US PIPELINE REGULATIONS-1: Increasing US natural gas lines’ MAOP requires close study

June 26, 2006
Increasing the maximum allowable operating pressure of US gas transmission pipelines requires careful consideration and must be done on a case-by-case basis.

Increasing the maximum allowable operating pressure of US gas transmission pipelines requires careful consideration and must be done on a case-by-case basis.

A higher maximum stress level (as a percent of specified minimum yield strength, or SMYS) for various class locations (increasing the maximum design factor to 0.8 from 0.72), allowing higher design factors in class locations, and waiving traditional pressure testing requirements usually mandated for class-location changes would allow the MAOP of certain US natural gas transmission pipelines to be increased.1 2

A higher design factor allows the pipeline operator to increase pressures, improving gas pipeline efficiency through a combination of opportunities to raise the capacity of existing pipelines, reduce the capital cost of new pipelines (lower steel and welding costs from thinner, higher-strength pipe), and reduce operating costs through a higher density gas flow and associated reduced friction loss.

PHMSA (Pipeline & Hazardous Materials Safety Administration) must approve these changes with a pipeline-specific waiver made through a public notification process. The Maritimes and Northeast Pipeline, Alliance Pipeline, and Rockies Express Pipeline all recently applied for waivers to increase MAOP.3

A waiver process should permit pressure increases on specific pipelines or pipeline segments that can properly demonstrate that critical process elements related to a pipeline’s lifecycle have occurred and are effective. These process lifecycle elements include: design, material, construction-initial testing, operation, and maintenance.

The pipeline operator, not PHMSA, must demonstrate that the lifecycle elements are thorough and complete. PHMSA may set additional requirements through the waiver process, such as requiring smart pigging on all high-stress pipelines, or mandating improvements in third-party damage prevention programs as conditions of a specific waiver. All waivers should include the requirement that they may be revoked should PHMSA determine conditions authorizing them have not been met during the lifecycle of the pipeline.

While this article, the first of two, focuses primarily on gas, a brief discussion is also presented on why increasing pressures on liquid pipelines may not be as viable or economically advantageous, and as a result should be much more limited. The second article summarizes observations obtained from PHMSA’s Mar. 21, 2006, MAOP public meeting and identifies additional key issues and concerns which need to be addressed before granting pressure increase waivers.

Lifecycle approach

Pipelines have a limited life. But a properly managed steel pipeline can remain in service for significantly more than 100 years. A pipeline not properly managed, or treated recklessly, lasts for a considerably shorter time, even if constructed with modern techniques.

In issuing the June 29, 2004, public notice for class location change waivers, PHMSA listed a set of threshold requirements (see box), along with an extensive chart identifying three levels of acceptance criteria: “probable,” “possible,” and “requires substantial justification.”1

Given the large economic incentives behind gas pipeline pressure increases, it can be tempting to overstate the effectiveness of certain elements in a pipeline lifecycle to gain approval. Applicants must avoid attempts to rush approval with incomplete engineering analysis or poor risk-assessment techniques to fill critical information gaps needed to make proper decisions about waiver requests.

Special precautions must ensure that all elements in a pipeline’s lifecycle are satisfactory, providing multiple levels of independent safety protection to ensure pipeline containment. Over-reliance on only one element, such as integrity management in a maintenance program, or serious gaps in critical lifecycle information, substantially reduce the effectiveness of checks and balances, increase risks of failure by many orders of magnitude, and negate the intent of performance-based safety approaches.

Waiver requests where serious information gaps may exist (e.g., “requires substantial justification”) may require a very high-pressure hydrotest, well in excess of minimum federal limits (100% SMYS), and a combination of other management practices to overcome critical lifecycle information deficiencies and acquire a waiver.

Poor construction techniques which may be missed as a result of serious gaps between FERC and PHMSA pipeline oversight regarding construction inspection can greatly increase pipeline risks.4

FERC rarely inspects during construction activities (lacking the safety responsibility, experience, manpower, and background). And neither PHMSA nor its interstate agents take jurisdiction until the pipeline has been placed in service. This inspection gap can create situations that substantially increase the potential for time-dependent anomalies to enter a pipeline during construction.

Responsible US pipeline operators, though not obligated to do so, take extra quality precautions to avoid introduction of such anomalies. Many other operators, however, only comply with the minimal requirements and don’t adequately address this exposure.

Why increase MAOP?

The shift to decentralized gas-fired power plants is driving most of the US growth in gas demand. It is not unusual for large gas pipeline projects to cost several billion dollars. Given the considerable transmission infrastructure already in place (about 300,000 miles), operators of both old and new gas lines are under considerable financial pressure to achieve the greatest possible efficiency.

Problems associated with expanding or developing new pipeline rights-of-way in segments of the country where open space is at a premium add to the complexity of discussion.

All hydrocarbon streams moved in pipelines are compressible. The volume of the material changes as a function of pressure and is usually stated as the inverse of the bulk modulus (C = -1/BM). Gases are highly compressible and follow well-defined thermodynamic principles relating density to temperature and pressure.

Liquid hydrocarbon streams are much less compressible than gases. Because liquid hydrocarbons are usually a complex mixture of many hydrocarbon compounds, the bulk modulus is typically stated as a range for liquid products. For example, the bulk modulus for gasoline at 60º F. is between 125,000 and 150,000 psi.

The high compressibility of gas pipelines causes the system pressure loss associated with flow to drop along the pipeline as the pressure is increased because the actual gas velocity, the velocity calculated at the pressures and temperature within the pipe, falls. The efficiency of moving gas along a pipeline for a fixed-mass flow therefore increases (less system pressure loss) as the pipeline pressure is raised.

