Remedies to maintain pipeline integrity

In many countries, hydrocarbons are transported by way of buried pipelines. In North America, crude oil and some of its refined products are shipped mainly by pipelines and, as of late, increasingly by rail. This switch to rail transportation has been, in part, a result of opposition to the construction of new pipelines that transport hydrocarbons. Unfortunately, there have been many incidents of train derailments where tanker cars carrying hydrocarbons have caused environmental damage. Additionally, in 2013, a train derailment in Lac-Mégantic (Canada), resulted in the deaths of 47 people. The 74 tank cars that derailed were carrying crude oil.

Opponents, both environmental and political, cite the many incidents of pipeline leaks or ruptures that have resulted in catastrophic environmental damage to lakes and rivers, as well as being a potential danger to the people living near a pipeline right-of-way. One of the main causes of pipeline failure is corrosion, and corrosion is preventable.

A combination of cathodic protection (CP) and coatings are used to prevent external corrosion on buried and submerged pipelines. Coatings are the primary source of protection for a pipeline and are supplemented by the use of CP. Coating failure exacerbates any attempt to maintain pipeline integrity. Adding additional CP to compensate for coating failure is difficult at best, and may not be effective in preventing corrosion.

Coatings for pipeline corrosion protection

Pipelines that have been built over the last 30 years are generally coated with fusion bonded epoxy (FBE), three layer polyethylene (3LPE), three layer polypropylene (3LPP), liquid epoxy and urethane, extruded polyethylene (PE) and cold applied tapes. The coatings that were used in the 1960s - 1980s included coal tar enamels, asphalt enamels, cold applied tapes, wax and mastics.

Only general reference will be made to specific coating types when discussing coating attributes and why coatings fail in this article. Moreover, coating attributes and limitations will be stated throughout. They are given as a general guideline for coating selection for new pipelines, and also to consider what may be happening to an existing coating.

Coatings are mandated for newly constructed pipelines the energy industry. Many of the aforementioned coating systems would not be approved for new construction based on past performance.

Whether stipulated or not, in construction permits, pipeline coatings should possess the following properties:

• Electrically isolate the external surfaces of the pipeline from its environment.
• Have sufficient adhesion to resist under film migration of electrolytes.
• Be sufficiently ductile to resist cracking.
• Resist damage due to normal handling and soil stress.
• Be compatible with CP.
• Resist deterioration due to the environment and service temperature.

Why coatings fail

Werner1 defines coating failure as follows: “A buried pipeline coating has exceeded its useful life when adequate CP can no longer be economically maintained.” All coatings will deteriorate with time, some more than others. The rate and amount of deterioration depends upon the coating, pipeline operating temperature and environment. Generally, coatings fail as a result of poor surface preparation, wrong choice and/or improper application.

Surface preparation

Most of today’s high performance coatings require a near-white blast cleaned surface with a sharp peak to valley profile of at least 1.5 mm. Additionally, prior to blast cleaning, the pipe surface should be free of soluble salts, principally chlorides and sulfates. If present, these salts would need to be removed prior to application.

Epoxy coatings (liquid and FBE) are the coating of choice for most large diameter (greater than 304 mm) pipeline systems. These epoxies are used as the primary coating system or in combination with PE or polypropylene. Epoxies can absorb moisture. When a semipermeable membrane separates a solution of different concentrations, the water permeates from the concentrated solution to the dilute solution. This is known as osmosis. The application of CP will facilitate osmosis, resulting in a process called electro-osmosis. The presence of dissolved salts on a pipe surface may result in an osmotic pressure build up and disbond the coating (usually observed as blisters). These areas of disbonded coating require increased CP current.

Any coating would benefit from a properly prepared surface, even those that call for a power wire brushed surface, as was the practice for asphalt, coal tar enamels, mastics and tapes.

Poor surface preparation results in reduced adhesion of the coating to the pipe surface. Loss of adhesion can occur from forces applied during construction, while in operation and from chemical interaction.

Wrong choice of coating

Pipeline operating temperature

When selecting a pipeline coating, the system’s operating temperature must be taken into consideration and must account for excursions above the initial design. A pipeline’s maximum operating temperature must be considered during the selection of a coating.

Soil stress

Mechanical forces in clay soils can cause coating damage to tapes, mastics, coal tar and asphalt enamels through abrasion as a result of pipe movement. Even with a blast-cleaned surface, these coatings do not exhibit sufficient adhesion to resist soil stress and soil loading.

Epoxies, three layer systems and extruded PE are not affected by soil stress or soil loading.

Piping installed by horizontal directional drilling (HDD) should be coated with an abrasion resistant coating, such as an epoxy or urethane to prevent damage during installation. Coal tar and asphalt enamels, tapes and mastics are not abrasion resistant coatings and would undergo extensive damage if used for HDD.

Improper application

Inspect, inspect, inspect. This cannot be stressed enough. Inspection of the coating should be done at all stages of the coating process by qualified personnel. If a pipeline coating fails in service, the integrity of the pipeline will be compromised.

