Pipeline coatings 24Todd ByrnesSaudi Aramco, Dhahran, Saudi Arabia

24.1 Introduction

It is hoped by the end of this chapter that the reader will leave with some understandingof what coatings are available and the salient points about how they function. In addi-tion, current trends in coating research and the key factors driving these efforts will beillustrated. Practical implementation of new technologies is the key focus, rather thanan in-depth analysis of the science.

When people talk about pipeline coatings, they think of them primarily as a barrierto aqueous corrosion. While that is a major role, coatings do so much more than just“block moisture.” Some other functions include the following:

• Separating the pipeline from corrosive chemicals, gases, and microbiologically influencedcorrosion (MIC).

• Reducing the amount of cathodic protection current required for corrosion mitigation.• Protecting piping against Corrosion Under Insulation (CUI).• Reflection of thermal radiation and insulation of the pipe contents from heat loss or heat gain.• Reducing the friction between the liquid media and the pipe wall.• Resisting abrasion and impact during transportation and burial.• Controlling pipe buoyancy in offshore applications.• Reducing or preventing deposit buildup, thus boosting production rates.• Passive fire protection (generally cementitious or intumescent coatings).

For example, it is widely perceived that internal pipeline coatings are there forcorrosion preventiondbut they are just as useful as “flow coats.” That is to reducethe friction between the viscous crude and the internal pipe wall. This allows morethroughput and hence greater production rates.

However, the two functions cannot be simply interchanged. A flow coat can beeffective from 40 mm (1.5 mils). That is, just enough to cover the “hills and valleys”of the steel surface roughness. But to operate as a meaningful corrosion barrier, it needsa minimum of about 125 mm (5 mils)! In addition to fulfilling such tasks, coatings alsohave to exhibit economy, functionality, and practicality.

Economymeans that the product itself must be inexpensive, and there must be a prac-tical pathway for its cheap application to the pipe (spray, brush, wrapping, fusing, etc.).

Functionality simply means that the product must withstand exposure to atmo-spheric, buried or immersion conditions, extremes of temperature, soil currents, soilstresses, microorganisms, pressure, aggressive chemicals, and so forth.

Practicality refers to the fact that the product must resist ultraviolet (UV) exposureand mechanical damage during storage and transportation, withstand mechanical

Trends in Oil and Gas Corrosion Research and Technologies. http://dx.doi.org/10.1016/B978-0-08-101105-8.00024-3Copyright © 2017 Elsevier Ltd. All rights reserved.

operations (bending, hydro-testing) in the field, and must be sufficiently abrasion andimpact resistant to survive the rigors of burial or thrust-boring activities.

This chapter only addresses tubular oil and gas gathering or flow lines, trunk lines,and transmission lines. This discussion does not cover plastic-coated pipes, drill pipes,risers, heat exchanger tubing, coatings under insulation etc, because their requirementsand protection mechanisms are outside the scope of this chapter.

24.2 Older technologies

As can be seen in Fig. 24.1, the first real external coatings were bituminous or tar based,which had the virtues of being sticky, water repellent, and available. Nevertheless,they were cheap and effective and up until 1978, coal tar enamel and cement mortarwere the only two coatings listed in the American Water Works Association(AWWA) standards!

The products in this section can still be commonly found, but their performance hasbeen, to some extent, superseded by newer products with superior characteristics [1].This is usually higher performance, better environmental compliance, easier and saferhandling, less demanding surface preparation, and so forth.

24.2.1 Coal tar enamel

Coal tar enamel (CTE) is a polymer-based coating produced from the plasticization ofcoal tar pitch, coal, and distillates. Inert fillers are added to provide the desired propertiesof the system. The coal tar pitch, which forms the basis for the enamel, consists ofpolynuclear aromatic hydrocarbons and heterocyclic compounds. Over the years, thiscoating has been used in conjunction with a primer, a fiber glass or mineral felt reinforce-ment, and an outerwrap [3]. A typical pipe specification isAWWAC203. Formore detailon any standard referenced throughout this chapter, please refer to Table 24.1.

1940

Coal tar enamel

Cold-applied tapes

Fusion bond epoxy

Mainline coating developments1940 - present

MLPP

Asphalt

2-layer PE

3-layer PE

1950

1960

1970

1980

1990

2000

Figure 24.1 Evolution of pipe mainline coatings [2].

564 Trends in Oil and Gas Corrosion Research and Technologies

Table 24.1 Summary of common external pipe and joint coatingstandards

Standard Title

AWWA C203 Coal-tar protective coatings and linings for steel water pipes

AWWA C210 Liquid-epoxy coating systems for the interior and exterior of steel waterpipelines

AWWA C214 Tape coating system for the exterior of steel water pipelines

AWWA C217 Petrolatum and petroleum wax tape coatings for the exterior ofconnections and fittings for steel water pipelines

AWWA C225 Fused polyolefin coating systems for the exterior of steel water pipelines

API RP 5L9 External fusion-bonded epoxy coating of line pipe

BS EN 10300 Steel tubes and fittings for onshore and offshore pipelines. Bitumen hotapplied materials for external coating

BS EN 12068 External organic coatings for the corrosion protection of buried orimmersed steel pipelines used in conjunction with cathodicprotectiondtapes and shrinkable materials

CSA Z245.20 Plant-applied external fusion-bonded epoxy coating for steel pipe

CSA Z245.21 Plant-applied external PE coating for pipe

CSA Z245.22 Plant-applied external polyurethane foam insulation coating for steel pipe

CSA Z245.30 Field-applied external coatings for steel pipeline systems

ISO 21809-1 Petroleum and natural gas industriesdExternal coatings for buried orsubmerged pipelines used in pipeline transportation systemsdPart 1:Polyolefin coatings (3-layer PE and 3-layer PP)

ISO 21809-2 Petroleum and natural gas industriesdExternal coatings for buried orsubmerged pipelines used in pipeline transportation systemsdPart 2:Single layer fusion-bonded epoxy coatings

ISO 21809-3 Petroleum and natural gas industriesdExternal coatings for buried orsubmerged pipelines used in pipeline transportation systemsdPart 3:Field joint coatings

ISO 21809-4 Petroleum and natural gas industriesdExternal coatings for buried orsubmerged pipelines used in pipeline transportation systemsdPart 4:Polyethylene coatings (two-layer PE)

ISO 21809-5 Petroleum and natural gas industriesdExternal coatings for buried orsubmerged pipelines used in pipeline transportation systemsdPart 5:External concrete coatings

NACE SP0394 Application, performance, and quality control of plant-applied singlelayer fusion-bonded epoxy external pipe coating

Pipeline coatings 565

The introduction of glass fiber inner wraps and the application of outer wrapsonto the coating surface improved the mechanical strength of the system and pro-vided extra protection against soil stresses and impact damage during handling andinstallation.

CTE coatings have very good electrical insulation and low water permeation prop-erties that resist bacterial attack and the solvent action of petroleum oils. Coal tar isparticularly durable and used for low-maintenance items. For example, the lock gatesof the Panama Canal have used CTE for decades [4]. CTE is still used under ConcreteWeight Coatings (CWCs) for offshore use. However, CTE has carcinogenic proper-ties, and many countries have now banned its use.

