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Best Practice SABP-H-092 01 JUN 2017 Inspection and Root Cause Analysis of FBE External Coating Failures Document Responsibility: Coatings Standards Committee Primary contact: Mana Mansour Page 1 of 26 Copyright©Saudi Aramco 2017. All rights reserved. Saudi Aramco DeskTop Standards Table of Contents 1 Scope ................................................................... 2 2 Purpose ................................................................ 2 3 Definitions ............................................................ 2 4 References ........................................................... 4 5 Responsibilities ................................................... 6 6 Introduction ......................................................... 6 7 Field Investigation ............................................... 7 8 Lab Investigation ............................................... 12 9 Bibliography ...................................................... 15
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Page 1: Saudi Aramco Engineering Standard - otkrit1.comotkrit1.com/reports/coatings/FBE_failure_analysis_SABP.pdf · Saudi Aramco: Company General Use Previous Issue: 01 JUN 2017 Next Planned

Best Practice

SABP-H-092 01 JUN 2017

Inspection and Root Cause Analysis of FBE External Coating Failures

Document Responsibility: Coatings Standards Committee

Primary contact: Mana Mansour Page 1 of 26

Copyright©Saudi Aramco 2017. All rights reserved.

Saudi Aramco DeskTop Standards

Table of Contents

1 Scope ................................................................... 2

2 Purpose ................................................................ 2

3 Definitions ............................................................ 2

4 References ........................................................... 4

5 Responsibilities ................................................... 6

6 Introduction ......................................................... 6

7 Field Investigation ............................................... 7

8 Lab Investigation ............................................... 12

9 Bibliography ...................................................... 15

Page 2: Saudi Aramco Engineering Standard - otkrit1.comotkrit1.com/reports/coatings/FBE_failure_analysis_SABP.pdf · Saudi Aramco: Company General Use Previous Issue: 01 JUN 2017 Next Planned

Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

Issue Date: 01 JUN 2017 Shop Application of FBE to the External Surfaces of Line Pipes

Saudi Aramco: Company General Use

Previous Issue: 01 JUN 2017 Next Planned Update: 01 JUN 2020 Page 2 of 26

Primary contact: Mana Mansour

1 Scope

The scope of this document is FBE failures on externally coated buried pipelines.

Premature external FBE coating failures have been observed on buried Saudi Aramco

Oil and Gas transmission lines. A reasonable expectation of service life for FBE is

around 30 years, but failures within less than 10yrs of installation have been observed.

Given the inspection, remediation costs and in particular the safety impacts of

premature failures, a more structured and comprehensive approach towards field

investigations is felt warranted to better understand and prevent such occurrences in the

future. It is hoped that this best practice will detect chronic quality and contractor errors

that only a long term study of this nature is capable of exposing.

2 Purpose

The purpose of this document is to act as a guide to both field and lab personnel when

assessing the cause of external coating failures on FBE coated buried pipelines. It

details the methodology, accepted practices and decision making to be followed when

confronted with a coating failure or potential failure. This practice has been developed

with Coating, CP, Piping and Corrosion specialists to assist in correctly assigning the

mode of failure and most probable failure root cause and the most appropriate corrective

actions.

3 Definitions

CIPS Close-Interval Potential Survey. Used for detecting areas with low CP

potential

CNS Chlorides, Nitrates and Sulphates – the ‘usual’ anions that drive

corrosion.

CD Cathodic Disbondment. Coating delamination driven by excessive CP

current.

CP Cathodic Protection (impressed current or sacrificial anodes).

EDS Energy-Dispersive (X-ray) Spectroscopy or EDX. Used to determine

elements present.

DCVG Direct Current Voltage Gradient. Used for detecting coating defects and

anomalies.

DFT Dry Film Thickness of FBE film usually in microns (μm)

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

Issue Date: 01 JUN 2017 Shop Application of FBE to the External Surfaces of Line Pipes

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DJ Single pipes (12m) are commonly welded at the plant into a 24m length

called a ‘Double Joint’. The DJ weld is usually shop coated. Multiple

DJ’s are welded in the field to form a ‘Pipe String’.

DSC Differential Scanning Calorimetry. Used to determine Tg and % cure of a

resin.

ECDA External Corrosion Direct Assessment. Inspection methodology for

external pipeline corrosion.

EIS Electrochemical Impedance Spectroscopy – technique used to measure

film permeability and behaviour with respect to moisture penetration.

FBE Fusion Bonded Epoxy.

FJ Field Joint. Weld between 2 pipe strings. Compare with GW or DJ.

FTIR Fourier Transform Infrared Spectroscopy. Used to determine chemical

structure of organic materials.

GW Girth Weld. Another designation for Field Joint (FJ).

Holiday Exposed bare steel on a coated pipe (due to damage etc)

HSS Heat Shrink Sleeve. Commonly used on girth welds (Field Joints)

ID Internal Diameter – refers to location of coating on pipe.

ILI In-Line Inspection using intelligent internal scraper to detect pipe wall

thinning.

KM Kilometer. Usually refers to a location along the pipe. Eg; KM71.

MIC Microbiologically Influenced Corrosion.

MPN Most Probable Number. Measure of Bacteria Numbers.

qPCR Quantitive Polymerase chain reaction. Method to measure live and dead

bacteria numbers

ML Metal Loss. In the case of piping, the reduction in wall thickness.

OD Outer diameter of a pipe

Pipe String Pipeline, welded together in preparation for burial.

SEM Scanning Electron Microscope. Used for high magnification imaging and

analysis.