Coating influence on pipeline integrity

CP

In the oil and gas industry, CP is a requirement for corrosion protection in order to maintain the integrity of a buried or submerged pipeline. CP is an electrochemical technique in which a flux of electrons is sent into a metal. This increases the negative charge at the metal surface and, in the case of a pipeline, retains the Fe++ cations in the metal, thus, preventing oxidation and corrosion. In practical terms, a current is sent through an electrolyte from the anode to the cathode (pipeline). Coatings are the primary source of corrosion protection for a pipeline. CP provides corrosion protection at coating holidays. Generally, pipeline systems are protected using impressed current CP (ICCP) from remote ground beds (buried anodes) that are powered by a rectifier.

For an effective coating system, CP is relatively inexpensive. The length of pipeline that can be protected from a remote ICCP varies with the efficiency of the coating, diameter of the pipeline, and somewhat less with the soil resistivity. The CP system changes the potential of the buried pipe’s surface by providing sufficient current density to the coating holidays. The required current density is determined when the pipeline potential reaches -0.85 V vs a saturated copper-copper sulfate electrode. The effective reach of one remote system is determined by the following attenuation equation:

• Ex = E0 e(-αx)
• Where:
• Ex = the pipeline potential in volts at a distance ‘x’ along the pipeline from the remote ground bed.
• E0 = the pipeline potential in volts at the location of the ICCP.
• x = the distance along the pipeline (graph shows both directions from centre point).
• α = the attenuation constant and is equal to √Rs/RL.
• RS = longitudinal resistance per unit length of the pipeline.
• RL = pipeline leakage resistance.

Figure 1 illustrates an attenuation curve for pipeline potential against distance along a pipeline from a remote ICCP. As the pipeline leakage resistance decreases, caused by coating deterioration, the distance that can be protected from a remote ICCP also decreases. For example, a 914 mm dia. pipeline with a coating efficiency of 99.99% (0.01% bare) would require a remote ICCP every 50 km. In this case, ‘x’ would equal 25 km. The longitudinal resistance of the pipeline would be the limiting factor for distance reached from a remote ICCP, provided the coating has the efficiency as stated heretofore.

A coating with a bare area of 3 - 10% would require more closely spaced ICCP systems. Where the coating is deemed to be more than 30% bare, a continuous ICCP system would be required. The examples given assume a soil resistivity in the range of 1000 - 20 000 Ωcm. No actual distances have been calculated for each example, as the purpose of the discussion is to show that CP cannot be relied upon to provide adequate corrosion protection for a pipeline when its coating undergoes substantial deterioration. Additional CP is not just a matter of pumping more current out of a remote ground bed to compensate for increased current demand as the coating deteriorates.

Cathodic disbonding

For an impressed current CP system, current flowing to the pipeline produces a reduction reaction of water, according to the following:

H2O –> H+ + OH–

The hydrogen ion (H+) is discharged at the cathode (pipe surface) to form a polarisation film of nascent hydrogen.

H+ + e– –> H

Hydroxyl groups (OH–) that form at the pipe surface at coating holidays create an alkaline environment and are the primary cause of cathodic disbondment. An example of cathodic disbondment on a FBE coated pipeline is shown in Figure 2.

According to Neal2, sufficient research has been done to show that disbonding at coating holidays on all pipeline coatings are due to alkaline conditions caused by CP, and it is one of the primary changes observed in buried pipeline coatings. Cathodic disbonding tests, although severe, will show which coatings are most affected by CP. Generally, epoxy and epoxy-primed coating systems show the best resistance of any coating system to cathodic disbonding.

A study by Papavinasam and Revie3 ranked coating failure modes in polymeric pipeline coatings (epoxies). They concluded that electrochemical changes in polymeric coatings (one such change is water absorption) may be considered a coating failure and not all changes affect the ability of a coating to protect the pipeline. The coating protects the pipeline and, when it fails, the CP system acts as a backup. Only after both mechanisms fail would the pipeline become susceptible to corrosion. Additionally, Neal concluded that FBE coatings will absorb moisture, are transparent to CP current and are an oxygen barrier. These combined properties allow the formation of a protective magnetite layer. The outcome is a stable current demand and an economical CP system.

Stress corrosion cracking

Stress corrosion cracking (SCC) in pipelines, known as environmentally assisted cracking, can cause catastrophic failure of a pipeline. Two SCC types have been identified; near neutral pH SCC and high pH SCC (classical).

Neutral pH SCC occurs in alternate wet-dry soils and soils that disbond or damage coatings. Insufficient CP is one contributor with the potential range for this type of SCC between -760 mV to -790 mV (Cu/CuSO4).

High pH SCC occurs typically within 20 km downstream of a compressor station or pump station. The potential range for this type of SCC is between -600 mV to -750 mV (Cu/CuSO4).

