corrosion control in the oil and gas industry || mitigation – external corrosion

Mitigation – External Corrosion

CHAPTER

9
9.1 IntroductionThe external surfaces of oil and gas infrastructure are exposed either to the atmosphere (abovegroundstructure) or an underground environment (buried in soil or submerged in water). The standard pro-cedure for controlling external corrosion of structures exposed to the atmosphere is the application ofelectrically insulating coatings, and for underground structure, is the use of electrically insulatedcoatings and cathodic protection (CP).1–3 Coating is the first line of defense against external corrosion.If this fails, CP should act as backup, protecting those areas where the coatings have failed. Regu-lations in many countries require that all the external surfaces of underground structure are protectedby these two systems.
This chapter provides an overview of the coatings and cathodic protection used to mitigate externalcorrosion in oil and gas infrastructures.

9.2 CoatingsCoatings control corrosion by physically isolating the structure from the environment. The coatingsused in the industry have evolved over the years. They can be broadly classified into polymericcoatings, metallic coatings, girth weld coatings, insulators, and concrete coatings. Table 9.1 presentsthe various oil and gas sectors in which different classes of coating are used.

9.2.1 Polymeric coatingsPolymeric coatings are the workhorse in the oil and gas industry, and are used to protect the externalsurface of many infrastructures.4 They are used as aesthetic and anti-corrosion coatings for above-ground structures, and as anti-corrosion coatings for buried or submerged infrastructures. Figure 9.1presents the polymeric coatings used over the past 80 years.5

In the 1930s and 1940s, coal tar coatings were commonly used and were applied in the field. In the1950s and 1960s, asphalt and coal tar coatings were commonly used and were applied in the field. Waxand vinyl tapes were also used to some extent during this time. In the mid-1950s, extruded poly-ethylene (two layer) coatings applied in the mill were introduced, and have continued in use since thenprimarily on small diameter pipes. From the 1960s to the 1980s, polyethylene (PE) tape coatings,either single or double wrap, were applied in the field. In the early 1970s, mill-applied fusion bondedepoxy (FBE) coatings were introduced, and have been increasingly used on large diameter lines since

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00009-1

Copyright � 2014 Elsevier Inc. All rights reserved.529

http://dx.doi.org/10.1016/B978-0-12-397022-0.00009-1

Table 9.1 External Coatings Used in Various Oil and Gas Sectors

Sector ComponentType of ExternalCoatings Unique Reasons

Production Drill Pipe • Usually not used

Casing Pipe • Usually not used

Downhole Tubular • Polymeric• Concrete

• Concrete coatings are usedin downhole tubular toprevent collapse of pipeline.

Acidizing Pipe • Polymeric• Concrete

Water Generators • Polymeric

Gas Generators • Polymeric

Open mining • Not applicable

In situ Production • Polymeric• Insulators

• Insulators are used in in situproduction pipeline tomaintain highertemperature.

Wellhead • Polymeric

Pipelines • Polymeric• Insulators• Thermal spray• Girthweld

• Insulators are used inoffshore productionpipelines to avoid hydrateformation.

• Thermal spray coatings areused in offshore pipeline toprovide cathodicprotection.

• Girthweld coatings areapplied in the field after theline pipes are weldedtogether.

Heavy Crude Oil Pipelines • Polymeric• Insulators• Girthweld

HydrotransportationPipelines

• Polymeric• Girthweld

Separators • Polymeric

Gas Dehydration Facilities • Polymeric

Recovery Centers(Extraction)

• Polymeric

Upgraders • Polymeric• Insulators

Waste Water Pipelines • Polymeric• Girthweld

Tailing Pipelines • Polymeric• Girthweld

Lease Tanks • Polymeric

530 CHAPTER 9 Mitigation – External Corrosion

Table 9.1 External Coatings Used in Various Oil and Gas Sectors Continued

Sector ComponentType of ExternalCoatings Unique Reasons

Transmission-pipelines

Transmission Pipelines(Midstream Pipelines)


Compressor Stations • Polymeric

Pump Stations • Polymeric

Pipeline Accessories • Polymeric

Transportation-Tankers

Ships • Polymeric

LNG Tanks • PolymericInsulators

Railcars • Polymeric

Other modes • Polymeric

Storage Gas Storage N/A

Oil Storage • Polymeric

Refining Refineries • Polymeric• Insulators

Distribution Product Pipelines • Polymeric• Girthweld

Terminals • Polymeric

City Gates and LocalDistribution


CNG Tanks • Polymeric

Special Diluent Pipelines • Polymeric• Girthweld

CO2 Pipelines • Polymeric• Girthweld

Biofuel Infrastructure • Polymeric• Girthweld

High Vapor PressurePipelines


Hydrogen Pipelines • Polymeric• Girthweld

9.2 Coatings 531

that time. They are now commonly used in North America. Since the 1980s, extruded three layercoatings have been in use in Europe and Japan. These consist of an inner layer of FBE and an adhesivelayer followed by an outer polyolefin (polyethylene or polypropylene) layer. In the 1990s compositecoatings were introduced. Composite coatings are a variation of three layer coating with inner FBE andouter polyolefin layers, but the adhesive is replaced with a graded layer of FBE and modifiedpolyethylene.

9.2.1a Coal tarCoal tar enamels are thermoplastic in nature and are applied by pouring hot enamel on the structure tobe protected.

1930 1940 1950 1960 1970 1980 1990 2000 2010

year

Coal Tar

Wax & Vinyl Tape

Asphalt

2-Layer

Polyethylene Tape

Fusion Bonded Epoxy

3-LayerComposite

FIGURE 9.1 Coatings Applied in the Oil and Gas Industry Over the Years.5


i. TypesA typical coal-tar enamel coating consists of liquid primers (adhesives), coal tar enamels, inner-wraps,outer-wraps, and finish coats (kraft paper, whitewash and/or water-emulsion latex paint).

Liquid primers (adhesives) produce a bond between the metal and coal tar enamel. They areapplied by brushing or spraying. The adhesives are prepared by dissolving coal tar pitch, coal tar oils,chlorinated rubber, and synthetic plasticizer in a suitable solvent.

The coal tar enamels are prepared by dissolving processed coal tar pitch and inert mineral filler in asolvent (typically hydrocarbon oil). It is manufactured in three basic categories: unplasticized orregular enamel, semi-plasticized, and fully-plasticized.6 Regular enamel is a hard product. It has thehigher resistance to moisture, petroleum oils, and soil stress but it has the narrowest temperature rangeof service and the least flexibility. Semi and fully plasticized coatings are produced by addition ofsmall amounts of a special coal to the coal tar pitch. Semi-plasticized enamel has a wider servicetemperature range (�18 to 60�C (0 to 140�F)) than the regular grade, and is somewhat more flexible.Fully plasticized enamel is produced in various grades for different service conditions. These areparticularly suitable for pipeline applications.

The inner wrap is a thin, flexible, uniform mat consisting of porous glass fibers bound together by aresin. It may be reinforced or non-reinforced. It is compatible with the coal tar enamel coating and itstexture allows for it to be completely embedded within the coating material.

There are three types of outer wraps: non-woven glass fiber, woven glass fiber, and laminated glassfiber. They are uniformly impregnated with coal tar enamel and are porous, so that the coal tar enamelbleeds through them and fuses into the finish coats.

The finish coat may consist of one or more layers of kraft paper, whitewash, and/or latex paint. Kraftpaper is a smooth and water-repellent material bonded onto the outer-wrap. The type of kraft paper, thename of the applicator, and the name of steelmanufacturer are normally printed on it.Whitewash consists

9.2 Coatings 533

of linseed oil, quicklime, and salts all dissolved in water, and is applied on top of the outer-wrap. Latexpaint consists of synthetic materials and pigments in water. After application the synthetic materialscoalesce and dry, producing a white-colored, water-resistant layer that adheres onto the outer-wrap.

Certain coal tar enamel coatings may also be applied at room temperature (cold-applied). Cold-applied coatings usually are used on structures exposed to mildly corrosive environments and notunderground infrastructure.7

ii. Laboratory performanceThe properties of coal tar enamels vary widely because of the differences in ingredients, raw materials(especially coal), and manufacturing processes. Standard laboratory methodologies are used toestablish minimum performance criteria. The performance requirements are described in the followingstandards:

• ANSI/AWWA C202, ‘Coal Tar Protective Coatings and Linings for Steel Water Pipelines –Enamel and Tape – Hot Applied’

• NACE RP399, ‘Plant-Applied, External Coal tar Enamel Pipe Coating Systems: Application,Performance, and Quality Control’

• ANSI/AWWAC210, ‘Liquid Epoxy Coating Systems for the Interior and Exterior of Steel WaterPipelines’

• NACE RP0602, ‘Field-Applied Coat Tar Enamel Pipe Coating Systems: Application,Performance, and Quality Control’

iii. Field performanceCoal tar coatings have a low permeability to moisture (water), high dielectric resistance, good anti-fouling properties and they are resistant to barnacles. All these properties contribute to their goodcorrosion resistance and performance in marine environment. Only small amounts of current arerequired to cathodically protect structures coated with coal tar. Coal tar coatings do not normallyshield the current, but there have been a few reports of coal tar coatings disbonding in a manner thatprevents the cathodic protection current from reaching the pipeline. In those instances, the pipeline issusceptible to corrosion. Excessive cathodic protection, on the other hand, may exfoliate coal tarcoatings.

Coal tar coatings have a tendency to alligator when exposed to sunlight; the outer-wrap of thecoating hardens, contracts, and slips over the inner-wrap causing alligator marks. Coal tar coatings,therefore, should be protected from the sunlight. High operating temperature has resulted in cracks incoal tar coatings.

Coal tar coatings are brittle at low ambient temperatures and have low adherence to steel at highambient temperatures. Therefore temperature control during transportation and construction isimportant; otherwise these coatings may crack and disbond.

The most frequent type of failure of coal tar enamel coatings during operation is associated withimproper surface preparation. Studies have indicated that coal tar coatings applied to wire-brushedsurfaces failed within one year, whereas the same coatings applied on sandblasted surfaces (surfaceprofile is 1.5 to 3.5 mils (38 to 90 mm)) were in a satisfactory condition after five years exposure in thesame environment. Many of the problems experienced with coal tar enamel coatings could have beenminimized or even eliminated had there been a better understanding of surface preparation in the 1930sand 1940s, when these coatings were extensively applied.


iv. State-of-the-artUntil the 1960s, coal tar coatings were used extensively to protect steel pipelines in the oil and gasindustry. However, since the 1970s, their usage declined progressively because of the variation in theproperties of coal tar, limited supply of materials, environmental pollution during application (pouringof hot coal tar emits toxic fumes), and development of other superior materials. Currently, coal tarcoatings are not extensively applied on new infrastructure but those which have already been coatedwith coal tar coatings do continue to operate.

9.2.1b AsphaltAsphalt is a dark colored cementatious material that is thermoplastic in nature. Its predominantconstituent is bitumen. Asphalt is non-toxic and relatively tasteless. Chemically, it is a stable,polymeric, aliphatic hydrocarbon which has good resistance to water and chemicals. Asphalt variesin its chemical and physical characteristics, depending on the temperatures to which it issubjected during the distillation process. It has softening points ranging between 38 and 93�C (100 and200�F).

Asphalt is available as enamel, emulsion, or cutback. Asphalt enamel is a solid at ambient tem-perature and has a high softening point. Asphalt emulsion is a dispersion of asphalt particles in anaqueous phase. Small amounts of chemicals or clay are used as emulsifiers. The emulsion can beclassified as anionic, cationic, or non-ionic depending on the electrical charge on the asphalt particle.Asphalt cutback is a liquid solution of asphalt in a volatile solvent.

i. TypesThere are two types of asphalt coatings: asphalt enamel and asphalt mastic.Asphalt enamel. An asphalt enamel coating consists of primer, enamel, and reinforcing and protectivewrappers. Table 9.2 presents typical constituents of asphalt enamel.8,9 The primer is a blend of asphaltin a petroleum solvent which may be applied at room temperature (i.e., cold-applied) by brushing orspraying. Before application of the primer, any oil and grease on the surfaces of the steel pipe areremoved with a petroleum solvent. The pipe surface is thoroughly cleaned by blasting, wire brushingor scraping. However, it should be noted that at the time when asphalt coatings were predominantlyused, the conditions during the preparation of the steel surface were not tightly controlled. When theprimer has dried, the hot asphalt enamel (typically at around 204�C (400�F)) is applied. The asphaltenamel consists of petroleum asphalt combined with appropriate inert mineral fillers. The wrapper isthen applied simultaneously along with hot enamel. The wrapper may be single-wrap, double wrap, ormultiple-wrap.Asphalt mastic. Mastic coating consists of a prime, mastic, and whitewash. Typical minimumthickness of the mastic coating is 0.64 cm (0.25in.). The primer is applied in the same manner as theprimer for asphalt enamel coating. When the primer has dried, the hot mastic mixture is applied. Themastic is a mixture of binder, mineral aggregate and miner filler, and is applied onto primer at tem-peratures between 128 and 204�C (280 and 400�F). The finished mastic coating is painted with awhitewash prepared from quick lime in water.

ii. Laboratory performanceMany laboratory experiments conducted between 1910 and 1950s recommended asphalt coating as theprimary coating of choice for protecting the external surface of underground pipelines. Cathodic

Table 9.2 Constituents of Asphalt Enamel8,9

Asphalt Enamel -Constituents(layers fromsteel pipe) Single-Wrap

Double Wrap

Multiple-WrapSingle Coat Double Coat

First 1 Coat of asphalt primer 1 Coat primer 1 Coat primer For multi-wrap coatingsadditional coatings of hotasphalt enamel andwraps of asphaltsaturated felt, glass mat,or asphalt saturated glasswrap are used. Kraftpaper may be used for theoutside wrap only, toprevent adhesion toadjacent pipes or otherobjects

Second 1 Coat of hot asphaltenamel 3/32 inch � 1/32

1 Coat of hot asphaltenamel 3/32 inch � 1/32

1 Coat of hot asphaltenamel 3/32 inch � 1/32

Third 1 wrap of asphaltsaturated feltA or asphaltsaturated glass wrapcompletely bonded to theenamel

1 wrap of glass mat(embedded in coating)

1 wrap of asphaltsaturated felt, asphaltsaturated glass wrap orglass mat completelybonded to the enamel

Fourth 1 wrap of asphaltsaturated felt or asphaltsaturated glass wrapcompletely bonded to theenamel

1 Coat of hot asphaltenamel 2/32 inchminimum

Fifth 1 wrap of asphaltsaturated felt or asphaltsaturated glass wrapcompletely bonded to theenamel

Athe felt may be made of asbestos

9.2

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disbondment testing was extensively used to select the appropriate composition of asphalt coatings.Table 9.3 lists other tests used to evaluate asphalt coatings.10,11 Standards providing guidelines onperformance tests include:

• BS 3690, ‘Bitumens for building and civil engineering specifications for bitumens for road andother paved areas’

• EN 10300, ‘Steel tubes and fittings for onshore and offshore pipelines - bituminous hot appliedmaterials for external coatings’

iii. Field performanceThe field performance of asphalt coating was extensively investigated in the 1950s and 1960s. Onestudy found that the coating resistance decreased to about 7% of the original value over a period of 10years. In spite of this substantial decrease in coating resistance, the current requirement after ten yearswas relatively small, and the pipeline did not suffer any corrosion damage.12

In another study, a 539 km (335 mi.) 41 cm (16 in.) diameter pipeline constructed in the 1940s wassurveyed twice at approximately ten year intervals.13 After ten years, the Pearson survey (see section11.3.6) revealed 200 anomalies: 23% of which were characterized as weak, 57% as moderate, and 20%as strong. Forty anomalies (characterized as strong) were excavated and the performance of the asphaltcoating examined (Table 9.4). Of over 278,700 m2 (3 million sq. ft.) of asphalt mastic coating, only4.6 m2 (50 sq. ft.) was damaged. The coating discontinuity was measured as 1 per 6.4 km (4 mi.) ofpipeline. The coating conductance was also low, indicating that the water absorption of the coating waslimited (Table 9.5).

After approximately 20 years, the follow-up coating conductance survey (see section 11.3.4) wasconducted and the results were compared with the 10 year survey data. Progressive deterioration of thecoating as a whole was not evident, and the coating conductance was still relatively low, indicating thatthe coating was still adequately protecting the surface. Two discontinuities, which had been classifiedas medium signal strength during the 10 year survey, were excavated.14 At both locations the dis-continuities had enlarged in area, and the pipe surface had rusted to a considerable extent, although nopitting of the pipe was observed. The coating adhered to the soil lumps and had little or no bond to thepipe. The coating on the soil lump had softened to the extent that a hole could be dug in the masticwith a knife.

In one location, the 20 year survey indicated that the coating discontinuity exceeded the length ofthe 122 cm (4 ft.) bell hole. This discontinuity should have been classified as a major discontinuity 10years previously, but there was no indication of it in the 10-year survey. (It would appear the coatinghad progressively disintegrated at the holidays between the two surveys.) At another location in whichthe aboveground survey indicated no anomaly, 305 m (1,000 ft.) section of pipe was excavated. Theinspection revealed two coating blisters of approximately 10 cm (4 in.) in diameter and of approxi-mately 9.5 mm (3/8 in.) in height. The blistered coating was 12.7 mm (1/2 in.) thick and had no visiblecracks or pinholes. The pipe surface under the blisters was dry, but had rusted considerably, indicatingthat cathodic protection had not reached the pipe surface below the blister. The coating in theremaining inspected portion of the pipe adhered onto the pipe well, including the areas adjacent to theblisters. It was not known whether these blisters were caused by some incident at the time of con-struction or resulted from cathodic protection current.

One common problem observed with asphalt coating is the bleeding of the asphalt enamel throughthe outer wrap.15 When this happens, the asphalt coating softens on the side covering the steel and

Table 9.3 Methods for Testing Asphalt Coatings10,11

Standards

Property Primer for Enamel Primer for Mastic Enamel Binder for Mastic

Flash point Bureau of Explosives, AASHOMethod of Test T79

Bureau of Explosives, AASHOMethod of Test T79

ASTM D 92 ASTM D 92

Viscosity ASTM D 88 ASTM D 88

Distillation ASTM D 402 ASTM D 402

Penetration ASTM D 5 ASTM D 5 ASTM D 5 ASTM D 5

Softening point ASTM D 36 ASTM D 36 ASTM D 36 ASTM D 36

Solubility in carbontetrachloride (except that CCl4is used instead of CS2)

ASTM D 4 ASTM D 4 ASTM D 4 ASTM D 4

Bond strength NACE T-6A-19

Loss of heating at 325 �F ASTM D 6 ASTM D 6

Ash ASTM D 271

Durability ASTM D 113

Sieve analysis ASTM D 546

Impact strength, bending test,depression test, and electricalresistance

NACE T-6A-19

9.2

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Table 9.5 Field Performance on Asphalt Coatings13

MilesInspected

Approximate Ageof Coating, Years

Pearson SurveyResults

Average CoatingConductance,Micromhos per sq. foot

4e25 Less than 5 Not performed 1.21

6.8 10 No discontinuities 1.01

6.0 10 No discontinuities 1.54

50 10 Discontinuities 6.6

Table 9.4 Conditions of Asphalt Coatings after about Ten Years in the Field13

Conditions of Asphalt Coating Number of Locations

Total number of excavations 40

Friable mastic) 21

Tool abrasion (e.g., construction damage) 7

Miscellaneous 6

None found (Several discontinuities asindicated by Pearson survey upon excavationand visible inspection showed no obvious flawor disintegration of the coating)

6

)Loss of cohesion between the asphalt and mineral aggregate giving the coating a friedappearance


disbonds from it. Another common problem with asphalt coating is cracking and moisture absorption.When an asphalt coating ages, it loses its flexibility; consequently it cracks and absorbs moisture. Soilstress on pipelines further contributes to the cracking. The cracks result from repeated shrinking andswelling of soils (especially clay) due to fluctuations in their moisture content. For these reasons,asphalt coatings, particularly enamel, have very low resistance to soil stress. Because of moistureabsorption, porous asphalt coatings pass cathodic protection current. For this reason stress corrosioncracking (SCC) is less prevalent under asphalt coatings.16

Most field problems with asphalt coatings have been attributed to the quality of application.Asphalt coatings were predominantly applied in the field, and the extent of surface preparation,particularly in the early days of the pipeline industry, was minimal when compared to today’s stan-dards. Had the external surfaces of the steel structure been better prepared prior to the application ofthe coating, their performance would have been even better.

iv. State-of-the-artAsphalt coatings are no longer in common use for onshore underground infrastructure, primarilybecause of the availability of better, mill-applied coatings. Some companies may still use them onconcrete-coated offshore pipelines.

9.2 Coatings 539

9.2.1c TapeThe use of tapes as a pipeline coating originated from their successful application for insulatingelectrical wires. Tapes may be applied in the mill or in the field.17–18 The development of procedures towrap them onto the pipeline in the field made tape coatings popular in the 1970s. The tapes may bespirally wrapped by hand, or, more frequently, by machines.

i. TypesEight tape coatings are frequently used in the oil and gas industry.19–21 The following section describesthe constituents of these coatings, and Table 9.6 compares their performance.Polyethylene (PE). Polyethylene (PE) is a linear or highly-branched polymer with a crystallinestructure. The density of low density polyethylene (LDPE) is in the range 0.91 to 0.93 g/cm3 (0.0329 to0.0336 lb/in.3) and that of high density polyethylene (HDPE) is in the range 0.94 and 0.97 g/cm3 (0.034and 0.035 lb/in.3). When compared to LDPE, the HDPE has a larger crystalline structure, higher yieldstrength, higher creep resistance, and is less permeable to aqueous phase, but it has lower resistance toelongation. The PE used as tape coatings is mostly LDPE, or a blend of LDPE and HDPE. Overthe years, the compositions and performance of the coatings have been continuously improved.22–24

Table 9.7, for example, compares the properties of PE pipeline tapes used in the 1960s with those usedin the 1970s. Some constituents of polyethylene type degrade at temperatures above 54�C (130�F),therefore polyethylene tapes are typically used to protect infrastructure operating at temperaturesbelow 50�C (122�F).

