Heidersbach R. Metallurgy and Corrosion Control in Oil and Gas Production

CORROSION CONTROL 129

cially available comparators used for this purpose.

Comparisons are made with a specially constructed

magnifying glass that allows comparison of the surface

in question with four different grades of surface prepa-

ration. Other methods of surface - proﬁ le determination

include the use of replica tape for making a negative

image of the surface in question. A soft plastic tape with

a hard backing is applied to the area in question. After

the tape is removed, the proﬁ le of the tape replica is

measured using a specially calibrated microscope.

14,25 – 30

Coating inspectors also use visual photographs avail-

able from NACE and SSPC to document the surface

conditions to be expected after wet abrasive blasting or

water jet cleaning.

31,32

The appearance of grit - blasted surfaces will vary

depending on the speciﬁ c grit used and the steel sub-

strate in question. It is often advisable to prepare a ﬁ eld

sample for referee purposes prior to starting a surface

preparation project. This ﬁ eld sample, representative of

the agreed - upon surface cleanliness for the project, may

be a plate of metal or a part of the structure. These

prepared areas can then be used as reference by the

contractor and the inspector. It is important that the

surface be preserved in its “ as agreed ” condition until

the project is completed.

Inspection Before and During Coating Application

Application equipment and methods need to be

inspected prior to and during painting operations. This

includes making sure that pigments are stirred and sus-

pended in the vehicle, proper mixes of two - component

paints are maintained, and so on. New low - VOC paints

make coating application more difﬁ cult and harder

to apply.

Pigments need to be stirred and suspended in the

vehicle. Proper operation of all equipment must be

insured so that the coating will be delivered in the

appropriate manner.

The newer low - VOC paints make coating application

more difﬁ cult and increase the need for better coatings

inspection.

Wet ﬁ lm thickness is normally determined manually

by inserting a special tool into the wet ﬁ lm as shown in

Figure 6.11 . The notches between the teeth on this tool

have various depths, and the wet ﬁ lm thickness is deter-

mined as the midpoint between the last coated notch

and the next deeper notch. Once the thickness is mea-

sured, the wet ﬁ lm will usually ﬂ ow back and cover the

tooth marks. The dry ﬁ lm thickness can be estimated by

knowing the percent solids in the paint, and corrective

action can be taken to reapply more paint or reduce the

application rate as needed. Thin ﬁ lms will not provide

adequate coverage, and many thick ﬁ lms will not cure

correctly. If a more precise measurement is necessary,

eccentric roller gages, lens gages, or needle micrometers

can be used.

33

Inspection after Application The most common tests

applied to dry ﬁ lms are thickness and adhesion

measurements.

Magnetic thickness gages are usually used for dry -

ﬁ lm thickness determinations on steel substrates. They

need to be calibrated, and they are less accurate on

curved surfaces or thin (sheet vs. plate) carbon steels.

34,35

They usually cannot be used on most stainless steels

with the exception of the low - alloy 13 - chrome martens-

itic stainless steels used for pipelines and similar appli-

cations, where they must be specially calibrated to

compensate for the reduction in magnetic alpha ferrite

in the metal.

Nondestructive magnetic measurements can be con-

ﬁ rmed by destructive tests, which are also used in cases

of disputes. The most common destructive test uses a

Tooke gage, which measures the exposed cut coating

after it has been cut with a special scribe.

36

The exposed

cut surfaces, shown in Figure 6.12 , are viewed under a

Figure 6.11 Wet - ﬁ lm step or notch gage applied to a newly

painted surface. Photo courtesy of NACE International,

reproduced with permission.

Figure 6.12 Cross section of a coating cut for Tooke gage

measurement of dry ﬁ lm thicknesses.

A = A′ tan 45° = A′

tan

45° = 1

45°

A

B

B′A′

Top Coat

Primer

Steel Substrate

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130 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

special magnifying glass, and the thickness of the cut

edges are calibrated on the instrument.

Adhesion tests are nondestructive tests often per-

formed on dry ﬁ lms in accordance with a variety of

international standards.