In 1995, the National Energy Board of Canada4 (NEB) held an inquiry into SCC on Canadian oil and gas pipelines. In its report filed in 1996, the NEB stated that most of the SCC-related failures occurred on pipelines coated with PE tape. The report stated that some PE tapes are prone to disbonding because of tenting created by the tape, which occurs between the pipe surface on spiral welds and long seams welds. Also, disbondment occurs where the tape is overlapped between successive wraps of tape, or where soil stress has caused the coating to move or wrinkle (Figure 3).

Due to the high electrical insulating property of PE and the relatively long path under the disbonded tape, sufficient CP current cannot reach the pipe to prevent corrosion. This is called shielding. When shielding does occur it can result in pitting corrosion. Of greater concern, as a result of shielding, is extensive general corrosion or the formation of an environment susceptible to SCC. These two scenarios could lead to catastrophic failure of the pipeline.

Classical SCC failures have been reported in Canada and in many countries on pipelines coated with tape, asphalt and coal tar. Importantly, no SCC has been found on any pipeline coated with FBE or liquid epoxy. FBE has been used on pipelines since the 1970s, and liquid epoxy since the 1980s.

Maintaining pipeline integrity

Both CP and coatings are required to maintain pipeline integrity. Many of the older ‘low adhesion’ coatings deteriorate over time to the point of total ineffectiveness. Industry experience has shown that this has happened with mastics, asphalt enamels, tapes and, to an extent, coal tar enamels.

Figure 4 illustrates how costs for CP can accelerate as coating deteriorates.5 Current requirements per kilometre have been calculated for a pipeline with a 714 - 914 mm dia. and a current density of 10 mA/m2. Initially, current requirements are low. At 30% coating deterioration, the curve ascends almost vertically. Where it flattens again, the pipeline is essentially bare. With more than 30% coating failure, an ICCP system may not provide adequate current distribution, as seen from the attenuation curve. A distributed ICCP system may be required at a substantial cost increase over a remote system, and would require anodes located adjacent to the pipeline and parallel to it. The length of pipeline that an ICCP remote system would protect in the example given is approximately 10 - 150 m. As the coating fails, additional power would be required as well as more anodes, feeder cables and current control systems. Cost can escalate an order or magnitude (or greater to change) from a remote ICCP system to a distributed one.

An additional cost associated with coating failure and the use of distributed ICCP is monitoring. For an efficient coating system, pipe potentials measured at aboveground test stations would give a good indication of the level of corrosion protection. Such is not the case for a pipeline protected with a distributed ICCP. Here, a continuous over-the-line potential survey would be required at a cost greater than an order of magnitude over a test lead survey.

In the presence of shielding, over-the-line potential surveys are suspect in their ability to accurately assess the status of corrosion protection of a pipeline. Other costlier methods, such as pigging, hydrostatic testing or discrete excavations, would be needed. Regardless of the integrity assessment method used, remedial programmes will be required if corrosion is found.

Remedial options are generally limited to additional CP, recoating, pipe replacement or a combination of the aforementioned choices. The cost of pipe replacement is known. As a comparison, the cost of recoating is about 50 - 80% of the cost of pipe replacement, depending upon the severity of corrosion found and the amount of pipe replacement associated with it. Coating rehabilitation of a transmission pipeline is shown in Figure 5.

In the case of a disbonded coating causing shielding, additional CP would not be an effective option. Thus, the only alternatives are rehabilitation by recoating, pigging or pipe replacement. If SCC is suspected, a planned integrity programme checking for crack colonies at selected bell hole excavations, pigging and hydrostatic testing may be required.

Conclusion

Pipelines are an intrinsically safe method of transporting hydrocarbons. However, the integrity of a pipeline must be sacrosanct. An effective pipeline coating is essential to maintain the integrity of a buried or submerged pipeline. CP is used as a supplemental system to prevent corrosion of a pipeline at coating defects. Where a coating undergoes substantial deterioration, CP becomes onerous to apply and maintain and, in some cases, may not be effective.

Remedial measures to maintain pipeline integrity when the coating fails include additional CP, recoating and pipe replacement. All of these measures can be expensive. If SCC is detected, remedial measures include pigging, bell hole excavations at discrete locations to examine the pipe surface for SCC, periodic hydrostatic testing and pipe replacement. Costs could exceed replacement costs of the suspect pipe.

An effective coating system reduces maintenance costs and eliminates expensive remedial measures.

References

• WERNER, D. P. et al, ‘Survey Results on Pipeline Coating Selection and Use’, Materials Performance, November 1992.

• NEAL, D., ‘Pipeline Coating Failure - Not Always What You Think’, Corrosion 2000.
• PAPAVINASAM, S., ATTARD, M., and REVIE, R. W., ‘External Polymeric Pipeline Coatings Failure Modes’, Materials Performance, October 2006.
• Transportation Safety Board of Canada, Pipeline Investigative Report, P09H0074, 2009.
• ALLISTON, C., BANACH, J., and DZATKO, J., ‘Liquid skin’, World Pipelines, November 2002.

This article was originally published in World Pipelines. To receive your free copy of the magazine, click here.