A typical polyethylene tape consists of three layers: adhesive, inner anti-corrosion tape, and outermechanical protection tape. The inner and outer layers are prefabricated as rolls. The adhesive is amixture of rubber and synthetic compounds in a suitable solvent, which is applied in the liquid form toa properly prepared surface. It provides a bond between the surface and the inner tape layer. The innertape layer consists of a polyethylene backing layer and a laminated butyl-adhesive layer. The innerlayer is applied after the liquid-adhesive and before the outer layer tape. The outer layer is also a two-layer tape consisting of a polyolefin backing layer and a laminated butyl-adhesive layer.

One common failure mode of polyethylene tape is disbondment, usually caused by soil stress.The outer layer also has good resistance to the adhesion of foreign material, but still certain soils,e.g., clay can attach onto polyethylene tape. When this occurs, the polyethylene tape is stretched byalternate wetting (expansion) and drying (contraction). This problem cannot be overcome even withproper application, because polyethylene tapes stretch easily. The disbonded tape coating normallyshields the cathodic protection current, and if water enters the area beneath the disbonded tape,corrosion occurs.Polyvinyl chloride (PVC). Polyvinyl chloride (PVC) tapes have characteristics similar to polyethylenetapes. They resist ultraviolet (UV) rays, but are stiff and lack conformability, so they are primarily usedon aboveground rather than underground structures. Plasticized PVC tapes, however, are flexible.Polymer alloy. Polymer alloy tapes also have characteristics similar to PVC tapes, but they are not asstiff. Therefore they can be used as coatings to protect both aboveground and below-groundinfrastructures.Hot applied. Hot applied tapes consist of a bituminous material within a fabric. These tapes are pliableenough to unwind from the roll. The adhesive is first applied on the surface, and the pipe is heated toapproximately 120�C (250�F) to facilitate the bonding of the adhesive onto the pipe surface and that ofthe tape onto the adhesive.

Table 9.6 Comparison of Pipeline Tape Coatings19e24

Properties Polyethylene

PolyvinylChloride

PolymerAlloy

HotApplied Wax

WovenPolyolefinGeotextileFabric

Tapes withIntegratedPrimers Co-Extruded

Soil stress resistance Poor Poor Poor Good Poor Good Poor Better

Adhesion to steel Good Good Good Good Poor Good Good Better

CP Shielding Poor Poor Poor Good Good Better Poor Better

Handling in Field Good Good Good Better Poor Good Good Good

Damage repair Good Good Good Better Better Good Good Better

Compatable field jointmaterial

Better Good Better Better Better Poor Better Better

Bending Compatibility Better Good Good Poor Poor Poor Good Better

Ease of Application Better Good Good Poor Better Poor Good Good

Resistance to Bacteria Better Better Better Poor Poor Poor Better Better

Cathodic Disbondment Good Good Good Better Good Good Good Better

Surface Preparation Good Good Good Better Better Good Good Good

540

CHAPTER9

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Table 9.7 Comparison of Polyethylene Tape Pipeline Coating Properties20e24

Property

Manufactured in

1960’s 1970’s

Backing composition 100% Low densitypolyethylene

60e80% Low densitypolyethylene þ 20e40% Highdensity polyethylene

Backing thicknessA 0.23 mm 0.30 mm

Adhesive type Pressure sensitive Butyl rubber based

Adhesive thicknessA 0.1 mm 0.2 mm

Tensile strengthA 4.5 kg/cm width 5.8 kg/cm width

Adhesion to primed steelA 1.1 kg/cm width 3.0 kg/cm width

Dielectric strengthA 13,000 volts 20,000 volts

Impact resistanceB 4.5 kg/cm 8 kg/cm

Tear resistanceC 3.6 kg 6.0 kg

AASTM D-1000 Test MethodBASTM G8 Test MethodCASTM G-1004 Test Method

9.2 Coatings 541

Wax. Wax tapes are made from plastic fiber saturated with a blend of petrolatum waxes, plasticizers,and corrosion inhibitors. Wax tapes are easy to apply but are vulnerable to construction and physicaldamage, so they are often backed with PVC or PE tape to provide mechanical protection.Woven polyolefin geotextile fabric. Some coatings use woven polyolefin geotextile fabric (WGF)materials as their backbone. The woven fabric materials provide both mechanical and corrosionprotection. WGF tapes stretch to a lesser extent. For example, typical polyethylene tape stretches by upto 600%, but WGF stretches by only 15%. For this reason, WGF resists soil stress better than poly-ethylene tapes. In addition due to their fabric backbone they are cathodic protection compatible.Tapes with integrated primers. Tapes with integrated primers are similar to the PE tapes when theyhave a solid-backing and are similar to WGF tapes when they have a mesh backing. The experiencewith this type of coating is limited.Co-extruded. Co-extruded tapes contain, in addition to the normal ingredients of PE, synthetic butylrubber adhesive.

ii. Laboratory performanceThe performance requirements are described in the following standards:

• ANSI/AWWA C214, ‘Tape Coating Systems for the Exterior of Steel Water Pipelines’• ANSI/AWWA C209, ‘Cold-Applied Tape Coatings for the Exterior of Special Sections,

Connections, and Fittings for Steel Water Pipelines’

iii. Field performanceTape coating was first applied to a 19 km (12 mi) long, 20 cm (8 in.) diameter natural gas pipeline in1954 in Texas. An evaluation in 1970 indicated that this line was still in operation and the polyethylenetape coating was in good condition.25


Between 1954 and 1956, the use of plastic tapes on pipelines grew, mainly due to the developmentof power-driven equipment to apply the coating in the field on pipe sizes in the 15 to 25 cm (6 to 10 in.)range. Equipment for applying the tape coatings on larger diameter pipelines was developed by 1956.In 1958, polyethylene tape was applied to 2,414 km (1,500 mi.) of 15 to 61 cm (6 to 24 in.) diameternatural gas transmission pipeline. This was the first major pipeline to be externally protected withpolyethylene tape. The first stationary wrapping equipment was fabricated in 1959. The combinationof stationary wrapping equipment and polyethylene was well suited to field application, since itallowed polyethylene tape to be extensively and quickly applied in the field.

In 1965, the ability to apply plastic tape in extremely cold weather conditions was demonstratedwhen 1.98 mm (78 mils) of 76 cm (30 in.) pipeline was coated with polyethylene tape in NorthernAlberta, Canada. The temperature fell to as low as �35�C (�31�F) during application. Daily appli-cation rates reached 3,658–3,962 m (12,000–13,000 ft), which was equivalent to the application ratesat warmer temperatures.

In 1967, a coating mill was built to apply a polyethylene tape coating. In this mill, the tape wasapplied automatically to full lengths of pipe, practically as the pipe was being made. By 1968,approximately 120,696 to 160,929 km (75,000 to 100,000 mi.) of pipelines of different sizes had beencoated with polyethylene tape. In 1968 alone, polyethylene tape was applied to more than 9,656 km(6,000 mi.) of pipeline, of diameters between 13 and 132 cm (5 and 52 in.). In 1971, the length ofpipeline applied with polyethylene tape coating increased to the equivalent of 11,265 km (7,000 mi.) of76 cm (30 in.) diameter pipe. Most of the coatings were applied to pipelines of diameters between41 cm (16 in.) and 122 cm (48 in.).

Table 9.8 compares the coating conductance of a polyethylene pipeline coating over a period ofabout 20 years. The coating was applied to a 150 mm (6 in.) diameter pipeline of 48 km (30 mi.)

Table 9.8 Coating Conductance of Polyethylene Tape and Coal Tar Coatings in

Comparable Environments

Age of Coatings (Years)

Coating Conductance, (mmhos/m3)

Coal Tar Enamel Polyethylene Tape

1 80.2 e

2 178.2 45.9

3 467.0 70

4 258.2 76.5

5 903.8 78.3

6 1248.2 70

7 1635.0 106.4

8 1108.3 98.3

9 1291.2 108.9

10 1527.9 188.1

11 2388.7 239.0

12 2238.1 212.4

16 e 520

19 e 700

Table 9.9 Current Requirements to apply Cathodic Protection on a Polyethylene

Tape Coated Pipeline (48 Km length of w 200 mm Diameter Pipeline)

Year Current Requirements (mA/m2) Pipe to Soil Potential (mV)

1958 7.5 1270e2000

1963 11.4 1275e1875

1964 10.5 1350e1700

1965 12.6 1200e1675

1968 13.6 1175e1600

1969 14.8 1125e1600

1970 16.1 1050e1325

1971 18.1 950Ae1650

1972 14.9 950Ae1650

1974 16.9 1000Ae1650

Alow P/S potential reading was measured at point of bond to a crossing pipeline

9.2 Coatings 543

in length. The conductance of the tape coating was 700 mmhos/m2 (72 mmhos/ft2) indicating that it hadretained its physical, chemical, dielectric, and moisture resistance properties even after 20 years ofoperation. The coating conductance of coal tar enamel coating in a similar operating environment wasalmost one order of magnitude higher than that of polyethylene tape.26–27

Table 9.9 compares the current requirements for a polyethylene tape coating on 48 km (30 mi.) of200 mm (8 in.) pipeline. The current requirement increased from the initial 7.5 mA/m2 (0.7 mA/ft2) to16.9 mA/m2 (1.6 mA/ft2) after 16 years of service. Several other studies have also indicated low currentrequirements for protecting different polyethylene coated pipelines (Table 9.10).

Table 9.11 presents the CP current requirement data of more than 35,404 km (22,000 mi.) ofpipelines in North America for a two year period. These pipelines were of various sizes and were

Table 9.10 Typical Current Requirements to Apply Cathodic Protection of Coated Pipelines

CoatingPipeDiameter, mm Pipe Length, km

ConstructionDate

Current Density(mA/m2)

Polyethylene tape 457 140 1969 11.8

Polyethylene tape 203 148 1962 78.5

Polyethylene tape 863 1260 1963e69 50.6

963 450 1962e68 31.6

50 92 1967 76.4

Polyethylene) 50 234 (of which 159 km coatedwith polyethylene tape)

1971 31.2

Coal Tar Enamel) 50 234 (of which 76 km coatedwith coal tar enamel)

1971 132.3

)on same pipeline

Table 9.11 Current Requirements to Apply Cathodic Protection on Pipelines Coated with Different

Coatings26,27

Type of Coating Length of Pipe (Miles)Average PipeDiameter (Inches)

Current Required (mA per Sq.ft.)

Average Range

Polyethylene Tape 3,648 12.5 9.6 0.2e95

Asphalt 6,552 18.0 6.5 0.5e550

Coal Tar 10,744 20.4 10.5 0.1e260

Wax 1,056 19.5 11.0 0.2e684

Other 395 8.3 0.9 0.1e10

Total 22,395 9.4 0.1e684


coated with different coatings: coal tar, asphalt, wax, and polyethylene tape. The soil and serviceconditions of all pipelines were comparable. The cathodic protection current demand values werecomparable, but the variation of CP current demand of tape coatings was relatively low.

By the late 1980s and early 1990s, after 25 years of successful usage, the industry started expe-riencing problems with the polyethylene tape coatings. The main problems include: shielding ofcathodic protection current; disbondment at welds and dents; damage due to rock impingement; soilstress problems; and tenting that occurs between the pipe surface and the tape along the ridge createdby the longitudinal weld reinforcement (Figure 9.2).

For polyethylene tape coatings, the cohesion (its ability to adhere to itself) exceeds the adhesion (itsability to adhere to the pipe). When ground water moves in the gap between coating and pipe surface,corrodes the pipe, and forms corrosion products under the tape. The volume of corrosion productsexceeds that of the corroded steel, so the corrosion products mechanically force the polyethylene tapefrom the metal surface. Since the tape’s cohesion exceeds its adhesion, the tape disbonds from themetal surface. The wedge created by the corrosion products between the pipe and the polyethylenetape facilitates further disbonding.

Polyethylene tape coatings are also prone to disbondment because of tenting, which occurs be-tween the pipe surface and the coating along the ridge created by the longitudinal weld reinforce-ment.28 A second area of potential disbondment is the overlap between successive wraps of tape.

When polyethylene tapes disbond, they allow moisture to penetrate under the coating. The highelectrical insulating property and high cohesive strength of the polyethylene tape prevent thecathodic protection current – applied through the soil – from reaching the pipe surface beneath thedisbonded polyethylene tape. Consequently, the environment beneath the disbonded polyethylene tapesustains corrosion and stress-corrosion cracking in spite of the fact that the pipeline is externallyprotected by CP.

Polyethylene tape coating is a significant factor in the occurrence of near-neutral pH SCC expe-rienced in Canada in early 1990s; nearly 75% of failures caused by near-neutral pH SCC have occurredon polyethylene tape coated pipe (see section 10.3.2 for more details). Single-wrapped polyethylenetape coated pipe had five times as many SCC colonies per meter as asphalt/coal tar coated pipe.Double-wrapped polyethylene tape-coated pipe had nine times as many colonies per meter as asphalt/coal tar coated pipe. Near-neutral pH SCC typically occurs on the exterior surface of a pipe coated withpolyethylene tape in the tenting region of the double submerged arc weld and adjacent to it. Cracks

FIGURE 9.2 Tenting of Polyethylene Coating on Pipelines Leading to Stress-Corrosion Cracking.28

Reproduced with permission from Wiley.

9.2 Coatings 545

also form in the body of the pipe in areas where the coating has been damaged, or where a disbondmenthas formed along the spiral tape overlap (see Fig. 9.2).

Polyethylene tape also sustains bacterial growth. The organisms grow at the overlap between thepolyethylene tape wrap, with the organic adhesive providing nutrients. A study found that a poly-ethylene coated pipeline submerged in a lake had large colonies of shell and organic matter on thesurface.29

Polyethylene tape coatings in clay soil are also susceptible to wrinkles. The wrinkles form becausethe tangential force applied by the clay soil is greater than the tape adhesion and the polyethylene yieldstrength. This force causes damage to the coating, especially at the 3 and 9 o’clock positions. In somecases, the wrinkles formed on the outer layer penetrate to the inner layer of the coating. A study foundthat after about 10 years of service on a 41 cm (16 in.) diameter pipeline 111 km (69 mi.) long pipeline,the polyethylene tape in the sandy and rocky soils was in excellent condition, but in clay soil it hadwrinkled.

iv. State-of-the-artThe occurrence of near-neutral pH SCC in major North American gas transmission pipelines wrappedwith disbonded polyethylene tape coating resulted in the industry stopping using tape coatings onlarger diameter pipelines.30 A survey conducted in 1988 indicated that only 7% of the pipeline


companies use polyethylene tape as their primary coating for large diameter pipelines (> 41 cm (16in.)). Another survey indicated that at least five major gas transmission companies have discontinuedor significantly restricted the use of polyethylene tape coatings even as repair coatings. The problemscited by these companies include: shielding of cathodic protection current, disbondment at welds anddents, damage due to rock impingement, high sensitivity to application techniques, soil stress problemsand high susceptibility to SCC. As a result of these issues, polyethylene tape is currently not theprimary coating of choice for new underground pipelines.

9.2.1d Extruded polyolefinsExtruded plastic coatings have been available to the oil and gas industry since 1956.

Thermoplastic coatings are applied on to pipelines by an extrusion process (Figure 9.3).31,32 Highdensity polyethylene – commonly known as extruded polyethylene – is the most frequently usedpolymer. This coating is yellow in color and hence it can be known commercially as ’yellow jacket’.Polypropylene extruded coatings may also be used. Extruded polyethylene and polypropylene coatingsare collectively known as extruded polyolefin coatings. The operating temperature range for anextruded polyethylene coating is �40 to 82�C (�40 to 180�F) and for extruded polypropylene coatingit is �21 to 88�C (�5 to 190�F).

i. TypesThe extruded polyolefin coatings may be broadly classified into four types depending on the extrusionprocess and the type of adhesive used:33

The adhesive used in Type A is rubber modified asphalt. Type A coating is crosshead-extruded ontothe pipeline. The Canadian Standards Association (CSA) standard CSA Z245.21 classifies the Type Aas System A1. Type A coating is extensively used in North America and Australia. It is only applied tosmaller diameter pipelines, i.e., up to 61 cm (24 in.).

The adhesive used in Type B is butyl rubber. It is either side-extruded and spirally wrapped orspirally extruded around the pipeline. CSA Z245.21 classifies the Type B as System A2. Thepeel-adhesion requirement of Type A2 is 19.6 N/25 mm whereas that of Type A1 is 3.0 N/25 mm.Type B can be applied on pipelines of diameters between 6.35 and 262 cm (2.5 and 103 in.).Both Type A and B coatings can be used up to temperatures between 60 and 66�C (140and 150�F).34

FIGURE 9.3 An Extrusion Process.31,32

9.2 Coatings 547

The adhesive used in Type C and D is ethylene copolymer or terpolymer. Type C coating iscrosshead-extruded and Type D is helically extruded onto the pipeline. Types C and D are extensivelyused in Europe and the Middle East. An ethylene copolymer or terpolymer adhesive is used in theseextruded polyethylene coatings.35

It should be noted that there is another process called fusion bonding which is used to applypolyethylene. This process of application is entirely different from the extrusion process.Commonly, low density polyethylene may be fusion bonded to the pipeline. Such fusion bondedlow density polyethylene (FBPE) has been used since 1983 in Australia.36 During this type ofapplication, the pipe surface is first grit blasted and preheated. The pipe is then clamped into thedipping beam, which is then lifted by overhead crane into the fluidized polyethylene bed. The pipe isslowly dropped into the polyethylene bath. The polyethylene bath consists of homopolymers orcopolymers of ethylene, other olefinic materials, antioxidants, and carbon block. The lower edge ofthe heated pipe makes contact with the polyethylene, which fuses directly onto the pipe surface. Thepipe is continuously rotated by the dipping beam at a constant circumferential speed. The first powderparticles to touch the steel pipe surface are oxidized. This oxidation produces polar groups at the endsof the long chain polyethylene molecules which causes the adhesion of the coating to the steel pipe.As more powder is melted onto the steel pipe, the desired thickness is achieved. The coatingthickness typically varies between 1.8 mm and 3 mm (0.07 and 0.12 in.), depending on diameter ofthe pipe. After coating, the pipe is removed from the polyethylene bath and it is heat-treated. Thispost-heat treatment ensures that the coating has properly been fused, and its surface porosity reduced.Post-heat treatment also provides characteristic smooth black finish. The coated pipe is then air-cooled.

ii. Laboratory performanceThe performance requirements of extruded polyethylene and fusion-bonded polyethylene aredescribed in the following standards:

• NACE RP0185, ‘Extruded Polyolefin Resin Coating Systems for Underground or SubmergedPipe’

• CSA Z245.21, ‘External Polyethylene Coating for Pipe’• DIN 30670, ‘Polyethylene Coatings for Steel Pipes and Fittings – Requirements and Testing’• ANSI/AWWA C215, ‘Extruded Polyolefin Coatings for the Exterior of Steel Water Pipelines’• ISO 21809-Part 1: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,

and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 1: Polyolefin Coatings (3-Layer PE and 3-Layer PP)

• Australian Standard AS 2518, ‘Fusion Bonded Low Density Polyethylene Coating for Pipesand Fittings’

iii. Field performanceExtruded polyethylene coatings have been the workhorse of the oil and gas industry for protecting theexternal surfaces of small diameter pipelines. They have excellent resistance to soil stress and mostother forms of degradation. They are extensively used on pipelines in Arctic regions in Canada, USA,and Russia because of their high impact resistance at low temperatures. The impact resistance ofextruded polyethylene coatings increases with decreasing temperature, reaching a maximum atapproximately �30�C (�20�F) and then decreases. The impact resistance at �60�C (�75�F) and at

Table 9.12 Mechanical Properties of the Extruded Polyethylene29

Duration inService,Years

ImpactResistance(Lbf.in)

Elongation(%)

TensileStrength(Lbf/in2)

Thickness(mils)

Hardness(Shore D)

Beforeinstallation

46 638� 40 4422�298 50 46�3

2 44 353�133 2460�611 45 55�4

8 36 103�68 1990�213 43 57�2


þ10�C (50�F) are comparable. Changes to the mechanical properties of extruded polyethylenecoatings occur over a wide range of temperature, with no sharp temperature at which the coatingsbecome brittle.37

Studies conducted on more than 8,000 km (w5,000 miles) of offshore pipelines in Italy andVenezuela indicated excellent performance of extruded polyethylene coatings for more than 25 years.Table 9.12 compares the mechanical properties of coatings over eight years of field service.29 Themechanical properties do diminish progressively over the years, but the extruded polyethylene coat-ings adequately protect the pipeline, and most failures have been due to improper quality controlduring transportation, application, and construction. These include the use of improperly sized woodsupport for the pipeline during transportation, use of an improper die-head size (e.g., use of a 76 cm (30in.) diameter die-head for extruding a 66 cm (26 in.) diameter pipe), and inadequate protection againstUV exposure of the coating before installation.

iv. State-of-the-artExtruded polyethylene coatings continue to be extensively used, especially on pipelines of diameter upto 61 cm (24 in.).

9.2.1e EpoxyThe term ‘epoxy’ refers to a chemical group which is a three-membered ring containing two carbonatoms and an oxygen atom. The simplest epoxy material is ethylene oxide (Figure 9.4). An epoxy resinis a polymer that contains two or more epoxy groups.38

There are three prominent types of epoxy resins:

• Digylcidyl Ether of Bisphenol-A Resin (DGEBA): Bisphenol-A and epichlorohydrin react toform this resin (Figure 9.5). For this reason this resin is frequently referred to as bisphenol-Aepichlorohydrin. This resin is widely used to produce protective coatings.

C

O

C

FIGURE 9.4 Epoxy Group.

HO OH CH2

CH2 CH-CH2-

- - -

C

CH3

CH2

CH3

O

CH2CH CI

O

+

CH3

CH3

Bisphenol - A

O

CH CH2-

O

Epichlorohydrin

DGEBA

C

O - -

FIGURE 9.5 The Reaction Between Bisphenol-A and Epichlorohydrin to Produce DGEBA Resin.

