David Nor Mann Ace 2005

8/3/2019 David Nor Mann Ace 2005

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FITNESS FOR PURPOSE ISSUES RELATING TO FBE AND THREE LAYER PE COATINGS

Dr Colin ArgentMacaw Engineering Ltd

Tyne and Wear, NE28 6ULEngland

David Norman

David Norman Corrosion ControlCornwall, TR8 5SA

England

ABSTRACT

This paper reviews the development, application and in-service performance of FBE and 3LPEcoatings. The main factors affecting the fitness for purpose of a coating are the risk of failureand the modes of failure when the pipeline is in service. Coating failure modes are discussedwith particular reference to whether the dominant failure mode will create problems of long


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INTRODUCTION

The paper discusses coating selection - fitness for purpose with respect to the constructionand operating conditions, coating application - essential controls to ensure fitness for purpose,and operation coating failure modes and integrity threats to a pipeline.Each of these issues is comprised of two main components technical and cost.Every decision made on a pipeline, whether driven by cost or technical considerations, will

have an impact on the long term integrity of a pipeline. Risk assessment provides a basis forassessing the long term impact of these decisions.

WHAT SHOULD A COATING DO?

An ideal coating will stop pipeline corrosion. The minimum requirement is that a coatingshould stop corrosion for the design life of the pipeline but a more realistic objective is that the

coating should stop corrosion for as long as the pipeline remains in service. Most pipelines areoperated well beyond the original design life.

Inevitably coatings get damaged by external forces or by a number of long term degradationprocesses that affect the constituents of the coating. Typically this results in coating defectsthat expose the pipe steel to the environment around the pipeline and this corrosion risk can becontrolled by cathodic protection. Many coatings also show a loss of adhesion such that wateror soil penetrates between the pipe and the coating. Ideally this failure mode should not create

new corrosion threats to the pipeline but in many cases it does.

For operating pipelines the key coating issues can be resolved into three questions. How is the coating performing? How does the coating impact on monitoring and maintenance costs? When will a coating degrade to the point at which it is no longer sustainable?

For new pipelines the problem is simpler. Fore-warned with hindsight, from the experience of

others, an operator can select the coating system and application conditions that will guaranteea long, low maintenance life for the pipeline. Experience over the last 10 years suggests thathindsight lacks the 20 20 vision so often claimed for it. New coatings are being applied withinherent problems that will impact on the through life monitoring and maintenance.


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and excellent specifications have been developed by the CSA (1), and others, for both FBE andfor 3LPE.

The common baseline standard for FBE stand-alone coating and 3-layer coatings with an FBEfirst layer requires the following essential stages in the coating application.

Phosphoric acid pre-treatment and de-ionised water wash to remove contamination Blast cleaning to an Sa 21/2 finish with an angular profile of >50 micron Chromate pre-treatment to stabilise the surface oxide layer and enhance the wetting of

the steel substrate by the FBE. (Chromate pre-treatment is not used in some countriese.g. USA.)

Application within the optimum temperature range for wetting and flow of the FBE

The proportionate cost of each of these surface preparation procedures is typically 2 3% ofthe total applied coating cost and the heating is typically no more than 10%. The major cost inany pipeline coating project will be the coating material which will be ~50% for stand-aloneFBE and more than 60% for the FBE, adhesive and PE in a 3LPE coating.

Costs will vary from project to project and with plant location but the applied cost of 3LPEcoatings are typically ~25% more than stand alone FBE. MCL coatings for field joints typically

turn out 5 6% higher than field applied FBE and 3-layer heat shrink materials undercut fieldapplied FBE by ~20%.

FAILURE MODES

The ideal coating will provide effective corrosion protection for the design life of the pipeline,and beyond but some coating failure or damage is inevitable. Damage control is probably the

major argument used in the comparison of the performance of 3LPE and FBE coatings. FBErequires more careful handling during transportation and construction because the coating ismore susceptible to mechanical damage than 3LPE.

Coating failure can take a number of forms depending on the root cause. A summary of thecauses of coating failure and the resulting failure mode is shown in Figs 1 6. The causesinclude inappropriate material selection, poor process controls in plant and site application,construction damage and in-service failure, for example from inter-action with the backfill.

