ASME PRESSURE VESSELS
The scope of this presentation is to present basic information and understanding of the ASME code for the design of pressure vessels for the chemical and process industry as applicable in the United States and most of North and South America. For more information about our products, heavy plate & custom fabrication services or fabrication capabilities contact us today!
Corrosion under insulation is a hidden problem
Corrosion under insulation (CUI) is one of the costliest avoidable problems facing the hydrocarbon processing industry (HPI) today. CUI afflicts refineries— specifically, the steel piping, storage tanks, container vessels and other process equipment within the plants that are subject to extreme temperature fluctuations. Calcium silicate or mineral-wool insulation applied to the pipe or vessel can mitigate the thermal cycling effects. But the presence of seams, gaps or other discontinuities in the insulation layer makes them susceptible to infiltration by outside moisture or from the process environment itself.
Understanding the mechanisms.
CUI originates when water and contaminants infiltrate an insulated system that has certain water retention, permeability and wetability characteristics. Water sources include rainfall, cooling tower drift, steam discharge, wash downs and (because insulation is not vapor tight) condensation. Water may enter the system due to breaks in the waterproofing, inadequate system design, incorrect installation, poor maintenance practices or a combination of such factors.
Once wet, the insulation system’s weather barriers and sealants trap the water inside, so the insulation remains moist. Next to the equipment surface, the insulation forms an annular space or crevice that retains the water and other corrosive media. For example, chlorides and sulfates that may be native to the insulation can accelerate the corrosion process.
Substrates of either carbon steel (CS) or austenitic and duplex stainless steel (SS) are susceptible to CUI. In CS, CUI occurs in piping or equipment with a skin temperature in the range of 25°F to 350°F (-4°C to 175°C), where the metal is exposed to moisture over time under any kind of insulation. The rate of corrosion varies with the specific contaminants in the moisture and the temperature of the steel surface. Waterborne chlorides and sulfates concentrate on the CS surface as the water evaporates.
In austenitic and duplex SS, external stress corrosion cracking (ESCC) can occur, but the temperature threshold is higher, from 120°F to 350° F (50°C to 175°C). For ESCC to develop, sufficient tensile strength must be present. Here again, waterborne chlorides concentrate on the SS’s hot surface as water evaporates.
Why CUI is a hidden problem.
Once infiltration occurs, insulation and cladding conceal the progress of degradation to piping and equipment. Even with observation ports, less than 1% of the surface is visible, and those areas generally are not representative of the whole unit. Removal of just some insulation to complete a minor repair job can lead to the discovery of a degree of corrosion that is an unpleasant surprise and may require a facility shutdown to rectify.
Typically, insulation is removed on a 15–20 year cycle, which makes diagnosing a problem in a timely manner less likely. Yet, because in existing facilities pipes and vessels may have been put into service when coatings, insulation and refinery operating conditions were very different than they are today, it is all the more critical to promptly identify deterioration lurking on these substrates.
The evolution of the CUI problem goes back to the 1970s. Before that time, little if any thermal insulation was applied to heated CS equipment and vessels below 300°F (150°C). But as energy costs increased, it became more cost-effective to apply insulation. Concurrently, newer processes came onstream, operating at higher and often cyclic temperatures while austenitic SS pipe and equipment became more common as well. Together, these developments dramatically increased the amount of insulation used in the HPI and set the stage for CUI to become a pervasive issue.
Chronic CUI has also become a problem for reliability engineers. Major equipment outages, whether for periodic inspection and maintenance or due to a catastrophic failure, account for more operational disruptions than any other cause. Understandably, all of the major HPI companies became aware of and were concerned about the problem, with one taking the lead in thoroughly analyzing the mechanisms of corrosion and developing test protocols for protective coatings to deal with it.
Topcoating recommended Although it is common in the petrochemical and refining industries to use a shop-applied inorganic zinc (IOZ) coating as a primer on new CS piping (because it dries quickly and is cost effective), IOZ provides inadequate corrosion resistance in closed, sometimes wet, environments. At temperatures greater than 140°F (60°C), the zinc may undergo a galvanic reversal, where the zinc becomes cathodic to the CS. Shop-primed pipe will be finish-coated at the jobsite, depending on the service conditions needed.