9.2 Coatings 549

• Novolac epoxy resin: Phenol and formaldehyde react to form this resin (Figure 9.6). Novolacresin has better chemical resistance than DGEBA to organic acids, and exhibits very lowshrinkage but has low adhesion depending on formulation.

• Cycloaliphatic epoxy resin: Cyclic oleins and peracetic acid react to form this resin (Figure 9.7).It is frequently used to manufacture solvent-less liquid epoxy and solvent containing liquid epoxycoatings.

The epoxy resin itself is not a suitable material for coating, but it polymerizes in the presence of curingagents to produce a protective coating.39 The process of polymerization is also known as curing, and

OH

PhenolOH

OH

CH2OH

H2O+

OH

CH2OH

CH2O

Formaldehyde

+

+

OH

and/or

OH

HOCH2

Novolac Resin

OH

CH2

OH

CH2

OH OH

CH2

OH

CH2OH

Phenol oroligomers

heat

heatacid

FIGURE 9.6 The Reaction Between Phenol and Formaldehyde to Produce Novolac Resin.

FIGURE 9.7 Cycloaliphatic Epoxy Resin.


the chemical that initiates the curing is called the curing agent. Epoxy resins polymerize bytwo main methods: homopolymerization and copolymerization. During homopolymerization, theepoxy resin molecules react directly with each other in the presence of a catalyst such as tertiaryamine, whereas during copolymerization, the epoxy resin molecules react with each other and alsowith the curing agent, so that the curing agent actually becomes a part of the resultant coating.

Amines (aliphatic, aromatic, and polyamide), phenolic resins, vegetable oil fatty acids, Lewisacids, and acid anhydrides are usually used as curing agents, with the type chosen determining theproperties of the epoxy coating. Table 9.13 presents a general trend of how the curing agent influencesthe properties of the resultant coating. In addition to the resin and the curing agent, the epoxy coatingcontains other chemicals known as fillers. These are added to modify the flow of coating, to dilute it, toimprove its barrier properties, or to adjust its flexibility. The epoxy coating will also contain pigments,which provide characteristic color to the coating.

i. TypesThe epoxy coatings can be broadly classified into: FBE, solvent-less liquid epoxy, and solvent-containing liquid epoxy. Table 9.14 presents application characteristics of the different epoxy coatings.Fusion bonded epoxy. FBE requires heat to cure and to adhere onto the metal substrate. The rawmaterials (Table 9.15) including curing agents are mixed at low temperatures and ground to powdersand are sprayed onto a heated substrate. The epoxy cures in the presence of heat to produce a smoothcoating of the steel surface. Table 9.16 presents typical surface preparation and coating processesduring application of FBE. Table 9.17 presents characteristics of FBE coatings.40

Solvent-containing liquid epoxy. Solvent-containing liquid epoxy is primarily used as weld-joint and/or repair coating (see section 9.2.2d for more details).

Table 9.13 Influence of Curing Agents on the Properties of Epoxy Coatings

Property

Curing Agent

Aliphatic Amine Aromatic Amine BF3 Anhydride

Strength Excellent Excellent Good Good

Electrical Properties Good Excellent Good Excellent

Heat Resistance Good Excellent Good Good

Dimensional Stability Good Very good Very good Excellent

Cure Room temperature High temperature High temperature High temperature

Table 9.14 Application Characteristics of Epoxy Coatings

Nature

Fusion BondEpoxy (FBE)Powder

Solvent-LessLiquid Epoxy

SolventContainingLiquid Epoxy

Type Thermoset Thermoset Thermoset

Raw material state Solid Liquid Liquid

Solids content (Volume %) 100 100 71

Number of components One Two Two

Pot life Not applicable 5 minutes at 80�C 1 hour at 20�CFlammability No No Yes

Shelf life 6 months at 5e25�C 12 months at 5e35�C 12 months at 5e35�CApplication equipment Electrostatic powder

sprayTwin component hotairless spray

Cold airless orpneumatic spray

Capital expenditure Moderate Moderate Less expensive

Compatibility

Side extrusion Good Excellent Excellent

Cross head extrusion Excellent Fair Fair

Powder sprayed adhesive Excellent Fair Fair

Recycling of oversprayedmaterial

Yes No No

Effective amount ofdeposited material (allowingfor recycling and solventevaporation losses), %

95 50e80 35e55

Application temperature, �C 180e 245 25e190 25e190

Cure temperature, �C 180e230 150e190 150e190

FBE application afterapplication of adhesive

5e30 sec 30 sec.e2 h 30 sec.e6 h

Pipe coating speed, meter/min

2e15 0e10 0e10

Delay before qualitycontrol, h

1 24 24

Table 9.15 Typical Compositions of FBE Coatings

Component Function Composition (%)

Bisphenol-A Epoxy 65e70

Dicyandiamide Curing Agent 1e3

2,4,6-Tris (Dimethylaminomethyl) Phenol Catalyst 0.1e1

Calcium Silicate Filler 25e30

Titanium Dioxide Pigment 2e4

Chrome Oxide Pigment 0.1e1

Diopside CaMg(SiO3)2 Filler 0.2e2

Calcium Carbonate Filler 0.1e1

Prehnite [2CaO.Al2O3.3SiO2] Filler 1e3

9.2 Coatings 551

Table 9.16 Typical Surface Preparation and Coating Process during Application of FBE Coating

Material/Process Conditions

Steel Hot Rolled

Surface roughness Shot or grit blasted

Cleaning Phosphoric acid (H3PO4) wash and water wash

Surface oxidation, preheat before coatingapplication

At 220 to 245�C (450�F) in air for 2 minutes maximum

Storage of epoxy resin Humidity controlled (very low humidity) room at 15�CCoating method, electrostatic spray Fluidized bed using air with �40�C dew point

Post cure 3 minutes at 204�C (400�F)

Table 9.17 Advantages and Disadvantages of FBE Coatings41

Properties Advantages Disadvantages

Cost Reduced cathodic protection (CP) cost Relatively high material cost

High capital cost for applicationequipment

Application Mill application provides a good qualitycontrol

Requires near white (SSPC-SP-10)

Good control of material usage Sensitive to contamination

Sensitive to surface condition (e.g.,slivers)

Corrosionprotection

Compatible with cathodic protection Subject to small scale damageresulting in small holidays

Does not creep or flow in service Field repair techniques are eithercumbersome or low quality

Low CP current requirement with lowincrease in demand over time

Field joints are not as high quality asmain coatings

High adhesion prevents major handlingdamage


Solvent-less liquid epoxy. Certain epoxy resins may be sprayed onto the pipeline without any solventat room temperature. Such resins are normally viscous and take longer to cure. Solvent-less liquidepoxy coating has not yet matured enough to have been applied extensively on infrastructure, but areused in the field as rehabilitation coatings.

ii. Laboratory performanceThe performance requirements of epoxy coatings are described in the following standards:

• CSA Z245–20, ‘External Fusion Bond Epoxy Coating for Steel Pipe’• ANSI/AWWA C213, ‘Fusion bonded Epoxy Coating for the Interior and Exterior of Steel Water

Pipelines’

9.2 Coatings 553

• AWWA Standard, ‘Liquid Epoxy Coating Systems for the Interior and Exterior of Steel WaterPipelines’, ANSI-AWWA C210

• ISO 21809-Part 2: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 2: Fusion Bonded Epoxy Coatings

• NACE RP0394, ‘Application, Performance, and Quality Control of Plant-Applied, FusionBonded Epoxy External Pipe Coating’

• NACE T-6B-B Report, ‘Amine Cured Epoxy Resin Coatings for Resistance to AtmosphericCorrosion’, Materials Performance 9(5) (1970), p.37

• NACE T-6H-7 Report, ‘Epoxy Ester Coatings for Atmospheric Service’, Materials Performance24 (1) (1985), p.54

• NACE T-6H-28 Report, ‘Epoxy-Polyamide Coatings for Resistance to Atmospheric Corrosion’,Materials Performance 21 (7) (1982), p.51

iii. Field performanceIn one study, 40 excavations were made to examine FBE coated pipe, fittings, and welds. The resultsconsolidated in Table 9.18 indicate considerable variations in the performance of FBE with respect toadhesion and cathodic disbondment. The pH beneath the disbonded coating in all field examinationswas between 7 and 14, indicating that the cathodic protection current had penetrated the coating toprotect the steel below.41,42

In another study, FBE coating was evaluated after five years of operation.29 Although good per-formance was noticed in most areas, in some locations the coating came off easily from the surface. Adetailed failure analysis indicated that almost all failures were due to poor surface preparation (mostlydue to chloride contamination), and due to damage of the coating during the transportation and

Table 9.18 Field Performance of FBE Coatings),40

Property ConditionNo Phosphoric AcidPretreatment, %

With PhosphoricAcid Pretreatment, %

Adhesion Excellent 10 38

Good 48 62

Poor 32 0

Extremely Poor 10 0

Cathodic Disbondment(Accidental holidays)

0 21 38

1e5 5 8

6e10 16 31

11e20 25 8

20 32 15

Underfilm Corrosion Slight 58 54

None 42 46

)Based on results obtained from 40 test sites. Approximately five areas were tested per site. Percentages refer to the numberof areas tested that exhibited the properties indicated

Table 9.19 Performance of FBE on a Pipeline Transporting Hot Crude

Property Pipeline 1 Pipeline 2 Pipeline 3

Temperature at the inspection zone (�C) 85 108 94

Color change Dark green) Dark green Black

Thickness (mils) 17.8 � 1.8 14.8 � 1.2 15.9 � 1.4

Hardness, H > 4 2 3

Impact resistance (lbf.in) 40 20 20

Corrosion detected Yes No Yes

Failure, if any Localized No Localized


installation. Table 9.19 presents the properties of an FBE coating on an oil transmitting pipeline afterone year of operation at 85�C (185�F). The impact resistance of the coating decreased drastically. Inaddition, the color of the coating changed from light green to dark green, sometimes to black. Thelocalized failure observed in pipelines 1 and 3 was attributed to mechanical damage. It is important tomention that these pipelines operated without CP.

In another field, the performance of FBE on a hot pipeline under cathodic protection wasevaluated and was found to be satisfactory. For this pipeline, about 1 A of current was enough toprotect the 100 km (62 mi.) of 25 cm (10 in.) pipeline. This low value of current demand indicatesthat the coating damage is about 0.1 to 0.2%. A similar value of cathodic protection current wasestimated for another 20 km (12.4 mi.) length of 30 cm (12 in.) gas pipeline. For the latter, thecathodic protection current demand after three years indicated average coating damage between0.4 and 1%.43 Good performance of FBE coatings have also been experienced in onshore gaspipelines operating at 95�C (203�F), and in offshore oil pipelines operating at 100 to 110�C (212 to230�F). In both fields, a few incidences of coating disbondment caused by mechanical damage wereobserved.

Several field inspections have indicated the formation of blisters on FBE coatings. In most in-stances, the blisters originated at some form of defect (coating holiday (see section 11.2 for definitionof holiday)) and the pH beneath the blister was above 7 indicating that the cathodic protection currentpassed through the blistered coating.

iv. State-of-the-artCurrently, FBE is the primary coating of choice for new pipeline in many parts of the world, either asthe single coating or as a base coat for multilayer coating.44 Surface preparation of the pipe prior toapplication of FBE is the factor which has the greatest effect in determining the performance of thecoating. FBE coating is now almost exclusively applied in the mill, where surface preparation isextremely well-controlled.

9.2.1f MultilayerFrom the late 1980s, multilayer coatings have been increasingly used in Europe and Japan. Theunderlying principle behind these coatings is to combine the chemical resistance and interfacialproperties of epoxies and the mechanical strength of polyethylene.45–52 Multilayer coatings are notjust distinct layers of different coatings, but synergic interaction between various layers. It is

Table 9.20 Comparison of Properties of FBE, Extruded Polyethylene, and Multilayer Coatings

Properties FBE Extruded Polyethylene Multilayer

Flexibility Excellent Excellent Excellent

Adhesion Excellent Limited Excellent

Cathodic disbondment Excellent Limited Excellent

Impact resistance Limited Excellent Excellent

Moisture penetration Limited Excellent Excellent

Abrasion Excellent Excellent Excellent

Soil stress Excellent Excellent Excellent

Burn back Excellent Excellent Excellent

Weathering Excellent Excellent Excellent

Application Excellent Excellent Excellent

9.2 Coatings 555

therefore important that strong chemical bonds form between the different coating layers. Table 9.20presents the advantages of multilayer coatings in comparison to FBE and extruded polyethylenecoatings.

i. TypesVarious coatings may be combined to produce multilayer coatings, but three layer and compositecoatings predominate. For some special conditions, a four layer coating is used.

Three layer coating. A three layer coating consists of an epoxy inner layer, an adhesive inter-mediate layer, and polyolefin outer layer (Figure 9.8).

Epoxy inner layer. The first layer of the multilayer coating is the epoxy inner layer, which is applieddirectly onto the steel. This epoxy primer layer: provides a thin continuous film that bonds directly andfirmly onto the steel surface. It provides effective bonds with intermediate layer; thus ensuring goodadhesion of all layers onto the steel; is resistant to chemical attack; and has good cathodic disbondmentresistance.

The epoxy primer layer may be FBE, solvent-less liquid epoxy, or solvent-containing liquidepoxy. In the early development of three layer coatings, liquid epoxy was used as the inner layer,but recently FBE is used more often. Before application of the inner layer, the steel surface is grit-or shot-blasted giving a surface profile of between 60 and 110 mm (2 and 4 mils). Therefore, thetypical minimum thickness of the epoxy inner layer is 150 mm (6 mils) to ensure that the metalsurface is completely covered. The epoxy inner layer is typically between 50 and 100 mm (2 and4 mils) thick.

Adhesive intermediate layer. The adhesive intermediate layer joins the polar epoxy inner layer andnon-polar polyolefin outer layer. The intermediate layer typically consists of species such as maleicanhydride grafted polyethylene or copolymers of maleic anhydride and polyethylene which can reactwith the epoxy inner layer, along with a co- or ter-polymer compatible with the polyolefin outer layer.To ensure that strong interfacial bonds form between the inner and intermediate layers, it is importantthat the intermediate layer is applied before complete polymerization (curing) of the epoxy inner layertakes place. The thickness of the intermediate layer is typically between 100 and 400 mm (3.9 and15.7 mils).

FIGURE 9.8 Typical Three Layer Constituents.


Polyolefin outer layer. The outer layer consists of an extruded polyolefin: polyethylene or poly-propylene. This layer is typically between 1.5 and 3 mm (59 and 118 mils) thick. The role of thisrelatively thick polyolefin outer layer is to provide mechanical protection for the structure and to act asmoisture barrier.

Polyethylene has excellent mechanical properties, but it softens at higher temperatures. Poly-propylene has higher resistance to softening at higher temperature, but does not bond well with steel.Therefore, the polyolefin outer layer for higher temperature application is typically manufactured frompolypropylene co-polymerized with small amounts of polyethylene.53–55 Anitoxidants may further beadded to increase its oxidation resistance at higher temperatures. The co-polymerization of poly-propylene with polyethylene also overcomes the brittleness of polypropylene at lower temperatures(approximately 0�C (32�F)), and the copolymer also has higher impact strength at low temperatures(as low as �30�C (�22�F)).Composite coating. A composite coating consists of a blend of both epoxy and polyolefin (poly-propylene or polyethylene) without the intermediate layer. To create a homogeneous blend, both thenon-polar polypropylene and polar epoxy are suitably modified. The blend is then applied by extrusionor spraying.Four layer coating. Three layer coatings used in special applications, such as in hot countries wherecoated pipes may be exposed for long periods to solar radiation, may have an additional white anti-solar acrylic coating 30–40 mm (1.2–1.6 mils) applied over the polyolefin outer layer. Such acoating thus consists of four layers.

9.2 Coatings 557

ii. Laboratory performanceThe performance requirements of multilayer coatings are described in the following standards:

• CSA Z245.21, ‘External Polyethylene Coating for Pipe’; Type B1 provides guidelines on 3-layercoating and Type B2 provides guidelines for composite coating

• NACE RPO185, ‘Extruded Polyolefin Resin Coating Systems for Underground or SubmergedPipe’

• ISO 21809, ‘External coatings for buried or submerged pipelines used in pipeline transportationsystems, Part 1: Polyolefin coatings (three layer PE and three layer PP)’

iii. Field performanceThree layer coatings are widely used in Europe, and years of good performance have been experi-enced. Composite coatings have been in use for over 20 years. They are mostly used in Canada whenthe service temperatures is above 65�C (150�F). They are applied on pipelines of diameter up to48"(1.2 meter) in diameter and of length over 500 km (310 mile) – however, examination of a sectionof composite coatings after exposure for 11 years underground indicated good performance.56

iv. State-of-the-artThree layer coatings are widely used in Europe, China, India, Middle East, and Japan. Compositecoatings are increasingly being used as external coatings for pipelines in frontier areas.57–59

9.2.2 Girth weld coatingsIn the early stages of the oil and gas industry, coatings were applied in the field. Currently, mainlinecoating is applied onto linepipe as it is produced. The linepipe sections, with their coating, are thenshipped to the field where they are welded together to produce pipeline. The coatings applied toprotect weld-joints are known as girth weld coatings or joint coatings. Girth weld coatings areapplied in the field where the conditions are not as good as in the mill where the mainline coatingsare applied. Their performance depends on the bonds to the substrate and to the mainline coating,the moisture seal at the joints, and water absorption. Theoretically any mainline coatings (discussedin section 9.2.1) could be used as a girth weld coating. If a different girth weld coating is used, then itmust be compatible with the mainline coating. Also, the process of applying the girth weld coatingshould not alter the properties of the mainline coating; mild processes are economical in the field; (forexample, heating to a temperature of 200�C (392�F) to apply FBE may not be an optimum process inthe field); and the process should not alter the strength of the girth welds (for example heating thepipeline to apply FBE may increase the strength of steel to a level that might make it unacceptable forcertain services).60

Figure 9.9 presents various types of girth coatings used over the years,61 and the following sectiondescribes them.62

9.2.2a Tape coatingSection 9.2.1c discusses the general characteristics of tape coatings and Table 9.21 provides specificcharacteristics of girth weld tape coatings.

1930 1940 1950 1960 1970 1980 1990 2000 2010year

Coal Tar and asphalt

Tape

Wax

Fusion Bonded Epoxy

Liquid Epoxy and urethane

Poly propylene

Shrink sleeve

FIGURE 9.9 Girth-Weld Coatings Applied on Oil and Gas Industry Over the Years.61

Table 9.21 Characteristics of Girth Weld Tape Coatings

Tape Application

Typical MaximumOperatingTemperature, �C

ISO 21809e3Type Remarks

Bituminous Hot applied 30 1A • Single layer or multi-layers• May be applied with or

without primer

Petrolatum Hot applied 30 1B • Single layer or multi-layers• With primer

Wax Hot applied 30 1C • Single layer or multi-layers• With primer

Polymeric Cold applied 50 to 80) 1D • Single layer or multi-layers• With primer

)Specific coatings for higher temperature may also be available


i. TypeIn general, any type of tape coating discussed in section 9.2.1c may be used as girth weld coating, butthe following four are frequently used: bituminous tape, petrolatum tape, wax tape, and polymeric(mostly olefin based) tape.

ii. Laboratory performanceThe performance characteristics of girth weld tape coatings are described in the following standards:

• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Type 1: Tape coating)

9.2 Coatings 559

• NACE RP 190, ‘External Protective Coatings for Joints, Fittings, and Valves on MetallicUnderground or Submerged Pipelines and Piping Systems’

• NACE Technical Committee Report 59–7, ‘Application Techniques, Properties and ChemicalResistance of Polyethylene Coatings’, Corrosion 15 (3) (1959), p.33 (117t)

• CSA Z245.22.10, Plant-Applied External Polyurethane Foam Insulation Coating for SteelPipe – Annex A: Polymer Tape coatings

iii. Field performanceAlthough formal studies on girth weld coatings are lacking, their field performance is similar to that ofmainline tape coating (see section 9.2.1c)

iv. State-of-the-artTape coatings are used as girth weld coatings because of the ease with which they can be applied in thefield. A survey conducted in 1988 indicated that tape coating was the first choice for about 30% of theresponders.

9.2.2b Heat shrinkable coatingHeat shrinkable coatings are thermoplastic coatings consisting of an adhesive and an extruded poly-olefin outer layer. Section 9.2.1d describes the characteristics of extruded polyolefins. The circum-ferential compression exerted by the shrinking polyolefin is the unique characteristic of this type ofcoating. This compression reinforces the bonding of the coating onto the steel surface. Heat shrinkablecoatings are available as tubular sleeves, wrap-around sleeves, and tapes. They may also be applied oncomplex structures.

i. TypeHeat shrinkable coatings may be broadly divided into two categories: those with primer andthose without primer. Table 9.22 provides some characteristics of different types of heat shrinkablecoatings.

Table 9.22 Characteristics of Heat Shrinkable Girth Weld Coatings

Tape Primer Adhesive


ISO 21809e3Type

Polyethylene No Mastic 50 2A-1

Polyethylene No High shear strengthmastic

90 2A-2

Polyethylene No High shear strengthhybrid or hot-melt

120 2A-3

Polyethylene Liquid epoxy or FBE N/A 120 2B

Polypropylene Liquid epoxy or FBE N/A 130 2C


ii. Laboratory performanceThe performance requirements for girth weld heat shrinkable coating are described in the followingstandard:

• 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, andNatural Gas Industries – External Coatings for Buried or Submerged Pipelines used in PipelineTransportation Systems, Part 3: Field Joint Coatings (Type 2: Heat Shrinkable Coatings)

iii. Field performanceOne study analyzed the compatibility of mainline and girth weld coatings, based on experience of morethan 100,000 field joints. In the network, FBE mainline coating had FBE joint coating; three layerpolyethylene mainline coating had heat-shrink sleeves, polyurethane, and polyethylene joint coatings;three layer polypropylene mainline coating had shrink sleeve, polypropylene, and polyurethane jointcoatings; and tape mainline coatings had tape joint coating. Based on experience, the company con-tinues to use shrink sleeve on three layer polyethylene and polypropylene mainline coatings.61

iv. State-of-the-artHeat shrinkable coatings are extensively used as girth weld coatings because of the ease with whichthey can be applied in the field.

