COATING APPLICATION CASE HISTORIES, BOTH GOOD AND BAD

Examples   

Example 1

Corrosion Under Mineral Wool Insulation. During a 2003 turnaround in a major Gulf Coast refinery, several units in a large crude processing block underwent a thorough CUI inspection.  Mineral wool insulation originally installed when the unit was built in 1975 was removed for visual inspection.
Coatings were present in most cases, but they were not immersion grade coating.  Of 18 pressure vessels inspected for CUI or CUF (corrosion under fireproofing), all were found to have  suffered CUI, two were found to have CUF in addition to CUI, and 12 vessels required weld buildup to restore minimum wall thickness.

Example 2

Corrosion Under Mineral Wool Insulation.  Heat exchanger in a major Gulf Coast refinery.  A critical service shell and tube heat exchanger was found to have suffered severe CUI.  Mineral wool insulation retained wetness in multiple areas along the bottom of the shell.  The coating was from  original construction and was not an immersion grade coating.  It was typical practice to install mineral wool blanket encased between two layers of wire mesh to allow for better handling.  Poultry netting and other square shaped wire mesh have been used.  After removal of the insulation, a small seepage type leak began in two locations.  The exchanger could not be removed from service without shutting down a large part of the refinery.  Because the  service was not flammable, a mitigation method involving rolled steel plates, each fitted with drain tubes and adhered to the vessel, then installation of a fiberglass wrap was utilized to protect vessel from further corrosion and route the drip type leakage to a safe location.

Example 3 

CUI on Red Lead Primer Steel Surface.  A pressure vessel built in 1975 and originally  7
coated with red lead primer was stripped of its mineral wool insulation for visual inspection in 2003. The vessel operates continuously at 125ºF (52ºC).  Because the non-immersion grade coating remained continuously wetted under the water absorbent mineral wool insulation, the resultant corrosion was extreme.  Technical analysis, based only on the depth of pits measured before complete removal of rust scale, resulted in a decision to replace the drum.  Replacement of the drum required shutdown of a  tower, installation of jumpover piping, and a unit slowdown of several days length.  After removal from service, further examination revealed external metal loss in excess of 0.5 in (13 mm).  It was determined that the new drum did not require insulation. It was noticed that the red lead primer was still intact in places. The light area in the lower right is the saddle. Looking up at the side of the vessel shell revealed horizontal grooves caused by corrosion at the locations where the wire mesh was in direct contact with the vessel. The authors believe the wire mesh was austenitic stainless steel. This area was directly beneath the location of water entry into the insulation.  

Case Histories   

Case 1

Wastewater Towers.  In 1991, two wastewater towers in a major Gulf Coast refinery near  Houston, Texas, were stripped of their old insulation to be recoated and reinsulated.  The towers operate continuously and uniformly along their height at 250ºF (121ºC).  At the time of application of two coats of epoxy phenolic, the steel temperature measured 190ºF.  At this point in history, there were no specialty coatings formulated for application to hot steel surfaces.  A "slow" thinner was used to help reduce dry spray.  After the coating application, the towers were re-insulated with expanded perlite insulation.  Recent inspection of the exposed manway covers and under the insulation through ports intended for ultrasonic thickness measurements revealed the coating is in very good condition.  No cracking, flaking or other signs of degradation were observed.

Case 2

Debutanizer Tower.  In June of 1990, a debutanizer tower in southern Louisiana was stripped of its thermal insulation for inspection. The tower operates at 180º-280ºF (82-138ºC), a critical region for CUI.  The tower was insulated with calcium silicate and mineral wool insulation in different areas.  It was found to be water saturated with a poorly maintained mastic and wire weather barrier.  The steel substrate was severely pitted in some areas.  The steel was abrasive blast cleaned to SSPC SP-10 and coated with a 2-coat solvent borne epoxy phenolic system.  The vessel was reinsulated with expanded perlite block and aluminum jacketing.  After 9 years of operation, the tower was recently stripped of the insulation and inspected as part of an ongoing CUI inspection program.  The epoxy phenolic coating was found to be in excellent condition.  Although rust staining was noted at support brackets for platforms and other appurtenances, this was found to be blast abrasive and debris which remained in contact with the intact coating.  Apparently, debris from the scaffolding and other access structures fell onto and collected on some surfaces, after they were properly painted but was not removed prior to installation of the new thermal insulation.