24.2.2 Asphalt

Asphalt is a by-product of the oil refining process, but can also occur naturally. Acommon specification is BS-EN-10300. Asphalt’s electrical resistivity and resistanceto water permeation tends to drop with time compared with those of coal tar, but it isone of the cheapest coatings on the market [5].

Although it looks and behaves in a similar fashion, it is chemically distinct fromcoal tar. Bituminous is sometimes used to refer to both CTE and asphalt, which causessome confusion.

24.2.3 Dielectric tapes/wraps

A typical tape system comprises a liquid primer applied on the steel, followed by oneor more layers of two-ply tape. Two-ply tape is usually made from polyethylene (PE)or polyvinyl chloride (PVC) with an adhesive layer of butyl rubber on one side. Thebacking tape and the adhesive are the “two plies” in the description.

Butyl rubber is sticky and adhesive with good resistance to oxygen (compare withtire bladders, which are mostly butyl rubber). PE and PVC have excellent water resis-tance and are strong dielectrics (i.e.; highly insulating). AWWA C214 is a well-knownspecification for tape coatings.

Robust adhesive backed outer wrap(s) are commonly used over the inner wrap(s)for mechanical protection. Variations exist where the cold adhesive is replaced by“hot-melt” adhesives as covered under AWWA C225, or the inner wrap has adhesiveplaced on both sides (3-ply tape) as discussed in BS-EN-12068.

While in principle it sounds like an ideal solution, tapes historically have receivedsome “bad press.” This is due to their susceptibility to soil stresses (which can wrinklethe tape) and the shielding properties of the PE/PVC. The dielectric (insulating) prop-erties that frustrate corrosion currents unfortunately also block protective cathodic pro-tection (CP) current. This, however, is only an issue if the tape disbonds. If CP currentis prevented from reaching the disbonded areas and water is present, then corrosion canprogress unchecked.

Three-ply or so-called “self-amalgamating” tapes are said to offer better perfor-mance over two-ply tapes. This is because with adhesive on one side only, therewill always be a defined interface along which moisture can travel. Because butyl

566 Trends in Oil and Gas Corrosion Research and Technologies

rubber is more like a viscoelastic than a solid, placing it on both sides (see Fig. 24.2)means the adhesives will merge, wherever it contacts itself and any interface will grad-ually disappear [6].

24.3 Current technologies

24.3.1 Fusion-bonded epoxy

Fusion-bonded epoxy (FBE) is also referred to as powder coating. The first commer-cial powder marketed in 1959 was 3M’s Scotchkote 101. To demonstrate the FBEpipe coating’s toughness to skeptical contractors familiar with coal tar coatings,3M representatives would “beat the coating off a coal tar enamel-coated pipe, witha piece of pipe coated with Scotchkote 101. The coal tar enamel flew off while theScotchkote coating remained intact” [8].

FBE is plant applied by the electrostatic application of micron-sized thermosettingpowders onto heated steel (see Fig. 24.3). The FBE powders melt and flow between180 and 250�C (356e482�F) and form a smooth, glossy film typically300e600 mm (12e24 mils) thick on the steel surface.

As the cross-linking reactions proceed, the film gels and ultimately cures. Thewhole process can take place in under a minute. Internal FBE coatings usuallymake use of a primer, generally phenolic. FBE sees wide application to mainlinepipe, girth welds (GWs), valves, etc.

The most important property of FBE and indeed all polymers is the glass transitiontemperature (Tg). This is the temperature at which the polymer transitions from a hardrigid state to a soft plastic material. Near the Tg, permeation of moisture and gasesbecomes easier.

Before the year 2000, most FBE only had a Tg of about 100�C (212�F) and werethus limited to operating temperatures of 60�C (140�F) [10]. Operating too close tothe Tg risks water absorption, which can decrease the Tg. However, operating tem-peratures greater than 150�C (302�F) are now possible.

FBE is applied relatively thin compared to other coatings, which means it is possiblefor some moisture to reach the steel-FBE interface. This allows for the conduction of

Figure 24.2 Three-ply (i.e.; double-sided adhesive) pipeline tape [7].

Pipeline coatings 567

sufficient CP current to protect the underlying steel. Very few failures due to cathodicshielding are known from FBE. Repair is usually achieved by liquid epoxies or FBEmelt sticks. Common specifications include CSA Z245.20, ISO 21809-2, API RP5L9, and NACE SP0394.

24.3.2 Dual-layer coatings

Sometimes, two layers coatings are specified (e.g.; Dual Layer FBE). The secondarylayer may be for abrasion resistance, a friction surface for CWCs, a thermal or impactbarrier, a UV barrier for increased corrosion resistance, and so on. The second layerneed not necessarily be the same as the first layer and could be polyurethane, polyester,or some other coating.

24.3.3 Polyolefin

PE and polypropylene (PP) are both examples of polyolefins (POs). POs are specifiedalmost as often as FBE for the protection of steel pipe.

PE is impermeable to water but has poor gouge resistance. PP has superior resis-tance to impact, indentation, abrasion and soil stress, excellent chemical resistance,and low water vapor transmission. PP is also resistant to higher operating temperaturesthan PE.

CSA Z245.21 is one of the more widely used specifications. Repair is by meltsticks or repair patches. There are instances where it can be used on GWs, but heatshrink sleeves (HSSs) are more typical. It is not practical for valves.

24.3.4 Two layerd2LPO

POs are nonpolar and do not bond well to steel. Therefore either a mastic orPE-copolymer adhesive is used to generate adhesion between the PO and steel (the

Figure 24.3 Fusion-bonded epoxy powder application onto heated pipe [9].

568 Trends in Oil and Gas Corrosion Research and Technologies

PO and the adhesive are the 2 layers in a 2LPO system). Mastic-based adhesives,although being relatively inexpensive, provide good cathodic disbondment (CD)resistance.

However, they have low shear and peel strength values and are restricted to low-temperature applications. Products based on copolymers have very good adhesionand shear resistance but generally poor CD resistance. CD is measured as the growthof a circular holiday made on an immersed coating subject to an electrical potential.The bigger the hole grows, the lower the resistance. A common specification for2LPO is ISO 21809-4.

24.3.5 Three layerd3LPO

A three-layer system consists of the PO, a copolymer adhesive layer and an FBE layeragainst the steel as a primer (hence 3 layer). All three layers are applied sequentiallyonto a prepared pipe as can be seen in Fig. 24.4.

The FBE has excellent adhesion to steel and is an excellent corrosion barrier,whereas the PO has excellent mechanical and impact properties. The copolymer haspolar functional groups grafted onto a PE or PP backbone, usually through reactionwith free radical initiators and maleic anhydride [12]. The resultant polymer thereforehas affinity with both the polar FBE and the nonpolar PO [13].

The PO itself is applied hotdeither by coextrusion or by side-extrusion (wrap-ping) as shown in Fig. 24.5. Usually the FBE, adhesive, and PO are applied withinseconds of each other, before completion of the cross-linking process to ensure thebest interlayer adhesion. A common 3LPO specification is ISO 21809-1.

