Monday, December 22, 2014

Fireproofing Materials

Concrete
The excellent fire protection afforded by concrete has been demonstrated time and time again over 90 years of experience in the petrochemical industry. The high mass and low thermal conductivity of concrete make it very effective at reducing heat input to the underlying structure. Poured-in-place concrete, using forms, is common for columns and beams. Gunite is pneumatically applied to spheres and other structures where the use of forms for poured-in-place concrete is impractical. The principal drawback with gunite application is that it can be very messy.

Post-fire inspections have shown that concrete spalls to various degrees but the general conclusion is that concrete/gunite performs satisfactorily with the steel structures well protected. Wire reinforcement is commonly used. Reinforcement does not prevent cracking and spalling of the concrete but it does minimize the loss of fractured material during a fire exposure.
Excellent Fire Endurance of 30 Year Old Concrete
A refinery fire initiated at a gas oil line from a crude distillation unit and burned for about 12 hours. The main pipe rack near the crude tower at the center of the fire was damaged beyond repair. The support structure for the crude tower overhead equipment was severely damaged.

The aluminum jacketed thermal insulation on vessels and exchangers was destroyed (aluminum melts at about 660°C) but most pressure vessels and heat exchangers, showed no visible signs of permanent damage, primarily due to the cooling effect of liquid contents. Gaskets that had been damaged and high strength bolts that had been tempered by the fire exposure, had to be replaced.

Thermal expansion and contraction on structural support columns near ground zero caused a good deal of cracking and de-lamination of the concrete fireproofing; however, no evidence of deep damage to the concrete was found. The main concern was for the support structure of the crude distillation tower as the refinery is located in a seismic zone.
The radiant heat and direct fire exposure caused spalling of the 30 year old concrete cover on the exterior of the vessel skirt. Firewater cooling added to the spalling problem. Some rebar was exposed at the crude tower foundation, most notably on the side of the tower that faced the fire. Concrete was removed for inspection of the crude tower skirt and anchor bolts. No heat buckling of the skirt or distortion of the bolt seatings was observed. Bolts were checked for cracks and hardness measurements were made to confirm strength. The concrete fireproofing had prevented any permanent damage to the vessel skirt and anchor bolts. The 30 year old concrete was now a mess but it had served its function.

Source:http://www.wermac.org/materials/fireproofing.html

Wednesday, December 17, 2014

Why Fireproofing is used?

Why Fireproofing is used?

Typically, fireproofing is designed to protect the structural steel which supports high risk or
valuable equipment. The failure point is generally considered to be 1000°F, as this is the point where steel has lost approximately 50% of its structural strength. The aim then, is to prevent structural steel from reaching 1000°F for some period of time. Tanks, pressure vessels, and heat exchangers may experience a significant cooling effect from liquid contents and so, less fireproofing protection is generally required. Some thermal insulation systems may serve a dual role as fireproofing and this is common with some pressure vessels. Piping may be insulated but it is not generally considered to be fire proofed.

Fireproofing needs to be durable to survive the rigors of every day life in the plant so that if and when a fire does occur, the fire endurance properties have been maintained and the fireproofing can be depended on to function satisfactorily. Everyday exposure may involve mechanical abuse, exposure to oil, solvents, and chemicals, and outdoor weathering for prolonged periods of twenty, thirty, forty years or more. As a coating for steel, fireproofing may provide a good measure of corrosion protection. When applied directly to steel, concrete may passivate the steel surface by providing an elevated pH. Experience has shown, however, that passivation is less than certain, especially in coastal marine environments. Corrosion under concrete fireproofing can be significant. Intumescent coatings promise better corrosion protection than concrete by virtue of their low permeability but cases of severe corrosion under fireproofing (CUF) have been reported with these materials.
Intumescent epoxies are complex proprietary materials. Concrete and some of the other materials that are used for fire protection are more familiar. The materials themselves may seem simple, but the important details of system design are often overlooked.