37 – 39

Coating holidays are defects (usually holes, which

may be microscopic) in the coating that expose the

underlying metal to the corrosive environment. They

are normally detected using electrical holiday detector.

An electrode is passed over the surface being inspected

and, as it passes over a defect, the system passes current

between the electrode and the metal being inspected.

40

The operator can then mark the holiday for repair. This

is shown in Figure 6.13 . While Figure 6.13 shows the

inspection of an internal coating in a large diameter

pipe, the same procedure is used on structural metal,

pipeline exteriors, and any steel structure coated with a

nonconductive coating system. Holiday detectors must

be selected for the appropriate application, as high -

voltage detectors used on thick - ﬁ lm exterior pipeline

coatings would damage thinner coatings, and the lower -

voltage instruments used for thin ﬁ lms would not pen-

etrate thicker, more resistant coatings.

40,41

Any defects noted during surface preparation, appli-

cation, or after ﬁ lm drying should be noted and remedi-

ated before the next step in the coatings or construction

process.

Weather Conditions Weather conditions must be

measured before coatings operations can begin. Table

6.11 shows the conditions where condensation will form

on a metal surface depending on the metal temperature,

air temperature, and relative humidity. NORSOK speci-

ﬁ es that no ﬁ nal blast cleaning or coating applications

TABLE 6.11 Relative Humidity and Surface Condensation Temperatures on Uninsulated Metal Surfaces

42

Metal Surface

Temp.

Surrounding Air Temperature ° F

40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120

3 5 ° F 6 0 3 3 1 1

4 0 6 9 3 9 2 0 8

4 5 6 9 4 5 2 7 1 4

5 0 7 1 4 9 3 2 2 0 1 1

5 5 7 3 5 3 3 8 2 6 1 7 9

6 0 7 5 5 6 4 1 3 0 2 1 1 4 9

6 5 7 8 5 9 4 5 3 4 2 5 1 8 1 3

7 0 7 9 6 1 4 8 3 7 2 9 2 2 1 6 1 3

7 5 8 0 6 4 5 0 4 0 3 2 2 5 2 0 1 5

8 0 8 1 6 6 5 3 4 3 3 5 2 9 2 2 1 6

8 5 8 1 6 8 5 5 4 6 3 7 3 0 2 5

9 0 8 2 6 9 5 8 4 9 4 0 3 2

95 % of Relative Humidity 83 70 58 50 40

100 84 70 61 50

105 85 71 61

110 85 72

115 86

120

Reprinted with permission from NACE.

R. Baboian, NACE Corrosion Engineer ’ s Reference Book , 3rd edition, NACE International, Houston, TX, 2002, p. 74, reprinted with permission.

Figure 6.13 Electrical holiday testing in the interior of a

large - diameter water pipe.

11

. Photo courtesy of NACE

International, reproduced with permission.

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CORROSION CONTROL 131

can be conducted if the relative humidity is greater than

85%, the steel temperature is less than 3 ° C (5 ° F) above

the dew point, and coating applications and curing tem-

peratures must be above freezing for both air and metal

temperatures.

7

This Norwegian standard is primarily

intended for the cold and humid conditions found in the

North Sea and nearby construction yards. NACE rec-

ommends air temperatures above 5 ° C (40 ° F) and rela-

tive humidities of 85%. Some paints can be applied at

lower temperatures and moisture - cured urethane

coating systems may be used at higher humidities.

12

Coatings must always be applied in accordance with the

manufacturer ’ s recommendations, and some coatings,

for example, epoxies, may require higher temperatures

for proper curing.

Areas of Concern and Inspection Concentration

This section is intended to illustrate a number of prac-

tices necessary to insure successful coatings applica-

tions, inspection, and repair. In any structure there are

areas where coatings surface preparation, application,

and repair are more difﬁ cult. There are also regions on

a structure where corrosion damage, if encountered, will

be more signiﬁ cant than the unsightly damage else-

where on the same structure. These are areas that can

sometimes be remediated prior to coating. If they

cannot, then special attention must be paid during all

phases of a coating project, as well as during operations

when the difﬁ cult/critical areas should require addi-

tional emphasis.