The universal strategy for external corrosion protection on buried or sub-sea pipelines acceptsthat coating damage will occur and CP is built into the pipeline design to prevent metal loss atthese sites of coating damage. If the failed coating does not impede the flow of CP currentonto the pipe steel then normal CP monitoring will ensure continued pipeline integrity.


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Extensive adhesion problems (2) have been seen with 3LPE coatings over the last 10 years sothe risk of CP shielding must be assumed to apply to these coatings. Loss of adhesion inthese coatings has been attributed to two main causes:

Poor standards of surface preparation including surface cleanliness, blast profile andlack of chemical pre-treatments

Application of the FBE first layer at a temperature compatible with the second adhesivelayer but below the optimum temperature for flow, surface wetting and development ofgood adhesion.

COATING CP INTERACTION

External corrosion control on steel pipelines is achieved by the combined use of a protectivecoating and cathodic protection. The coating provides the first, and major, defence againstcorrosion and the cathodic protection serves to prevent pitting or general corrosion where thepipe steel is exposed by damage to the coating. Some degree of coating damage is to beexpected on all pipelines, for example due to external interference, so this combined approachto corrosion control is essential.

Ineffective Cathodic Protection

Ineffective cathodic protection can be caused by the accelerated degradation of a coating suchthat the total cathodic protection current demand for full protection cannot be met. However,inaccurate monitoring of pipe to soil potentials is a common cause of under protection.Common examples include a failure to correct for the voltage drop error inherent in ONpotential measurements and lack of close interval survey data between fixed test points. ISO15589 (3) provides a guide to industry best practice for monitoring pipeline CP systems.

Winski (4) poses an argument for the use of DCVG surveys that states this technique has thecapability to size coating defects accurately so that large defects can be repaired in order toreduce the total cathodic protection current demand. It is argued that small defects areprotected by the cathodic protection.

Intelligent pig inspection data provides information on the size, depth and location of corrosiondefects in a pipeline and the deepest pit depth is commonly recorded in small features.Polarisation of exposed pipe steel may vary with defect size because the current distributionwill be influenced by the local resistance of the soil coating interface.

Common causes for loss of protection due to excess cathodic protection current demandinclude:

Accelerated breakdown of thermoplastic coatings due to high temperature operation


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Cathodic Protection Shielding

Total Cathodic Protection Shielding

Total cathodic protection shielding is used here to describe the following pipeline condition: The pipe coating has lost adhesion, and Water has penetrated beneath the coating, and The pipe steel remains at, or near, the free corrosion potential, and The pH and chemistry of the water under the coating is not altered significantly by the

cathodic reaction of the applied cathodic protection.

Total cathodic protection shielding creates the risk of: Pitting and general corrosion

Microbial induced corrosion Near neutral pH SCC

Corrosion due to total cathodic protection shielding is most commonly associated with poorfield application of tapes and heat shrink materials with a polyolefin based outer layer. It hasalso been recorded on two layer polyethylene coatings with a butyl rubber primer where theprimer suffered progressive degradation with time such that all adhesion between the pipe andthe coating was lost.

Beavers and Thompson (5) report that coal tar and asphalt thermoplastic coatings, and fusionbonded epoxy powder coatings allow some cathodic protection current to leak through thecoating such that total shielding would not normally be expected. However, microbial corrosionhas been reported beneath coal tar and bitumen coatings with poor adhesion. A polarisedpotential of 950 mV is required (3) for the effective control of microbial corrosion so this form ofcorrosion does not necessarily indicate total cathodic protection shielding. However, microbialactivity would be expected to reduce in the high pH environment associated with partialcathodic protection shielding and high pH SCC. A significant level of cathodic protectionshielding should therefore be expected with mill applied thermoplastic coatings of ~3+mmthickness should the coating system lose adhesion to the pipe and lift off the surface to allowwater penetration.

Near neutral pH SCC has been associated with cathodic protection shielding by tape coatingsthat have lost adhesion to the pipe and with thermoplastic coatings where the cathodic

protection shielding is attributed to high ground resistance where bedrock occurs at pipe depth.

Partial Cathodic Protection Shielding

Partial cathodic protection shielding is used here to describe the following pipeline condition:


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Partial cathodic protection shielding contributes to the risk of high pH SCC.