Part of the limitation on the operating temperature of FBE is environmentalmoisture and mechanical impact at or near the Tg. However, because the PO jacketis a tough and very effective moisture barrier, 3LPE and 3LPP can sometimes beused at temperatures at or above the Tg of the FBE primer. This is tempered, however,by the reality that significant stresses are present in the PO coating that may damagethe primer layer if the Tg of the FBE is on par with the operating condition.

Figure 24.4 3LPE coating in-line application process [11].

Pipeline coatings 569

24.3.6 Liquid coatings

Liquid coatings can be applied by spray, brush, or roller. A typical standard is AWWAC210. Although the volumes of liquid coatings used for mainline pipes are smallcompared with FBE and 2LPO/3LPO, there are definite applications, for example,repairing other coatings, short coating runs, GWs, valves, spools, tanks, vessels,specialized environments (wear, chemical, UV), etc. where liquid coatings areindispensable.

Typically liquid paints tend to be epoxies, but almost any coating can be utilized toprotect pipe surfaces. Polyurethanes have been used for external UV protection, abra-sion coatings, and GWs. Even inorganic zinc has been used as an external coating forthe MorganeWhyalla above groundwater pipeline in South Australia, which hasdelivered outstanding service since 1944 [15].

For aggressive media, specialty formulations such as Epoxy Novalac are used tocombat low pH, high temperatures, and aggressive solvents. Baked phenolics areoccasionally used for the internals of tube heat exchangers because of their high chem-ical and heat resistance up to 200�C (392�F).

24.3.7 Tapes and wraps

24.3.7.1 Viscoelastic wraps

Viscoelastics are novel materials based on polyisobuteneethe same material used inchewing gum. They adhere to almost any surface, flow under pressure, and are insen-sitive to surface preparation. In addition, they are highly moisture repellent, immune topolar solvents and bacteria, and can be applied at very low temperatures. The materialis normally sold as a roll or tape with an internal mesh layer for support and a releasefilm. But it is also sold as a profiling putty or even an injectable liquid.

This system is occasionally described as being “CP compatible”; however, this ismisleading. CP compatible is generally understood to mean that CP current will passthrough a coating, and disbondment will not increase the risk of corrosion. In reality,viscoelastic systems are rarely used without a rigid outer wrap (usually PVC) to pro-vide rigidity and impact protection to the whole system. PVC or PE will not pass CPcurrent.

Shot blast

Inductionheating Extruded PE

layer

PE top coat

Epoxy powder Water spraycooling

Pipe endcleaning

Figure 24.5 3LPE inline coating process [14].

570 Trends in Oil and Gas Corrosion Research and Technologies

Therefore more accurate descriptions are “CD resistant” and “CP cooperative.”This is because in the event of a penetration the material will flow around and outof the hole, effectively healing the puncture. That is, the outer wrap is wound suffi-ciently tightly that the viscoelastic is placed under compression. In other words, CDvalues of zero or even negative values are possible!

The second point is that the material is so sticky that it tends to fail cohesively,rather than by disbondment (adhesively). This should be apparent from Fig. 24.6.That is significant quantities of material will always adhere to the steel, which meansthat no additional CP current will be required.

Field data suggest that this material has excellent corrosion resistance [17]. A rele-vant specification is CSA Z245.30. Viscoelastics can be used as maintenance coatings,for mainline pipes, GWs, valves, flanges, and other complicated shapes.

24.3.7.2 Wax tapes

Wax systems generally use a primer against the steel followed by a microcrystallinewax-impregnated carrier mesh. AWWA C217 is a typical specification. This productmakes use of the water-repellent properties of wax to exclude water from the steelsurface. An outer wrap is often required for mechanical protection. Wax tapes candry out and crack, and like all tapes, there is some possibility of damage due tosoil stresses. They are not commonly specified for mainline pipe or GWs, but theydo have good utility for valves, flanges, and other similarly complicated shapesbecause of their ability to conform to such surfaces.

24.3.7.3 “Cathodic protection-compatible” tapes

To retain the convenience of tape mounted systems, some manufacturers havedispensed with dielectric backings in favor of woven geotextile meshes or fabricsbacked with rubber-modified bituminous adhesive.

Figure 24.6 Viscoelastic with expanded carrier mesh and outer wrap [16].

Pipeline coatings 571

The geotextile is for shear and impact protection. The open weave of the tape ismeant to allow electrolyte (hence current) to access the surface of the tape, whereasthe adhesive adheres tenaciously to the steel, providing the corrosion protection[18]. These products are not common, and the number of manufacturers is limited.

24.3.8 Abrasion-resistant overlays

There is a distinction between pipe that is buried in rocky ground where impact resis-tance is desirable; and pipes that are thrust-bored where abrasion resistance is mandatory[19]. Both need tough, gouge-resistant coatings, and abrasion-resistant overlay (ARO) isthe blanket term used for both scenarios. AROs usually take the form of a secondarycoating over a primary corrosion barrier layer.

For alluvial soils, polyolefinic coatings or polyurethane might be quite satisfactory.For rockier soils, dual layer epoxies with superior hardness and gouge resistance areneeded. For severe soil conditions or horizontal directionally drilled applications,composite wraps employing fiber (glass) reinforcement or polymer concrete (a mixtureof concrete and epoxy) present a particularly hard wearing surface.

24.3.9 Concrete

Concrete is not a material that springs to mind as a corrosion coating; however, thepassivating action on iron and the self-healing properties of concrete actually makeit a very good solution for protection of steel. For example, an underground pipe linedwith cement mortar lining (CML) and externally coated with concrete was constructedin 1855 in St. John, New Brunswick, Canada. This pipeline was inspected in 1963 andstill found to be in reasonable condition [20]. Indeed mortar lining is still routinelyused for water transmission purposes. Incidentally, the mortar itself is occasionallyprotected with an organic coating to minimize leaching and calcification of the conduit.

In the context of the petrochemical industry, cement is used but mainly for buoy-ancy control on subsea pipelines, namely as Concrete Weight Coatings (CWC). ISO21809-5 is a common specification. Because concrete is permeable to chloride ionsand chloride depassivates steel, FBE (or CTE) is used as the corrosion barrier againststeel for offshore piping, with the concrete placed over the top. Concrete is alsooccasionally used as an ARO as described in the previous section.

24.3.10 Summary

Several standards that were referenced throughout this chapter are compiled inTable 24.1. They are good references for those interested in the different coating types.

Only the most commonly used coating materials were covered, but many othersare possible. For example polychloroprene, ethylene propylene diene monomer,and so on. The coatings discussed in the previous sections are summarized belowin Table 24.2, which also includes the maximum operating temperatures and benefitsand disadvantages of each method.

572 Trends in Oil and Gas Corrosion Research and Technologies

Table 24.2 Summary of modern external pipe coatingtechnologies [21]

Coating“Maximum”

temperature Benefit Disadvantage

FBE 90�C (194�F) • FBE is more flexiblethan other coatings,meaning pipes can bebent after coating inthe field.

• Excellent adhesion tosteel.

• Is able to pass cathodicprotection (CP) currenteliminating CPshielding.

• Cures instantly.

• Not as mechanicallyrobust as 3LPE.

• Pipe must be heated.

