule apply to pipelines as defined in 49 CFR 192.3. This includes, but is not limited to, line pipe, valves and other appurtenances attached to line pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. The baseline integrity assessment and periodic re-assessment requirements apply only to line pipe including crossovers, bypass piping, etc.
No. While periodically assessing the pipe condition and correcting identified anomalies is an important part of the rule, there are other important requirements. Operators must develop improved management and analysis processes that integrate all available integrity-related data and information and assess the risks associated with pipeline segments in HCAs. Furthermore, operators must enhance damage prevention programs and implement additional risk control measures beyond those already required by Part 192. Examples of these additional measures include: installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs.
Typically, OPS inspects the operator for compliance with the pipeline safety regulations, however, compliance responsibility would have to be determined on a case by case basis and is contingent on the terms of contracts, operating agreements, and any other relevant correspondence between the involved parties. Depending on the terms of the agreement, either or both could be held responsible.
Yes, provided the assessment meets the requirement of Subpart O and can be used as a baseline assessment.
The rule applies to all operators of gas transmission pipelines subject to Part 192.
Yes. Operators of transmission pipelines transporting other gases must adjust the formula for determining potential impact circles to reflect the constant appropriate for the gas transported.
The rule does not apply to gathering lines. Section 192.9 has been changed to make this clear. The rule does apply to low-stress pipeline that meets the definition in 192.3 as a transmission line, but some requirements are slightly different for low-pressure transmission pipelines (i.e. <30% SMYS).
The regulatory deadlines for assessments (e.g., that re-assessments be conducted within specified intervals, based on operating stress levels) continue to apply, as well as the schedule requirements for any remediation required by 192.933 that may be pending at the time ownership of the pipeline is transferred. Compliance deadlines established in 192 Subpart O for identifying segments in HCAs and for completing 50% or 100% of Baseline Assessments continue to apply. For purposes of integrity management, an operator acquiring a pipeline would be expected to integrate that pipeline into its integrity management program. OPS would expect this integration to occur within one year. Integration of new assets into existing Baseline Assessment Plans may result in realigning schedules for future assessments based on the relative risk of the acquired pipeline and the operator’s existing pipeline(s).
Integration of acquired pipe into an operator's IM plan could constitute the kind of substantial change in the IM program for which notification is required under 192.909(b), if the integration caused significant changes to existing schedules and programs.
Where sections of consensus standards are incorporated by reference into a rule, those sections become binding requirements the same as if the language were repeated in the rule. Operators must follow the requirements in the Appendices of ASME/ANSI B31.8S when those Appendices, or sections thereof, are referenced in the rule, even though the standard indicates that the appendices are non-mandatory.
Lines that transport both liquids and gas must meet requirements applicable to both. In practice, this means that the more stringent requirements must be met.
OPS expects operators to implement "should" statements in industry standards that are invoked by the rule. Operators may choose to implement an alternative approach in meeting the recommendations of invoked standards. If this approach is taken, program requirements for the alternative approach must exist in IM Program documents and records must be generated by the alternative approach. The IM Program documents must also technically justify that the alternative approach provides an equivalent level of protection. If an operator chooses not to implement a "should" statement in an invoked standard, a sound technical basis for why it has not been implemented must be documented in the IM Program documents.
When standards are incorporated into a rule by reference, the requirements of the standard become requirements of the rule. Operators are required to implement "must" and "shall" statements in the standard. Where the standard provides an alternative, e.g., in the event an action that "must" be done cannot be accomplished, the alternative must be implemented with appropriate justification. (In the event of conflicts between provisions in the standard and the Rule, the Rule takes precedence).
Section 192.901 states that of the requirements in subpart O only the requirements in sections 192.917, 192.921, 192.935 and 192.937 apply to plastic transmission pipeline. Each of these sections contains requirements specifically applicable to plastic pipelines. Operators of plastic transmission pipelines must meet the requirements in these sections that are specifically directed at plastic pipelines and need not comply with other requirements in the designated sections.
An operator need not develop an integrity management program if there are no high consequence areas on its system. The operator must have completed an evaluation to determine that no high consequence areas exist, and this evaluation must be maintained available for inspection. Even if no HCAs exist, however, there are some requirements in Subpart O with which an operator must comply:
- An operator must have a process to periodically evaluate its pipeline to determine if new HCAs have been created. Changes along the pipeline route, including housing construction and creation of new facilities meeting criteria in the definition of identified sites could cause HCAs to come into existence. An operator must be able to demonstrate that it has periodically evaluated its pipeline to assure that there continue to be no HCAs.- An operator must submit semi-annual "performance measure" reports in accordance with 192.945(a) indicating that there are no HCAs on its system.
If the periodic evaluation identifies that a new HCA exists, then the operator must prepare an integrity management plan and meet all the requirements of subpart O.
The integrity assessment provisions of the rule apply only to line pipe, including pipe that may be within the boundaries of facilities (e.g., compressor stations, metering stations). The other provisions of the rule apply to the equipment in these facilities (e.g., compressors) if the locations meet the criteria to be designated HCAs. Thus, operators must consider facilities when establishing potential impact circles (the diameter of the pipe into/out of the equipment should be used), and should include in their integrity management program processes for addressing these facilities. These processes should integrate all available information affecting the likelihood and the consequences of equipment or facility failure and identify and implement additional preventive or mitigative measures to reduce risk at these facilities, if needed. An operator's performance monitoring process should evaluate the effectiveness of these processes and the risk controls that are implemented to reduce facility risk.
"Distribution center" is not defined in federal pipeline safety regulations. State definitions can vary. OPS recognizes the actions of each state in defining what constitutes a distribution center.
No. See 192.9.
The regulations do not define "idle" pipe. Pipe is considered either active or abandoned. OPS understands "idle" pipe, as used in the context of this question, as pipe not currently being used to move gas but that could be put back in service at a future date. All pipe is subject to the requirements of the integrity management rule. However, idle pipe presents different risks and different treatment is appropriate.
In-service pipe (i.e., that contains gas, but is not presently being used to transport gas) represents a potential hazard to public health and the environment, even though idle. If such pipe leaks or ruptures, an explosion could result. Leaks may go undetected for some time, since idle pipe may not be covered by operator's SCADA systems. For these reasons, operators must meet all requirements and deadlines for pipe that contains gas. Such pipe must be included when determining if the requirement to assess 50% of covered pipeline mileage by December 17, 2007, has been met.
Out-of-service pipe (i.e., pipe laid up with nitrogen) represents much less hazard. Degradation of such pipe can occur, but is not likely to result in safety impacts. OPS will accept deferral of activities required by the rule for out-of-service pipe. All deferred activities must be completed as part of any later return of that line to service. A baseline assessment need not be run immediately if the deadline for completing baseline assessments (i.e., December 17, 2012) has not yet expired, unless the risk posed by the line would require an earlier assessment. The baseline assessment plan should be modified to assure that a baseline assessment is completed by the appropriate deadline. If the deadline has expired, then a baseline assessment must be completed as part of returning the line to service.
Adding an idle line into the IM program would be considered a substantive program change and would require notification under 192.909(b).
Any newly-constructed gas transmission pipeline placed into service after the effective date of the integrity management rule, February 14, 2004, is considered "newly-installed" for purposes of the rule. Therefore, the baseline assessment on such piping is not due until 10 years following the installation of the pipeline. The same applies to pipe in covered segments that operators replace. In this case, the operator may credit this mileage as "assessed" for determining compliance with the 50% progress milestone. The ten-year due date for conducting the baseline assessment for new pipe would also apply to pipe replaced under this circumstance. This does not, however, relieve the operator of requirements to conduct tests required under other provisions of Part 192 associated with placing pipeline into service.
OPS expects operators to diligently pursue completion of actions required by the rule. At the same time, OPS recognizes that these actions cannot occur immediately. OPS inspectors will assess an operator's plans, actions, and progress to verify that an operator is making a good faith effort to comply.
For immediate repairs, physical remediation may take some time, but should be done promptly. Immediate action is needed, however, to assure safety. OPS expects that actions to reduce pressure or shut in the line will begin as soon as a defect meeting immediate repair criteria is identified.
For the specific example of identifying HCAs for newly-installed pipe, the requirements for newly-identified HCAs apply. Any HCAs on the new pipe must be identified and included in the baseline assessment plan within one year (192.905(c)). These new HCAs must be assessed within ten years from date of installation of the new pipe (192.921(g)).
The provisions of NACE RP0502-2002, which is incorporated into the rule by reference, govern the use of ECDA. The recommended practice does not specify any time limit between step 2, Indirect Inspection, and step 3, Direct Examination. OPS expects that operators would perform direct examinations shortly after completing the indirect inspection step, particularly if any severe indications are identified. Operators must be prepared to justify that any delay between these two steps does not affect the continued validity of the indirect inspection results or represent an imminent threat to pipeline integrity. Also, refer to FAQ-232.
Section 192.905(c) requires that newly-identified HCAs be incorporated into an operator’s baseline assessment plan within one year from the date the area is identified. This requirement applies to operators who previously had no HCAs and thus no IM program. They must develop a program, which includes a baseline assessment plan, within one year to address the new areas (and any that may be identified later).
A documented justification should include technical rationale completely describing the basis or reason for the decision. It is not sufficient simply to re-state the decision without describing why it was made.
Operators are responsible for assuring accurate results. OPS expects that operators will have enough understanding to assure that the process accurately identifies pipeline anomalies and sufficiently assures pipeline integrity. Operators will need to obtain enough information from their vendors to assure that they understand the capabilities and limitations of the vendor’s techniques including the tolerances of tools to be used.
The level of detail in the framework will vary depending on the level of maturity of each program element. In general, OPS expects that elements that must be implemented early will have considerable detail. This includes identification of all high consequence areas, threat identification, and baseline assessment plans. The description in the framework of elements that will be implemented later may be more sketchy. These include a continual process for evaluation and assessment, process for adding preventive and mitigative measures, and plans for confirmatory direct assessment. OPS would expect a reasonably complete description of the elements that relate to managing the IM program, e.g., quality assurance, management of change, and record keeping, although the IM program descriptions of these elements may become more detailed as experience is gained.
OPS would find unacceptable a situation in which a program element was being actively implemented but little or no description of that element is included in the IM framework/program. Program elements should be thought out, documented, and receive the internal approvals the operator considers necessary before they are implemented.
The Baseline Assessment Plan and the Framework both must be prepared by December 17, 2004.
No. Because of the significant diversity in operator integrity management programs and processes, OPS does not believe it is possible to develop a useful template that is broadly applicable across the industry. As long as the basic requirements for these documents as specified in 49 CFR 192, Subpart O, are clearly and completely addressed, an operator is free to use a format for these documents that best supports its internal management and operational needs.
A fully-developed program involves complete documentation of how each element noted above will be performed.
