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Reprinted from August2010 | HYDROCARBONENGINEERING |

Stephen A. Anderson, Intertek, USA, discusses the importance ofunderstanding and protecting against corrosion under insulation.

OUT OF SIGHT, OUT OF MIND?

In 2006 an ageing Gulf Coast petrochemical facility experienced aleak from a 4 in. hydrocarbon line. After several minutes this leakfound an ignition source, causing a massive re that destroyedhalf the unit and cost the company US$ 50 million. Despite theadvances in materials, inspection and maintenance practices, theinsidious problem of corrosion under insulation (CUI) still costs theindustry millions of dollars a year. As part of a comprehensive assetintegrity programme a denitive strategy to combat CUI shouldinclude:

Careful design and materials selection. Development of corrosion circuits. Risk assessment or risk based inspection evaluation. Development of mitigation strategies. Visual inspections and nondestructive examination (NDE). Ongoing maintenance, monitoring and inspection practices.

This article discusses practical plans and solutions tocombating this ever present problem that threatens the integrity ofequipment.

In order to prevent unnecessary shutdowns and accidents, thecondition of equipment and piping should be monitored to detectwhen equipment should be retired from service (retirement limit).This monitoring can be done visually, acoustically with a UT probe orwith a radioactive source and lm (radiography). This allowsmanagement and inspectors to identify problems before they createdangerous conditions or cause expensive shutdowns.

Unfortunately equipment at chemical plants is difcult to reachand is usually insulated. Under certain conditions CUI can occur,threatening the integrity of equipment. Inspection points areselected where experience suggests corrosion is likely to causesignicant problems. This process of dening and naming corrosioncircuits, identifying risks, monitoring corrosive locations, measuring

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and analysing data and maintaining equipment condition is crucial inassisting management in making important economic and safetydecisions, and combating the problem of CUI.

Design, materials and operationalconsiderationsCUI results from the collection of water or vapour between a metal

surface and thermal insulation. On carbon steels CUI generallyoccurs in the form of general corrosion or localised corrosion. Inaustenitic stainless steels, such as the 18-chromium-8-nickel (18-8)or AISI 300 series stainless steels, CUI often occurs as stresscorrosion cracking (SCC) and pitting.

On equipment, CUI typically occurs where water can collect bygravity, such as at penetrations to insulation or where attachmentsmay channel drainage. On horizontal piping, damage often occurs atthe 6 oclock position, while on vertical pipe runs damage frequentlyoccurs at the bottom.

In carbon and low alloy steels CUI results in large areas of wetscale. In austenitic stainless steels chloride SCC often occurs atwelds and in non-stress relieved bends. Although CUI can occur overa broad temperature range of -10 - 250 F, the greatest potential andmost severe environment is between 120 - 200 F.

Seven controllable factors affecting CUI have been identied.They are as follows:

Equipment design. Service temperatures. Insulation selection. Protective coatings. Weather barriers. Climate. Maintenance practices.

CUI can occur under the following conditions:

Corrosion of carbon steel at temperatures between 32 - 300 F, andis most severe at approximately 200 F.

Corrosion of carbon steel occurs due to temperature cycling aroundthe ambient temperature or at operation below the dew point.

Corrosion of austenitic stainless steels is most likely to occur whenthere is the condition for cracking, specifically chloride SCC. Typically

this occurs over the temperature range of 140 - 300 F, and is mostsevere at approximately 200 F.

The 18-8 grades (e.g. 304, 316, etc.) are very susceptible to SCC,particularly by chloride ions. CUI occurs on 18-8 grade equipmentcontaminated with chlorides and can fail catastrophically and in arapid manner.

Corrosion of carbon steel and stainless steel occurs when waterpenetrates an insulation system that is operating in a susceptibletemperature range. The water may be from condensation, leaks inthe insulation, rain, fire protection systems, etc.

The amount of carbon steel lost because of CUI is determined by theduration and frequency of exposure, the corrosivity of theenvironment, and the failure of paint and jacketing acting as barriers

to corrosion. Design and operating conditions such as cyclic thermal operation,

intermittent service, poor jacketing, exposure to steam vents, coolingwater towers, dead legs and attachments all accelerate CUI.

Examples of susceptible areas

Penetrations All penetrations or breaches in the insulation jacketing systems,

such as deadlegs (vents, drains and other similar items), hangersand other supports, valves and fittings, bolted on pipe shoes, laddersand platforms.

Table 1. Basic data required for LOF analysis (API 581)

Basic data Comments

Maximum temperature ( F) Determine the maximum process temperature in this equipment/piping. Note that steam traced lines are in the 120 - 250 Frange unless the operating temperature is higher than 250 F.

Type of environment? Determine the type of environment of the equipment/piping location based on:Tropical/marine: average rainfall = >40 in./y (i.e. coast, cooling tower drift, etc.)Temperate: average rainfall = 20 - 40 in./y Arid/desert: average rainfall =

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Steam tracer tubing penetrations. Termination of insulation at flanges and other components.