2LPE 60�C (140�F) • Cheap effectivecoating.

• Low temperatureresistance.

3LPE 90�C (194�F) • Damage tolerant,water impermeablecoating.

• Respectable tempera-ture resistance.

• Susceptible tocathodic shielding.

3LPP 140�C (284�F)

Liquid epoxy w150�C (302�F) • Tends to be a widerrange of chemistriesavailable to suitdifferent roles (e.g.;epoxy, polyurethane,etc.).

• Usual for field repairs.

• Pipe generally bentbefore coating.

• Cure is sensitive totemperature andhumidity.

• Very long curetimes.

Viscoelastic 80�C (176�F) • Excellent corrosionresistance.

• Excellent cathodicdisbondmentresistance.

• Self-healing properties.• High tolerance tounderpreparedsurfaces.

• Maintenanceproblematic.

• Limited temperature.

Pipeline coatings 573

24.4 Field joint coatings

Field joint (FJ)dalso referred to as GW coatingsdare listed here in a separate sectionfrom the mainline coatings covered in Sections 24.2 and 24.3, because they represent anumber of different challenges. These include the following:

• Ensuring adhesion between the mainline (parent) and FJ coating.• Maintaining quality in joint surface preparation and coating application, because such

coatings are usually applied in the field.• The need to execute the joint quickly. For offshore applications, the FJ and coating must be

completed in minutes, as the cost of the pipe-laying barge is measured in thousands of dollarsper day. The same applies to thrust-bored pipes, where the pipe string cannot be jacked untilthe preceding pipe GW and coating is completed.

• Practical issues such as availability of equipment and skilled personnel.

The history of FJ coating development is shown in Fig. 24.7. FBE powder or liquidpaints (e.g.; epoxies) are commonly used for the FJ of FBE mainline pipe. For POmainline pipes, there are a number of options. Tape wraps were traditionally employedas they were cheap, effective, and simple to use, but have fallen from favor because ofa number of historical failures. Similar failures have also been experienced under HSS.

In Table 24.3 are summarized the most common current external FJ coatings,including a description, benefits, and drawbacks. The code in the first column (labeled“Type”) is the same code to be found in Table 1 of ISO 21809-3, which is a morecomprehensive list of FJ coatings. This is to allow the reader to easily cross-reference between our table and the ISO 21809-3 table.

Most of the methods detailed are already familiar to the reader. New developmentsin FJ coating technology are discussed in later sections. A good source of informationregarding the field performance of GW coatings is the Gas Research Institute report;“Field Applied Pipeline Coatings” [22].

1940

1950

1960

1970

1980

1990

2000

Coal-tar enamel/asphalt

Mastic HSS

FBE

Hot melt HSS

Hybrid HSS

Tape

Field joint coatings development1940 - present

Urethane & epoxy

PP

Figure 24.7 Evolution of field joint coatings [2]. FBE, fusion-bonded epoxy; HSS, heat shrinksleeve; PP, polypropylene.

574 Trends in Oil and Gas Corrosion Research and Technologies

Table 24.3 Summary of common current external field joint coatings

Type Coating Description and benefits Drawbacks

1A Bituminous Hot applied bituminoustapes

Older method, notcommonly employed.

1C Wax tapes A blend ofmicrocrystallinewax-saturated syntheticfabric in tape form.Conforms to itemshape. Can have goodtemperature resistance.

Relatively soft.

1D Dielectric tapes Usually a PVC or PEbacked tape employinga butyl rubber adhesiveor fusible bituminousbacking. Simple toapply and good shortterm performance.

Liable to soil stress, lossof adhesion, substratedisbondment, andcathodic protection(CP) shielding effects.

1Ea Viscoelastic Excellent corrosionresistance.

Maintenance problematic.

Excellent cathodicdisbondmentresistance.

Low temperatureresistance.

Self-healing properties.

2A PE-based heat shrinksleeve (HSS)

Applied onto steel with amastic or hot meltbacked HSS. Used for2LPE mainlinecoatings.

Same as 2B, 2C.

2B PE/ polypropylene(PP) HSS for 3LPEmainline coatings

Steel is first primed withepoxy [e.g.; fusion-bonded epoxy (FBE)].A copolymer adhesivebacked HSS isemployed. Quick andcompatible with mostmainline coatings.

Some incidents ofdelamination due tosoil stress, etc.

2C Susceptible to cathodicshielding and pittingcorrosion.

3A FBE. Single or dualLayer

Compatible with mainlinepipes using FBE as theprimary corrosionprotection barrier.Compatible with CPprotection.

Requires inductionheating power supply.

3B

Continued

Pipeline coatings 575

24.4.1 Heat shrink sleeves

An HSS is a radiation cross-linked PO sheet with usually some form of adhesivebacking. For application to bare steel, either a mastic or hot melt adhesive would beemployed. For application to FBE (or liquid) epoxy primed pipe, a copolymer adhe-sive backing is preferred. In both cases, the sheet is wrapped around the GW andthe free ends joined by means of a closure strip.

The sleeve is then heated. The polymer chains “shrink” and the internal diameter(ID) of the wrap shrinks until it is tightly clamped onto the GW. Fig. 24.8 is anexample of a sleeved GW. A successful application is usually signaled by the absenceof wrinkles in the sleeve and the uniform extrusion of the adhesive from out of theopen end(s) of the sleeve.

However on occasion the heating is uneven, or soil stress deforms the shrink. Thiscan generate a path for moisture to enter. Because the wrap is a strong dielectric,cathodic protection is unable to combat corrosion underneath the film. HSSs are stillpopular, but CP shielding and pitting failures can be the result if the specification orapplication is poorly executed.

Table 24.3 Continued

Type Coating Description and benefits Drawbacks

4A Liquid Paint Tends to be a wider rangeof chemistries availableto suit different roles.Does not needspecialized equipment.

Takes time to cureusually.

4B Epoxy or polyurethane

5A Thermally sprayedPE/PP (3LPO)

Epoxy primer is required.Highly compatible withpolyolefin mainlinepipe.

Not commonly used.

5D

5B Hot spiral woundpolyolefin (PO)(3LPO)

A heated tape of PO iswound around the girthweld (GW) afterapplication of the FBEand adhesive.

Properties similar toparent coating.

5E

5C Injection-molded PP(3LPP)

The GW is coated withFBE and thencopolymer adhesive. Amold is placed aroundthe GW and liquid PP isinjected into the cavity.

Fast system for offshoreuse.

576 Trends in Oil and Gas Corrosion Research and Technologies

24.5 Challenges and drivers

Improvements in pipeline coating technologies are influenced by four main drivers:Economics, Legislation, Innovation, and Efficiency.

Economics means the cost associated with the construction (capital cost) andongoing maintenance of a coated pipeline. These can be broken down into thefollowing:

• Material Costs: the costs of the paints and abrasives used.• Labor Costs: associated with mobilization, surface preparation, coating application, stand-by

time etc. Upfront material and labor costs can be lumped together under the term CAPEX(capital expenditure).

• Maintenance Costs: associated with maintaining the coating to a reasonable condition. Thefrequency of maintenance depends on the quality of the original specification and productsused, skill of the applicator, and so on. These costs are sometimes described as OPEX (oper-ating expenses).

