January 2019, Vol. 246, No. 1

Features

MAOP Reconfirmation via Hydrotest – Considerations for Success

By Colin Silla, District Manager, Gas Transmission Systems (GTS)

For many years, hydrostatic testing of pipelines has been used to ensure fitness for service by ruling out manufacturing and construction related defects. Current federal code requires hydrostatic tests for newly installed natural gas transmission pipelines and is outlined in Subpart J of 49 CFR, Part 192.

The testing requirements were modified from ASME B31.8 by the Office of Pipeline Safety/DOT and included into the federal code in 1970 as requirements to establish the Maximum Allowable Operating Pressure (MAOP) of pipelines. The code included a clause allowing operators to continue to operate their pre- 1970 pipelines at the highest operating pressure experienced during the five years preceding July 1, 1970 as MAOP.

This method of establishing MAOP is referred to as the “grandfather” clause. Recent regulatory changes will eliminate the grandfather clause and tighten requirements on historical records of post 1970 tests. Operators may be required to test pipelines that have been in operation (in-situ) for over half a century.

While the principles of hydrostatically testing a 50-year-old pipeline compared to testing a new pipeline are essentially the same, the execution can be vastly different. This article highlights some of those differences and shares lessons learned by GTS from testing over 1,000 miles of in-situ pipelines, primarily to validate MAOP.

Code Updates

PHMSA announced its intentions to finalize the rule making for the Pipeline Safety Act of 2011 in three parts starting in March of 2019. The Pipeline Safety Act of 2011 is commonly referred to as the “Mega Rule” for its widespread changes to natural gas regulations within the federal code.

The bulk of the rulemakings will come in the first phase, with the second and third parts having less widespread impacts. The elimination of the grandfather clause is one of the myriads of changes in the notice of proposed rulemaking, stemming from the Mega Rule.

A recent publication by the Gas Pipeline Advisory Committee (GPAC) estimated nearly 6,800 miles of pipeline have an MAOP established via the grandfather clause. Furthermore, the rulemaking prescribes stringent guidelines on acceptable documentation for pipelines installed post-1970, which had a hydrostatic test performed.

If operators cannot defend documentation as “Traceable, Verifiable and Complete” (TVC) they may need to reconfirm MAOP of those lines as well.

Moving forward, operators will need to reconfirm the MAOP on these older lines via one of six proposed methods:

1) Hydrostatic Test, 2) Pressure reduction commensurate with an existing test factor, 3) Perform an engineering critical assessment, 4) Pipeline replacement, 5) Pressure reduction on lines operating <30% of SMYS, or 6) Other approved alternative technology

The logistics of planning and anticipated challenges can seem daunting.

Method 1

Even though there are six proposed methods for reconfirmation of MAOP on pipelines without a valid hydrostatic test, operators may easily find themselves with limited options.

For example, in most cases, pipeline replacement will likely be cost prohibitive for longer lengths, particularly in urban areas, and pressure reductions might not be feasible assuming a pipeline normally operates only slightly under its historical MAOP.

Finally, alternative technologies may require lengthy justification and regulatory approval or end with the request being denied. Because of these limitations, operators may quickly be reduced to the option of hydrostatically testing their lines.

Hydrostatic Testing

My typical over-simplified elevator pitch of a hydrostatic test for those not in the industry is that water is injected into a pipeline, the ends are sealed, and the line is pressurized to a factor above what it typically operates at, to provide a factor of safety when it is placed in operation.

Those in the industry know a hydrostatic test is a much more complicated process. Factors such as maintaining a consistent fill to eliminate air pockets, accounting for hydrostatic head, staying within a given pressure range, de-watering, drying and tie ins can all be challenging aspects of any given hydro- static test. However, when testing an in-situ pipeline, that may only scratch the surface.

Hydrostatic Test

In addition to the challenges of testing a new line, testing an in-situ pipeline presents a whole slew of additional challenges that need to be addressed:

Validate Features and Attributes of the Line: In order to establish TVC records it is imperative to do a comprehensive review of all records and features on the line to be tested.

The information found should be consolidated into a pipeline features list (PFL), a comprehensive database for all pipeline asset information that is integrated into the operator’s GIS system of record.

The PFL is a valuable resource for pre-planning and engineering to identify problematic features that may inhibit execution of the test (e.g. an unpiggable valve), and to identify all physical characteristics of the pipe and appurtenances to be tested so appropriate test pressures can be determined and confirm that the desired MAOP can be established.

For example, the PFL will help identify a lower strength pup or deter mining if a fitting can tolerate the desired test pressures based on its manufacturing specification and ratings.

Outage Management/Planning: The biggest difference between an in-situ line and a new line is that the in-situ line has been (and likely still is) in operation. In many cases, the line cannot be easily taken out of service without impact to customers.