Risk-Based Analysis

Fireproofing is a misnomer because no material is completely fireproof. All construction materials are subject to fire damage. What we really mean is fire resistant - we seek to resist potential fire situations for a given period of time. Fireproofing is passive, built-in protection that buys time to fight the fire, shut off the fire's fuel supply and shut down the process. The aim is to minimize the overall damage incurred.
The decision to fireproof is driven by risk-based analysis. One needs to first consider the nature of the fire threat and then make an assessment of the required period of fire endurance for a wide variety of equipment including structural steel, pressure vessels, heat exchangers, pipe supports, LPG spheres and bullets, valves, and cable trays. The location of specific equipment within a process unit is important, as is a unit's location with regard to neighboring facilities.

Test Methods and required Time Rating

No fire test method is going to be typical of a real fire situation and so, there is no single correct or "best" fire test method. Standardized testing simply provides a frame of reference for relative comparisons of fireproofing materials and designs.
In the 70s, ASTM E119 "Fire Test of Building Construction Materials" was the only internationally accepted standard for investigating the performance of fireproofing materials. This test method, however, was designed to measure the fire performance of walls, columns, floors, and other building members in solid fuel fire exposures. It does not simulate the high intensity of liquid hydrocarbon-fueled fires.
Where fireproofing is required, the level of fireproofing varies with the application in the plant. Typical protection requirements for a refinery or petrochemical plant might be as follows:

  • For structural steel, a facility may require a fire test rating of two or three hours. Poured-in-place concrete or gunite is most common with a specified minimum thickness of 2.0 to 3.0 inches (50-75 mm). Lightweight cementitious products may also be used.
  • For steel vessels, a facility may require a fire test rating of one to two hours. Gunite applied at 1.5 to 2.0 inches (40-50 mm) may be required. Alternative fireproofing materials that provide a comparable fire resistance rating may be used, including systems that function as both thermal insulation and fireproofing.
  • Plate and frame exchangers are a special concern because of the rubber gasketing material between plates. These exchangers are provided with a protective enclosure designed to prevent the exchanger from exceeding its maximum operating temperature for an hour or so. The maximum operating temperature is vendor specified and typically less than 300°F (150°C).
  • Electrical and pneumatic components (including manual initiators, valve actuators, aboveground wiring, cable, and conduit) essential to emergency isolation, depressurization, and process shutdown are generally fireproofed to achieve a rating of at least 15-20 minutes. This equipment needs to function properly in the first few minutes of a fire

Source:http://www.wermac.org/materials/fireproofing.html

Monday, December 15, 2014

Introduction to Fireproofing

Fireproofing, a passive fire protection measure, refers to the act of making materials or structures more resistant to fire, or to those materials themselves, or the act of applying such materials. Applying a certification listed fireproofing system to certain structures allows these to have a fire-resistance rating.

The term fireproof does not necessarily mean that an item cannot ever burn: It relates to measured performance under specific conditions of testing and evaluation. Fireproofing does not allow treated items to be entirely unaffected by any fire, as conventional materials are not immune to the effects of fire at a sufficient intensity and/or duration.

Fireproofing is employed in refineries and petrochemical plants to minimize the escalation of a fire that would occur with the failure of structural supports and the overheating of pressure vessels. The damage that fire could potentially do very early on, could add significant fuel to the fire.

The purpose of fireproofing therefore, is to buy time. The traditional method of fireproofing has been poured-in-place concrete or gunite. Other fireproofing materials, such as lightweight cements, prefabricated cementitious board, and intumescent coatings are used to a lesser extent, primarily in areas deemed less critical and where weight reduction is a significant benefit.

Source:http://www.wermac.org/materials/fireproofing.html


Friday, December 12, 2014

The Keys to Beating Corrosion: Early Detection and Expert Monitoring

As every industry professional knows too well, corrosion is a relentless and ever-present concern for the chemical process industry (CPI). 