Improvement in any one of these areas translates into a financial or performancewindfall for the asset owner.

Legislation alludes to the greater scrutiny that operators are subjected to, thanks toa greater public awareness of the environmental and safety consequences posed by“uncontrolled hydrocarbon releases.” The Santa Barbara incident in May 2015, wherea 24” pipeline failed and released 2934 barrels of heavy crude oil (500 of which wentinto the Pacific Ocean), is a recent example [24]. This even impacts testing protocols,because the best way to avoid failures is to ensure that the standards are truly represen-tative of operating conditions.

Innovation implies advancements in technology that facilitate new opportunitiespreviously considered unfeasible. For example; FBE coatings beyond 150�C(302�F) will allow exploitation of oil reservoirs inaccessible to “older” technologies,

Figure 24.8 Heat shrink sleeve [23].

Pipeline coatings 577

which translates into greater national economic output. Some other examples of imme-diate industry challenges would be the following:

• Internal coatings resistant to methanol and monoethylene glycol or MEG (used for hydrateprevention) at temperatures above 60�C (140�F).

• Successful application of FBE onto high strength steel at temperatures, without adverselyimpacting the metallurgical properties of the pipe.

• External coatings for subsea piping below 2000 m (6560 ft.). That is, lower profile, lowerweight, better insulating coatings, resistant to higher pressures.

• Internal coatings for sour gas service (>5 mol% H2S, >8 mol% CO2) with service temper-atures higher than 95�C (203�F).

• More rapidly applied or cured GW coatings (powder, liquid or wraps) for offshore or thrust-boring applications.

• More resistant and flexible ARO coatings.• Improvement in PO chemistries and elimination of the adhesive layer in 3LPO applications

(direct application of PO onto FBE).• External coatings with improved adhesion and lower CD values.• Improved standard testing methodologies that better reflect and predict real-life

environments.

Other challenges include the growing use of biofuels (e.g., ethanol), which tend tohave more moisture absorption and MIC problems. Carbon sequestration means coat-ings that will have to resist 100% CO2. Oil sands and shale oil are very viscous, abra-sive, and tend to be transported at elevated temperatures. As exploration delves intothe Arctic, permafrost and ultra-low temperatures present issues for application andoperation of coated lines.

Efficiency relates to any technological advance that will decrease running costs (orboost production) under a fixed set of operating conditions. An example would be theuse of a smoother ID coating to increase production rates on an existing line.

24.6 Incremental technologies

The term “incremental” in the section title refers to the fact that most progress revolvesaround steadily improving the properties of coatings that are already functioning in aparticular role. So what are the properties of interest for pipeline coatings and how arethey being improved?

24.6.1 Improved heat and pressure resistance

Before we start, the important property of the Tg should be defined. Each polymer hasa different Tg value, and it represents a point where the intermolecular forces thatrender the polymer chains relatively immobile with respect to one another are over-come by the thermally activated motion of those chains.

Therefore as the temperature is increased, a transition from a rigid to a rubbery stateis observed. This is particularly important for coatings as the rate of diffusion of water,

578 Trends in Oil and Gas Corrosion Research and Technologies

anions, cations, and oxygen accelerates at temperatures beyond the Tg [25]. Thefurther the operating temperature is below the Tg, the more inelastic the behavior.This can cause issues with pipe bending and so on. The Tg can be influenced byaltering the base chemistry, the functional groups, chain lengths, degree of cross-linking, and crystallinity of the polymer.

The current maximum temperature limit for commercial FBE is around 125�C(257�F). While higher Tg epoxies can already be realized by using highly function-alized resin systems to increase the cross-link density, this negatively impacts the flex-ibility of the material. Therefore most efforts have been aimed at increasing thestiffness of the polymeric backbone. Operating temperatures above 150�C (302�F)are seen as attainable.

An example is OUDRATherm HPC 6510, which DOW claims can deliver a Tg of160�C (320�F) [26]. AXALTA says that has developed a product with a Tg of 180�C(356�F) and good resistance to high levels of H2S and CO2 [27]. These performancesare a large improvement on current products.

Of course, research is not only limited to epoxies and many other systems includingpolyetherimides, bismaleimides, polycyanurates, vinyl esters, fluorinated compounds,and so forth are under investigation [28].

24.6.2 Low application temperature fusion-bonded epoxy

To achieve optimal performance, current FBE products require application tempera-tures in excess of 230�C (446�F) for single layer systems and 200�C (392�F) forthree-layer systems. The introduction of high-strength steels such as X80, X100,and X120 for use in pipeline construction has presented a challenge to the industryin terms of the availability of suitable coating systems.

High-strength steels (particularly grades X100 and greater) cannot withstand preheattemperatures in excess of 200�C (392�F). Exposure to the high heat required whencoating with a typical FBE product results in the degradation of some of the key prop-erties of these high strength steels. Low application temperature (LAT) chemistries thatcan be applied under 180�C (356�F) are under development [29].

One project in Alberta Canada, applied a LAT primer onto 3600 X-120 steel,followed by a high-performance composite coating system (HPCC) 3LPE typecoating with good results [30]. LAT products are also useful for offshore GW coat-ings, where the shorter heating times mean more production and hence greater costsavings.

24.6.3 High-performance composite coating system

An HPCC system is a monolithic, all powder, multicomponent coating system con-sisting of an FBE base coat, a tie layer containing a chemically modified PE adhesive,and a medium-density PE outer coat. All three components of the composite coatingare applied as powders, using an electrostatic powderecoating process.

The tie layer is a blend of adhesive and FBE with a gradation of FBE concentration.Thus there is no sharp and well-defined interface between the tie layer and the FBE

Pipeline coatings 579

base coat, nor with the PE outer coat. The adhesive and PE are similar to each other andintermingle easily to disperse any interface.

The coats are therefore strongly interlocked and behave as a single-layer coatingsystem without the risk of delamination. Delamination has been a performance issuewith some three-layer PE coatings, especially under cyclic conditions. Being a singlelayer coating and thinner, the HPCC will have less internal stress development whensubjected to large temperature changes.

24.6.4 Improved chemical resistance

Of the world’s remaining conventional gas reserves to be produced, approximately40%drepresenting over 2600 trillion cubic feet (tcf)dare sour. Among these sourreserves, more than 350 tcf contain H2S in excess of 10 mol%, and almost 700 tcfcontain over 10 mol% CO2 [31]. For example the Kashagan Field in the CaspianSea has 15 mol% H2S and 4 mol% CO2.

Acid gases such as H2S and CO2 are highly corrosive, and new resin chemistries arerequired to deal with them. As existing wells age, seawater is often injected to boostreservoir pressures. However, this increases the water-cut of the produced oil andintroduces oxygen, chlorides, and bacteria with corresponding negative impacts ondownstream pipelines.

A 2008 United States Geological Survey (USGS) report estimated that 90 billionbarrels of undiscovered, technically recoverable oil, 1670 trillion cubic feet of tech-nically recoverable natural gas, and 44 billion barrels of technically recoverablenatural gas liquids are contained north of the Arctic Circle. Of this figuredwhichrepresents 13% of the expected undiscovered oil in the worldd84% is expected tooccur offshore [32].