TGA Thermal Gravimetric Analysis. Alternate method for determining thermal

stability and chemical composition of compounds

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

Issue Date: 01 JUN 2017 Shop Application of FBE to the External Surfaces of Line Pipes

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TMA Thermo-Mechanical Analysis. Alternate method for determining Tg.

Tg Glass Transition Temperature. Transition point between rubber like and

solid like behaviour.

XRD X-ray diffraction. Method for determining crystallographic structure of

inorganic compounds (oxides, soil, etc)

XRF X-ray fluorescence. Method for determining elemental composition of

inorganic materials (soils, oxides, etc)

4 References

4.1 Saudi Aramco References

Saudi Aramco Engineering Standards

SAES-H-002 Internal and External Coatings for Steel Pipelines and

Piping

SAES-H-002V Approved Saudi Aramco Data Sheets for the Pipeline and

Piping Coatings

Saudi Aramco Materials System Specification

01-SAMSS-024 Pipe Handling and Nesting

09-SAMSS-089 Shop Applied External FBE for Steel Line Pipes

09-SAMSS-200 Storage, Handling and Installation of Externally Coated

Pipe

Saudi Aramco Inspection Requirements

Form 175-091300 Shop-Applied External FBE Coating

4.2 Industry Codes and Standards

American Society for Testing and Materials

ASTM D4417 Field Measurement of Surface Profile for Blast Cleaned

Pipe.

ASTM D4959-16 Determination of Water Content of Soil by Direct Heating

ASTM D5162-08 Discontinuity (Holiday) Testing of Nonconductive

Protective Coating on Metallic Substrates

ASTM G14 Test for Impact Resistance of Pipeline Coatings

ASTM G51 – 95 Measuring pH of Soil for Use in Corrosion Testing.

ASTM G57 – 06 Field Measurement of Soil Resistivity Using the Wenner

Four-Electrode Method.

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

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ASTM G162 Conducting and Evaluating Laboratory Corrosion Tests in

Soils.

ASTM G187-12A Measurement of Soil Resistivity Using the Two-Electrode

Soil Box Method.

ASTM G200-09 Measurement of Oxidation-Reduction Potential (ORP) of

Soil

ASTM G6677-01 Adhesion Testing

International Organization for Standardization

ISO 8502-3 Assessment of Dust on Steel Surfaces (pressure sensitive

tape method)

ISO 8502-9 Preparation of steel substrates before application of paints

and related products — Tests for the assessment of surface

cleanliness — Part 9: Field method for the conductometric

determination of water-soluble salts

The Society for Protective Coatings (SSPC)

SSPC PA 2 Measurement of Dry Coating Thickness with Magnetic

Gages.

Canadian Standards Association

CAN/CSA-Z245.20 External Fusion Bond Epoxy Coating for Steel Pipe.

NACE

NACE RP0394 Application, Performance, and Quality Control of Plant-

Applied Fusion Bonded Epoxy External Pipe Coating.

NACE SP0169 Control of External Corrosion on Underground or

Submerged Metallic Piping Systems

Miscellaeneous

DIN 50929-3 Metal corrosion; corrosion probability of metallic

materials with external exposure to corrosion; ducts and

structural elements in soils and water.

DMRB BD 42/00 Design of Embedded Retaining Walls and Bridge

Abutments

AWWA C105-10 Polyethylene Encasement for Ductile-Iron Pipe Systems.

DVGW GW 9 Evaluation of Soils In View Of Their Corrosion Behaviour

towards Buried Pipelines and Vessels of Non-Alloyed Iron

Materials.

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

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5 Responsibilities

Although not fixed, it is assumed that the responsibilities will be shared as follows;

Proponent – Usually the pipeline owner or operator.

Coating Inspector – Usually under the control of the proponent. Responsible for

collection of all related data and samples (coating, soil, Subkha, corrosion products) at

the failure site. The proponent may request assistance from Consulting Services, R&DC

or Inspection Department for this investigation.

Consulting Services Department (CSD) – To provide technical support upon request.

Technical Services Division (R&DC) – Responsible for performing the laboratory

investigation and interpretation of analytical results. TSD is part of the Research &

Development Center (R&DC). The R&DC report should be forwarded to the proponent

for further action.

Third Party Laboratories - proponent or CSD can engage approved third party labs to

carry out investigations/ testing as needed.

6 Introduction

This document is split into two parts; Field and Laboratory activities.

The Field part instructs the Coating Inspector on what to look for, what samples to

collect, how to collect and where to store them, how to identify them, where to send

them, what relevant history needs to accompany the collected samples and how to

complete the Failure Analysis Request.

The Laboratory part is intended to identify required samples and pertinent analytical

methods/tests. It dictates how to perform a comprehensive analytical investigation,

interpret analytical results and structure the report based on the input of both field and

laboratory (R&DC or third party lab). In the absence of an obvious cause, the

proponent, R&DC & CSD should meet to identify both a cause and corrective action.

The following tables are useful in executing this best practice.

Table 1. Guide for the Field Investigation ...................................................................... 17

Table 2. Common Failure Classifications ....................................................................... 19

Table 3. Guide for the Laboratory Investigation ............................................................. 21

Table 4. Guide for the Laboratory Technician ................................................................ 22

Table 5. Guide for the Coating Engineer ........................................................................ 25

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

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7 Field Investigation

The first step in conducting a failure investigation is to survey the location. Visual

ovservations provide important information, as does knowledge of the service and

history of the pipe. Other factors like the FBE film condition, performance of the CP

system, etc. are also vital. If such information is not recorded immediately, it will likely

be lost. Refer to Table 1 and Table 2 for guidance.

