http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/ 

Preventing Damage to Corrosion Protection During Pipelaying

by Jim Britton (1996) from Offshore Magazine

Introduction Corrosion control for offshore pipelines is typically achieved with a combination of pipe coatings supported wilh cathodic protection to cover coating holidays or defects. The nature of offshore pipelines dictates that the most cost effective and reliable method of providing the cathodic protection component is the use of zinc or aluminum alloy bracelet anodes. This method has served the pipeline industry well for many years.

Larger diameter pipelines require a stabilizing weight coating, usually concrete, installed over the thin film corrosion coating. This weight coating provides mechanical protection to the corrosion coating as well as allowing the bracelet anodes to be flush with or even below the outer profile of the pipe. Thus. damage from contact with the pipelay stinger or burial sled to the anodes or coating is minimized.

As the oil and gas industry moves into deeper water, the trend is toward smaller diameter heavy-wall pipe with no weight coating. The smaller the diameter, the greater the risk that an anode can be hooked up on the stinger or in the trenching plow. If an anode is snagged, there is a risk that it will slide along the pipeline and damage the coating or even gouge the pipeline.

Top-mounted anodes Since most of the possible damage will occur on the pipeline1s journey over the stinger, the anodes have a better survival rate if they are tapered. In that way, they would better traverse the rollers and straighteners on the lay barge.

This anode alteration does not solve the problem entirely, but it does help. Several operators have reduced the risk of a snag by top mounting the anodes on the pipe. Such a position helps passage through the stinger, but would not necessarily help the pipe through a trenching plow or jetting sled.

An additional concern is that the pipe usually will rotate on its axis between the point of exit from the stinger until seabed touchdown. In several documented cases, this rotation has resulted in burial in the mud of all the anodes over a long section of line, leaving the upper half of the pipeline exposed to seawater. The anode's electrical resistance will be significantly increased by this mud bllrial and consequently the current delivered by the anode is reduced.

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/ 

Figure 1. Polyurethane tapers on each side of the anode bracelets protect the anodes during pipelaying and burial

Figure 2. A top-mounted anode is least vulnerable in the pipelaying process

Polyurethane Tapers Another solution is the use of polyurethane tapers. which is gaining momentum. The anode is mounted conventionally and is overmolded on site with a shallow angle cast polyurethane taper on the leading, and often the trailing edge. The low viscosity rapid curing resins ensure that the anode is firmly anchored to the pipe and electro-mechanical lead wire connection is encapsulated and thus protected from mechanical damage.

The process can be used offshore equally well. The polyurethane resin appears to form an excellent bond to the thin film epoxy pipe coatings commonly used offshore. While the cost of applying these tapers is not insignificant, they can be viewed as cheap, proven insurance.

Pin Brazing On most offshore pipelines, and certainly those in the Gulf of Mexico, the anode is clamped rather than welded to the pipeline. The electro-mechanical connection to the pipeline is made by two or more #6 AWG cables (Pigtails) which are powder (thermite) welded to the pipeline. This welding process can often be unreliable, especially if performed offshore on the deck of a barge. The connection has little or no mechanical strength. Some operators are moving to pin brazing as the electro-mechanical attachment method. While not infallible, pin brazing offers an improved mechanical connection. The method is far more popular in Europe, but is slowly making inroads into the Gulf of Mexico area.

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/ 

Monitoring Systems One preventative method which can detect dislocated anodes or significant coating damage is a method of field gradient monitoring. This system utilizes two-dimensional field gradient sensors (electrochemical reference electrodes) which are more commonly employed in the monitoring of cathodic protection systems. The electrode array is capable of detecting changes in eleclrical field gradient adjacent to the pipeline without having to actually contact or otherwise interfere with the pipeline. A newly installed anode passing the array will cause a rapid gradient change in the seawater around the pipeline which can be detected by this array and reported on a computerized chart recorder. The upset in the field gradient will only occur if the anode is in electrical contact with the pipeline. Uthe anode should become isolated or detached from the pipeline, it will pass the array and create no gradient upset Thus, the operator will know that the anode has become detached. Since coating defects also cause an upset in the field gradient strength around a pipeline, damage areas can also be detected.

Figure 3. This printout from an electrode array system positioned on a pipelay vessel stinger indicates the presence of a pipeline anode.