But with lower temperatures comes a greater likelihood of methane hydrate forma-tion, which can build up and plug a pipeline. The common solution thereto is withmethanol or MEG injection. However, these chemicals are highly aggressive toorganic coatings.

Many firms are working on products to meet all of the challenges mentioned. Onesuch example is ethylene-chlorotrifluoroethylene (ECTFE) powder coatings, whichcan withstand very high concentrations of chemicals up to 150�C (302�F) but can stillbe applied using conventional powder application methods [33]. Fluorinated coatingsare already in common use for offshore and subsea fasteners.

24.6.5 Improved flow properties

The use of internal flow coatings has many beneficial effects: control over corrosionduring storage and operation, improved flow and production rates, and reduced foulingand fuel (pumping) costs [34]. The degree of drag imposed by the coating onto themedia depends on the physical smoothness of the coating and/or the physio-chemicalaffinity between the coating and the media.

One manufacturer produces a flow coat that provides a pipe surface that is over 50%smoother, with surface roughness reduced to 1e4 mm (0.04e0.15 mil). Compare this

580 Trends in Oil and Gas Corrosion Research and Technologies

with 20e35 mm (0.78e1.37 mil) for bare steel, or 10e15 mm (0.4e0.6 mils) forsolvent-based coatings. The term IPC (Internal Plastic Coating) is sometimes usedfor flow coats. See also Section 24.7.4 on hydrophobic coatings.

24.6.6 Improved abrasion resistance

For coated pipes buried in rocky ground or pipes installed by thrust boring, resistanceto abrasion, impact, and gouging are essential. The same applies to pipes installed bymicrotunneling, pipe jacking, or horizontal directional drilling. Currently the chiefmeans of protection is with dual layer FBE coatings. Work is being done on eventougher FBE coatings, but polyurethaneda highly wear resistant materialdis alsosometimes specified.

For particularly severe conditions, laminate wraps using glass or carbon fiber in ther-moset resins are gradually being adopted. The main problem with ARO type coatingsdand that includes the GWsdis that there is a strong time pressure to apply and curethem, because the pipe string is usually laid as soon as the GW or ARO layer is ready.

24.6.7 Improved mechanical properties

Improved mechanical properties such as flexibility (resistance to cracking) are partic-ularly desirable in liquid coatings subject to bending. Products such as FBE alreadytend to have good flexibility (�3 degrees/PD). This is important because pipes areoften bent in the field to accommodate changes in terrain. Some concrete jacketingproducts even claim to have some capacity for bending.

24.6.8 Improved insulation

As offshore exploration pushes into deeper waters, more effective insulation isrequired to prevent cooling of the product. As the temperature drops, the viscosityof the fluid and the risk of hydrate formation rise. Hydrates, also known as methaneclathrates, can solidify and block a flowline.

The immense subsea pressures mean that the external insulation must be incom-pressible and prevent migration of water to the steel interface. It turns out that PP isan ideal candidate. PP can be foamed to various densities. It can be filled with glass(up to 25%) to form “syntactic polypropylene.” Or it can be used as a solid coating.As the density of the PP increases, so does the incompressibility, but at the expenseof the insulation factor.

So ubiquitous is this PP insulation technology, that new designations have beendeveloped to communicate the concept within the industry. For example, 5LPP issimilar to 3LPP, but with an added thick layer of PP insulation, finished off with anouter shield layer as demonstrated in Fig. 24.9. Sometimes an additional insulating/shield layer is added, forming 7LPP. Even more layers can be added, giving rise towhat is known as “multilayer coatings.”

Treatment of GWs in such pipes is difficult. If HSSs are used, insulation must befirst formed in place using temporary molds or preformed sections cut to fit. Only

Pipeline coatings 581

then can the HSS be installed at the FJ and shrunk. If the outer GW jacket is rigid, itmust be installed first and joined to the parent material by mastic adhesive or fusionwelding. Then the foam can be injected or foamed in place using the jacket as amold. CSA Z245.22 is a useful reference for further discussion of this technology.

24.6.9 Advances in preparation and application

If a coating engineer had a wish list, it might include coatings tolerant of marginalsurface preparation, insensitive to surface contamination (salts, oxidation, humidity)and applicable by unskilled labor. Other items on the list might include the ability toreliably blast and coat smaller diameter pipe (using robotic techniques), improvedinspection possibilities (again via robotic techniques), less environmentally damagingproducts (reduced waste, lower VOC’s), and so forth. These are all areas of activeinvestigation.

24.6.10 3LPO field joint coatings

One of the limitations of 3LPO coating is that the application of the FBE primer, thecopolymer adhesive layer and the final PO topcoat are applied within seconds of eachother to ensure that sufficient unreacted functional groups are available to react anddevelop decent interfacial adhesion between each layer. This can be problematic forFJs.

A new product which combines the adhesive and the PO components together isbased on a semi-interpenetrating network (IPN) of linear POs and a cross-linkablemonomeric epoxy [36]. The term “protective network coatings (PNCs)” is used inter-changeably with IPN.

An example is Scotchkote’s PNC1011. This is sold as tape in 1600e2800 wide rolls of1 mm (40 mil) thick film. It can be applied directly to a gelled or cured FBE primer bymachine in under 6 minutes. Multiple layers can be applied up to 3 mm total. It bondsequally well to itself, the FBE, and the PO parent coating. The benefit of such productsis that the adhesive application step is eliminated and processing times are speeded upconsiderably.

21

1. Fusion bonded epoxy 2. Adhesive 3. Solid PP 4. TDF 5. Outer shield

34

5

Figure 24.9 5LPP insulated pipe [35].

582 Trends in Oil and Gas Corrosion Research and Technologies

Other providers offer a complete GW coating system where a machine applies theFBE powder coat, followed by a hot melt PE. The PE is modified with active func-tional groups so that an intermediate adhesive layer is not required to ensure bondingto the FBE [37].

24.6.11 Advances in testing and standards

There are many shortcomings in existing test standards. For example, older weatheringtests had poor correlation to actual field results. For CUI coatings, there are no inter-national standards. Accurate testing is particularly critical in an era where coating (i.e.;pipe) failures can attract heavy fines and intense scrutiny.

Coatings subject to cathodic protection are at risk of CD. This is because wherethere are breaks in the coating, alkaline conditions are generated, which may degradethe ability of the coating to adhere to the steel. New products that are tolerant of muchhigher CP current densities are being produced.

Most of the existing standard CD test methods were originally designed for onshorepipeline applications with service temperatures �95�C (203�F). Limited CD data areavailable for testing temperatures higher than 95�C (203�F). There is also some debateabout the best place to measure the test temperature in the experimental set-up, becausethis will obviously affect the results.

That existing standards or their modifications are suitable for the needs of subsea/deep-water pipeline applications needs to be investigated with the proliferation of newhigher temperature and often much thicker coating systems [38].

24.7 “Breakout” technologies

“Breakout” refers to innovations and products that are not familiar to average coatingengineer and represent a significant departure from current practice. Many of the newdevelopments revolve around an explosion of research into smart coatings, surfaceengineering, and nanotechnology.

