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Downstream Manufacturing Restricted

DBAM Code and Name:

MAN.15.10 Provide Asset Availability – Ensure

Assessment and Mitigation Planning for

Corrosion Under Insulation andExternal Chloride Stress Corrosion Cracking

Document Number

DSM-1510002-SP-20 Equipment Integrity

Shell Downstream Manufacturing

Assessment and Mitigation Planning forCorrosion Under Insulation and

External Chloride Stress Corrosion Cracking

Table of Contents

1. General ......................................2 1.1 Scope ........................................... 2 1.2 Purpose ........................................ 2 1.3 Overview....................................... 2 1.4 Deviations..................................... 2 1.5 Tools............................................. 3 1.6 Definitions..................................... 3

2. Assessment ..............................4 2.1

General......................................... 4

2.2 Prioritising Units ........................... 5 2.3 Developing the Equipment and

Piping List ..................................... 5 2.4 Challenging the Need for

Insulation...................................... 5 2.5 Performing an Initial External

Visual Inspection .......................... 5

2.6 Determining the Probability ofOccurrence of CUI and ECSCC... 6

2.7 Estimating the PotentialConsequence of a Failure............ 6

2.8 Determining the InspectionStrategy ........................................ 7

3. Mitigation Planning.................. 8 3.1 Development ................................ 8 3.2 Additional Considerations ............ 8

Appendix 1 – Example InsulationSystem Checklist ................... 18

Appendix 2 – Technical Basis ...... 19

Appendix 3 – Risk Assessment

Example .................................. 27

Version: 1.0 Date: January 2007 Custodian: DME/4 ECCN: EAR99 Page: 1 of 28

Printed _______________ Printed copies are uncontrolled

Printed copy should not be used more than 1 month after printed date

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DBAM Code and Name:

MAN.15.10 Provide Asset Availability – EnsureEquipment Integrity



Document Number

DSM-1510002-SP-20

1. General

1.1 Scope

1. This Downstream Manufacturing (DSM) Specification (SP) provides requirements and

supporting elements for the assessment and mitigation planning for corrosion under

insulation (CUI) of carbon and low alloy steels and external chloride stress corrosion

cracking (ECSCC) of austenitic stainless steel.

2. Duplex stainless steels and high alloys are excluded from this Specification. A

knowledgeable materials and corrosion engineer should be consulted for requirements

for these materials.

1.2 Purpose

1. This SP provides sites with a risk-based assessment and mitigation planning

methodology for CUI and ECSCC based on operating conditions, installation design and

current condition.

2. Implementation of this SP provides sites with an understanding of the equipment and

piping susceptible to CUI and ECSCC and an equipment and piping list prioritised by

both the likelihood of deterioration occurring and the estimated potential consequences

should a pressure boundary breach occur.

3. This SP describes the risks consistent with the March 2006 edition of the Group Risk

Assessment Matrix.

4. This SP summarizes the technical issues to consider in the management of these

mechanisms.

1.3 Overview

The approach employed by this document assesses the risk of CUI and ECSCC by a

combination of the current condition of the equipment or piping, the original equipment

specifications and accurate operating conditions. A graphical representation of the

management program for CUI or ECSCC is shown in the first row “Prioritisation and

Inspection Strategy Determination” of Figure 1, Overview: Management of Corrosion Under

Insulation for Carbon/Low Alloy Steel, and Figure 2, Overview: Management of External

Chloride Stress Corrosion Cracking for Austenitic Stainless Steel.

1.4 Deviations

1. The requirements in this SP are based on expert knowledge and field experience.

Individual sites should rarely need to adopt more or less stringent requirements.

2. Deviations from the requirements in this SP shall use Deviation Request Form

DSM-0515001-TO-12, which shall be kept in a log for technical assurance auditing.




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3. Deviations from the recommendations in this SP may occasionally be necessary due to

specific local requirements.

4. Deviations from the recommendations in this SP should also be logged and provided tothe technical community and the Equipment Integrity (EI) Global Process Owner (GPO)

for review and use in the continuous improvement of this specification.

1.5 Tools

1. This SP uses a semi-quantitative method to assess CUI and ECSCC risks. More

quantitative, computerized risk assessment tools may be employed provided the results

using those methods are consistent with this Specification. Computerized tools shall be

endorsed for use for CUI and ECSCC by the EI GPO.

2. With computerized risk based inspection (RBI), the CUI/ECSCC assessment can be

performed at the individual equipment or piping level or it may be more efficient to

group piping and equipment and analyse them together. Groups of equipment and pipingwith the same service that cannot be isolated individually and are in similar condition

may be good candidates for grouping. Groups of equipment can include a corrosion loop

or a long line of piping in a piperack.

1.6 Definitions

1. Corrosion under insulation (CUI) – Aqueous corrosion of carbon and low alloy steels.

The resulting corrosion pattern is of generally uniform morphology. CUI does not

include external chloride stress corrosion cracking.

2. Cladding – Insulation covering; usually aluminium sheet, but can be stainless steel,

galvanised carbon steel, or UV-cured fibreglass.

3. Criticality – A combination of the probability of failure and the consequence of the

failure (another term for long-term average risk)

4. Deadleg – Components of a piping system that normally have no significant flow.

Examples include blanked branches, lines with normally closed block valves, lines with

one end blanked, pressurized dummy support legs, stagnant control valve bypass piping,

spare pump piping, level bridles, relief valve inlet and outlet header piping, pump trim

bypass lines, vents, drains, bleeders, sample points and instrument connections.

Note: Deadlegs and attachments that protrude from insulated piping can operate at a

much different temperature than the operating temperature of the active line. This

temperature difference is important in determining items in a CUI program.

5. External chloride stress corrosion cracking (ECSCC) – stress corrosion cracking of

austenitic alloys containing less than 32% nickel initiating on the external (non-processcontacting) surface. Refers to austenitic stainless steel in this SP unless duplex stainless

steel or high nickel alloy specifically detailed. In addition to chloride, can also include

other halides (fluoride and bromides) in the environment.