7.1 Installation and Operation

7.1.1 Provide pipeline name, exact KM location and Joint number of the

failure (GPS coordinates if possible).

7.1.2 Provide age of the pipe section.

7.1.3 Provide temperature of the transported media.

7.1.4 How long was the pipe stored above ground before burial and under

what conditions (covered, exposed).

7.1.5 Provide the pipe cover (depth of burial).

7.1.6 If the pipeline is scrapable, provide the %ML reported by the last three

ILI runs as available. Provide results from field verification

inspections (copies of inspection sheets).

7.1.7 All samples collected should be marked with the pipeline name, KM

location, pipe joint number, where the sample was collected (bottom,

top and side of the trench, etc.), date, collector’s name and contact

number. If pipe markings are still visible, copy those too.

7.2 Environment

7.2.1 Visual

7.2.1.1 Take macro shots of the whole site to give perspective to

integrity/corrosion engineers not familiar with the application

and environment.

7.2.1.2 Take medium range and close-up photos of the defected areas.

Also, ensure that the photographed area contains an object for

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

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scale such as a ruler, pen, etc. Record the joint number and

KM location in the field of view of the photograph.

7.2.1.3 Record mainline and girth weld coating color(s), the color and

condition of the corrosion products (reddish-brown, black,

white, dry/wet). Color change on exposure to air may aid in

identification.

7.2.1.4 Determine the o’clock position of the defect(s). Is it at the

girth weld? Along the pipe seam? Is the defect elongated in

direction of pipe or perpendicular? Is it on a field bent

section?

7.2.2 Soil

7.2.2.1 Describe the soil type (clay, silt, sandy, loam, humus, etc.).

Pay attention to the soil where the pipeline defect is.

7.2.2.2 Take a sample of soil (2 – 3 kg), associated with the coating

failure and place in an airtight glass jar or plastic container.

Exclude all air. Deliver to Lab within 48hrs.

7.2.2.3 Redox potentials should be measured at site.

7.2.2.4 Soil pH should be measured in the field (ASTM G51).

7.2.2.5 Take a sample of any free [ground] water into a clean

appropriate container (depending on intended test). Measure

pH of water with litmus paper/pH probe. Fill to brim to

minimize oxygen and send to the Lab.

7.2.2.6 Measure Soil resistivity using Wenner four probe

measurement method (ASTM G57) or by using a soil box with

the two probe measurement (ASTM G187 – 12a).

7.2.2.7 Take soil and water samples specifically for MIC

measurement. Only use sterilized bottles supplied by R&DC.

Make a note of any ‘rotten egg’ smell during excavation and

measure soil pH (ASTM G51)

7.2.2.8 Note the position of the water table with respect to the pipe.

7.2.2.9 Document if the soil is compacted, and is adjacent to areas of

disturbed earth (perhaps from a previous excavation). Oxygen

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Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092

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concentration cells may exist that can drive the corrosion of

the pipe in the undisturbed soil.

7.2.3 Cathodic Protection (CP)

7.2.3.1 Before large scale excavation, if possible, measure the

potential (using a Copper/ Copper sulphate electrode) at the

defected area.

7.2.3.2 Are there any physical obstacles that might have shielded the

defect area (e.g; boulders, rocks, stones, high resistance soils).

7.2.3.3 Document any stray DC/AC currents (from electrical sources

other than the CP system dedicated to the pipe). They may

originate from leaking earth currents from electricity pylons,

power substations, external CP systems, train earth returns,

etc. Tests are available to determine direction and strength of

stray currents.

7.2.3.4 Look for white calcacreous scales or deposits surrounding the

defect area or even underneath the FBE film. They may be

indicative of over-protection. Obtain samples of these white

deposits and send to Lab.

7.3 Pipe

Approximately 75% of all coating failures, are usually related to poor surface

preparation. Therefore the condition of the steel underlying the coating is

probably the most important evidence that you will investigate.

7.3.1 Underfilm1

7.3.1.1 If there are intact blisters, you must always attempt to sample

any liquid trapped underneath the film. Use a syringe to draw

the sample (minimum 50ml). It should be sent to a lab to be

analyzed for pH and anion concentrations (chloride, sulfates).

7.3.1.2 If syringe sample is not possible, still attempt to test any liquid

found underneath delaminated coatings using pH sensitive

1 By underfilm, we mean any items of interest between the steel and the film. However the physical film itself is addressed in the next section.

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litmus paper. If alkaline, this is a good sign that the CP system

is working correctly especially if the steel substrate is also

free of corrosion.

7.3.1.3 If possible, determine surface salt levels under both

delaminated and intact coatings using Bresle patch (ISO 8502-

9). Report salt level in mg/m2.

7.3.1.4 Note condition of pipe under coating failure. Is it corroded

(rusted) or free of corrosion? Does the corrosion mirror blister

locations or the opposite?

7.3.1.5 If possible, measure the blast profile with TESTEX tape

(ASTM D4417) and record result in microns.

7.3.1.6 Look for contamination like abrasive particles (might be

metallic or mineral) under a microscope or magnifying glass.

7.3.1.7 Look for grease and oil (ASTM D4285-83). I.e.; Wash surface

with solvent. Evaporate most of the solvent. Pour onto a glass

slide. Evaporate and look for the presence of an oily film,

which would be indicative of contamination.