In fact, corrosion is the main contributing factor to:
•Increased production costs
•Health and safety risks
•Environmental issues, and
•Legal liabilities. 

With the spread of corrosion presenting a daily threat in the CPI (Chemical Process Industries), it is important to constantly inspect and monitor equipment for early signs of corrosion to prevent costly repairs or equipment failure later.

The effects of corrosion are startling:

•“As of 2014, the annual cost of corrosion in the U.S. is estimated to be about $1 trillion (about 6% of the gross domestic product).”
•“For the petrochemical sector, the annual cost is about $1.7 billion.”
•“The annual cost in the CPI is over 8% of the annual plant capital expenditures across these industrial sectors.”
Not only does corrosion cost the CPI substantial amounts of money, it also reduces the operating life of equipment, which in turn reduces the value of assets. There are many different methods to inspecting corrosion. The following methods help to locate the problems and can keep you aware of the type and location of corrosion.

Methods of detecting corrosion:

100_6376
•API Visual Inspection
•Magnetic Particle Flaw Detection
•X-Ray
•Ultrasonic Inspection
•Dye Penetrants
•Remote Visual
•Bracelet Probe (CUI)
•EMAT
•Moisture Detection (CUI)
•Eddy Current
•Risk Based Inspection (RBI)

Monitoring corrosion is used to closely watch areas with signs of corrosion in all critical components. There are also several methods for monitoring corrosion.
EMAT-Guided-Wave-Inspections2

Methods of monitoring corrosion:

•Ultrasonic Testing
•Radiographic Testing
•Guided Wave Testing
•Electromagnetic Testing
•EMAT
•Advanced Laser Testing (ALT)
•X-Ray (Computed Radiography)

Source:http://www.advancedcorrosion.com/latest/the-keys-to-beating-corrosion-early-detection-and-expert-monitoring


Friday, December 5, 2014

Cost of Corrosion Annually in the US Over $1 Trillion

Corrosion will cost the US economy over $1 trillion in 2014. That’s one of the largest expenditures NACE Corrosion Costs Study. However, this report leaves out the enormous (at least as much as direct costs) tally of indirect costs that the consumers experience from corrosion and the inflation increases since 1998.
we make, and it’s all going down the drain. The total annual corrosion costs in the U.S. rose above $1 trillion in the middle of 2013, illustrating the broad and expensive challenge that corrosion presents to equipment and materials. The most commonly quoted figure for corrosion costs is $276B in 1998 and was reported in the
From $276B to $1 Trillion: Understanding the Real Cost of Corrosion
The NACE sponsored report examines each industry in depth, providing discussions of the causes, costs, and results of corrosion, and arrived at a figure of $276B in direct corrosion costs. Indirect costs were estimated to be at least as much as direct costs.  In the 15 years that have passed since the study was released, inflation has driven both the direct and indirect costs of corrosion over $500 billion annually, totalling over $1 trillion in 2013.
At over 6.2% of GDP, corrosion is one of the largest single expenses in the US economy yet it rarely receives the attention it requires. Corrosion costs money and lives, resulting in dangerous failures and increased charges for everything from utilities to transportation and more. For a more thorough breakdown of specific corrosion costs by industry, see the NACE Corrosion Costs Study(and approximately double the numbers to have a good estimate of current values).
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About the author: Dr. Jackson is part of G2MT Labs, a company at the cutting-edge of new technologies that promise to dramatically reduce the costs (both economic and social) of corrosion.  
source:http://www.g2mtlabs.com/corrosion/cost-of-corrosion/

Monday, November 17, 2014

Is There A Cure For Corrosion Under Insulation?

Most facility managers, engineers, and maintenance and construction personnel now know that corrosion under insulation (CUI) exists and, left to its own devices, can cause serious problems and even catastrophic consequences.

It is also widely known that the results of CUI are costly. How costly? That is harder to define. Most studies on the topic involve all forms of corrosion and their associated costs without providing the individual cost of corrosion related to insulation.

