steam boiler inspections using remote field testing - power engineering.pdf
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2/15/2015 Steam Boiler Inspections Using Remote Field Testing Power Engineering
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POWER ENGINEERING
Steam Boiler Inspections UsingRemote Field Testing03/01/2011
By Mynor Celis, P.Eng, Russell NDE Systems
Forced outages of steam boilers due to tube leakages remain the leading cause of lost production inplants. Due to hundreds, if not thousands of linear feet of pipe, there is a high potential for failure withoutnotice. One of the biggest challenges for maintenance and operations personnel is the prevention of tubefailures in boilers and heat exchangers without causing significant loss to the company. When excursionsfrom normal operating conditions occur, the question must be raised, “if our boiler tubes were damagedby the excursion (for example, overheating, or a condenser tube leak), how do we find out if we have aproblem that could lead to failure?”
Boiler operation always involves harsh working conditions. On the fuel side of tubes, high operatingtemperatures and corrosive by-products from burning fossil fuels or solid waste can seriously degradethe life-expectancy of the boiler tubes. On the water/steam side, there is a high potential for oxidization ofboiler tubes due to high temperature steam and the corrosive action of chemicals in the water supply.
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These conditions may cause metal to overheat, corrosive wall thinning, and localized pitting, any or all ofwhich can lead to premature failure of the tubes, possible injuries to personnel, damage to adjacent tubesand a forced outage.
In spite of these adverse operating conditions, boilers have a life expectancy upwards of 30 years andmost premature failures are due to conditions that make operational variables deviate from expectedparameters.
Industrial best practice is to inspect all tubes periodically, checking to ensure that mechanical propertiesof the materials are intact and that material thickness is within normal expectations. A proper andrigorous inspection regimen will go a long way to reduce the probability of premature boiler failures.
Thomas R. Schmidt of Shell Oil headed the initial development of the remote field testing (RFT)technique for measuring oil well casings. After that, several tools have entered the market using RFT formultiple specialized applications.
The primary benefit of this technique is that it does not require contact with the object under test tomeasure material thickness and condition. Additionally, a high-quality inspection can be assured withoutrequiring couplant and with minimal surface preparation. RFT also shows high sensitivity to detection ofdefects on the ID or OD of the tube in question and can measure through non-ferromagnetic coatings,linings and scale.
There are two approaches to doing maintenance of any kind: a preventative approach or a correctiveapproach (pro-active or reactive). This holds true with boiler inspections. A preventative approach seeksto look at the long-term wear-and-tear tendencies on the equipment, with an eye towards improvingoperations through improvements to the fuel-air mixture, flow balancing and the creation of amaintenance specification for tube repair or replacement. Undertaking a corrective approach looks toinspect the boiler after a failure to look for collateral damage and to ensure that the failure mechanismhas not affected other areas in the boiler.
Of the two, the former is more advantageous from the perspective of being performed before failure,within the context of the firm’s long-range operational plan, resulting in a reduced effect to the operationsbudget and significantly reduced time lost due to unexpected outages.
Long-term overheating (creep): This type of failure occurs when the operating temperature of the boilertubes exceeds the operational limits for an extended period of time. These limits are variable based onthe tube size and thickness, operating pressures, as well as the tube locations in the boiler andconstruction materials. Overheating leading to creep damage can be caused by internal deposits, whichreduce flow through the tubes or, more commonly, sudden spikes in operating temperature due to
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increasing load or issues with the temperature control. These reduce the resistance of the tubes.
Figure 1 Long-term overheating (creep)
How to detect creep damage: During the period of long-term overheating, the surface of the tube willdevelop blisters at the locations subject to the highest temperature and will develop elongated axialcracks. Both of these failures will reduce overall tube thickness and material properties of the tube.Additionally, thick, dark, brittle oxides will appear on the internal and external surfaces of the tube. All ofthese conditions can be detected through RFT as the changes in the tubes electrical permeability can beeasily measured.