24.7.1 Self-healing coatings

“Smart” coatingsdespecially ones that automatically react to repair or limit corrosionin the event of damagedare nothing new. The use of zinc to cathodically protect galva-nized steel was first recorded in 1742 by Melouin [39]. Chromate conversion coatingshave been used for the last century to passivate nonferrous alloys. The leachingbehavior of chromate allows it to repassivate exposed metal in the presence of sufficientmoisture.

Chrome-free self-passivating coatings have been developed, such as ChemicallyBonded Phosphate Ceramics (CBPC) that show 10,000 hours resistance underASTM B117 testing [40]. CBPC takes the well-known passivating effect of phos-phates on iron but complements it with a secondary ceramic layer, which acts as a

Pipeline coatings 583

reservoir for phosphate to maintain the passivated layer. As might be anticipated, thiscoating exhibits unique heat, flame, abrasion and chemical resistance, and good ther-mal and electrical insulating behavior. It requires little surface preparation and can bereturned to service an hour after application.

Next imagine a coating that cracks or is scratched, exposing millions of imbeddedpores. Now imagine that in half the pores is a liquid resin, and in the other half is aliquid catalyst. Or maybe all the pores are resin filled, with polymerization triggeredby moisture or oxygen from the environment or by electrochemical reactions associ-ated with corrosion [41].

For example, anodic (corroding) sites are associated with increasing acidity,whereas the cathodic areas are associated with alkalinity. Whatever the mechanism,these newly liberated materials flow or react and protect the damaged area. The activeagents could be added as immiscible submicron-sized droplets, which would be evenlydispersed in the parent coating during the mixing process. Or they could be “prepack-aged” in micron-sized inert shells.

Another variation is that otherwise-soluble inhibitors could be held in nanostruc-tures formed by solegel chemistry for release as a result of chemical or mechanicalstress from the environment.

Inherently conducting polymers (ICPs) such as polyaniline (PANI) are believed toanodically protect steel by maintaining the steel potential in the passive region. Or bybecoming itself (the ICP) polarized through galvanic coupling to the base metal sub-strate at defects in the coating such that the ICP releases an inhibiting anion. Bothcathodic reduction of the conducting polymer and ion exchange with cathodicallygenerated OH�, or both, can lead to the release of the anion dopant. When the aniondopant is a corrosion inhibitor, damage-responsive corrosion protection occurs [42].

24.7.2 Self-inspecting coatings

Self-inspecting or self-monitoring is a loose term applied to coatings, which do morethan just passively fail. That is, they are able to signal distress or loss of performance tothe asset owner. Some examples already familiar to the engineer are bleaching (due tochemicals or excessive potentials), the use of multilayered coatings of different colors(useful as wear indicators as each successive layer is exposed), pH-sensitive coatings(that change color, courtesy of the addition of pH-sensitive indicator), and so on.However, these are all visual effects.

Coatings possess many more interesting properties such as capacitance, impedance,resistance, etc. These in turn are affected by temperature, strain, interfacial reactions(at the steel surface), and so on. On macroscopic levels, these influences are moderatedby thinning, cracking, and swelling of the coating film. Therefore changes in baseproperties can be indicative of macroscopic damage.

Such changes can be detected by sensors internal or external to the pipe. A miniaturesensor has been developed, which is attached to the internal pipe wall and is hiddenunderneath an internal polyurethane lining. External piezoelectric devices communicatewith the internal sensor through the pipe wall ultrasonically. The internal sensors in turnfeed back the information regarding thinning of the polyurethane lining. This is useful

584 Trends in Oil and Gas Corrosion Research and Technologies

in slurry pipelines where there are high rates of wear [43]. Another example is the incor-poration of Fiber Optic Bragg gratings into external coatings for measuring strain andother properties [44].

24.7.3 Nanotechnology

Nanotechnology, in the context of paint, normally relates to the addition of nanosizedadditions with a view to achieve certain outcomes. By way of analogy, lamellar Mica-ceous Iron Oxide pigment has been added to paint since the 1900s because of its barriereffect to the diffusion of moisture and oxygen [45]. In the 1970s glass and aluminumflake was added for a similar reason.

While nanotechnology can manifest itself in a variety of applications, the onus willbe to try to concentrate here on solutions that are firmly on the nanoscale. A goodexample is the partial replacement of zinc in zinc-rich coatings with carbon nanotubes.The reason why the zinc loading is traditionally so high is to ensure particle-to-particle(i.e.; electrical) contact. If the protective current could be “short-circuited” through thecoating to where it is needed (areas of exposed steel) by carbon nanotubes instead, thiswould represent a significant weight and cost savings to the coating purchaser.

It turns out that nanotube impregnated coatings also have a raft of other unexpectedbenefits. For example; the nanotubes also work like composite fibers, adding strengthand crack resistance to the coatings [46].

Another example is built-in controlled-release corrosion inhibitors (CRCIs). That is,the CRCI is encapsulated in a micron-sized ceramic shell or absorbed inside the internalcavities of a porous spheredready to passivate the steel whenever a “free surface” isexposed. For example, when the overlying coating is gouged or penetrated. Porousparticles, unlike ceramic shells, allow the paint to withstand vigorous mixing [47].

24.7.4 Hydrophobic coatings

Hydrophobic surfaces have immense potential for corrosion “repellent” surfaces,biofouling reduction, drag minimization, and microbial-resistant surfaces. Water is avery destructive element. It is the electrolyte for most corrosion processes and canpermeateprotectivecoatings, resulting inosmoticblistering, loweringof theTg, and soon.

Hydrophobic coatings operate on the relatively simple assumption, that if one caneliminate water before it has a chance to permeate the coating, then one should be ableto greatly extend the service life of the coating. A number of products are already onthe market and do indeed have some impressive water-repelling properties.

ACULON is a commercial coating used for superhydrophobicity and oleophobic-ity and also antifouling applications. Superhydrophobicity can be realized by mate-rials such as polysiloxanes, fluoroalkylsilanes, or fluoropolymers; or by loweringthe surface energy by using densely packed and vertically aligned carbon nanotubesor polyacrylonitrile (PAN) nanofibers.

Other techniques include self-assembled monolayers of phosphonates, organometal-lics, and so forth. Hydrofoe by LotusLeaf Coatings uses microtexturing nanotechnologyto mimic the bumps on lotus leaves, which lowers the surface energy to generate waterrepellency.

Pipeline coatings 585

24.7.5 Antifouling coatings

Fouling refers to the deposition on internal pipe walls of biological organisms (e.g.;zebra mussels) or marine flora, scale buildup (e.g.; carbonates in hard water systems),hydrocarbon deposits such as waxes in oil lines or in the case of subsea gas linesdmethane hydrates.

Combating fouling requires injection of antibiological agents, water-treatmentchemicals, insulation systems, and deicing agents, depending on the cause. Apartfrom being expensive, chemicals can sometimes damage the coating and more oftenthan not, are an inefficient means of control. Surface treatments or coating modificationthat could prevent these deposits in the first place would be more efficient and couldavoid continuous injection and monitoring.

