Due to great chemistry and metallurgical innovations of the steel industry, higher strength steels have made significant strides, in specified minimum yield strength (SMYS), wall thickness control, toughness and weight per foot.
However, one significant factor in these great improvements was no consideration for corrosion allowances. It has decreased with every incremental increase in the making of higher strength steels. Corrosion in carbon steel is the same whether it is a 35,000-yield pipe or an 80,000-yield pipe or 0.375-inch wall thickness (WT) vs. 0.215-inch wall thickness.
Wall loss of 25% on 35,000-yield pipe results in a 44% on the higher strength steel pipe. Lower strength steel results in recoat type repair while higher strength steel results in a composite repair or replacement. Unfortunately, the U.S. coating industry and pipeline operators have not kept up with these changes to offset or complement the improvements in great improvements made in higher strength steel.
So, what is the next step? Either add more corrosion allowances to the steel or improve the coatings. Coatings are supposed to be the first line of defense against corrosion control while cathodic protection is secondary.
Efforts have been made in the development of high-strength steels that have yielded great strides in cost reduction while increasing operating pressures. In addition, the use of high-strength steels has had an effect on the reduction of wall thickness, which resulted in less material, shipping and welding costs. These developments have improved the toughness properties of the steel as well as the ability of the weldability even under field and ambient conditions.
This has resulted in the reduction of pipe construction costs, especially with respect to shipping and reduced welding times for thinner wall thicknesses. Because it is difficult to prevent external corrosion on pipeline steels, controlling the corrosion rate through the use of coating and cathodic protection is the most economical solution. Increasing the wall thickness is another solution; however, it would negate or offset all of the gain that was developed with high-strength pipeline steels and associated costs.
Understand the Problem
Due to the lack of extra or additional corrosion allowance from the older, heavier wall pipe, the mechanisms of corrosion must be better identified, along with methods of arresting the corrosion process. There are many forms of corrosion; however, there are two primary methods of slowing the process down to a manageable/safe level: Coatings and cathodic protection (CP) work well for underground or submerged pipeline systems.
The following is an overview of coatings and CP:
- Coatings are the first line of defense against external corrosion.
- Coatings are not perfect and must be cathodically protected to slow down the corrosion rate at breaks (holidays).
- CP is applied to underground and submerged structures to prevent corrosion of the steel substrate at holidays.
- Coatings such as fusion-bonded epoxies (FBE) allow CP through micro-pores: 14-16 mils thickness is common for line pipe, while 20-24 mils thickness is common for horizontal directionally drilled (HDD) crossings.
- Types of coatings play an important role in the cathodic protection of the pipeline.
- CP is used to protect only the exposed metal substrate at small holidays.
- Smaller holidays reduce the size and high expense of operating CP systems.
- A well-designed, coated structure will ensure good current attenuation with CP.
There are several physical and chemical properties required for a good line pipe coating, according to NACE. Those are:
- An effective electrical insulator
- An effective moisture barrier
- An application method that does not adversely affect the properties of the pipe
- An application that presents a minimum of coating defects
- Good adhesion to pipe surface
- Ability to resist development of holidays with time
- Ability to resist damage during handling, storage and installation
In addition, NACE has many other considerations that are too numerous to mention, but many of the properties are up to the discretion of the pipeline operator, coating manufacturer and the plant.
Since the United States, Canada and South America are the biggest users of FBE coatings for underground pipelines, industry has done little to demand that coating manufacturers address the changes, such as reduction of wall thickness (WT).
Corrosion rates on pipeline steels are generally the same, whether it is 0.5-inch WT lower strength steel or 0.25 WT, or higher strength steel. What this means is running a remaining strength of corroded pipe calculation (RSTRENG) on thinner wall pipe will show that the safe operating pressure will be reduced more significantly, thereby resulting in a more advanced repairs such as a composite sleeve versus just a recoat and backfill.
As a bare minimum, coating thickness should provide more than 99% of the protective needs of a buried or submerged pipeline. The remaining less than 1% needs to come from cathodic protection. Coatings should be designed deteriorate at a slow rate over the life of the pipeline system under normal and abnormal operating conditions. However, this is rarely the case, due to many external factors that are rarely considered in the design of the pipe.
What are some of the factors that affect coating deterioration? Among them are AC and DC interference issues either from power lines, transit systems or other pipelines. Also, aggressive soils such as clays with low pH or low resistivity, rock conditions, microbial activity and high water tables. This is usually an after-the-fact issue left to the corrosion engineer to resolve with additional cathodic protection.
