The NTSB has published a study report on the integrity management of gas transmission pipelines in high consequence areas. Their findings are:
1.There has been a gradual increasing trend in the gas transmission significant incident ratebetween 1994-2004 and this trend has leveled off since the implementation of the integrity management program in 2004.
2.From 2010–2013, gas transmission pipeline incidents were overrepresented on high consequence area pipelines compared to non high consequence area pipelines.
3. While the Pipeline and Hazardous Materials Safety Administration’s gas integrity management requirements have kept the rate of corrosion failures and material failures of pipe or welds low, there is no evidence that the overall occurrence of gas transmission pipeline incidents in high consequence area pipelines has declined.
4.Despite the intention of the gas integrity management regulations to reduce the risk of all identified threats, high consequence area incidents attributed to causes other than corrosion and material defects in pipe or weld increased from 2010–2013.
5.Despite the emphasis of integrity management programs on time dependent threats, such as corrosion, gas transmission pipeline incidents associated with corrosion failure continue to disproportionately occur on pipelines installed before 1970.
6.From 2010–2013, the intrastate gas transmission pipeline high consequence area incident rate was 27 percent higher than that of the interstate gas transmission pipeline high consequence area incident rate.
7.Approaches used during integrity management inspections of gas transmission pipelines conducted instate inspections vary among states and whether this variability affects the effectiveness of integrity management inspections
has not been evaluated.
8.The Pipeline and Hazardous Materials Safety Administration (PHMSA)’s resources on integrity management inspections for state inspectors, including existing inspection protocol guidance, mentorship opportunities, and the availability of PHMSA’s inspection subject matter experts for consultation, are inadequate.
9.Federal to state and state tostate coordination between inspectors of gas transmission pipelines is limited.
10.The lack of high consequence area identification in the National Pipeline Mapping System limits the effectiveness of pre-inspection preparations for both federal and state inspectors of gas transmission pipelines.
11.There is a considerable difference in positional accuracy between interstate and intrastate gas trans
mission pipelines in the National Pipeline Mapping System, and this discrepancy, combined with the lack of detailed attributes, may reduce state and federal inspectors’ ability to properly prepare for integrity management inspections.
12.The discrepancies between the Pipeline and Hazardous Materials Safety Administration’s National Pipeline Mapping System, annual report database, and incident database may result in state and federal inspectors’ use of inaccurate information during pre-inspection preparations.
13.The lack of published standards for geospatial data commonly used by pipeline operators limits operators’ ability to determine technically sound buffers to increase the safety margin and also hinders integrity management inspectors from evaluating the buffer’s technical validity.
14.The lack of a repository of authoritative sources of geospatial data for identified sites may contribute to operators’ inaccurate high consequence area identification.
15.Inappropriate elimination of threats by pipeline operators can result in undetected pipeline defects.
16.The prevalence of inappropriate threat elimination as a factor in gas transmission pipeline incidents cannot be determined because the Pipeline and Hazardous Materials Safety Administration does not collect threat identification data in pipeline incident reports.
17.The inadequate evaluation of interactive threats is a frequently cited shortcoming of integrity management programs, which may lead to underestimating the true magnitude of risks to a pipeline.
18.The prevalence of interactive threats in gas transmission pipeline incidents cannot be determined because the Pipeline and Hazardous Materials Safety Administration does not allow operators to select multiple, interacting root causes when reporting pipeline incidents.
19.Inspectors lack training to effectively verify the validity of an operator’s risk assessment.
20.Many pipeline operators do not have sufficient data to successfully implement probabilistic risk models.
21.A lack of incident data regarding the risk assessment approach(es) used by pipeline operators limits the knowledge of the strengths and limitations of each risk assessment approach.
22.Whether the four approved risk assessment approaches produce a comparable safety benefit is unknown.
23.Sufficient guidance is not available to pipeline operators and inspectors regarding the safety performance of the four types of risk assessment approaches allowed by regulation, including the effects of weighting factors, calculation of consequences, and risk aggregation methods.
24.Professional qualification criteria for pipeline operator personnel performing integrity management functions are inadequate.
25.The use of inline inspection as an integrity assessment method for intrastate pipelines is considerably lower than for interstate pipelines (68percent compared to 96percent) in part due to the operational and configuration differences.
26.A much higher proportion of integrity assessments is conducted by direct assessment for intrastate pipelines than for interstate pipelines partly due to operational and configuration differences.
27.Of the four integrity assessment methods, inline inspection yields the highest per mile discovery of anomalies that have the potential to lead to failure if undetected.
28.In line inspection is able to inspect the integrity of the pipeline segments susceptible to multiple threats.
29.Improvements in in-line inspection tools allow for the inspection of gas transmission pipelines that were previously uninspectable by in-line inspection.
30.Operators may limit the use of in-line inspections due to operational complications.
31.There are many limitations to direct assessment, including that (1) it is limited to the detection of defects attributed to corrosion threats, (2) it only covers very short sub-segments of the pipeline, (3) it relies on the operator’s selection of specific locations for excavation and direct examination, and (4) it yields far fewer identifications of anomalies
compared to in-line inspection.
32.The selection of direct assessment by the pipeline operator as the sole integrity assessment method must be subject to strict scrutiny by the inspectors due to its numerous limitations.
33.Pipeline operators view geographic information systems as the preferred tool for effective data integration, as it can be used as a system of records and a source of authoritative data.
Read the full report with recommendations in this link.
