Parth Iyer, Senior
Integrity Engineer, and Cassandra K. Moody, Professional Engineer, Dynamic Risk
Critical Assessments (ECA) have been incorporated into United States pipeline
safety regulations1 as a means for reconfirming the maximum
allowable operating pressure (MAOP) for onshore steel gas transmission
pipelines, while engineering assessments (EA) have been a longstanding method
for proving consistent conclusions and recommendations across a variety of
situations in accordance with the guidance in Canadian standard CSA Z662:191.
both ECAs and EAs are established practices with their own minimum standards
and regulatory requirements, they each follow different progressions to satisfy
their respective applications. This article outlines the key differences
between the EA and ECA approaches and proposes a consolidated approach that is
applicable to circumstances where EAs or ECAs may be employed.
terminology surrounding the analytical process compared in this paper varies
across North American pipeline safety authorities. To clear up confusion, the
usage of terms in this paper will identify their respective regulatory
EA and ECA have defined terms in the Canadian Standard (CSA) Z662, adopted by
the Canadian Energy Regulator Onshore Pipeline Regulations (SOR/99-294).2
CSA distinguishes EA from ECA (Table 1).
United States pipeline safety federal regulations do not specifically define
the term Engineering Assessment; however, Engineering Critical Assessment is
defined in the natural gas transportation safety regulations in 49 CFR, Part
192.34 and is referenced in Subpart L – Operations Sections 192.625
addition to the existing pipeline safety regulations as part of RIN 2137-AE72
Final Rule8, commonly referred to as the “Gas Mega Rule,” the
Pipeline Hazardous Materials Safety Administration (PHMSA) established new MAOP
reconfirmation requirements through a choice of six methods. One of the
specified methods is ECA analysis.
related hazardous liquid pipeline safety regulations in 49 CFR Part 1959 do
not explicitly define EA or ECAs.
engineering analysis, as related to pipes susceptible to longitudinal seam
failures are mentioned in 49 CFR Part 195.303(d)10 as a risk-based
alternative to pressure testing older hazardous liquid and carbon dioxide
pipelines. This clause requires consideration of steel mechanical properties,
including fracture toughness, similar to that of Canadian ECAs.
summarizes the convergencies in the four terms discussed above, related to the
documented engineering procedures discussed above from the U.S. and Canadian regulatory
addition to the federal pipeline safety regulations in the US and the standard
incorporated by reference in Canada, industry standards and guidance bodies
have discussed engineering assessments in various documents to provide pipeline
operators guidance for the safe operation of assets.
American Petroleum Institute (API) maintains a robust standard detailing the fitness-for-service
(FFS) methodology in API 57911. FFS assessment12 is
defined as a methodology whereby flaws or a damaged state in a component is
evaluated to determine the adequacy of the component for continued operation.
API 579 Part 2 details an eight-step procedure to determine the FFS of a
component organized by flaw type and damage mechanism13. When
fracture mechanics is considered, damage mechanisms like brittle fracture,
crack-like features, corrosion, and other damage, align with the CSA Z662 ECA
API 579 FFS assessment procedures cover both the present integrity of the
component given a current state of damage and the projected remaining life.
Qualitative and quantitative guidance for establishing remaining life and
in-service margins for the continued operation of the equipment are provided in
regard to future operating conditions and environmental compatibility.
standard API 110414, Welding of Pipelines, details analysis to
determine weld-specific fitness-for-purpose criteria. The terms ECA and
fitness-for-service are used interchangeably in this standard. Similar to
Canadian ECAs, additional qualification tests, stress analysis, and inspection
are essential under this standard.
American Society of Mechanical Engineers standard B31.8S, Managing System
Integrity of Gas Pipelines15, identifies ECA as suitable for threat
prevention and repair method for certain instances of internal corrosion,
external corrosion, stress corrosion cracking, girth weld defects, third-party
damage, manufacturing, and construction threat disposition.
federal regulations and industry standards organizations, several organizations
have mentioned EAs in their reports. Two notable industry reports include the
International Natural Gas Association of America (INGAA) Fatigue Considerations
report16 and the Pipeline Research Council International (PRCI)
report on Fatigue Life Assessment of Dents17. Both reports detail
fracture mechanics-based calculations and assessments for flaws to determine
the fitness for service using ECA principles.
Canada, the requirements for engineering assessments are provided in Clauses
3.4, 4.1.12, 5.8 and 10.1 of CSA Z662.
3.4 establishes the structural requirements for the engineering assessment;
Clause 4.1.12 outlines the considerations for pipeline design; Clause 5.8
outlines the considerations for material qualification, and Clause 10.1
provides the detailed elements that need consideration as applicable. It is
noted that there is an opportunity to focus the EA as applicable to a specific
threat or circumstance, but there is also a requirement to consider risk
assessment as part of the analysis18.
the US, Operators that chose to conduct an MAOP reconfirmation under 49 CFR
Part 192.624(c)(3) “Method 3” using an ECA to establish the material strength
and MAOP of the pipeline segment must assess: Threats; loadings and
circumstances relevant to those threats, including along the pipeline
right-of-way; outcomes of the threat assessment; relevant mechanical and
fracture properties; in-service degradation or failure processes; and initial
and final defect size relevance. The ECA must quantify the interacting effects
of threats on any defect in the pipeline15.
evaluating the material properties required for the U.S. ECA analysis, the
documented records of material properties considered in such an analysis to
reconfirm the MAOP must be traceable, verifiable, and complete (TVC) records.