7.3.1.8 Try a black (UV) light to see if hydrocarbon contamination

present (organic materials will fluoresce).

7.3.2 Corrosion Product

If the FBE is adherent and otherwise unaffected (apart from lifting at the

edges due to expansion of the corrosion reaction product), the corrosion

is likely due to localised mechanical damage at the time of installation.

7.3.2.1 Photograph the failure in-situ so that a complete record is

available to the proponent.

7.3.2.2 Scrape the corroded area and place corrosion products in an

airtight container. Record color, smell, is it wet or dry and

send for analysis.

7.3.2.3 Remove loose corrosion products with a wire brush and wipe

clean with a rag. Take photos of the exposed corroded surface.

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Look for shiny surfaces with steep walls (pit) or terrace

structures indicative of MIC action.

7.3.2.4 If practical, remove ALL corrosion (preferably with abrasive

blasting) and photograph again. Measure pit depth and shape.

This will help identify the defect on ILI scans and establish

corrosion rates.

7.4 FBE Coating

If the failed pipe coating is relatively intact it is called adhesion failure (cohesion

> adhesion). If the film can be only pried from the surface in chips, it is cohesive

failure (adhesion > cohesion). If it does not adhere and is brittle – it is an

adhesive/cohesive failure.

7.4.1 Appearance

7.4.1.1 Record mode of coating failure. More specifically, simple

delamination, blistering, chipping or disintegration. Note if the

film is brittle (fragments into pieces) or tough (fails by

delamination in sheets). If the coating flakes/chips, record the

size.

7.4.1.2 Record color of the coating. Note any difference between

sides.

7.4.1.3 Record any markings or stencils on the FBE.

7.4.1.4 Measure the DFT, particularly of blisters. The blistered area

might be abnormally thin compared to other locations (shorter

permeation time).

7.4.1.5 In the case of chalking, measure the DFT of the UV affected

area. Seek out areas protected by tape or slings. These will be

obviously glossy compared to the damaged area. Measure the

DFT. As epoxy loses thickness proportional to UV exposure,

it is possible to approximate the time exposed by comparing

with the non UV exposed area.

7.4.1.6 Also collect samples from ‘good’ areas of the same joint,

away from the defected area. These will be held for

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comparison with the failed material. Some coatings are no

longer manufactured, and these specimens may be the only

option left for control testing.

7.4.1.7 Report any coating scratches, gouges or cracks. Record their

common orientation, sizing or spacing. Photograph the defects

in detail.

7.4.1.8 Record presence and nature (color, wetness and size) of any

contamination or adhered corrosion products on the back of

the film.

7.4.1.9 Measure the adhesion of the film to the steel at two locations

(one close to the failure and another location, which represents

‘good’ adhesion). Pull-off test if possible or x-cut (ASTM

D6677).

7.4.1.10 Collect samples of the coating and store appropriately. If large

sheets, place between two stiff bits of cardboard and send to

Lab in an envelope. If it is curled up, use a cardboard tube. If

it fragments, send to Lab in a zip-lock bag. Note marking

requirements mentionedpreviously.

Refer to Table 5 in the Appendix and trace back the failure manifestations to a possible

underlying cause (or causes).

8 Lab Investigation

Refer to Table 3 and Table 4 for guidance on testing mentioned below.

8.1 Environment

8.1.1 If liquid was collected from underneath intact blisters, measure the pH

and conduct a chemical analysis. Alkaline pH indicates CP protection

active. High levels of CNS anions like nitrates, sulphates and chlorides

(NO32-, SO4

2+, Cl-) might indicate surface contamination. Unblistered

areas on the pipe should be simultaneously tested to confirm. If CNS

are absent, this might indicate a cure issue in the coating in that

chlorides have penetrated the film (unlike oxygen and water, anions

are usually too large to permeate through a properly functioning film).

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8.1.2 Perform XRD, XRF, MIC (qPCR) on soil and liquid samples collected

in the field.

8.1.3 Determine the soil % moisture content (ASTM D4959). Corrosivity

increases logarithmically above 60% mositure.

8.1.4 Measure the resistivity of received soil samples using a two-electrode

soil box (ASTM G187). Mix with distilled water such that the soil :

water ratio is in multiples of 5% (w/v) up to a maximum of 20% and

plot resistivity against w/v% water.

8.1.5 Execute a full geochemical water analysis (pH, conductivity, total

dissolved solids, etc.). Prepare a soil water mixture (w/v%) in the ratio

1:5. For example 100 g soil : 500ml distilled water. Agitate

ultrasonically for 3 hrs at 45°C with intermittent mixing. Allow to

settle for 24hrs and again agitate ultrasonically for 1hr at 45°C. Allow

to settle and when the water layer is clear, collect via syringe about

200mL for analysis. Sulphates acts as a food source for MIC. Chloride

is damaging to steel passivation layers. Nitrates contribute to the

overall TDS which is related to soil conductivity and hence corrosion

rate. The purpose of this step is to measure the corrosion rate

electrochemically of steel coupons of soil-water wash.

8.1.6 Using the above values and field derived redox value, assign a soil

corrosivity. Available methods are listed in the Standards Section.

Note this value is only relevant for uniform metal loss. If the

mechanism is pitting, then this value is not applicable.

8.1.7 Corrosivity information is of limited use in determining the FBE

failure mechanism, but it is useful in determining how long the

corrosion has been active (corrosion rate or CR), and can be used as a

proxy in determining when the FBE failed.

