DSM-1510002-SP-20_V1.0[1]

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Assessment and Mitigation Planning for Corrosion Under Insulation and External Chloride Stress Corrosion Cracking

DBAM Code and Name: MAN.15.10 Provide Asset Availability – Ensure Equipment Integrity

Document Number DSM-1510002-SP-20

Shell Downstream Manufacturing

Assessment and Mitigation Planning for Corrosion Under Insulation and External Chloride Stress Corrosion Cracking Table of Contents 1.

2.

2.6

General ...................................... 2 1.1 1.2 1.3 1.4 1.5 1.6

Scope ........................................... 2 Purpose ........................................ 2 Overview....................................... 2 Deviations..................................... 2 Tools............................................. 3 Definitions..................................... 3

2.7 2.8

3.

2.4 2.5

General......................................... 4 Prioritising Units ........................... 5 Developing the Equipment and Piping List ..................................... 5 Challenging the Need for Insulation ...................................... 5 Performing an Initial External Visual Inspection .......................... 5

Version: 1.0

Date: January 2007

Mitigation Planning .................. 8 3.1 3.2

Assessment .............................. 4 2.1 2.2 2.3

Determining the Probability of Occurrence of CUI and ECSCC... 6 Estimating the Potential Consequence of a Failure ............ 6 Determining the Inspection Strategy ........................................ 7 Development ................................ 8 Additional Considerations ............ 8

Appendix 1 – Example Insulation System Checklist ................... 18 Appendix 2 – Technical Basis ...... 19 Appendix 3 – Risk Assessment Example .................................. 27

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General 1.1

1.2

1.3

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.

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.

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

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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. Date: January 2007

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1.5

1.6

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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 to the technical community and the Equipment Integrity (EI) Global Process Owner (GPO) for review and use in the continuous improvement of this specification.

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 piping with 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.

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.

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External chloride stress corrosion cracking (ECSCC) – stress corrosion cracking of austenitic alloys containing less than 32% nickel initiating on the external (non-process contacting) 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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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.

Version: 1.0

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 Date: January 2007

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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-byunit 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

2.4

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 piping in 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.

Challenging the Need for Insulation After the equipment and piping list has been developed but prior to starting the determination of 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.

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.

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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 the consequences 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. Date: January 2007

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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 Austenitic Stainless Steel for ECSCC.

2.

To determine the Inspection Strategy,

3.

Version: 1.0

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.

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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Mitigation Planning 3.1

3.2

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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 all these 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.

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 to CUI 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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Figure 1 – Overview: Management of Corrosion Under Insulation for Carbon/Low Alloy Steel

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

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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 or last applied

Cladding/ Insulation Condition

Insulation type

Heat tracing

External environment

Points

Constantly 175°C

Regular inspection and maintenance (every 5 years)

TSA < 15 years

Inside building, not steam traced and not sweating REMOVE FROM CUI PROGRAM

0

REMOVE FROM CUI PROGRAM

Good to Engineering Standards or new/renewed ( 30 years or unpainted or unknown

Poor condition, damaged/ wet/broken seals

Cal Sil, Rockwool (no spec), unknown

Low integrity design or leaking (steam)

150ºC - 175°C 300ºF - 350ºF

−5ºC - 49°C 26ºF - 119ºF OR 111ºC - 149°C

or

226ºF - 299ºF 50°C - 110°C 120ºF - 225ºF or cycling/sweating conditions

50% of the time) (e.g. cooling tower/deluge systems)

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

Consequence of Failure for Individual Equipment and Piping

Probability

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

A (1 - 10)

IS-4

IS-4

IS-4

IS-4

IS-3

Priority

1

2

3

4

5

Asset Damage & Consequential Business Loss

No/Slight damage 10M USD Substantial or total loss of operation

Harm to People

No/Slight injury or health effect Not affecting work performance or daily life activities. (First Aid case and medical treatment case. Exposure to health hazards that give rise to noticeable discomfort, minor irritation or transient effects reversible after exposure stops.)

Minor injury or health effect Affecting work performance, such as restriction to work activities or need to take up to 5 days to fully recover. (Restricted or lost workday cases resulting in up to 5 calendar days away from work. Illness such as skin irritation.)

Major injury or health effect Affecting work performance in the longer term, such as absence from work for more than 5 days, affecting daily life activities for more than 5 days or irreversible damage to health. (Long-term disabilities. Illnesses such as sensitisation.)

Permanent total disability or up to three fatalities (Illnesses such as corrosive burns or cancer.)

More than 3 fatalities (Cancer to a large exposed population. Major fire or explosion resulting in more than 3 fatalities.)

Environmental Effect

No/Slight Effect Slight environmental damage contained with the premises. (Small spill in process area or tank farm area that readily evaporates.)

Minor Effect Minor environmental damage but no lasting effect. (Small spill off-site that seeps in the ground. On-site groundwater contamination. Complaints from up to 10 individuals. Single exceedance of statutory or other prescribed limit.)