If the records for material properties used in the ECA are not TVC, the
operators of gas transmission pipelines in the US must then adhere to the
verification testing stipulations in 49 CFR 192.607(a)19.
documented material properties are available, the federal pipeline safety code
stipulates gas transmission pipeline operators are to use conservative
assumptions (Table 3) for material toughness20 and strength21
values while conducting predicted failure pressure analysis reviews by a
subject matter expert for corrosion metal loss and crack-like defects in
accordance with 49 CFR 192.712.
this paper, the general term engineering assessment (EA) will signify a
documented process of analysis for a variety of pipeline integrity purposes.
Specific regulatory requirements for a given asset must always be considered
based on the jurisdiction of the individual asset and any applicable
develop an EA methodology applicable to assets outside of a particular
geographic location, the strengths and weaknesses of each method are considered
in Table 4.
summary, ECAs are rigorous in applying fracture mechanics to determine flaw
size but have limited applications. EAs, while more broadly applicable to
and risks to the operation of pipeline systems, lack the formal requirements
and process of ECAs. Competent engineers and robust data are required in all
for pipelines located in Canada are employed under the following circumstances:
the United States, ECAs have been incorporated into the federal Code 22
explicitly for the following circumstances:
sections of the US pipeline safety regulatory code23 implicitly allow for EAs
by using sound engineering principles or when calling for subject matter expert
analysis related to:
PHMSA notice of proposed rulemaking (NPRM) indicates ECAs are being considered
for changes in gas class location24.
proposed approach for EAs and ECAs follows a process that reflects the plan-to-do-check-act
(PDCA) approach25. This approach is well established in the safety
management systems literature applied to pipeline integrity management. The
proposed approach is similar to the four-step process described in external26
or internal corrosion direct assessments27 and the eight-step
FFS process outlined in API 57928.
the purpose of the EA
the pipeline assets that are within the scope of the EA
and document known information, including historical inspections
the integrity threats considered within the scope
each threat, review and assess:
whether each threat hinders accomplishing the purpose of the EA based on the
any gaps and make the necessary recommendations to fulfil the purpose of the EA
corrective actions and recommendations in a timely manner
provides a simple visualization of the suggested EA approach overlaid with the
PDCA cycle. Determining the purpose of the EA provides the foundation for the
specific analysis considerations employed in subsequent steps. It is important
to note, as will be demonstrated in the following case study, that available
fracture mechanics modeling techniques common to Canadian ECAs and the API 579
FFS guidance may be used in step five when threats are assessed as the specific
suggested model for conducting an EA must be led by a competent and qualified
engineer who considers pertinent information and makes conservative assumptions
in the absence of documentation.
of jurisdictional determination or a specific type of EA delineation, for
general FFS purposes, collection and consideration of system-specific
information while conducting an assessment is essential. A competent and
qualified engineer should consider, at a minimum, the pipeline system
operational considerations, properties, threat assessments, risk assessments,
inspections and repairs while conducting an EA.
demonstrate the EA approach, let’s consider the fitness for service of a discontinued
NPS 8 natural gas pipeline that is to be returned to service. Within this EA,
the threats listed in Table 6 by ASME B31.8S were evaluated along with
most recent semi-quantitative risk assessment results.
proposed PDCA EC methodology is applied to this case study showing how the
threat-based EA was overlaid with the semi-quantitative risk algorithm to yield
a sound, engineering basis for reactivation.
initiating the EA, proper planning is essential to ensure adequate analysis is
performed. The purpose of this specific case study EA was to determine the FFS
to reactivate a single pipeline asset. Beyond comparing inspection feature
lists and repair documentation, a concerted effort to ensure the known failure mechanism
behind the historical failures was being robustly evaluated.
data surrounding the geohazard threat was a significant portion of the document
segments comprising the asset of the study are summarized (Table 5). Another
challenge with this pipeline was the presence of two short sections of
unpiggable piping. We made sure to review the hydrostatic pressure test
information as well as other wall thickness readings on these non piggable
threats prescribed by ASME B31.8S, including interacting threats, were
considered and reviewed (Table 6).
walk through the evaluation process for the threat of external corrosion. The
effectiveness of the existing prevention and mitigation systems, such as
external coatings and cathodic protection, was evaluated with in-line
inspection (ILI) results along the mainline to determine the severity of the
demonstrates the existing prevention and mitigation systems effectively manage
the threat of external corrosion from the scarcity of external metal loss anomalies
reported in the ILI.
proximity to AC powerlines was also considered for this threat due to their
adverse effect and increased risk of localized accelerated corrosion and threat
to worker safety. Publicly sourced spatial data29 revealed three AC
powerlines within 50 km of the in-scope pipelines.