Key Features that Should be Remediated Before

Coating There are certain features, perhaps structural

defects, on structures that should be removed before

surface preparation and coating application. Several of

these are shown in Figures 6.14 – 6.17 . These features

should be removed or minimized before surface prepa-

ration begins; otherwise, they will lead to premature

coatings failures.

43

Skip welds are often applied to hold equipment in

place during construction and usually supply adequate

strength for structural purposes. Unfortunately, if they

are not sealed using continuous sealing welds, they allow

crevices to form. This is a major problem for any struc-

Figure 6.14 Skip welds versus continuous welds. Drawing

courtesy NACE International, reproduced with permission.

Continuous weld Skip weld

Desirable Special attention required

Figure 6.15 Weld splatter. Drawing courtesy NACE Inter-

national, reproduced with permission.

Figure 6.16 Gouge with bridged - over coating subject to moisture accumulation and

corrosion.

Bridaged-over gouge

Steel substrate

Coating

ture intended for immersion service, but crevices allow

moisture to collect and create corrosion problems even

in atmospheric exposure. The sealing welds do not need

to be strong, because this could cause metal distortion,

as shown in Figure 4.22 , but they should be water tight

and inspected to insure that no cracks or crevices remain.

Welds should be ground smooth and weld splatter

should be ground ﬂ at so that it does not cause thin

layers or bare spots in the coating.

Voids due to bridged - over gouges or coating shrink-

age will collect moisture, especially in immersion service,

and will eventually lead to coating failure. The sharpness

of the gouges or internal corners should be ground

smooth or, in the case of internal corners like those

shown in Figure 6.17 , a rounded weld bead can increase

the radius and provide more surface area for adhesion.

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132 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

Figure 6.18 Stripe coating prior to painting on an above -

ground storage tank: (a) welds; (b) through - wall ﬁ tting; and

(c) ladder attachments.

Figure 6.19 Flange on the exterior of an above - ground

storage tank. All corrosion was ground away and the edges

were rounded before abrasive blasting and stripe coating.

Figure 6.20 Construction aid on an offshore structure tank

wall that was left in place and stripe coated prior to

overcoating.

Figure 6.17 Void space caused by coating shrinkage.

Steel

Void

Space

Coating

Stripe Coating Certain key locations will remain dif-

ﬁ cult to clean, coat, and inspect. It is common practice

to use stripe coatings in these locations. A stripe coat is

a supplemental coating applied to ensure there is ade-

quate protection of critical areas like ﬂ anges, edges,

welds, and so on.

7

Stripe coats are shown in Figure 6.18 on an above -

ground storage tank under construction. They should be

allowed to set - to - touch before overcoating.

Stripe coats are usually applied by brush or roller to

insure adequate thickness. Their color should contrast

with the substrate and with the overcoat to allow for

easy inspection to insure adequate cover. It is consid-

ered good practice to grind all edges and to extend the

striping at least 1 in. (2.5 cm) from the edges. This is

especially important for maintenance coating, because

exposed edges are more susceptible to corrosion and

are likely to exhibit intergranular exfoliation (Fig. 6.19 ).

Construction aids, such as shown in Figure 6.20 must

also be stripe - coated. While they are designed to be

removed, they are often left in place.

Figure 6.21 shows equipment at a tropical pipeline

receiving station with corrosion on fasteners, ﬂ anges,

welds, and edges. All of these areas need to be ground

smooth and stripe - coated after surface preparation is

completed.

Final Comments on Inspection Most North American

organizations use NACE, ASTM, and SSPC standards

for coatings inspection, while European and other orga-

nizations tend to use ISO standards, which are likely to

be derived from standards originally developed in

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CORROSION CONTROL 133

Figure 6.21 Corrosion on a complicated geometry structure

needing grinding and smoothing plus stripe coating after

surface preparation.

European countries. This practice is changing, and the

trend toward the use of ISO standards is likely to

continue.

17

While standard industrial practice is to develop and

maintain checklists of items to be inspected, these

checklists do not substitute for inquisitive and intelli-

gent inspection teams. Unanticipated situations are

likely to occur on many projects, and it is the responsi-

bility of the inspection organization to bring them to the

attention of the appropriate parties.