Case 3

Coating Applied on Marginally Prepared Steel Surface.  Some coating manufacturer claim their organic coatings are not only suitable for under insulation environments, but that they may also be applied to marginally prepared steel.  Usually, this means that grit blasting is not required and that  tightly adhered rust may be left on the steel.  It is common practice for such coatings to be tested on steel coupons of similar condition at the service temperature.  It is also important to know whether the steel to be coated is contaminated and the nature of the contaminants to assure that the test conditions accurately represent the actual steel to be protected.

A refinery in Asia experimented with an organic coating that was claimed to be applicable to non-blasted, rusted steel.  After 2 years of operation under insulation, the coating exhibited complete failure due to lack of adhesion.  The coating also exhibits signs of heat degradation,

CONCLUSIONS    

Risk based inspection strategies and evolving NDE technologies are critical tools in an effective CUI inspection undertaking.  In addition, an understanding of history is important to assure undesirable events are not repeated.

In the case of CUI, this is recognition that:

• Water will almost always get into insulation systems 
• Absorbent insulation will exacerbate the corrosion 
• Coatings selected for protection from CUI on hot or cold steel surfaces under insulation must be proven to resist the "hot and wet" or "cold and wet" conditions which exist for very long periods under insulation 
• Surface preparation and application must be quality assured to assure the selected coating is capable of the desired long term corrosion protection 

Source;http://wenku.baidu.com/view/9307622a915f804d2b16c1c2

COATING APPLICATION "DO'S AND DON'TS"

Do's and Don'ts 

Even the right coatings are often doomed to failure before they are applied.  There are many reasons for this, such as:

• Over reliance on the contractor.  Plants usually do not employ anyone with this specialty expertise and so there is an over-reliance on the contractor for coating material selection and specification writing.  Although many industrial coating contractors are sufficiently  knowledgeable regarding correct surface preparation and coating application, the contractor usually does not have adequate background or knowledge of how the equipment will operate, what the specific jobsite scenario will involve, and the condition of the steel surfaces to receive the coating.
• Lack of information on the equipment condition and anticipated range of operating temperature.  Is the steel surface heavily corroded or pitted?  Will it be in cyclic or intermittent service?  Will it operate below the dewpoint?   
• Lack of information regarding on-site restrictions on methods of surface preparation.  Will dry abrasive blasting be allowed?  What means of protection from grit and dust would allow use of abrasive blasting?  What is the cost of this? 
• Lack of a detailed written coating specification  
• Lack of a pre-job meeting where all parties review the specification and come to agreement on timing, scope, materials, method(s) of surface preparation, method(s) of coating  application, special needs regarding protection from weather, special needs regarding work on vessel or piping while in operation, inspection hold points 
• Lack of third party inspection

All of these details can result in confusion on the contractor's part, improper selection of the coating material, improper surface preparation and coating application, or all of these.  We have found that problems result most often from inadequate flow of information and details.  Plant personnel often do not understand what details are necessary to draft the specification, nor is there typically the correct expertise readily available to gather the information, select the proper coating material and draft the specification

Source:http://wenku.baidu.com/view/9307622a915f804d2b16c1c2

Signs and Symptoms

Corrosion is perhaps one of the more obvious signs of plant ageing because of visible signs of corrosion product, either external or internally within equipment. The nature of many materials, especially carbon and low alloy steels, is to react with the environment by a corrosion process to attain a more stable condition, e.g. metallic iron “wants” to become iron ore again.

Many equipment items take account of this in the design process e.g. corrosion allowance so it is important to note that the presence of corrosion products, i.e. rust, does not indicate that equipment is not fit for its service. Rust is merely a sign that the equipment is ageing. The rate of this ageing process and its importance in risk terms are parameters the plant operator should be concerned with.

Susceptibility 

All metallic materials are susceptible to corrosion and/or corrosion cracking. Materials termed

“corrosion resistant alloys” or CRAs are less susceptible but not immune. This class nof materials are protected by a corrosion process that forms a thin layer of metal oxide at the  surface. Should the layer be damaged in an environment that does not support re-oxidation, then the material can become susceptible to corrosive attack.