CP data and ILI results did not reveal any cause for concern.
line of the EA had multiple prior inspections using various magnetic flux
leakage and geometry ILI technologies. After considering the repair history of
addressed defects, the remaining anomalies calculated failure pressures using
the ASME Modified B31G method30 were evaluated to ensure fitness for
a summary of the external metal loss anomalies remaining. The scheduled
response for all the reported external metal loss anomalies was calculated
using the approach described in ASME B31.8S to determine the remaining life and
internal inspection after the pipeline was reactivated. This calculation
revealed a minimum response time of greater than 10 years, which confirmed no
immediate corrective action was required for this threat before the resumption
evaluate the effect of pressure cycles as covered by the manufacturing threat,
historical operational data was plotted for a twelve-year period and compared
to cycling patterns in TTO Number 534. Figure 4 indicates the
historical pressure and flowrate of the pipeline, which did not meet the
criteria for aggressive pressure cycling.
industry guidance in ASME B31.8S and other reports35 were considered
for gas pipelines which historically have not been significantly affected by
pressure cycling due to the compressible nature of gas and a limited number of
as manufacturing is a stable threat with potential defects present during the
pre-commissioning pressure test, any small, survivable features remaining after
the successful hydrostatic pressure test would be resident, non-injurious
primary threat of geotechnical outside force was evaluated through a review of
additional pertinent data, including ground stability slope inclinometer
surveys, an asset-specific geotechnical report following landslide activity, a
company damage prevention management program, and recent HDD remediation
activity to circumvent an active fault line, was
These preventatives and mitigative measures were deemed adequate to manage the
threat of outside geotechnical forces.
other five threats not discussed in this paper and interacting threats were
evaluated based on industry guidance and information available by competent and
sound engineering practices employed and asset-specific analysis conducted on a
threat basis were documented in the EA report. The report was peer-reviewed and
accepted before delivery to the asset operator.
the EA review, adequate data was provided to determine FFS, and no threats were
identified as unmitigated that could hinder the EA’s purpose of reactivating
the asset. Assumptions were documented, and recommendations were provided in
the final report.
an additional check of the desktop engineering assessment conducted, risk
results were also evaluated by calculating the failure frequencies for all
threats based on available information and a semi-quantitative risk model. For
this pipeline, the risk results identified third-party mechanical damage as the
major driver, with failure frequencies at all points except one being below
10-4 ruptures/km-year (Figure 5).
drastic dip in failure frequencies near the 21,000 m chainage is from a newly
replaced HDD section of pipe. The risk algorithm yielded third-party damage as
the major driver based on the depth of cover for the specific pipeline, though
pipeline depth met or exceeded the regulatory requirements for cover across the
length of the pipeline.
the HDD remediation was performed before the risk results were calculated,
outside forces were not a driving threat.
engineers working on the desktop EA as well as those responsible for the
semi-quantitative risk assessment, agreed the separate perspectives of
threat-based assessment vs. the computational risk assessment provided a
comprehensive and independent evaluation of the asset’s state of integrity.
This complete review instilled integrity assurance in the resulting
reactivation of the asset system.
necessarily an objective of the specific EA scope, but a consideration is the
financial savings of performing a robust and sound engineering assessment to
determine reactivation FFS instead of running another non-destructive pipeline
ILI or other assessment. As the pipeline in question was out of service at the
time of the EA, significant costs to perform an assessment would be incurred if
this method were selected.
on the threat-guided EA and the computational risk results, the pipeline was
determined fit to resume service.
recommendations, summarized by threat in Table 8, were suggested
following the EA to maintain the asset’s integrity over the remaining
proposed methodology and the associated case study demonstrate the
effectiveness of employing a robust and comprehensive approach to EAs or ECAs
to determine fitness for service. The proposed approach employs the strengths
of both EAs and ECAs, namely the incorporation of threat analysis, risk
assessment results, and fracture mechanics to provide pipeline operators with
objective and technically sound results and tailored recommendations.
in circumstances where no data or low confidence data is available, the
involvement of one or more subject matter experts or competent engineers to conduct
the EA or ECA using conservative assumptions is invaluable. P&GJ
is a senior integrity engineer at Dynamic Risk and a licensed professional
engineer in Canada with over 10 years of pipeline integrity experience. He has
an excellent understanding of pipeline integrity management programs, risk
assessments, in-line inspections, regulatory audits and integrity data
is a professional engineer with 14 years of pipeline experience encompassing
integrity management program (IMP) responsibilities in addition to serving in
regional operations engineering capacities. Moody leads technical teams and
provides subject matter expertise in program management, operations, safety
management systems, threat assessment and change management principles.
at the 35th Pipeline Pigging & Integrity Management Conference, February
2023. Copyright 2023 Clarion Technical
Conferences and the authors.