What is creep? Creep may be defined as a time-dependent deformation at elevated temperature and constant stress. It follows, then, that a failure from such a condition is referred to as a creep failure or, occasionally, a stress rupture. The temperature at which creep begins depends on the alloy composition. For the common materials used in superheater and reheater construction, Table I (see below) gives the approximate temperatures for the onset of creep. It should be pointed out that the actual operating stress will, in part, dictate or determine the temperature at which creep begins.

The end of useful service life of the high-temperature components in a boiler (the superheater and reheater tubes and headers, for example) is usually a failure by a creep or stress-rupture mechanism. The root cause may not be elevated temperature, as fuel-ash corrosion or erosion may reduce the wall thickness so that the onset of creep and creep failures occur sooner than expected.

However, regardless of the cause, the failure will exhibit the characteristics of a creep or stress rupture. Indeed, the ASME Boiler and Pressure Vessel Code recognizes creep and creep deformation as high-temperature design limitations and provides allowable stresses for all alloys used in the creep range. One of the criteria used in the determination of these allowable stresses is 1% creep expansion, or deformation, in 100,000 hours of service. Thus, the code recognizes that over the operating life, some creep deformation is likely. And creep failures do display some deformation or tube swelling in the immediate region of the rupture.

Figure 1. Schematic creep curve. Courtesy Babcock & Wilcox.

At elevated temperatures and stresses, much less than the high-temperature yield stress, metals undergo permanent plastic deformation called creep. Figure 1 shows a schematic creep curve for a constant load; a plot of the change in length verses time. The weight or load on the specimen is held constant for the duration of the test. There are four portions of the curve that are of interest:

An initial steep rate that is at least partly of elastic origin, from point "0" to point "A" in Figure 1.

This is followed by a region in which the elongation or deformation rate decreases with time, the so-called transient or primary creep, from region "A" to "B" of Figure 1. The portion from point "0" to point "B" occurs fairly quickly.

The next portion of the creep curve is the area of engineering interest, where the creep rate is almost constant. The portion from "B" to "C" is nearly linear and predictable. Depending on the load or stress, the time can be very long; two years in a test and several decades in service.

The fourth portion of the creep curve, beyond the constant-creep-rate or linear region, shows a rapidly increasing creep rate which culminates in failure. Even under constant-load test conditions, the effective stress may actually increase due to the damage that forms within the microstructure.

Without going into a detailed discussion of the atom movements involved in creep deformation, suffice it to say that creep deformation occurs by grain-boundary sliding. That is, adjacent grains or crystals move as a unit relative to each other. Thus, one of the microstructural features of a creep failure is little or no obvious deformation to individual grains along the fracture edge.

The first two stages will not leave any microstructural evidence of creep damage. Somewhere along the linear portion of Figure 1, the first microstructural evidence of damage appears as individual voids or pores. The location of these first voids or holes varies, often noted at the junction of three or more grains, occasionally at nonmetallic inclusions. These individual voids grow and link to form cracks several grains long, and finally failure occurs. The ultimate rupture is by a tensile overload when effective wall thickness is too thin to contain the steam pressure.

Since creep deformation occurs by grain-boundary sliding, the more grain boundary area, the easier creep deformation will be. Creep deformation and creep strength are a grain-size sensitive property. Thus a larger grain size improves creep strength. For austenitic stainless steels, SA213 TP321H for example, the code requires a grain size of #7 or coarser, to assure adequate creep strength. The elevated temperatures where creep occurs lead to other microstructural changes. Creep damage and microstructural degradation occur simultaneously. For carbon steels and carbon-1/2 molybdenum steels, iron carbide will decompose into graphite. For the low-alloy steels of T-11 and T-22, the carbide phase spheroidizes. Thus, creep failures will include the degraded microstructures of graphite or spheroidized carbides along with the grain-boundary voids and cracks characteristic of these high-temperature, long-time failures.

While creep failures are expected for superheaters and reheaters operating at design conditions, deviations from these parameters will promote early failures. The steam temperature always varies some from individual tube to tube, and the design allows for this variability. However, when the range of temperatures is larger than accounted for, the hottest tubes fail sooner than expected. A more likely cause of premature failure is the slow increase in tube-metal temperatures due to the formation of the steam-side scale.

Steam reacts with steel to form iron oxide along the ID surface of the tube.

The microstructures themselves will show the grain-boundary sliding and the resultant creep cracks or voids. For stainless steels, the microstructures are similar in that the failure is by grain-boundary-sliding and crack formation.

