21676 Corrosion Under In

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Corrosion under Insulation (CUI)

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i found the following articles and i think it will be useful to share it with the forummembers.

by the way i face this problem actual in my work ,and we must take care of it.


CUI is a particularly severe form of localized corrosion that has been plaguing chemical

process industries since the energy crisis of the 1970s forced plant designers to include

much more insulation in their designs.

Intruding water is the key problem in CUI. Special care must be taken during design notto promote corrosion by permitting water to enter a system either directly or indirectly by

capillary action. Moisture may be external or may be present in the insulation materialitself. Corrosion may attack the jacketing, the insulation hardware, or the underlying

equipment.

For high temperature equipment, water entering an insulation material and diffusing

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inward will eventually reach a region of dryout at the hot pipe or equipment wall. Next to

this dryout region is a zone in which the pores of the insulation are filled with a saturatedsalt solution. When a shutdown or process change occurs and the metal-wall temperature

falls, the zone of saturated salt solution moves into the metal wall.

Upon reheating, the wall will temporarily be in contact with the saturated solution, and

stress-corrosion -----ing may begin. The drying/wetting cycles in CUI associated

problems are a strong accelerator of corrosion damage since they provoke the formation

of an increasingly aggressive chemistry that can lead to the worst corrosion problemspossible, e.g. stress corrosion -----ing, and premature catastrophic equipment failures.

Types of Corrosion Under Insulation

By understanding the types of corrosion that can occur under insulation, the proper

materials and construction can be employed to prevent them. Intruding water is the key

problem in CUI . Special care must be taken during design not to promote corrosion by

permitting water to enter a system either directly or indirectly by capillary action.

Moisture may be external or may be present in insulation.

What is the Mechanism of Corrosion Under Insula tion?

The mechanism of corrosion under insulation involves three requirements:

Availability of oxygen.1.High temperature.2.Concentration of dissolved species.3.

Normally, as the temperature increases, the amount of oxygen dissolved in solution

decreases as the boiling point is reached resulting in reduced corrosion rates. However,

on the surface covered by insulation, a poultice effect is created which holds in the

moisture which essentially makes it s closed system. In fact the measured corrosionrates associated with corrosion under insulation follow trends to higher corrosion rates

commonly associated with only pressurized systems. Furthermore, in cases where

precipitation becomes trapped on the metal surface by insulation, corrosive atmospheric

constituents such as chlorides and sulfuric acid can concentration to also accelerate

corrosion. In some cases, chlorides are present in the insulation which greatly promotes

corrosion of the underlying surface which it becomes laden with moisture.How do I Inspect for Corrosion Under Insulation?

The most common and straightforward way to inspect for corrosion under insulation is tocut plugs in the insulation that can be removed to allow for ultrasonic testing. However,

many times such plugs can be the source of moisture leakage. The main problem with

this technique is that corrosion under insulation tends to be localized and unless the

inspection plug is positions in the right spot the sites of corrosion can be missed. Other

techniques that are available include special eddy current techniques, x-ray, remote TV

monitoring and electro-magnetic devices.How do I Prevent Corrosion Under Insulation?

The most serious problem is the system already in service with a know corrosion underinsulation problem. Inhibitors have been tried with varying success since repeated wet /

dry cycles may make inhibitors ineffective. This is an area of opportunity. However, longterms performance and efficacy must be proven. Water proofing to prevent the ingress of

water from outside sources is another method. However, it has been shown that

sometimes these techniques tend to lock in moisture which can also increase corrosivity.

Careful selection of insulation materials to prevent those that contain high levels of corrosive impurities such as chlorides is critical to reducing corrosion under insulation.

One of the best but most expensive options to prevent corrosion under insulation is theuse of protective coating systems. Unfortunately, in most cases, coatings that have been

successful for atmospheric service are used under insulation with disastrous results. In it

often a surprise that under-insulation service is a more severe condition than straight

atmospheric service. Special coating system must be utilized that have proven

performance. In some applications inorganic zinc has worked well, but not in others.Anticorrosion and inhibitive coatings are being are also being proposed or considered forlonger term performance.





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INTRODUCTION

Corrosion under insulation (CUI) is real threat to the on stream reliability of many

of today's plants. This type of corrosion can cause failures in areas that are not

normally of a primary concern to an inspection program. The failures are often the

result of localized corrosion and not general wasting over a large area. These

failures can tee catastrophic in nature or at least have an adverse economic effectin terms of downtime and repairs. The American Petroleum Institute code, API 570,

Inspection, Repair, Alteration and iterating of In-service Piping Systems, the piping

code first published in June 1993, identifies CUI as a special concern. Typically, as

happened with API 653 and the Clean Water Act, the API codes become an industrystandard, and theregulations demand that organizations maintain a program tomeet that standard. OSHA 1910 is the rule with the teeth in this case. CUI is

difficult to find because of the insulation cover that masks the corrosion problem

until it is too late. It is expensive to remove the insulation, particularly if asbestos

is involved. There are a number of methods used today to inspect for corrosionunder insulation. The main ones are profile radiography, ultrasonic spot readings,

and insulation removal. The other method now available is real-time X-ray. Real-

time X-ray has proven to be a safe, fast and effective method of inspecting pipe in

plant operations.