8.2 Pipe

The following methods in most cases cannot be conducted in the field. A section

or sample of the actual pipe has to be cut or removed for the lab. If this is done,

a control section (away from the defect) will also be required to act as a control.

8.2.1 Identify any surface contamination on non-corroded surfaces such as

metallic grit, non-metallic abrasive, dust, hydrocarbons, etc.). Use

SEM, XRD, XRF and optical microscope as necessary.

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8.2.2 Examine corroded pipe surfaces to determine the nature of the

corrosion products. Use SEM, XRD, optical microscope as necessary.

8.2.3 Conduct a cathodic disbondment test. This gives valuable information

about the quality and current state of the FBE film.

8.2.4 Run impedance spectroscopy (EIS) on or as close as possible to the

failed coating. This will tell you about the permeability of the coating.

8.2.5 Execute bend testing on a coated strip prepared as per NACE RP-0394

– Appendix H. This will confirm the flexibility of the film.

8.3 Coating

Usually, only stand-alone separate pieces of coating will be available for Lab

analysis.

8.3.1 Establish the Tg through DSC (CSA Z245-10) or TMA. The Tg is a

measure of cure and chemical properties. Note prolonged exposure to

moisture can also drop the Tg.

8.3.2 Measure the coating DFT (SSPC- PA2) using an electronic gauge or

micrometer. Excess coating thickness can often result in less flexible

behavior during installation. Insufficient coating is indicative of poor

quality control and offers less resistance to moisture permeation.

8.3.3 Inspect the backside of the coating under a microscope. Describe any

adhered corrosion products and debris. Check for abrasive particles,

dirt, grease, etc. Characterise contamination by SEM, XRD, etc.

8.3.4 Examine the coating cross section under the SEM. Determine the level

of porosity (CSA Z245-10). Look for striations (laminations)

indicative of inadequate inter-coat fusion. This may be deliberate (as

in Dual Layer FBE), or indicative of a coating layer applied outside of

its gel time.

8.3.5 Determine the % inorganic filler under the SEM (elemental mapping

technique). The percentage in the cross-section is related to the volume

%. Sometimes manufacturers will increase the inorganic filler at the

expense of the more expensive organic resin, degrading the flexibility

and permeability.

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8.3.6 Conduct FTIR of coating to establish chemical structure and match to

a particular manufacturer. The color alone may be sufficient if a

product database is available.

8.3.7 Establish the % cure through DSC analysis (CSA Z245-10). Both

undercure and overcure will affect coating flexibility and permeability.

8.3.8 Conduct tensile testing on the failed coating and control sample to

establish ductility and strength. The coating should be ductile and

strong. If it fails with small deformation, this indicates embrittlement.

8.3.9 Digest the failed coating and control sample, determine the elemental

composition (specifically chlorides). This is useful in contrasting with

elements detected on the steel (underneath the coating). Elements

detected on the steel, but NOT in the coating are evidence that they

were present before coating application (and did not simply migrate

there). If they did indeed migrate through the film, they would also

appear in the failed coating. The absence of these elements in the

control sample would be suggestive of a curing or compositional

failure in the defect sample.

8.3.10 Record any signs of UV degradation (chalking, loss of gloss,

decreased flexibility, fading, color difference between the front and

back of the coating).

9 Bibliography

a. Romanoff, Melvin, “Underground Corrosion”, NACE, Houston, TX, 1989.

b. Bayer G., Zamanzadeh Z., “Failure analysis of paints and coatings for

transmission & distribution pipeline and utility structures case studies”, Matco

Services Inc.

c. Bayer G., Zamanzadeh M., “Failure Analysis of Paints and Coatings”, Matco

Associates, Pittsburgh, AUG 3, 2004.

d. Papavinasam S., Attard M., Revie R, “External Polymeric Pipeline Coating Failure

Modes”, Materials Performance, OCT 2006.

e. Brossia S., “Final Report Dissecting Coating Disbondments - ENAUS 811”, DET

NORSKE VERITAS, 2010.

f. Norsworthy R, "Study examines coating compatibility with CP", Oil and Gas

Journal, Volume 107, Issue 20, May 2009.

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g. Khera A., James E. Marr J., Saleh Al-Sulaiman S., “System-wide ECDA application

advances integrity management”, Oil and Gas Journal, Volume 109, Issue 14, April

2011.

h. M. Zamanzadeh, “Fusion Bonded Epoxy Coatings (FBE) and Disbondment”,

CORROSION 2016, 6-10 March, Vancouver, British Columbia, Canada.

i. Zamanzadeh M., Taheri P., Mirshams R., “Cathodic Protection, Defective

Coatings, Corrosion Pitting, Stress Corrosion Cracking, Soil Corrosivity Mapping

and Corrosion Assessment in Aging Pipelines”, Corrosion Risk Management

Conference Houston, TX May 23-25, 2016.

j. Zee M, “Catasrophic Failure of Aging Underground Pipelines Is Inevitable Under

Certain Corrosion Conditions”, EXNOVA.

k. Appachalian Underground Corrosion Short Course (AUCSC)

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APPENDIX A

Table 1. Guide for the Field Investigation

# Stage Break-

down

Action Done?

1.

Sy

stem

His

tory

-

Physical Location of the coating Failure (GPS)

2. Age of Pipe Section (yrs)

3. Temperature of Pipe Media (C)

4. Storage Time (UV Exposure) in months

5.

Env

iro

nm

ent

Vis

ual

Take macro shots of pipeline

6. Take macro shots of coating defect

7. Describe defect location (is defect near spiral or seam weld, near girth

weld, under HSS, at bend?)