How to prevent creep damage: Often, when boilers are operating outside of standard operationalparameters, it goes unrecorded or unnoticed by the operator. Either of these issues can lead to prematurefailure, as the degradation of the tube’s material properties is not being accurately recorded. As such, it isnecessary to run periodic performance evaluations on the boiler. Ensuring frequent calibration of thethermostats is the best way to prevent unexpected temperature spikes and to help ensure that the unit iswarmed up in accordance with the manufacturer’s recommended specifications. Frequent sampling ofthe unit’s feed water supply—ideally once per shift—will help to ensure that the feed water quality is withinthe manufacturer’s recommended parameters. Regular internal flushing of the boiler tubes will ensure
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removal of any material deposits clogging the tubes. Any deposits must be measured frequently, andchemical cleaning is recommended when the deposit density exceeds 15 g/sq.ft. Cleaning becomesmandatory as the density reaches 30 g/sq/ft. Frequent drum inspections are mandatory according to themaintenance manual of the manufacturer. Depending on the hours of service, it is necessary to determinehow well the equipment is working, the effectiveness of the water treatment and that there are no failuremechanisms affecting the internal surface, mainly in the area of water-steam interface line.
Lastly, it is necessary that all spare parts used in maintenance or repairs are correct to themanufacturer’s specifications. It should be noted that when any tube fails as a result of creep damage,there will be a rupture with slightly rounded edges and jagged edges with cracks or breaks in the vicinityof the rupture. A thick, fragile layer of magnetite will appear near the failure, indicative of long-termoverheating.
Short Term Overheating: Most often, these failures occur when the tubes are left without sufficientcooling and occur in short order. Failures caused by short-term overheating frequently occur at the top ofthe tubes or close to the steam collector. If the failure occurs in a single tube and if surrounding tubeshave no appearance of alteration, it suggests that the failed tube was at least partially obstructed,causing the temperature to rapidly exceed material limits, causing an explosion or leak in the tube.
Figure 2 Short-term overheating
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How to detect short-term overheating: As these failures occur rapidly, it is recommended that the tubesbe inspected visually through the inspection ports during start-up. If red spots suddenly appear on atube, it is a signal that the tube may be plugged. This type of inspection is necessary after chemicalcleaning, tube replacement or re-commissioning after a long period of dormancy.
How to prevent short-term overheating: As a result of the rapid occurrence of this type of failure, it is notreadily detectable through non-destructive testing methods. The best way to prevent it is to flush thetubes with water to ensure all obstructions are removed prior to startup and by ensuring that the purgeand bottom headers are open as the pressure is increased. This type of failure can be recognized by thelongitudinal rupture, smooth edges and no loss of wall thickness as the rupture.
Oxygen Corrosion: Oxygen corrosion occurs in a boiler due to small corroded regions which acts as ananode to the rest of the boiler, causing further corrosion. This process is exacerbated by the presence ofdissolved oxygen in the boiler system. Ideally, the boiler surface would be covered with a protective layerof iron oxide, preventing the attack of free oxygen in the water supply. The small pits that result fromoxygen corrosion can cause significant stress, and will result in the formation of cracks in the region
Figure 3 Oxygen corrosion
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How to detect oxygen corrosion: RFT is one of the most effective methods used to detect oxygen corrosionif it is located at the fire side. High tool sensitivity and accuracy (>1/8” diam.) allows for the earlydetection of initial defects, providing data necessary to determine a repair or replacement protocol beforethe tube fails. Ultrasonic testing (UT) can also be used, but is limited by significantly slower inspectiontime and the fact that 100 percent coverage is impossible. The latter increases the risk that seriousdamage to tubes could go unnoticed.
How to prevent oxygen corrosion: The most effective way to prevent oxygen corrosion in boiler tubes is toprevent oxygen from entering the system in the first place.
Oxygen enters a boiler system primarily through three means: air can be trapped during normal operationwhen internal pressure is less than the ambient atmospheric pressure; when the system is left open formaintenance; and as a result of molecular dissociation of water in the system. Other critical factors arethe presence of ambient moisture in the system and, the loss of a passivation layer after chemicalcleaning. Eliminating these factors can successfully prevent oxygen corrosion. It is recommended that allmetal surfaces be kept dry using positive-pressure inert gas, moisture-absorbing materials, or acontinuous flow of dry, dehumidified (<30 percent) air.