What is clear, however, is that the cost of corrosion in the United States continues to increase. A study completed in 2001 by a research team of corrosion specialists enlisted by Congress titled, "Corrosion Costs and Preventative Strategies in the United States" reported the direct cost of corrosion to be $276 billion per year, with that number potentially doubling when indirect costs are also considered. Compare this to the first study conducted in 1975, which established the benchmark cost of corrosion at $70 billion. Factoring in inflation, this is actually an improvement if the data are compared to the gross domestic product, with 3.2 percent for 2001 versus 4.2 percent for the 1975 study.

CUI is typically difficult to identify because it lies hidden under insulation material, often until it becomes a serious problem. It is also expensive to inspect for or repair since that usually requires inspection by radiography, ultrasonic or other forms of inspection but in most cases requires the removal of the insulation system. This is especially true if the removal involves material with asbestos. A study done by ExxonMobile Chemical and presented to the European Federation of Corrosion in September 2003 indicated that:
  • The highest incidence of leaks in the refining and chemical industries are due to CUI and not to process corrosion;
  • Most piping leaks (81 percent) occur in diameters smaller than 4-inch nominal pipe size; and
  • Between 40 and 60 percent of piping maintenance costs are related to CUI.
Finally, one of the largest chemical manufacturing companies in the world, E.I. DuPont de Numours and Company, estimates that the direct cost of CUI repairs and replacements well exceeds $10 million per year, which does not include normal preventative maintenance costs and indirect costs like loss of production and revenue. This is especially revealing since DuPont is known internationally as a company with world-class facility engineering, maintenance and workplace safety. Adding to this problem is the accepted belief that industrial facilities in the United States are aging, being operated and maintained by fewer personnel, and funded by reduced budgets.

It can therefore safely be determined that CUI remains a large problem for industry, even if it is not clear exactly how big the problem is today.

For CUI to form there must be two basic ingredients: moisture and warm temperatures. For iron products like carbon steel piping and equipment, oxygen is also needed. To have chloride stress corrosion (SCC) of 300 series stainless steel, there also must be the presence of chloride ions. Obviously, oxygen is fairly easy to find, but, maybe surprisingly, so are chloride ions, which are available in a great number of places from seawater, drinking and process water, and chloride chemical compounds to roadway de-icing salts. The presence of acids, acid gases, and bases like caustics and salts also can create and accelerate corrosion.


Source:http://www.insulation.org/articles/article.cfm?id=IO051101

Monday, November 10, 2014

When is it cost-effective to use thermal spray in petrochemical facilities?

Typically, thermal spray coatings are cost-effective in the petrochemical industry when you consider the cost of inspection, especially under insulation.

Even the best, most expensive paints must be inspected in 3-7 year cycles when used in CUI (Corrosion Under Insulation) conditions. Inspections most often mean scaffolding, removing all cladding and insulation, intensive inspection, including a lot if UT testing of pits, blasting, painting, re-insulating, re-cladding, removing scaffolding, etc. If thermal spray aluminum (TSA) is used instead of paint, these inspection cycles are pushed out to 25 years (ExxonMobil) to 40 years (Shell).

In this case, blasting and recoating is not required, just inspection, as it is known that a properly installed anodic TSA coating system will not corrode or “sacrifice” itself unless it is installed in such a way that the TSA has to provide anodic protection for a large cathode (unfavorable anode to cathode ratio) when an electrolyte (water or wet insulation) connects the TSA to a non-TSA coated area. We don’t do this in the petrochemical field, as we coat an entire vessel, column, or pipe (flange to flange) instead of just a tiny area and expect it to protect the entire structure.

Regarding the cost of thermal spray in a refinery, one must consider the entire erected costs (scaffolding, cladding, insulation, grit blasting and disposal, etc.) of a coating job and not just “the coating.”