CURRENT COATINGS 3LPE

One of the first methods of applying polyethylene (PE) to pipelines was by sintering or fusion ofthe polymer directly onto the prepared steel substrate. This was followed by the masticadhesive / PE pipeline protection system (mastic / plastic) that has been used to protect pipeup to 250mm in diameter, and by a two layer system with a hard polymer adhesive.

In order to improve the capability of the 2-layer polymer adhesive / PE system a 2-pack liquidepoxy coating was applied between the cleaned and profiled substrate and the polymeradhesive. This 2-pack epoxy coating forms a mechanical bond with both the substrate and theintermediate, adhesive polymer layer.

In the early 1980s Mannesmann developed and patented the system of three layer PE pipecoating using FBE instead of 2-pack epoxy as the first layer. By this time FBEs had becomeestablished as mono-layer pipeline protective coatings, and it was accepted that an FBE first or

primer layer, in a 3-layer polyolefin system, provided better adhesion of the system to thesubstrate. For many years the thickness of the FBE layer was specified around 75 microns.However, the use of a thicker 1st layer has generally been accepted as a means of achievingbetter protection. Some projects are now specified with over 200 microns of FBE. In recentyears two main types of 2nd, adhesive layer have been applied. Copolymer adhesives havebeen improved, but grafted adhesives have provided added capability to the 3-layer PE coatingsystems. A copolymer adhesive will form a mechanical bond with the FBE and PE layers, but agrafted adhesive can chemically react with the FBE and PE layers. In so reacting the strength

of the bond is improved. There is now a tendency to specify over 150 microns of FBE, around200 microns of a grafted copolymer adhesive, and either MDPE or HDPE. The use of HDPEcan reduce the required coating thickness. The overall coating thickness will depend on thedensity of the PE used, diameter of the pipe and the use to which the coated pipe will be put.Generally the thickness is between 1.5mm and 4.2mm. Three layer PE coatings can beoperated at around 60 deg.C with LDPE, and 80 deg. C for MDPE/HDPE.

As products carried in pipelines became hotter so coatings were required that would not

degrade under higher temperature conditions. Three layer PP coatings provided a highertemperature capability than PE coatings. The first three layer PP coatings were applied in thelate 1980s. Three layer PP coating systems are very similar to three layer PE systems in theirprinciples of application and protection. Their thickness depends on the diameter of the pipe,the temperature rating etc., but is usually in the range of 1.3 to 3.8 mm. Three layer PPsystems can currently be operated at up to 110 deg C


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Two layer PE with mastic adhesive have shown problems with the mastic sinking to the bottomof the pipe in warm weather. Early variants of the mastic are reported to have oxidised to aloose, friable powder after 20 30 years service leading to corrosion problems where waterpenetrated beneath the pipe coating. CP current access beneath the loose coating isprevented by the insulating properties of the polyethylene. Stress cracking has been a

problem on lines coated with low density polyethylene (Fig. 1). The cracking tends to initiatefrom minor chips or scratches in the coating and in extreme cases have been observed toaffect a complete pipeline. The most extreme problems are thought to have been caused by aninadequate material specification.

Two layer PE coatings with hard adhesive have shown problems with the hard polymer losingadhesion from the substrate, de-lamination of the PE and polymer layers and cracking of thepolymer (Fig. 1). Corrosion has been reported where the polymer adhesive has becomedetached from the substrate and water has penetrated beneath the coating. The loosepolyethylene prevents CP current access to the pipe steel (Fig 4).

The long term adhesion performance of three layer PE applied over a two pack epoxy primerdepends on how well the primer wetted the metal substrate.

Severe problems have been found during construction or within a few years of commissioning

on modern three layer PE coatings applied over an FBE primer. Loss of adhesion has beenreported on a number of new pipelines within 2 years of commissioning (Figs. 2 & 4). Thesymptoms range from complete delamination at the steel interface with the formation ofcorrosion products, to reduced adhesion such that the coating can be easily peeled from theun-corroded substrate. These problems have been attributed to poor surface preparation(incorrect blast profile, inadequate removal of surface scales, residual dust, lack of chemicalpre-treatments etc.) and incorrect application temperatures (2). Active corrosion beneath anapparently intact coating has also been observed on new pipelines with low density

polyethylene three layer coating. The corrosion was attributed to the relatively high oxygenand water permeability of the low density polyethylene. Stress cracking has been reported innew, low density polyethylene coatings with cracks initiating from minor scratches in the outersurface. In some instances the stress cracking has also originated from minor defects withinthe polyethylene or at the polyethylene adhesive interface.

