News and Views, Volume 55 | Materials Lab Featured Damage Mechanism

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CREEP FATIGUE IN STEAM COOLED BOILER AND HRSG TUBES

By:  Wendy Weiss

Figure 1. Tube to header weld crack.

Creep-fatigue is caused by the accumulation of damage through synergistic interaction of cyclic stress and elevated operating temperature. The creep and fatigue components of the damage usually occur at different periods in the thermal cycle to result in a failure with characteristics of both mechanisms. Structural Integrity has an experienced group of materials specialists and a full-service metallurgical testing laboratory that can help with any situation involving material property characterization.   

 

Creep-fatigue is generally assumed to be the active mechanism when the rate of fatigue damage is influenced by the strain rate and hold times while the tube is operating at temperatures within its creep regime.

Mechanism

Creep-fatigue is essentially the accumulation of damage through synergistic interaction of cyclic stress and an elevated operating temperature. The creep and fatigue components of the damage usually occur at different periods in the thermal cycle. Cyclic loading may occur at temperatures within the material’s creep regime (≥800°F for Cr-Mo tubing). Once steady state conditions are reached, the component may continue to be exposed to high temperatures and localized stresses, which can result in the accumulation of additional plastic strains due to creep. Furthermore, if residual stresses due to thermal transients were present, creep relaxation would add to the magnitude of the inelastic strain. The key takeaway regarding creep-fatigue damage is that the fatigue life can be significantly less than would be predicted from pure fatigue test data.

Figure 2. Crack surface of the tube to header weld crack, with a thick oxide layer and creep damage along its length.

Typical Locations

  • Superheater and reheater tubes where tube metal temperatures are in the creep regime
  • Welded connections
  • Bends
  • Tube-to-header attachments

Features

  • Generally initiates on the OD surface
  • Typically, single cracks
  • Cracks are generally relatively straight, relatively wide, and oxide-filled or oxide-lined
  • Creep voids and microfissures can surround the primary crack, but creep damage does not have to be present

Root Causes

Creep-fatigue is caused by the interaction of stresses, both cyclic and static, and elevated temperature exposure. Root causes can include excessive stresses/strains, excessive tube temperatures, and unit operation. 

Excessive stresses/strains can result from the following, many of which are related to HRSG operation: constrained thermal expansion, pressure changes, fluid temperature changes, non-uniform temperatures, load transfer between hot and cold conditions, changes in external loads, transient temperature differences, steam or water hammer, forced vibration, flue gas flow problems, thermal transients due to condensate flashing into tube circuits, improper attemperation, and incorrect or inadequate drains.

Excessive tube temperatures can result from excessive temperature ramp rates, poor distribution of tube temperatures, poorly designed thickness transitions at header connections and supports, and poor material selection for tubing.

The number of service hours, number of stop/starts, and the characteristics of the stop/starts are unit operation influences that can affect creep-fatigue damage.

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News and Views, Volume 54 | Materials Lab Featured Damage Mechanism

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STRAIN-INDUCED PRECIPITATION HARDENING (SIPH) IN AUSTENITIC STAINLESS BOILER TUBES

By:  Wendy Weiss

Structural Integrity’s Metallurgical Laboratory offers comprehensive metallurgical laboratory services to support client material issues.

Strain-Induced Precipitation Hardening, also known as SIPH, is a commonly misinterpreted boiler tube failure mechanism that occurs when austenitic stainless steel tubing is cold or warm worked during fabrication and then is installed with either improper or no solution annealing heat treatment. While the basic mechanism and the root cause are understood, the complex interaction between heat chemistry, quantity of cold or warm work, and subsequent thermal history makes it very difficult to predict under precisely what circumstances damage due to SIPH will result in failure of a boiler tube.

Longitudinally oriented crack at the extrados of a bend in a stainless steel superheater tube.

Mechanism
SIPH occurs when a heat of austenitic stainless steel containing certain precipitate-forming elements (e.g., niobium, titanium, vanadium, etc.) either intentionally or as residuals is cold or warm worked during subsequent material processing. The cold or warm working creates excess defects in the sub-structure of the material, which serve as preferred sites for precipitation of temper-resistant carbides or carbo-nitrides. Precipitation occurs when the material is heated to a sufficiently high temperature that is well below the solution annealing temperature. This can occur rapidly during a poorly executed heat treatment if the material does not reach the proper solution annealing temperature, or it can occur more slowly at typical operating temperatures for superheater or reheater tubing in utility-type boilers.

Once formed, precipitates anchor to the defects, resulting in a substantial increase in the elevated temperature or creep strength of the interior of the grains. At the same time, there is a narrow zone of material immediately adjoining the grain boundaries that remains largely precipitate-free due to the diffusional characteristics of the grain boundary itself. Ultimately, the interior portion of the individual grains becomes very strong at elevated temperatures while the material immediately adjoining the grain boundaries becomes comparatively creep weak. In addition, any surface-active elements that may be present in the material, such as arsenic, tin, antimony, etc., will tend to concentrate at the grain boundaries, further reducing their strength.