The integrity management rule requires operators to develop and implement an Integrity Management Program. The Integrity Management Program Framework lays the foundation for how the operator intends to develop and implement its program. As described in 192.911, the elements of an integrity management program must include several management, analytical, and operational processes. OPS expects that a number of operators may not have fully developed these aspects of their integrity management programs at this time. OPS also recognizes that making significant, fundamental changes in operator management, analytical, and operational processes and implementing new analytical tools takes time. As such, OPS does not expect operators to have fully mature integrity management programs by the initial deadline (December 17, 2004).
As described in 192.907, OPS expects the integrity management framework to describe how an operator currently addresses each element of an integrity management program, and their plans for how they intend to improve these processes to reach a fully-developed integrity management program. (OPS expects that an operator will have an established process or procedure for any activities that are being implemented). Hence, the framework is a roadmap for developing a full integrity management program, and should include timeframes for completing intended improvements. A fully developed integrity management program would include complete, well-documented, and effectively implemented processes for all integrity management program elements defined in 192.911. During OPS inspections, each operator's performance in implementing its framework will be examined.
Pipeline integrity management programs must meet the requirements of Subpart O. As long as those requirements are met, the programs may be part of broader company management systems. Elements of existing management systems that can meet the requirements of the rule can be incorporated into the pipeline integrity management program. Alternatively, operators may decide that processes and methods used in their pipeline integrity management programs could be useful for other purposes, and may integrate them into broader company systems. OPS expects to see a description of the pipeline integrity management program that meets the requirements of the rule. OPS is willing to consider elements of broader company programs and systems as part of this program description, provided they are sufficiently complete and robust to meet rule requirements. It is the operator’s responsibility to demonstrate how such existing corporate management systems meet the requirements of the rule.
Yes.
Section 192.917(d) requires that "An operator of a plastic transmission pipeline must assess the threats to each covered segment using the information in sections 4 and 5 of ASME B31.8S, and consider any threats unique to the integrity of plastic pipe." (emphasis added). Other sections applicable to plastic pipelines also refer to "covered segments." The operator of a plastic transmission pipeline must identify its "covered segments" to comply with these requirements.
Section 192.903 defines a covered segment as a segment of a transmission line located in a high consequence area (HCA). Section 192.903 further defines an HCA as an area established by one of the two methods described in the definition. The definitions in section 192.903 "apply to this subpart," meaning they apply to all sections of the subpart, including those identified in section 192.901 as applicable to plastic transmission pipeline. Thus, in defining its "covered segments" to comply with the sections applicable to plastic transmission pipeline, an operator of a plastic transmission pipeline must identify those portions of its pipeline that are located in HCA.
The rule does not explicitly address mapping/measurement inaccuracies. Instead, it specifies the use of distances that apply to pipelines, and distances from those pipelines, as they actually exist in the field. The research behind the C-FER equation used to estimate potential impact circles was based on actual measurements of the distances affected by pipeline accidents.
PHMSA recognizes that mapping and measuring technologies involve some level of inaccuracy/tolerance. Operators must take these into account and consider the uncertainties in the distances they measure or infer when evaluating potential impact circles (PICs). Each operator's approach must be technically sound, must account for the uncertainties as they exist in the mapping/measurement methods used by the operator, and must be documented in its IM plan or related procedures. Operators may use a combination of techniques in order to account for these inaccuracies. For instance, aerial photography may be used as an initial screen. Field measurements (such as pipeline locators along with chainage measurements or survey quality range finders) may be used to verify if structures near the edge of the PIC (i.e., within the range of mapping/GIS inaccuracies) are actually inside or outside the PIC. PHMSA will inspect each operator's approach to assure that the operator's process is adequate to identify all covered segments.
Operators need to know the characteristics of HCAs along their pipeline to make decisions required by the integrity management rule. For example, the number/nature of housing units (e.g., large apartment buildings) can affect the consequences of a leak or rupture, and thus affect the relative risk ranking of a segment or decisions regarding preventive and mitigative measures. Section 3.3 of ASME/ANSI B31.8S specifies additional consequence factors to consider, including security of gas supply, public convenience and necessity, and the potential for secondary failures.
No. Growth of a pipeline segment already in the IM program, as a result of growth of the related HCA, does not constitute a newly-identified HCA, and no requirements of the rule applicable to newly-identified HCAs are triggered by such growth. Operators must assure, however, that the pipe newly covered under the IM program is appropriately assessed at the next scheduled assessment for the covered segment. Operators must also consider any unique issues, e.g., relative to preventive and mitigative measures decisions, that may be introduced by including the new pipe as part of the HCA.
Yes, operators may designate an entire segment, or their entire pipeline, as covered by the rule. Operators will still need to gather information about the areas near their pipeline in order to consider differences in the consequences of pipeline accidents as part of their risk assessments and to identify appropriate preventive and mitigative measures.
The rule addresses only pipeline in high consequence areas. Operators may, at their discretion, include in their integrity management programs additional pipeline segments, such as small non-HCA segments separating HCAs that are near each other, since it may be easier to manage assessments over the single, longer length of pipeline. OPS will evaluate compliance with the rule, including its requirement to complete assessment of 50% of covered mileage by December 17, 2007, considering only mileage determined to be in HCAs in accordance with the criteria in the rule.
Under the circumstances described, the MAOP of the line is 1000 psi, governed by the capability of the most limiting component (the old line). Potential impact circles can be calculated using the 1000 psi MAOP. Use of the line at higher pressure would require that the line be uprated, in accordance with Part 192 requirements. The management of change element of the operator's integrity management program should require that HCAs be re-evaluated, using the new MAOP, prior to any such uprate.
Information concerning the derivation of the C-FER equation can be found in Gas Research Institute report GRI-00/0189, A Model for Sizing High Consequence Areas Associated with Natural Gas Pipelines. That document is available in the rulemaking docket at http://dmses.dot.gov/docimages/p56/120467.pdf
If a building or outside area is typically or normally occupied by 20 or more people while in use, then the location is considered an identified site. The rule provides that operators can rely on information from local public officials with emergency response or planning responsibilities to make these determinations. Operators need not consider persons who merely pass through an area, since these persons are considered to be in transit and cannot truly be said to "occupy" the location.
Where parking lots are used for other purposes (e.g., an antique car club that meets on weekends, regular social gatherings), these uses must be considered on their own merits. Identified sites are defined as areas that are occupied by more than 20 persons for specified periods. While it is possible that sufficient people might be in a parking lot near a pipeline resulting in more than 20 persons in proximity to the pipeline at one time, these persons are considered to be in transit and cannot truly be said to "occupy" the parking lot and therefore are not subject to the regulation.
The potential impact circle concept is only applicable for flammable gases. Operators of pipelines carrying non-flammable gases must consider their entire pipelines as if they were in high consequence areas, or they may apply for a waiver to use another method that they may propose for defining HCAs.
No. The definition of an identified site provides for buildings/locations that are "occupied by twenty (20) or more persons". A location that 20 or more people passed through in a day would not be "occupied" by 20 or more persons. Twenty or more persons must be present at one time for the building/outside area/open structure to be defined as an identified site.
Not necessarily. A change in the method for determining HCAs would not, by itself, be considered a substantial change requiring notification under 192.909(b). If the change results in a significant change in the amount of system mileage that is determined to be HCA (e.g., 25% change), a notification should be submitted.
No. An operator with only a limited amount of pipeline can elect to treat its entire pipeline as an HCA and need not determine if potential impact circles contain 20 houses nor locate identified sites.
No. The rule defines identified sites as including "a facility" occupied by persons who are confined, of impaired mobility or would be difficult to evacuate. The rule also provides that operators seek information about these facilities from public safety officials in order to provide a reasonable bound on the efforts that operators must expend to identify such sites. Generally, the focus should be on facilities that are licensed or registered as a care provider, and where multiple disabled individuals would be expected.
Over time, new HCAs may be identified, such as when population distributions change or new sites that are occupied by 20 or more persons are identified. Operators must consider such changes to determine whether new HCAs have been created. A newly-identified HCA must be incorporated into the integrity management program (including the baseline assessment plan) within one year of its identification. A baseline assessment for pipeline segments in newly identified HCAs must be performed within ten years of its identification.
The potential impact radius is an approximation of the extent of immediate damage from a pipeline incident. Damage may extend slightly beyond that radius in some instances. Additionally, structures extending into the radius would very likely burn, and those fires will not be limited to the portion of the structure within the radius. The rule requires that a building containing 20 people for the time periods specified in the rule must be treated as an identified site if any portion of it is within the potential impact radius.
The effects of pipeline incidents are proportional to distance from the pipeline. When an identified site is close to the pipeline, more of the pipeline length is within the radius of potential effects.
Studies of the effect of pipeline ruptures have shown that the area affected is typically elliptical in shape, with the long axis of the ellipse parallel to the pipeline. This is likely caused by the effect of escaping gas jetting along the pipeline right-of-way. The HCA definition extends from the beginning of the first circle to the end of the last (rather than from center-to-center) to account for this effect.
OPS expects an operator to make a good faith effort at establishing contact with public safety officials along portions of its pipeline containing HCAs. The failure of public safety officials to respond along some portions of a pipeline right-of-way should not be a basis for assuming that officials in other locations will not cooperate. If contact cannot be established, the rule requires the use of other sources of information for identification of identified sites. Further explanation of OPS expectations for a good faith effort to discover identified sites can be found in Advisory Bulletin ADB-03-03, dated July 17, 2003, which is available on this web site (http://primis.phmsa.dot.gov/gasimp/) under "key documents".
If an operator uses Method 1 to identify HCAs, then all of its class 3 and 4 pipeline will be HCA and the operator need not separately look for identified sites on that pipeline. The operator would need to consider identified sites on any class 1 or 2 pipeline that the operator also operates.
OPS has engaged in a cooperative program with the National Association of State Fire Marshals (NASFM) to help prepare fire service officials to work with other local safety and planning officials to locate "identified sites." This will include developing tools that can assist NASFM members in understanding issues related to pipeline safety and related emergency response. The program will also include making its results public, so that regulators and the public can see what sites are identified. Fire marshals and other public safety officials are dedicated to protecting the safety of their communities, and OPS expects they will willingly assist pipeline operators. Operators are required to approach these officials, to describe their need to locate facilities meeting the criteria for identified sites, and to elicit their cooperation. In instances in which public safety officials cannot, or will not, cooperate, another mechanism must be used to locate identified sites, as specified in 192.905(b)(2). OPS expects the NPRM on 1162, when it becomes final, will reinforce this process.
The rule does not specify a frequency for updating data used to identify HCAs. Instead, the rule states that operators must complete an evaluation when they have information that the area around a segment not previously identified as an HCA has changed so that it might now be one. Operators are expected to assure that their HCA definitions are current. In an area in which there is rapid growth or change in the use of buildings near the pipeline, that may require frequent updating. In an area where less growth is occurring, updates could occur more infrequently. In any event, OPS would expect that operators would evaluate conditions along their pipelines at least annually to determine if they have changed.
