Corrosion under Insulation (CUI)

[Mohamed]

i found the following articles and i think it will be useful to share it with the forum members.
by the way i face this problem actual in my work ,and we must take care of it.

Corrosion under Insulation (CUI)

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 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 the insulation material itself. Corrosion may attack the jacketing, the insulation hardware, or the underlying equipment.
For high temperature equipment, water entering an insulation material and diffusing 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 saturated salt 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 problems possible, 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 Insulation?

The mechanism of corrosion under insulation involves three requirements:

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

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 corrosion rates 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 to cut 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 under insulation problem. Inhibitors have been tried with varying success since repeated wet / dry cycles may make inhibitors ineffective. This is an area of opportunity. However, long terms 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 the use 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 for longer term performance.

[Mohamed]

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 effect in 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 industry standard, and theregulations demand that organizations maintain a program to meet 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 corrosion under 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 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 is most 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 SUSCEPTIBLE 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 personnel protection, 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 stress corrosion -----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 to the 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: Profile Radiography
  
  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 technically challenging 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 caps or 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 recovered carefully. 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 in service.
  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 areas beneath 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 the insulation 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 the instrument 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 and control 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. The video 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 manipulates the 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
  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 pipe in 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 systems available 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-ray can 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 extreme caution

REAL TIME RADIOGRAPHY USES TO LOCATE PIPING 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 root cause 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 extensive field 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.

[mkhurram79]

Thanks Mohamed for all useful articles

[belonk_182]

Dear Mohammed,

Is Real-Time Radiogrpahy applicable to detect CUI on large pressure vessel?

Regard,
Bangkit Widayat
Inspection Engineer

[Carlos L. Goel]

Wonderful article, something we forgot to build.

[Han Ah kwang]

Reference

[link Point to another website Only the registered members can access]

[Han Ah kwang]

Control of CUI (Technical Document)

[link Point to another website Only the registered members can access]

[Han Ah kwang]

Control of CUI (Technical Document)

[link Point to another website Only the registered members can access]

[alfonzob74]

I want sharing an article about CUI.

[alfonzob74]

I want sharing an article about CUI.

[M A ElZomor]

Re: Corrosion under Insulation (CUI)

Very Useful Information
Many Thanks

[M A ElZomor]

Re: Corrosion under Insulation (CUI)

Very Useful Information
Many Thanks