8. Describe nature of defect (orientation, depth, size, spacing, aspect ratio)

9.

So

il

Take a sample of soil in ziplock bag/palstic containre and send to Lab

10. Describe soil type (loamy, clay, rock, sand, limestone)

11. Describe the soil compaction around the defect compared to the

surrounding pipe.

12. Take a sample of ground-water in clean bottle and send to Lab

13. Measure pH of soil and water (litmus paper or pH tester)

14. Measure soil resistivity

15. Measure Redox potential

16. Record position of water table relative to defect location

17.

CP

Measure the local pipe potential before excavation, if possible

18. Measure the local pipe potential after excavation,

19. Describe any obstacles to CP current (large boulder/rock/stones/debries etc

in contact with pipe at the defect location)

20. Identify any sources of stray current (electrical substations, neighbouring

CP installations, HV transmission power lines etc)

21.

Pip

e

Und

erfi

lm

Extract liquid from any intact coating blisters, measure pH and send

sample to the lab

22. Note condition of steel underneath delaminated film (rusted, pristine)

23. Measure blast profile

24. Identify contamination on steel surface (abrasive, grease, oil, dust)

25. Determine salt levels using Bresle patch

26.

Corr

osi

on

Photograph defect as is. Describe nature and morphology of corrosion

27. Photograph defect after removal of loose corrosion product (wire brush)

28. Describe properties (color, wet/dry, smell) of the corrosion products

29. Collect corrosion products in plastic bag/container and send to lab

30. Describe appearance of exposed steel surface.

31. Photograph defect after removal of all corrosion (use grit blast)

32. Measure pit depths. Describe pit size, spacing, shallowness, elongation.

33.

FB

E

Coat

i

ng

Appe

aran

c

e

Document color of film

34. Describe film properties (brittle, fragments, flexible, tough)

35. Measure DFT at defect and adjacent areas

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36. Describe any Pipe markings/Stencils

37. Describe any scratches, gouges, impact marks on the coating.

38. Describe any contamination or adherent corrosion visible on backside of

the film.

39. Measure the adhesion of the FBE film.

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Table 2. Common Failure Classifications

# Failure Appearance Most Likely Cause Recommended Field

Tests

Recommended

Lab Testing

A.

Bli

ster

ing

A form of adhesion failure. Blistering during

application (caused by excessive

temperatures) needs to be differentiated

from blistering after exposure to soil or

immersion.

- Improperly cured coating are typically

permeable to moisture and salts which

may diffuse through and cause

bilstering.

- It can also occur due to

electroendosmosis (where an applied

electric current whether CP or stray

current) drives water molecules into the

film.

- If the pipe service is cold with respect to

the soil, then a ‘cold wall’ effect is

possible where water vapour condenses

against the steel, under the coating.

Surface contamination such as salt

accelerates the process.

Measure CP

potential and check

for overprotection

Conduct Bresle

Test of steel under

blister

Measure pH

underneath blisters

Measure DFT

DSC (check

cross-linking)

Identify coating

type (lab FTIR)

Blister water

test (look for

CNS levels)

B.

Del

amin

atio

n

A form of adhesion failure. Delamination

implies that the surface adhesion is very

poor and possibly that the film is retaining

some flexibility. That is cohesion >>

adhesion. Physical surface contamination is

the usual cause (blasting artifacts, oil,

grease, dust etc). Insufficent line application

temperature (affects fusion onto the steel)

may be a factor. Usually pull-off tests are

not conducted with FBE, as the FBE-to-steel

adhesion values >> than glue-to-FBE

adhesion values!

Use a knife and see

how much film can

be lifted off in one

piece.

Comment on any

hydrocarbon

contamination on

the steel.

Record condition

of steel (rust %,

profile, etc)

Perform SEM to

look for

abrasive

particles on the

underside of the

film. Eg; garnet,

metal grit, etc.

Determine

organic

contamination

C.

Em

bri

ttle

men

t

A form of cohesion failure. Embrittlement

can be due to;

- Contamination (hydocarbons, chemicals,

solvents)

- Low quality FBE raw materials

- UV damage

Embrittled coatings may be susceptible to

soil stress, osmotic pressure and may not

resist the penetration of moisture. The FBE

will tend to chip rather than bend and will

form small pieces. It will show very limited

flexibility when bent.

Use a knife and see

how much film can

be lifted off in one

piece.

Record condition

of steel (rust %,

profile, etc)

Perform DSC

(check for

undercure or

overcure)

Perform tensile

testing if

possible to

confirm loss in

ductility. A

bend speciment

to CSA245 is

ideal.

D.

Mec

han

ical

Dam

age

Mechanical damage (Scratches and gouges)

of the coating are obvious at the installation

stage. They may be caused by mechanical

contact during transport, thrustboring,

excavation, burial etc.

However the origin of the defect may be

obscured after time in service. Normally the

FBE is sound and well adhered with a

localized area of metal loss indicating an

initial breach that has expanded over time.

Elongated pitting parallel to the pipe axis is

relatively easy to trace back to scratches

likely from a thrust boring operation.

Evaluate condition

of surrounding

FBE (adhesion,

flexibility)

Note orientation,

depth and aspect

ratio of the metal

loss.

Measure depth of

any pitting.

N/A

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E.

Cra

ckin

g

Cracking is more likely to occur during

pipeline installation. Usually it is associated

with brittle coatings (see embrittlement

section above)

The cracks will likely be hairline and hard to

detect except by spark testing. Prolonged

weathering might cause corrosion product

seepage out of the cracks and then the cracks

become visible.