Around 6 years ago, ExxonMobil reported that when the entire erected costs are considered, TSA coatings cost them 0.5%-1.5% more than liquid coatings; however, some of the paints used in CUI service have doubled and tripled in price since then. Many times, thermal spray can be applied at lower costs than wet paint when you consider factors like weather conditions, no VOC regulations, ease of or less need for touch-up, robust coatings that can be applied offsite and then installed, etc. As a pipeline applicator who did both wet paint and thermal spray coating, we charged less for thermal spray than a three-coat paint system.

Source:From James Weber of Sulzer Chemtech Tower Field Service on November 17, 2011

Monday, November 3, 2014

Case Study: Washington State Issues Record Fine in Tesoro Refinery Explosion


The Washington Department of Labor & Industries (L&I) determined that the explosion that killed seven workers at the Tesoro petroleum refinery in Anacortes, Washington could have been prevented. L&I fined the company $2.39 million for 39 “willful” violations and five “serious” violations of state workplace safety and health regulations. This is the largest fine in the agency’s history.

A heat exchanger at the refinery ruptured around 12:30 a.m., April 2, 2010, releasing hydrocarbon vapor that then ignited. The incident occurred during maintenance on the Naphtha Hydrotreater (NHT) process unit. During routine operations involving an on-line switching of unit heat exchanger feed trains, a feed-effluent heat exchanger catastrophically failed, due to high temperature hydrogen attack (HTHA), releasing a hot, pressurized flammable hydrocarbon/hydrogen mixture. Seven workers, five men and two women, died as a result. It is the worst industrial disaster in the 37 years that L&I has been enforcing the state’s workplace safety law, the Washington Industrial Safety and Health Act. 

The heat exchangers were nearly 40 years old and were subjected to extreme heat and pressure, wide temperature and pressure swings, extensive chemical exposure and a near doubling of production over the years. These are all stresses that can damage this equipment, including causing cracking.


Source:http://www.corrosionblog.com/2010/10/washington-state-issues-record-fine-in.html

Tuesday, October 28, 2014

For corrosion to occur, four conditions must be met simultaneously...

  1. Operating temperatures in the range of 100°F – 300°F (38°C – 149°C)
  2. Oxygen
  3. Water must be present.  This water must be liquid water, not water vapor.  Water vapor does not contribute to corrosion.
  4. Corrosive chemical(s)

If one of the above conditions is absent, corrosion will not occur; all four are required simultaneously. In a very large number of cases in industrial settings, the operating temperatures of pipes and equipment are above the 300°F (150°C) range.  Therefore, corrosion is not a worry on a day-in and day-out basis.  But the reality is that industrial equipment is periodically shut down for maintenance.  The shutdown process will take the equipment through the critical temperature range window of 100°F – 300°F (38°C – 149°C) initially as the unit is shut down, idled, and then again, as it is restarted and brought back up to its normal operating temperature range.  And since oxygen is approximately 21% of the air that we breathe, exposure to it cannot be avoided.
The bottom line is that we really cannot do too much to control the existence of the key temperature range, or the presence of oxygen.  But we can exercise control over the two remaining conditions:  the presence of water and chemicals.Typically, where water is present, it contains some chemical elements like chlorides, which might be dissolved salts found in rainwater.  So, of the four necessary conditions for corrosion to occur, the most obvious condition we can focus our efforts on preventing is the presence of water in contact with both the steel requiring protection and the insulation material it touches. There are four general areas in which the insulation industry and specifiers direct their efforts in order to control the presence of water:
  • Selection of the insulation material
  • Protective jacketing design
  • Protective coatings
  • Insulation system maintenance

Each of these areas has its limitations, and more often than not a combination of one or more of the methods is used. 

Source: http://www.sangwonkorea.co.kr/#!1/c172g

Monday, October 20, 2014

Article by Tony Fernandes: If I Were 22: Dream the Impossible..