Damaged insulation areas Damaged or missing insulation jacketing. Termination of insulation in a vertical pipe or piece of equipment. Caulking that has hardened, separated or is missing.

Bulges, staining of the jacketing system or missing bands (bulgesmay indicate corrosion product buildup).

Low points in systems that have a known breach in the insulationsystem, including low points in long, unsupported piping runs.

Carbon or low alloy steel flanges, bolting and other componentsunder insulation in high alloy piping.

Other The following are some examples of other suspect areas that should beconsidered when performing inspection for CUI.

Areas exposed to mist overspray from cooling towers. Areas exposed to steam vents.

Areas exposed to deluge systems. Areas subject to process spills, ingress of moisture or acid vapours. Carbon steel systems including those insulated for personnel

protection, operating between 10 - 250 F (-23 - 120 C). CUI isparticularly aggressive where operating temperatures causefrequent or continuous condensation and reevaporation ofatmospheric moisture.

Carbon steel systems that normally operate in service above 25 F(120 C), but are in intermittent service or are subjected to frequentoutages.

Deadlegs and attachments that protrude from the insulation andoperate at different temperatures than the operating temperature ofthe active line, i.e. insulation support rings, piping/platform

attachments. Systems in which vibration has a tendency to inflict damage to

insulation jacketing providing paths for water ingress. Steam traced systems experiencing tracing leaks, especially at

tubing fittings beneath the insulation. Systems with deteriorated coating and/or wrappings. Cold service equipment consistently operating below the

atmospheric dewpoint. Inspection ports or plugs that are removed to permit thickness

measurements on insulated systems represent a major contributorto possible leaks in insulated systems. Special attention should bepaid to these locations. Inspection plugs should be replaced andresealed promptly.

Corrosion circuitsTypically corrosion management manuals identify which degradationmechanisms (corrosion, cracking and embrittling mechanisms) are activewithin each area of a facility and dene their location and severity ofdegradation to aid integrity management activities such as inspection,process and corrosion monitoring.

Corrosion loops or circuits are typically marked up process owdiagrams (PFDs) that show the location(s) of the various corrosionmechanisms and the affected equipment items. The assigned damagemechanisms and circuits are based on industry guidance documentssuch as API 571.

Using the concept of circuits, data on one part of a circuit can beused to infer conditions about the rest of the circuit. Given a history of

measurements for inspection points in a circuit, corrosion rates can becalculated for both individual inspection points and the entire circuit. Thisinformation, combined with knowledge about the type of equipment,operating conditions and various safety considerations, can be used todetermine the expected life of equipment and when it would be prudentto inspect the equipment again. Identication of circuits within a pipingsystem allows the inspector to take measurements on a representativepercentage of measuring points within a circuit on any given inspection.

Naturally the most corrosive systems or circuits demand the mostattention. However, as equipment and piping ages, the lower corrosionrate circuits also achieve the potential to fail and become hazardous.Therefore, it is essential that an organised, scientic monitoringprogramme is developed for a facility.

Risk based inspectionRisk based inspection (RBI) programmes provide a structured method foridentifying and assessing the potential impact of deciencies on anoperating plant, as well as ascertaining inspection methods to mitigatethese deciencies. RBI therefore provides a systematic methodology forfactoring risk into infrastructure maintenance and inspection decisionmaking.

A comprehensive RBI programme analyses the likelihood of failure(LOF) and identies the damage mechanisms of concern, as well asidentifying the consequence of failure (COF) should a leak or failure occur.This methodology is therefore helpful in identifying areas or circuits on aprocess facility where CUI may be a problem and identies what theconsequences of a potential leak may be.

The basic data that should be considered when evaluating thelikelihood of failure from CUI is listed in Tables 1 and 2 (taken from API 581).

By analysing the data in Tables 1 and 2, one can determine ifequipment items have a high, medium or low susceptibility to failure, dueto CUI.

On the consequence side, process stream data, inventories andpotential leak sizes are evaluated. Obviously priority should be given toequipment containing explosive, ammable or toxic process streams withlarger inventories and the potential for large leaks or gross rupture of thesusceptible equipment.

The product of the LOF and COF identies the risk posed by aparticular item (in this case an explosive, ammable or toxic leak due to

CUI). This risk ranking or prioritisation can then be applied to inspectionfrequencies, scope of inspections, the use of testing and monitoringtechniques to evaluate equipment condition, and corrosion rates in orderto determine remaining useful life and tness for service.

Figure 1. Pipe failure at 6 o' clock position due to CUI.

Table 2. Estimated corrosion rates for carbon and low alloy steel(API 581)

Unmodified - CUI corrosion rate (mpy)

Temperature F Tropical/marine Temperate Arid/desert

-10 - 60 5 5 1

61 - 120 15 10 2

121 - 250 35 15 4

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Mitigation strategiesProtective coatings or paint are an important method of corrosion controlin reducing or preventing CUI. A good quality coating, correctly appliedover a properly prepared surface, generally results in excellent service. Ingeneral, once the weather or vapourproong is breached, the insulatedenvironment stays wet for much longer than the surfaces of mostuninsulated equipment. Also, under warm insulation the coating is

obviously subject to higher temperatures than most painted, uninsulatedequipment. Abrasive blasting is the best surface preparation for all coating

systems and all substrates. It is generally accepted that the user mustprepare the surface prior to coating by removing any chemicalcontamination rst and blasting to a 1 - 2 mm (0.001 - 0.002 in.)prole.