In a superheater or reheater tube, often the very first sign of creep damage is longitudinal cracks in the steam-side scale. As creep deformation expands the tube diameter, the brittle ID scale cannot follow the expansion. Cracks develop in an axial or longitudinal direction which is perpendicular to the principle hoop stress. With time, the tube continues to expand, and these cracks widen. This wide crack shortens the path from steam to steel; iron oxide forms preferentially at the tip of the crack, as there is less oxide thickness to protect the steel; and a cusp forms within the steel tube. The cusp acts as a notch or a stress raiser, reducing the local wall thickness. Creep voids form here, often before any other obvious grain-boundary damage appears elsewhere within the microstructure. With continued high-temperature operation, creep cracks grow from the cusp and ultimately weaken the cross section to the point where failure occurs.

Creep failures are characterized by:

bulging or blisters in the tube

thick-edged fractures often with very little obvious ductility

longitudinal "stress cracks" in either or both ID and OD oxide scales

external or internal oxide-scale thicknesses that suggest higher-than-expected temperatures

intergranular voids and cracks in the microstructure

Editor's note: Some ASME Boiler and Pressure Vessel Code requirements may have changed because of advances in material technology and/or actual experience. The reader is cautioned to refer to the latest edition and addenda of the ASME Boiler and Pressure Vessel Code for current requirements.

Table IInitial Creep Temperature

For superheaters and reheaters, the scale that forms is essentially magnetite alloyed with chromium, molybdenum, manganese, and silicon from the alloy steels of T-11 and T-22. For waterwalls, the iron oxide may be contaminated with impurities from the boiler water and corrosion debris from the pre-boiler circuits of condenser and feedwater heaters. In any event, the thermal conductivity of the steamside scale is about 5% of the thermal conductivity of the steel tube. Thus, an effective insulating layer forms and prevents proper cooling of the tube metal by the steam. The net effect of the scale is to raise the tubemetal temperature. Depending on the scale thickness, which is dependent on the time and temperature of operation, tube-metal temperature increases of 25 - 75oF are likely. Such a large increase raises tubemetal temperatures beyond the safe design range. These elevated temperatures result in increased creep deformation rates, more rapid oxidation and corrosion (thinner walls and higher stress) and hasten the onset of creep failures. An increase of 60oF (from 1040oF to 1100oF for example) will decrease creep life by 90%. An increase of 60o F due to steam-side scale formation in a superheater or reheater is not unusual.

Carbon steel.......................800oF

Carbon + 1/2 Molybdenum............850oF

1-1/4 Chromium-1/2 Molybdenum......950oF

2-1 /4 Chromium-1 Molybdenum.......1000oF

Stainless steel....................1050oF

Priority 1 items should be considered for inspection with in the next 7,500 hours or 50 thermal cycles of operation.

Locations with no known or documented inspection history and are considered high-risk areas associated with steam leaks, cracks and ruptures. i.e. boiler outlet connection; wye block / lateral fittings; longitudinal seam welds (traffic areas); attemporator spools; drain penetrationsSteam Boiler Inspections Using Remote Field Testing

03/01/2011

By Mynor Celis, P.Eng, Russell NDE Systems

Forced outages of steam boilers due to tube leakages remain the leading cause of lost production in plants. Due to hundreds, if not thousands of linear feet of pipe, there is a high potential for failure without notice. One of the biggest challenges for maintenance and operations personnel is the prevention of tube failures in boilers and heat exchangers without causing significant loss to the company. When excursions from normal operating conditions occur, the question must be raised, if our boiler tubes were damaged by the excursion (for example, overheating, or a condenser tube leak), how do we find out if we have a problem that could lead to failure?

Boiler operation always involves harsh working conditions. On the fuel side of tubes, high operating temperatures and corrosive by-products from burning fossil fuels or solid waste can seriously degrade the life-expectancy of the boiler tubes. On the water/steam side, there is a high potential for oxidization of boiler tubes due to high temperature steam and the corrosive action of chemicals in the water supply. These conditions may cause metal to overheat, corrosive wall thinning, and localized pitting, any or all of which can lead to premature failure of the tubes, possible injuries to personnel, damage to adjacent tubes and a forced outage.

In spite of these adverse operating conditions, boilers have a life expectancy upwards of 30 years and most premature failures are due to conditions that make operational variables deviate from expected parameters.

Industrial best practice is to inspect all tubes periodically, checking to ensure that mechanical properties of the materials are intact and that material thickness is within normal expectations. A proper and rigorous 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 for multiple specialized applications.