Contribute to the surviving victims of Bhopal by buying my book "Practical Process Safety Management"
1.There has been a gradual increasing trend in the gas transmission significant incident ratebetween 1994-2004 and this trend has leveled off since the implementation of the integrity management program in 2004.
2.From 2010–2013, gas transmission pipeline incidents were overrepresented on high consequence area pipelines compared to non high consequence area pipelines.
3. While the Pipeline and Hazardous Materials Safety Administration’s gas integrity management requirements have kept the rate of corrosion failures and material failures of pipe or welds low, there is no evidence that the overall occurrence of gas transmission pipeline incidents in high consequence area pipelines has declined.
4.Despite the intention of the gas integrity management regulations to reduce the risk of all identified threats, high consequence area incidents attributed to causes other than corrosion and material defects in pipe or weld increased from 2010–2013.
5.Despite the emphasis of integrity management programs on time dependent threats, such as corrosion, gas transmission pipeline incidents associated with corrosion failure continue to disproportionately occur on pipelines installed before 1970.
6.From 2010–2013, the intrastate gas transmission pipeline high consequence area incident rate was 27 percent higher than that of the interstate gas transmission pipeline high consequence area incident rate.
7.Approaches used during integrity management inspections of gas transmission pipelines conducted instate inspections vary among states and whether this variability affects the effectiveness of integrity management inspections
has not been evaluated.
8.The Pipeline and Hazardous Materials Safety Administration (PHMSA)’s resources on integrity management inspections for state inspectors, including existing inspection protocol guidance, mentorship opportunities, and the availability of PHMSA’s inspection subject matter experts for consultation, are inadequate.
9.Federal to state and state tostate coordination between inspectors of gas transmission pipelines is limited.
10.The lack of high consequence area identification in the National Pipeline Mapping System limits the effectiveness of pre-inspection preparations for both federal and state inspectors of gas transmission pipelines.
11.There is a considerable difference in positional accuracy between interstate and intrastate gas trans
mission pipelines in the National Pipeline Mapping System, and this discrepancy, combined with the lack of detailed attributes, may reduce state and federal inspectors’ ability to properly prepare for integrity management inspections.
12.The discrepancies between the Pipeline and Hazardous Materials Safety Administration’s National Pipeline Mapping System, annual report database, and incident database may result in state and federal inspectors’ use of inaccurate information during pre-inspection preparations.
13.The lack of published standards for geospatial data commonly used by pipeline operators limits operators’ ability to determine technically sound buffers to increase the safety margin and also hinders integrity management inspectors from evaluating the buffer’s technical validity.
14.The lack of a repository of authoritative sources of geospatial data for identified sites may contribute to operators’ inaccurate high consequence area identification.
15.Inappropriate elimination of threats by pipeline operators can result in undetected pipeline defects.
16.The prevalence of inappropriate threat elimination as a factor in gas transmission pipeline incidents cannot be determined because the Pipeline and Hazardous Materials Safety Administration does not collect threat identification data in pipeline incident reports.
17.The inadequate evaluation of interactive threats is a frequently cited shortcoming of integrity management programs, which may lead to underestimating the true magnitude of risks to a pipeline.
18.The prevalence of interactive threats in gas transmission pipeline incidents cannot be determined because the Pipeline and Hazardous Materials Safety Administration does not allow operators to select multiple, interacting root causes when reporting pipeline incidents.
19.Inspectors lack training to effectively verify the validity of an operator’s risk assessment.
20.Many pipeline operators do not have sufficient data to successfully implement probabilistic risk models.
21.A lack of incident data regarding the risk assessment approach(es) used by pipeline operators limits the knowledge of the strengths and limitations of each risk assessment approach.
22.Whether the four approved risk assessment approaches produce a comparable safety benefit is unknown.
23.Sufficient guidance is not available to pipeline operators and inspectors regarding the safety performance of the four types of risk assessment approaches allowed by regulation, including the effects of weighting factors, calculation of consequences, and risk aggregation methods.
24.Professional qualification criteria for pipeline operator personnel performing integrity management functions are inadequate.
25.The use of inline inspection as an integrity assessment method for intrastate pipelines is considerably lower than for interstate pipelines (68percent compared to 96percent) in part due to the operational and configuration differences.
26.A much higher proportion of integrity assessments is conducted by direct assessment for intrastate pipelines than for interstate pipelines partly due to operational and configuration differences.
27.Of the four integrity assessment methods, inline inspection yields the highest per mile discovery of anomalies that have the potential to lead to failure if undetected.
28.In line inspection is able to inspect the integrity of the pipeline segments susceptible to multiple threats.
29.Improvements in in-line inspection tools allow for the inspection of gas transmission pipelines that were previously uninspectable by in-line inspection.
30.Operators may limit the use of in-line inspections due to operational complications.
31.There are many limitations to direct assessment, including that (1) it is limited to the detection of defects attributed to corrosion threats, (2) it only covers very short sub-segments of the pipeline, (3) it relies on the operator’s selection of specific locations for excavation and direct examination, and (4) it yields far fewer identifications of anomalies
compared to in-line inspection.
32.The selection of direct assessment by the pipeline operator as the sole integrity assessment method must be subject to strict scrutiny by the inspectors due to its numerous limitations.
33.Pipeline operators view geographic information systems as the preferred tool for effective data integration, as it can be used as a system of records and a source of authoritative data.
Read the full report with recommendations in this link.
Contribute to the surviving victims of Bhopal by buying my book "Practical Process Safety Management"
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