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TRANSCRIPT
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
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)
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
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.
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.
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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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
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 7 of 26
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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
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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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
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.
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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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.
Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092
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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.
Document Responsibility: Paints and Coatings Standards Committee SAEP-H-092
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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