US PIPELINE REGULATIONS - Conclusion: PHMSA needs to clarify SMYS for pressure boosts
The US Pipeline & Hazardous Materials Administration needs to clarify in each waiver application for an increase in pipeline maximum allowable operating pressure what maximum specified minimum yield strength (MAOP plus pressure accumulation) it would allow in areas where operators seek to increase MAOP.
This article, the second of two, identifies key issues and concerns to be addressed before granting pressure increase waivers and summarizes observations obtained from PHMSA’s Mar. 21, 2006, MAOP public meeting. The first article (OGJ, June 26, 2006, p. 70) discussed the general context in which the MAOP debate is occurring.
Although MAOP is defined in regulation, not all parties understand that gas transmission pipeline regulations permit pressure accumulations up to 110% MAOP or 75% of specified minimum yield strength (SMYS), whichever is lower (49CFR192.201(a)2(i)). Increasing MAOP to 80% SMYS and adding a 10% pressure-accumulation increase would put peak possible pressures at 88% SMYS, close to the 90% SMYS hydrotest limit.
PHMSA has yet to make clear what accumulation pressure, if any, it will allow for pipelines requesting a 0.8 design factor. For a specific waiver, this accumulation decision should depend on the minimum stress level (minimum hydrotest-MAOP ratio) and timing of the most recent hydrotest. Experience indicates that minimum hydrotest pressures should be 1.25 times MAOP.
Modern pipe steel, assembled into a pipeline with rigorous welding and construction techniques, can withstand pressures well in excess of those contemplated for pressure increases without bursting. Modern steel pipelines include anomalies, but these anomalies may not pose a risk, even during the long life of a pipeline.
Requiring hydrotesting before a pipeline can become operational ensures that pipelines do not contain initial anomalies that can become a problem early in operation.
US pipeline regulations require performing a hydrotest to at least 125% of MAOP for gas transmission lines. A hydrotest in excess of 90% SMYS, therefore, may never have occurred. Many operators perform hydrotests well above 90% SMYS to reduce the size of possible time-dependent anomalies (the greater the hydrotest pressure the smaller the remaining anomalies in the pipe), but this is not required. Integrity management regulations also call for periodic inspection-testing of gas transmission pipelines in high-consequence areas, though hydrotesting is only one option for conducting this reinspection.
US pipeline regulations specify no limit on the upper value of a hydrotest. Some countries, such as Canada, have historically placed a rational upper limit on a hydrotest as the first confirmed deviation in the pressure-volume curve.
A high hydrotest pressure removes or decreases the size of anomalies that remain by taking larger threat anomalies to failure. The major problem pipelines face is how to avoid or spot the specific anomalies that can survive a hydrotest or other inspection and can grow to failure with time, or are added after the last integrity inspection and can grow to failure between inspections at higher operating pressures.
Examples of anomalies that can grow include:
- Corrosion-related-external, internal, or stress-corrosion cracking.
- Pressure-cycling sensitive-seam welds associated with older pipelines, wrinkle bends, and anomalies added by third-party damage that do not fail immediately (a greater problem with modern tougher pipe steel).
The fundamental issue when considering whether to raise pressure on a gas pipeline is determining whether all time-dependent anomalies that could fail at higher pressures have been removed. Anomalies of concern include stable anomalies that could move into the time-dependent category as a result of an operating pressure increase on an already operating pipeline.
Smart pigging has proven superior in identifying general corrosion anomalies in pipelines, especially anomalies that can be exacerbated or introduced after a hydrotest. Smart pigging, however, cannot reliably determine stress-corrosion cracking (SCC) in most gas pipelines. New pipelines virtually eliminate SCC-risk through modern coatings such as fusion-bonded epoxy, prudent construction techniques, and environmental studies evaluating SCC-risk environments. Proper construction-welding records and proper inspections can also usually screen out manufacturing anomalies that might move from stable to time-dependent.
The last major time-dependent risk is latent third-party damage-events that do not cause the pipe to fail when they occur. Even given newer and tougher pipe, such latent anomalies should remain risks when considering pressure increases.
Smart-pigging technology such as magnetic-flux leakage cannot reliably determine risks introduced by third-party damage, such as latent grooves, which can fail as pressures are increased. In the absence of a fairly recent high-pressure hydrotest, therefore, other methods must evaluate whether third-party time-dependent risks are present in a pipeline segment sufficient to disallow a pressure waiver.
Factors affecting this evaluation include: the effectiveness of the pipeline’s damage-prevention program, and how assertively the pipeline operator has maintained the program; the nature of any past third-party damage to the pipeline segment; the condition and width of the pipeline right-of-way; and the lay depth of the pipeline. Horizontal directional drilling poses one of the more insidious time-dependent third-party threats.
MAOP public meeting
PHMSA held a public meeting in Washington, DC, Mar. 21, 2006, to discuss the MAOP increase on gas transmission pipelines.1
Table 1 presents a summary of approximate gas-transmission mileage, as well as permitted maximum design factors, and approximate miles of pipeline currently operating above 0.72% SMYS for several countries.
The US has substantially more gas transmission pipeline miles than the other countries shown. The increase to a maximum design factor of 0.8 spans several decades in Canada and is a more recent development in the UK.