Current Sources Care must be exercised when specifying these systems to ensure that all possible extraneous sources of electrical current flow in the seawater are appreciated and taken into account Such sources of current are:

• Poorly or improperly grounded welding • generators • DC powered thrusters • The cathodic protection system on the barge itself, especially if it is an impressed current system.

Once these interference sources are quantified, the gradient array can be sized and positioned to do it's job accurately. The major advantage of an on-line monitoring system is that problems are detected in real

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  time. With this method, repairs or adjustments can be made during the pipe lay, rather than being found during the post-lay inspection, at which time a costly retrofit or repair is the only solution. In summary, the best and most practical measures that can be taken to prevent damage to the corrosion control systems depend on the type of pipeline and the pipelay method. The following general guidelines may prove useful.

• Weight-coated pipelines: Any pipeline with a concrete weight coating should be at low risk provided that the anodes are flush or recessed below the profile of the concrete. No additional precautions are considered useful.

• Reel laid pipelines: This lay method is particularly suited to deep water. particularly for smaller diameter pipe. Anode tapers would help, but are not always practical, given the speed at which the pipe is laid. The pipelines should be designed with top mounted anodes. and the probability of mud burial should be reflected in the anode size and spacing. The field gradient monitoring system should be specified because the lines are not weight coated, and anode/coating damage is a real possibility.

• Conventional pipelay (S-Lay) > 200 It. seawater: Conventionally laid pipe without a weight coating

should use square shouldered anode bracelets with polyurethane anchor tapers. The tapers can be installed in the pipe coating yard before offshore loadout. If the pipe is installed in water depths greater than 200 feet in the Gulf of Mexico, for example, it will not be necessary to bury the line except at safety fairway crossings. Astinger-mounted gradient array should be specified to verify anode attachment and to monitor the condition of the pipe coating. If tapers cannot be installed for any reason, then the anodes should be tapered and the gradient monitoring specified.

• Conventional pipelay (S-Lay) < 200 It. seawater: Shallow pipe will have to be open trenched or jetted

to achieve the required cover. This will involve the use of a towed burial sled or trencher. Under this scenario, the polyurethane anchor tapers with square shouldered anodes offer tremendous benefits due to the enhanced risk of mechanical damage at the burial stage. Similarly, the use of stinger and sled exit point gradient arrays provides absolute verification that no damage is occurring, and if it is, determines the location.

• J-Lay pipelines: This lay method is used only for deep pipelines. Depending on the geometry of the J-Lay frame and the anode installation procedure, there may be minimal risk of damage. Each project should be examined to determine where the last point of mechanical interference with the anode will be.

• Bottom or controlled depth towed pipeline installation: Towed pipelines will have abrasion resistant coatings and may have anodes cast directly onto the pipeline in the foundry. While direct cast anodes can work successfully, they are expensive and not without some problems. Polyurethane anchor tapers will provide the same mechanical stability at a lower cost and allow conventional anodes to be employed. There is no application for on-line monitoring, but a detailed postlay gradient survey will confirm that no anodes have become dislodged or pipe coating badly damaged

 

 

 

 

 

 

 

 

 

 

 

 

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The Role of Cathodic Protection in Offshore Pipeline Integrity by Jim Britton (1998) from Hart's Pipeline Digest

What Is Out There? 

Over 24,000 miles of pipeline have been laid on the Outer Continental Shelf (OCS) in the Gulf of Mexico since 1948. Over the years, much of this pipeline has been abandoned or removed, but as of June 1997, there were still some 17,000 miles of active pipe. Pipe-laying activity has been up and down over the years, somewhat mirroring the "boom and bust" cycles of the oil and gas industry. Some 1,222 miles are over 30 years old, and 5,952 miles have celebrated a 20th anniversary. Obviously these 5,000-plus miles of pipe would be considered at higher risk from an integrity standpoint than the 11,000 miles younger than 20. The mere fact that these old lines are still in operation reflects well on the skills of the corrosion control community (Figure 1).

Figure 1.  

