Page 128 - Pipeline Risk Management Manual Ideas, Techniques, and Resources

Riskvariables and scoring 5/105
automatic electric openers that are geared to operate at a rate destructive testing (NDT) techniques such as ultrasonic, mag-
less than the critical closure time (see Appendix D). If a valve netic particle, dye penetrant, etc., to find pipe wall flaws that
must be closed manually. it is still not possible to close the valve are difficult or impossible to detect with the naked eye.
too quickly-many turns of the valve handwheel are required
for each 5% valve closure. Points for this scenario are assessed Evaluating the integrity verification
at 5.
For purposes of risk assessment, the age and robustness of the
D. Integrity verifications (weighting: 25%) most recent integrity verification should dnve the score assign-
ment. The performance of a series of inspections, especially
Pipeline integrity is ensured by two main efforts: (1) the detec- using in-line inspection, where results can be overlaid and more
tion and removal of any integrity-threatening anomalies and (2) minor changes detected is even more valuable.
the avoidance of future threats to the integrity (protecting the
asset). The latter is addressed by the many risk mitigation meas- Age of verification
ures commonly employed by a pipeline operator, as discussed
in Chapters 3 through 6. The age consideration can be a simple proportional scoring
The former effort involves inspection and testing and is fun- approach using a predetermined information deterioration rate
damental to ensuring pipeline integrity, given the uncertainty Note that information deterioration refers to the diminishing
surrounding the protection efforts. The purpose of inspection usefulness of past data to determine current pipe condition.
and testing is to validate the structural integrity of the pipeline (see discussions in Chapters 2). The past data should be used
and its ability to sustain the operating pressures and other anti- to characterize the current effective wall thickness until better
cipated loads. The goal is to test and inspect the pipeline system information replaces it. Five or 10-year information deteriora-
at frequent enough intervals to ensure pipeline integrity and tion periods-after which the inspection or test data are no
maintain the margin of safety. This was discussed earlier and longer providing meaningful evidence of current integrity-
illustrated by Figure 5.3. are common defaults, but these can be set more scientifically.
A d&ct is considered to be any undesirable pipe anomaly, An inspection interval is best established on the basis of two
such as a crack. gouge, dent. or metal loss, that could later lead factors: (1) the largest defect that could have survived or been
to a leak or spill. Note that not all anomalies are defects. Some undetected in the last test or inspection and (2) an assumed
dents, gouges. metal loss. and even cracks will not affect the defect growth rate.
service life of a pipeline. Possible defects include seam weak- A failure size must be estimated in order to calculate a time
nesses associated with low-frequency ERW and electric flash to failure. For cracklike defects, fracture mechanics and esti-
welded pipe, dents or gouges from past excavation damage or mates of stress cycles (frequency and magnitude) are required
other external forces. external corrosion wall losses, internal to determine this. For metal loss from corrosion, the failure size
corrosion wall losses. laminations. pipe body cracks, and cir- for purposes of probability calculations can be determined
cumferential weld defects and hard spots. by two criteria: (1) the depth ofthe anomaly and (2) a calculated
A conservative assumption underlying integrity verification remaining pressure-containing capacity of the defect con-
is that defects are present in the pipeline and are growing at figuration. Two criteria are advisable since the accepted calcu-
some rate, despite preventive measures. By inspecting or test- lations for remaining strength (see Appendix C) are not
ing the pipeline at certain intervals, this growth can be inter- considered as reliable when anomaly depths exceed 80% of the
rupted before any defect reaches a failure size. Defects will wall thickness. Likewise, depth alone is not a good indicator of
theoretically be at their largest size immediately before the next failure potential because stress level and defect configuration
integrity verification. This estimated size can be related to a are also important variables [86].
failure probability by considering uncertainty in measurements These defect rates of growth can be estimated after succes-
and calculations. Therefore, the integrity re-verification inter- sive integrity evaluations or. when such information is unavail-
val is implicitly establishing a maximum probability of failure able, based on conservative assumptions. With knowledge of
for each failure mode. maximum surviving defect size, defect rate of growth, and
The absence of any defect of sufficient size to compromise defect failure size, all of the ingredients are available to estab-
the integrity ofthe pipeline is most commonly proven through lish an optimum integrity verification schedule. This in turn
pressure testing and/or ILI. the two most comprehensive sets the information deterioration scale. Unfortunately, most
integrity validation techniques used in the hydrocarbon trans- of these parameters are difficult to estimate with any degree
mission pipeline industry today. Integrity is also sometimes of confidence and resulting schedules will also be rather
inferred through absence of leaks and verifications of protec- uncertain.
tive systems. For instance, CP counteracts external corrosion
of steel pipe and its potential effectiveness is determined Robustness of verification
through pipe-to-soil voltage surveys along the length of the
pipeline, as described in Chapter 4. All ofthese measurement- Integrity verifications vary in terms of their accuracy and
based inspections and tests are occasionally supported by ability to detect all types of potential integrity threats. The
visual inspections of the system. Each ofthese components of robustness consideration for a pressure test can simply be the
inspection and testing of the pipeline can be-and usually pressure level above the maximum operating pressure. This
should be-a part of the risk assessment. establishes the largest theoretical surviving defect. The role of
Common methods of pipeline survey. inspection. and testing pressure level and a possible scoring protocol are discussed
are shown in Appendix G. Pipe wall inspections include non- below.