Once the test section of an in-situ test has been identified, the operator must consider the impact to core and non-core customers fed by the pipeline and all options for maintaining service; whether service can be back fed from other systems, cross-tied to another pipeline, or perhaps reinforced with a downstream distribution crosstie. However, if the sole source of gas is from the pipeline to be taken out of service, the operator must consider the impact of curtailment to noncore loads.

Whether there is planned maintenance or low demand periods that the test can be planned around is another factor to consider. In cases in which the customer cannot be taken out of service temporary supply must be considered. There are many scenarios to evaluate when considering using CNG or LNG. In some cases, rural single feed customers have been fed from small volume CNG cylinders mounted on trailers.

Another option is to supply district regulator stations via CNG tube trailers to support the demand. In one extreme case, half a dozen LNG trailers were routinely swapped out as they injected at about 900,000 standard cubic feet per hour (scfh) into a manifolded system to keep a large city supported when their radial line needed to be taken out of service.

Cleaning and Contaminants: Another distinction between an in-situ line and a new line is possible introduction of contaminants over the years. Operator GTS has worked with have encountered mercury, Polychlorinated biphenyls (PCB) oils, varying amounts of scale or “black powder,” and liquids that could host a litany of other nasty items.

The concern here is not just the toxins themselves, but the likelihood they will contaminate large volumes of hydrostatic test water and 1) be released in the event of leak or rupture and 2) limit operator’s ability to economically dispose of the water.

Most often, permits to discharge water dictate water quality requirements. These contaminants can be collected, removed and contained in much more cost-effective manner before water is introduced into the pipeline.

Operators should consult with their field operations and environmental teams to determine if there has been any history of contaminants found in the pipeline via routine operations and maintenance (O&M) or prior modifications and develop a detailed cleaning plan to ensure the line is clean prior to introducing test water. Water samples should be taken via a rinse run to determine if the cleaning has been adequately performed prior to fill.

Pigging and Impediments: The line needs to be able to at minimum accommodate poly and brush pigs to facilitate the cleaning operation and hydrostatic test. If the pipeline was installed prior to 1970, there would likely have been little, if any, consideration to making the line “piggable.”

Smart pigs were not around, and a hydrostatic test may not have been required, so there was no basis to consider piggability. Consequently, common design and construction practices included unpiggable features such as: reduced port ball valves, plug valves, short radius elbows or large degree miters, unbarred branches/tees, inserted drips, and pressure control fittings.

More uncommonly, pigging impediments such as protrusions into the line from antiquated tapping methods, leftover construction debris of all shapes and sizes, and even a telecommunications cable strung many miles within one particular pipeline have been encountered. While an operator must prepare the line to accommodate pigging for the hydrostatic test, consideration should be given to performing additional retro- fits to accommodate smart pigs for future direct assessments (DA).

Final Considerations

It is important to note that in-situ tests are costly, and effort should be made to maximize opportunities while this test is performed. Given the extended clearance necessary, the entire line should be evaluated for additional O&M opportunities such as fixing leaking valves, transferring/upgrading services, replacing fittings to accommodate longer pig trains (not just hydrotest pigs).

Additionally, operators should also take the pipeline’s integrity management (IM) assessment into account when determining test pressures. Hydrostatic testing is an accepted method for performing DA as outlined in Subpart O, and ASME B31.8S provides a table which contains IM re-assessment intervals commensurate with various hydrostatic test pressure multipliers. In considering an extension of DA reinspection intervals, careful evaluation should be performed to determine whether the test pressure can be increased to meet these multipliers without risking unnecessary damage to the pipeline. Finally, operators should consider a spike test when testing in-situ pipelines to reconfirm MAOP or as DA.

Proper use of a spike test will minimize the size of any “just surviving” (subcritical) flaws that remain after the test, extending the useful life of the pipeline and essentially eliminating the potential for crack growth during the test. However, many opponents to spike testing are quick to point out the risk/reward citing potential damages that can be introduced on the line.

Currently, whether spike testing will be required in the final rule to establish MAOP in certain situations is unknown. It is generally agreed from industry experts that a spike test is only effective if the pressure reduction following the spike period is at least 10% of the spike pressure and the spike duration be as short as possible around five to ten minutes.

Conclusion

While hydrostatic testing is not the only method by which an operator may reconfirm previously grandfathered MAOPs, there is a likelihood that it will be widely applied. Costly lessons learned can be avoided by implementing a sound plan considering the elements above.

The proposed rule allows the operator 15 years to reconfirm MAOP on affected pipelines – those grandfathered or without TVC records. Operators should plan carefully before jumping into what can be a complicated hydrostatic pressure test. P&GJ

Author: Colin Silla is a mechanical engineer with eight years of experience in the natural gas pipeline industry. He serves as the southeast district manager overseeing the Atlanta, Ga. office for GTS and is member of the TIMP committee for AGA. He holds a PMP certification, and has earned a master’s degree in mechanical engineering, as well as an MBA with an emphasis in finance and organizational strategy.