Caustic Corrosion: Caustic corrosion refers to the corrosive action of sodium hydroxide with a metal andis restricted to: water-cooled tubes in regions of high heat fluctuation; regions with heat transfer in
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welding rings or other devices that disrupt flow; horizontal or inclined tubes; places with thick internaldeposits reducing flow rates. This penetration may be filled with dense corrosion products whichsometimes contain magnetite crystals. Most often, the metal surface has a smooth contour andlaminations. Sodium hydroxide is added to boiler water in non-corrosive concentrations; however otherphysical factors tend to concentrate it further, leading to the production of corrosive alkaline in the boiler.
Figure 4 Caustic corrosion
How to detect caustic corrosion: Caustic corrosion is easily detected using non-destructive testingmethods, because the affected area is found with reduced wall thickness. If this is in its early stage theremay not be any blister, but if the thickness is reduced there is likely to be a blister or deformation in thetube. Remote field testing is the most suitable method. These tools have high sensitivity and inspectionspeed, allowing for rapid detection of corrosive damage. UT can also be used, once the affected region hasbeen located.
How to prevent caustic corrosion: When sodium hydroxide is present—either by itself, or as a salt-producing alkaline—with a concentration mechanism, there exists the possibility of caustic corrosion. Toreduce the likelihood of caustic corrosion damage in a boiler, the amount of free sodium hydroxideavailable to produce alkaline salts in the condenser water must be controlled at the purification stage.This will prevent nucleate boiling, and the formations of water-level lines. Proper purging will prevent theformation of sludge deposits.
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Acidic Corrosion: There are two necessary conditions for this type of failure to occur: the boiler must beoperated with a pH below normal parameters, and there must be a means to concentrate the acid-producing salts that are responsible for the low-pH environment. If both of these conditions are met, thenthe protective layer of iron oxide is dissolved, and the bare metal is left unprotected.
Figure 5 Acidic corrosion
How to detect acidic corrosion: Corrosion of this type primarily results in metal loss on the interiorsurface of the tube. Similar to caustic corrosion, areas affected by a low pH environment tend to havesmooth edges and lamination. The difference between the two is that the region affected by acidiccorrosion is often covered with iron oxide.
Remote field testing has high sensitivity, and can detect minimal corrosion accurately from 1/8”diameter, making it one of the most effective ways to detect acidic corrosion. The Ultrasonic testing todetermine the extent of wall loss however this can only be effectively utilized once the affected region isknown.
How to prevent acidic corrosion: Two ways exist to reduce the probability of acidic corrosion in the boiler.The first involves reducing the availability of free acid, or acid producing salts in the boiler, avoidingmake up water with Low Ph. The second involves eliminating the means to concentrate the acid in theboiler, such as bubble formations, water-side deposits, and water-level lines. This can be achieved
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through regular, proper purging of the boiler.
Stress Corrosion: Stress corrosion is caused by a combination of two separate factors: tensile stresseson the pipe caused by internal pressure, or residual stresses induced by improperly-applied heattreatment, or tube bending; and a corrosive material such as sodium hydroxide or chlorine. Thiscombination results in cracking near the stressed region. Stress corrosion usually occurs near welds, ortube bends.
Figure 6 Stress corrosion
How to detect stress corrosion: Stress corrosion displays as cracking near welds subject to tensilestresses. While stress corrosion cracking can be difficult to see, it can be detected visually. Liquidpenetrant inspection provides a surer means of detection. Additionally, ultrasonic testing or radiographictesting can detect stress corrosion cracking.
How to prevent stress corrosion: Annealing will relieve residual stresses from welding or bending. Addingphosphates to the operating environment will help prevent the formation of free sodium, reducing theconcentration of corrosion products.
Hydrogen Damage: When chemicals are added to boiler water to balance pH, an electrochemical reactioncan occur, releasing free hydrogen atoms into the environment. This can cause decarburization,embrittlement and the formation of molecular hydrogen and methane in the steel. Hydrogen damage isrestricted to evaporator tubes with pre-existing corrosion problems. Hydrogen atoms diffuse into the
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steel of the boiler tubes. Some of these atoms bond with either each other, or the carbon in the steel,forming molecular hydrogen or methane. These gasses accumulate until the pressure causes theseparation of the metal along the granular borders, producing inter-granular micro-cracks. This in turnreduces the mechanical strength of the tube, which causes it to burst. Any tubes suspected of failing dueto hydrogen damage should have samples taken and sent for metallographic analysis in a lab.