Management Options 

Corrosion can be prevented or monitored and controlled. Prevention methods include 

coatings and/or cathodic protection (often termed “CP”). CP can be achieved either by the 

use of impressed currents or by connection of sacrificial anodes typically made from zinc or 

aluminium blocks. If coatings are used there should be evidence of coatings inspection and 

if CP is employed evidence of maintenance and monitoring of CP effectiveness should be 

available. 

For monitoring and control, management of corrosion is achieved through the following 

processes: 

• Identification 

• Detection 

• Quantification 

• Assessment 

Identification usually involves a risk assessment, e.g. RBI plan or may take the form of asset 

registers arranged to identify those equipment items that are expected to corrode in one way 

or another. Detection is the application of a suitable inspection technique, often visual, that can locate the corrosion. 

Quantification is achieved by measuring the remaining thickness of material available to 

contribute to the overall structural integrity of the equipment. In some instances, engineering 

judgement is applied but this should be documented to a sufficient extent that reasonable 

next inspection intervals can be deduced. 

Source:http://www.hse.gov.uk/offshore/ageing/ageing-plant-summary-guide.pdf

Specific Types of Common Corrosion

Carbon Dioxide (Sweet) Corrosion 

Carbon dioxide dissolves in water to form carbonic acid which causes what is known as
sweet corrosion. The product of this form of corrosion is iron carbonate which forms as a film
on the metal surface. At higher temperatures (+80oC) this film has protective qualities leading
to lower than expected corrosion rates at higher temperatures. Sweet corrosion is typically
observed as metal wall thinning and shallow pitting. Under high velocity conditions deep
elongated pits are sometimes observed.

Hydrogen Sulphide (Sour) Corrosion 

Hydrogen Sulphide dissolves in water to cause what is known as sour corrosion. The product
of this form of corrosion is iron sulphide. The low solubility of iron sulphide in water results in
the formation of a dark or black corrosion product film that is able to protect the steel surface
from general corrosion even in aggressive systems. However due to the conductive nature of
the protective film any local break in the iron sulphide layer can result in very severe pitting.

Hydrogen sulphide may also cause hydrogen damage in susceptible steels. The reaction
which gives rise to the iron sulphide film releases atomic hydrogen which can then diffuse
into the steel where it can lead to the formation of hydrogen blisters or through wall cracking
(Sulphide Stress Corrosion Cracking or Stress Oriented Hydrogen Induced Cracking).

Microbial Corrosion 

Microbial corrosion is caused by the action of bacteria contaminated systems, commonly sulphate reducing bacteria (SRB’s). It is not the bacteria themselves that attack the metal but the local environments that they create and contribute to that leads to corrosion of the structure. Microbial corrosion is typically a problem inside pipes which are left with stagnant water, at dead legs and in the bottom of tanks. For microbial corrosion to occur conditions must be suitable to support bacterial life. These requirements include: 

• Presence of bacterial life in the system. 
•  Source of Sulphate. 
• Source of Carbon. 
• Source of water. 
• Anaerobic conditions. 
• Close to Neutral pH. 
• Suitable temperature and pressure for bacterial life to be sustained. 

Atmospheric Corrosion 

Moisture, oxygen and aggressive species such as sulphate, nitrates and chlorides present in 

the atmosphere can lead to atmospheric corrosion occurring on exposed structures. 

Atmospheric corrosion proceeds under the same mechanism as wet corrosion however as a 

bulk liquid phase is only present during rainfall the corrosion reactions proceed in a thin film 

of condensed or absorbed moisture on the metal surface. 

The major factors that affect the rate of atmospheric corrosion at a given location are the 

moisture levels and the concentrations of aggressive species in the environment. Marine 

environments for example with high levels of chlorides present would exhibit significantly 

greater corrosion rates than inland environments with low levels of chloride. Similarly 

exposed metal structures in industrial locations with high levels of pollution and therefore 

higher levels of sulphates and nitrates than rural locations would record higher atmospheric 

corrosion rates than would be observed in rural locations. 