Comparisons between countries must occur in context. For example, Canada has a Pipeline Crossing Regulation right-of-way program that has significantly reduced third-party damage to transmission pipelines in the roughly 18 years since enactment.2 The UK uses distance requirements to define clearances between pipelines and dwellings as well as areas where transmission pipelines are not permitted.
The US has no similar regulations and probably would not enact such rules given its extensive pipeline network and differentiated judicial system.
Third-party damage threats and safety offset differences, however, should play a significant role in decisions to raise pressures through waivers in the US.
Stress is not the primary issue threatening modern steel pipelines. How the operator manages threats to the pipeline through its lifecycle is. Assuming no threat is present, such as presupposing a low corrosion rate, does not constitute prudent threat management. Ignoring the consequences of a possible rupture in a highly populated area also fails as a management practice, and risk assessment should never attempt to compensate for poor route selection.
The lifecycle approaches related to the roughly 5,000 miles of grandfathered gas pipeline operating at more than 0.72 in the US demonstrate these points.3 Superior high-pressure hydrotesting (well above 100% SMYS and completed decades ago), and a litany of management processes throughout the pipelines’ lifecycle have led to their safe operation even at higher design factors.
Pressure waiver concerns
A lifecycle approach is appropriate for certain modern pipelines, requiring that no serious information gaps regarding time-dependent anomalies (beyond simple corrosion) exist. One of the most serious misapplications of risk-assessment principles is using them to fill in critical information gaps or make misleading assumptions or misrepresentations about threats that can lead the pipeline system to rupture failure.
If a pipeline requesting a pressure waiver does not have the documentation to properly address pressure-sensitive anomalies, the waiver should not be granted.
Statements regarding current smart-pig technology indicating that smart pigs can reliably determine grooves or dents with stress concentrators raise particular concerns. These threats are time-dependent and their times-to-failure difficult to predict. Most faults of this sort will also likely fail as ruptures.
The ideal proof test for new pipeline wishing to increase pressures to a design factor of 0.8 is a high-pressure hydrotest (minimum 1.25 MAOP), coupled with 100% girth weld radiological inspections. The high-pressure hydrotest, however, may not always work for pipelines in high elevation-profile environments. Until alternative inspection methods or management can achieve similar results options should be viewed skeptically.
Given the higher operating stress levels for pipelines requesting pressure waivers, operators must quickly report any overpressure events in excess of new pressure limits (MAOP plus approved accumulation pressure) to PHMSA. All MAOP waivers from PHMSA should include a requirement that 49CFR191.23(b)(4) does not constitute a condition to avoid timely (within 24 hr) reporting of an overpressure event above the waived limits. This reporting should not pose a problem and will assist PHMSA in proper use and confirmation of important risk-management applications on higher-stress pipelines that have received waiver approval.
Beyond reducing the likelihood of a pipeline failure as pressures are increased, prudence dictates that PHMSA also review the consequence of any failure in completing pressure-increase waiver requests. The potential impact zones associated with pipeline ruptures at higher pressures will expand because of the higher mass flow of the greater gas density and pipeline inventory.
Inspections, therefore, must incorporate additional segments of the pipeline-perhaps not adequately captured by previous inspections or tests with the smaller, empirically derived, lower-pressure potential impact circles utilized in current regulation-and review population density. This holds especially true for waiver requests where operating pressures are increased significantly in Class 2 or 3 areas, or when Class 1 areas become Class 2 or 3 areas as a result of development.
Appropriate impact-zone calculations based on more scientific methods must take place, especially for higher-pressure and larger-diameter pipelines, given the lack of US offset regulations. Even a relatively small-diameter pipeline, such as the 20-in., thick-walled, high-pressure Corrib project in Ireland, can have large impact zones, well off the regulatory chart and beyond potential empirical impact correlations, as pressures or rupture-mass flows approach the exotic.4
US pipeline operators considering a significant pressure increase should demonstrate clearly that their impact circles are based on rigorous impact-zone calculations, not simply minimum federal regulatory screening standards.
The process used to grant waivers must remain public, and pipelines that receive approval should be required to notify the public along the pipeline right-of-way well in advance of the increase. Notification to those along the pipeline should also extend well beyond the potential impact zones defined in current federal pipeline regulations.
International standards have demonstrated operational success for the higher 0.8 design factor in lower-population areas. Many of these standards, however, also mandate setback distances from pipelines, while US pipeline regulations do not. This does not mean that technical lessons learned from other countries should not be applied to pipelines in the US, only that such application should happen in full context.
References
- http://primis.phmsa.dot.gov/meetings/MtgHome.mtg?
mtg=40&s=3C926B4D78B845F1ADCE449D3A2F8EEA&c=1 - Van Egmond, Chris, PHMSA Mechanical Damage Technical Workshop, Houston, Feb. 28-Mar. 1, 2006, http://primis.phmsa.dot.gov/rd/mtg_022806.htm
- PHMSA Natural Gas Maximum Allowable Operating Pressure for Class Locations public meeting, Reston, Va., Mar. 21, 2006, http://primis.phmsa.dot.gov/meetings/Mtg40.mtg
- Kuprewicz, Richard B., “The Proposed Corrib Onshore System-An Independent Analysis,” Center for Public Inquiry, November 2005, http://www.publicinquiry.ie/reports.php