What would I do if I were 22? My advice to those just starting out on their careers comes in three parts.
First: Dream the impossible.
I know it seems like an obvious thing to say, and I am sure you've heard it a thousand times before. But too often, people dream too small. Not because they can't dream big but
because they have been conditioned to play it safe.
Growing up, my father wanted me to be a doctor. He was a doctor and he wanted me to be one too. I wasn't keen but he wanted me to try anyway. So to make him happy, I went for the entrance exam. But instead of doing the paper, I took a nap and handed it in empty. I told my father, look I gave it a go but I failed.
Dreams are not enough, though. Everyone has dreams, not everyone works at them. That brings me to the second part of my advice.
Second: Have a plan.
If you know where you want to be, you should have an idea how to get there. You must work towards it. Otherwise, your dreams are just talk. Set yourself a goal, set yourself some targets and figure out how you are going to do it.
It's hard work, and it's not for the faint-hearted. But if you are passionate about it, it does not become work, it'll be a joy to do.
Third: Don't give up.
Dreams worth having are never easy to achieve, and more often than not, you will encounter disappointment.
Never let failure get you down. It really is better to have tried and failed than to have never tried at all. You will either learn learn something valuable from the experience, or be that much closer to your dream. Keep pursuing your passion and success will come chasing after you.
When I started AirAsia, everyone told me I was crazy, that it would never work. And, to be honest, I didn't always know how it would turn out.
But it was a risk worth taking. Now I can say if I get hit by a bus tomorrow, I will have no regrets because I have achieved what I set out to do.
And that is the only life worth living.
Source:https://www.linkedin.com/pulse/article/20140527112605-18376250-if-i-were-22-dream-the-impossible?trk=mp-reader-card

Friday, October 17, 2014

About Refractories


What Are Refractories?


Refractories are heat-resistant materials that constitute the linings for high-temperature furnaces and reactors and other processing units. In addition to being resistant to thermal stress and other physical phenomena induced by heat, refractories must also withstand physical wear and corrosion by chemical agents. Refractories are more heat resistant than metals and are required for heating applications above 1000°F (538°C).
While this definition correctly identifies the fundamental characteristics of refractories--their ability to provide containment of substances at high temperature--refractories comprise a broad class of materials having the above characteristics to varying degrees, for varying periods of time, and under varying conditions of use. There are a wide variety of refractory compositions fabricated in a vast variety of shapes and forms which have been adapted to a broad range of applications. The common denominator is that when used they will be subjected to temperatures above 1000°F (538°C) when in service. Refractory products fall into two categories: brick or fired shapes, and specialties or monolithic refractories. Refractory linings are made from these brick and shapes, or from specialties such as plastics, castables, gunning mixes or ramming mixes, or from a combination of both.
Many refractory products, in final shape, resemble a typical construction brick. However, there are many different shapes and forms. Some refractory parts are small and may possess a complex and delicate geometry; others are massive and may weigh several tons in the form of precast or fusion cast blocks.
What Are Refractories Made Of?


Refractories are produced from natural and synthetic materials, usually nonmetallic, or combinations of compounds and minerals such as alumina, fireclays, bauxite, chromite, dolomite, magnesite, silicon carbide, zirconia, and others.
What Are Refractories Used For?


In general, refractories are used to build structures subjected to high temperatures, ranging from the simple to sophisticated, e.g. fireplace brick linings to reentry heat shields for the space shuttle. In industry, they are used to line boilers and furnaces of all types--reactors, ladles, stills, kilns--and so forth.
Source:http://www.refractoriesinstitute.org/aboutrefractories.htm

Saturday, October 11, 2014

Unexpected CUI Identification

The cold section of the unit operates at varying temperatures below freezing, depending on the stage of the process. Impact tested carbon steel piping was utilized for the majority of the piping that had a design temperature greater than -50˚F. The original construction specifications did not require any 
coating for piping designed to continuously operate below 20 ˚F. It was found that this criteria is acceptable, provided that the line is continuously operated below freezing. This is based on visual inspection of lines that were frozen, as they did not exhibit any significant signs of corrosion. The unexpected piping that was found with corrosion problems was not correctly identified based on 
operating temperatures specified. 