9.2.2c Powder epoxyThe fusion bonded coating (FBE) described in section 9.2.1e may also be used as a girth weld coating;girth weld FBE coating is commonly known as powder epoxy. In their use, care is taken so that theapplication temperature does not change the properties of the steel (application of FBE requiresheating the steel substrate to higher temperatures, which may change the properties of the steel).Therefore, the application temperature is restricted to less than 275�C (527�F). The temperature limitis lower for higher strength steels (e.g., X70 and higher). The application process is also controlled sothat the FBE adheres well onto both the steel and the mill-applied coating.

i. TypeTwo types of powdered epoxy coating exist: single and double layer.

ii. Laboratory performanceIn general, the standards used to evaluate mainline FBE can be used to evaluate girth weld FBE.Specific tests used to evaluate FBE girth weld coatings are described in the following standards:

• ISO 21809 Part 3: Materials, Equipment, and Offshore Structures for Petroleum,Petrochemical, and Natural Gas Industries – External Coatings for Buried or SubmergedPipelines used in Pipeline Transportation Systems, Part 3: Field Joint Coatings (Type 3: FBEPowder Coatings)

• NACE RP0402, ‘Field-Applied Fusion Bonded Epoxy (FBE) Pipe Coating Systems for Girthweld Joints: Application, Performance, and Quality Control’, NACE, Houston, TX

iii. Field performanceThe field performance of girth weld FBE coatings is similar to mainline FBE coatings.

9.2 Coatings 561

iv. State-of-the-artFusion bonded epoxy powder coating is used as a girth weld coating with FBE mainline coating.

9.2.2d Liquid epoxyA solvent-containing epoxy coating (discussed in section 9.2.1e) may also be used as a girth weldcoating. They are also known as two-part epoxy coatings. The epoxy resin and curing agent areseparately dissolved in suitable solvents, and the two parts are mixed just before application.Increasingly, solvent-free two-part liquid epoxy field-girth weld coatings are used. The mixed liquid isthen either sprayed or brushed on the infrastructure.63 The epoxy resin undergoes its polymerizationreaction (curing) with or in the presence of curing agents to produce protective coatings. This reactionnormally takes place at ambient or at slightly elevated temperatures (typically up to 65�C (149�F)).Several precautions must be taken to avoid the hazards associated with solvents. Considerable effortsare being made to reduce and/or replace the organic materials in the solvents.64 Formulations have alsobeen developed with water as solvent; such coatings are known as water-borne epoxy coatings.However, water-borne epoxy coatings do not cure properly under moist conditions, or when thetemperature is below 15�C (59�F).

i. TypeThere are two types of liquid epoxy coatings:

• Traditional liquid epoxy girth weld coatings may be applied by brush, spray, roller, or trowel. ISO21809-Part 3 classifies this liquid epoxy coating type as liquid epoxy 4A.

• Liquid epoxy coatings are further reinforced with glass flakes, glass mats, or glass fibers. ISO21809-Part 3 classifies this liquid epoxy coating type as fiber reinforced Epoxy 4C.

ii. Laboratory performanceThe performance requirements of liquid epoxy are provided in the following standards:

• 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, andNatural Gas Industries – External Coatings for Buried or Submerged Pipelines used in PipelineTransportation Systems, Part 3: Field Joint Coatings (Type 4A: FBE Powder Coatings and Type4C: Fiber Reinforced Epoxy)

iii. Field performanceLiquid epoxy girth weld coatings are normally used with FBE mainline coatings. Experience withusing liquid epoxy girth weld coatings and other mainline coatings has been mixed. One pipeline inwhich liquid epoxy girth weld coating was used with a three layer mainline coating has not beensuccessful. The real reason for this incompatibility has not been properly established.

iv. State-of-the-artTheir ease of application make the liquid epoxy coatings popular – especially with FBE mainlinecoatings.

9.2.2e UrethanePolyurethanes have been primarily used as thermal barrier coatings, and to some extent also as anti-corrosion coatings. The polyurea coating is a variation of polyurethane coating and was introduced inthe 1990s.65–68


Urethane coatings are also known as isocyanate coatings, because isocyanate is one of the startingmaterials for making urethane. Isocyanate reacts with another chemical containing a hydrogen atomattached to either an oxygen, sulfur, or nitrogen atom. Equation 9.1 shows the typical chemicalreaction:

RNCOþ R’XH / RNðHÞCðXÞOR’ (9.1)

If X in Eqn. 9.1 is oxygen, (i.e., R’XH ¼ R’OH), the product formed is known as urethane(Eqn. 9.2).

RNCOþ HOH / RNðHÞCOOH’ (9.2)

In Eqn. 9.2, water reacts with isocyanate; i.e., R’ is H.Polyurethane coatings are generally formed by reacting polyisocyanate with polyols.

i. TypesPolyurethane coatings may be classified as brushed, sprayed, or cast urethanes, on the basis of the waythat they are applied.

ii. Laboratory performanceThe performance characteristics of polyurethane coatings are presented in the followingstandards:

• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Type 4B: Liquid Polyurethane andType 4E: Cast Polyurethane)

• NACE Task Group T-6H-30 Report, ‘Urethane Topcoats for Atmospheric Applications’,Materials Performance 23 (11) (1984), p.51

• NACE Task Group T-6B-16 Report, ‘Urethane Protective Coatings for Atmospheric Exposures’,Materials Performance 1 (9) (1962), p.95

• NACE Task Group T-6A-17 Report, ‘Urethane Protective Coatings’, Materials Performance 1 (6)(1962), p.105

iii. Field performanceThe field performance of polyurethane is similar to that of liquid epoxy coatings.

iv. State-of-the-artPolyurethane coatings are commonly used as girth weld coatings with FBE mainline coatings.Polyurethane coatings, in general, do not perform well above 60�C (140�F).

9.2.2f VinylesterThis coating consists of a vinylester, reinforced with glass flakes, glass fibers, or glass mat. Vinylestergirth weld coatings may be applied by brush, spray, roller, or trowel.

9.2 Coatings 563

i. TypeThere is only one type of vinylester used in pipeline application.

ii. Laboratory performanceThe performance characteristics of vinylester coatings are presented in the following standard:

• 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, andNatural Gas Industries – External Coatings for Buried or Submerged Pipelines used in PipelineTransportation Systems, Part 3: Field Joint Coatings (Type 4D: Reinforced Vinylester)

iii. Field performanceOnly limited information is available on the field performance of vinylester coatings.

iv. State-of-the-artVinylester coatings may sometimes be used as girth weld coatings, but their use is limited.

9.2.2g PolyolefinsThe polyolefin coatings discussed in section 9.2.1d can also be used as girth weld coatings. Polyolefingirth weld coatings have an inner epoxy primary layer and an outer polyolefin layer.

i. TypeDepending on the type of polyolefin and the manner in which the polyolefin layer is applied, polyolefinfield joint coatings may be classified into five different types: flame spray polypropylene, hot appliedpolypropylene tape or sheet, injection molded polypropylene, flame spray polyethylene, and hotapplied polyethylene tape or sheet. Table 9.23 provides general characteristics of these coatings.

ii. Laboratory performancePerformance characteristics of polyolefin girth weld coatings are described in the followingstandards:

• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Polyolefin based coatings)• Type 5A: flame spray polypropylene,• Type 5B: Hot applied polypropylene tape or sheet,• Type 5C: Injection molded polypropylene,• Type 5D: Flam spray polyethylene, and• Type 5E: Hot applied polyethylene tape or sheet).

iii. Field performanceThe field performance of polyolefin coatings is similar to heat shrinkable girth weld coatings, but thestudies of their field performance are limited.

iv. State-of-the-artPolyolefin girth weld coatings are used with polyolefin mainline coatings, but they are not used aswidely as heat shrinkable coatings.

Table 9.23 Characteristics of Polyolefin Girth Weld Coatings

Tape (Outer Layer)InnerLayer Intermediate Layer


ISO 21809e3Type

Flame spraypolypropylene

Epoxy Optional 110 5A

Hot appliedpolypropylene tapeor sheet

Epoxy Modified polypropylenepowder

110 5B

Injection moldedpolypropylene

Epoxy Modified polypropylenepowder

110 5C

Flame sprayedpolyethylene

Epoxy Modified polyethylenepowder

70 5D

Hot appliedpolyethylene tapor sheet

Epoxy Modified polyethylenepowder

80 5E


9.2.2h WaxA wax coating consists of a microcrystalline wax (inner layer), wrap (intermediate layer), and hotapplied wax (outer layer). They are normally used up to 50�C (122�F) and are flexible, semi-solid,adhere well onto material, do not brittle, and permeate through pores of the structure. They do notrequire a specific surface pattern in order to adhere so they can be applied onto poorly preparedsurfaces. These properties make them attractive as girth weld coatings.69,70

i. TypeThere is only one generic wax coating.

ii. Laboratory performanceThe performance characteristics of wax girth weld coatings are described in the following standards:

• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Type 7: Hot AppliedMicrocrystalline Wax Coatings)

• NACE RP0375, ‘Wax Coating Systems for Underground Piping Systems’

iii. Field performanceMicrocrystalline wax girth weld coatings have been used satisfactorily for a long time in the oil and gasindustry for certain applications.

iv. State-of-the-artWax coatings continue to be used as girth weld coatings in the oil and gas industry.

9.2 Coatings 565

9.2.2i ElastomericAn elastomeric coating consists of a primer, a bonding agent and an elastomer. The elastomer coatingmay either applied by in situ vulcanization or an adhesive method. In the former, the primer, bondingagent and unvulcanized rubber are first applied and are then bound together by applying polyamidetape. A portable autoclave is then used to cure the rubber. Once the rubber has cured the autoclave andpolyamide tape are removed. In the adhesive method, the cured rubber sleeve is applied and is securedby an adhesive that cures at ambient temperature.

i. TypeThese coatings used may be classified into two types, depending on the type of elastomer used:polychloroprene and ethylene propylene diene monomer (EPDM) based. Polychloroprene is a solidrubber and is normally used on structures operating at ambient temperatures. EPDM based coatingshave better temperature resistance than polychloroprene, so these are used on structures operating atelevated temperatures.

ii. Laboratory performancePerformance characteristics of elastomeric coatings are described in the following standards:

• 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical, andNatural Gas Industries – External Coatings for Buried or Submerged Pipelines used in PipelineTransportation Systems, Part 3: Field Joint Coatings (Type 8A: Polychloreprene and Type 8B:Ethylene Propylene Diene Monomer)

iii. Field performanceNo systematic field performance of elastomeric coatings is available.

iv. State-of-the-artElastomeric girth weld coatings are used only when the mainline coating is also an elastomericcoating.

9.2.2j Visco-elastic coatingsVisco-elastic coatings combine the properties of solid and liquid. They have good ratio betweenelasticity and viscosity. They are non-polar, hydrophobic, and highly adhesive coatings.

i. TypeThere are several types of visco-elastic coating.

ii. Laboratory performanceThe performance characteristics of visco-elastic coating are described in the following standard:

• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Type 8A and 8B)


iiTh

ivV

9Wtecginthwine

eitfeles

satueg

9IIth(Idh

in

i. Field performancehe field performance of visco-elastic coatings has not been systematically evaluated, but this coatingas been widely promoted as a coating having good and flexible adhesion.

. State-of-the artiscoelastic coatings are used on pipelines in hot-dessert regions.

.2.3 Repair coatingshen the primary coatings (mainline coating or girth weld coating) do not provide sufficient pro-ction, they must be repaired. The coatings used for this purpose are known as repair or rehabilitationoatings. There are several reasons for using repair coatings, such as in situations when the mainline orirth weld coatings are accidentally damaged (which normally happens during construction); whenspection indicates presence of breaks in or disbondment of the mainline or girth weld coatings; whene mainline or girth weld coatings are intentionally removed to inspect the steel surface beneath;hen operation requires tapping or welding new facility (e.g., additional pipe) into the existingfrastructure; or when the cathodic protection current demand increases to a point where it is notconomical to effectively apply it.One field study reported that a steel pipeline transporting oil was initially coated with an asphalt

namel coating. After about 40 years of service the CP current demand increased to such an extent thatwas not possible to apply sufficient current adequately. Therefore, the asphalt coating was removedrom about 600 m (1,975 feet) length of the pipeline, and the exposed surface coated with a 100% solidpoxy-urethane repair coating. Initially only 465 m (1,525 feet) of repair was planned, but the longerngth had to be recoated to achieve the CP application criteria (�1.00 volt pipe to soil potential – seeection 9.3.4).

In general, any girth weld coating can be used or is used as a repair coating. The repair coatinghould meet the environmental and safety regulations, be economical, be compatible with the fieldpplication (e.g., surface preparation) and operating conditions, be effective in protecting infrastruc-re from corrosion, and be compatible with any adjacent pre-existing coating. Table 9.24 presentsnvironmental and safety considerations in using field coatings.71 Table 9.25 and Table 9.26 presenteneral and performance characteristics of field coatings.

.2.4 Insulatorsnsulators are used to prevent the exchange of heat between the infrastructure and the environment.nsulators are primarily used in the offshore sector to minimize heat transfer between the pipeline ande ocean water. Insulating offshore pipelines prevents the formation of hydrates, wax, and asphaltenesthereby, enhances flow), and increases the duration of cooling period after the system is shut off.nsulation is also used in oilsands pipelines, which transport heavy oil (see section 2.9.3 for moreetails) operating at elevated temperatures (typically up to 150�C (302�F)), and in refineries to retainigher temperatures (typically above 100�C (212�F)).The materials used as insulators should have good thermal insulation properties. The thermal

sulation of a material is a measure of the transfer of heat, Q, across it, as given by (Eqn. 9.3):

Q ¼ UoADT (9.3)

Table 9.24 Environmental and Safety Considerations in Using Field Coatings71

Coating type Tape Heat shrinkable

Powdered

Epoxy Liquid Epoxy Urethane Urethane Elastomeric Polyolefin

Coating type Tape Heat shrinkable Powdered

epoxy

Liquid epoxy Urethane Urethane Elastomeric Polyolefin

Sub-type Several Mastic, hot melt,

with epoxy primer

FBE 100% solid

(polyamine

cured)

Coal-tar

(polyamide

cured)

Rigid (Aromatic

polyurethane)

Cast Coal tar or

polyurethane

Copolymer

Primer Yes/no No for mastic and

yes for all others

No Self or use others No No No No FBE

Solids

content, %

Depends

on primer

100 100 100 74 100 100 100 100

Mix ratio NA NA 1:1 2:1 4:1 1:1 1:1 4:5:1 NA

Volatile organic

content (VOC), lbs/

gallon

Present 0 0 0 1.9 0 0 0 0

Contains amines Yes Yes (in primer) No Yes No No No No Yes

Contains coal tar No No No Yes No No Yes (coal tar

based)

or No

(polyurethane

based)

No

Contains flammable

solvents

Yes No No No Yes No No No No

Application methods • Wrap • Torch or electrical

resistance

• Electrostatic

spray

• Fluidized bed

• Heat cured

• Brush

• Spray

• Brush

• Spray

• Spray • Cast in

mold

• Spray • Wrap

Shelf life, months 6 18 24 6 6 12 12

9.2

Coatin

gs

567

Table 9.25 General Application Characteristics of Some Field Coatings71

Coating TypePowderedEpoxy Liquid Epoxy Urethane Urethane Elastomeric

Sub-type FBE 100% solid(polyaminecured)

Coal tar(polyamidecured)

Rigid (Aromaticpolyurethane)

Cast Coal tar orpolyurethane

Optimal coatingthickness, mil

16 25 16 25 40 40 to 80

Surfacepreparation,SSPC standard(SSPC-SP)

10 10 10 10 10 10

Blast profile, mils 2.0 2.0 2 to 3 2.5 2.5 2 to 3

Ambienttemperature, �F

Not applicable Above 41 50 to 110 �40 to 150 �40 to 150 50 to 140

Substrate surfacetemperature, �F

425 to 488 Above 41 and5�F above dewpoint

50 to 110 and5�F above dewpoint.

�40 to 150 and5�F above dewpoint

�40 to 120 and5�F above dewpoint

50 to 140 and5�F above dewpoint

Materialstemperature, �F

Not applicable 120 to 150 50 to 90 32 to 150 32 to 80 120 to 140

Airless spraypump

Not applicable Plural Single Plural Not applicable Plural

Spray pressure,psi

Not applicable 2,200 2,100 to 2,500 1,800 to 2,500 Not applicable 4,260

Dry filmthickness, mils(per coat)

25 (max) 45 (max) 24 (max) Unlimited 40 to 100 Unlimited

Number of coatsrequired

1 1 1 to 2 1 1 1

After coating,time to lapsebefore thecoating is dry totouch, duration attemperature, �F

90 secs at 450�F 2 hours at 75�F 4 hours at 75�F 1 to 10 min 75�F 15 min at 75�F Less than 10 minat 75�F

568

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ation–Exte

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sion

After coating,time to lapsebefore thecoating is dry tohandle, hours attemperature, �F

Upon completionof coating

3 hours at 75�F 12 to 24 hours at75�F

5 to 60 min at75�F

45 min at 75�F 6 to 8 hours at75�F

After coating,time to lapsebefore holidaytesting, hours attemperature �F

Upon completionof coating


5 to 60 min at75�F


After coating,time to lapsebefore backfilling,hours attemperature, �F

After holidaydetection

3 hours at 75�F 24 to 48 at 75�F 30 to 180 min at75�F


Ultimate curingtime, hours attemperature, �F

Not applicable 7 days at 75�F 7 days at 75�F 7 days at 75�F 5 days at 75�F 7 days at 75�F

After coating,time to lapsebefore recoating(i.e., applicationof subsequentlayer) can beperformed

No recoatingallowed

Within 3 hours at75�F

6 hours(minimum) and24 hoursmaximum at75�F

0.5 to 1.5 hoursat 75�F

30 mins at 75�F 2 to 6 hours at75�F

Material forrepairing thecoating

Patchcomponent orliquid epoxy

Brash grade orpatchcomponent

Brush grade Self or brushgrade

Self or brushgrade

Self or brushgrade

9.2

Coatin

gs

569

Table 9.26 General Performance Characteristics of Some Field Coatings71

Coating TypePowderedEpoxy Liquid Epoxy Urethane Urethane Elastomeric

Sub-type FBE 100% solid(polyamine cured)

Coal tar(polyamidecured)

Rigid (Aromaticpolyurethane)

Cast Coal tar orpolyurethane

Average coatingthickness, mils

18 27 20 30 40 53

Adhesion to steel(ASTM D4541);mils

1,650 1,850 750 2,000 1,750 1,000

Abrasionresistance (ASTMD4060, C517, 1kg, 1000 cycles);mg loss

120 135 160 80 (30 for ceramiccontainingcoating)

52 40

Flexibility (ASTMD522); at 180� 1’mondrel

Failed Failed Failed Pass Pass Pass

Elongation (ASTMD638);Percentage

4.8 2.8 3.2 4.8 4.5 59

Cathodicdisbondment(CSA Z245.20;-3.5 V 48 hours);mm radius

8.0 6.0 17.5 4.0 3.0 10

Dielectric strength(ASTM G149); kV

29.7 (18 mils with1,150 V/mil)

7.1 (27 mils with263 V/mil)




31 (53 mils with585 V/mil)

Hardness (ASTMD2240); Shore D

85 82 65 72 75 68

570

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sion

Impact resistance(ASTM G14); in-lbs

160 29 28 50 120 76

Penetrationresistance (ASTMG17); Percentage

Nil Nil 13 5 3.1 6.6

Stability (wet)(ASTM D870); �F

�100 to 230 �30 to 120 �30 to 120 �40 to 150 �40 to 195 �30 to 120

Water absorption(ASTM D570);Percentage

0.83 2.0 1.2 1.4 1.0 2.0

Water vaporpermeability(ASTM D1653); g/m2/24 hours

7.5 3.8 12 12 10 37

Volume resistivity(ASTM D257);1014 ohm.cm

13 8.6 3.5 58 60 2.6

Salt spray (ASTMB117); 2,000hours

Pass Less than 3/80undercut

Less than 3/80undercut

Pass Pass Pass

Chemicalresistance (CSAZ245.20); 10%HCl, 10% NaOH,5% NaCl

Pass Pass Pass Pass Pass Pass

9.2

Coatin

gs

571

Table 9.27 Thermal Insulation Properties of Some Materials72

Insulation Material

Overall Heat Transfer Coefficient

BTU/hr-ft2-�F• BTU/hr-ft-�F)

• BTU-in/hr-ft2.�F)) W/m2-Kn (W/m-K))

Polyethylene) 0.20 0.35

Solid polypropylene 0.50 2.84

Polypropylene foam 0.28 1.59

Polypropylene) 0.13 0.22

Polypropylene (PP)-solid)) 0.04

Synthetic PP)) 0.02e0.04

Synthetic polyurethane 0.32 1.81

Synthetic polyurethane foam 0.30 1.70

Polyurethane 0.07 0.12

Polyurethane (PU)-solid)) 0.04

Glass synthetic polyurethane 0.03 0.17

Synthetic PU)) 0.02e0.03

Polystyrene 0.26

Mineral Wool)) 0.25

Fiberglass)) 0.24

Composite 0.12 0.68

Synthetic epoxy)) 0.02

Synthetic Phenolic)) 0.01

Pipe-in-pipe synthetic polyurethane foam 0.17 0.96

Pipe-in-pipe 0.05 0.28


where Q is the heat transfer rate; Uo is the overall heat transfer coefficient; A is the surface area ofthe material; and DT is the difference in temperature between two sides of the insulating material.Table 9.27 presents the overall heat transfer coefficients of some materials.72

9.2.4a TypesPolyurethanes are widely used as insulating materials.73–77 Polyurethane foams are formed by theencapsulation of gases during the polymerization reaction (Eqn. 9.1). These gases may be produced bythe intentional addition of gas-producing substances (for example hydrocarbons or fluorocarbons), orthey may be produced as a byproduct of the polymerization reaction (for example CO2 gas is formedwhen the reaction in Eqn.9.2 proceeds further (Eqn. 9.4)).