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6. Inspection Strategy (IS) – Plan for inspection and maintenance of equipment items

susceptible to CUI. An IS:

a. Is developed from probability and consequence assessment.

b. Includes visual and NDE inspections, potential repair/replacement plans for metal

loss; repair/replacement plans for coating and insulation systems.

c. Includes re-assessment needs for future inspection.

7. Linework – Piping or piping system

8. Plant – All the units at an entire location (e.g. Berre, Geismar, Stanlow, etc.). Also

referred to as a "site".

9. Process unit – Section of a site that manufactures a product. For example, the "IPA"

process unit uses propylene as a feedstock and produces isopropyl alcohol. Also referred

to simply as a "unit" or “factory”.

10. RBI – Risk Based Inspection

11. Site – All the units at an entire location (e.g. Berre, Geismar, Stanlow, etc.). Also

referred to as a "plant".

12. Stainless steel – Austenitic stainless steel, unless specified otherwise in this SP. This

term does not apply to duplex stainless steels or nickel alloys.

13. Susceptible areas – Areas on equipment or piping that are more vulnerable than other

areas because they retain moisture or because they are points of water ingress. See

Appendix 2, Technical Basis, for a description of some common locations on equipment

that are more susceptible to CUI.

14. Tag number – Equipment number or piping system number.

15. Unit –Section of a site that manufactures a product, also referred to as a "process unit" or“factory”. For example, the "IPA" unit uses propylene as a feedstock and produces

isopropyl alcohol.

16. UV – Ultraviolet light

17. VCE - Vapour cloud explosion

18. VIR – Value Investment Ratio

2. Assessment

2.1 General

1. This section describes how to perform a site assessment for CUI and/or ECSCC and

includes how to prioritise the units to be assessed, how to prioritise the equipment and

piping within each unit and how to determine which inspection strategy to apply to the

equipment and piping. These steps are outlined in the first row “Prioritisation and

Inspection Strategy Determination” of Figure 1, Overview: Management of Corrosion




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Under Insulation for Carbon/Low Alloy Steel, and Figure 2, Overview: Management of

External Chloride Stress Corrosion Cracking for Austenitic Stainless Steel.

2.2 Prioritising Units

Sites may elect to assess CUI and ECSCC risks across the entire site as a whole or unit-by-

unit with the priority of unit assessment based on the type of hydrocarbon each unit processes

(e.g. a unit processing ethylene would have a higher priority than a unit processing residue).

The decision on how to assess should be based on the effectiveness and efficiency of

application of each method.

2.3 Developing the Equipment and Piping List

1. A complete list of equipment and piping systems with their corresponding historical,

installation, and process condition data shall be developed for the equipment and pipingin each unit being assessed.

2. This equipment and piping is analysed and a risk-based inspection strategy determined

through the process described in the remainder of Section 2. This process may be

performed at the individual equipment or piping level or it may be more efficient to

group piping and equipment and analyse them together. Groups of equipment and piping

with the same service, in similar condition and that cannot be isolated individually may

be good candidates for grouping. Groups of equipment can include a corrosion loop or a

long line of piping in a piperack.

2.4 Challenging the Need for Insulation

After the equipment and piping list has been developed but prior to starting the determinationof the inspection strategy, the need for insulation should be verified. Sites should use the flow

scheme of Figure 3, Challenging the Need for Insulation (and part two in Figure 4) to

determine whether or not insulation is actually required and if a detailed Risk-Based

Inspection (RBI) analysis is necessary.

2.5 Performing an Initial External Visual Inspection

1. After the equipment and piping list has been generated, an initial external visual

inspection shall be conducted to assess the condition of the insulation system and

exposed areas of the coating.

2. Personnel experienced with inspection of CUI and ECSCC should participate in this

inspection.

3. The condition of the insulation and data necessary to determine the probability of CUI

and/or ECSCC shall be collected and documented.

1. Refer to Appendix 1, Example Insulation System Checklist.




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4. Sites may use the results of the latest documented external visual inspection to serve this

purpose if the quality, relevancy, time the inspection data was performed provides

adequate information to determine the probability as outlined Section 2.7.

5. For additional insight into CUI and ECSCC, refer to Appendix 2, Technical Basis.

2.6 Determining the Probability of Occurrence of CUI and ECSCC

1. After the initial external visual inspection is completed, the probability of CUI/ECSCC

shall be determined.

2. Several factors affect this probability, including operating temperature, insulation type

and condition, coating type and condition, and age of the coating system.

3. Personnel experienced with CUI and/or ECSCC and personnel experienced with the

equipment history should be involved in determining the probability of occurrence. The

same experienced individual who participated in the external visual inspection should participate in the probability determination.

4. Probability of occurrence shall be quantified using Table 1, Probability Assessment for

CUI of Carbon/Low Alloy Steel or Table 3, Probability Assessment for ECSCC of

Austenitic Stainless Steel.

a. Each probability factor heads a column in the tables.

b. Move down the column to the description that matches that of the condition of the

equipment or piping being evaluated.

c. Move across to the Points column on the right to determine the number of points for

that probability factor.

d. Repeat this procedure for each factor in the table.

e. Add all the points to determine the Probability Point Total.

Note: Wall thickness considerations are not included in the probability assessment table

for carbon/low alloy steel, but appreciate that the less wall loss can be tolerated, the

more probable a CUI failure will be at a specified corrosion rate.

2.7 Estimating the Potential Consequence of a Failure

1. After the equipment and piping list has been generated, the consequence of a potential

failure shall be determined. The first step is to determine the failure mode:

a. For CUI, the potential failure mode is a ½ inch (12.5 mm) hole throughout the

evaluation. Although smaller and larger hole sizes are possible, using a consistent

hole size that encompasses the vast majority of expected failures, ensures that theconsequences of failure are based on the process conditions and not arbitrary

variations in the hole size.

b. For ECSCC, the potential failure mode is a “weeping” leak through a fine network

of cracks. Global industry experience has shown that a hole as a potential failure

mode is not practical and, since stainless steel exhibits a high level of fracture

toughness, a collapse failure mode is extremely rare.