Each commercial and industrial building that is occupied should be considered when determining HCAs. If 20 or more persons occupy a building, it may qualify as an identified site. In buildings with multiple offices/businesses, operators may assume that 20 or more people "occupy" the building 5 days/week and at least 10 weeks/year or they may count the occupants. Commercial buildings that the operator concludes are not occupied by 20 or more people should be considered in counting the number of "buildings" intended for human occupancy. Each structure/office/unit that is occupied in such a building should be counted in the analysis of 20 or more buildings within the impact circle.
No. Section 192.905 requires that an operator use either method (1) or method (2) from the definition in 192.903, not both. If an operator elects to use method (1) on a pipeline segment, then all of the class 3 and 4 areas associated with that segment will be considered HCAs. If, on the other hand, an operator chooses to use method (2) on a pipeline segment, then potential impact circles would be drawn and some areas that are class 3 might not be determined to be HCAs. An operator can select one method to use for its entire pipeline or can apply either method to individual segments of its pipeline.
Operators of pipelines operating below 30% SMYS who use method (2) should recognize that there are some requirements in section 192.935(d) that apply to class 3 and 4 pipelines that are not in HCAs.
All High Consequence Areas (HCAs) must be identified as part of an operator’s initial integrity management framework, which must be completed by December 17, 2004. OPS will expect to see the operator's process for identifying HCAs described in the initial framework. The rule allows operators to use existing data on the density of buildings intended for human occupancy near the pipelines, pro-rating any potential impact circles larger than 660 feet in radius, until December 17, 2006.
The potential impact radius must be calculated along the pipeline using the following formula:
PIR = 0.69 * (p*d2)0.5
Where:
PIR = Potential Impact Radius (in feet)0.69 is a constant applicable to natural gas (constants for other gases must be determined in accordance with Section 3.2 of ASME B31.8S-2001)
Pipeline segments for which the circle defined by the potential impact radius includes 20 or more buildings intended for human occupancy or an identified site are considered high consequence areas.
Alternatively, Operators may treat all class 3 and 4 locations on their pipelines as high consequence areas. If they elect to use this option, the use of potential impact circles is limited to looking for identified sites in any areas of their pipeline which are not class 3 or class 4 or to considering housing density and identified sites in areas where the potential impact circle radius would exceed 660 feet (i.e., for large-diameter, high-pressure pipelines).
Operators can select either method for use on their entire pipeline system, or may use each method only on selected portions of their pipeline.
When associated with a transmission line, an offshore platform must be considered as a possible "identified site". The platform may become an HCA if it is occupied by enough people (including employees of the operator) on a sufficient number of days each year to meet the criteria in the rule.
As used in the rule "covered segment" means a continuous segment of pipeline located in an HCA. If the potential impact circle methodology is used to identify HCAs, then, at a minimum, the covered segment begins at the outermost edge of the first potential impact circle that meets the HCA criteria and extends axially to the outermost edge of the last contiguous potential impact circle that meets the HCA criteria. This length of pipe may be subdivided to facilitate integrity assessments. Examples include such divisions as pressure limiting stations, pipe size changes or other practical divisions.
Yes. An operator is expected to make a reasonable effort to identify sites meeting the criteria for "identified sites". The rule requires that operators consider information they glean from routine operations and maintenance activities along the pipeline and from public officials responsible for safety or emergency response/planning who indicate to the operator that they would know of locations near the pipeline meeting these criteria. If no public officials have such knowledge, then the operator must identify facilities that either: have visible signs; are licensed by a Federal, State, or local government agency; or appear on a list or map available from such an agency. See OPS’s Advisory Bulletin ADB-03-03 dated July 17, 2003, (available on this web site -- http://primis.phmsa.dot.gov/gasimp under "key documents") for additional guidance.
Operators must continually monitor conditions along their pipeline. When they become aware of population or usage changes that create or change an HCA (e.g., population expands to encompass more of the area near the pipeline right-of-way), this information should be factored, at least once per calendar year, into their integrity assessment planning, risk analysis, and consideration of the need for additional preventive and mitigative risk controls.
Yes. While the assessment requirements of 49 CFR 192 Subpart O are applicable to line pipe, all other requirements, including covered segment identification, are applicable to the entire pipeline, which is defined in 49 CFR 192.3 as all parts of those physical facilities through which gas moves in transportation. OPS expects operators to understand which compressor stations and other facilities meet criteria to be treated as covered segments in HCAs.
Section 192.905 requires that information on identified sites be obtained from "public officials with safety or emergency response or planning responsibilities". That section also states that this "could include officials on a local emergency planning commission or relevant Native American tribal officials." The precise titles of the appropriate officials are likely to vary from community to community. They may include the fire chief, or equivalent, or public officials who would be responsible for evacuations in the event of a natural disaster. Each operator is responsible for identifying appropriate public officials. If an operator cannot locate public officials who can provide information about locations meeting the criteria for identified sites, then the operator must use one of the other methods identified in Section 192.905 to locate them. See OPS’ Advisory Bulletin ADB-03-03 dated July 17, 2003, (available on this web site, http://primis.phmsa.dot.gov/gasimp/, under "key documents") for additional guidance.
No. The rule requires that MAOP be used in calculating potential impact circles (PIC) to identify HCAs. Pipelines can operate up to their MAOP, and integrity must be assured for such operation. Operators whose MAOP is significantly higher than their operating pressure could choose to derate their pipeline to reduce the calculated size of PICs. In such a case, subsequent increases in MAOP would be subject to the requirements of Subpart K for uprating and would require that PICs be re-calculated.
Yes. The rule is intended to provide enhanced protection for gatherings of people, and gatherings of operator employees are expected to gain the same enhanced protection. Areas, including buildings and facilities, where operator employees gather in sufficient numbers and on a sufficient number of days to meet criteria in the definition of HCAs should be so classified.
Identified sites are defined as areas that are "occupied" by more than 20 persons for specified periods. While roads and expressways near pipelines could well carry enough traffic that more than 20 persons are in proximity to the pipeline at one time, these travelers can not be said to "occupy" that location. The definition of identified sites is intended to provide additional protection for areas where people stay for more than a few seconds or minutes. Most roads and expressways need not be considered as potential "outside areas" that could qualify as identified sites. Additionally, the preamble recognized that added protection was provided to pipelines near highways with design characteristics commensurate with the pipeline safety regulations.
However, for operators of pipelines that are not designed commensurate with the pipeline safety regulations and are located in areas that are regularly congested, such that traffic stands for many minutes within a potential impact circle, operators should make a determination to include or exclude these pipelines as "identified sites" on their own merits based on the integrated information they have about their pipelines at these locations. OPS expects that such areas will usually occur within developed areas where the pipeline would already be defined as a high consequence area, and that HCAs identified solely due to the proximity of traffic choke points will be rare.
Operators should re-evaluate risk annually. This should include consideration of any new information identified during the annual review of high consequence areas, results of assessments conducted during the year, and any changes to the pipeline system or its operations. Operators should use the results of the updated risk analysis to modify their baseline assessment plans and other IM actions, as appropriate.
No. The four risk assessment approaches described in ASME/ANSI B31.8S are all valid. The approach that is appropriate for an individual operator will often be driven by circumstances specific to that operator, including the size/complexity of their system and the expertise/experience of their personnel. Some operators, particularly those with few miles of transmission pipeline, may conclude that the SME approach is sufficient.
Yes. As part of the information and risk analysis required by 192.917 (b) and (c), an operator is expected to consider all information that can affect the likelihood and consequences of pipeline failure. 192.917 (b) requires that an operator gather and evaluate, as a minimum, the data specified in Appendix A to ASME/ANSI B31.8S. Section A9 of that Appendix addresses weather related and outside force threats, and includes topography, soil conditions, and earthquake faults among the data to be integrated. Thus, if such external risk factors are significant, they must be considered by the operator.
The focus of the integrity management rule is reducing the risk of pipeline failures to high consequence areas. The integrity management programs developed to comply with rule requirements must include the use of risk analysis to support operator integrity decisions. Operator risk analysis processes require the evaluation and measurement of both the probability and consequences of pipeline failures. The appropriate consequences to be included in these risk analyses depend on the decisions that are being supported by the risk analysis results.
In the context of fulfilling requirements of the integrity management rule, operators should maintain a focus on the risk of failures to high consequence areas.
If consequences considered in the risk analysis are expanded to include consequences related to operator business performance, then the operator must provide assurance that this approach does not skew decisions away from protection of HCAs. For example, consideration of operator business performance consequences should not result in pipeline segments with high risk to HCAs being given lower priority for integrity assessments than segments with low risks to HCAs but higher business consequences.
There may be situations in which business impacts have secondary related safety consequences. Operators may include these consequences in the overall assessment of risk related to an integrity decision. It is necessary, however, that such secondary consequences are evaluated and balanced appropriately with other safety consequences in the risk analysis.
Operators whose integrity management programs meet criteria for exceptional performance in 192.913 can implement performance-based programs in which they can establish longer reassessment intervals. One of those criteria is a comprehensive process for risk analysis. OPS expects a thorough risk analysis and integration of other information regarding pipeline integrity to be key elements in establishing longer reassessment intervals under performance-based programs.
As part of a comprehensive risk analysis required by 192.917 (c), OPS expects operators to determine the risk associated with third party damage to pipeline segments that could affect an HCA. Operators must follow section 5 of ASME/ANSI B31.8S, which contains guidance on risk assessments. OPS will not prescribe specific risk analysis methods that the operator must use. OPS also understands that outside force damage prevention is challenging because it involves factors outside of the operator’s control. Nonetheless, there are a number of actions operators can take to reduce the likelihood of third party damage. If a pipeline segment is in an HCA, and third party damage is determined to be a significant risk (e.g., as might be expected in a high population area, with new construction near the line), the operator must implement the comprehensive additional preventive measures in 192.935.
Many of the elements of an IM program required by the rule depend on the results of data integration and risk analysis. For example, the baseline assessment plan must include a schedule based, in part, on risk factors. The operator's initial risk analysis should be performed early in IM program implementation, before the baseline assessment plan is finalized.
Section 192.917(e)(3) requires that operators consider the five years preceding identification of a high consequence area to determine a maximum operating pressure that will assure the stability of manufacturing and construction (M&C) threats. As long as operation does not involve pressures higher than the highest operating pressure experienced during those five years, any M&C threats can be considered stable. (The "preceding five years" referred to in sub-paragraph 192.917(e)(3)(i) is the same five years preceding HCA identification.)
Operators should note that section 192.917(e)(3) specify that "the analysis must consider the results of prior assessments on the covered segment." This includes any prior hydrostatic tests, including tests conducted after the pipe was installed. OPS considers that a hydrostatic test, meeting subpart J requirements, is sufficient to demonstrate that any manufacturing and construction defects will remain stable at the operating pressures related to that test. Operators need not consider the operating pressure in the five years preceding HCA identification for segments that have passed a Subpart J hydrostatic test.