½RNðHÞCOOH� / RNH2 þ CO2 (9.4)

The amine produced in this reaction (Eqn. 9.4) may further react with an isocyanate to produce apolymer with a urea-type linkage (Eqn. 9.5):

RNH2 þ RNCO / RNH� CO� NHR (9.5)

Table 9.28 Properties of Polyurethane Foams72

Foam Property

Nominal Density kg/m3 ASTM Test Method

160 224 320 500 D1622

Compressive strengthat 20�C, MPa

2.035 4.563 8.144 22.998 D1621, perpendicular

1.999 3.819 9.144 21.217 D1621, parallel

Compressive strengthat �196�C, MPa

3.300 7.485 15.829 48.394 D1621, perpendicular

3.494 7.540 17.107 47.408 D1621, parallel

Thermal conductivityat 20�C, W/mK

0.0292 0.0345 0.0407 0.0425 C518

Thermal conductivityat �160�C, W/mK

0.0253 0.0316 0.0346 0.0390 C177

Closed cell content % 95 95 95 96 D2856

Leachable halides, ppm < 20 < 20 < 20 < 20 D871

Flammability, /10 S.E 10 10 10 10 D1692

Tensile strengthat 22�C, MPa

2.412 3.517 6.649 12.582 D1623

Tensile strengthat �196�C, MPa

3.204 4.854 8.305 15.055 D1623

Tensile modulus, MPa 11.8 19.4 24.0 29.5 D1624

Water absorption, %Vol 0.17 0.15 0.12 0.10 D2842

9.2 Coatings 573

The reactions presented in Eqns. 9.1, 9.2, 9.4, and 9.5 are adjusted to produce polyurethane foams ofdesired properties. Table 9.28 presents some typical properties of polyurethane foams. Typically, theyhave low thermal conductivity (i.e., the overall heat transfer coefficient is low) so they are used asthermal insulators. To protect the polyurethane from mechanical damage, an additional extrudedpolyethylene layer is applied.

In some designs, an external metallic pipe physically protects the carrier internal pipe. This designis commonly known as pipe-in-pipe (PIP) or dry insulation, because the outer pipe prevents wateringress into the insulator. In PIP designs, the pipes are metallic and the annulus between them may befilled with insulation materials (foam, granular, gel, and inert gas), or it may be left as vacuum.Alternatively, several pipes are bundled together with insulating material. In a way, such bundledpipelines are a special configuration of PIP. PIP insulation is commonly used in offshore production totransmit fluids from high-pressure and high temperature (above 150�C (302�F)) reservoirs.

9.2.4b Laboratory performanceThe performance requirements of polyurethane thermal insulators are described in the followingstandards:

• CSA Z245.22, ‘Plant-Applied External Polyurethane Foam Insulation Coating for Steel Pipe’• ASTM G189, ‘Standard Guide for Laboratory Simulation of Corrosion Under Insulation’• ISO/TC 67/SC 2/WG 19, Petroleum and Natural Gas Industries – Wet Thermal Insulation

Coatings for Pipelines, Flow Lines, Equipment, and Subsea Structures


• NACE SP 0198, ‘Control of Corrosion under Thermal Insulation and Fireproofing – A SystemsApproach’

• NACE Task Group T-6A-17 Report ‘Urethane Protective Coatings’, Materials Performance 1 (6)(1962), p.105

• NACE Task Group T-6H-30 Report ‘Urethane Topcoats for Atmospheric Applications’, MaterialsPerformance 23 (11) (1984), p.51

• NACE Task Group T-6B-16 Report ‘Urethane Protective Coatings for Atmospheric Exposures’,Materials Performance 1 (9) (1962), p.95

9.2.4c Field performanceA pipeline was designed for transporting dry bitumen from a production facility to a transmissionpipeline. This 35 km (22 mi) long pipeline was designed for 30 years of service at an operatingtemperature between 120�C (248�F) and 130�C (266�F). A three layer system was selected to controlcorrosion and to thermally insulate this pipeline. It consists of an FBE anti-corrosion coating (350 mm(14 mil)), polyurethane foam insulation (50 mm (1.97 in.)) and extruded polyethylene (2.5 mm (100mil)) or (3.8 mm (150 mil)). This pipeline has been operating for more than 10 years without any majorissues.

Depending on the formulation, polyurethane foams absorb and retain water. In one study, it wasfound that most water was retained superficially on the surface in one formulation, whereas water hadpenetrated the foam in another formulation.73 In another study, it was found that the polyurethanefoams have low water absorption properties, but they absorb sufficient water to become electricallyconductive and allow the passage of cathodic protection current.74

9.2.4d State-of-the-artA three layer system, consisting of an internal anti-corrosion layer, an intermediate insulation layer,and an external polyethylene layer, is widely used to prevent or reduce heat loss from systemsoperating at higher temperatures (e.g., refinery pipes and oilsands pipelines) or in systems exposed tocolder environments (e.g., offshore pipelines).

9.2.5 Metallic (thermal spray) coatingsMetallic (Thermal spray) coatings are used in submerged marine structures, especially offshorepipelines. Thermal spray coatings protect steel, either by acting as a barrier coating or as a sacrificialanode. Zinc (Zn) provides better galvanic protection and aluminum (Al) provides better barrier pro-tection; hence Zn-Al alloys combine the protective properties of both Zn and Al. Among variouscombinations, 85% Zn–15% Al alloy is widely used. The history of the development of thermal spraymetallic coatings can be summarized as follows:

• In 1742, a French chemist, Malouin, described a method for protecting steel by immersion inmolten zinc (hot-dip galvanization).

• In 1837, a British patent for flexing steel with ammonium chloride prior to galvanizing wasgranted.

• During World War 1, the flame spraying of plastic coatings was commercialised.78

9.2 Coatings 575

• In the 1940s, a ten year study of various coatings concluded that:79

• Metallized zinc had outperformed all other coatings studied;• Metallized zinc provided secondary (galvanic) protection when the organic top-coating

deteriorated or damaged;• Zinc metallization was not economical if the length of the service period was less than 4–5

years; and• The minimum thickness of metallized zinc required was about 4–5 mm.

• Until the 1950s, thermal sprayed aluminum (TSA) was not widely used due to the formation ofrust stains. The development of sealants in the 1950s solved this issue.

• In 1950, the AmericanWelding Society (AWS) Committee on Thermal Spraying (then known as theCommittee on Metallizing) began an extensive study of the corrosion protection of thermallysprayed zinc and aluminum coatings on low carbon steel. More than 4,000 panels were tested over a20 year period in eight test sites across the United States. Panels were exposed to seawater at tideand below tide levels at two different locations, and in the remaining six locations the panels wereexposed to a range of atmospheric conditions, including industrial, salt air, and salt sprayenvironments. The conclusions obtained from this study can be summarized as follows:• Aluminum coatings 75–150 mm (0.003–0.006 in.) both sealed and unsealed provided

protection of carbon steel over the 20 year period in seawater as well as in severe marine andindustrial environments.

• Over the same time period, unsealed zinc coatings required 12 mil (0.3 mm) of thickness inseawater and 9 mil (�0.2 mm) in marine and industrial atmospheres, whereas 3 to 6 mil (0.07to 0.15 mm) of sealed zinc was sufficient to provide same extent of protection.

• The application of one coat-of-wash primer and one or two coats of aluminum vinyl enhancedthe appearance and extended the life of aluminum and zinc coatings.

• Overall, aluminum coatings performed better than all the other coatings tested, and they had alower tendency to develop pits and blisters.

• In the 1960s, the oxidation of thermal spray coating during application (spraying) was a majorproblem, but the development of high speed spray pumps overcame this problem.

• In 1984, the tethers, risers, and flare boom of a tension leg platform (TLP) installed in water 480feet (146 m) deep in Hutton, North Sea was protected by TSA. The TSA coating was a 99.5%Al flame-sprayed coating with a 1,000 psi (6.9 MPa) adhesion. The coating was sealed with twocoats of vinyl sealer on the tethers and a silicone sealer on the risers. Based on the success ofthis project, operators started specifying TSA as corrosion protection for several North Sea andGulf of Mexico projects.

• Between 1987 and 1988, TSAwas used for splash zone protection in nine platforms installed inthe North Sea. The 8 mil (0.2 mm) thick TSA was further protected with 2 mil (0.05 mm) ofpolyurethane sealer.

• In 1989, TSAwas used to protect the risers on the Joillet platform installed in the Gulf of Mexico.• The largest offshore application of TSA in the 1990s was on the Heidrum TLP, which had a 50

year design life.• Metallized coatings have now been used to provide protection in many industries, especially

offshore and marine structures. Currently there are three thermal spraying processes: combustion,electric arc, and plasma.


9.2.5a TypeThermal spray coatings are normally either Zn, Al, or 85% Zn–15% Al.

Zinc is electronegative in the galvanic series and hence thermally sprayed zinc coating is used asa sacrificial coating; i.e., it provides galvanic protection. On the other hand, thermally sprayedaluminum is a barrier coating. The Al2O3 layer on its surface is tight, adherent, and has good me-chanical strength. A zinc and aluminum alloy coating combines the advantages of both sacrificial zincand protective aluminum. Zinc and aluminum are not miscible in the solid state, but are in the liquidstate.

Due to its lower atomic weight, a smaller weight-percentage of aluminum produces a larger volumefraction of the aluminum phase. For example, a mixture of 28% by weight of aluminum and 72% byweight of zinc produces an alloy which is 50% aluminum and 50% zinc by volume. The properties ofZn-Al alloy coatings depend on the size, distribution and volume fraction of the zinc and aluminumphases:

• At above 95% by weight of zinc, the coatings behave much like pure zinc.• Coatings containing 5–22% by weight of aluminum (with 78–95% by weight of zinc) combine

the best properties of both materials.• The optimum performance is found at 85% by weight of zinc and 15% by weight of aluminum. At

this weight ratio, the metallized coating contains 30% of volume of aluminum and 70% byvolume of zinc. Its microstructure consists of a continuous network of elongated aluminumparticles separated by pores filled with a finely divided zinc-rich phase. The improved corrosionresistance, relative to either pure zinc or aluminum, is due to the combination of both theformation of aluminum oxide (self-healing corrosion product) and the presence of zinc-rich phase(sacrificial cathodic protection). This composition is widely used to produce thermal spraycoatings.

• Thermal spray coatings with a composition that is 55% aluminum and 45% of zinc by volume arealso used. This alloy mostly consists of an alpha-aluminum phase with an inter-dendritic zinc-richphase.

TSA coatings of thickness less than 200 mil (5 mm) are porous in nature and are susceptible to wateringress and corrosion. Increasing the thickness (typically to 350 mil (9 mm)) plugs the pores, butthicker coatings have poor adhesion due to differential thermal expansion of substrate andcoating. Therefore, typically TSA layers of about 200 to 300 mil (5 to 7.5 mm) mm of thickness areused. To plug the pores, sealants and paints are thermally sprayed on immediately after the TSA.Polyvinyl chloride, polyphenolic resins, polyester resins, polyurethanes, and polyamide epoxies arecommonly used as sealants. Thermally sprayed zinc coatings are also sealed and painted to extendtheir life.

9.2.5b Laboratory performanceStandards providing guidelines for evaluating thermally sprayed coatings include:

• AWS C2.2, ‘Recommended Practice for Metallizing with Aluminum and Zinc for Protection ofIron and Steel’

• AWS C2.25/C2.25M, ‘Specification for Thermal Spray Feedstock Solid and Composite Wire andCeramic Rods’

• CSA G189. ‘Sprayed Metal Coatings for Atmospheric Corrosion Protection’

9.2 Coatings 577

• NACE 12/AWS C2.23M/SSPC-CS 23.00. ‘Specification for the Application of Thermal SprayCoatings (Metalizing) of Aluminum, Zinc, and their Alloys and Composites for the CorrosionProtection of Steel’

• BS 5493, ‘Code of practice for protective coating of iron and steel structures against corrosion’• SSPC CS 23.00. ‘Specification for the application of thermal spray coatings (metalizing) of

aluminum, zinc and their alloys and composites for the corrosion protection of steel’• ISO 21809-Part 3: Materials, Equipment, and Offshore Structures for Petroleum, Petrochemical,

and Natural Gas Industries – External Coatings for Buried or Submerged Pipelines used inPipeline Transportation Systems, Part 3: Field Joint Coatings (Type 6: Thermal SprayAluminum). This standard addresses TSA used as girth weld coatings

9.2.5c Field performanceSeveral investigators have evaluated the performance of thermal spray coating in variousenvironments. Results from some long-term field experiments and experience are summarized in thissection.

The US Navy exposed two TSA coatings in Port Hueneme Harbor, California and the study foundthat 3 mil (0.1 mm) unsealed TSA coating performed well, even after 18 years of exposure. The LaQueCenter exposed several samples of TSA coatings on steel panels in Kure Beach, North Carolina. Thecoatings were of different compositions, and of thicknesses between 3 mil (0.08 mm) and 6 mil (0.15mm). After 34 years of exposure, the TSA coatings performed extremely well in the marine atmo-sphere, with individual performance of Al-Zn and Al-Mg coatings depending on the applicationprocedure, especially the gun size. The 100% Al coating was least affected by the nature of itsapplication.

Another study conducted in marine atmospheres using TSA of various compositions (with Alcontent between 45 and 70%) determined the time for the first rust to form was 15 years on panelsexposed in a severe marine atmosphere, i.e., 80 feet (25 meters) from the ocean, and 25 years onpanels exposed in a moderate marine atmosphere, i.e., 820 feet (250 meters) from the ocean. The USArmy exposed various metallic coatings with and without polymeric top layers over a period of 20years at Buzzard’s Bay, Massachusetts and at La Costa Island, Florida. Based on this study, the USNavy approved the use of TSA coatings for naval ships with the following recommendations: aminimum adhesion strength of 13.8 MPa (2,000 psi), a minimum coating thickness of between 10 miland 15 mil (w0.25 and 0.38 mm), and two coats of a heat-resistant Al sealer for high temperatureservice (780�C (1436�F)).

Studies in Norway found that visible damage had occurred in TSA coatings of 6 mil (0.16 mm)thickness after 15 years, and concluded that a 8 mil (0.2 mm) thick TSA coating would be required for60 years service. Studies in Russia and Germany also came to similar conclusions.

Several inspections of the Hutton platform have been carried out. The potentials of the tether inyear one ranged between �980 and �1,000mV (Ag/AgCl), and between �880 and �910 mV(Ag/AgCl) in year eight, indicating continued protection by TSA. One tendon and a production riserwere removed for inspection after three years of service. The tendon exhibited blistering while the riserdid not. Despite the blisters, the TSA coating was in excellent condition with no measurable reductionin coating thickness or evidence of corrosion damage to the substrate. Visual inspection by videocameras of the splash zone after three years of service revealed no deterioration in coating quality orperformance, or any corrosion damage. High-pressure water jetting (4,000 psi (27.6 MPa)) was used to


remove fouling, in order to enable better inspection. This strong mechanical impact did not cause anycoating deterioration. After eight years of service, the riser strings were visually surveyed and pho-tographed. No corrosion was detected in the splash zone.

One riser string was retrieved due to a work-over of a well after eight years. Coating thicknesssurveys, around the circumference and along the length of the riser joint measured at or above specifiedthickness (8 mil (0.2 mm)), indicated no degradation since installation. Adhesion strength wasdetermined by a pull-off method. The adhesion strength between the dolly and the TSA coating was500 psi (3.5MPa), but the TSA coating adhesion to the steel was better than this value. The typicaladhesion strength of the coating during manufacture was of the order of 1,500 to 2,000 psi (10 to 14MPa). Coating adhesion was also tested using the scribe test, which indicated that it was excellent onthis riser. In a few cases, flaking did occur. The steel substrate was examined after the coating wasremoved by chemical means. The substrate was in pristine condition with the original blast profile stillintact. This indicated that the underlying steel was never exposed to the corrosive environment.

9.2.5d State-of-the-artThermal spray coatings are used with polymeric top-coatings in offshore oil and gas infrastructure toprovide external corrosion control. They are popular in such applications due to the difficulty inrepairing the infrastructure, and the difficulty of applying traditional external CP. Preliminary studieshave also confirmed that the metallic coatings/polymeric coating/cathodic protection combination maybe used as three layer protection system (Table 9.29 through 9.31).59

9.2.6 Concrete coatingsConcrete coatings are primarily used in offshore pipelines as weight coatings for buoyancy protection.They are also used in onshore pipelines for backfill protection at river crossings, in rocky locations, and

Table 9.29 Comparison of Cathodic Disbondment of Polymeric Coatings with and without Thermal

Sprayed (48% Zn-52% Al) Metallic Underlayer Coating59

Area of Disbondment (%)

Coating Constant Temperature Fluctuating Temperature

Potential, V L0.78 L0.93 L0.78 L0.78 L0.93 L0.78

Break Yes Yes No Yes Yes No

Composite 0.00 17.00 n/a 0.00 0.00 0.00

Me/Composite 0.00 9.00 1.50 5.00 9.00 8.00

FBE 2.25 75.00 n/a 60.00 40.00 71.00

Me/FBE 8.76 5.63 33.75 14.69 10.94 24.69

Coal tar 60.00 100.00 n/a 50.00 37.50 78.75

Me/Coal tar 52.50 40.00 67.50 39.81 14.38 53.75

Urethane 80.00 70.00 n/a 0.00 0.00 0.00

Me/Urethane 8.13 10.63 68.75 9.69 3.13 75.63

Me ¼ 48% Zn-52%Al as underlayer

Table 9.30 Comparison of Cathodic Protection Current Demand in the Presence and Absence of 48%

Zn-52%Al Underlayer Coating59

Cathodic Current Demand, mA




Composite 3.66 11.48 0.01 3.24 4.19 n/a

Me/Composite 0.04 0.10 �3.33 �0.84 �0.84 �1.95

FBE 30.83 13.17 4.37 102.52 165.24 n/a

Me/FBE �0.40 21.16 0.90 1.43 0.96 �3.60

CTE 13.62 41.74 n/a 1.77 6.17 0.64

Me/CTE �5.40 �0.50 �0.40 �3.30 �2.30 0.20

Urethane (Spray) 38.80 16.48 �0.83 179.00 206.50 n/a

Me/Urethane (Spray) �4.09 7.98 �1.28 �1.03 15.12 0.35

Me ¼ 48% Zn-52%Al as underlayer

Table 9.31 Comparison of Cathodic Disbondment in the Presence of Various Metallic Under-Layers

with Urethane Top-Layer Coating59

Area of Disbondment (%)




No metallic underlayer 80.00 70.00 N/A 0.00 0.00 0.00

Zn 90.00 90.00 3.75 90.00 3.75 90.00

85%Zne15%Al 83.75 16.25 16.25 80.00 5.00 5.00

48%Zne52%Al 8.13 10.63 68.75 9.69 3.13 75.63

Al 1.25 3.13 40.00 13.75 5.00 76.25

9.2 Coatings 579

in locations where pipelines are prone to soil movement. Typically the concrete weight coating isapplied over an anti-corrosion polymeric coating, and the system is further backed up by cathodicprotection.

Concrete coatings are not used to a great extent in onshore pipelines; however, combinations ofsteel, polymeric coatings, and concrete are extensively used in structures such as bridges and buildingsin conjunction with cathodic protection. The performance of the concrete coating depends on severalfactors, including the reliability of the concrete and polymeric coatings; the compatibility between thetwo (for example proper aggregate size of the concrete coating should be selected so that it does not


damage the polymeric coating); and compatibility between the coatings and CP (when polymericcoating fails the CP current should reach the metal surface, thus protecting it from corrosion).

The reliability of the concrete coating depends on two factors: the durability of the concrete itself,and the permeation of water and other species (e.g., chloride ions) through it to reach the polymericcoating. Figure 9.10 describes factors which affect the durability of concrete. These include thetemperature cycle, alkali-aggregate reaction, presence of sulfates, flow, and carbonation.80

In cold northern regions, concrete deteriorates more rapidly due to cyclic freezing and thawing,which are not encountered in warmer regions. The silica and carbonates from concrete react chemi-cally with alkalis (e.g., sodium hydroxide and potassium hydroxide) to form alkali gel. The gel hashigher affinity towards water, and consequently its volume increases. The increased volume cracks theconcrete. The alkali-silica reaction is more common than alkali-carbonate. The calcium hydroxides(hydrated lime), calcium aluminate, and calcium silicate present in concrete chemically react withsulfates (e.g., sodium sulfate, calcium sulfate, and magnesium sulfate) to form calcium sulfates andcalcium sulfoaluminates. The products of these reactions expand the volume and consequentlydeteriorate the concrete. Flow causes erosion of concrete by bringing abrasive materials, e.g., sand,

FIGURE 9.10 Factors Affecting the Durability of Concrete.80


9.2 Coatings 581

gravel, and ice. In marine environments, the effect of flow is significant in the tidal zone due to theerosion caused by high and low tides (Figure 9.10). When CO2 permeates into the concrete it reactswith calcium hydroxide to produce calcium carbonate. Carbon dioxide may also react with silica,alumina, and ferric oxide present in concrete to produce the respective carbonates. This process isknown as carbonation, and it reduces the pH of concrete from 13 to as low as 8.

Some approaches undertaken to increase the durability of concrete include controlling the water/cement ratio, controlling the composition, use of sealers, and use of corrosion inhibitors. Reduction ofthe water content of concrete decreases its permeability. Certain regulations require the water-to-cement ratio in concrete to be equal or less than 0.4.81 The composition of concrete may beadjusted by using nonreactive aggregate, low alkali cement, limiting the alkali content of the concretemixture, and using supplementary cementing materials (e.g., fly ash and silica fume). Sealers areapplied or sprayed on top of concrete to prevent or reduce entry of extraneous materials into it. Somecommonly used sealers include silane, siloxane, and linseed oil. Corrosion inhibitors (e.g., calciumnitrite) are added to control the penetration of chloride into the coating, and to protect the steel sur-face.82 Epoxy coatings may be used to control the corrosion of steel inside concrete.