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2. With the equipment and piping list and the potential failure mode identified, an estimate

of the duration of a leak and the quantity that would be released shall be developed and

the consequence of such a potential failure estimated.

a. Health, Safety & Environmental and Financial consequences shall be determined

individually with the highest consequence level governing.

b. Personnel experienced in hazard evaluations should be consulted to validate the

assigned Health & Safety and Environmental consequences.

c. Where they exist, a similar unit in another Manufacturing location shall be

benchmarked to validate the consequences established with discrepancies resolved.

d. Personnel experienced in the assessment of operational and financial impacts should

provide input in to the Financial consequence determination.

i. Both equipment damage and lost production should be analysed.

ii. The cost of repairs should not be included in the analysis unless total equipment

replacement is determined to be the only feasible repair.

Note: For ECSCC, asset availability (economic consequences) most likely is the

governing scenario for most services due to the potential size of the leak (“weeping”

through a fine network of cracks). However, in some services, a weeping leak may result

in HSE consequences. Due to the latter situation, the potential HSE consequence of

leaks should also be determined.

2.8 Determining the Inspection Strategy

1. With the Probability Point Total and the consequence of a potential failure determined,

the inspection strategy shall be determined using Table 2, Strategy Matrix for CUI of

Carbon/Low Alloy Steel for CUI and Table 4, Strategy Matrix for ECSCC of AusteniticStainless Steel for ECSCC.

2. To determine the Inspection Strategy,

a. Determine the Probability (A, B, C, or D) from the Probability Point Total

determined in section 2.7.

b. Move across this row until it intersects with the column corresponding to the

consequence level determined in Section 2.7.

c. The box at the intersection indicates the Inspection Strategy.

3. See Appendix 3, Risk Assessment Example, for an example of how the consequence, the

probability and the inspection strategy were determined for a natural gas line.




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3. Mitigation Planning

3.1 Development

1. The mitigation plan should include a detailed, quarter-by-quarter schedule to mitigate the

risks identified during the assessment to As Low As Reasonably Practicable (ALARP)

and a cost estimate of sufficient quality to submit for T&R funding.

2. For CUI estimating, the following initial inspection coverages should be used:

a. IS-1 Delag 100% of susceptible areas followed by visual inspection & restoration

b. IS-2 Delag 50% of susceptible areas followed by a visual inspection & restoration

c. IS-3 Delag 50% of susceptible areas followed by a visual inspection & restoration

d. IS-4 No initial inspection. Reassessment interval to be assigned.

3. In the planning stages for CUI IS-1 inspection strategies, due to the number of

susceptible areas on a typical piece of equipment, the scaffolding necessary to access allthese areas, the potential consequences of a leak, the overall condition of the installation,

the insidious nature of CUI and the probability of finding deterioration that will cause the

inspection to be expanded, plan to entirely strip the equipment or piping for this strategy.

4. For ECSCC estimating, the initial inspection coverage for IS-1 thru IS-4 should be

assumed to be delagging of all susceptible areas and other accessible areas, visual and

eddy current inspection, followed by recoating and reinsulating. For IS-5, no initial

inspection is required as a reassessment interval will be assigned.

5. Inspection strategies are based on the risk of CUI or ECSCC resulting in the items that

have been ranked as IS-1 having a higher risk than items ranked IS-2, IS-2 higher than

IS-3, etc. Therefore, IS-1 ranked items should generally be planned to be completed

before IS-2 ranked items, IS-2 before IS-3.

6. The justification for mitigating financially driven impacts shall include a VIR analysis.

3.2 Additional Considerations

1. If removing lagging during unit operation could compromise process stability,

consideration should be given to delagging in smaller sections to allow progress to be

made without waiting until the next turnaround or outage.

2. As explained in Appendix 2, Technical Basis, areas particularly susceptible to water

ingress and/or water accumulation such as external stiffener rings or insulation support

rings have the highest inspection priority.

3. Consider equipment components and pipework inside of vessel skirts (not stacked vessel

skirts) and not operating below dew point as being inside buildings and not susceptible toCUI unless other problem conditions (steam tracing, etc.) exist.

4. Equipment with insulating paint should not be considered susceptible to CUI or ECSCC

unless excessive rust bloom or other conditions exist that indicate deterioration is

occurring.




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5. Equipment that uses personnel protection cages (as a replacement for insulation) is not

susceptible to CUI or ECSCC and therefore does not fall under the CUI/ECSCC

program.

6. Equipment that uses permanent removable insulation blankets is susceptible to CUI or

ECSCC and shall be included in the assessment.

7. Sites should consider inspecting and mitigating lower and higher ranked items together

where practical to increase efficiency and lower costs (e.g. RAM 4 and RAM 3

consequence piping laying side-by-side in a piperack).

8. Sites may elect to mitigate CUI and ECSCC risks unit-by-unit with the priority of the

units based on the type of hydrocarbon each unit processes (e.g. a unit processing

ethylene would have a higher priority than a unit processing residue).

a. This type of mitigation program is acceptable provided the first phase of mitigation

targets the highest risk items (IS-1s) across the site.

b. Mitigation of lower risk items (IS-2s, etc.) would then follow in the subsequent phases.

c. Mitigation of a lower risk item (e.g. an IS-2) during a higher risk phase of mitigation

should be by exception and only when significant benefit can be demonstrated (e.g.

significant cost savings, etc.).