Linings, Wraps, Greases, and Waxes

Internal linings, exterior wraps, and greases and waxes

ﬁ nd limited but important uses as oilﬁ eld coatings.

Linings Linings are relatively thick coatings (paint

layers) or, more commonly, sheet materials adhered to

or in intimate contact with the interior surface of a pipe

or other container. Their purpose is usually to protect

the metal surface from corrosion, although some tubular

product liners are also used to minimize ﬂ ow resistance

and increase production rates — usually on downhole

tubing where inside diameters are restricted and bound-

ary layer effects are signiﬁ cant.

44,45

Linings are often used on tank bottoms and the lower

interior side walls of large storage tanks as well as on

cargo and product holds on ships, ﬂ oating production

storage and ofﬂ oading vessels (FPSOs), etc. They are

also used for lining pipelines, injection wells, production

tubing, and other equipment tubular products.

44

Figure

6.22 shows a lining inside a ﬂ anged pipeline segment.

Figure 6.22 The ﬂ ange end of a liner segment installed in an

oilﬁ eld pipeline.

46

High - density polyethylene (HDPE) is the most com-

monly used liner material, but other thermoplastic

materials are also used. HDPE liners are used for water

injection pipelines and injection well tubing, for multi-

phase oil and gas gathering lines, sour multiphase crude

product pipelines, and oil transmission lines. Medium -

density polyethylene (MDPE) is used for water disposal

and injection lines, while polyamide 11 (PA - 11), also

known as nylon, ﬁ nds use for elevated temperature sour

gas and multiphase sour hydrocarbon gathering lines.

44

Table 6.12 compares the relative costs of several resins

used for lining offshore topside piping systems.

Many liners are used to prolong the life of existing

structures that have already deteriorated signiﬁ cantly.

This makes surface preparation difﬁ cult, but the sur-

faces to be lined should be as clean and as obstruction

free as possible. A sizing plate is often run through the

pipeline to conﬁ rm the minimum ID within the host

pipe. Solid liners are then often inserted by pulling them

through the system using an arrangement similar to that

shown in Figure 6.23 . Once the liner has been inserted,

it is expanded against the liner wall, usually by ﬂ uid

pressure. Most liners are thermoplastics, and they will

set after a certain time, conforming to the restraints of

the structure surrounding them.

It is important that liners ﬁ t tightly because gases,

water, and other ﬂ uids will permeate all polymers and

can accumulate at the liner – metal interface. Debonding

of the liner can occur if the ﬂ uid pressure in the system

is suddenly released and the accumulated gas pressure

between the liner and the wall does note permeate

through the liner. Venting systems have been developed

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134 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

TABLE 6.12 Common Water Analysis Determinations

Determination Produced Water and Other Waters Injection Water Cooling Water Boiler Water

Alkalinity X X X X

Microbiological X X X

Barium O

Calcium X X X O

Carbonate X X X X

Carbon dioxide X O O X

Chloride X X X X

pH X X X O

Hydrogen sulﬁ d e O

Iron X X X O

Magnesium X X O

Manganese O

Oxygen O O O

Phosphate O O

Silica X X X

Speciﬁ c gravity X X O

Speciﬁ c resistivity X X O X

Strontium O

Sulfate X X O X

Sulﬁ t e O O

Total dissolved solids X X X X

Zinc O

X, determination usually made.

O, determination occasionally made, for example, manganese counts to correlate with iron counts for corrosion monitoring.

Adapted from table 4.1.

53

Figure 6.23 System for drawing unexpanded liner into a pipeline.

Pulling Head

Wire Cable

Steel Pipeline

Plastic Liner Pipe

Guide Shoe

Figure 6.24 Debonded liner caused by rapid pressure release

in a ﬂ uid piping system.

to prevent high - pressure buildup in the annulus between

the liner and the structure. If the proper venting does

not occur, debonding such as shown in Figures 6.24 and

6.25 may result. Undetected debonding may allow cor-

rosive ﬂ uid accumulation behind the liner. Debonded

liners can also create signiﬁ cant ﬂ ow restrictions.