The NACE standard recommends topcoating the IOZ to extend its service life, and that it not be used by itself under thermal insulation in service temperatures up to 350°F (177°C) for long-term or cyclic service. In cases where pipe is previously primed with an IOZ coating, it should be topcoated to extend its life.
Though valiant efforts to keep water out of insulated systems can be made using different design materials and configurations of the equipment to be insulated, CUI is not usually kept at bay on the strength of those measures alone. Industry guidance, provided by NACE International, The Corrosion Society, holds that immersion-grade protective coatings are the best defense against CUI in both insulated CS and austenitic and duplex SS. Insulated steel capable of trapping water is considered to be under immersion at 210°F (99°C) or higher.
NACE Standard SP0198-2010, “The Control of Corrosion Under Thermal Insulation and Fireproofing Materials— A Systems Approach,” reflects the latest insights in CUI prevention and mitigation from the oil and gas industry, including the products and systems available to combat CUI that have a track record of success. And many of the insights stem from the shift of oil and gas exploration, extraction and processing to offshore deepsea locations around the world.
This shift has numerous implications for those entrusted with protecting floating production, storage and offloading (FPSO) assets from corrosion, in general, and CUI, in particular. The marine environment combined with extreme process temperature fluctuations can accelerate the corrosion rate of process equipment and CS process piping and vessels under insulation by a significant factor compared to onshore assets.
Given such customer demand, the protective coatings industry has developed products that can accommodate not only extended life cycle expectations, but also the dramatic increase in steel fabrication work to produce the equipment and vessels.
Research and development is key.
Ten years ago, the typical process operating temperatures of insulated equipment were lower than they are today. Modern facilities operate at temperatures as high as 400°F (205°C), where 300°F (150°C) was more the norm previously. Although most equipment doesn’t run at the high end of the temperature design, spikes can occur for various reasons and must be taken into account when specifying the appropriate coating system. Thus, a crucial consideration when determining the appropriate protective coating system to use under insulation is the expected service temperature of the equipment or piping, especially when intermittent thermal cycling—from hot to ambient or hot to less hot temperatures—is present.
Present commercially available coatings are engineered to perform at various temperature ranges because one size does not fit all. Phenolic epoxies are for temperatures of –50°F to 300°F (–45°C to 150°C); Novolac epoxies should be applied for temperatures of –50°F to 400°F (–45°C to 205°C); and inert multipolymeric matrix coatings are best for temperatures from –50°F to 1,200°F (–45°C to 650°C).
Coatings suitable for refinery applications should perform well in testing protocols based on both accelerated and real world scenarios involving typical CUI mechanisms. Chief among these is the boiling water test, which is the gold standard for accelerated testing of heat-resistant coatings. To ensure a coating can offer superior resistance to thermal cycling, a steel panel is subjected to thermal shock in a simulated immersion scenario. The best results show no adhesion or blistering after 80 cycles of the test when applied at ambient temperatures.
But these coatings have to endure more than just corrosion. Manufacturers of second-generation CUI coatings recognize that products must address the challenges stemming from new construction. Now coatings must offer enhanced shop coating and throughput properties; durability during transportation and erection of fabricated modules; and worker friendliness in a shop environment.
This means more flexible coatings, with harder films, that deliver measurable reductions in dry-to-recoat and dry-to touch times; better impact resistance to limit damage in transport from the shop to the jobsite; and lower volatile organic compound emissions to promote worker safety. With these attributes come a reduced total cost of ownership and extended service life for high heat applications and equipment under insulation. Coatings that demonstrate these additional attributes will perform well in rigorous testing protocols based on ASTM standards for abrasion and impact resistance, such as the falling sand, Taber abrasion and pencil hardness tests. These tests are done under similar ambient temperature conditions to the ones used in the boiling water test.
Source: Hydrocarbon Processing: Special Report: Corrosion Control – March 2013
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