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Downstream Manufacturing

DBAM Code and Name: Assessment and Mitigation Planning for



Version: 1.0 Date: January 2007 Custodian: DME/4

Figure 1 – Overview: Management of Corrosion Under Insulation for Carbon



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DBAM Code and Name: Assessment and Mitigation Planning for



Version: 1.0 Date: January 2007 Custodian: DME/4

Figure 2 – Overview: Management of External Chloride Stress Corrosion Cracking for



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Figure 3 –Challenging the Need For Insulation – Part 1




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Figure 4 – Challenging the Need For Insulation – Part 2




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Table 1 – Probability Assessment for CUI of Carbon/Low Alloy Steel

Operating

Temperature

Coating Status

when new orlast applied

Cladding/

InsulationCondition

Insulation type Heat

tracing

External environment Points

Constantly

<−5°C or >175°C

<25ºF or >350ºF

REMOVE FROMCUI PROGRAM

Full QA coating

≤ 8 years sinceapplication

or

TSA < 15 years

Good toEngineeringStandards ornew/renewed(<5 years in

age)

Regularinspection andmaintenance

(every 5 years)

Not present Inside building, notsteam traced and not

sweatingREMOVE FROM CUI

PROGRAM

0

150ºC - 175°C

300ºF - 350ºF

Full QA coating8-15 years in

age orconventional

coating ≤ 8years sinceapplication

orTSA 15-30 years

Averagecondition,

overall highintegrity design& construction,tight inspection

ports

ExpandedPerlite,

Foamglass,Closed-Cell

Foam

Highintegritydesign

(steam) orelectrical

Arid or in-land

<500mm/yr [<20”/yr]rain

Low wetting rate(<20% of the time)

1

−5ºC - 49°C26ºF - 119ºF

OR111ºC - 149°C

226ºF - 299ºF

Conventionalcoating 8-15years in age

Averagecondition,

conventionaldesign andconstruction

Fibreglass, Asbestos,

Regular Perlite,Mineral/Rock

Wool (<10ppmCl)

Mediumintegritydesign(steam)

Moderate climate

500-1000mm/yr rain

[20-40”/yr] rainMedium wetting rate

(20 - 50% of the time)

3

50°C - 110°C120ºF - 225ºF

orcycling/sweating

conditions

Full QA orconventional

coating:> 15 years in

ageor

TSA > 30 yearsor

unpainted orunknown

Poor condition,damaged/wet/broken

seals

Cal Sil,Rockwool (no

spec),unknown

Lowintegrity

design orleaking(steam)

Coastal & marine

>1000mm/yr [>40”/yr]rain

High wetting rate(>50% of the time)

(e.g. coolingtower/deluge systems)

5

Notes:

(a) This probability table applies to equipment operating outdoors and in the temperature range of -5°C to 175°C [25°F to

350°F].

(b) Dead legs on equipment or piping operating outside of the CUI range must also be considered, as they will likely

operate in the CUI range at some location. For example, a long dead leg on a 230 °C [450°F] line could easily be in

the

50 – 110 °C [120°F - 225°F] metal temperature range for high probability of CUI.

(c) In case of cyclic service (or regular temperature changes), the range corresponding to the most critical temperature

reached shall be taken.




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Table 2 –Strategy Matrix for CUI of Carbon/Low Alloy Steel

Probability

Point Total

Inspection Strategy (IS)

D (> 20) IS-4 IS-3 IS-2 IS-1 IS-1

C (17 – 20) IS-4 IS-4 IS-3 IS-2 IS-1

B (11 - 16) IS-4 IS-4 IS-4 IS-3 IS-2

P r o b a b i l i t y

A (1 - 10) IS-4 IS-4 IS-4 IS-4 IS-3

Priority 1 2 3 4 5

Asset Damage &ConsequentialBusiness Loss

No/Slightdamage

<10k USDNo Disruption to

Operation

Minor damage10k -100k USD

Brief Disruption toOperation

Moderatedamage

100k -1M USDPartial Shutdown

Major damage 1M -10M USD

Up to two weeksshutdown

Massive damage>10M USD

Substantial ortotal loss ofoperation

Harm to People No/Slight injuryor health effect

Not affecting workperformance or

daily life activities.(First Aid caseand medical

treatment case.Exposure to

health hazardsthat give rise to

noticeablediscomfort, minor

irritation ortransient effectsreversible after

exposure stops.)

Minor injury orhealth effect

Affecting workperformance,

such as restrictionto work activities

or need to take upto 5 days to fully

recover.(Restricted or lost

workday casesresulting in up to5 calendar daysaway from work.Illness such asskin irritation.)

Major injury orhealth effect

Affecting workperformance inthe longer term,such as absence

from work formore than 5 days,affecting daily lifeactivities for more

than 5 days orirreversible

damage to health.(Long-termdisabilities.

Illnesses such assensitisation.)

Permanent totaldisability or up

to three fatalities (Illnesses such ascorrosive burns or

cancer.)

More than 3fatalities

(Cancer to a largeexposed

population. Majorfire or explosionresulting in morethan 3 fatalities.)

C o n s e q u e n c e o f F a i l u r e f o r

I n d i v i d u a l E q

u i p m e n t a n d P i p i n g

Environmental

Effect

No/Slight Effect

Slightenvironmental

damagecontained with thepremises. (Smallspill in process

area or tank farmarea that readily

evaporates.)

Minor Effect

Minorenvironmentaldamage but nolasting effect.

(Small spill off-sitethat seeps in theground. On-site

groundwatercontamination.

Complaints fromup to 10

individuals. Singleexceedance of

statutory or otherprescribed limit.)

Moderate Effect

Limitedenvironmental

damage that willpersist or requirecleaning up. (Spill

from a pipelinerequiring removaland disposal of alarge quantity of

sand/soil.Observed off-site

effects ordamage. Off-site

groundwatercontamination.)

Major Effect

Severeenvironmental

damage that willrequire extensive

measures torestore beneficial

uses of theenvironment. (Oilspill at a jetty thatends up on local

beaches requiringclean-up. Off-site

groundwatercontamination

over an extensivearea. Extendedexceedances of

statutory or otherprescribed limits

with potentiallong-term effects.)

Massive Effect

Persistent severeenvironmental

damage that willlead to loss ofcommercial,

recreational useof loss of naturalresources over awide area. (Crude

oil spillageresulting in

pollution of a largepart of a riverestuary and

extensive clean-up and

remediationmeasures.)