A failure of three layer PP applied over an FBE has been reported prior to the coated pipebeing ditched primarily due to inadequate pipe temperatures in the plant during the application

of FBE (Fig 4).

Schwenk(6) reported effective corrosion control, in extended laboratory tests, beneath sinteredPE coatings that had lost adhesion.


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A compromise in PE resin properties is required to achieve the optimum in-serviceperformance and ease processing during the manufacture of the pipe coating. Various gradesof PE have been used for pipe coatings and these are classified as low density (LDPE),medium density (MDPE) and high density (HDPE)

Low density PE (


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Incorrect use of pressure rollers

Most of these problems can be monitored and controlled by the application of a structuredquality control (QC) and testing programme in the pipe mill (8).

CURRENT COATINGS - FBE

Fusion bonded epoxy powder (FBE) was introduced in the late 1950s, for the coating of smalldiameter pipe but the FBE performance did not meet the requirements for large diameter, highpressure pipe. Formulators, resin manufacturers and pipeline operators worked together in

the 1970s to produce FBEs with acceptable chemistry and protective properties.Subsequently many thousands of kilometres of pipelines have been coated with FBE,particularly in the Middle East, UK, and North America.

The achievement of good surface preparation is critical to the success of FBE coatings inprotecting pipelines. Hygroscopic salts remaining on the pipe surface, under the FBE coating,can cause blistering and loss of adhesion (Fig 2). In the early 1980s both phosphoric acidcleaning and chromate pre-treatment were introduced to the FBE pipe coating industry.

Phosphoric acid, in association with abrasive blast cleaning, cleans the surface of the pipe andremoves the majority of contaminants, including hygroscopic / soluble salts. Chromate pre-treatment modifies the surface chemistry of the substrate and thus provides a surface to whichFBEs have a better adherence.

FBE systems can be also applied in the field for the protection of field joints.

Whatever the type of FBE being applied the achievement of an excellent degree of surface

preparation remains the most important overall factor.

Reported Degradation

Extensive loss of adhesion has been reported on early examples of FBE coatings applied tolarge diameter pipelines. In some cases the delamination is accompanied by the formation ofa high pH carbonate bicarbonate environment but high pH SCC has not been reported.

FBE coatings are susceptible to construction damage, such as impact (Fig 4) and stonedamage, and require more care to contain this problem. Incorrect cure may also lead tocracking problems during field bending. Lowered adhesion of coatings at cut-backs has alsobeen experienced, usually due to a cold-end problem in the coating plant.


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Coating Material

Since the late 1950s FBE formulations have radically changed. These changes have usuallybeen for the better, giving increased flexibility, increased resistance to mechanical damage andincreased cathodic disbonding resistance, and increased temperature resistance.

All FBEs have a tendency to absorb moisture and soluble salts relatively easily. There arethree processes by which water and salts enter and penetrate the coating film, these are:osmosis, electro-osmosis and electrophoresis.

It is therefore extremely important that FBEs are correctly formulated. There have beeninstances where extra amounts of fillers have been added, to cheapen the product, with

disastrous results.

If the substrate is not clean corrosion can take place and the FBE film can blister and loseadhesion.

Coating Application

Problems encountered with the application of FBE coatings include the following:

Poor surface preparation: blast profile Poor surface preparation: residual corrosion products e.g. mill-scale Poor surface preparation: residual salt Poor surface preparation: residual dust Poor surface preparation: lack of chemical pre-treatments Low application temperature and poor flow High application temperature and foaming Excess thickness and foaming Incomplete cure Blistering

Most of these problems can be monitored and controlled by the application of a structured

quality control (QC) and testing programme in the pipe mill(8)

.

THROUGH LIFE COSTS


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A full cost model is beyond the scope of this paper which is concerned with pipeline coatingsso only costs incurred as a direct result of variable coating performance are considered.