The original line list identified the operating temperature for the flowing case and did not consider normal operating temperatures based on stagnate flow. The cases presented below should have been originally identified as having a CUI potential. However based on the listed operating conditions, these piping systems were not identified to have a CUI potential and were not included in the inspection strategy. The first two cases represent intermittent flow conditions while the third case represents a deadleg condition. In the below cases, none of the piping was originally coated due to being identified as normally operating below 20 ˚F. The first case was identified in the background section which resulted in a through wall failure of an ethylene vapor line. The original specifications of theplant identified the line as operating at –12 ˚F. At this temperature, the line was not flagged to be included in the CUI inspection strategy. After investigation, it was found that the operating temperature was correct, when the pressure control valve was open and flowing. The normal operation of the valve was to be in the closed position, creating a stagnate leg with no flow. Under these conditions the typical temperature of the line was only slightly below ambient. 

After removing the insulation at the location of the leak, it was found that the corrosion extended beyond the area of the leak and traveled further down the pipe back to the 14 inch line. The insulation was removed to the 14 inch line, where a severe area of corrosion was found on the branch connection, Figures 2 and 3. 

The 14 inch line was also identified as having an operating temperature of –12 ˚F. The 14 inch line was the supply line to the system relief devices and under normal conditions was completely
stagnate, Figure 4. It is only under a pressure relieving event that the actual operating temperature reaches the specified –12 ˚F. The insulation on the entire length of the 14 inch line was removed for inspection. It was found that the first signs of frost rings, indicating that the temperature was below freezing did not occur until within 7 feet of the 24 inch main header. The leak location was approximately 20 feet from the where the piping was normally operating at or below freezing conditions. Based on the nominal wall thicknesses of the piping, the corrosion rates are estimated to be in the range of 0.004in/yr to 0.011in/yr. The corrosion rates are roughly the same for the 14 inch line and the 1-1/2 inch line.

With the 1-1/2 inch line requiring a smaller wall thickness, it was more susceptible to developing a through wall failure. The second case of CUI deals with a 1-1/2 inch carbon steel makeup line to the ethylene refrigeration system. The line branches off of the suction to the ethylene product pumps and runs to the ethylene refrigeration accumulator. This line was originally identified as operating at -11 ˚F. This line is in operation once per week, for approximately 3 hours, it is stagnate the remainder of the time. The piping orientation is shown in Figure 9.
The original specification for this line was to utilize impact carbon steel to a manual globe valve where a specification break to stainless steel occurs. The intent was to minimize the carbon steel piping while keeping the globe valve within sight of the accumulator; however due to the location of the vessel, this required approximately 140 feet of carbon steel piping before the specification break to stainless. The initial visual inspection of this line found several areas of damaged/missing insulation. After removing most of the insulation, the piping was assessed by profile radiography to determine the remaining wall thickness without having to disturb the scale, Figures 7 and 8. There were several areas that were identified as having less than 1/32 inch remaining wall thickness.


The worst section of piping was located the furthest from the main header and within approximately 30 feet of the specification break. The line was found to be frozen and free of corrosion within 20 feet of the main header. The third case of CUI deals with a ¾ inch carbon steel bleeder off of a 12 inch acetylene converter feed main header. The bleeder piping and valve were located within 1 foot of the main header. The main header was originally identified as operating at 21˚F and normally is at this temperature. The CUI was caught on a visual inspection of the line, were the stem of the bleed valve that protruded through the insulation showed noticeable corrosion and was observed to be sweating. After removal of the insulation, it was found that the main header was frozen and free of corrosion. The ¾ inch piping was frozen next to the main header and showed signs of sweating back to the valve. The piping was assessed by profile radiography, where it was determined that the remaining wall thickness was approximately 1/16 inch localized in areas, Figure 11 . It was determined that the piping was acceptable to be in service up to the next scheduled outage. This line was hand cleaned and coated to arrest the corrosion and is scheduled for replacement with stainless steel. 

