Back to Basics
Inspection Techniques for Detecting
Corrosion Under Insulation
by Michael Twomey*
In the past few years, I have been pointing out a new reason for going "Back to Basics." That new reason is that the basics of even our classic (standard) techniques are changing. For example, radiography now very often uses electronic imaging rather than film. That's a new basic to be learned, permitting new and valuable applications.
Frank A. Iddings
Tutorial Projects Editor
Table 1
Figures 1-3
Figures 4-6Corrosion under insulation is a real threat to the onstream 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 be 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 Rerating of In-service Piping Systems, the piping code first published in June 1993, identifies corrosion under insulation as a special concern. Typically, as happened with API 653 and the Clean Water Act, the API codes become an industry standard, and the regulations demand that organizations maintain a program to meet that standard. OSHA 1910 is the rule that ensures the standard is met.
Corrosion under insulation is difficult to find because of the insulation cover that masks the 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.
Corrosion under insulation is difficult to find because of the
insulation cover that masks the problem until it is too late.
When Does Corrosion Under Insulation Occur?
The problem occurs on carbon steels and 300 series stainless steels. On carbon steels it manifests as generalized or localized wall loss. With the stainless pipes it is often pitting and corrosion induced stress corrosion cracking. Though failure can occur in a broad band of temperatures, corrosion becomes a significant concern in steel at temperatures between 0 and 149 ºC (32 and 300 ºF) and is most severe at about 93 ºC (200 ºF). Corrosion and corrosion induced stress corrosion cracking rarely occur when operating temperatures are constant above 149 ºC (300 ºF) (Kobrin and Moniz, 1993). 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 Susceptable to Corrosion Under Insulation
API 570 specifies the following areas as susceptible to corrosion under insulation: 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 -4 and +120 ºC (25 and 250 ºF). Corrosion under insulation is particularly aggressive where operating temperatures cause frequent condensation and re-evaporation of atmospheric moisture.Other susceptable areas include: carbon steel piping systems that normally operate in-service above 120 ºC (250 ºF) but are in 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 60 and 204 ºC (150 and 400 ºF), as these systems are susceptible to chloride stress corrosion cracking; 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 attention.
All equipment will be shut down at some time or other. The length of time and the frequency of the down time 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 radiography offers a real advantage. Once the damaged areas are identified in carbon steel pipe, follow-up X-rays and ultrasonics can measure the loss by external corrosion. These techniques will not detect corrosion induced stress corrosion cracking in stainless steels.
Alternative Inspection Methods
The present corrosion under insulation detection methods are: profile radiography, ultrasonic thickness measurement, insulation removal, infrared, and neutron back-scatter.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 blowout factor for the exposure in order 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.
Profile radiography (Figure 1) is an effective evaluation method, but becomes technically challenging in piping systems over 250 mm (10 in.) in diameter and only offers the limited luxury of verifying relatively small areas. This technique will not detect corrosion induced stress corrosion cracking on stainless steels. In addition, radiation safety can be a real concern. Nobody can work within the area while the inspection is underway. This can result in downtime and personnel scheduling conflicts.
Ultrasonic Thickness Measurement. This is an effective method (See Figure 2), but limited to a small area. 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 corrosion induced stress corrosion cracking on 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 corrosion induced stress corrosion cracking on stainless steels and may require eddy curent or a liquid 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 work 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 gage 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
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 (Figure 3). There are two major categories of real time radiography devices on the market today, one using an 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 (Wolf, 1995).The X-ray digital fluoroscopy equipment operates at a maximum of 75 KV, a low level radiation source, but the voltage is adjustable to 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 powerful 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 camera 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 to 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.
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 600 mm (24 in.) 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 radiography cannot 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.
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 corrosion under insulation inspection crew then inspects the pipes iso by iso.The C-shaped arm is the actual device 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 and white heads-up display mounted on a hardhat. A typical scan will go up the pipe while moving the arm about 45 degrees to both sides of the track. The C-arm is then rotated 180 degrees and the pipe is scanned downward in a similar fashion. After rotating 90 degrees, the up and down process is repeated.
Results
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.
Real Time Radiography Used to Locate Piping Components for Positive Materials Identification Programs
Alan Wolf (1995) of Exxon Research and Engineering 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 suggests real time X-ray as an effective alternative to insulation removal in the search for piping components. Using correct procedures with real time radiography extensive field tests have demonstrated a 99 percent field reliability of detecting circumferential welds with a weld crown of at least 1-2 mm (0.04-0.08 in.). Figure 6 shows a real time radiography image of a weld crown through insulation. Real time radiography’s proven ability to detect weld crowns offers compelling testimony of the system’s ability to detect corrosion under insulation.
Definition of Terms
Cobalt 60: Nuclear isotope that emits gamma radiation with far greater penetrating power than iridium 192. Used to expose radiographic film.Comparater block: A steel object such as a steel ball or block used to calculate the "blow-out" factor for distortion on a radiograph of a wall pipe. The "blow-out" factor is then used to calculate the true thickness of the pipe wall.
Deadleg: Section of piping of a system where there is no product flow and therefore has different corrosion characteristics.
Fluoroscopy: Real time X-ray system based on the principal of fluorescing screens.
Gamma radiation: Photons or packets of energy emitted from certain nuclear isotopes such as iridium 192 or cobalt 60.
Iridium 192: Nuclear isotope that emits gamma radiation. Used to expose radiographic film.
Ricki T: A type of comparison block used to calculate the "blow-out" factor for distortion on a radiograph of a pipe wall.
X-ray: Photons or packets of energy emitted from the cathode ray tube of an X-ray unit when the cathode is bombarded with electrons.
References
Kobrin, G., and B. Moniz, "Inspection, maintenance and prevention of corrosion of piping under thermal insulation," First International Symposium on Process Industry Piping, December 14-17, 1993, Orlando, Florida, sponsored by NACE International and MTI.Wolf, H.A., "Positive materials identification of existing equipment," Second International Symposium on Mechanical Integrity of Process Piping, 1995. MTI Publication No. 48.
- * CONAM Inspection Inc., 1247 Norwood Avenue, Itasca, IL 60143-1124; (630) 773-9400; fax (630) 773-6519.
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