Moderate Effect Limited environmental damage that will persist or require cleaning up. (Spill from a pipeline requiring removal and disposal of a large quantity of sand/soil. Observed off-site effects or damage. Off-site groundwater contamination.)

Major Effect Severe environmental damage that will require extensive measures to restore beneficial uses of the environment. (Oil spill at a jetty that ends up on local beaches requiring clean-up. Off-site groundwater contamination over an extensive area. Extended exceedances of statutory or other prescribed limits with potential long-term effects.)

Massive Effect Persistent severe environmental damage that will lead to loss of commercial, recreational use of loss of natural resources over a wide area. (Crude oil spillage resulting in pollution of a large part of a river estuary and extensive cleanup and remediation measures.)

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Table 3 – Probability Assessment for ECSCC of Austenitic Stainless Steel Operating Temperature

Shop coating or Al-wrap Status & Age

Cladding/ Insulation Condition

Insulation type

Heat tracing

External environment

Points

Constantly >175°C or 350°F or 12 yrs Or Maintenance coating > 8 yrs Or Al-wrap* > 20 yrs

Average condition, no special precautions taken at susceptible areas (c)

Fibreglass, Asbestos, Regular Perlite, Mineral/Rock Wool (low Chlorides 15 yrs Or Maintenance coating > 12 yrs Or unknown

Poor condition, severely damaged, wet Or unknown

Mineral/Rock Wool (no Chlorides spec), Cal Sil

Low integrity design or leaking (steam) or electrical (PVC insulation)

40”/yr] rain High wetting rate (> 50 % of the time) or exposed to cooling tower/deluge systems

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 Inspection Strategy (IS)

Consequence of Failure for Individual Equipment and Piping

Probability

Probability Point Total 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

A (< 10)

IS-5

IS-5

IS-5

IS-5

IS-4

Priority

1

2

3

4

5

Asset Damage & Consequential Business Loss

No/Slight damage 10M USD Substantial or total loss of operation

Harm to People

No/Slight injury or health effect Not affecting work performance or daily life activities. (First Aid case and medical treatment case. Exposure to health hazards that give rise to noticeable discomfort, minor irritation or transient effects reversible after exposure stops.)

Minor injury or health effect Affecting work performance, such as restriction to work activities or need to take up to 5 days to fully recover. (Restricted or lost workday cases resulting in up to 5 calendar days away from work. Illness such as skin irritation.)

Major injury or health effect Affecting work performance in the longer term, such as absence from work for more than 5 days, affecting daily life activities for more than 5 days or irreversible damage to health. (Long-term disabilities. Illnesses such as sensitisation.)

Permanent total disability or up to three fatalities (Illnesses such as corrosive burns or cancer.)

More than 3 fatalities (Cancer to a large exposed population. Major fire or explosion resulting in more than 3 fatalities.)

Environmental Effect

No/Slight Effect Slight environmental damage contained with the premises. (Small spill in process area or tank farm area that readily evaporates.)

Minor Effect Minor environmental damage but no lasting effect. (Small spill off-site that seeps in the ground. On-site groundwater contamination. Complaints from up to 10 individuals. Single exceedance of statutory or other prescribed limit.)

Moderate Effect Limited environmental damage that will persist or require cleaning up. (Spill from a pipeline requiring removal and disposal of a large quantity of sand/soil. Observed off-site effects or damage. Off-site groundwater contamination.)

Major Effect Severe environmental damage that will require extensive measures to restore beneficial uses of the environment. (Oil spill at a jetty that ends up on local beaches requiring clean-up. Off-site groundwater contamination over an extensive area. Extended exceedances of statutory or other prescribed limits with potential long-term effects.)

Massive Effect Persistent severe environmental damage that will lead to loss of commercial, recreational use of loss of natural resources over a wide area. (Crude oil spillage resulting in pollution of a large part of a river estuary and extensive cleanup and remediation measures.)

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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 or inspections)

⇒

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:

3.

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 has accumulated in water traps and low areas.

6 to 8 years

Coating system begins to fail, especially in water traps and low areas.

8 to 10 years

Coating system has failed nearly completely and CUI has started.

Approximately 15 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.

Approximately 20 years

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

Degradation of equipment caused by ECSCC is non-trendable degradation mechanism and therefore 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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To aid in an understanding of the life cycle of ECSCC, a typical ECSCC 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, water has accumulated in water traps and low areas.

6 to 8 years

Coating system has begun to fail. Chloride build-up due to evaporation/condensation cycling in water retaining parts.

8 to 10 years

Probability of ECSCC increases with age.

More than 15 years

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

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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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.

6.

5.

Source of water is typically mist, rain, deluge systems, malfunctioning steam traps, and leaking tracing. 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.

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.

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 tendency to absorb water (and chlorides)

7.

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.

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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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: Coating System

4.

8.3

Climate 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

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

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 protects the 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.

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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:

11.

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.

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 the skirt-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 in services 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 (