A few weeks ago British Petroleum, administrator and partial owner of Alaska’s Prudhoe Bay oil field, announced that recent tests had revealed corrosion in the pipeline system and shut down production. With production partly restored, BP officials say tests have shown that the corrosion is isolated and normal flow may return soon. Ultrasound tests are being made to determine how much of the shut down pipeline can be returned to service temporarily. Tempers have cooled along with the media coverage, but BP still faces a costly rebuilding project.

BP only discovered the current corrosion problems after a significant oil spill prompted a survey of the pipeline system. In March, a transit line in the North Slope system, which BP operates on behalf of itself, Conoco-Philips and Exxon Mobil, gushed 201,000 gallons of oil onto the tundra, the North Slope's largest oil spill ever. The spill brought new regulatory scrutiny and a grand jury investigation of possible criminal charges.

Was all the trouble avoidable? Experts say not only have the anti-corrosive properties of steel improved, monitoring technologies have also advanced during the last 30 years. Most companies now consider regular use of smart pigs, which employ magnetic fields or ultrasonic technology to detect worn areas, good operating procedure. BP officials said they have not recently used smart pigs at Prudhoe Bay because they thought their monitoring system was sufficient.

Crouch: Age doesn’t matter.

ENR.com’s Jeffrey Rubenstone interviewed Alfred Crouch, a staff engineer in the applied physics division of the San Antonio-based Southwest Research Institute, about the latest methods and practices in pipeline inspection. Crouch is a licensed professional engineer and a Fellow of the American Society for Nondestructive Testing.

ENR.com: What would you consider to be a normal schedule for smart pigging of oil pipeline systems?

AC: The government has mandated that hazardous liquid pipeline operators implement Integrity Management Programs (IMPs) that detail their proposed use of smart pigging or other investigative methods to determine the condition of their high-pressure pipelines in high-consequence areas and to identify segments that may need repair or replacement.  Assessment intervals are typically specified to be no more than five years, though variances may be granted for pipeline segments where it is justified on an engineering basis or because there is no applicable internal inspection device available.  In those cases, alternative means of integrity assurance must be proposed.

BP’s Prudhoe Bay pipeline, it should be noted, is a low-pressure pipeline. I’m not familiar enough with what they do to comment on its maintenance.
Although the government allows use of either smart pigging, hydrotest or a non-invasive approach known as Direct Assessment (DA), most liquid pipelines readily accept smart pigs and the liquid pipeline industry has taken the lead in use of smart pigging for integrity assurance. 

The smart pigging interval appropriate for an individual pipeline segment will depend on a number of factors, including the history of previous corrosion or other defects, the use of other monitoring technologies, the operating pressure of the line, the nature of the specific product carried by the line and the potential consequences of a leak or rupture.

Related Links:
  • BP Closes Prudhoe Over Corroded Pipes,
  • BP Could Have Saved $170M with Better Monitoring,
  • Engineer Warned BP on Pipeline
  • ENR.com: What are the major threats facing an oil pipeline system that needs this type of monitoring? What are the primary causes of corrosion?

    AC: The major pipeline threats include corrosion (metal loss), excavation-induced damage and material defects including cracking. Corrosion can occur at the inside surface or outside surface of the pipe. Internal corrosion can be caused by water, carbon dioxide or some other contaminant in the pipeline. External corrosion can occur when the pipeline’s protective coating deteriorates or is damaged. Exposure of the steel pipeline surface to ground water can create an electrolytic cell that causes the iron component of the steel to rust and flake off, reducing the pipe wall thickness. The presence of bacteria and their byproducts can accelerate the corrosion rate resulting in deep, steep-edged pitting. 

    ENR.com: What are the limits of this testing, and are there other nondestructive methods besides smart pigging to monitor pipelines for weaknesses and corrosion?

    AC: Smart pigging is generally recognized as the most comprehensive and most definitive method for pipeline integrity assurance for those lines that can accept smart pigs. Some pipelines, due to their construction or due to low operating pressures or low flow rates, cannot support effective smart pigging. For those lines, two alternatives are hydrostatic testing and Direct Assessment. Hydrostatic testing requires that the pipeline be filled with water, pressurized to a level exceeding the normal operating pressure and then maintained at that pressure long enough to determine whether there are any leaks. Hydrotest gives the operator confidence that the pipeline will be able to operate at its designated pressure without leaking or rupture. It reveals nothing, however, about the presence of sub-critical defects that may grow to failure in the future.

    Direct Assessment is a relative new-comer to the pipeline integrity toolbox.  If past history and operating parameters are used to model a pipeline, one can prioritize segments of the pipeline with regard to their potential for containing corrosion or other threats. Follow-up examination of those segments with local nondestructive testing or other measurements will reveal whether the high-priority segments are in fact experiencing corrosion or other defects. If no problems are found in these areas, the operator gains confidence that the rest of the pipeline is safe. An important component of DA is the routine monitoring of cathodic protection potentials. This monitoring can reveal locations of potential corrosion.

    ENR.com: What changes, if any, have you seen in pipeline monitoring technology over the last few years, and are there any better, more accurate methods appearing on the horizon?