Monitoring systems for checking the annular pres-

sure behind linings have been noted. Through - wall

X - rays can be used to identify precise locations where

debonding has occurred.

46

Wraps At one time, pipeline wraps were a standard

means of coating the exterior of buried pipelines. Many

years of ﬁ eld experience have shown that this is no

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CORROSION CONTROL 135

Figure 6.25 In - service liner breach failure on a high - pressure

sour gas pipeline.

46

can degrade pipeline coatings and the lack of soil con-

solidation which prevents effective cathodic protection.

The two - layer wrapping system shown in Figure 6.26

includes a mastic tape intended to insure watertight

bonding to the primary coating system, a fusion - bonded

epoxy (FBE). The lighter - colored outer wrapping is

glass - reinforced for mechanical damage protection.

Wraps are also used to protect hard - to - coat areas

such as the bolted ﬂ anges shown in Figure 6.27 .

Reinforced plastic wraps are often used on rigid

piping systems such as the cooling tower piping shown

in Figure 6.28 . These relatively brittle plastics should not

be used on equipment subject to mechanical vibrations

or large thermal excursions because they can crack and

lead to moisture intrusion.

Figure 6.26 Petrolatum tape with glass - reinforced outer

wrap used at the air – soil interface on piping. Photo courtesy

of Denso, Inc.

Figure 6.27 Reinforced wraps used to coat ﬂ anges on above -

ground piping systems.

Figure 6.28 Plastic wrap on cooling tower piping. Photo

courtesy of Denso, Inc .

longer advisable, because any motion of the pipeline is

likely to produce debonding that will expose unpro-

tected metal to the environment and also prevent

cathodic protection from reaching the exposed sub-

strate underneath the debonded wrap. The application

of new long - distance pipeline wraps is now limited to

occasional rehabilitation projects where the economics

of wrapping is considered justiﬁ ed for short - term exten-

sions on projected pipeline use. Wraps are still used

extensively for many other applications, and some of

them are discussed below. Other discussions appear in

the section on pipelines later in this book.

Figure 6.26 shows the application of wraps at the

soil – air interface on pipelines. This is a common area for

corrosion problems because of mechanical stresses that

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136 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

Figure 6.29 Wet valves in a sump on a crude oil pipeline.

Figure 6.30 Waxed tape on a valve in a manhole.

Figure 6.31 Repair wrap being installed on the tidal and

splash zone portions of a marine piling. Photo Courtesy of

Denso, Inc.

Many wet surfaces are so complex and their surface

preparation is so difﬁ cult that no other coating systems

are appropriate. Figure 6.29 shows valves in an outdoor

sump associated with a tropical - climate crude oil pipe-

line. Wax - ﬁ lled wraps like the ones shown in Figure 6.30

are the preferred means of controlling exterior corro-

sion in these situations. The reinforced wraps are

intended to provide a diffusion barrier against moisture

intrusion, and the hydrophobic nature of the wax ﬁ ller

further reduces water intrusion.

Another advantage of wraps is they can be applied

to wet surfaces with minimal surface preparation. Figure

6.31 shows a swimmer applying a wrap to the underwa-

ter and tidal portions of a marine piling.

Most wraps are intended to be moisture permeation

barriers, but if they are debonded or mechanically

Figure 6.32 Pitting of underground pipeline where wrap was

ineffective in preventing corrosion.

damaged, they often act as electrical insulators prevent-

ing cathodic protection currents from reaching the

exposed metal surface. This happened on the pipeline

shown in Figure 6.32 , and extensive corrosion occurred

underneath the wrap.

It is important that wraps have sufﬁ cient mechanical

strength and substrate adhesion. If they do not, they can

unravel from the structure as shown in Figure 6.33 .

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CORROSION CONTROL 137

Figure 6.33 Low - build nonadhesive wrap coming loose from

above - ground pipeline. Photo courtesy of S. Munoz, Corrosion

y Proteccion, Cuernavaca, Mexico .