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Table 3 – Probability Assessment for ECSCC of Austenitic Stainless Steel

Operating

Temperature

Shop coating

or Al-wrapStatus & Age

Cladding/

InsulationCondition

Insulation type Heat tracing External

environment

Points

Constantly>175°C or <50°C

>350°F or <120°F

REMOVE FROMECSCC

PROGRAM

Shop Coating(full QA) < 8

yrsOr

Al-wrap*< 15 years

Good toEngineeringStandards

(undamaged)

RegularInspection/

Maintenanceevery 5-years

Regularinspection andMaintenance

(every 5 years)

Not present Inside building,not steam tracedand not sweatingREMOVE FROM

ECSCCPROGRAM

0

Shop coating(full QA) 8 -

15 yrsOr

Maintenance

Coating <8yrsOr

Al-wrap* 15-20 yrs

Averagecondition, butwith specialprecautions

taken at

susceptibleareas (c)

ExpandedPerlite,

Foamglass,Closed-Cell

Foam

High integritydesign

(steam) orelectrical (Cl-

free

insulation)

Arid or in-land

<500mm/yr[<20”/yr] rain

Low wetting rate

(< 20 % of thetime)

1

Shop coating> 12 yrs

OrMaintenancecoating > 8

yrsOr

Al-wrap* > 20yrs

Averagecondition, no

specialprecautions

taken atsusceptibleareas (c)

Fibreglass, Asbestos,

Regular Perlite,Mineral/Rock

Wool(low Chlorides

<10ppm)

Mediumintegritydesign(steam)

Moderateclimate

500-1000mm/yrrain

[20-40”/yr] rainMedium wetting

rate(20 – 50 % of the

time)

3

50 - 175 °C

120 - 350°For cycling/sweating

conditions (b)

Shop coating> 15 yrs

OrMaintenancecoating > 12

yrsOr

unknown

Poor condition,severely

damaged, wetOr

unknown

Mineral/RockWool

(no Chloridesspec),Cal Sil

Lowintegrity

design orleaking

(steam) orelectrical

(PVCinsulation)

Coastal &marine

>1000mm/yr[>40”/yr] rain

High wetting rate(> 50 % of the

time) or exposedto cooling

tower/delugesystems

5

Notes:

(a) Dead legs should be treated same as main pipe, except that temperature should be estimated, since the dead leg will

be much cooler, especially if long. For example, a dead leg on a 230°C (450°F) line could easily be in the 50-175°C

(120-350°F) metal temperature range for high probability.

(b) In case of cyclic service (or temporarily temperature changes), the range corresponding to the most critical

temperature reached shall be taken.




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Table 4 –Strategy Matrix for ECSCC of Austenitic Stainless Steel

Probability

Point Total

Inspection Strategy (IS)

D > 20 IS-5 IS-4 IS-3 IS-2 IS-1

C (15 - 19) IS-5 IS-5 IS-4 IS-3 IS-2

B (10 - 14) IS-5 IS-5 IS-5 IS-4 IS-3

P r o b a b i l i t y

A (< 10) IS-5 IS-5 IS-5 IS-5 IS-4

Priority 1 2 3 4 5

Asset Damage &ConsequentialBusiness Loss

No/Slightdamage

<10k USDNo Disruption to

Operation

Minor damage10k -100k USD

Brief Disruption toOperation

Moderate

damage100k -1M USD

Partial Shutdown

Major damage 1M -10M USD

Up to two weeksshutdown

Massive damage>10M USD

Substantial ortotal loss ofoperation

Harm to People No/Slight injuryor health effect

Not affecting workperformance or

daily life activities.(First Aid caseand medical

treatment case.Exposure to

health hazardsthat give rise to

noticeablediscomfort, minor

irritation ortransient effectsreversible after

exposure stops.)

Minor injury orhealth effect

Affecting workperformance,

such as restrictionto work activities

or need to take upto 5 days to fully

recover.(Restricted or lost

workday casesresulting in up to 5

calendar daysaway from work.Illness such asskin irritation.)

Major injury orhealth effect

Affecting workperformance inthe longer term,such as absence

from work formore than 5 days,affecting daily lifeactivities for more

than 5 days orirreversible

damage to health.(Long-termdisabilities.

Illnesses such assensitisation.)

Permanent totaldisability or up

to three fatalities (Illnesses such ascorrosive burns or

cancer.)

More than 3fatalities

(Cancer to a largeexposed

population. Majorfire or explosionresulting in morethan 3 fatalities.)

C o n s e q u e n c e o f F a i l u r e f o r

I n d i v i d u a l E q

u i p m e n t a n d P i p i n g

Environmental

Effect

No/Slight Effect

Slightenvironmental

damagecontained with thepremises. (Smallspill in process

area or tank farmarea that readily

evaporates.)

Minor Effect

Minorenvironmentaldamage but nolasting effect.

(Small spill off-sitethat seeps in theground. On-site

groundwatercontamination.

Complaints fromup to 10

individuals. Singleexceedance of

statutory or otherprescribed limit.)

Moderate Effect

Limitedenvironmental

damage that willpersist or requirecleaning up. (Spill

from a pipelinerequiring removaland disposal of alarge quantity of

sand/soil.Observed off-site

effects ordamage. Off-site

groundwatercontamination.)

Major Effect

Severeenvironmental

damage that willrequire extensive

measures torestore beneficial

uses of theenvironment. (Oilspill at a jetty thatends up on local

beaches requiringclean-up. Off-site

groundwatercontamination

over an extensivearea. Extendedexceedances of

statutory or otherprescribed limits

with potentiallong-term effects.)

Massive Effect

Persistent severeenvironmental

damage that willlead to loss ofcommercial,

recreational useof loss of naturalresources over awide area. (Crude

oil spillageresulting in

pollution of a largepart of a riverestuary and

extensive clean-up and

remediationmeasures.)