Data integration is an important concept in the IM rule. In principle, this is an action that will help assure that operators learn about their pipelines the things that data from disparate activities can tell them. An example is provided in ASME/ANSI B31.8S:
An operator suspects that a possible corrosion problem exists on a large diameter pipeline located in a populated area. However, a CIS indicates good cathodic protection coverage in the area. A Direct Current Voltage Gradient (DCVG) coating condition inspection is performed and reveals that the welds were tape-coated and are in poor condition. The CIS results did not indicate a potential integrity issue but data integration prevented incorrect conclusions.
The analytical process considering the synergistic effect of multiple and/or independent facts or data constitutes data integration.
Data aggregation is a first step. Often, data that is generated about the pipeline from routine activities has not been seen by other groups within the company. Data aggregation should bring together all relevant information so that it can be better evaluated in context with available data. However, data aggregation, by itself, is not sufficient. Operators must also evaluate the aggregated data to look for problems that might not have been identified absent such an evaluation. There is no single means of performing this evaluation. GIS systems can be significant aids in performing data integration, but use of these systems is not required. The models used for risk analyses required by the rule can also be a valuable tool for performing data integration. In some cases, use of subject matter experts (SME) may be sufficient. An operator needs to consider the types of data available and the relative complexity of their pipeline system and its environment and then develop and implement processes for data integration that are appropriate for its particular circumstances.
Operators should use the best information that they have available in performing the data integration and analysis associated with integrity management and must assure the quality of information used. Information of this nature would be subject to review during integrity management inspections.
Yes. Section 192.917(b) requires that operators gather and integrate existing data "on the entire pipeline" that could be relevant to covered segments as part of performing their risk assessment. Data from non-covered segments must be considered in this process. Non-covered pipeline has generally been subject to the same operational and maintenance practices, corrosion control, etc., and experience on it is relevant to the likelihood of problems in covered segments. Operators generally need not conduct excavations, perform new analyses, etc. to generate information, but must consider data that already exists. The initial data gathering process is likely to highlight weaknesses in the existing data, however. OPS expects that operators will identify these weaknesses and will modify O&M procedures, as appropriate, to improve the process for gathering new data during future opportunities (e.g., when pipe is exposed). In this manner, OPS expects that the data on which operators base their IM programs will improve over time, and that the risk analyses and data integration that are part of the program will similarly improve.
The risk posed by each pipeline segment covered by this rule must be considered in scheduling baseline assessments and periodic re-assessments. Risks must be evaluated using a risk assessment that meets ASME/ANSI B31.8S, Section 5, as required by 192.917(c). Section 5.10 of the standard specifically addresses use of risk assessment for prioritizing pipe segments for assessment.
ASME/ANSI B31.8S defines "subject matter experts" as "individuals that have expertise in a specific area of operation or engineering." Section 192.915 requires that an operator’s IM program provide criteria for qualifications. Each operator is responsible for assuring that the individuals it may rely on as SMEs have an appropriate level of expertise and experience to fulfill their function. Operators should document the qualification of their SMEs. OPS inspections may include examination of the qualification of SMEs.
The rule requires that operators evaluate the risk posed by their covered segments, identifying those that pose the highest risk. The situations in which the rule requires that a covered segment be treated as a high-risk segment are those that experience has shown to be significant contributors to pipeline risk. OPS expects these segments to be given special consideration in developing an assessment schedule.
When conducting integrity management inspections, OPS expects to review a risk ranking of all HCA segments as part of the Baseline Assessment Plan review. An operator must have a process that is consistently and uniformly applied across all of its covered segments, considers all factors that affect the likelihood and consequences of pipeline failure, and that produces a risk ranking of HCA pipeline segments. This same process can also be applied to other pipeline segments outside of HCAs.
The rule requires that an operator must use risk assessment to prioritize covered segments for baseline assessments and reassessments (192.917(c)). OPS expects to see a ranking by covered segment.
Operators will need to manage their assessments, and some aggregate indication of risk, by piggable section, could be useful in that regard. Such aggregation can mask important information, however. For example, a number of low-risk covered segments in a piggable section could result in that section being determined to be of moderate risk even though it contains the highest risk covered segment in an operator's program. Operators need to know the relative risk of individual covered segments so that they can appropriately plan their assessment activities.
In addition, other interacting threats could adversely affect the stability of residual manufacturing and construction defects. An operator is expected to conduct its threat identification analysis in sufficient detail to identify if other interacting threats could adversely affect the stability of residual manufacturing and construction defects, as required by ASME B31.8S, Section 2.2, and establish its assessment plans accordingly.
Assessments for manufacturing and construction defects generally are not required for pipe that has successfully passed a Subpart J pressure test even if these changes in operating conditions occur. (See FAQ-219.)
The rule specifies that any pressure increase, regardless of amount, will require that the segment be prioritized as high risk for integrity assessment.
OPS considers a successful Subpart J pressure test to be sufficient to reveal any manufacturing and construction defects that could jeopardize pipeline integrity at operating pressures less than or equal to MAOP, as of the date of the pressure test. Any manufacturing and construction defects that survive the Subpart J pressure test are considered to be stable and not subject to failure, unless other threats adversely affect the stability of the residual manufacturing and construction defects. An operator is expected to conduct its threat identification analysis in sufficient detail to identify if other interacting threats could adversely affect the stability of residual manufacturing and construction defects, as required by ASME B31.8S, Section 2.2, and establish its assessment plans accordingly.
Assessments addressing the threat of manufacturing and construction defects are required for pipe that has never been tested to Subpart J requirements if operating conditions on the line change. (See FAQ-220)
Internal inspection, pressure testing, and direct assessment are acceptable methods to assess pipeline integrity (192.921(a), 192.937(c)). However, the method(s) selected must be appropriate to address the identified threats to the line being assessed. (Thus, for example, direct assessment can only be used where the threats are external or internal corrosion or stress corrosion cracking). Confirmatory direct assessment can be used for assessments conducted on no longer than seven-year intervals when re-assessments conducted using these specified methods are scheduled to occur at intervals longer than 7 years, and when the threats of concern are corrosion. Other technologies that an operator can demonstrate provide an equivalent understanding of pipe condition may be acceptable methods. However, operators must inform OPS 180 days before conducting an assessment using other technologies.
The integrity management rule requires that pressure tests be conducted according to the requirements of 49 CFR Part 192, Subpart J (192.921(a)(2), 192.937(c)(2)). This test uses a medium of liquid, air, natural gas, or inert gas to raise the pressure inside a pipe to a prescribed level for a prescribed length of time. (An operator must use test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S to justify an extended reassessment interval in accordance with 192.939. See FAQ 207).
Yes, operators can aggregate ECDA regions if they have similar characteristics (See NACE RP-0502-2002, Section 3.5.1.2).
The NACE standard describes complementary as: "the strengths of one tool compensate for the limitations of another." Generally, an operator should endeavor to use tools based on different technologies.
Operators must follow ASME/ANSI B31.8S, section 6.2 in selecting the appropriate internal inspection tool. Any tool(s) used must be appropriate to detect anomalies associated with threats identified for the line being assessed. OPS expects operators to evaluate the segment specific risks associated with each portion of the line that could affect an HCA and determine the appropriate assessment technology or combination of technologies to confirm whether or not those specific threats are present.
For purposes of satisfying the progress requirements, operators must use the cumulative mileage of covered segments. Operators should not use the total miles assessed in making a determination of whether the 50% criteria has been satisfied
Operators are expected to review the results of integrity assessments promptly. Operators are required to obtain sufficient information to identify conditions that present a potential threat to the integrity of the pipeline no more than 180 days after an integrity assessment, unless the operator can demonstrate that it is impracticable to obtain the information within this limit.
All baseline integrity assessments must be completed by December 17, 2012. Assessments for 50% of the pipeline mileage in HCAs must be completed by December 17, 2007. The highest risk segments should be prioritized for early assessment.
The date on which an assessment is considered complete will be the date on which final field activities related to that assessment are performed, not including repair activities for in-line inspection tool runs and direct assessments. This would be when a hydrostatic test is completed, when the last in-line inspection tool run of a scheduled series of tool runs is performed, when the last direct examination associated with direct assessment is made or the date on which field activities associated with "other technology" for which an operator has provided timely notification are conducted. Evaluation of the assessment results, integration of other information, and repair of anomalies must still be performed in accordance with the requirements established for these activities in the rule. These activities are considered to occur after the completion of the "assessment".
In those rare instances in which only a partial assessment is performed (e.g., in-line inspection system loss of power results in loss of data near the end of a pig run) operators will be expected to evaluate the results that were obtained within 180 days of the early termination, in accordance with 192.933(b). If however, the quality of the partial data is suspect and an entire rerun is to be performed, then the evaluation will be expected within 180 days after the successful rerun.
Yes. The rule requires (192.921(e)) that an assessment conducted prior to December 17, 2002, must meet the baseline requirements in Subpart O if it is to be used as a baseline assessment. A key element of those requirements is that the assessment method be based on the threats faced. Section 192.921(a) requires that an operator must select the method, or methods, that are best suited to address the identified threats.
Any pressure test that meets or exceeds the requirements of Subpart J will satisfy the integrity management rule.
Yes. The rule requires that operators prioritize covered pipeline segments for baseline assessment based on risk. Thus, the schedule in the Baseline Assessment Plan generally should show that the highest risk segments are scheduled for assessment prior to the lower risk segments. However, this does not preclude an operator from using a prior assessment for a baseline, even if the segment(s) covered by that assessment later turn out to be relatively lower risk.
The rule requires that baseline assessments must be completed on at least 50 percent of the covered segments by December 17, 2007, and that assessments be prioritized based on risk. Although OPS expects operators to concentrate on the highest risk pipe, some segments not among the highest risk pipe may be counted towards the 50 percent requirement. OPS recognizes that practical issues associated with scheduling and conducting assessments may lead to some lower risk pipe being assessed prior to high-risk pipe. For example, during an in-line inspection to address a high risk segment, an operator may also assess another lower risk segment that happens to be located in the same section of pipe that is being inspected. This additional segment may be credited against the December 17, 2007, deadline. OPS inspections will review how an operator has prioritized segments for assessment to assure that appropriate emphasis is being placed on the highest-risk pipe.
Pressure reduction is not an assesment method. Although a pressure reduction can provide an equivalent margin to failure as a pressure test, a pressure reduction provides no information about the condition of the pipeline. One of the primary objectives of this rule is for operators to obtain a better understanding of the condition of their pipe so they can make well-founded technical decisions to reduce risk and protect HCAs. Section 192.933(a) specifies that a reduction in operating pressure taken to provide an immediate improvement in safety cannot extend more than 365 days without the operator providing a technical justification that continued pressure restriction will not jeopardize the integrity of the pipeline.
The Baseline Assessment Plan must be modified whenever there are changes to the pipeline in HCAs. For example, if an operator identifies a new HCA through monitoring its right-of-way or through its process for identification and assessment of newly-identified HCAs [as required by 192.911(p)], this newly identified pipeline segment must be included in the Plan. Pipeline segments in newly-identified HCAs must be included in the Baseline Assessment Plan within one year after their identification. These pipeline segments must be assessed within ten years of their identification.