Use a knife and see

if the film can be

lifted away.

Perform spark test

to confirm

penetration of the

crack to the steel.

Cross section

through crack,

to measure

extent of

penetration.

Tensile testing

to evaluate film

flexibility

DSC, TGA and

FTIR analysis

to confirm FBE

specification

F.

Cat

hodic

Dis

bondm

ent

High CP current density at the coating

defect location can generate highly alkaline

conditions at the steel surface. These

alkaline condition may interfere with the

adhesion of the FBE (cathodic disbondment)

or even cause a chemical deterioration of the

FBE film. Such defects are usually circular

in nature and associated with prior holidays.

The underlying steel however may show

little corrosion due to the protective effects

of the CP and alkalinity.

Describe the size

and aspect ratio of

the defect. Is there

corrosion present?

Pitting?

Measure if

possible the pH

under any

disbonding film.

Measure the

current density

adjacent to the

defect using a

coupon

Analyze the

film with DSC.

Perform

SEM/EDX on

the back side of

the coating

G.

Str

ay C

urr

ent

Current from sources other than the

dedicated CP system (eg; HV transmission

power lines, electric trains, etc) can wreak

severe damage on pipelines. Generally the

damage is in the form of severe localized

pits, where the foreign current leaves the

pipeline, usually through a coating break.

Asses the exisiting

FBE condition and

adhesion.

Investigate for

stray currents.

N/A

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Table 3. Guide for the Laboratory Investigation

# Stage Action Done?

1.

Env

iro

nm

ent

Measure CNS levels of field received samples

2. Make extract from soil samples and perform full geo-chemical analysis

3. Perform microbial analysis on soil/water samples

4. Measure soil moisture content

5. Measure soil resistivity

6. Measure soil corrosion rate (electrochemical methods, weight loss). Document if any

pitting.

7.

Pip

e sa

mp

le

(if

po

ssib

le) Identify any substrate surface contamination or corrosion product using SEM, XRD

or optical microscope.

8. Conduct CD test on coated section

9. Conduct Impedance Spectroscopy (EIS) test on coated section

10.

Fil

m

Measure Film DFT

11. Inspect backside of film. Characterize any contamination or corrosion products

found.

12. Examine cross-section and comment on porosity and percent filler content. Look for

laminations or any unusual features.

13. Conduct FTIR on film

14. Establish % cure using DSC

15. Establish Tg (DSC or TMA)

16. Conduct tensile test and establish % elongation, yield and Ultimate stress

17. Digest film. Compare elements detected with elements found on surface underneath

adhered film. Comment on diffusion of said elements through film.

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Table 4. Guide for the Laboratory Technician

# Test Method F/L Test Used for

1.

Soil

Resistivity F/L ASTM G57/

ASTM G187

Low soil resistivity values means

increased corrosion rates. Not so relevant

for coating.

2. Moisture % F/L ASTM D4959 High soil moisture values means

increased corrosion rates. Not so relevant

for coating.

3. Chloride and

sulphate

L SP High levels might explain blistering as

compromised FBE may let these large

anions through. Also corrosion

accelerated as increased anions linked to

decreasing soil resistivity.

4. pH F /L ASTM G51 Acidic pH may cause faster metal loss

but doesn’t really impact functioning

FBE

5. MIC L SP High values means increased pitting

rates. Not so relevant for coating.

6. Redox

Potential

F ASTM G200 High values means increased corrosion

rates. Not so relevant for coating.

7. Soil Potential F ASTM G200 Can be used to assess CP protection

level. Underprotection only has

implications for corrosion and does not

affect the coating, whereas excess levels

can cause blistering and CD. Also used to

detect stray current.

8.

Pip

e

Bresle Test

(surface salt)

F ISO 8502-9 Used to determine pre-existing

contamination. Surface salt on the steel

draws in moisture through the film via

osmosis, leading to blistering.

9. Glass Slide

test

F SP Grease and oil on steel surface are

dissolved with hexane, and then

evaporated away from a glass slide. The

oily film retained is indicative of

hydrocarbon contamination. UV light

may also detect this.

10. Tape Test F ISO 8502-3 Tape applied to the steel surface will

collect any dust and this can be rated to

comment on plant cleanliness. Dust

affects film adhesion.

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11. Surface

Profile

F ASTM D4417 FBE bonds to steel mechanically, so a

minimum profile is needed.

12.

Coat

ed P

ipe

Bend Test L NACE RP-0394 Measure flexibility and ductilty of FBE.

13. CD test L ASTM G95 Measures the resistance of the FBE to

alkaline conditions associated with

overpotentials.

14. Blister Test F SP Fluid is extracted from a blister and

tested for pH and CNS. This tells us

about any CP protection present, and if

the steel was originally contaminated or

not.

15. Impedance

Spectroscopy

- EIS

L ISO 16773 Measure an increase in permeability of

the coating perhaps due to moisture

adsorption, undercure, exposure to

chemicals, etc.

16.

‘Fre

e’F

ilm

(L

ab)

DSC or TMA L ISO 11357 Used to determine Tg. Tg is an important

property linked to the cure of the coating

and moisture absorption.

17. Film digestion L SP Sometimes used to differentiate anions

that have diffused through the FBE,

rather than pre-exisiting anionic

contamination of the steel.

18. Tensile L ASTM D2370 Measure of film strength. Low strength

might indicate undercure. It is possible

for a film to be undercured, yet still

ductile and flexible. However it will fail

at low stress.