Consideration must be given to both chemical degradation andpermeability of the coating. Highly permeable coatings allow corrosion tostart behind the coating, even in the absence of breaks or pinholes.Finally, many coatings depend on some form of sacricial inhibitor or areessentially only that (i.e. organic zinc rich coatings).

Finally, routine maintenance of weatherproong reduces problemsassociated with deterioration caused by CUI. Maintenance and inspectionneed to assure closure of a system immediately after work is completed.Mechanical and inspection work needs to be closely tied to insulationrepair. Time delay before insulation repair can result in severe corrosionproblems in an insulated system.

Visual inspection and NDEFollowing the identication of circuits susceptible to CUI and the riskranking of the equipment items, inspection personnel should visuallyinspect circuits or equipment items that have been identied as high risk.The inspector should consider the following susceptible areas andconditions during the survey:

Weathered, split or missing mastic moisture barriers on piping andon vessel heads and sidewalls, above supports and around nozzles.

Dead (inelastic), loose or missing caulking at seams andconnections.

Punctured, split or corroded metal jacketing. Improper installation interfering with water runoff. Mold, mildew or moisture at insulation support rings or vacuum

rings on vessels. Red stains or white deposits on jacketing. Unprotected insulation where parts have been removed. Unsealed metal wall thickness test points. Flashing that does not shed water. Gaps around pipe hangers and other protrusions. Gaps in jackets at top of vertical pipe runs.

Open joints in jackets from physical damage. Attachments, nozzles, ladders, supports, gangways, etc.

Damaged insulation and weather barriers should be reported tomaintenance for timely repair work. Where visual inspection identiesareas that are showing signs of CUI, further inspection or evaluationneeds to be conducted. This could include:

A pulsed eddy current (PEC) technique to determine wall losswithout the removal of the insulation. This is typically used asscreening tool to identify corrosive areas.

If critical areas are identified (either visually or with PEC), strippinginsulation and conducting further visual and UT inspections will berequired.

Follow up work should include a tness for service evaluation onequipment showing signicant degradation.

Ongoing maintenance, monitoring andinspection practicesBased on circuitisation and risk analysis, specific inspectionplans should be developed for each equipment item. These plansshould detail the identified damage mechanisms (CUI), thelikelihood of failure, and what, how, when and where inspectionsshould be conducted. A plant wide programme to identify

equipment and piping susceptible to CUI may be established asfollows:

Divide the plant into inspection areas and set inspectionpriorities. Look for factors that signify potential corrosionproblems.

Location: exposure to rain, fire protection deluge systems,safety showers and ground water.

Temperature: operation between 0 - 149 C (32 - 300 F),temperature cycling or below dewpoint temperature service.

Materials of construction: Type 300 series stainless steelssubject to chloride SCC. Carbon and low alloy steels subjectto general and localised (pitting) corrosion.

Age of facil ities: old equipment can be expected to have

more corrosion than newer facilities. Risk potential: potential for personal hazard, environmental

damage and product loss increase risk potential. Insulation type: ability to wick water increases corrosion

potential. Asbestos containing insulations have some of theworst wicking problems and have given rise to several cases ofCUI.

Coverings: reinforced mastics deteriorate faster than metalor polyvinylchloride plastic jackets.

Visually inspect selected unit s for indications of wetinsulation and corrosion. Several types of instruments areavailable that can detect moisture.

Use NDE tools such as PEC to identify CUI.

Remove sections of suspected wet insulation or areas showingsigns of corrosion to inspect the metal surfaces beneath.

Nozzles, particularly at the insulation weather seal, aresusceptible to accelerated CUI. Vessel drawings should bechecked for all nozzle attachments, and nozzles that may besusceptible to CUI should be marked. These nozzles must thenbe visually inspected. If nozzles show signs of having corrosionor CUI problems, they should be identified for further testing.

For areas showing significant corrosion, a fitness for serviceevaluation should be conducted.

Decide what action to take, whether to simply replace andreseal insulation at the inspection point, or to completelyreplace the system or some other combination of stripping,

blasting, repairing, coating, reinsulating and resealing. All areas of damaged insulation or weather barriers should

be repaired in a timely manner by maintenance. All new inspection data should be used to update original

risk assessments, keeping the risk analysis, susceptibleareas and state of knowledge current.

ConclusionsDespite advances in materials and inspection practices, CUI stillremains a serious industry problem, costing facilities manymillions of dollars each year. One of the reasons for this is that itis an unseen problem, still overlooked by inspection andmaintenance and often not considered by management. Byapplying asset integrity techniques, risk based analysis and thelatest inspection and maintenance practices one can minimisethe likelihood of a catastrophic failure due to CUI.