The Baseline Assessment Plan can also be modified if the operator gains knowledge from the initial (baseline) assessments or from its risk assessments that leads to a change in inspection priorities, assessment methods, or other improvements to its program. The operator must document all Plan modifications and the reason(s) for the changes. This documentation must be available for OPS review during an inspection.
An operator with multiple operating companies could have one plan for each operating company or separate legal entity or a single plan covering all operating companies. Each Baseline Assessment Plan must meet the requirements of 192.919 and address all covered pipeline segments for the pipelines covered by the Plan.
Operators must comply with federal and, when applicable, state pipeline safety requirements. The 50% requirement in the federal integrity management program regulation applies to all pipeline systems that are covered under the rule - interstate and intrastate. Thus, an operator may develop a single Baseline Assessment Plan that covers both intrastate and interstate pipelines. An operator is to rank, assess and remediate its system as a whole, thus assuring that the highest risk-ranked HCAs will be addressed first, regardless of whether they are on interstate or intrastate segments of the system. Inspections for intrastate piping will be done by state agencies (if they are a certified to do so by OPS). To facilitate OPS and state pipeline safety program inspections, it is desirable that an operator s plan delineate which line segments are intrastate and which are interstate. This information will help to focus inspection activities by states and OPS to appropriate pipe segments.
OPS expects to see a viable, active planning and scheduling process that is likely to result in assessments being performed in the relative sequence identified by risk assessment. OPS will review an operator’s process for managing its baseline assessment schedule. The degree of specificity of assessment schedules will vary depending on how far in the future assessments are planned.
No. Intervals for full assessments must be established per the requirements in 192.939. Maximum reassessment intervals vary with pipeline stress level as presented in the table in that section, but shorter intervals may be required if indicated by the operator’s risk analysis. If an interval of longer than seven years is established, then some assessment must be performed no less frequently than every seven years. Confirmatory direct assessment, alone, is sufficient to fulfill this requirement.
ICDA is based on the use of a model to predict areas within which internal corrosion is most likely to occur. Once identified, those areas must be examined to determine if corrosion exists. (The number and required location of examinations differs depending on the circumstances of the assessment).
There are a number of ways in which operators can be more restrictive during first time use of ECDA. Operators must apply more restrictive criteria in each phase of ECDA (i.e., pre-assessment, indirect examination and direct examination). Examples of more restrictive criteria that could be used include but are not limited to:
Pre-assessmentThe specific considerations in determining the feasibility of ECDA, ICDA, and SCCDA will differ, since the methods themselves differ. In any case, PHMSA expects an operator's IM plan to include a written process integrating the information available about the pipeline to demonstrate its conditions/characteristics are consistent with assumptions made in each of the DA methods. The plan is also expected to provide mechanisms to maintain the associated documentation to record the basis upon which the operator concluded that each selected DA method is feasible.
For ECDA, this should include determining the practicality of using two complementary indirect examination tools, assembling information about the pipeline (including coating condition and cathodic protection experience) necessary to define Regions, and identifying areas where indirect tools may not provide accurate readings and determining how those areas will be handled. This also includes all documentation associated with verification that the indirect examination tools will accurately assess the pipeline based upon local pipeline conditions and characteristics.
For ICDA, this should include a review of operating history of the line to demonstrate that conditions have been suitable for application of the methodology. Note that ICDA cannot be used for systems that have previously carried wet gas (see FAQ 126).
For SCCDA, this should include determining that the information necessary to use the method (see FAQ 223) is available.
The rule requires that conditions presenting a potential threat to pipeline integrity be discovered as soon as the operator has enough information to do so [See 192.933(b)]. The rule also establishes a maximum time limit of 180 days after completion of the assessment to "discover" a condition presenting a potential threat to pipeline integrity. In the case of ECDA, the assessment is considered complete when the last Direct Examination is completed (Refer to FAQ-34 and FAQ-58). However, because the direct examination provides the operator with specific, quantitative information about conditions presenting a potential threat to pipeline integrity, "discovery" must be declared immediately upon completion of the direct examination. Therefore, for ECDA, the 180-day time limit to declare "discovery" of a condition potentially affecting the integrity of the pipeline identified during a direct examination is moot. (If an operator encounters unusual circumstances which indicate the need to delay declaration of "discovery" until significantly after completion of the direct examination, those circumstances, along with the action plan to obtain enough additional information to determine if a condition presenting a potential threat to the integrity of the pipeline has been "discovered," must be documented.)
Another consideration for ECDA is the time that is required to conduct the direct examinations after the completion of the indirect inspection step. Although both the rule and NACE RP0502-2002 are silent on this timeframe, OPS would expect that direct examinations be completed within a reasonable period of time after the completion of the indirect inspection step. OPS understands the operator needs flexibility to deal with seasonal restrictions, weather, permitting, supply interruptions, and other issues that impact scheduling direct examinations and repairs. However, OPS expects operators to be able to demonstrate continuing progress toward completion of the direct examinations. If an operator experiences delays interrupting continuing progress, OPS would expect an operator to document the reasons for the delays and take additional precautions, if necessary, to assure pipeline integrity until the direct examinations can be accomplished. OPS will review documentation related to the above issues during integrity management inspections to verify that the operator had a reasonable basis for delaying continuing progress and that as a result pipeline integrity was not threatened.
In addition, operators should note that the assessment is not completed until the last required direct examination is completed (again refer to FAQ-34 and FAQ-58). Operators that delay completion of all direct examinations past the due date for completing the assessment may be out of compliance with assessment schedule requirements.
No. The rule addresses the threat of third party damage in two ways. First, the threat of a future third party damage event is expected to be present in covered segments. Therefore, prevention of future events is addressed under the requirements for preventive and mitigative actions.
Second, if, as part of a baseline assessment or reassessment, the operator has gathered data from an ECDA or internal inspection tool survey, then he must take further action to look for third party damage events that did not result in immediate failure, but may have resulted in residual damage that could fail in the future. The rule requires that the data gathered as a result of the ECDA or internal inspection tool surveys be integrated with data relevant to third party activity, such as encroachments or foreign line crossings. Areas in which anomalies from an internal inspection or ECDA survey align with such possible indicators of third party activity provide potential indications of residual third party damage in the covered segment.
The operator must have defined procedures in its integrity management program addressing how it will respond when the data integration activities provide a potential indication of residual third party damage in a covered segment. Where data integration suggests potential damage to the pipeline exists, the procedures should include a local excavation and direct examination of the pipeline, including (as necessary) NDE of the pipeline to identify or characterize damage. Since the threat of residual third party damage is the result of a localized, time independent event, operator procedures will require responses where the data integration suggests evidence of a residual third party defect, and would not necessarily require a response for the entire covered segment. However, data gathered from the evaluation of previous residual third party defects should be considered when evaluating data for the entire covered segment and the need for additional surveys and actions taken to assure the integrity of the covered segment.
Section 192.929(b)(1) requires that operators planning to use SCCDA must gather and evaluate "data related to SCC at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME/ANSI B31.8S, appendix A3...indicate the potential for SCC." This is because information from actual examinations of pipe in service are the most reliable indicator of problems and are the key data relied upon in the SCCDA method. Operators may not have heretofore gathered such information.
NACE International has recently published recommended practice RP0204-2004. While OPS has not yet reviewed this recommended practice for possible incorporation into the integrity management rules, it does provide current guidance concerning stress corrosion cracking and the use of DA processes in its assessment.
Operators who find they are subject to the threat of SCC, and who intend to use SCCDA to conduct assessments, should revise their O&M procedures to assure that relevant data is collected that will allow the SCCDA process to be used. Data collected should include magnetic particle NDE, which is vital to detecting stress corrosion cracking, as well as data on soil conditions, coating condition, etc.
Operators should note that the criteria for susceptible segments in ASME/ANSI B31.8S, Appendix A, Section 3.3 (a)-(e) relate to classical, high-pH SCC. These same factors, except for those relating to temperature [factors (b) and (c)], should be referred to regarding the susceptibility of near-neutral SCC as specified in the NACE recommended practice RP0204-2004.
At this time, use of DA for near-neutral SCC is considered "other technology" and operators must notify OPS at least 180 days before conducting an assessment using such a method. This could change if OPS adopts the new recommended practice, but rulemaking will be required to do so.
Historical conditions must be considered. The ICDA process is designed to identify areas where internal corrosion may have occurred, largely due to the fact that an electrolyte is/was present. Direct examinations are then conducted in those areas to determine whether internal corrosion has, in fact, occurred. The fact that an electrolyte is not present under current operating conditions may not mean that internal corrosion does not exist if electrolytes were introduced under previous operating conditions. For at least the first application of ICDA, then, considering historical conditions could be important. Of course, other information that confirms a lack of internal corrosion in areas where electrolyte could have been present historically (e.g., in-line inspection results, results of pipe replacement/examination) could alleviate the need to consider historical conditions. Operators should assure that there has been an opportunity to detect internal corrosion that may have occurred in the past, or should look for it during their initial ICDA.
No. There is no specific limit on when an operator must reassess in these circumstances. Invalid results, however, can call into question whether an assessment was actually completed. Thus, operators may want to perform reassessment before the original reassessment interval expires, if still possible. In any event, OPS would expect operators to respond in a time frame that is commensurate with the importance of the potential problem that is identified.
No. If guided wave UT is used as one of the complementary tools for indirect inspections as part of ECDA, it would not be considered other technology. NACE RP0502-2002 lists some indirect inspection tools, but notes that they are not the only tools that can be used. Rather, they are representative examples. "Other indirect inspection methods can and should be used as required by the unique situations along a pipeline or as new technologies are developed. [The operator must] assess the capabilities of any method independently before using it in an ECDA program" (3.4.3.1). Use of guided wave technology, alone, as an examination method or as an alternative to excavating pipeline to conduct a direct examination would be considered "other technology" and would require notification prior to use.
This provision, and provisions in NACE RP0502-2002 requiring additional actions "when ECDA is applied for the first time" apply to the first application of ECDA in each Region containing covered segment(s).
No. These are indirect measurement techniques that can be used in ECDA. If used in that context, and in conformance with NACE RP0502-2002, these techniques would not represent "other technology". OPS would not find them acceptable as assessment methods if used alone, outside the context of ECDA.
The categories of "severe", "moderate", or "minor" refer to the severity of indications (see Section 4.3 of NACE RP0502-2002). Each operator is responsible for determining these severities during the indirect inspection step.
"Immediate", "scheduled", or "monitored" refer to the priority for excavation (see Section 5.2 of NACE RP0502-2002). After each indication has been categorized according to its severity, the operator is responsible for determining the urgency (prioritization) of excavation of indications for direct examination (see 192.925(b)(2)(iii)).
Identified defects then must be scheduled for remediation (see 192.933(c)), or classified as "immediate", "one-year", and "monitored" repair conditions (see 192.933(d)). This classification must be done once the operator has sufficient information to "discover" remediable defects.