19. DFT L ASTM D6132,

ASTM D1005,

ASTM D4138

Low DFT application might lead to

reduced service life as the diffusion

barrier thickness is reduced.

20. Cross-section L SP Provides information on porosity and %

filler content

21. SEM / EDS L SP Used to identify surface contamination on

both pipe and coating underside.

22. XRD L SP Used for differentiating material like

garnet from sand, usually from film

underside. Analysis of corrosion

products.

23. Elongation % L SP Used to appraise flexibility of FBE film.

If low, indicates some sort of

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embrittlement, porosity or excessive filler

content

24. FTIR L SP Can detect inferior resin, reduced resin

levels or deleterious adulteration.

F = Field, L = Lab, SP = Standard Practice

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Table 5. Guide for the Coating Engineer

# Factors Factors Mode of Action Failure Manifestation Field Observation and

Testing

Lab Testing

1.

FB

E P

rodu

ct

Resin Quality Inferior or incorrect resin or wrong

proportions.

Underperformance. I.e.; earlier failure,

poorer resistance to moisture.

Expect to see under film

corrosion. Could possibly see

free water

FTIR of the coating should detect

deviation from standard formulation. Tg

will differ. Mechanical properties and

performance will suffer.

2. Filler Manufacturer increases percentage of filler (to

reduce cost) or uses wrong type

Underperformance. Embrittlement Flexibility will drop Cross-section using microscopic image

analysis – comparison with control.

FTIR and Tg of resin would not be

affected.

3. Storage Conditions (e.g.,

moisture content and/or

temperature too high).

Water will generate porosity in applied film. It

turns to steam at coating temperature.

Temperature (outside manufacturer

recommended storage temperature) will react

prematurely

Porosity in the film means increased

permeability to moisture, less

flexibility.

Prematurely reacted powder will give

poor quality coating

Expect to see under film

corrosion. More brittle

behaviour.

Bend (tensile) test will give lower

result

Cross-section using microscopic image

analsyis will show excessive porosity

4.

Su

rfac

e P

repar

atio

n

Cleanliness Grease/oil/dust/blast debris will prevent

adhesion of FBE and it will delaminate. Blast

debris may include abrasive material.

Sheet delamination Adhesion testing. Film still

relatively tough (lifts off in

one sheet and does not crack

or crumble). Visible

contamination of steel

Glass slide test for hydrocarbons. Optical

confirmation for abrasives. Tape test for

dust.

5. Surface Salts Hygroscopic salts can cause osmotic blistering

leading to delamination. Common Failure

Mode

blistering Bresle patch. Use a syringe

for suction of trapped

solution within the blister.

CNS testing for blister liquid

6. Profile Insufficient profile (μm). No Mechanical

bonding.

delamination Testex tape and tip

micometer.

FBE underside film roughness usually

mirrors steel profile

7.

App

lica

tion

Application temperature too low

or too aggressive quenching or

too fast a line speed.

Undercure (FBE doesn’t crosslink fully) Poor adhesion. Permeable to water.

Lower strength

Surface tends to be

abnormally glossy.

DSC will show undercure

Impedance Spectroscopy will show higher

permeability

8. Application temperature too

high, insufficient quenching or

too slow a line speed.

Overcure. Coating becomes brittle (excessive

cross-linking.

Embrittlement. Film fragments easily. Knife adhesion test shows

poor result.

DSC won’t show much change.

Bend testing and tensile testing and

microhardness will give lower values as

compared with control sample.

9.

Tra

nsp

ort

/

Bu

rial

Excessive UV exposure (beyond

6 months)

Breakdown of coating. Loss in flexibility. Embrittlement Chalking Tensile testing of the film. Bend test if

possible

10. Chemical exposure Oils, fats, solvents, chemicals, hydrocarbons or

even condensation over long period of time.

Film destruction and permeation Discoloration and film

underperformance.

Test Tg, permeability, impedance

spectrscopy.

11. Mechanical damage (transport /

burial)

Holiday. Under film corrosion Heavy localized corrosion despite intact

film surrounding defect.

Visual. Observation of

surrounding defects.

N/A

12.

Op

erat

ion

(En

vir

on

men

t)

high chlorides, sulphates/Subkha Salt may permeate through film and accelerate

corrosion

Blistering and /or delamination of FBE N/A Soil box. Cl, SO4 and TDS test. CNS test

of blister fluid. Film digestion and

analysis.

13. High MIC activity Excessive pitting of the steel Does not affect FBE film normally Record Pit appearance and

smell

qPCR

14. Cold Wall Effect Cold pipe media can encourage condensation

of vapour on underside of film

Delamination and loss of adhesion.

Blistering.

Process history. Supported by absence of CNS under FBE

film (not prime cause)

15. CP. Overrprotection will not Overprotection (Instant Off potential is more Coating holiday, cathodic disbondment pH of soil/water is high. Pipe- pH of soil/water extract

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affect film. negative than -1.2V or current density of bare

steel is greater than 30 mA/m2) generates

locally high concentration of hydroxyl ions

and calcareous deposit to-Soil potential measurement

and current density

16. Stray current Uncontrolled CP systems, HV power lines, DC

trains etc. can cause serious pitting at a coating

holiday due to current discharge.

Neat hole in FBE and unusually deep

pitting in the steel with no corrosion

products. Surrounding FBE usually in

good condition.

Interference survey, record

appearance of corrosion pits

after excavation

N/A


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