Source:http://www.hse.gov.uk/offshore/ageing/ageing-plant-summary-guide.pdf

Common forms of localised offshore corrosion

Pitting corrosion 

Pitting is an extremely localised form of attack where the wall loss is confined to a very small
area of the surface. The conditions within the pit can quickly become increasingly aggressive
causing corrosion pits to rapidly advance through the wall thickness whilst the vast majority
of the pipe or vessel wall remains unaffected. This can lead to very rapid failures as the pit
quickly penetrates the wall. This form of attack is one of the main forms of corrosion
observed in corrosion resistant alloys, however it is also found with corrosion of carbon
steels.

Crevice corrosion 

Crevice corrosion is similar to pitting corrosion, in that it is likely to be observed under the
same environmental conditions that have given rise to pitting. In crevice corrosion the area of
localised attack is found within crevices which typically form around and under washers, bolts
and seals. The solution within the trapped pocket can become increasingly aggressive and
significant localised attack can occur around the crevice.

Galvanic corrosion 

Galvanic corrosion occurs at the junction of two dissimilar metals which are in electrical
contact with each other. According to their relative positions within the galvanic series one
metal will be protected from corrosion at the expense of the other. Depending on the relative
surface areas of each metal this form of corrosion can proceed extremely quickly. If the
cathodic metal is much larger than the anodic metal surface then the observed corrosion
rates can be extremely high as a large cathodic area is driving corrosion at a relatively small
anodic point.

Source:http://www.hse.gov.uk/offshore/ageing/ageing-plant-summary-guide.pdf

Type of CUI inspections: Pulsed Eddy-Current (PEC)

Assessing condition of pipework and pressure vessels under insulation can be advantageous to plant operators. The Pulse Eddy Current (PEC)  system was developed as a solution to the detection of corrosion under insulation (CUI) and validated by Shell Global Solutions.

Compared with conventional eddy-current testing, pulsed eddy-current inspection requires no direct contact with the object being tested. Measurements can be made through any material not conducting electricity including coatings, insulation materials, weather sheeting and even corrosion
products. It is a very useful characteristic that also enables high temperature non-destructive testing (NDT) inspections.

Inspection approach

The PEC instrument probe is placed against the metal weather sheeting (non-ferrous) of the insulated pipe or vessel. The geometry of the test object should be simple. A magnetic field is created by placing an electrical current in the transmitting coil of the probe. This field penetrates through the weather sheeting and magnetizes the pipe wall. The electrical current in the transmission coil is then
switched off, causing a sudden drop in the magnetic field.As a result of electromagnetic induction, eddy-currents will be generated in the pipe wall. The eddy-currents diffuse inwards and decrease in strength. The rate of decrease of the eddy currents is monitored by the PEC probe and is used to
determine the wall thickness.

Comparison with ultrasound wall thickness measurement

Both pulsed eddy-current and ultrasound wall thickness measurement have strong and weak points. The relevance of these strengths and weaknesses varies greatly from application to application.

Benefits at a glance

• ƒNo loss of production, as inspection can take place while the inspection object is in service.
• ƒReduced inspection costs, as insulation material does not need to be removed.
• Significantly lowered costs for underwater inspections.
• Speedy inspection, as surfaces do not require any preparation.
• Good reproducibility of PEC readings at the same locations.
• Plus minus 10% accuracy for corrosion detection under insulation and only plus minus 0.2% accuracy for corrosion monitoring.
• Inspections within a temperature range from -100°C to 550°C (-150°F to 1000°F).
• Inspection of objects with a wall thickness of 3 to 35 millimeter.
• Inspection of objects with a pipe diameter above 75 millimeter.

Areas for application

Pulsed eddy-current can be effectively applied for corrosion 

monitoring and detection on pipes and vessels made of 

carbon steel or low-alloy steel without making contact with 

the steel surface itself.

ƒInsulated and/or coated equipments

• ƒ Objects under high temperature conditions
• ƒ Heavy corroded equipments
• ƒ Offshore risers and caissons
• ƒ Objects behind concrete fireproofing
• ƒ Laminations
• ƒ Annular rings
• ƒ Bridges

Source: http://www.tuv.com/media/corporate/industrial_service/NDT_Pulsed_Eddy_Current_TUV_Rheinland.pdf