Assessment methods must be identified, and demonstrated to be capable of addressing applicable threats, before an assessment is conducted. At the same time, OPS recognizes that last-minute problems arise and that plans must often change as a result. It is acceptable for operators to change their assessment plans due to unexpected situations, but the reasons for the change and the acceptability of a changed assessment method should be documented when the change is made, prior to implementing the assessment.
The ICDA process is designed to locate portions of the pipeline in which electrolyte may be present (and corrosion may therefore be occuring) and to examine those areas to identify any degradation. The process is not applicable to wet gas systems, because electrolyte is present throughout and the ICDA screening process can not work.
Pipeline systems that formerly carried wet gas could potentially have suffered internal corrosion at any location. Application of ICDA, alone, may not identify such degradation, since it focuses on areas where electrolyte may be present under current conditions. Therefore, ICDA cannot be used as an assessment method for a pipeline system that formerly carried wet gas, unless a plan is developed as required by 192.927(b). An assessment conducted subsequent to conversion that would have found any significant areas of internal corrosion degradation and caused their remediation would support the acceptability of ICDA. Results from such an assessment should be considered in integrating data concerning pipeline condition.
Direct assessment is an acceptable assessment method. Like all assessment methods, however, it can only be used in situations for which it is applicable. DA is not applicable for all threats. In addition, there are circumstances (described in NACE-RP0502-2002) under which DA cannot be used. Operators will be expected to be able to demonstrate that DA, and any other assessment method, is applicable for the threats and circumstances associated with IM assessments for which it is used.
NACE is developing a standard for internal corrosion direct assessment (ICDA). OPS will consider incorporating that standard into the rule once it is approved. In the meantime, the rule, itself, includes requirements for ICDA that are consistent with drafts of the standard under development. Operators must follow the requirements in the rule and in ASME/ANSI B31.8S, Section 6.4 and Appendix B2 (referenced in the rule). Operators also must use the model in GRI 02-0057, "Internal Corrosion Direct Assessment of Gas Transmission Pipelines – Methodology" to identify ICDA regions (see 192.927(c)(2)). Operators must develop their own procedures based on the requirements in the rule and the referenced standard, and can also use the draft NACE standard as guidance.
No. The mere absence of records is not sufficient to demonstrate that an event involving intrusion of water or electrolytes did not occur. An operator must review all available information, including available records, to provide reasonable assurance that water or electrolytes have not been present. Where an operator relies, in part, on lack of records showing such information, an operator should be able to demonstrate that its record-keeping practices make it likely that any intrusion, if one had occurred, would have been recorded. Historical operating records such as drip records and gas quality records may help support a conclusion that a pipeline section has not contained electrolytes
Yes. The rule requires that operators using SCCDA systematically gather and analyze excavation data for pipe at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME/ANSI B31.8S, appendix A3.3 indicate the potential for SCC (192.929(b)(1)). Relevant data from pipe not in covered segments must be considered in this process. Additional guidance concerning stress corrosion cracking can be found in Advisory Bulletin ADB-03-05, issued October 8, 2003 (68 FR 58166).
Operators can use indirect assessment tools not listed in NACE RP0502-2002, in accordance with Section 3.4.3.1 of the NACE RP, which states "...Other indirect inspection methods can and should be used as required by the unique situations along a pipeline or as new technologies are developed." Operators using tools not listed in the NACE standard "must demonstrate their applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method" (192.925(b)(1)(ii)).
No. The rule specifies that CDA can only be used for external and internal corrosion (192.931(a)).
The rule requires (192.923(b)) that an operator’s plan for using direct assessment as a primary assessment method must comply with ASME/ANSI B31.8S, Section 6.4 (and Appendices B2 and A3 for internal corrosion and stress corrosion cracking, respectively) and NACE RP0502-2002. To comply with both standards, an operator must fulfill the more restrictive requirements. Indirect examinations with both complimentary tools must thus be made over the entire length of an ECDA region.
This requirement refers to the determination and evaluation of ICDA Regions and whether they impact covered segments. Where covered segments are present, the "entire pipeline" would encompass pipeline from each location where liquid may first enter the pipeline upstream of the covered segment to the furthest downstream point where internal corrosion might have occurred (even if this point is downstream of the covered segment). The term analysis in this context means the three steps of the ICDA process: (1) pre-assessment, (2) ICDA region identification, and (3) identification of locations for excavation and direct examination.
Yes. The ICDA process described in NACE RP-0502-2002 is for dry-gas systems. The rule requires that operators who plan to use ICDA for systems transporting gas containing an electrolyte develop a plan (192.927(b)). Such use of ICDA is considered "other technology". Operators must submit notification of their planned use of this technology at least 180 days before the assessment is scheduled. Operators are encouraged to submit notifications as early as they can.
No. The notification required in 192.925(b)(3)(iii) refers to assuring that company, and contractor, personnel involved in planning and performing ECDA are aware of changes in the ECDA plan. OPS need not be notified unless the changes substantially affect the total IM program's implementation or significantly modify an operator's overall IM program or the schedule for carrying out program elements (192.909(b)). Changes in the plans to conduct ECDA direct assessments on specific covered segments would not meet this threshold.
If an operator can demonstrate that a covered segment is not susceptible to the threat of internal corrosion, then no assessment method need be applied to assess this threat. An operator must identify threats to its pipeline based on data integration and risk analysis (192.917). Operators must also apply one or more assessment methods, "depending on the threats to which the covered segment is susceptible" (192.921(a)).
In areas where the language of the rule conflicts with the AMSE standard, the rule requirements shall take precedence. In this case, the pressure tests must satisfy the requirements of subpart J.
Assessments of some kind must be performed at intervals no longer than seven years. Assessments for all threats must be performed using in-line inspection, pressure testing, direct assessment, or "other technology" within the maximum intervals specified in 192.939, which vary based on operating stress levels. (Operators whose integrity management programs satisfy the criteria for "exceptional performance" in 192.913 can establish longer intervals for these assessments, based on their risk assessments). Seven-year assessments conducted within those maximum intervals (if the maximum interval exceeds 7 years) can be performed using confirmatory direct assessment or, for low-pressure pipelines, the methods specified in 192.941.
All baseline assessments must be completed by December 17, 2012, ten years after the enactment of the Pipeline Safety Improvement Act of 2002. Re-assessment intervals must be established for each covered segment and some form of assessment (i.e., full reassessment, confirmatory direct assessment, or low-pressure reassessment) must be performed within seven years after the baseline assessment for that segment is completed (or less if the operator’s risk evaluation determines that a shorter interval is needed to assure pipeline integrity). Thus, some re-assessments will be required before all baseline assessments are completed if operators use the entire ten-year period to perform baseline assessments.
For example, a HCA pipeline segment that was assessed (baseline) in 2004 will require re-assessment no later than 2011.
PHMSA can grant waivers from the reassessment intervals specified in 192.939 in instances in which appropriate inspection tools are not available or where conducting an assessment would imperil gas supply. Operators must apply for such waivers at least 180 days before the end of the reassessment interval, unless local gas supply issues make this impractical. Operators whose integrity management programs meet criteria for exceptional performance in 192.913 can implement performance-based programs in which they can establish longer reassessment intervals based on their own risk analyses, except that reassessment by some method must be carried out at an interval no greater than seven years (see 192.913(c) and FAQ-133).
Section 192.939(a)(1) specifies requirements for establishing reassessment intervals. Two options are allowed: basing the interval on identified threats, assessment results, data integration, and risk analysis or using the intervals specified in Table 3 of ASME/ANSI B31.8S. An operator using the former option (192.939(a)(1)(i)) could establish intervals longer than those in Table 3. The intervals that can be established by either method are limited to the maximum intervals in the Table in 192.939.
Pressure tests used as IM assessments must meet the requirements of Subpart J, including required test pressures. Higher test pressures must be used to justify extended reassessment intervals (192.937(c)(2)). As used here "extended reassessment intervals" refers to any interval longer than seven years as required by 192.937(a) and 192.939(a) and (b).
Operators conducting assessments by pressure testing and who use test pressures meeting Subpart J requirements may establish a reassessment interval of seven years, unless their analysis under 192.939(a)(i) indicates a need for a shorter interval. This is true even if Table 3 would lead to a shorter interval.
Operators who use Table 3 test pressures may establish reassessment intervals in accordance with Table 3 up to the maximums listed in the table in 192.939, again unless their analysis under 192.939(a)(i) indicates a need for a shorter interval. Operators who establish intervals longer than seven years must conduct a confirmatory direct assessment within the seven-year period. (For segments operating at less than 30% SMYS, a low-stress reassessment per 192.941 may be conducted in lieu of CDA – see 192.939(b)(1)).
Operators may use straight-line interpolation to determine acceptable intervals between the 5, 10, 15, and 20 year intervals listed in Table 3. In no case must operators reassess more frequently than once every seven years unless such frequent reassessments are determined necessary by risk assessment.
All covered segments must be assessed at least every 7 years. For pipelines operating below 30% SMYS, confirmatory direct assessment (CDA) or low-pressure reassessment (per 192.941) are available options for performing these assessments. It is up to each operator to select the assessment method appropriate for each covered segment.
No. CDA is an interim measure, intended to provide for assessments at the minimum frequency specified in the Pipeline Safety Improvement Act of 2002. It provides assurance that significant unknown degradation is not occurring, but does not provide a knowledge of pipe condition equal to that which would be obtained from one of the other specified methods. A successful CDA allows operation for the remainder of the assessment interval (or until the next CDA in the case of low-pressure pipeline on 20-year interval and for which the interval has more than 7 years to run) but it does not allow that interval to be extended.
Provisions applicable to pipelines operating below 30% SMYS apply to pipelines for which the MAOP is less than 30% SMYS. Increasing operating pressure to greater than 30% SMYS would require uprating pursuant to Subpart K. For integrity management purposes, the requirements applicable to each covered pipeline segment must be met at all times. Some requirements vary depending on pipe stress level. There is no grace period allowed to come back into compliance if stress levels are changed. Operators planning to increase stress levels to >30% SMYS must determine, as part of planning for that increase, whether additional actions need to be taken to be in compliance with integrity management requirements. If an assessment has not been performed in over 15 years, the maximum interval allowed for pipelines between 30 and 50% SMYS under 192.939, then an assessment would need to be conducted before the pressure increase is implemented. (Note that similar considerations are required for pressure changes that would increase stress levels to above 50% SMYS).
OPS does not envision changes or exceptions to the required reassessment intervals. Section 192.913 describes the criteria by which an operator demonstrating exceptional performance can qualify for performance-based approach. Such an approach is available to operators with mature integrity management programs who have conducted at least 2 assessments on covered segments that they intend to include in the performance-based approach. Operators implementing a performance-based approach can deviate from the inspection intervals specified in the rule, as provided in 192.913(c).
Re-assessments must be conducted within the specified number of actual years. For example, a pipe segment assessed on March 23, 2004 must be re-assessed before March 23, 2011, using at least confirmatory direct assessment. This segment would need to be re-assessed using one of the methods specified in the rule before March 23, 2014, March 23, 2019 or March 23, 2024, depending on its operating stress (see192.939).