9.2.6a TypeConcrete weight coatings are typically composed of ASTM C150 Type II Portland cement with amaximum tricalcium aluminate (C3A) content of 8%. The reason for specifying this low C3A contentis to minimize sulfate attack on the concrete weight coating.

However, ASTM Type I or EN 197 Type CEM I Portland cements having a C3A content greaterthan 8% may also be used. In addition, they may be composed of supplementary materials, such as flyash, ground granulated blast-furnace slag, and silica fume.83

9.2.6b Laboratory performanceThe performance requirements of polymeric coating, concrete coating, and CP are provided in thefollowing paragraphs:

• ISO 21809, External coatings for buried or submerged pipelines used in pipeline transportationsystems, Part 5: External concrete coating

• ASTM A775: Standard Specification for Epoxy-Coated Steel Reinforcing Bars. (Thisstandard provides criteria to protect rebar steel inside concrete, and may also be useful forevaluating polymeric coatings between pipes, and concrete coatings used in the oil and gasindustry)

• NACE Standard RP0290: Standard Recommended Practice: Impressed Current CathodicProtection of Reinforcing Steel in Atmospherically Exposed Concrete Structures

9.2.6c Field performanceField experience with concrete coatings in the oil and gas industry is limited, but the infrastructureindustry (building and bridges) has long experience in controlling the corrosion of rebar steel in concretestructures, by using polymeric coating and cathodic protection. The sequence of materials in both casesis the same; i.e., steel/polymeric coating/concrete/cathodic protection. Before using knowledgetransferred from other industries, one important aspect should be noted. The use of polymeric (anti-corrosion) coating has been controversial in the infrastructure industry, with some recommending its useand others recommending against using it; i.e., the use of polymeric coating is an option in the


infrastructure industry. In contrast, the use of polymeric coating is almost mandatory in the oil and gasindustry. Some experiences of the infrastructure industry are described in the following paragraphs.

Eighty one bridges in Iowa were surveyed after being in service for 20 years.84 The survey foundthat the loss of adhesion of epoxy coatings on concrete was higher in locations where concrete hadcracked than in locations where it had not cracked. Moisture and higher chloride concentrations at thecracked locations decreased the bond between the epoxy coating and the steel. However, the surveyfound little corrosion in the cracked locations.

Another survey on a bridge in Virginia found that the epoxy coating disbonded from concretewithin four years and the rebar beneath it had corroded. The corrosion products so formed distressedthe concrete. Yet another survey conducted in 1990s indicated that the substructures of several bridgesin Florida experienced severe corrosion.84 The steel rebars of the structures were protected by epoxycoatings. These were defective and had disbonded from the concrete, mainly due to poor coatingquality, poor concrete quality, and poor construction practices during construction. Another surveyconducted on a bridge in Georgia found a loss of adhesion of epoxy coatings from concrete and fromsteel, but no steel corrosion beneath the disbonded coating. Many failures were attributed to improperquality control during construction, especially the pouring of concrete on top of the polymeric coating.This survey recommended improvements to this procedure, and quality control measures to be takenduring constructing infrastructure. Yet another survey on a bridge in North Carolina found rebarcorrosion in locations where the epoxy coating had defects (breaks and pin holes).

The following conclusions may be drawn from the experience from infrastructure industry, withrespect to using concrete coatings in the oil and gas industry. The products of steel corrosion maydistress concrete coatings. When the concrete coating is properly formulated and applied on polymericcoating, no disbonding of the polymeric coating from either steel or concrete occurs. A properlyapplied epoxy coating can protect the steel from corrosive environments containing chloride ions at upto 0.08 weight percentage. Loss of adhesion of coating adhesion may not necessarily lead to corrosion,as long as the CP current reaches the steel surface through the concrete and polymeric coatings.

9.2.6d State-of-the-artConcrete coatings are used as weight coatings in offshore oil and gas pipelines to overcome buoyancyand to onshore pipelines to reduce pipe movement. Concrete coatings that are fully bonded on topipeline are also used as mechanical protection in rough terrain.

9.3 Cathodic protectionThe primary objective of the various coatings discussed in section 9.2 is to prevent the environment orelectrolyte that causes corrosion from contacting the metal surface. In order for a coating to meet thisobjective, it should: remain bonded onto the surface; electrically isolate the external surface of theinfrastructure from the environment; have sufficient adhesion to effectively resist under film migrationof moisture; be sufficiently ductile to resist cracking; have sufficient strength or otherwise be protectedto resist damage due to handling, storage (e.g., UV radiation), and installation during construction;resist deterioration due to the environment (e.g., soil stress, chemicals, and microbial species) and tothe temperature variation during operation (i.e., it should not break or disbond); and maintain constantelectrical resistivity over time.

Table 9.32 Typical Range of Current Required to Effectively

Apply Cathodic Protection

Coating Resistance,Ohms/Square foot

Cathodic Protection Current,Amperes)

Perfect coating)) 0.000058

5,000,000 0.0298

1,000,000 0.1491

500,000 0.2982

100,000 1.491

50,000 2.982

25,000 5.964

10,000 14.91

No coating 500

)To apply 1 mA/ft2 of current to protect a 36-in. diameter pipeline of 10 miles inlength in a soil with average resistivity of 1 x 103 ohm-cm))A break-free coating with resistivity of 1 x 1013 ohm-cm

9.3 Cathodic protection 583

No coating is available which can meet all of the above performance criteria for the entire durationof its life. In practice, coatings undergo different forms of deterioration (see section 10.2.1) at differentrates (sections 10.2.3 and 10.2.4). If the locations where coating has failed become anodic (see section5.2 for the concept of ASME), corrosion occurs. To prevent this, cathodic protection (CP) is applied.CP controls the corrosion of a metal by converting its surface into a cathode. This is achieved bymoving the potential of the metal surface in the negative direction by using an external current source.

Both coating and CP work together; i.e., one cannot be effective without the other in controllingexternal corrosion of underground oil and gas infrastructures. Using only the coating without CPincreases the probability that localized corrosion will occur in those locations where the coating fails.Using only CP without a coating increases the amount of current required to move the potential ofmetal surface in the negative direction. Table 9.32 illustrates how coating and CP can be effective andeconomical in protecting a metal from corrosion.85

9.3.1 PrincipleAs discussed in section 5.2, four elements (anode, cathode, metallic conductor, and electrolyticconductor) are required for corrosion to take place. Of these, the anode, cathode, and metallicconductor are present in the metal itself. Therefore when a metal comes in contact with an electrolyte,corrosion takes place. The basic principle of cathodic protection is to remove all anodic areas of themetal or structure of interest so that it does not corrode.

At the anodic sites (ref. Eqn. 5.1), metal ions leave the metal surface and dissolve in theelectrolyte; i.e., at the anodic sites the current flows from the metal surface to the electrolyte. Thisprocess is corrosion. At the cathodic sites, the metal ions (ref. Eqn. 5.2) or some other ions (e.g.,hydrogen (Eqn. 5.3) or oxygen (Eqn. 5.4)) leave the electrolyte and return to the metal; i.e., at thecathodic sites the current flows from the electrolyte to metal. This process accompanies thecorrosion reaction.


Cathodic protection forces all surfaces of the metal of interest to become cathodic, and anothermetal becomes the anode; i.e., another metal is sacrificed. The metal that is sacrificed undergoescorrosion, hence this metal is often known as the sacrificial anode. Thus, application of cathodicprotection does not eliminate corrosion, but transfers it from the structure of importance to another lessimportant metal.

Figure 9.11 illustrates the principle of cathodic protection using a section of a pipeline as thestructure to be protected.86 Before implementing cathodic protection, both anodic and cathodic re-actions take place on the surface of the pipeline. By installing an anode (also known as ground bed) andconnecting it to the pipeline through a source of current, all anodic reactions are forced to take place onthe ground bed and all cathodic reactions are forced to take place on the pipeline.

The amount of current required to convert a large structure such as a pipeline is huge, hence a largeanodic surface is required. Such an approach is not economical. For this reason, most of the surface ofthe structure is covered with non-conducting coatings to decrease the area to be converted into acathode. The larger the area protected by the coating, the smaller the amount of current needed tosupply cathodic protection; consequently smaller the amount of anode needed. Figure 9.11 illustratesthis concept.

To apply CP in practice the following questions should be answered. What is the amount of currentrequired to properly protect a given area of the structure? What is the source of that current? Whatmaterials are required, and how will it be ensured that the entire structure is completely protected?

9.3.2 Amount of currentThe amount of current required to protect the entire surface of a structure is huge, that this is un-economical; as a result, the surface is protected with non-conducting (high-resistance) coatings. Thesecoatings however are not perfect and they do not cover 100% of the surface for its entire service life.

In general, it is assumed that the coatings cover about 95% of the surface when they are installed,and that this area progressively decreases during service life. The extent of this decrease depends onseveral factors, including the type of coating, environment, and service history. Section 10.2.4 providesa method for estimating the coating deterioration rate.

The next question is to determine the amount of current required to protect those areas of thestructure not protected by coatings. Recollect Figure 5.3 which explains how the system moves fromthe redox potentials of zinc and hydrogen towards the corrosion potential. Figure 9.12 presents thesame concept using iron as its example.87,88 When an iron electrode is coupled with an oxygenelectrode, the redox potential (Eequal) of iron moves to the corrosion potential, so that:

• the corrosion potential is more positive than the redox potential of iron• the corrosion potential is more negative than the redox potential of oxygen• the current at the redox potential of oxygen is IC• the current at the redox potential of iron is IA• the current at the corrosion potential is Icorr.

From this illustration, the amount of current (Ireq) ideally required to cathodically protect iron can becalculated:

Ireq ¼ IC � IA (9.5)

FIGURE 9.11 The Principle of Applying Cathodic Protection.86

(A) A freely corroding structure before applying cathodic protection. Note: both anodic and cathodic reactions

take place on its surface. (B) the structure after applying cathodic protection. note: only the cathodic

reaction takes place on its surface and the anodic reaction takes place on the surface of anode. (C) the

structure after applying coating and cathodic protection. note: the area of the pipeline where cathodic

reaction takes place has decreased.

Reproduced with permission from NACE International.


FIGURE 9.12 Determination of the Amount of Current Required to Apply Cathodic Protection.87



When current is forced onto the iron surface, its potential moves from Ecorr to a potential that is morenegative; i.e., it moves in the active direction. In other words, the amount of current (Ireq) required tocathodically protect a metal is the amount of current required to force a metal to move from itscorrosion potential to its redox potential. Normally, current density (ireq), rather than current is used;current density being the amount of current per unit area. Thus:

ireq ¼ iC � iA (9.6)

where ic, and ia are current densities at the redox potential of cathode (e.g., hydrogen), and at the redoxpotential of anode (e.g., iron) respectively. The total current (Ireq) required to cathodically protect thesurfaces of a structure which is not protected by coatings is then (Eqn. 9.7):

Ireq ¼ A:UA:ireq (9.7)

Table 9.33 Typical Current Requirements for Cathodic Protection of Bare Steel

Environment Current Requirement (mA/m2)

Neutral soil 5 to 16

Well aerate natural soil 22 to 32

High acid soil 32 to 160

Soil supporting sulfate reducing bacteria 65 to 450

Heated soil 32 to 270

Stationary fresh water 11 to 65

Moving oxygenated fresh water 54 to 160

Seawater 32 to 110

Cold and Arctic seawater 160 to 430


where Ireq is the total current required to cathodically protect the uncoated structure (in mA), A is thesurface area of the structure (in m2), UA is the percentage area not protected by coatings (%), and ireq isthe current required per unit area to cathodically protect the uncoated structure (in mA/m2).

In reality CP may not be applied to move the potential all the way to the redox potential of iron, butto a potential sufficiently negative (as indicated as Ecp). Consequently the current required is alsoreduced to Icp. In the absence of any other method for determining current requirements, the valuespresented in Table 9.33 may be used.

9.3.3 Current sourceThe current required to apply cathodic protection comes from several sources including sacrificialanodes, impressed current, batteries, engine generators, thermoelectric generators, thermo-generators,wind-powered generators, gas turbines, fuel cells, and solar cells. Of these, sacrificial anode andimpressed current are most popular and best established.

9.3.3a Sacrificial anodeSection 5.2 discusses galvanic series and electromotive force series. If a metal that is towards the active(i.e., negative) end of the series is connected with another metal which is towards the noble (i.e.,positive) end of the series, then the more active metal undergoes anodic oxidation (i.e., corrosion)preferentially, and the other electrode undergoes cathodic reduction. The activemetal sacrifices itself toprotect the othermetal. In order for a sacrificial anode to protect the structure, both should be electricallyconnected to one another and also be in contact with the same electrically conducting environment.Cathodic protection is applied using sacrificial anodes when the protective current required is less than 4to 5A and the resistivity of the electrolyte (or environment) is typically below 10,000 ohm-cm.

Magnesium, zinc, and aluminum are active metals and are frequently used as sacrificial anodes.Typically, zinc anodes are used when the soil resistivity is below 1,500 ohm-cm, magnesium anodesare used when the soil resistivity is between 1,500 to 10,000 ohm-cm, and aluminum anodes are usedfor offshore applications.

The properties used to characterize sacrificial anodes are: driving potential, current output, cathodicprotection circuit resistance, theoretical energy output, actual energy output, current efficiency, utili-zation factor, and anode life. Table 9.34 presents typical values for some of these properties.

Table 9.34 Characteristics of Materials Typically used as Sacrificial Anodes for Applying Cathodic Protection

Material

Specification ofMaterials Usedas Anodes

Drivingpotentiala,b

TheoreticalEnergyOutput(A-h/kg)

ActualEnergyOutput(A-h/kg)

CurrentEfficiency, %

Rate ofConsumption(kg/A-year)

CorrosionPotential,V vs CCS

Zinc, Type 1 ASTM B418,Type I

0.20 860 781 90 11 �1.06

Zinc, Type 2 ASTM B418,Type II

0.25 816 730 90 12 �1.10

Magnesium H-1alloy

0.60c 2,205 551 to1,279

25 to 58 6.8 to 16 �1.40 to�1.60

Magnesium highpotential

0.85c 2,205 992 to1,191

45 to 54 7.3 to 8.3 �1.70 to�1.80

Aluminum-Zinc-Mercuryalloy

0.20 2,977 2,822 95 3.1 �1.06

Aluminum-Zinc-Indiumalloy

0.25 2,977 2,591 87 3.3 �1.11

aTo polarize carbon steel to �0.85 V vs, CCSbWhen calculating the anode output the absolute values of potential are used (mathematically the values should be negative)cDue to anodic polarization anode output is not exactly as calculated by Eqn. 9.6

588

CHAPTER9

Mitig

ation–Exte

rnalCorro

sion


i. Driving potential (DVDP)This is the potential between the anode (VA) and the potential to which the cathodically protectedmetal is shifted (VCPS) (Eqn. 9.8):

DVDP ¼ VA � VCPS (9.8)

From Table 9.34 it is obvious that the driving force of magnesium anodes is higher than those of zincanodes.

ii. Current output (Iout.a)The current output of the anodic material depends on the driving potential and the resistance betweenthe anode and the structure to be protected (cathode) (Eqn. 9.9):

Iout:a ¼ DVDP

RT:1; 000 (9.9)

where Iout.aA is the current in milliamperes, DVDP is the driving potential, and RT is the resistancebetween anode and cathode, commonly known as the cathodic protection circuit resistance.

iii. Cathodic protection circuit resistance (RT)There is a resistance to current flow between the anode and the cathode. This resistance is known asthe cathodic protection circuit resistance, RT and it is the sum of several resistances, as defined inEqn. 9.10:

RT ¼ Ra þ Rc þ Rw (9.10)

where Ra is the resistance between the anode and environment (ground or seawater or electrolyte), Rc

is the resistance between the cathode and the environment, and Rw is the resistance of the metal wireconnecting the cathode and anode.

The resistance between the anode and the environment depends on the position of the anode(vertical or horizontal), and on whether single or multiple anodes are used (Eqn. 9.11).90,91

Ra ¼ Rv ¼ Rh ¼ RN (9.11)

where Rv is the resistance between a vertical anode and ground (Eqn. 9.12), Rh is the resistance be-tween a horizontal anode and ground (Eqn. 9.13), and RN is the resistance between group anodes andground (Eqn. 9.14).

For a single anode that is vertically placed in the ground, the resistance between it and the ground isgiven by Eqn. 9.12:

Rv ¼ rsoil

2pLA

�ln8LAdA

� 1

�(9.12)

where rsoil is the soil resistivity in ohm centimeters (U.com), LA is the length of anode in centimeters(cm), and dA is the diameter of the anode in centimeters.


For a single anode that is horizontally placed in the ground, the resistance between it and theground is given by Eqn. 9.13:

Rh ¼ rsoil

2pLA

0@ln

244L2A þ 4L

ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffið2hAÞ2 þ L2A

q2dAhA

þ 2hAdA

�ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffið2hAÞ2 þ L2A

qLA

� 1

351A (9.13)

where hA is the distance between the surface and the center of the anode, in centimeters.When more than one anode is used, the current outputs of individual anodes reduce due to mutual

interference resistance; this resistance decreases as the spacing between the anodes increases. For agroup of anodes that are vertically placed in the ground, the resistance between them and the ground isgiven by Eqn. 9.14:

RN ¼ rsoil

2pNALA

�ln8LAdA

� 1þ 2LASAC:CP

:ln 0:656NA

�(9.14)

where NA is the number of anodes and SAC.CP is the center to center spacing between anodes incentimeters.

To reduce the resistance between the anode and the environment, anodes are often placed inbackfill materials. Table 9.35 presents the chemical composition of a typical backfill material.92,93

These materials absorb and retain water, thereby reducing the resistance between the anode and theenvironment. In addition, backfill materials ensure uniform current distribution from the anode, andhence prolong its life.

Similarly to the resistance between anode and the earth, there is a resistance between cathode (i.e.,the structure to be protected) and the earth in the current path (Rc). In many instances this resistance issmall when compared to Ra and is therefore ignored.

In addition to the resistances (Ra and Rc) between electrodes (anode and cathode) and the earth, theresistance of the metallic connector (Rw) joining the anode and cathode is also important. Thisresistance depends on its length and diameter. Table 9.36 presents typical resistances (Rw) of coppercables that are often used to connect anodes and cathodes.

iv. Theoretical energy outputThe energy output is a measure of the electrochemical equivalent of the energy stored in a metal. It is ameasure of the current discharged per hour per unit mass of metal. One ampere-hour means that one

Table 9.35 Typical Backfill Material to Cover Sacrificial Zinc and Magnesium Anodes

Typically Used with

Composition of Backfill, %

Resistivity,ohm-cm

Hydrated Gypsum(CaSO4)

BentoniteClay

SodiumSulfate

Zinc 50 50 250

Magnesium in soil withhigh resistivity

75 20 5 50

Table 9.36 Typical Resistances Metallic Cables used in the Cathodic Protection System93

Size of Copper Wire AWG) Diameter (mil) Diameter (mm)Resistance at 20oC, ohm/meter

14 64 1.6 8.4650

12 80 2.1 5.3152

10 102 2.6 3.3466

8 129 3.3 2.0998

6 162 4.1 1.3222

4 204 5.2 0.8334

3 230 5.8 0.6595

2 258 6.5 0.5217

1 289 7.3 0.4134

1/0 325 8.3 0.3281

2/0 365 9.3 0.2608

3/0 410 10.4 0.2070

4/0 460 11.7 0.1641

)American Wire Gauge (AWG) is a standardized wire gauge predominantly used in USA and Canada for electricallyconducting wire


ampere of current flows for one hour and is equivalent to 0.5 ampere of current flowing for two hours,or to two ampere of current flowing for 30 minutes. The theoretical energy output of pure zinc is 372ampere-hours per pound. This means that one pound of zinc will discharge one ampere of currentcontinuously for 372 hours. If the amount of current discharged increases, the duration decreases, andvice versa. For example, one pound of zinc discharging 10 amperes of current will be consumed within37.2 hours. On the other hand, one pound of zinc discharging 0.1 ampere of current will last for3,720 hours.

v. Actual energy outputIn order for the anode material to be 100% efficient, all its surfaces should function as an anode, and allcathodic sites should reside on the structure being protected. This seldom occurs. A small portion ofthe anodic material itself undergoes reduction reaction, i.e., acts as cathode. Consequently the actualenergy output from an anode material is less than the theoretical energy output.

vi. Current efficiencyThe current efficiency is the ratio of the actual energy output that can be used for cathodic protection tothe theoretical energy output.

vii. Utilization factorThe utilization factor is a measure of the percentage of the anodic material which can be used forcathodic protection purposes. For example, a utilization factor of 90% means that once 90% of thematerial is consumed, it can no longer be used as anode. The resistance to earth of the remaining 10%of the material is so high that there is very little or no current output from it.


viii. Anode lifeThe life of anode is the length of time for which a material can be used as sacrificial anode (Eqn. 9.15):

tanode ¼Ith:a::ma:Ieff :a:UFa

tfuncIout:a(9.15)

where tanode is the anode life in years, Ith.a is the theoretical output in A-h/kg, ma is the anode mass inkilograms, Ieff.a is the current efficiency, UFa is the utilization factor, tfunc. is hours per year (8,766), andIout.a is the anode output in amperes.