Active Gulf of Mexico Pipelines: Mileage vs. Age

External Corrosion Control of Offshore Pipelines 

All offshore pipelines are protected from seawater corrosion in the same way. The primary corrosion control system is pipeline coating. This is supplemented with cathodic protection (CP) to provide protection at coating defects or "holidays." In the Gulf of Mexico, the pipeline coatings used until the early to mid-1970s were either asphaltic/ aggregate, "Somastic"-type, coatings or hot-applied coal tar enamels. Since then, the trend has been to use fusion-bonded epoxy powder coatings. In the earlier days, the trend in cathodic protection (CP) was to rely on impressed-current systems. In the 1960s and early 1970s, zinc bracelet anodes attached to the pipe were widely used. Since then, more

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  efficient aluminum alloys have surpassed zinc as the preferred material for offshore galvanic anodes. There are, however, still some operators using impressed current systems and some using zinc anodes.

 Bracelet Anodes 

Virtually all new pipelines installed in the Gulf of Mexico are equipped with aluminum bracelet anodes. There are two basic types, square shouldered and tapered.

The square-shouldered anodes are typically used on pipe that has a concrete weight coating. When installed, the anodes are flush with, or slightly recessed inside, the outside diameter of the concrete.

The tapered anodes are designed to be installed on pipelines with only a thin film corrosion coating. The whole idea is to protect the bracelet anodes during the pipe-laying process. The anodes are particularly at risk from mechanical damage when the pipeline travels over the stinger on the back of the lay barge.

Even with these tapered designs, non-weight-coated pipelines still sustain anode damage, which can in turn cause coating damage. Several methods are being used to combat this problem. The use of cast-on polyurethane tapers is gaining popularity, and mounting both halves of the bracelet on top of the pipe is a common technique when pipe is laid from a reel barge and the anodes have to be attached offshore (Figures 2 and 3).

Figure 2. Six-inch pipe reeled on the barge Chickasaw

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  Figure 3. Tapered bracelet anodes installed on top of pipe

Designing CP Systems for Offshore Pipelines 

When designing a cathodic protection system for a pipeline, the corrosion engineer has to consider the following variables, all of which will have an impact on the final anode alloy and size selection:

• Design life required - (minimum is 20 years) • Pipe diameter length and to-from information • Geographic location • Type of coating • Pipe-lay / installation method • Water depth • Burial method • Product temperature • Electrical isolation from platforms or other pipelines

The smart cathodic protection designer will look early on at the intended pipe installation method, as this will have a direct impact on the amount of coating damage one may expect (there is also a risk of having anodes detached during the lay process). In all pipeline design guidelines, the conservative approach is advised. For example, the majority of early Gulf of Mexico (buried) pipelines were designed on the basis of 2 mA / ft. of bare steel and 5% coating failure. In essence, this means taking 5% of the total pipeline surface area, and applying 2 rnA / ft. of cathodic protection current to it. This may sound reasonable, until one looks at what 5% bare means:

On a 40 ft. joint of 12 in. pipe, 5% bare coating would have 2 square feet of bare steel, or to express it another way. 4 linear feet of pipe would have the coating gone from 180° of the circumference. This is an extremely conservative figure. As a result, the early pipeline system designs would appear to be very conservative.

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  Pipeline Integrity 

When considering the role of cathodic protection (CP) in pipeline integrity we should investigate what causes offshore pipelines to fail and leak. If all the failures of pipelines in the Gulf of Mexico were counted and tabulated, the findings would probably show the general trend expressed in Figures 4 and 5. (These graphs are based on studying a limited sample of failure reports from two oil companies.)

Figure 4. Causes of offshore pipeline failure

Figure 5.  

Causes of offshore riser failure

Since external corrosion is only responsible for a very few of the documented pipeline failures, we could truthfully say that, in general, the combination of CP and coatings is doing a good job.

However, we must not be led into a false sense of security. The only reason the external leaks have not started in earnest is that the old systems were unknowingly over-designed. Thus, a 25-year design life has effectively turned into 30, 35 or even 40 years.

There is a practical limit on how long sacrificial anodes will last, and it is based on the auto-corrosion rate of the anode material. If we were to assume that pipeline systems are all good for at least 30 years, then there should be several thousand miles of pipeline with depleted CP systems (Figure 1). The question, then, is why are we not seeing more external failures?