Yes. Operators are required to integrate relevant information on the condition of the pipeline in making decisions on excavation timing and other mitigative actions. Tool accuracy should be considered as part of the data integration process.
Accounting for tool accuracy is most important for immediate repair anomalies. Immediate repair conditions may not be discovered (because the ILI tool "undercalled" the defect), even if the tool functioned within its published accuracy specifications, if tool accuracy is not considered. Information on tool accuracy should be used to assure that defects requiring early excavation and mitigative action are properly identified and characterized. This does not necessarily mean simply adding the vendor-supplied accuracy specification to reported depth of metal loss indications. Several sources of data may be used, in conjunction with vendor-supplied tool specifications, to characterize pipeline defects. These include results of previous excavations, confirmation digs, results of concurrent inspections, and comparison to prior inspections. Uncertainties in this data should also be considered.
In addition, information on tool accuracy may be incorporated in engineering analysis such as "probability of exceedance" to help operators prepare a comprehensive defect remediation plan and schedule future assessments. Pipeline operators have the flexibility to apply processes specific to their unique risks by utilizing these techniques when evaluating specific pipeline defects.
Tool accuracy specifications are not the only uncertainty associated with assessment results, and are therefore not the only factor to be considered in evaluating the quality of internal inspection data and in making excavation timing and mitigation decisions. Defect characterization should consider all relevant uncertainties to assure that defects posing a potential integrity threat, including those meeting the criteria in 192.933, are promptly identified. The operator must document its approach for dealing with ILI accuracy and uncertainty per 192.947(d).
Yes. This requirement appears in Section 7 of ASME/ANSI B31.8S, which is specifically referenced in 192.933(d)(1), and thus becomes part of the rule. It applies to examination of the defect. However, the rule also requires that pressure be reduced once an immediate repair condition is discovered (see 192.933(d)(1)). Pressure reductions should be taken promptly.
The rule also specifies (192.933(c)):
"...If an operator cannot meet the schedule for any condition, the operator must justify the reasons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety. An operator must notify OPS in accordance with §192.949 if it cannot provide safety through a temporary reduction in operating pressure or other action...."
Thus, an operator is required to examine immediate repair conditions within 5 days. If an operator cannot do so, it must document its justification for why it cannot and how continued safety is assured. Operators need only notify PHMSA of their inability to examine immediate repair conditions within 5 days if they cannot reduce pressure. Operators must take additional action (e.g., complete examination of the defect) within 365 days or document additional "technical justification that the continued pressure reduction will not jeopardize the integrity of the pipeline." (192.933(a)).
No. B31G and RSTRENG are not valid for situations with metal loss exceeding 80 percent of wall thickness (see Figure 1-2 in B31G, which requires "repair or replace" for conditions involving wall loss greater than 80 percent). These methods cannot be used to determine failure pressure for these situations.
Section 192.917(e)(5) requires that an operator who finds corrosion on a covered pipeline segment "must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics." The conditions for which this provision applies are specified in 192.933(d). There is one specific criterion in Section 192.933(d)(i) related to corrosion – an immediate repair condition in which a calculation of remaining strength shows a predicted failure pressure less than or equal to 1.1 times MAOP.
In determining actions for non-covered segments, operators should consider any data obtained for non-covered segments during the same assessment (i.e., that were part of the same ILI run) that identified the immediate corrosion condition as specified by 192.933(d)(i). Additionally, operators should consider non-covered segments where coating and environmental conditions are similar to those resulting in the immediate corrosion condition in the covered segment. Operators should conduct a root cause evaluation to identify the factors (e.g., coating and environmental conditions, equipment or operator error) that were important to the significant corrosion that was found, and should use the results of that evaluation to guide their review of data regarding non-covered pipeline segments to identify areas that need to be addressed.
The special scheduling requirements and requirements to reduce pressure or take other action of Section 192.933(d) do not apply to non-covered segments. OPS expects operators to take action to address these segments in a timely manner, consistent with the importance to safety of the potentially degraded condition of the pipeline.
Yes. Since temporary pressure reductions may remain in place for up to 365 days, this provides a reasonable amount of safety margin to compensate for defect growth for one year until the defect can be repaired.
There are three options for calculating reduced operating pressures:Operators can use B31.G or RSTRENG to calculate Psafe. This calculation, in either case, includes a safety factor of 0.72.
Operators can reduce pressure to 80 percent of its level at the time the defect was discovered. OPS considers that a reduction of this magnitude includes sufficient safety margin.
Operators can use B31.G or RSTRENG to calculate Pfailure and can then apply safety margins to determine a new safe operating pressure. Operators that can demonstrate and justify reliable defect growth rates using empirical data may be able to justify higher temporary operating pressures, if they can show that the defect will not grow to a size that results in the predicted failure pressure being less than 1.1 times the temporary operating pressure within 365 days of initiating the pressure reduction. (If reliable defect growth rates can not be determined, Table B1 of B31.8S provides conservative estimates of growth rates that can be used for this purpose). Defect growth calculations must be performed based on defect growth during the entire time between when the assessment data was obtained and the end of the 365 day period.
Yes. Operators may find problems in non-covered segments while performing assessment of covered segments (e.g., because non-covered segments are also inspected during an ILI assessment) and must take appropriate actions to meet the requirements in 192.485, 192.703(b), 192.711, 192.713, 192.715, 192.717, and 192.719 as applicable. The provisions and requirements in Section 192.933(d) apply only to covered segments. In non-covered segments, operators are responsible for determining the appropriate criteria and schedule for remediating anomalies, consistent with the significance of the identified problem.
The anomaly repair schedule requirements in 192.933(d) apply to baseline assessments and subsequent re-assessments required by the new integrity management rule. Prior internal inspection tool runs do not need to comply with the 192.933(d) criteria unless the pipeline segment inspection is declared to be a baseline assessment as described in 192.921(e). (All defects identified in the most recent prior assessment relied upon as a basis for a performance-based program under 192.913 must be repaired per 192.933).
In addition, operators are expected to review the results of their prior integrity assessments to prioritize pipeline segments for the Baseline Assessment Plan and to perform the information and risk analysis required in 192.917. In performing these reviews, operators should confirm that anomalies or defects identified in these earlier runs that might compromise integrity have been mitigated. (All defects in the most recent prior assessment relied upon as the basis for a performance-based approach under 192.913 must be repaired per 192.933).
Any assessments conducted after February 14, 2004 (the effective date of the rule), are considered assessments covered by Subpart O, and the schedule criteria of 192.933(d) apply.
Using a prior assessment is allowed in 192.921(e) if the prior assessment meets the baseline assessment requirements in Subpart O and if all remedial actions are carried out for the anomalous conditions referred to in 192.933. As written, a prior assessment is only a candidate for use as baseline assessment until all anomalies requiring repair under 192.933 are repaired. It is only after all conditions are met that a prior assessment can become a baseline assessment.
The rule does not require that monitored conditions be repaired. These conditions must be recorded so that they can be monitored during future integrity management assessments. They must be repaired if future assessments show changes which cause these anomalies to meet criteria for immediate repair or one-year conditions or in the judgement of the person evaluating the assessment are sufficient to require repair.
Yes. The rule specifies that the temporary pressure reduction be determined using ASME/ANSI B31G or RSTRENG or that pressure must be reduced to a level not exceeding 80 percent of the level at the time the condition was discovered.
The repair schedules in 192.933 apply only to the covered segment. However, the operator is responsible for promptly addressing anomalies identified in the other portions of the pigged section in accordance with 192.703(b).
No. A reduction in operating pressure is intended to provide an additional safety margin until the defect can be remediated. To assure that additional margin is provided, the pressure reduction must be based upon pressures that the pipe has actually experienced, with the defect present (i.e., pressures for which safety has been demonstrated). These may be well below the "maximum allowable operating pressure" for the pipe. The rule requires that the pressure reduction must be calculated using ASME/ANSI B31G or RSTRENG or that the pressure be reduced at least 20 percent from the level at the time the condition was discovered.
Pipeline Integrity relies on data to make repair decisions. Any data collected, whether "baseline", "reassessment", or from other sources must be acted upon when the information is available. Pig runs can include some length for high consequence areas and some length for non high consequence areas. The integrity management rule repair criteria apply to high consequence areas. If anomalies fall in a high consequence area the answer is yes. The integrity management rule requires a program that integrates all information regarding the integrity of the pipeline. Anomalies discovered in segments in high consequence areas after the effective date of the rule must be repaired in accordance with the criteria and schedules for repair conditions specified in 192.933. Anomalies discovered in segments in non high consequence areas must be repaired in accordance with existing rules in Subpart M, Maintenance, of Part 192.
Pressure should be reduced, or the line should be shut down, as soon as practicable once an immediate repair condition is identified.
Discovery of a condition occurs when an operator has adequate information about the condition to determine that it presents a potential threat to the integrity of the pipeline. Depending on circumstances, an operator may have adequate information when the operator receives the preliminary internal inspection report, gathers and integrates information from other inspections, or when an operator receives the final internal inspection report. Operators are required to obtain sufficient information about a condition to make this determination no later than 180 days after an integrity assessment, unless the operator can demonstrate that the 180-day period is impractical.
Yes. The rule requires that operators who identify corrosion in a covered segment that could adversely affect the integrity of the line must evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics (192.917(e)(5)). This section of the rule refers to conditions identified in section 192.933 as those requiring this evaluation and remediation. Those conditions represent severe corrosion -- instances in which the remaining strength of the pipe is less than or equal to 1.1 times MAOP. As a matter of prudence, OPS would expect operators to consider non-covered segments, as appropriate, when less severe corrosion is found (e.g., when a new corrosion threat has been identified), but such broader evaluations are not required by the rule.
An operator should not wait until after an assessment is conducted to perform its risk analysis and implement appropriate preventive and mitigative measures. Preventive and mitigative actions are a response to the threats faced and the relative risk of the pipeline subject to those threats. It could be valuable for operators to have assessment results in hand to consider when identifying additional preventive and mitigative measures, but the baseline assessment for some segments may not be conducted for several years (e.g., as late as 2012). Operators can, and should, gather enough information before this time to evaluate risk and make the required determinations regarding preventive and mitigative measures. Operators need to document the basis for these determinations, and should have a means of monitoring to determine if the additional measures are effective.
After an operator completes its baseline assessment for a segment, it should revisit its risk analysis, incorporating the results of the integrity assessment and identifying the significant risks that remain. The operator should then analyze those risks to determine if additional actions (or other additional Preventive & Mitigative Measures) should be undertaken. Although the rule establishes no firm time limits by when this risk analysis must be performed, PHMSA believes it is reasonable to expect that this analysis as well as the identification of any additional potential preventive and mitigative actions should be completed within one year after the assessment has been performed. This will allow time for reviewing the assessment results and excavating the worst features, thereby developing confidence in the validity of the assessment and an understanding of the line's condition.