9.3.3b Impressed current – power source94–96

The maximum driving potential (DVDP, Eqn. 9.8) from using a sacrificial anode is 1V. Further, thecurrent output of sacrificial anodes is typically up to 5 mA. For these reasons sacrificial anodes cannotbe used to apply CP on a large structure. When the current required to apply CP exceeds 5 mA, theimpressed current method is typically used. Table 9.37 compares CP using the sacrificial anode andimpressed current methods.97

Figure 9.13 presents a typical system used to apply cathodic protection by the impressed currentmethod. All the basic elements (anode, groundbed, and cathode, i.e., structure) used in the sacrificialanode method are also required to apply CP by the impressed current method. The main difference isthe source of electrical current. An external power source (commonly the electric utility system) isused for this. The positive terminal of the external power source is connected to the anode, and thenegative terminal to the structure to be protected (the cathode). Another device, known as a rectifier,regulates the current flow between the power source and the cathodic protection system. The rectifier

Table 9.37 Comparison of Cathodic Protection with Sacrificial Anode and with Impressed Current97

CharacteristicsSacrificial Anode CathodicProtection

Impressed Current CathodicProtection

Power source Anode External; but constant power isrequired.

Maintenance Relatively little Relatively high

Installation Relatively easy Relatively sophisticated;experienced and certified electricalpersonnel required.

Inspection Relatively less Relatively more

Record keeping Relatively less Relatively more

Adjustment of amount of current Not possible without resistorsin the circuit

Yes

Current output Limited (typically less than 5 mA) High

Cost of replacing spent anodes High Relatively low

Nature of coating Need good coating Can be used with poor coating orwithout coating

Electrical isolation of structure Needed Can be used without electricalisolation of structure

Cathodic interference Low Possible

FIGURE 9.13 Schematic Diagram to Apply Cathodic Protection by Impressed Current.89,98



does two things: it converts (rectifies) the alternating current from the power source into direct current,and it adjusts (normally lowers) the voltage of the direct current to a value that is appropriate forapplying CP.

The current from the external source is alternating current (AC). In an AC system the current flowchanges direction at regular intervals. For example, for a 60 cycle AC power source, the direction ofcurrent changes 120 times per second. Figure 9.14 presents a basic rectifier unit and shows how the ACcurrent flows through it. The current can enter the bridge from the transformer through connections 1or 2. When the current enters through:

• Connection (1) of the transformer it passes through leg (c) of the bridge. The current then passesthrough the external circuit (i.e., ground bed and structure being protected) before returning toconnection (2) through leg (b).

• Connection (2) of the transformer it passes through leg (d) of the bridge. The current then passesthrough the external circuit before returning to connection (1) through leg (a).

For 60 cycle AC current passing through a rectifier, the above two processes repeat 120 times everysecond. Irrespective of the direction of the AC current entering the rectifier, it flows out of the rectifierin only one direction; i.e., the current output of the rectifier is direct current (DC).

When a rectifier converts an AC to DC some power is lost. The extent of this loss determines itsefficiency (Eqn. 9.16):

Receff ¼ Vdc:IdcWac

:100 (9.16)

where Receff is the efficiency of the rectifier, Wac AC power in Watts, Vdc is the DC potential in voltsand Idc is the DC current in amperes. The power lost in the rectifier appears as heat; therefore rectifierunits are equipped with coolers.

FIGURE 9.14 Rectifier Unit for Impressed Current Cathodic Protection System.86,99

(A, B, and C are transformer units, D is a bridge to direct the flow of current, E is an ammeter, F is the voltmeter, G

is the ground bed, H is the structure to be protected, a, b, c, and d are the legs of bridge D, and 1 and 2 are

connectors).



Any metallic material can be used as an anode in the impressed current method, even one that iscathodic to the structure to be protected. The impressed current forces the anodic material to corrode orto undergo other anodic reactions (see Eqns. 9.17 and 9.18) irrespective of its natural tendency. For thisreason, the connections to the rectifier must be properly made. The positive terminal of the rectifiermust be connected to the anode and the negative terminal to the structure; otherwise the impressedcurrent will corrode the structure instead of protecting it.


Anodic materials corrode and hence should be replaced periodically. The rate at which theydisappear is known as the dissipation rate. The dissipation rate of a material decreases if it undergoesother oxidation (anodic) reaction, rather than the corrosion reaction. Such common reactions areoxygen evolution (Eqn. 9.17) and chloride evolution (Eqn. 9.18):

4OH� / O2 þ 2H2Oþ 4e� (9.17)

4CI� / CI2 þ 2H2Oþ 4e� (9.18)

Commonly used anode materials include cast iron (with 14.5% silicon and chromium), carbon,graphite, sintered iron oxide, lead-silver alloys, platinum, platinized titanium, and niobium. Theirdissipation rate is 0.5 kg/A-year.96 On the other hand, the dissipation rate of iron is 9.1 kg/A-year.Therefore, when scrap steel pipe, rail, rod, or other similar iron or steel materials are used as anodematerials, large volumes are required.

The amount of anode required to apply an impressed current is calculated as follows (Eqn. 9.19):97

ma ¼ Dt:Ireq:tlife (9.19)

where Dt is the dissipation rate in kg/A-year (normally assumed to be 1 kg/A-year in the design stage),Ireq is calculated using Eqn. 9.7 or using Table 9.33, and tlife is the anticipated life of the infrastructureto be protected, in years.

The rectifier voltage (Vrectifier) depends on required current and total resistance (Eqn. 9.20):

Vrectifier ¼ IreqRt

(9.20)

where Rt is the total resistance and is calculated using Eqn. 9.10. But calculation of Rw for impressedcurrent method involves three resistances (Eqn. 9.21):

Rw ¼ Rð�Þ þ RðþÞ þ Rgb (9.21)

where R(�) is the resistance of the cable connected to the negative terminal, R(þ) is the resistance ofcable connected to the positive terminal, and Rgb is the resistance of half the length of the anodeportion of the groundbed. Normally distributed anodes (see Figure 9.15) are used in the groundbed andcurrent flowing through the cable connecting the anodes drops at each anode encountered. Thereforethe effective resistance of the cable in the groundbed is normally taken as half the resistance of the totallength. Table 9.36 presents values of typical cables.

9.3.3c Impressed current – engine generatorAn engine generator may be used to produce electricity required for the impressed current cathodicprotection system when an AC power line is not available, or when a sacrificial anode system willnot produce a current adequate to apply cathodic protection. An engine generator can produce DCdirectly, but it is normally used to energize an AC generator (commonly known as alternator) andthen a rectifier is used to convert the AC to DC. This two-step process is more efficient and eco-nomic for the controlled production of a wide range of DC than producing it directly from an enginegenerator.

The cost of installing and operating this large block of engine generators is relatively high. Thenatural gas or oil required to operate the engine generator may be drawn directly from the oil and gaspipelines or may be transported to it periodically.

FIGURE 9.15 Schematic Diagram of Distributed Anodes.100



9.3.3d Impressed current – thermo-generatorIn remote locations, the DC for the cathodic protection system may be produced by a closed cyclevapor thermo-generator (CCVTG). Commercial thermo-generators which generate up to 5,000 Wand100 Vof power are available. The thermo-generator powers an alternator using a turbine. The turbinewheel is rotated by the vaporization of an organic liquid and subsequent expansion of the gas. Theorganic liquid is vaporized in a burner using hydrocarbon fuels. The organic vapor is cooled,condensed, and pumped back to the burner. These processes are repeated to power the alternator. Thealternator produces AC which is then converted into DC by a rectifier, and this is used to applycathodic protection.

9.3.3e Impressed current – thermoelectric generatorA thermoelectric generator produces DC. Commercial thermoelectric generators producing up to600 W and 48 Vof power are available. Higher power outputs can be achieved by stacking several ofthem. In practice, the power required for cathodic protection is calculated, and the number of ther-moelectric generators is then derived. The principle of a thermoelectric generator is same as that of athermocouple, which is commonly used to monitor temperature. In both a thermocouple and a ther-moelectric generator, the electricity is produced by heating the junction between certain dissimilarmetals. In a thermocouple, the electricity so produced is read by a calibrated voltmeter to display thetemperature. Each thermocouple generates up to 90 mV of potential. In a thermoelectric generator,


several thermocouples are connected in series to provide the required voltage output for the CP system.To generate the electricity, two dissimilar metal junctions are maintained at 1000�F (538�C) (hot) and325�F (163�C) (cold). The heat required for this purpose is produced by burning hydrocarbons. Thejunctions are immersed in a special fluid in sealed container.

9.3.3f Impressed current – solar electric power generatorSolar power systems are available to produce power up to 1000 W, 20 V, and 50 A. Certain materialsgenerate an electric charge when sunlight is incident on them. This principle is used to produce power.Solar power systems only function in the presence of sunlight, so they are combined with storagebatteries to produce continuous power. The system can normally provide 10 A of current to a rectifierfor two weeks without recharging.

9.3.3g Impressed current – batteryBatteries may be used to power cathodic protection systems in isolated locations with no electricityfacilities, or where the sacrificial anode method is not adequate to provide the requiredcurrent. Batteries are frequently used to apply cathodic protection to a well-coated pipeline crossing ariver. This method is not effective if current drain is high, i.e., on a bare or poorly coated structure.

9.3.3h Impressed current – windSimilar to solar energy, wind power can also be used to operate a cathodic protection system. Theymay be used in remote locations where there is no other source of power, and where the wind velocityis high and steady. The power output from a wind generator is not constant; hence, such a system iscoupled with a storage battery to provide continuous power to the cathodic protection system.

9.3.3i Impressed current – gas turbineThe operation of a gas turbine is only efficient and economical if there is a large pressure drop. Ex-amples where such large pressure drop occurs include gas transmission pipelines, gas productionfields, and wellheads. In these situations, gas flows through a bypass loop to operate the turbine andreturns back to the mainline. The turbine in turn energizes a DC generator which provides the currentto apply cathodic protection. Systems where large pressure drop occur are not common. For this reasonthis mode of impressed current system is not common.

9.3.3j Impressed current – fuel cellIn its simplest form, a fuel cell produces DC current and water when two gases are forced through asandwich of two porous electrodes. The gases normally used are oxygen and hydrogen, but attemptsare also being made to use natural gas. However, fuel cell technology is not yet mature enough toprovide a reliable impressed current source for cathodic protection.

9.3.4 Potential criteria101

As discussed in section 9.3.1, the basic principle of CP is to move the potential of the structure to theopen circuit potential of its anode, so that all anodic sites of the structure become cathodic (i.e.,sufficient current should be applied to move the potential from corrosion potential (Ecorr) to Ecp inFigure 9.12). Although simple in theory, when applied in real life several issues need to be addressed.In fact, one of the most debated issues in the oil and gas industry is the criteria used to determine


whether the structure is adequately protected by cathodic protection. Some widely used criteria arediscussed in the following paragraphs.

9.3.4a �850 mV ONThis criterion applies only to carbon steel and cast iron. A carbon steel or cast iron structure iscathodically protected when its potential is at least �850 mV vs. a copper-copper sulfate (CCS)reference electrode. This criterion was originally established in the 1920s, and was based on extensivestudy of the corrosion potentials of carbon steel and cast iron. Table 9.38 presents typical corrosionpotentials of cast iron and mild steel as measured in various soils at ambient temperature throughoutNorth America.102 From the data it is obvious that maintaining the potential of carbon steel and castiron at �850 mV vs. CCS would considerably reduce the corrosion rate (by decreasing the anodicareas on the metal). The table shows that when the potential of steel is �850 mV, the surface would beat least 50 mV cathodic (negative) to the corrosion potential. This criterion was adopted by the oil andgas industry, several standards developing organizations, and several companies. The advantages ofthis criterion include: only one potential needs to be measured to ensure that CP is properly applied;the potential is measured with the CP current turned on (therefore the current can be adjusted until thepotential is reached); the procedure is relatively easy for the field technician to carry out; and historicaldata is not required.

It is important to ensure that the potential measured is free from solution resistance (IR drop). Thepotential measurement is based on Ohm’s law (Eqn. 9.22):

E ¼ IR (9.22)

where E is the potential, I is the current, and R is the resistance. For the �850 mV vs. CCS cathodicprotection criterion to be valid, the potential measured should only be due to the potential between thestructure and the environment. However, there may be many elements present in between the structureand the reference electrode whose resistance will affect the measured potential. These elements couldinclude the structure-coating interface (as long as this interface is intact, cathodic protection is notnecessary); coating resistance (this resistance is important if there is structure-environment existsbeneath coating, i.e., when the coating disbonds); soil resistance; and soil-reference electrodeinterface.

Table 9.38 Typical Corrosion Potentials of Iron and Steel in Natural Soils and Water102

Metal Condition

Corrosion Potential, mV Vs.Copper-copper Sulphate (CCS)Reference Electrode

Mild steel Clean and shiny �500 to �800

Mild steel Rusted �200 to �500

Cast iron Not graphitized �500

Cast iron High silicon content �200

Steel Presence of mill scale �200


Thus the measured potential (Vmeasured) is (Eqn. 9.23):

Vmeasured ¼ VSE þ VSC þ ICoatRCoat þ ISRS þ VSR (9.23)

where:

• Vmeasured is the measured potential between the structure and reference electrode.• VSE is the potential between the structure and the environment. (This is the only potential of

interest with respect to CP and this potential should be �850 mV vs. CCS).• VSC is the potential between the structure and the coating:

• if there is no coating, this potential does not exist.• if the coating is intact there is no such potential, i.e., this parameter can be ignored, and• if the coating has disbonded and the coating is in between the structure and the reference

electrode, this potential is of great significance. In this situation the value of RCoating isimportant.

• ICoat is the current flowing across the coating; ICoatRCoat is commonly known as the IRcoat dropacross the coating.

• RCoat is the resistance of the coating:• if there is no coating, this value is ignored.• if the coating is intact with high RCoat value (see Table 9.32), CP and hence potential

measurement are not needed at all, and• if the coating has disbonded with high RCoat value it may electrically shield the structure from

cathodic protection. Under this condition:• Vmeasured has no relationship with VSE.• VSE ¼ VSC; depending on the value of VSC corrosion and SCC may take place, no matter

how much of CP current is applied and what is measured as Vmeasured.• RS is the resistance of environment (soil) or solution resistance. The influence of RS may be

avoided by moving the reference electrode as close as possible to the structure. By this procedurereasonable estimate of VSE can be obtained from Vmeasured.

• IS is the current flowing across soil; IRSoil is commonly known as IR drop across the soil.• VSR is the potential between the soil and the reference electrode. Normally this potential is low

and is ignored, as there is no current flow through the reference electrode.

Use of this criterion should be avoided at river or road crossings, where the reference electrode cannotbe placed closer to the structure. For poorly coated structures, i.e., coating with several breaksproviding current paths, use of this criterion may lead to the application of prohibitively large amountsof current. The use of cathodic protection and potential measurement should be questioned whenapplied to structures with disbonded coatings with high RCoat (see Table 9.33). Stray current interfereswith the potential measurement (section 9.3.7 discusses details of stray current and its control). Thestray current source may be constant or dynamic. A constant stray current source should be switchedoff while making the potential measurement. To overcome dynamic stray current (e.g., from a railwaytransit system), potential measurements should be taken for a duration of 24 hours, i.e., covering theperiod when the dynamic current source is both active and inactive. For example, a stable potential canbe recorded in the early hours of the day or late in the night when transit system is not operating.Telluric current (see section 9.3.7c for more details) interferes with the potential measurement.


Repeated measurement at the same location over a long period of time (at least two consecutive days)may help to delineate its effect.

9.3.4b �950 mV ONUnder certain conditions, the corrosion potential of cast iron and carbon steel is more negative than�850 mV vs. CCS. In these situations, the CP current is applied until the potential of the structurereaches �950 mV vs. CCS. This criterion is commonly used when the infrastructure is in microbi-ologically active soil (microbes can depolarize the electrode potential in the negative direction) orwhen the operating temperature increases (typically above 50�C (122�F)). In general, reaction ratesincrease with temperature (under ideal conditions, the reaction rate doubles for every 10�C increase intemperature). Consequently, the corrosion potential shifts in the negative direction as the temperatureincreases.

Before this criterion is used, the structure is thoroughly surveyed to ensure that the corrosionpotential is indeed more negative than �850 mV vs. CCS. (Section 11.3 discusses several surveytechniques.) When using the�950 mVON criterion, it should be noted that the current consumption ishigher than that required to meet the �850 mV ON criterion, so an adequate power supply should bedesigned and implemented. On the other hand, overprotection, i.e., application of potential beyond thatwhich is required, should be avoided. Normal industry practice is to avoid potentials more negativethan �1050 to �1100 mV cs. CCS since steel may be susceptible to hydrogen damage under suchconditions (section 5.18 presents more information on the hydrogen effect).

9.3.4c �850 mV OFFVmeasured measured with CP current on (i.e., as per �850 mV ON criterion) includes several otherparameters as defined by Eqn. 9.23. When the CP is turned off, the potential contributions due to the IRcomponents disappear immediately; consequently Eqn.9.23 reduces to Eqn. 9.24:

Vmeasured ¼ VSE þ VSC þ VSR (9.24)

The disappearance of the IR components is rather quick once the CP current is turned off, henceVmeasured is approximately equal to VSE, and the potential slowly drifts to the corrosion potential.During the �850 mV OFF measurement, the cathodic current is switched off and the potential ismeasured instantaneously. For this reason, this potential is sometimes known as the instant OFF po-tential measurement. If the measurements are continued for longer, the potential slowly drifts to thecorrosion potential. Figure 9.16 presents a typical potential response of a structure as a function of timeafter the cathodic protection current source has been switched off. The difference between the potentialwith current ON and immediately after the current is turned OFF is a measure of the IR drop, and thedifference between the OFF potential and the corrosion potential is a measure of the polarization of thestructure.

The main advantage of this criterion is the removal of errors due to IR drop from the measuredpotential. In order for this measurement to be accurate, all current sources to the structure must besimultaneously interrupted. Interrupting the current may be impossible or difficult in conditions where alarge structure (e.g., an oil or gas transmission pipeline) is protected by several current sources, andwhere sacrificial anodes are electrically bonded to it. It should further be noted that most factors affectingthe �850 mV ON criterion also affect the �850 mV OFF criterion, including access to the structure,seasonal fluctuation of corrosion potential, disbonded coating, stray current, and telluric current.

Duration

Potential

On potential

Spike due to inductive ef fect

Off potential

Corrosion potential

Cathodic protection current switched of f

FIGURE 9.16 Variation of Potential After Switching off Cathodic Protection Current.

(Indicating potential spike due to inductive effect, ON potential, OFF potential, and corrosion potential).


9.3.4d 100 mV polarization101

According to this criterion, the corrosion potential of the structure is moved 100 mV in the cathodic(negative) direction, no matter what it was before applying CP. Thus the potential profile of the surfacebefore and after the application of cathodic protection is the same, except for a shift in potential by 100mV in the negative direction after the application of cathodic protection. This is contrast to the �850mV criteria (ON and OFF), in which cathodic protection shifts the potential of the entire surface to�850 mV vs. CCS, no matter what the corrosion potential was beforehand. From this it is clear thatthese criteria are the same when the corrosion potential is around �750 mV, and different when thecorrosion potential is at a value that is very diiferent from this. Table 9.39 illustrates this conceptnumerically.

Two methods are used to determine the shift in potential: formation and decay methods; with thedecay method being the more common and efficient.

In the formation method, the corrosion potential of the structure is measured before applying CP,and then again after applying CP. The difference between the two measurements should be more than100 mV, with the potential measured after applying CP being more negative than the corrosion po-tential. The applying CP current generally decreases with time, and this observation is used to confirmthat the criterion is properly implemented.

In the decay method, the potential is continuously monitored with the CP current applied. The CP isthen temporarily interrupted, and the decay in the potential is monitored. From the decay, the instant off

Table 9.39 Comparison of Various Cathodic Protection Application Criteria

Criteria

Corrosion Potentialbefore Application ofCathodic Protection, mVvs. CCS

Potential afterApplication of CathodicProtection, mV vs. CCS

Degree of Polarization(Potential after CP ePotential before CP),mV)) Remarks

�850 mV ON �100) �850) �750 Large amounts of current isnecessary to applycathodic protection.

�850 mV OFF �100 �850 �750

100 mVpolarization

�100 �200 �100 Smaller amounts of currentis necessary to applycathodic protection.

�850 mV ON �750) �850) �100 Amount of current to applycathodic protection is thesame irrespective of criteriaused.

�850 mV OFF �750 �850 �100

100 mVpolarization

�750 �850 �100

�850 mV ON �900) �850) þ50 The structure is notcathodically protected. Inthis case �950 mV Vs.CCS criterion should beused.

�850 mV OFF �900 �850 þ50

100 mVpolarization

�900 �1,000 �100 The structure is cathodicallyprotected.

)IR free))Negative sign indicates that the potential moves in the cathodic (less corrosive) direction, and positive sign indicates that the potential moves in the anodic (morecorrosive) direction

602

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potential and corrosion potential are noted. The instant off potential point is reached quickly due to thedisappearance of IR effects (Figure 9.16). It should be noted that when the CP current is interrupted, thepotential may exhibit a spike due to inductive effects which may last a few milliseconds. Thereforethe instant off-potential is typically measured between 200 and 500 milliseconds after the interruptionof current. After the instant off-potential, the potential shifts exponentially with time in the positivedirection – due to the depolarization of the structure – until the corrosion potential is reached. Theduration of this period may be measured in minutes, hours, days, or weeks depending on soil condition,type of cathodic application technique, coating status, and other interferences. The instant off-potentialis then compared with the corrosion potential; the difference between these two potentials shouldexceed 100 mV (with the instant off-potential being more negative than the corrosion potential).

The 100 mV polarization criterion is used to apply CP not only to carbon steel, but also to othermetals including copper, aluminum, and metals for which a specific cathodic protection potential hasnot been established.

The main disadvantage of using the 100 mV polarization criteria is the time required to implementthe criteria, with depolarization taking from a few days to several weeks in some cases – as aconsequence the structure is not protected for an extended period of time. To overcome this issue oneapproach is not to wait for full depolarization but to monitor the decay only for a few hours in whichtime structure should depolarize by more than 50 mV. If a 50 mV depolarization has not occurredwithin a few hours, the 100 mV polarization is not an appropriate criterion for the structure under theconditions.