    AC: The evolution of smart pigging has progressed on three fronts: Increasing the range of threats detected, increasing defect detection and characterization capability and tolerating a wider range of environments and operating conditions.
    The very earliest smart pigs detected geometric anomalies such as dents and pipe ovality only. Corrosion detection followed and now there are additional pigs designed for crack detection, pipeline survey (mapping) and weld defects.  
    Corrosion pigs began as so-called “low-resolution” inspection tools. Their sensors each covered several inches of pipe circumference, so they were not able to accurately characterize (measure) defects smaller than that dimension. Today’s “high-resolution” tools use hundreds of sensors, each a fraction of an inch in extent, to produce detailed maps of corrosion defects and more accurate assessment of defect severity for the pipeline operator. Another recent smart pig enhancement has been the introduction of ultrasonic measuring technology.  

    The de-facto standard technology for corrosion smart pigging has been the magnetic flux leakage (MFL) method in which the pig carries strong permanent magnets and applies a magnetic field to the pipe wall. The amount of magnetic flux that the wall can contain is strongly influenced by its thickness and magnetic properties. This magnetic flux is measured by appropriate sensors and stored as an indication of the loss of wall thickness (depth of corrosion). MFL is an inferred method of wall measurement. Ultrasonic measurement, on the other hand, is a more direct measurement of remaining wall thickness using a technique similar to sonar. Ultrasonic corrosion pigs carry an array of ultrasonic transducers that generally require a liquid environment (a couplant) to couple ultrasound into the pipe wall.
    Smart pigs are often constructed as a train of modules connected by universal joints to allow the pig to negotiate bends in the pipeline. For relatively small diameter pipelines, early pigs could not be used in pipelines with tight bend radii, so those lines were deemed “unpiggable.” Current pig designs have largely overcome those limitations.  

    Smart pigs have a preferred speed range of two to seven miles per hour, rendering them unusable in high-throughput gas pipelines that may operate at more than twenty mph. New pig designs incorporate gas bypass capability that allows the gas to flow through them at high speed while the pig moves at its optimum slower speed.  
    And finally, the fact that ultrasonic technology was limited to liquid lines because of the couplant requirement has led to the development of electromagnetic acoustic technology (EMAT) smart pigs that can apply ultrasonic measurement in gas pipelines.

    Research in smart pigging is continuing with work sponsored by the pipeline industry and by government sources such as the U.S. Department of Transportation’s Pipeline Hazardous Materials Safety Administration (PHMSA). Current research, if successful, will bring better assessment methods for mechanical damage, will expand the smart pig capabilities to cover previously unpiggable pipelines and will provide new improvements to direct assessment technologies. 

    ENR.com: Are there particular problems that affect aging pipelines, near or exceeding their intended lifespan, as opposed to newer ones?

    AC: The threats to pipeline integrity are generally common to all pipelines without regard to their age. Corrosion can occur on new pipelines as well as old ones. Excavation-induced damage is a generally random occurring threat, so it is reasonable to expect that a line that has been in service for a long time would have a greater probability of experiencing one of those events than a new line.  
    The steel in a pipeline does not experience significant aging. Its properties after 50 years will not be much different than when it was new. The critical issue is whether the steel was protected from the pipeline’s environment and whether proper response was applied when defects were discovered.

    ENR.com: Is regular pigging just a matter of good practice, or is it generally accepted as necessary maintenance?

    AC: Regular use of cleaning pigs in liquid pipelines is a matter of good practice. A clean pipeline can deliver more product with less energy consumption than a dirty one, so there is economic justification for keeping the line clean. Beyond that, one should be concerned that substances left in the line may directly or indirectly promote corrosion of the pipeline. The government does not require regular cleaning pigging, so it is not necessary from that standpoint, but many pipeline operators consider it a necessary part of their maintenance programs.

    ENR.com: In your own experience, does observed corrosion in pipeline systems always indicate imminent failure, or is there some threshold of wear-and-tear that must be reached? Essentially, can a worn pipeline continue to be used without fear of failure in the near future?

    AC: First, let me comment on the terms “wear-and-tear.” Machines with moving parts experience wear from the friction between their parts. Although there are friction effects between a pipeline wall and its moving product, the wear is negligible. Degradation of a pipeline comes primarily from outside force or the interactions between the pipeline and its environment.

    Observed corrosion in a pipeline only rarely indicates imminent failure of the line. Light corrosion (for example, 10% loss of wall thickness) is never a cause of concern. On the other hand, if there is 80% loss of wall thickness, the pipeline operator must take immediate action to shut down or reduce the operating pressure to a safe level and repair the pipeline. There are other prescribed measures to be taken for other defects such as dents with gouges, lesser amounts of corrosion, grooves, etc. 

    Generally accepted assessment calculations are available to determine the safe pipeline operating pressure for corrosion defects, when their depth and other dimensions and the mechanical properties of the pipe steel are known. The pipeline operator relies on physical measurements after smart pigging and the use of these calculations to decide whether to replace, repair or to continue operating with careful monitoring. Corrosion failures of pipelines that are carefully maintained are rare. Smart pigging can detect and measure corrosion at a level well below the level critical for pipeline safety. Smart pigs are not perfect, however, in most cases, they will warn the pipeline operator well before growing corrosion reaches a level that threatens pipeline failure.