Greases and Waxes These materials are hydrophobic

and are often used for temporary coatings to limit cor-

rosion. Waxes are often incorporated into wraps to

enhance their ability to limit moisture migration.

Coatings Failures

All coatings will eventually fail. The reason for the fol-

lowing discussions is to provide some insight into why

these failures occur. If they are the inevitable result of

aging, then the coating system selection, surface prepa-

ration, and application were suitable for the intended

service. If premature problems develop, understanding

why these problems occurred will help coatings profes-

sionals decide how to prevent them in the future. This

understanding may also provide useful information jus-

tifying more expensive surface preparation or inspec-

tion procedures. Surface preparation is usually the most

expensive and most important part of any coating appli-

cation, and corrosion professionals must frequently

justify more expensive procedures to management.

Reasons for coating failures, in their approximate

order of importance, are:

12

•

Poor surface preparation and cleanliness

•

Poor coating application

•

Poor or inadequate inspection

•

Poor speciﬁ cations (both construction and coating)

•

Poor component design

•

Murphy ’ s Law

Remember, most coating systems will work for their

intended environment and most coatings failures are

due to inappropriate surface preparation or application

procedures or conditions.

47,48

Normal Aging Failures Normal protective coating

aging failures may show the following phenonmena:

•

Blistering

•

Checking, alligatoring, or cracking

•

Chalking and discoloration

•

Lifting or undercutting of the paint ﬁ lm

Figure 6.34 shows a marine piling with typical aging

of the protective coating. Several degradation processes

are apparent.

Coatings inspectors are trained to evaluate coatings

degradation in accordance with established interna-

tional standards. Figure 6.35 shows one of many ﬁ gures

from ASTM D 610, one of the standards used to rate

corrosion underneath protective coatings.

49

Blisters may be a normal result of aging coating

systems or they may be early indicators of improper

coating application.

All paint ﬁ lms are permeable to moisture to some

extent. Blistering occurs when the moisture at the ﬁ lm -

to - substrate interface builds up to the extent that pres-

sure is exerted and the coating – substrate interface

debonds. Water will always migrate through the paint

ﬁ lm driven by osmosis, and when the osmotic pressure

within the blister balances the coating adhesion around

the blister circumference, the blister will cease to grow.

Some blisters are associated with areas of corrosion,

which may start at coating holidays, whether these are

from the original coating process or due to mechanical

damage after the coating has set and aged. Most blisters

will show minimal corrosion beneath the blister due to

the high pH of the water that collects in the resulting

cavity. They should not be broken unnecessarily, because

this will remove the protective paint ﬁ lm and allow

more aggressive ﬂ uids to attack the underlying sub-

strate. When blisters occur late in the lifetime of a

coating, they are indications of imminent coating failure.

Figure 6.36 shows blisters on the below - ground

section of a pipeline vent riser. One of the blisters has

been broken to show the uncorroded steel underneath.

If the soil had remained undisturbed by a construction

project, the coating would have continued to provide

corrosion protection for many more years.

Figure 6.37 shows blisters forming near a scratch on

the exterior of a buried pipeline coating. Most of the

coating is undamaged, but blisters are forming parallel

to the scratch, and the coating would eventually debond

and fail. The black spots in the blistered area are where

the blisters have been broken to reveal discolored but

otherwise uncorroded steel.

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138 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION

Figure 6.34 Marine piling with aging coating showing typical aging features and patterns.

Checking

Blisters indicating

incipient failure

Lifting due to

corrosion

undercutting

Figure 6.35 Example of spot rusting pictures from ASTM Standard D 610.

49

Reproduced

with permission of ASTM International.

SPOT RUSTING

Rust Grade 3-S, 16% Rusted Rust Grade 3-G, 16% Rusted Rust Grade 3-P, 16% Rusted

Rust Grade 2-P, 33% RustedRust Grade 2-G, 33% RustedRust Grade 2-S, 33% Rusted

Rust Grade 1-S, 50% Rusted Rust Grade 1-G, 50% Rusted Rust Grade 1-P, 50% Rusted

GENERAL RUSTING PINPOINT RUSTING

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