The unit costs in the corrosion cost survey give a coating application cost for the 100 km

pipeline in the range $1.7m - $2.4m. An FBE coating is assumed to lie toward the bottom endof the scale of costs and 3LPE toward the top end. The unit cost of key stages in the surfacepreparation is estimated to cost between $51,000 and $72,000. These key stages includephosphoric acid wash, chromate pre-treatment and process controls to ensure appropriatesurface cleanliness, angularity of the blast profile and the optimum application temperature.

Various studies (10) have looked at construction issues relating to FBE and 3LPE coatings andconclude that projected savings, for example on selective or graded backfill, are only achievedin difficult terrain. Construction costs have therefore been excluded.

Unit costs for the applied CP scheme are assumed to be $50,000 regardless of coating type.CP specifications (3) do quote lower design currents for 3LPE in comparison FBE but this willnot have a major impact on CP system installation costs. In the authors experience the quoteddifference in design current (0.9 mA.m-2 for FBE and 0.4 m-2 for 3LPE for a 30 year design life)is not reflected in the actual current demand required in service. CP monitoring, to ISO 15589-

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(3)

, is not coating specific so no difference in through life CP monitoring is anticipated.

In line inspection is assumed to be a standard requirement and the CC Technology CorrosionCost survey quoted in line inspection costs as $3,200 5,300 per Km for gas lines and $4,600- $6,100 per Km for oil lines.

A typical through-life in line inspection programme for a modern pipeline will be based on fixedinspection intervals for a pipeline with effective corrosion control and minimal risk of external

damage. The net present value of a strategy based on an in line inspection every 10 years is$0.87m for a gas line and $1.06m for an oil line. An alternative strategy based on a postconstruction base line survey and repeat inspection at 15 year intervals gives a net presentvalue of $0.95m for a gas line and $1.17m for an oil line. These values have been calculatedassuming a 3 % annual depreciation.

A typical inspection strategy for a new pipeline with a 3LPE coating showing adhesionproblems is more intensive and includes excavations to investigate coating condition in the

early years and an initial in line inspection programme at 5 year intervals to monitor risks of CPshielding. Assuming that CP shielding is not a problem, and that a 10 year inspectionschedule is possible after 15 years, the net present cost of the through life inspectionprogramme is $1.65m for a gas line and $2.03m for an oil line.

If corrosion due to CP shielding is assumed the through life costs increase from repairs to the


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CONCLUSIONS

Modern pipeline coatings such as FBE and 3LPE have shown progressive development since

their introduction but the long term performance of these coatings is being undermined bycompromises during coating application. This problem is particularly severe for 3LPE coatings.

A compromise on the factors that control long term coating adhesion will show some saving incoating application costs. These factors include phosphoric acid washing, chromate pre-treatments, blast cleaning and complying with the optimum application temperature for FBE.However, the resulting reduction in long term coating adhesion incurs through life monitoring,inspection and maintenance costs that far outweigh any transient saving achieved in thecoating plant.

REFERENCES

1. CSA Standard Z245.20-02External Fusion Bond Epoxy Coating for Steel Pipe andExternal Polyethylene Coating for Pipe.

2. Norman D, Excellent pipeline coatings require excellent pipeline substratesNACE Corrosion 2004, Paper 04035

3. ISO 15589-1 Petroleum and natural gas industries Cathodic protection of pipelinetransportation systems. Part 1 Onshore pipelines

4. Winski J, Epicenter pipe-to-soil potentials measured without trailing cable.Pipeline and Gas Industry, V84, No6, June 2001

5. Beavers J A, Thompson N G, Corrosion beneath disbanded coatings: A review.NACE Corrosion 96, Paper 208

6. Schwenk W, Investigation of corrosion of steel pipe beneath PE coatings withoutwithout adhesion. 3R International 28 (6) 1989 pages 381-384


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C C Technologies

10. Thompson I, Espiner R, Barnett J, Coating backfill interactions on high pressuretransmission pipelines technical and financial issues.NACE Corrosion 2003 Paper 03046


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Figure 1: Coating failures resulting from unsuitable material properties

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Figure 2: Coating failures resulting from problems during application in the coating plant

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Figure 3: Coating failures resulting from problems during site application

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Figure 4: Coating failures resulting from inter-action with the backfill

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Figure 5: Coating failures resulting from problems during construction

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Figure 6: Coating failures caused by loss of adhesion in service

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