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Appendix 1 – Example Insulation System Checklist

Insulation Condition Checklist

Tick box if applicable

⇒ Caulking/sealant that has hardened and separated

⇒ Circumferential cracks in jacketing

⇒ Corrosion of cladding

⇒ Damaged or loose cladding

⇒ Damaged vapour barrier/stop

⇒ Failure at bends (open joints)

⇒ Foot traffic damage

⇒ Gaps due to uncontrolled expansion contraction

⇒ Hot/Cold spots

⇒ Icing and/or condensation

⇒ Longitudinal cracks in jacketing

⇒ Missing insulation (not re-installed after shutdowns orinspections)

⇒ Missing insulation at flanges/valve boxes

⇒ Missing self tapers, rivets or SS bands

⇒ Rust stains and bulges in metal cladding

⇒ Sagged insulation and cladding

⇒ No termination at flanges/valves

⇒ No termination in a vertical pipe or piece of equipment

⇒ Water increase at penetrations (e.g. nozzles)




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Appendix 2 – Technical Basis

1. Overview

1. Degradation of equipment and associated CUI typically occurs at a rate that depends on various

factors, including temperature, time, insulation type, coating type, equipment configuration, and

the presence of water. These factors are described in the sections below.

2. To aid in an understanding of the life cycle of CUI, a typical CUI degradation progression is as

follows:

Age Equipment and/or Barrier Condition

0 years New equipment properly coated, insulated and installed.Equipment operates continuously at 80°C (175 °F).

2 to 5 years No maintenance has been performed on the insulation system.Caulking has failed, Insulation is wet and water hasaccumulated in water traps and low areas.

6 to 8 years Coating system begins to fail, especially in water traps and lowareas.

8 to 10 years Coating system has failed nearly completely and CUI hasstarted.

Approximately15 years

Significant CUI has occurred with CUI rates averaging 0.125 –0.250 mm/yr (5 – 10 mpy) and as high as 0.50 mm/yr (20 mpy)in severe cases. Leaks have begun to appear.

Approximately20 years

Through-wall failures not uncommon at this point andsusceptible equipment has experienced significant degradation.

3. Degradation of equipment caused by ECSCC is non-trendable degradation mechanism andtherefore very unpredictable. The occurrence of ECSCC is caused by the presence of water,

chlorides and a temperature above 50°C (120°F). The influence of Material stresses also play a

role. These factors are described in the sections below.




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4. To aid in an understanding of the life cycle of ECSCC, a typical ECSCC degradation progression

is as follows:

Age Equipment and/or Barrier Condition0 years New equipment properly coated, insulated, and installed. Equipment

operates continuously at 80 °C (175 °F).

2 to 5 years No maintenance has been performed on the insulation system.Caulking has failed, insulation is wet, water has accumulated in watertraps and low areas.

6 to 8 years Coating system has begun to fail. Chloride build-up due toevaporation/condensation cycling in water retaining parts.

8 to 10 years Probability of ECSCC increases with age.

More than 15years

Industry experience indicates that through-wall failures caused byECSCC (leaks) occurs on the average of between 15 to 35 years.

2. Material Susceptibility

1. CUI can occur in carbon steel, low nickel steel, and low alloys up to and including 9-chrome

alloys.

a. Chrome alloys are typically used for their strength at elevated temperatures and thus outside

the susceptible temperature range but in the case of retrofits, reuse, or idling of equipment,

these alloys can be found operating in the CUI temperature range.

b. The primary consideration for material susceptibility is the operating temperature.

c. Alloy materials should not be taken out of the CUI program without consulting a corrosion

engineer.

2. ECSCC can occur in austenitic stainless steels, typically 304(L), 316(L), 321, 347 and associated

weldments.

a. Duplex stainless steels are highly resistant, although not immune, to ECSCC. Duplex stainless

steels are of the type 22Cr-5Ni (or higher alloyed), such as UNS S31803 (tradename SAF

2205) or UNS S32550 (tradename Ferralium 255).

b. Alloys containing more than 32% Nickel are not susceptible to ECSCC (e.g., Alloy-825).

3. Water

1. CUI for carbon steel and low-alloy steel under insulation occurs when water or water vapour

penetrates under the insulation and remains in contact with steel that does not have a protective

coating or that has a failed protective coating, in the susceptible temperature range.

2. CUI for carbon steel and low-alloy steel under insulation also occurs when the equipment sweats,even when there is no degradation of the insulation. Equipment sweating is caused by

temperature cycling above and below the ambient temperature or by operation below the

atmospheric dew point

3. Preventing water from reaching the steel is the key to preventing CUI.




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4. Areas with a higher exposure to wet conditions have a higher likelihood of water intrusion and

subsequent CUI. High exposure conditions include the following:

a. Mist from cooling water towers, steam vents, and process vents. b. Unattended steam and/or condensate and/or cooling water leaks.

c. Periodically tested deluge systems.

d. Coastal/marine areas.

4. Water and Chlorides

1 External chloride stress corrosion cracking of stainless steel under insulation occurs when water

or water vapour and chlorides penetrates under the insulation and remains in contact with stainless

steel in the susceptible temperature range that does not have a protective barrier or that has a

failed protective barrier.

2. ECSCC also occurs when the equipment sweats due to temperature cycling within the susceptible

temperature range.

3. Preventing water from reaching the steel surface is the key to preventing ECSCC.

4. Areas with a higher exposure to wet conditions have a higher likelihood of water intrusion and

subsequent ECSCC. High exposure conditions include the following:

a. Mist from cooling water towers, steam vents and process vents.

b. Unattended steam and/or condensate and/or cooling water leaks.

c. Periodically tested deluge systems.

d. Coastal/Marine Areas.

5. Source of water is typically mist, rain, deluge systems, malfunctioning steam traps, and leakingtracing. Rain in coastal areas typically contains more chlorides than rain in non-coastal areas.

6. Source of chlorides is typically water. An additional source for chlorides is insulation material,

PVC insulation of heat tracing, and vapours from neighbouring plants.

5. Corrosion Rate

1. Rate of CUI of carbon steel is directly correlated to equipment surface temperature and the

amount of water present.

2 Rate of CUI tends to be higher in areas where there is a cyclic wet/dry interface

(detachment/spalling of corrosion scale).