•

WHEN DOES CORROSION UNDER INSULATION OCCUR?

The problem occurs on carbon steels and 300 series stainless steels. On the carbon

steels it manifests as generalized or localized wall loss. With the stainless pipes it is

often pitting and corrosion induced stress corrosion -----ing (CISCC). Though

•

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failure can occur in a broad band of temperatures, corrosion becomes a significant

concern in steel at temperatures between 32°F (0° C) and 300°F (149° C) and ismost severe at about 200° F (93° C). Corrosion and CISCC rarely occur when

operating temperatures are constant above 300°F (149° C)(1). Corrosion under

insulation is caused by the ingress of water into the insulation, which traps the

water like a sponge in contact with the metal surface. The water can come from

rain water, leakage, deluge system water, wash water, or sweating from

temperature cycling or low temperature operation such as refrigeration units.

SYSTEMS SUSCEPTI BLE TO CUI

API 570 specifies the following areas as susceptibleto CUI:•

Areas exposed to mist overspray from cooling water towers.•

Areas exposed to steam vents.•

Areas exposed to deluge systems.•

Areas subject to process spills, ingress of moisture, or acid vapors.•

Carbon steel piping systems, including those insulated for personnelprotection, operating between 25° F and 250° F (-4° C and 120° C). CUI is

particularly aggressive where operating temperatures cause frequent

condensation and re-evaporation of atmospheric moisture.

•

Carbon steel piping systems that normally operate in-service above 250° F

(120° C) but are intermittent service.

•

Deadlegs and attachments that protrude from insulated piping and operate at

a temperature different than the active line.

•

Austenitic stainless steel piping systems that operate between 150° F and

400° F (60° C and 204° C). These systems are susceptible to chloride stresscorrosion -----ing.

•

Vibrating piping systems that have a tendency to inflict damage to insulation

jacketing providing a path for water ingress.

•

Steam traced piping systems that may experience tracing leaks, especially at

the tubing fittings beneath the insulation.

•

Piping systems with deteriorated coatings and/or wrappings.•Locations where insulation plugs have been removed to permit thickness

measurements on insulated piping should receive particular attentions (2).

•

All equipment will be shut down at some time or other. The length of time and the

frequency of the downtime spent at ambient temperature may well contribute tothe amount of corrosion under insulation that occurs in the equipment. It would be

a daunting task to muster the resources needed to tackle this extensive list of

piping with the traditional inspection methods. This is where real-time X-ray offers

a real advantage. Once the damaged areas are identified, follow-up X-rays and

ultrasonics can measure the loss by external corrosion. These techniques will not

detect CISCC in stainless steels.

ALTERNATIVE INSPECTION METHODS

The present corrosion under insulation detection methods are: ProfileRadiography

Figure 1: Profile Radiography Exposures are made of a small section of the pipe wall.

A comparator block such as a Ricki T is used to calculate the remaining wall

thickness of the pipe. The exposure source is usually Iridium 192, with Cobalt 60

•





used for the pipes of heavier wall. (See Figure 1.)

Profile radiography is an effective evaluation method, but becomes technicallychallenging in piping systems over 10 inches (25.4 cm) in diameter and only offers

the limited luxury of verifying relatively small areas.

This technique will not detect CISCC in stainless steels. In addition, radiation safety

can be a real concern. Nobody can work within the area while the inspection is

under way, this can result in downtime and manpower scheduling conflicts.

Ultrasonic Thickness Measurement

Figure 2: UT Inspection This is an effective method, but limited to a small area. (See

Figure 2.) It is expensive to cut the insulation holes and cover the holes with capsor covers. It is not practical to cut enough holes to get a reliable result. The

inspection holes cut in the insulation may compromise the integrity of the insulation

and add to the corrosion under insulation problem, if they are not recoveredcarefully. This technique will not detect CISCC in stainless steels.

Insulation Removal The most effective method is to remove the insulation, check the surface condition

of the pipe, and replace the insulation. This approach will detect CISCC in stainless

steels; may require eddy current or liquid dye penetrant inspection. This is also the

most expensive method in terms of cost and time lost. The logistics of insulation

removal will probably involve asbestos and its attendant complications. Process

related problems may occur, if the insulation is removed while the piping is inservice.