Hydrophobic coatings have already been given as an example. Smith et al. havedeveloped a functionalized coating with reduced hydrate adhesion to internal pipesurfaces [48], whereas Subramanyam discovered that nanotextured surfaces filledwith a lubricating liquid effectively prevent scale adhesion [49].

24.7.6 Microbiologically influenced corrosion-resistant coatings

Various active and passive compounds can be imbedded into a coating, which aredestructive to the attachment and replication of certain microbiological organisms,known to attack coatings or the pipe itself. For example, sulfate-reducing bacteriagenerate acid conditions, which will cause metal loss.

Some coatings exploit surface effects such as surface tension to prevent the attach-ment of microorganisms, whereas others incorporate antimicrobial agents into thepaints in the form of fillers or encapsulated chemicals. Graphene has been identifiedas being effective against MIC attack [50].

Other coatings incorporating silver and copper colloids have been promoted.Silanes like the AEGIS antimicrobial coating use polysiloxane to destroy microbialcells. Effective antimicrobial surface coatings can be based on an anti-adhesive prin-ciple that prevents bacteria from adhering, or on bactericidal strategies where organ-isms are killed either before or after contact is made with the surface. Manystrategies, however, implement a multifunctional approach that incorporates all ofthese mechanisms.

For anti-adhesive strategies the use of polymer chains or hydrogels is preferred.Bacterial destruction can be achieved using antimicrobial peptides, antibiotics, chito-san or enzymes directly bound, tethered through spacer-molecules or encased inbiodegradable matrices, nanoparticles, and quaternary ammonium compounds.

24.7.7 Nonmetallic solutions

Because this is out of the scope of the chapter, only a cursory examination of this topicwill be made. Alternatives to coated steel pipe have existed now for several decades.RTR (reinforced thermosetting resin) pipe uses thermosetting resins and is thereforesomewhat rigid. It is used for large diameter pipes such as desalination transmissionlines.

586 Trends in Oil and Gas Corrosion Research and Technologies

Unlike the familiar PE and PVC piping, reinforced thermoplastic pipe (RTP)dalsoknown as flexible composite pipedis available with pressure ratings from 300 to1500 psig (2.1e10.3 MPa) and is chiefly supplied in internal diameters from 2” to 5”(50e125 mm). RTP is simply a thermoplastic like HDPE with internal reinforcement(e.g.; braided PET). It is spoolable and flexible. An example use might be offshore risers.

Whatever the case, the absence of steel means the absence of corrosion. Whileexternal polyolefinic coatings are nothing new, drawn polymeric pipe liners for newand existing pipes are seeing wider application as the lining technology improves.Thick inert liners such as HDPE and polytetrafluoroethylene (PTFE) offer particularlygood chemical resistance and are used for drain lines, acid lines, etc.

While such a discussion may be somewhat removed from the coating sphere, it isstill important to understand that as the nonmetallic technology improves, coated steelpipe will be pushed out of more and more applications.

24.7.8 Encapsulant materials

Considerable effort has been directed at protecting line pipe and FJsdbut mechanicalconnections such as flanges, valves and well heads often suffer the worst corrosion,thanks to their complex three-dimensional geometries. The reason behind this is thatprotective coatings have a hard time maintaining a minimum coating thickness onsharp edges (thanks to surface tension effects), whereas tapes and wraps struggle toconform to sharp changes in section.

Such equipment usually requires far more inspection and maintenance, which isalmost an impossibility for semi-permanent solutions such as tapes and wraps. Evencoatings are not ideal as protection usually takes the form of a single continuousfilm. Bolted joints cannot be disassembled without breaking this film, and reinstate-ment of the coating in the field is much more difficult than in the shop.

Mechanical protection techniques such as Band Protectors and Bolt Caps have beenthe traditional solution, but limitations in all the discussed methods have driven thedevelopment of total Encapsulation systems. Encapsulants are basically thick buildelastomeric polymers, deliberately engineered to have no adhesion to the substrate.This is to enable rapid removal, rapid inspection, and rapid resealing of the encapsu-lated equipment.

That is the polymer can be cut, stretched, peeled away, and resealed in minutes. The“lack of adhesion” is usually achieved by incorporating a corrosion inhibitorsomewhere in the system. This has the side benefit that protection is available to theequipment should the encapsulation be penetrated. All the mentioned points can beobserved in Fig. 24.10. The thickness of the encapsulation is typically very high to main-tain structural integrity and to act as a diffusion barrier to moisture, salt, and oxygen.

Some commercial products are brush applied and are built up in layers of 2e3 mm.For these products, peeling from the substrate is achieved by application of an initialprimer layer of corrosion inhibitor, except at the free ends where adhesion is requiredto prevent water ingress. The benefits of this system are ease of application and repairin the field coupled with higher flexibility. The limitation is temperature resistanceof 60�C (140�F).

Pipeline coatings 587

Other products use fusible thermoplastics (usually cellulosic), which are meltedon-site and “spray” applied. Typical application temperatures are 165�C (329�F).They can be built to almost any thickness. The product acts as a jacket that can becut and peeled away to allow rapid inspection and resealed again using a smallermelt device. Decohesion from the substrate is achieved by imbedding the corrosioninhibitor (usually an oil) into the product itself.

This product however, suffers from a lack of adhesion to the pipe at the free endsthanks to the corrosion inhibitor. The polymer is typically less flexible than the brushproduct and application, and repair can be more complicated. However, ASTM B-117salt spray resistance values exceeding 11,000 hours are not uncommon.

24.7.9 “Green” coatings

The move to 100% solids coatings has been driven by the desire to eliminate harmfulsolvent emissions (VOC’s) on environmental and Occupational Health and Safetygrounds. The success of this can be seen in the widespread usage of FBE and 100%solids coatings.

Similar concerns plus the nonrenewable nature of petrochemical-based coating rawmaterials and precursors have encouraged the development of plant-based resins,monomers, and reactants. Some products such as RILSAN-PA11 by ARKEMA, basedon the Castor Oil Plant, have been around for 60 years. Continuing research has led tomany substitutions like a Bisphenol-A free coating based on acetoacetyl-modifiedsoybean oil [52].

24.8 Conclusion

The earliest recorded use of pipe to transport hydrocarbons dates back to the Chinese in1000 CE, where bamboo piping was used to transport natural gas used in the heating of

Figure 24.10 Brush applied, flexible, peelable encapsulation [51].

588 Trends in Oil and Gas Corrosion Research and Technologies

brine. However, it was not until the advent of steel pipes in the 1900s that the firstconcerted pipeline coatings emerged.

The first coating c.1920 was probably coal tar or asphalt, poured directly onto steelpipe in the trench, and smeared on with a mitt and/or rag. Within the space of100 years, coatings have been developed which can operate up to 150�C (302�F) inquite severe conditions. However, the number of emerging technologies suggests anexplosion of innovation in the coming decades.

This is not only important to the exploitation of the world’s current resources, but isinstrumental in meeting the challenges of the next century like pipelines for carbonsequestration and biofuel transport.

Those interested in learning more about current coatings are referred to the excel-lent publication “Onshore Pipelines: The Road to Success” by the International PipeLine & Offshore Contractors Association (IPLOCA) for more information [53].

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