PHMSA recognizes that the time required to implement preventive and mitigative actions is highly dependent on the proposed risk control activity. Some actions may be simple "quick fix" activities that can readily be implemented in the field. Other actions may involve major capital expenditures and require significant time for budgeting, engineering and design, and implementation. Because of this wide disparity, there is no fixed time requirement for implementing preventive and mitigative actions. PHMSA expects operators to provide a schedule by when additional preventive and mitigative measures will be taken, and to act as quickly as practical after identifying the need for such risk controls. In situations where lengthy periods are required for implementation, operators should determine if there are relatively simple, interim measures that can be taken to reduce risk while major projects are being implemented.
OPS intends this semi-annual requirement to be consistent with the semi-annual intervals for leak surveys required by 192.706. Semi-annual leakage surveys to comply with 192.935(d)(3) should therefore be conducted at intervals not exceeding 7 1/2 months, but at least twice each calendar year. Quarterly surveys should be conducted at intervals not exceeding 4 1/2 months, but at least 4 times each calendar year.
Section 192.935(b) requires that operators take specific actions to address the threat of third-party damage. In addition, section 192.935(a) requires that "An operator must take additional measures beyond those already required by Part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area." (emphasis added). Section 192.935(a) further requires that "An operator must conduct...a risk analysis of its pipeline to identify additional measures...".
The rule does not require that operators implement additional actions beyond those they presently implement, only that they implement actions beyond those already required. Operators who are already implementing protective measures that go beyond the regulations may not need to do more unless their risk analysis indicates otherwise. OPS inspections will include an evaluation of the operator’s risk analysis and will consider whether additional protective measures that have been implemented are consistent with its conclusions.
The action taken, and the timeliness with which they are implemented, must be commensurate with the nature and severity of the threat that has been identified. The example of relocating the line is the last and most extreme of the list of candidate actions listed in 192.935(b)(2). For this action, the "threat" level must be high. However, for other actions, such as increasing the frequency of patrols, the threat level need not be so high. To wait until an imminent pipeline failure exists is too high a threshold.
The reports must be complete through June 30 and December 31 of each year and must be submitted by two months after those dates. The report submitted in August should include data for the first half of the calendar year. The report submitted in February should include data covering the entire calendar year (i.e., updating the information in the August report).
Section 192.945 was revised by the rule correction published in the Federal Register on April 6, 2004 (69 FR 18228). As revised, the rule requires semi-annual submission of only the four overall measures. Operators implementing performance-based programs, under 192.913, are required to submit the additional performance measures they define for their programs in addition to the Section 9.4 measures.
Operators can use assessments conducted prior to identification of an HCA as baseline inspections. The provisions of 192.921(e) would apply, and the date of the assessment would mark the beginning of the required reassessment interval. If an operator, in the postulated situation, uses the prior assessment as the baseline for the new HCA segment, then the associated mileage can be included in the next semi-annual performance measure submittal. If the operator elects not to treat the prior assessment as its baseline, then the mileage should not be reported.
Yes. OPS will develop an on-line form for submitting this information. The form will be available on the OPS web site (http://ops.dot.gov). The same information can be submitted by mail or facsimilie, in accordance with 192.951, but OPS would prefer to receive performance measures via the web site.
These terms are defined in Section 13 of ASME/ANSI B31.8S. This is the same standard in which this performance measure is specified. OPS originally relied upon the definitions in this standard. This caused confusion, however. The term "incident", in particular, is defined much more broadly than as defined in 191.3 and historically used by the U.S. pipeline industry. At the request of the industry, OPS clarified the definitions in the on-line instructions for submitting performance measures. Operators should use the following definitions, taken from the revised instructions, in recording and reporting their performance measures:
Failure is a general term used to imply that a part in service: has become completely inoperable; is still operable but is incapable of satisfactorily performing its intended function; or has deteriorated seriously, to the point that it has become unreliable or unsafe for continued use. If an event involves the unintentional release of gas, it should be reported as an incident or leak.
Incident means an event meeting the criteria in the definition in 49 CFR 191.3:(iii)An event that is significant, in the judgment of the operator, even though it did not meet the criteria above
Leak means an unintentional escape of gas from the pipeline. This would include any unintentional release of gas from a pipeline that does not result in an injury, death, or $50,000 in property damage.
OPS expects that operators will exercise appropriate controls to ensure that their IM programs, and the procedures by which its elements are implemented, are approved for use. The level of management official responsible for that approval is up to each operator, but should be at a level sufficient to assure compliance.
Yes. An operator should be prepared to discuss with inspectors evidence demonstrating that the database was used as a contemporary record, rather than having been created after the fact. Procedures, historical printouts, and archived copies of the database are examples of means that can be used to demonstrate that the database is relevant documentation.
Section 192.947(d) requires that operators maintain, for the useful life of the pipeline, documents to support any decision, analysis and process developed and used to implement and evaluate each element of the baseline assessment plan and integrity management program. Copies of the evolving revisions of the baseline assessment plan, and of plans for periodic reassessments, should be included with the records maintained under this section.
Operators’ management of change process should be implemented as soon as there is a program whose change needs to be managed. If an operator approves its IM program, or portions thereof, for use before December 17, 2004, then management of change procedures should apply (to those approved programs/portions) at the same time. The rule requires that operators have a written IM program that addresses each program element by December 17, 2004, meaning that a management of change process must be implemented by no later than this date.
No. OPS understands that there are a number of factors that could result in the need to modify Baseline Assessment Plans after their initial preparation. For example, as information is obtained from the initial integrity assessments, risk analysis, and operating experience, an operator’s understanding about the specific integrity threats and relative importance of those threats may change. An operator may elect to apply a different integrity assessment method (e.g., select a different in-line inspection tool that may improve the capability to detect a particular type of defect), or perhaps accelerate assessments in some areas because the risks are higher than previously understood.
Because assessment plans are likely to change, OPS expects operators to document the basis for changes in the plan (required by 192.909(a)) so these can be reviewed during inspections. It is not necessary to apply for a waiver to change the Baseline Assessment Plan. Even though an operator's plan may change, the operator must still complete baseline assessments for 50% of the mileage in HCAs by December 17, 2007, and complete baseline assessments for all of the mileage in HCAs by December 17, 2012.
No. The rule requires that operators notify OPS of any changes "that may substantially affect the program’s implementation or may significantly modify the program or schedule for carrying out the program elements" (emphasis added). Changes to the schedule for assessing individual pipeline segments that do not significantly affect program implementation or plans for carrying out program elements would not require a notification. Operators need not notify OPS of insignificant changes to their assessment schedules. Operators must document the basis for such changes (as required by 192.909(a)), and this documentation must be available for OPS review during integrity management inspections.
Section 192.911(m) requires, in part, that each operator’s IM program include a communication plan addressing the elements of ASME/ANSI B31.8S section 10. That section describes basic information that should be provided periodically to different stakeholders. In summary, it includes information about the pipeline and relevant emergency response procedures. It should also include high-level information about the fact that the operator has a program to monitor pipeline integrity that provides for periodic assessment of pipeline in high consequence areas. API RP-1162 provides a further description of a public communications program.
The notifications required by the rule are:
No. The 180-day period is intended to allow for PHMSA review. Once that review is completed, if no objections are noted, the operator may proceed.
No. As stated in §192.927(c)(2) the operator must demonstrate that a different model for ICDA region identification is technically equivalent to the one shown in GRI 02-0057. Documentation of this equivalency analysis should be retained by the operator for inspection during an audit. The notification requirement for the "other technology" assessment method does not apply and there is no notification requirement specified in the rule for an operator's selection of an alternate ICDA region identification model.
The requirements for safety-related condition reports are distinct from those for integrity management. Where the provisions of 191.23 require a report, such report must be made independent of any requirements in Subpart O.
The type of changes considered here would include significant revisions to the baseline assessment plan schedule such as significant delays in segment assessments, or changes that affect the overall manner in which an operator is conducting its IM program. These qualifiers are intended to preclude notifications for minor, even editorial, changes, or changes anticipated to occur to baseline assessment schedules due to foreseeable circumstances such as weather, permitting delays, or re-ranking schedule priorities due to updated risk assessment information.
OPS encourages operators to submit notifications as far in advance as practical to assure time for appropriate review and for making alternative plans in the event that OPS objects to the proposed alternative approach.
Inspections of integrity management requirements will be conducted using written inspection protocols. Those protocols are available on this website (http://primis.phmsa.dot.gov/gasimp/) and comments submitted via this website will be considered during their development.
Yes. OPS will schedule all integrity management inspections as far in advance as possible. OPS will coordinate the inspections with the companies to identify mutually agreed upon dates whenever possible.
Appendix E to Part 192 is guidance and does not contain requirements. Where "must" is used to provide guidance for what an operator must do to comply with a requirement in the body of Subpart O, then that action may be required as a result of the language in the rule body. Compliance with Appendix E is not required solely because of the use of "must" statements.
Yes. Section 192.907 requires that "...an operator of a covered pipeline segment must develop and follow a written integrity management program...". Requirements that an operator chooses to incorporate in its program, even though they may go beyond requirements specified in regulations, become a part of the program that the operator must "follow". OPS expects that an operator will implement all activities included in the operator's program. OPS encourages operators to undertake additional activities beyond those required by regulation. However, OPS discourages operators from including those additional activities in their programs if they do not intend to implement those additional activities.
States may apply standards more restrictive than federal rules. Operators should consult with state pipeline safety authorities regarding the application of state laws.
The rule requires that an operator "notify" OPS (192.909(b), 192.921(a)(4), 192.933(c)), and 192.937(c)(4)), and these sections also require that operators notify state authorities where the pipeline is under their jurisdiction. Notifications under these provisions should be sent both to OPS and to states. Section 192.945 requires that performance measures be submitted to OPS. OPS intends to make these measures available to states. This rule does not require that operators separately submit performance measures to states, although some states may establish their own requirements to do so. Waivers from this regulation will be treated in the same manner as any other waiver, and the application process should be the same.
All programs must include risk assessment and data integration. For performance-based programs, OPS expects that the approaches used for these elements will be more thorough, complete, and mature than those used in prescriptive programs.
Performance-based operators must have:
· "A comprehensive process for risk analysis" (criterion i of 192.913(b)(1)). The risk assessment should be a tool that is actively used in all aspects of the integrity management program, well beyond prioritizing segments for inspection. Use of risk analyses and risk-based information should be ingrained in the management decision-making process for safety decisions.· "A comprehensive data integration process" (criterion iii). The process by which operators using performance-based approaches bring together all information relevant to a given covered segment for use in making decisions about its integrity is expected to be more thorough and complete than those used by operators following a prescriptive approach.
Operators pursuing a performance-based approach are also required to implement some program elements not required of operators using prescriptive approaches. See Section 192.913(b)(1).
No. Confirmatory Direct Assessment is a streamlined method that does not provide as much information about the pipeline as assessment methods required for baseline and periodic reassessments.