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  In truth, the answer to that question is that we probably are seeing a higher external corrosion leak rate than we have at any time in the past. But when will it peak? The pitting rate of steel in seawater on a well-coated pipeline in the absence of cathodic protection anodes could vary between 0.01-0.05 inches per year. Thus, it could take anywhere from 5 to 25 years to pit through an inch of steel. This amount of loss could be sufficient to cause a pipeline failure. Higher corrosion rates can be generally expected when the pipe coating has a combination of large damaged areas and adjacent pinhole defects, and when the pipe is exposed to seawater rather than mud. There is also a particular risk of microbiologically influenced corrosion (MIC) on buried lines with bitumastic-type coatings and depleted cathodic protection.

What Is The Risk? 

On pipelines in excess of 30 years old, the risks are quite high. If the cathodic protection systems have depleted, then corrosion will begin at numerous sites all over the pipeline. Unless detected and retrofitted, the first leak could be the end of the pipeline, as the next several hundred won't be far behind. There are only so many clamps that an operator can afford to install before economic concerns dictate pipeline replacement or abandonment. Given the cost of laying pipelines offshore today, many of the lines will never be replaced, and this could result in early deaths of the oil and gas fields they service. Other old lines are the critical links between the new deep water fields and the shore-based markets. Loss of these lines will present an interesting and unenviable dilemma for operators.

What Is The Answer? 

There are three basic strategies that a pipeline owner can adopt:

1. Survey the pipeline cathodic protection system. 2. Retrofit the cathodic protection anodes on pipelines of a certain vintage. 3. Do nothing (and hope that the laws of electrochemistry will ignore your pipeline), essentially ignoring the problem.

Cathodic Protection Surveys 

Close-interval cathodic protection surveys are the most logical strategy, but strangely enough, operators in the Gulf of Mexico survey very little. When a survey is actually run, it is usually of little value because the method used (trailing wire) inherently produces erroneous data.

There are accurate survey systems available; these either involve physically contacting the line at intervals or utilizing remotely operated vehicles (ROV's) (Figure 6) to track the pipeline and carry reference electrode arrays above the pipeline at known locations (a typical plot from such a survey is shown Figure 7). This type of survey will let the operator see the condition of the line and make informed decisions regarding retrofitting.

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  Figure 6. Work-class ROV Challenger equipped for pipeline survey. Photo courtesy of Sonsub Inc.

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  Figure 7. 

Detailed pipeline CP inspection plot. Green trace is current density, red trace is potential. Downward green spikes indicate anode locations; upward spikes reflect coating damage.

In addition to the corrosion data shown, the survey will also yield important information on the precise location of the pipeline and the depth of burial below the seabed; these data points can be crucial when designing the eventual anode retrofit.

Retrofit Anodes on Pipelines of a Certain Age 

Retrofitting the cathodic protection system with supplemental anodes would only make sense if the line in question is very old and the required additional life were significant. The cost to perform a pipeline cathodic protection inspection will run anywhere from $2,000 to $6,000 per mile, and that cost may be eliminated if the decision to retrofit is made. There will only need to be a post-installation survey, once the new anodes are laid.

Of course, retrofitting pipeline cathodic protection systems offshore is not always a simple matter, especially when lines are deeply buried. Often, the retrofit program will need an up-front survey to find the pipeline - so why not survey it first?

http://stoprust.com/technical‐papers/29‐corrosion‐protection‐and‐pipe‐laying/  Do Nothing 

Very often this decision is made based on the following logic: "If I know I have a problem, I will have to take care of it; if I don't survey the pipeline, I will not have to find out whether or not I have a problem." This logic sounds like the chronic smoker who dares not visit the doctor for fear it will be discovered he has lung cancer! A surprising number of operators follow this logic.

SUMMARY 

In summary, it must be concluded that cathodic protection plays an absolutely vital role in pipeline integrity offshore. Cathodic protection is cheap and reliable, with an outstanding track record of success in offshore applications. But cathodic protection systems have a finite life and unprotected steel has a very short life in seawater. Check your cathodic protection if the pipeline is more than 25 years old.

About the Author 

Jim Britton has worked in the corrosion control industry since 1972 and has been primarily involved in offshore and marine projects since 1975. He holds a bachelor's degree in corrosion technology from the United Kingdom. His work brought him to the United States in 1982. In 1986, he founded Deepwater Corrosion Services Inc., which specializes in engineering and manufacturing retrofit cathodic protection systems for offshore assets. Britton is a consultant for major oil companies worldwide. He has published a variety of articles and has been a guest lecturer at colleges and universities throughout the US. He has been an active member of NACE International since 1979.