Source:http://www.allriskengineering.com/library_files/AIChe_conferences/AIChe_2008/data/papers/P108061.pdf

Friday, October 3, 2014

Standard CUI Identification (25 ˚F – 250 ˚F)

Industry standards that are derived from NACE and API identify the piping systems that operate between 25 ˚F to 250 ˚F as having the greatest risk for developing corrosion under insulation (CUI). CUI can be broken into two categories, the first being corrosion of carbon steel due to contact with aerated water and forming corrosion cells. Carbon steel piping operating at temperatures greater than 250 ˚F is warm enough that the piping surface stays free of moisture. When operating below 25 ˚F any water that is present at the surface is frozen and does not provide a wet environment for a corrosion cell to develop. 

The second main category deals with stainless steels and their susceptibility to external stress corrosion cracking and pitting; however this paper will discuss experiences with the corrosion of carbon steel piping. Currently all piping that is identified as operating from 0 ˚F to 300 ˚F and insulated are part of a CUI inspection strategy that involves identifying breaches in insulation and removing insulation in suspect areas. Systems that have the greatest potential for issues with CUI have been the steam utility stations, low pressure steam and condensate piping, and regeneration piping that are insulated for heat conservation and personal protection purposes. Since the external corrosion rates are relatively the same for small bore and large bore piping, the smaller nominal wall thicknesses of line sizes 1-1/2 inch and smaller are more prone to developing through wall failures.

Steam utility stations have shown the highest potential for CUI. These piping systems are constructed of carbon steel, insulated for heat conservation, and for the most part are dead legs that stay at ambient conditions, as these sections of piping are not equipped with a steam trap and are usually 20 feet from the header. The typical orientation of the piping is a vertical leg that drops down to grade level from a main header. The piping is insulated to help prevent heat lose and condensate formation. The typical design of the steam utility station is to put a u-bolt support and valve near grade level, however, the main issue with this orientation is that it leaves a high potential for water ingression due to the number of insulation penetrations. Although properly sealed at installation, which is caulking, over time the caulk has the potential to break the seal and allow moisture ingression and eventual coating failure and corrosion cells to form. Here the areas that pose the greatest potential to develop a leak have been at the u-bolt to pipe interface and on the topside of the valve.


Inspection for CUI starts with a visual inspection of the insulation for defects that could allow moisture to enter the system. Based on the orientation of the piping, areas of insulation are selected for removal to examine the base metal. The above case of the ethylene guard drier moisture analyzer was caught on a CUI inspection. The initial insulation inspection showed that there were several breaches in the insulation and that the insulation appeared to holding water. After removing the insulation around the valve assemble and support, a very small leak was found in the form of bubbles coming from underneath the corrosion scale at the u-bolt support location, Figure 10. The section of u-bolt in direct contact with the pipe was completely corroded away. The insulation was stripped further back to the main header to where the frost rings were present. This was approximately an 8 foot deadleg section of piping. 

The section of piping that was still frozen near the header showed no significant signs of corrosion and the coating was still in good condition. During a maintenance unit outage, an operator was in the process of purging the process gas dryers, when the valve he was attempting to open snapped off at the 3/4 inch nipple between the valve and header. The valve was located on the dryer effluent filter bypass line. The system operates at 60˚F and is insulated. After investigating the process gas dryer system, a majority of the bleed valves were subject to CUI. The valves and nipples were replaced with stainless steel to prevent future instances of CUI at these locations. This is an example of piping that continuously operates at or near ambient conditions and is insulated to minimize ambient temperature swings, Figures 12, 13 and 14. 





Source: http://www.allriskengineering.com/library_files/AIChe_conferences/AIChe_2008/data/papers/P108061.pdf

Friday, September 19, 2014

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

Thursday, September 18, 2014

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

Monday, September 15, 2014

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

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