The 100 mV polarization criterion is not applicable in situations in which stray current is present,because polarizing the structure to 100 mV in the negative direction will not control corrosion. Inaddition, if all sources of stray current cannot be interrupted then it will not be possible to carry out aninspection to ensure that the 100 mV polarization criterion is met.

The 100 mV polarization criterion is also not applicable on structures consisting of dissimilarmetals, because a 100 mV polarization potential may not be adequate to polarize all the anodic areas ofthe structure.

As discussed in section 10.3.2, high pH SCC may occur at potentials between the corrosion po-tential and �850 mV vs. CCS. Applying the 100 mV polarization criterion may polarize the structureto potentials which are more susceptible to SCC.

i. AluminumThe 100 mV criterion is used to cathodically protect aluminum pipes. However it should be noted thataluminum, in a similar way to titanium and zirconium, is amphoteric in nature; i.e., it undergoesaccelerated corrosion at low and high pH. Polarizing aluminum to potentials more negative than�1,200 mV vs. CCS increases the pH. At higher pH values the oxides of aluminum dissolve rapidly,accelerating its corrosion. In addition, all precautions used to apply 100 mV polarization criteria forcarbon steel also apply to aluminum.

ii. CopperThe 100 mV criterion is also used to cathodically protect copper pipes. Copper is noble (more positive)than many metals, including cast iron, carbon steel, and aluminum. As a result many metals undergocorrosion when they are in contact with copper. It is therefore important to isolate these metals beforeapplying CP to copper.


9.3.4e 300 mV potential shiftThe 300 mV potential shift criterion is similar to the 100 mV polarization criterion, but in thiscriterion the CP is applied to shift the potential by 300 mV from the corrosion potential in thecathodic (negative) direction and the potential is measured with CP on. For this reason, the 300 mVpotential shift criterion suffers from the influence of IR drop. All limitations discussed for 100 mVpolarization criterion are also applicable to 300 mV potential shift criterion. This criterion wasdeveloped empirically for steel structures in concrete in which the corrosion potential is between�200 mV and �500 mV vs. CCS. In such situations, the steel is in the passive state, and areaswhich are not in this state are protected by shifting the potential by 300 mV in the negativedirection.

9.3.4f Net protective currentThe premise of this method is that corrosion does not take place in locations of the structure whichreceive current from the environment (soil or electrolyte), i.e., where reduction reactions take place.To implement this criterion, the CP current is first interrupted and a survey is conducted to locatecorrosive spots (i.e., anodic regions) of the structure. Section 11.3 describes various survey methods –the close-interval structure-to-soil potential survey is commonly used. The CP current is then turnedon, and another survey, commonly known as side-drain method, is used to determine whether theanodic regions of the structure are receiving CP current, i.e., current from the electrolyte. Threeidentical electrodes are used; one is placed directly over the structure, and the other two on eitherside. The potential differences between the electrode over the structure and the ones placed on theside of the structure are measured. If the electrode placed over the structure is negative with respect tothe ones placed on the side, then it is taken that that location of the structure is receiving cathodiccurrent.

This criterion is normally used on structure with long-line current activity (e.g., uncoated orpoorly coated structure) and in situations where other criteria cannot be easily or economicallyimplemented.

When using this criterion, it should be noted that anodic reactions, can take place at any locationwhere the potential is more positive than the Eequil (Figure 9.12). Corrosion cannot take place onlywhen the potential is more negative than Eequil. Nevertheless, it is assumed in practice that locationsreceiving any amount of current from the environment are not susceptible to corrosion. Further, theidentification of anodic sites may be difficult in areas of stray current activity, which contain severalinfrastructures (e.g., pipeline corridors), or on structures in high resistivity soil, with long-line currentactivity, or in which the distance between the anodic and cathodic areas is small.

9.3.4g E-log I curveSection 9.3.2 discusses the basic principle of this criterion. It is frequently used to establish theminimum current required to implement effective CP. To establish this criterion, the structure-to-soilpotential is measured as a function of CP current. Typically the potential measurements are made byinterrupting the cathodic current and measuring the instant off potential using a remote referenceelectrode. The E-log I plot is constructed from the measurements. Figure 9.17 presents theoreticalbackground to the plot (see section 9.3.2). The plot is used to derive the negative potential and theminimum current needed to achieve effective CP, and these values are used to design and operatethe cathodic protection system. Subsequent surveys are conducted to ensure that the current output of

ICIA

+

-

EC

Iappl=IC -IA

FIGURE 9.17 Typical E-Log I Curve to Establish a Minimum Cathodic Protection Current Requirement.


the cathodic protection system and the potential of the structure with respect to the remote referenceelectrode are close to the established value.

Implementation of this criterion requires elaborate arrangements and repeat measurements. It isalso important to place remote reference electrode in the same location every time the potential ismeasured. For these reasons, this criterion is normally used in situations where other criteria cannot beeasily implemented. Such situations include pipelines in river crossing, in well casings, and inpopulated industrial areas. Furthermore it should be noted that it may be difficult to reproduce theoriginal E-log I plot used to establish this criterion.

9.3.5 Applicability of cathodic protectionThere are situations in which cathodic protection is ineffective or not applicable at all. Cathodicprotection cannot protect features above conducting media such as the aboveground portions of tanks,valves, and offshore structures in splash zones. The CP implemented to protect the external surface of astructure cannot protect its internal surface because the current is interrupted by the external surfaceand returned back to its source. This is true even though the pipe material is a good electricalconductor. The CP will only protect the external layers of multilayered structures or features, e.g.,power or communication cables. Most current flows only to the outer layer, and little current flows tothe inner layers. This phenomenon is commonly known as electrical shielding (Figure 9.18). CP isineffective for protecting surfaces beneath non-conducting materials, e.g., disbonded coatings andinsulators. Very high potential drive is required to allow the current to penetrate through these non-conducting materials. Implementation of such a system may not be economically possible.

9.3.6 Factors influencing the effectiveness of cathodic protectionThe effectiveness of cathodic protection depends on several factors; some of which are discussed inthis section.

+ –A

C

E

B

FIGURE 9.18 Electrical Shielding Effect During Cathodic Protection.103



9.3.6a Protective coatingsA protective coating is the single most important factor influencing the application of cathodic pro-tection. As discussed in section 9.2, as long as the coating is intact, it is the first line of defense, givinglittle or no need for CP. As the coating deteriorates the amount of CP current needed increases. It isimportant that the protective coating does not disbond in such a manner to prevent the CP current fromreaching the metal surface.

9.3.6b Maintenance capacityControlling corrosion of a structure with CP is not a one-time operation, but is a continuous one.Therefore the capacity to operate and maintain the system should be established upfront and should beimplemented during service. Chapter 13 discusses general maintenance issues in corrosion control.

9.3.6c EnvironmentThe ease with which CP is applied depends on the type of environment. In general, factors whichincrease the corrosion rate make the application of CP relatively difficult. Such factors include oxygencontent, acidity, microbial species, and flow of water. Increases in any of these factors generally in-creases the current required to apply effective CP.

9.3.6d TemperatureThe effect of temperature on CP manifests through the effect of conductivity (or resistivity). In general,the conductivity of water decreases with decreases in temperature. The conductivity of frozen soil is


low when compared to unfrozen soil. It is for this reason that an anode ground bed is installed in deepsoil in permafrost regions (approximately 80 m (262 feet) from the surface). In these regions, the soilsurface is permanently frozen but areas deep below ground are unfrozen.

9.3.7 Stray currentsStray current is an unwanted current from external sources which interferes with that of the infra-structure of interest. There are three types: DC stray current, AC stray current, and telluric current.

9.3.7a DC stray currentDC current flowing from any source (other than the anode bed of the given infrastructure) and enteringthe infrastructure of interest is considered as stray current. The stray current from an external sourceflows to the earth, enters into the infrastructure from the earth, leaves the infrastructure, re-enters theearth, and finally returns to its original source. The point of the infrastructure at which the stray currentleaves and returns back to earth becomes anodic and undergoes corrosion.

Common sources of stray current include cathodic protection current from other pipelines orinfrastructure, railway transit systems, mining operations, welding operations, and DC transmissionsystems. The stray current may be steady or random. For example, the stray current from a neighboringCP system or DC transmission system is mostly steady (static stray current), and that from a railwaytransit system, mining operation, and welding operation is random (dynamic stray current).

i. Static stray currentFigure 9.19 illustrates a situation in which the CP current from one pipeline interferes with and causescorrosion in a neighboring pipeline.104 Figure 9.20 illustrates a test system to determine whether theCP of a given pipeline of interest is interfering with and causing corrosion in neighboring pipelines.105

In addition to other gadgets for applying CP, an automatic interrupter is installed in the pipeline ofinterest and test leads are installed both in the pipeline of interest and in the neighboring pipeline atappropriate locations. With the automatic interrupter operating in a cyclic fashion (e.g., 20 seconds ONand 10 seconds OFF), the potentials of both the pipeline of interest and neighboring pipelines aremeasured.106 For this purpose the CCS reference electrode is placed at the points of crossing.Table 9.40 presents some survey results illustrating different scenarios in which the CP systems ofneighboring pipelines may influence one another. From the examples presented in Table 9.40 andFigure 9.20 we can conclude that:

• the CP system of pipeline of interest (pipeline E) interferes with pipelines A and B• the CP system of neighboring pipeline C interferes with pipeline E• corrective measures to overcome stray current are required for pipeline A (to overcome stray

current from pipeline E) and pipeline E (to overcome stray current from pipeline C) and• no corrective measures are required for pipeline B (to overcome stray current from pipeline E), as

the influence is minimal.

In many situations, the proper installation, operation, and maintenance of a CP system may besufficient and effective to overcome the effect of stray current. Additional measures include the use ofa drainage bond, protective coating, galvanic anode, and electrical shields, and relocation of rectifier orthe infrastructure itself. Electrically connecting interfering infrastructure by resistance bonds is acommon method of overcoming stray current. The resistance of the bond is adjusted so that sufficient

FOREIGN PIPELINENOT CROSSINGPROTECTED LINE

AREA OF INFLUENCE SURROUNDING THE GROUND BED

ENDWISE CURRENT FLOW

GROUNDBED

CURRENTDISCHARGEFROM FOREIGNPIPELINE INREMOTEAREAS

PROTECTED PIPELINE

RECTIFIER

FIGURE 9.19 Stray Current from the Cathodic Protection of an Infrastructure Causing Corrosion in the Neighboring

Infrastructure.104



current is drawn to overcome the effect of the stray current. Figure 9.21 presents a bond between twointerfering pipelines installedto overcome the stray current.107 Stray current affects areas of theinfrastructure that are bare, e.g., those that have poor coating. Under such conditions, bonding may notbe economically feasible because the amount of current required to overcome the stray current is veryhigh. In this situation, repairing the coating or recoating the infrastructure may decrease the effect ofstray current.

The use of sacrificial anodes may sometimes be beneficial. With this arrangement, the stray currentfrom the neighboring structure is discharged at the anode rather than on the infrastructure of interest.Stray current may also be mitigated by using an electrical shield. For example, the effect of straycurrent on a pipeline of interest may be mitigated by placing bare pipes around it and connecting thebare pipe to the negative terminal of a neighboring pipeline. The bare pipe will pick up the stray currentfrom the neighboring pipeline thereby protecting the pipeline of interest. The bare pipe drains largeamounts of current from the neighboring pipeline. Therefore the diameter and length of the pipe shouldbe kept to a minimum. In extreme conditions when none of the mitigation strategies discussed so farwork, the possibility of relocating the rectifier of the neighboring infrastructure or relocating theinfrastructure of interest (e.g., rerouting of the pipeline) should be considered.

ii. Dynamic stray currentThe operating potential of a rail transit system is around 750 volts. If the running rails are notcompletely insulated from the earth, the stray current will affect infrastructures present on its return

FOREIGNLINE A

FOREIGNLINE B

FOREIGNLINE C

FOREIGNLINE D

PICKUP

STATION900 + 00

STATION10 + 00

STATION915 + 00

STATION1815 + 00

STATION1765 + 00

RECTIFIER GROUND BEDINSTALLATION

PROTECTED LINEUNDER TEST

DISCHARGECURRENTINTERRUPTERINSERTED FORTESTS

PIPELINE E(OWN PIPELINE)

RECTIFIER AND GROUNDBED ON FOREIGN LINE

2 WHITE LEADS

2 BLACK LEADS

FOREIGN LINE

PROTECTEDLINE

V+ –

FIGURE 9.20 Typical Testing System to Determine the Influence of Stray Current.105



path. The severity of this effect depends on the effectiveness of the insulation of the rail transit systemand traffic in the line. The frequency at which the infrastructure is exposed to higher voltages isdirectly proportional to the frequency of the trains on the track. The infrastructure is affected by straycurrent only when the train runs. Thus the stray current is dynamic in nature.

Table 9.40 Typical Survey Results on Stray Current Interference106

Foreign Pipeline

Potential, Vs CCS (V)

Effect of the Cathodic

Protection System of

Pipeline E

Effect of the Cathodic

Protection System of

Neighbouring Pipeline

Correction Required to

Overcome Stray Current from

Own Pipeline, V (Identified

as E in

Fig. 9.19) Foreign Pipeline, V

Designation

Distance

from

Pipeline E

Rectifier,

Feet (see

Fig. 9.20)

With Cathodic

Protection

Current of

Pipeline E

DV

With Cathodic

Protection

Current of

Pipeline E

DVON OFF ON OFF

On

Pipeline E

On

Neighbouring

Pipeline

On

Pipeline E

On

Neighbouring

Pipeline

Neighbouring

Pipeline on

Pipeline E

Pipeline E on

Neighbouring

Pipeline

A 10 �0.88 �0.85 �0.03 �0.87 �0.89 þ0.02 Fully

protects

(ON and Off

potentials

more

negative

than �0.85

V)

Interferes

(DV positive),

but the effect

minimum

No

interference

(ON and Off

potentials

more

negative

than �0.85

V; addition

testing may

be required

to confirm)

Fully protects

(ON and Off

potentials more

negative than

�0.85 V)

No (no

interference)

No (DV value

small)

B 900 �1.98 �1.02 �0.96 �0.32 �0.68 þ0.36 Fully

protects

(ON and Off

potentials

more

negative

than

�0.85 V)

Interferes

(DV positive)

No

interference

(ON and Off

potentials

more

negative

than �0.85

V; addition

testing may

Not adequately

protects (ON

and Off

potentials more

positive than

�0.85 V)

No (no

interrence)

Yes (DV value

positive and

high)

610

CHAPTER9

Mitig

ation–Exte

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sion

be required

to confirm)

C 1765 �0.68 �0.64 �0.04 �0.78 �0.78 0 Not

adequately

protects

(ON and Off

potentials

less

negative

than

�0.85 V)

No interference

(DV zero)

Interferes

(ON and Off

potentials

more

positive than

�0.85 V and

in other

locations of

the pipeline

it is more

negative

than

�0.85 V)

Not adequately

protects

(ON and Off

potentials more

positive than

�0.85 V)

Yes No

D 1815 �0.95 �0.91 �0.04 �0.68 �0.68 0 Fully

protects

(ON and Off

potentials

more

negative

than

�0.85 V)

No interference

(DV zero)

No

interference

(ON and Off

potentials

more

negative

than

�0.85 V)

Not adequately

protects

(ON and Off

potentials more

positive than

�0.85 V)

No No

9.3

Cathodic

protection

611

BOND TYPICALLYAN ADJUSTABLESLIDE RESISTERCONNECTEDBETWEEN THEHEAVY LEADTERMINALS FORWIRES FROMFOREIGN ANDPROTECTEDLINES

TYPICAL FOREIGN LINE CROSSINGTEST POINT INSTALLATION.TERMINAL BOX MAY BE BURIED,IF NECESSARY, RATHER THANPOST-MOUNTED

HIGH RESISTANCETEST VOLTMETER

COPPER SULPHATEELECTRODE DIRECTLYOVER FOREIGN LINEAT POINT OF MAXIMUMEXPOSURE

(TYPICAL)NO 8 & NO 12BLACK INSU-LATED WIRES FROM FOREIGNLINE

NO 8 & NO 12 WHITEINSULATED WIRES FROM PROTECTEDLINE

FOREIGN LINEBEING AFFECTEDBY STRAY CURRENTINTERFERENCE

PROTECTED PIPELINE WITH RECTIFIER(INTERRUPTED) CAUSING INTERFERENCEON FOREIGN PIPELINE

FIGURE 9.21 Bond to Overcome Stray Current Between Two Pipelines.107



Several of the methods used to mitigate static stray current are also effective in mitigating dynamicstray current. Ideally, a rail electrical system should be isolated from the earth. All inadvertent contactbetween the rail electrical system and the earth should be eliminated. Further, insulating joints shouldbe installed in the infrastructure in susceptible areas. After the insulating joints have been installed, theCP system should be suitably adjusted to ensure that the relevant section is properly protected.Sacrificial anodes may be installed, along with diodes. This arrangement ensures that the anodesdischarge the stray current rather than receiving it. Installation of a controller that automatically ad-justs the rectifier may be effective in providng additional current when the stray current is active. Thisstrategy is effective only if the area affected by the stray current is small. Installation of bonds betweenthe pipeline and the transit system may be considered in special situations in which all other strategiesare ineffective. The voltage of the transit system is very high; therefore implementation of this strategyrequires sophisticated analysis and extreme care.


9.3.7b AC stray currentThis is discussed in section 5.21.

9.3.7c Telluric currentThis is discussed in section 5.22.

9.3.8 Side effects of cathodic protectionCathodic protection is very effective in controlling the corrosion of materials, but in some situations itcan lead to undesired side effects. Some of these are described in this section.

Cathodic protection controls the corrosion of a material by making it a cathode. Consequentlycathodic reactions take place on the surface; however, the products of certain cathodic reactions maybe harmful to the structure. The primary example of this is the hydrogen effect (see section 5.18). Toavoid this, the application of potentials at which hydrogen reduction occurs is avoided.

The corrosion rates of amphoteric materials (aluminum, titanium, and zirconium) may increase dueto cathodic protection. Cathodic protection may increase the pH; at high pH the surface layers onamphoteric materials dissolve, resulting in higher corrosion.

Foreign structures, especially those near the anode ground bed may suffer accelerated corrosion ifthe current enters and discharges through it. Figure 9.19 illustrates this situation. To overcome thisissue, the foreign structure should be electrically connected to the structure being protected bybonding. This, however, increases the area of the surface being protected by the CP system.

9.3.9 Materials and accessoriesThe application of cathodic protection requires several materials and accessories, some of which aredescribed in this section.

9.3.9a Backfill materialBackfill materials are used in the anode bed to reduce the resistance between the anode and the ground.These materials are commonly known as ’breeze’ – a term used to indicate their finely divided nature.Typical materials include petroleum coke, calcined petroleum coke, coal coke, natural graphite par-ticles, crushed graphite particles, and metallurgical coke. Deep-anodes are typically placed in a cokecolumn and are installed at 60 to 90 m (196 to 295 feet) from the surface.

9.3.9b Test stationThe test station is the key to ensure that CP is working properly. There are several configurations oftest stations (Figure 9.22). They provide locations for connecting wires to measure structure toenvironment potential, to measure current flow (line current measurements), to connectgalvanic anodes to the structure, to insert resistance across the wires, and to insert bond acrossinsulation joints.

9.3.9c Current interrupterInterrupting the current is necessary and is used frequently to test the CP system. A current interrupterrelies on a quartz crystal to precisely time the current interrupt and to synchronize with other devices.

FIGURE 9.22 Typical Configurations of Test Stations for Cathodic Protection.108



9.3.9d Pulse generatorA pulse generator is required to conduct ON and OFF potential surveys. It may either produce its onepulse current or suitably interrupt the current from the CP power supply.

9.3.9e Ammeter clamp accessTo measure the current flowing through the pipeline (line current), a portable ammeter is clamped ontothe pipeline. Access to clamp the device should be installed.

References 615

9.3.9f Wires and cablesWires and cables between the anode bed and the structure carry the current. They should beperfectly insulated, otherwise they discharge current at points where they contact the environment.Insulation materials are rated to withstand at least 600 V and are normally made from polyethylene.They should be inspected during installation to ensure that they do not have any scars, cuts, or otherdamage. An insulator-checker is used to inspect the integrity of the insulators. The wires and cablesare connected to the anodes and the structures using low electrical resistance welds, brazes, andsolders, otherwise the connection resistance and cable and wire resistance decrease the currentoutput from the CP system.

9.3.9g Casing pipesCasing pipes used are at road and railway crossings to protect oil and gas pipelines. They are elec-trically insulated from the oil and gas pipeline, otherwise the casing pipes would carry current from theCP system that are intended for the oil and gas pipeline. Typically, insulating spacers are placed atseveral locations (typically 10 feet (w3 meter) apart) between the mainline and casing pipes. Thespacers may be made of rubber or plastic.

9.3.9h Insulated jointsInsulating joints are used to separate the infrastructure into various electrically separate sections so thatthe CP is applied effectively. Insulated joints are typically used every 25 to 60 miles (40 to 100 km) ofpipeline. They are also used to isolate the infrastructure in locations that are susceptible to stray currentfrom other structures.

References1. NACE RP 169 ‘Control of external corrosion on underground or submerged metallic piping systems.’

NACE International, 1440, South Creek Drive, Houston, TX, USA.2. ISO 15589, ‘Petroleum and natural gas industries – cathodic protection of pipeline transportation systems.’,

International Organization for StandardizationISO Central Secretariat1, ch. de la Voie-CreuseCP 56 - CH-1211 Geneva 20Switzerland.

3. CSA Z662, ‘Oil and gas pipeline systems (Annex L: Test methods for coating property evaluation)’ Ca-nadian Standards Association, 178 Rexdale Blvd.Toronto, Ontario, Canada M9W 1R3.

4. Mike J. Mitchell, ‘Progress in offshore coatings’ NACE CORROSION Conference 2004, Paper #4001,NACE International, Houston, TX (2004).

5. Papavinasam S, Revie RW. Pipeline coatings, White Paper, Proceedings, International Workshop onAdvanced Research & Development of Coatings for Corrosion Protection. Biloxi, Mississippi April 14–16,2004.

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