3. Rate of ECSCC is a non-trendable degradation mechanism and therefore very unpredictable.

6. Insulation Type

1. Insulation that absorbs and retains water has a higher likelihood of creating an environment that

promotes CUI or ECSCC.




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a. Mineral wool, fibreglass, and calcium silicate have the highest tendency to absorb water (and

chlorides).

b. Insulation with a closed cell structure, such as perlite and foam glass, has the lowest tendencyto absorb water (and chlorides)

2. Contact free insulation systems prevent accumulation of water and chlorides on the steel surface

and thereby reducing and significantly reduce the probability of developing both CUI and

ECSCC.

3. Insulating paint is sometimes used in lieu of conventional insulation. Equipment protected by

insulating paint is not considered to be susceptible to CUI or ECSCC.

7. Temperature

1. CUI susceptibility temperature range depends on the actual temperature of the process within the

piping or equipment. Experience shows that CUI can occur at a process temperature range from

-5 to175°C (+20 to350°F), and ECSCC at a process temperature range from 50 to 175°C (120 to

350°F).

2. With a well-maintained insulation system, external surface temperatures could typically be 10 to

15°C (20 to 30°F) closer to ambient air temperature than the process temperature. This

temperature difference can be much greater with significant insulation damage.

3. Surface temperature impacts the CUI corrosion rates. The highest CUI rates occur at a 50 to

110°C (120 to 230°F) temperature range.

a. In severe cases, CUI rates up to 1 mm/yr (40 mpy) have occurred at this temperature range,

although rates are typically on the order of 0.25 to 0.50 mm/yr (10 to 20 mpy).

b. Outside of this temperature range, rates typically decrease to 0.05 to 0.25 mm/yr (2 to 10

mpy/yr).

4. Rate of ECSCC is a non-trendable degradation mechanism and therefore crack initiation and

propagation rates are unpredictable. In practice, leakage has occurred within hours up to years.

5. Temperature cycles that include all or a portion of the CUI/ECSCC range tend to increase the

likelihood of CUI/ECSCC.

6. Breaches and damage points in the insulation can result in surface temperatures much lower than

the process temperature. These points can be at higher risk than the remainder of the system.

7. Although it can be argued that there is a correlation between temperature and probability of

ECSCC, in practice this is seldom the case.

8. All equipment spends some time at ambient temperature. Frequency and length of shutdowns

increases the probability of CUI.

9. Items such as deadlegs and vessel skirts, can operate at a much lower temperature and act as

cooling fins. These items are susceptible to CUI, even when the primary equipment temperature

is above 175°C (350°F).




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8. Coatings

8.1 General

Neither CUI nor ECSCC will occur if the protective coating has not failed or been damaged

unless a porous coating has been applied, which has occurred with silicone-based coatings on

stainless steel.

8.2 Carbon Steel

1. Coatings have a finite life and should be renewed if piping and equipment is to be

adequately protected from CUI.

2 Inorganic zinc coatings without a top coating are prone to rapid failure in the presence of

water.

3. Provided the coating was applied per the manufacturer recommendations (surface preparation, anchor profile, cure, etc.), the normal life expectancy of various common

coatings before breakdown commences is typically as follows:

ClimateCoating System

Coastal/Marine Temperate

Red Lead + Topcoat 8 yr 10 yr

Inorganic Zinc + Topcoat 8 yr 10 yr

Inorganic Zinc Only Less than 5 yr 8 yr

Immersion Service Coating 10 yr 15 yr

4. For carbon/low alloy steel, a TSA coating offers superior protection from CUI, if well

applied.

8.3 Stainless Steel

1. Aluminium foil wrapping is very effective for protection of stainless steel from ECSCC

when properly installed (applied with overlaps, in a manner that sheds water, etc.).

Aluminium wrapping is a cost effective and the preferred alternative for coating of

stainless steel.

a. Aluminium wrapping has been used in the process industry for over 20 years.

b. Aluminium wrapping can be applied online or offline.

c. Aluminium wrapping can be easily moulded around fittings and flanges.

d. Aluminium wrapping protects the stainless steel as a water/dirt barrier and protectsthe stainless steel by cathodic protection.

e. Although lifetime of aluminium wrapping is well over 20 years, its effectiveness will

also be affected by mechanical damage. It is therefore good practice to replace the

aluminium wrapping when equipment modification or maintenance occurs.

2. Organic coatings are appropriate for stainless steels provided good quality assurance and

control systems are in place.




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a. Life cycle costs of organic coatings should be evaluated because the use of

aluminium wrapping is almost always more cost effective and provides better

protection against ECSCC.

b. Organic coatings should be used only in areas in which aluminium wrapping is not

practical.

9. Heat Tracing

1. From the viewpoint of ECSCC, it is preferable to use electric heat tracing (in combination with

chloride free electrical insulation) in lieu of steam tracing, but in reality the majority of systems in

use will remain steam traced.

2. PVC electrical insulation of electrical heat tracing can be a source of chlorides.

3. Steam tracing failure inside the insulation defeats all CUI barriers because it introduces moisture,

strips away coatings and provides a temperature range where CUI and ECSCC are very

aggressive.

4. Steam tracing tubing is typically made of carbon steel, copper, stainless steel, or nickel alloy

(Incoloy) tubing.

a. Incoloy is expensive, but has a lower probability of in-service failure and may be justified on

the highest criticality systems.

b. Incoloy 825 has been justified and is now the standard for instrument systems on many sites.

c Stainless steel tubing is vulnerable to chloride stress corrosion cracking at similar conditions to

CUI and is unlikely to offer superior life in comparison to carbon steel tubing.

d. Copper ions make stainless steel more susceptible to pitting corrosion and an alternate material

is to be selected when steam tracing stainless steels.

5. The main leak point for steam tracing is around coupling joints. Locate these joints outside of the

insulation system.

6. The probability assessment used in this SP accounts for the fact that steam tracing increases the

probability of CUI/ECSCC.