Figure 7 Hydrogen damage
How to detect hydrogen damage: Hydrogen damage is hard to detect visually, except in the advancedstages when the pipe has visible cracks. Remote field testing is highly effective in detecting hydrogendamage because the changes in the electrical properties of the material due to hydrogen damage arereadily detected.
How to prevent hydrogen damage: The two critical factors in reducing a boiler’s susceptibility to hydrogendamage are the amount of hydrogen available, and the means to increase its concentration. Properchemical treatment of feed water, combined with a stringent pH control system is the best way to preventhydrogen damage.
Graphitization: Graphitization is caused by small structural changes of low-carbon steels at moderatetemperatures over extended periods of time. Graphitization causes the decomposition of pearlite inferrite, weakening the steel. The extent of the decomposition is dependent on the temperature. Thisphenomenon generally occurs due to long-term overheating, during which, the graphite nodules are linkedto each other, reducing the resistance to internal pressure, causing the metal to tear.
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Figure 8 Graphitization
How to detect graphitization: Graphitization occurs internally, with the graphite detaching from the steelreducing the total wall thickness. As with hydrogen damage, the electrical properties of the materialchanges when graphitization is present. For this reason, remote field testing is the most effective meansof detection.
How to prevent graphitization: The primary concern with respect to the susceptibility to embrittlementdue to graphitization is tube quality. Low carbon content steel is more susceptible to graphitization andlong-term overheating is liable to exacerbate the problem. A good metal passivation program and treatingthe boiler feed water with phosphate will reduce the probability of graphitization.
Fire Side Corrosion: Most fuel components can cause corrosion on boiler tubes. Due to incompletecombustion, deposits of combustion residue can change the heat transfer characteristics withpotentially severe effects on system efficiency. Most solid fuels contain 10 to 20 percent ash thatremains in the boiler after combustion, leading to lost heat transfer and corrosion. While liquid fuels donot exceed 2 percent ash, they do contain elements such as vanadium and sodium.
Figure 9 Fire-side corrosion
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How to detect fire side corrosion: When the surface of the boiler tubes are exposed to combustion gases,the damaged area of the surface will change color. Long-term corrosion of this type affects thepermeability and conductivity of boiler tubes, as well as causing pitting.
How to prevent fire side corrosion: Fuel selection is of primary concern in addressing the issue of fire-sidecorrosion. Fuels should be selected containing minimal corrosive agents such as sulfur, sodium andcalcium. Second, optimizing the combustion quality through control of temperature, fuel-air mixture, andair balancing will reduce the ash deposits in tubes. Thermocouples should be installed throughout theboiler to indicate when heat transfer is outside optimal operating range, which could be indicative of ashdeposits on the tubes. Third, continuous cleaning programs should be implemented in the boiler.
The probability of steam boiler failure is dependent on numerous operational and maintenance factors.The implementation of preventative inspection and tube profile measurements will help to ensure thatboilers are active for their expected 30-year average operational lives. An active regime of preventativemaintenance will be effective at reducing the financial impact of unexpected shut-downs due to boilertube failures.
Operations staff need to be trained in preventative maintenance procedures and processes. Often, whenboiler tubes undergo catastrophic failure, adjacent tubes are often damaged as well, increasing the
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Fuel Tech receives air pollution control contracts worth $3.6MnFuel Tech Inc. has received multiple air pollution control (APC) contracts, worth approximately $3.6million, from customers in China, Europe and the U.S.
outage time. Periodic inspections and follow-up preventative maintenance is necessary to ensure theboiler system remains in good repair, and potentially extend its life-expectancy. With this in mind, we canconclude that periodic boiler inspection is a vital part of any maintenance regime, and that remote fieldtesting is the optimal means for early detection of most causes of boiler tube failure.
Author: Mynor Celis, currently is Marketing Manager for Latin America for Russell NDE Systems,Edmonton, AB. Canada, He has previous experience as operation manager in a coal-fired power plant,having responsibility for the operation of the boiler, water and wastewater systems, high and low boilersteam pressure. He is a mechanical and electrical engineer with MBA specialization.
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