The primary benefit of this technique is that it does not require contact with the object under test to measure material thickness and condition. Additionally, a high-quality inspection can be assured without requiring couplant and with minimal surface preparation. RFT also shows high sensitivity to detection of defects 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 corrective approach (pro-active or reactive). This holds true with boiler inspections. A preventative approach seeks to look at the long-term wear-and-tear tendencies on the equipment, with an eye towards improving operations through improvements to the fuel-air mixture, flow balancing and the creation of a maintenance specification for tube repair or replacement. Undertaking a corrective approach looks to inspect the boiler after a failure to look for collateral damage and to ensure that the failure mechanism has 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 firms long-range operational plan, resulting in a reduced effect to the operations budget and significantly reduced time lost due to unexpected outages.

Long-term overheating (creep): This type of failure occurs when the operating temperature of the boiler tubes exceeds the operational limits for an extended period of time. These limits are variable based on the tube size and thickness, operating pressures, as well as the tube locations in the boiler and construction materials. Overheating leading to creep damage can be caused by internal deposits, which reduce flow through the tubes or, more commonly, sudden spikes in operating temperature due to 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 will develop blisters at the locations subject to the highest temperature and will develop elongated axial cracks. 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 of these conditions can be detected through RFT as the changes in the tubes electrical permeability can be easily measured.

How to prevent creep damage: Often, when boilers are operating outside of standard operational parameters, it goes unrecorded or unnoticed by the operator. Either of these issues can lead to premature failure, as the degradation of the tubes material properties is not being accurately recorded. As such, it is necessary to run periodic performance evaluations on the boiler. Ensuring frequent calibration of the thermostats is the best way to prevent unexpected temperature spikes and to help ensure that the unit is warmed up in accordance with the manufacturers recommended specifications. Frequent sampling of the units feed water supplyideally once per shiftwill help to ensure that the feed water quality is within the manufacturers recommended parameters. Regular internal flushing of the boiler tubes will ensure removal of any material deposits clogging the tubes. Any deposits must be measured frequently, and chemical cleaning is recommended when the deposit density exceeds 15 g/sq.ft. Cleaning becomes mandatory as the density reaches 30 g/sq/ft. Frequent drum inspections are mandatory according to the maintenance manual of the manufacturer. Depending on the hours of service, it is necessary to determine how well the equipment is working, the effectiveness of the water treatment and that there are no failure mechanisms 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 the manufacturers 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 vicinity of the rupture. A thick, fragile layer of magnetite will appear near the failure, indicative of long-term overheating.

Short Term Overheating: Most often, these failures occur when the tubes are left without sufficient cooling and occur in short order. Failures caused by short-term overheating frequently occur at the top of the tubes or close to the steam collector. If the failure occurs in a single tube and if surrounding tubes have 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

How to detect short-term overheating: As these failures occur rapidly, it is recommended that the tubes be inspected visually through the inspection ports during start-up. If red spots suddenly appear on a tube, it is a signal that the tube may be plugged. This type of inspection is necessary after chemical cleaning, 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 not readily detectable through non-destructive testing methods. The best way to prevent it is to flush the tubes with water to ensure all obstructions are removed prior to startup and by ensuring that the purge and bottom headers are open as the pressure is increased. This type of failure can be recognized by the longitudinal 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 an anode to the rest of the boiler, causing further corrosion. This process is exacerbated by the presence of dissolved oxygen in the boiler system. Ideally, the boiler surface would be covered with a protective layer of iron oxide, preventing the attack of free oxygen in the water supply. The small pits that result from oxygen corrosion can cause significant stress, and will result in the formation of cracks in the region

Figure 3 Oxygen corrosion

How to detect oxygen corrosion: RFT is one of the most effective methods used to detect oxygen corrosion if it is located at the fire side. High tool sensitivity and accuracy (>1/8 diam.) allows for the early detection of initial defects, providing data necessary to determine a repair or replacement protocol before the tube fails. Ultrasonic testing (UT) can also be used, but is limited by significantly slower inspection time and the fact that 100 percent coverage is impossible. The latter increases the risk that serious damage to tubes could go unnoticed.

How to prevent oxygen corrosion: The most effective way to prevent oxygen corrosion in boiler tubes is to prevent oxygen from entering the system in the first place.

Oxygen enters a boiler system primarily through three means: air can be trapped during normal operation when internal pressure is less than the ambient atmospheric pressure; when the system is left open for maintenance; and as a result of molecular dissociation of water in the system. Other critical factors are the presence of ambient moisture in the system and, the loss of a passivation layer after chemical cleaning. Eliminating these factors can successfully prevent oxygen corrosion. It is recommended that all metal surfaces be kept dry using positive-pressure inert gas, moisture-absorbing materials, or a continuous flow of dry, dehumidified (