7. As this can only be a general guide, local knowledge should be applied based on the condition of

the tracing network in general.

8. The probability score depends on the level of integrity of the steam tracing system, which depends

on the following features:

a. Tubing made of the proper material

b. Tubing installed using the highest level of quality control (adequate spacers, couplings outside

insulations)

c. Careful quality assurance verification has been performed after installation

9. High Integrity Design means that all the three features are satisfied. Medium Integrity Design

means that only two out of the three features are satisfied. Low Integrity Design means that no

features are satisfied.




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10. If extensive delagging is planned for a system incurring significant costs for insulation and

scaffolding, consideration should be given to renewing the associated tracing with couplings and

joints relocated outside of the insulation or replacement with an electrical heat tracing.

10. External Environment

In the probability assessment tables, reference is made to external environment with respect to rain and

wet industrial conditions. However, local conditions may vary and dictate a more or less severe

approach. For example:

1. A site in a temperate region [800 mm/yr (31.5 in/yr) rainfall], but at 60 km (37 mi) from the coast

with main wind direction from sea may classify as a coastal marine area.

2. A site in coastal area in an arid region with wind direction from the land side may classify as an

arid area.

11. Susceptible Areas

1. Protrusions extending through the insulation sheathing, even those properly caulked, will

eventually provide a means of water intrusion as caulking may start to dry out in a couple of years

and is seldom, if ever, renewed.

2. Examples of protrusions where water intrusion can occur include the following:

a. Stiffener rings

b. Insulation support rings

c. Skirt fireproofing “rain hat”

d. Brackets (platform, ladder, pipe, etc.)

e. Lifting lugs

f. Deadlegs (vents, drains, by-pass lines, level-leg-assemblies, etc.)

g. Small bore piping

h. Pipe hangers, supports and shoes

i. Valves, fittings, etc. with irregular insulation surfaces

j. Steam tracer-tubing penetrations

3. Other areas where water intrusion can occur include the following:

a. Terminations of personnel protection and other insulation systems, especially on vertical

surfaces

b. Steam tracing tubing junctions

c. Holes for inspection (i.e., condition monitoring locations)

d. Insulation junctions (cast to blanket, etc.)

e. Insulated flanges

f. Damaged or missing jacketing




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g. Improperly installed jacketing (improperly lapped, seams on top, etc.)

h. Sheathing seams (improper lap, hard/missing caulk, etc)

i. Cracked fireproofing on skirts (corrosion occurs primarily at both the base ring and near theskirt-to-vessel juncture weld)

j. Coat and wrap piping protection systems.

4. After intrusion, water saturates the insulation and accumulates at low points and other natural

collection areas. Examples include:

a. Insulation support rings

b. Stiffener rings

c. Lifting lugs

d. Sagging areas of piping and other low points

5. Accumulation of water can occur at a long distance from the point of intrusion, especially inservices where the surface temperature does not cause the water to evaporate. For example, on a

horizontal line in the middle of a span between pipe supports, where the insulation is missing at

the supports. Evaporated water can also travel through the insulated system and condense in

areas with a lower surface temperature.

6. For ECSCC, consider crevice corrosion sites (lap joints, crevices, etc.) in the evaluation.

7. Despite a thorough understanding of potentially susceptible areas, CUI remains difficult to

predict. Therefore the inspection approach shall include removal of an ample area (proportional

to the item being inspected) of insulation around the susceptible area to enable a thorough

assessment to be performed.




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Appendix 3 – Risk Assessment Example

1. Determining Consequence of a CUI failure

1. Assume the following piping system is being evaluated:

a. Natural Gas (API-570 Class 2) at 3.1 bar (45 psig) in a remote on-site location.

b. The Environmental Department estimates a leak would potentially result in several (<10)

odour complaints with no impact outside the fence.

c. Potential personal safety consequence is a first-aid incident.

d. The financial impact is less than 10,000 USD in equipment damage and repair cost and 2-day

outage of a single process unit worth 30,000 USD per day.

2. Using the Strategy Matrix (Table 2) to determine the consequence:a. Asset Damage & Consequential Business Loss – Move across to the box that reads “10 to

100k USD, brief disruption to operation”, corresponding to a consequence rating of 2.

b. Harm to People – Move across to the box that reads “No/Slight Injury”, corresponding to a

consequence rating of 1.

c. Environmental Effect – Move across to the box that reads “Minor Effect”, corresponding to a

consequence rating of 2.

3. Since the highest consequence rating was two (for both Asset Damage and Environmental Effect),

the overall consequence for this piping system is 2.

2. Determining Probability of a CUI Failure

1. Following is additional data on the fuel gas line:

a. Operating temperature: 135°C (275°F)

b. Coating information: Unpainted

c. Insulation type: Calcium silicate

d. Cladding/Insulation Condition: Average (Conventional Design)

e. Heat tracing: None

f. Environment: Located near the coast

2. Similar to the finding the consequence, follow the columns down on the probability assessment

table corresponding to the data above. For example, consider the operating temperature (the firstcolumn in Table 1, Probability Assessment for CUI of Carbon/Low Alloy Steel). With an

operating temperature of 135°C (275°F), move down the first column to the row that matches the

actual operating temperature (the fourth box from the top). Moving all the way across the fourth

row to the right-most column (Points), we find that this temperature corresponds to three points.




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Printed Printed copies are ncontrolled

3. Repeating this for each column, the following results are generated:

Column Heading Points

Operating Temperature 3

Coating Status 5

Cladding/Insulation Condition 3

Insulation Type 5

Heat Tracing 0

External Environment 5

Total 21

3. Determining Inspection Strategy

1. Recall that the Consequence and Probability for this example are:

a. RAM Consequence – 2.

b. Probability – 21.

2. To determine the Inspection Strategy, enter the Table 2, Inspection and Maintenance Strategy

Matrix for CUI for Carbon/Low Alloy Steel, in the top row for a Probability Score more than 20.

Move across to the column corresponding to a RAM Consequence of 2. This results in Inspection

Strategy 3 (IS-3).

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