Other factors eventually limit pressure increases. For example, liquid can separate out of gas at higher pressures, causing multiphase flows which can induce slug-force loading stresses on pipelines as well as other operating complications.

Given the high potential of modern technological advances to increase gas pipeline efficiencies while maintaining proper levels of safety, pressures can be increased on certain gas transmission pipelines subject to the conditions mentioned earlier. Such waiver pressure increases, however, should not be granted lightly or across all pipelines, even new pipelines, if critical information is missing, technological capabilities overstated, or risk-assessment approaches misapplied.

Liquid pipelines

While the proposed pressure increase applies only to gas transmission pipelines, a brief discussion on liquid pipelines is warranted to help explain why such an increase is not suited for most liquid systems. US pipeline regulation does not use the class location-design factor approach, and most liquid pipelines operate under a single maximum design factor of 0.72 throughout their system, with a permitted 10% overpressure accumulation which could take a liquid pipeline to 79% SMYS.

Hydrocarbon liquids are 100 to 150 times less compressible than gas in transmission pipelines. As a result, only increasing the liquid velocity can increase capacity or throughput. Unlike gases, for which increasing the pressure can reduce actual velocity, velocity on a liquid pipeline directly relates to the capacity increase, as density will not change significantly.

As the velocity of a pipeline increases, the system pressure drop increases by a power of two and the horsepower requirements by a power of three. For a liquid system, therefore, doubling the capacity doubles the velocity, prompts a fourfold increase in system pressure loss (22), and increases horsepower requirements by a factor of eight (23).

Many liquid pipeline systems face demands to increase throughput on systems already at the upper end of their velocity spectrum. No standard limits the velocity of a liquid pipeline. There are some guidelines, however, and many companies also have their own design limits, which can vary considerably.

As velocities increase, a management team must incorporate other design system considerations to ensure that a surge won’t cause the system to lose pressure control. These considerations usually affect operations well before so-called “erosion velocity” limits take over. The greater the velocity, the more significant the system design complexities or safeties needed to avoid overpressure situations which can break the pipeline’s hydraulic profile.

This combination of reduced compressibility, actual velocity, increased system pressure loss, marked horsepower requirements, and surge exposure usually drives the economic decision toward new pipeline (or looped parallel pipeline) rather than increasing maximum operating pressure to meet additional capacity requirements for most existing liquid pipelines.

The economic benefits of increasing operating pressures in liquid pipelines are thus limited to systems that can accept rational higher velocity, usually larger-diameter pipelines operating at the lower end of their velocity spectrum. A very limited number of older pipelines can realize savings by delaying additional pump-station capital costs and instead increasing maximum design pressures. New liquid pipelines can save on pipe metal with thinner pipe.

US gas transmission

For a given pipe diameter, thickness, and grade, which are usually fixed, design factor determines MAOP (the higher the design factor, the greater the permitted pressure). Table 1 presents the current design-factor limitations defined by US federal pipeline regulation (49CFR912.11-Design Factor (F) for steel pipe) and offers a breakdown by class location of the roughly 300,000 miles of US gas transmission pipelines.

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Building density drives location classification in the US. A higher class-location number indicates greater building density near the pipeline, with the assumption of a higher population density as well. US pipeline regulations do not set buffer distances between pipelines and buildings or major gathering centers, as is required in some other countries.

The vast majority of US gas transmission pipelines (Class Location 1) use a MAOP of 72% of SMYS (a design factor of 0.72). Exceptions to this limitation exist, such as the roughly 5,000 miles of Class 1 gas transmission pipelines grandfathered to operate at higher stress levels prior to enactment of federal pipeline regulation.

Of the 300,000 miles of pipeline, about 7% (20,000 miles) require inspection under the new gas integrity regulations defining high-consequence areas. To date, about 33% of gas transmission pipelines within HCAs have been inspected. When additional pipelines inspected outside HCAs are included, the total inspected pipeline undergoing integrity management increases to about 50,000 miles.5


  1. OPS Notice Docket No. RSPA-04-17401, “Pipeline Safety: Development of Class Location Change Waiver Criteria,” June 29, 2004.
  2. OPS Notice Docket No. RSPA-05-23447, “Pipeline Safety: Reconsideration of Natural Gas Pipeline Maximum Allowable Operating Pressure for Class Locations,” Jan. 6, 2006.
  4. Washington State Citizens Committee on Pipeline Safety Meeting, Mar. 16, 2006.
  5. Mohn, Jeryl L., “Testimony on Behalf of INGAA Before the Subcommittee on Highways, Transit and Pipelines Committee on Transportation and Infrastructure U.S. House of Representatives,” Mar. 16, 2006.

The author

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Richard B. Kuprewicz is president of Accufacts Inc., an energy consulting firm based in Washington state since 1999. He brings more than 33 years of operational and engineering experience in the industry to the position, offering special focus on appropriate pipeline design and operation in areas of unique population density or of an environmentally sensitive nature. Kuprewicz holds BS degrees in chemical engineering and chemistry from the University of California at Davis and a master’s in business administration from Pepperdine University at Malibu, Calif..

Based on paper prepared for the Pipeline Safety Trust.

PHMSA class waiver threshold requirements

  • No pipe segments changing to Class 4 locations will be considered.
  • No bare pipe will be considered.
  • No pipe containing wrinkle bends will be considered.
  • No pipe segments operating above 72% SMYS will be considered for a Class 3 waiver.
  • Records must be produced that show a hydrostatic test to at least 1.25 × MAOP.
  • In-line inspection must have been performed with no significant anomalies identified that indicate systemic problems.
  • Up to 25 miles of pipe on either side of the waiver location must be included in the pipeline company’s integrity management program and periodically inspected with an in-line inspection technique.