AC corrosion interference, for example, where pipelines are buried in AC transmission corridors, has occurred where newly constructed pipelines show leaks within six months of installation. While these may be extreme cases, they still catch operators off-guard, and the costs of mitigation can run into millions of dollars.
In contrast, if these potential problems had been planned into the design of the pipeline coating type and mitigation at the time of construction, the issues would have been minimized. Once the pipeline coating system integrity has been compromised, performance and risk of failure moves up on the risk ranking and re-assessment intervals become shorter, which means additional frequency in pigging and other surveys.
Now that one of the factors have been identified, what type of coating is required for the life of the pipeline? Is a single coat needed? Or what about a dual- (abrasion- resistant overcoat) or triple-layer coating similar to what the Europeans use? What is the optimum coating required for this set of conditions?
Line-pipe coating types that are available as the first defense against corrosion: Anti-corrosion coatings include single-layer FBE coating for line pipe 14-16 mils, two-layer FBE coating with abrasion-resistant overcoat for 20-24 mils or three-layer with epoxy primer, co-polymer adhesive, followed by high-density polyethylene – up to 120 mils.
Performance of these coatings is based on cleanliness, anchor pattern, acid wash, thickness, number of layers and type, and other variables. Transportation is based on storage, handling, shipping, installation and final testing.
Most U.S. pipeline operators use the FBE single-layer for line pipe and dual-layer for road and water crossings. Unfortunately, few pipeline operators order three-layer coating systems in the United States. Our European counterparts use the three-layer type most of the time. These coating systems come close to ideal for most factors encountered in the field.
I was fortunate to work for a large transmission company in the 1980s that tried out some of the first three-layer systems in the United States. A 30-inch line, 130 miles in length, installed in 1987, required only 0.5 amps to cathodically protect it in very low-resistivity type soils. It is my understanding that the CP current requirements have not changed since 1987 when it was initially installed. This demonstrates that little or no deterioration has occurred in 29 years. We, as an industry, would be hard-pressed to say that about conventional coating systems.
Because of the acceptance of conventional coating systems, pipeline operators spend millions of dollars on inline inspection (ILI) verification digs and repairs each year in order to maintain the integrity of their pipelines from external corrosion, cracking, material defects and mechanical damage. Operators run thousands of RSTRENG calculations to ensure that the pipeline can operate as it was designed.
Example 1: Lower Strength Steel
A 20-inch line, 0.500 WT, 35,000-yield, design factor 0.5 with an 800 psig established MAOP. However, the design pressure calculation is 874 psig. The RSTRENG maximum safe operating pressure based on the worst pitted area is 887 psig. In this case, it passed and will require recoat and backfill.
Example 2: Higher Strength Steel
A 20-inch, 0.25 WT, 70,000-yield, design factor 0.5 with 800 psig established 800 MAOP. However, the design pressure is 874 psig. The RSTRENG maximum safe operating pressure based on the worst pitted area is 451 psig. This case failed, which requires a repair sleeve or cut-out to meet code requirements.
These are examples of what pipeline operators must deal with on a day-to-day basis due to ongoing corrosion caused by aged coatings. Even though coatings are the primary player, CP should be used to protect the smaller coating holidays on new pipe. As coating ages, it should not degrade catastrophically.
The Next Step
Considerations for additional corrosion allowances include whether the pipeline is in AC and multiple pipeline corridors, whether HDD road and water crossings are involved, and whether there are high-consequence and environmentally sensitive areas to consider.
In looking at the possible need for multiple-layer coating systems, one must consider all of the previous factors as well as looking at interference areas caused by adjacent CP systems, DC rail and AC transmission. Also, aggressive soils, coating disbondment, long-term performance and the use of CP for the smaller holidays must be considered.
Coatings must be the first line of defense against corrosion. Selection and understanding of the physical and chemical properties must be known before selecting the type for long-term performance.
Cathodic protection should be the secondary factor, not the primary factor in protecting the pipe and related underground facilities. Too often, the CP systems become the primary defense against corrosion, once the line is commissioned. A small investment in multilayer coating systems means better integrity management and lower maintenance costs down the road.
Good coatings must minimize coating disbondment, reduce CP levels in the short as well as the long-term. Also, training and informing corrosion engineers, managers, procurement people must be a priority in our industry.
Author: Joe Pikas is vice president of Pipeline Integrity for Engineering Services, located in Houston. He can be reached email@example.com or 832-758-0009.