Infrared

In the right conditions, infrared can be used to detect damp spots in the insulation,

because there is usually a detectable temperature difference between the dry

insulation and the wet insulation. Corrosion is a distinct possibility in the areasbeneath the wet insulation.

Neutron Backscatter

This system is designed to detect wet insulation on pipes and vessels. A radioactive

source emits high energy neutrons into the insulation. If there is moisture in theinsulation the hydrogen nuclei attenuate the energy of the neutrons. The

instrument's gauge detector is only sensitive to low energy neutrons. The count

displayed to the inspector is proportional to the amount of water in the insulation.

Low counts per time period indicate low moisture presence.

REAL-TIME RADIOGRAPHY

Figure 3: Fluoroscopy provides a clear view of the pipes outside diameter through

the insulation, producing a silhouette of the pipe outside diameter (OD) on a TV-

type monitor that is viewed during the inspection. No film is used or developed.The real-time device has a source and image intensifier/detector connected to a C-

arm. (See Figure 3.) There are two major categories of RTR devices on the market

today; one using a X-ray source and one using a radioactive source. Each has its

•





own advantages and disadvantages, however the X-ray systems deliver far better

resolution than the isotope type equipment (3).The X-ray digital fluoroscopy equipment operates at a maximum of 75 KV, a low

level Mdiation source, but the voltage is adjustable to Figure 3 obtain the clearest

image. This allows for safe operation without disruption in operating units or even

confined spaces. The radiation does not penetrate the pipe wall as more powerfull

gamma-ray or X-ray would, instead it penetrates the insulation and images the

profile of the pipe's outside wall. The radiation is generated electrically so theinstrument is perfectly safe when the power is off, whereas the Iridium 192 used in

wall shots produces gamma-radiation constantly, even when shielded within the

camera. Therefore the gamma-ray carnera always needs careful supervision andcontrol during all operations, including transportation and shipping. The systems

with the electrically generated X-rays are far more convenient for shipping.

The new systems come with a heads-up, video display. The helmet-mounted, visor-

type video display frees the system operator's hands so that he can maneuver the

C-arm, while keeping the image before the operator at all times. The heads-up

display also improves interpretation by shielding the screen from the sun. Thevideo images can be printed on site using a video printer or recorded using a

standard VCR for evaluation later.

PERFORMING THE INSPECTION

Using the sorting criteria listed above it is possible to prioritize a list of piping for

inspection that is manageable in a reasonable time frame. The CUI inspection crew

then inspects the pipes iso by iso. The "C" shaped arm is the actual device that is

used to scan the pipe. A cathode ray tube on one side generates the X-rays,

shooting them across to the receiver on the other side. The operator manipulatesthe arm around the pipe, guiding it by the black & white heads-up display on his

hard-hat. A typical scan will go up the pipe while moving the arm about 45° to both

sides of the track. The C-arm is then rotated 180° and the pipe is scanned

downward in a similar fashion. After rotating 90° the up and down process is

repeated.

•

RESULTS

Figure 4: Example of Rust Build-Up

Figure 5

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Figure 6 To the untrained eye, the image in the

screen would appear to indicate very serious corrosion. However, what is being

imaged is the exfoliation of the rust (See figures 4 and 5.) Performing the

inspection in this manner the inspector can inspect a considerable amount of pipein a short time.

LIMITATIONS

One of the main limitations of the system is the C-arm. There are a couple of sizes

of C-arms available. The manufacturer has had success in checking pipes up to 24

inches in diameter. These systems were not originally designed for the field but

rather for laboratory work. This limitation has been addressed and the systemsavailable today are more robust. However, they still require a lot of care and

attention. There will always be some percentage of piping where real-time X-raycan not be used. The prime example is the center lines among tightly nested

pipelines with little clearance between the pipes. Finally, while the X-rays are low

energy, they are still radiation, and so the system must be used with extremecaution

•

REAL TIME RADIOGRAPHY USES TO LOCATE PI PING COMPONENTS FOR

POSITIVE MATERIALS IDENTIFICATION PROGRAMS

Alan Wolf (2) of Exxon Research and Engineer ing Company recently wrote, "Over

the years the industry has experienced several incident failures where the rootcause was attributed to installation of improper material." He also sug gests real-

time X-ray as an effective alterna tive to insulation removal in the search for pip

ing components. Using correct procedures with real-time radiography extensivefield tests have demonstrated a 99% field reliability of detect ing circumferential

welds with a weld crown of at least 1/32 to 1/16 inch (1-2 mm). Figure 6 shows an

RTR image of a weld crown through insulation. RTR's proven ability to detect weld

crowns offers compelling testimony of the system's ability to detect CUI.

•

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