Regardless of when the precipitation occurs, once the interior of the grains has been strengthened, the grain boundary regions are weakened. Any strain imposed on the material in response to an applied or residual stress is forced to concentrate in the grain boundary region, which substantially magnifies its effect. For example, suppose the bulk strain experienced by a cold-worked stainless superheater tube segment is very small – a fraction of a percent – and the material has undergone the SIPH reaction. The strengthened grain interiors will undergo no strain. Conversely, within the much smaller volume of the comparatively weak grain boundaries, the accumulated strain will be orders of magnitude higher than the bulk level.

Typical Locations

  • Bends
  • Offsets
  • Swages
  • Welded attachments

Features

  • Can initiate at midwall
  • Early-stage damage consists largely of grain boundary cavities and microfissures
  • Intergranular cracking

Root Causes
The single root cause of SIPH is the failure to properly solution anneal susceptible heats of austenitic stainless steel tubing that has been either cold or warm worked during fabrication.

An overall, cross-sectional view of the intergranular crack (image A) with higher magnification views of some of the secondary grain boundary microfissures and voids (image C). Slip bands (parallel lines in image B) indicate local deformation.

For any situation involving material property characterization, Structural Integrity has an experienced group of materials specialists and a full-service metallurgical testing laboratory that can help.

Visit Our Metallurgical Laboratory Services Page

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Creep Strength Evaluation When NDE Is Ineffective Core Sample Creep Testing

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News & Views, Volume 53 | Materials Lab Featured Damage Mechanism

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CIRCUMFERENTIAL THERMAL FATIGUE IN CONVENTIONAL WATERWALL TUBES

By:  Wendy Weiss

Circumferential Thermal Fatigue damage in Conventional Waterwall Tubes most commonly appears as circumferentially oriented cracking in the waterwalls of coal-fired supercritical units. Initially, the formation of ripple magnetite was a significant factor in the formation of this damage. Later, the introduction of oxygenated treatment controlled the formation of ripple magnetite, thus greatly reducing this damage mechanism.  In the early 2000s, however, this type of thermal fatigue began occurring more frequently as low NOx burners and separated overfire air systems were introduced. 

Figure 1. Tube with a series of circumferential cracks

Mechanism

Three basic factors contribute to this type of thermal fatigue damage. 

  1. The first factor is the starting tube temperature (i.e., the temperature under normal operating conditions). The higher the starting temperature, the greater the accumulation of damage in the affected tubing. For example, tubes subjected to higher heat flux or tubes with thick weld overlays will have higher average metal temperatures and accumulate damage more quickly. 
  2. The second factor is the extent of gradually increasing tube temperature caused by reasons such as internal deposit buildup, flame impingement, or unstable flow. 
  3. The third factor is the contribution of thermal transients due to slag shedding or using sootblowers or water cannons. 

Essentially, the thermal fatigue cracking results from the combination of increasing tube metal temperature and thermal transients and is aggravated by high starting tube temperatures. 

Figure 2. The external surface of the tube after the external deposits were removed

TYPICAL LOCATIONS

Figure 3. Cross-sectional views of the cracking in the etched (Top) and unetched (BOTTOM) conditions

  • Tubes with slag buildup and shedding
  • Areas affected by wall blow quenching
  • High heat flux locations
  • Areas affected by flame impingement
  • Cracking can be localized or widespread
  • Tends to be contained within a relatively narrow range of elevations

FEATURES

  • Circumferentially oriented, multiple, parallel cracks along the hot side of the tubes.
  • Notch shaped, oxide filled cracks in cross-section.
  • Adjacent tubes can exhibit variability in crack density.

ROOT CAUSES

  • High Initial Waterwall Tube Temperatures
    • Thick weld overlays
    • Higher heat flux
    • Flame impingement
  • Increasing Waterwall Tube Temperatures
    • Internal deposits including ripple magnetite, thick oxide layers, or feedwater corrosion products
    • Reduced internal flow rate
    • Formation of external oxides and deposits
  • Severe Thermal Transients
    • Natural or forced slag removal, including slag shedding and sootblowing
    • Use of water cannons or improper sootblowing
    • Flame instabilities
    • Unit operation, including forced fan cooling, rapid startups, frequent load cycling

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Structural Integrity Associates | News and Views, Volume 51 | Pitting Corrosion in Conventional Fossil Boilers and Combined Cycle:HRSGs

News & Views, Volume 51 | Materials Lab Featured Damage Mechanism

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PITTING CORROSION IN CONVENTIONAL FOSSIL BOILERS AND COMBINED CYCLE/HRSGS

By:  Wendy Weiss

Pitting is a localized corrosion phenomenon in which a relatively small loss of metal can result in the catastrophic failure of a tube. Pitting can also be the precursor to other damage mechanisms, including corrosion fatigue and stress corrosion cracking. Pits often are small and may be filled with corrosion products or oxide, so that identification of the severity of pitting attack by visual examination can be difficult. 

Figure 1. Severe pitting in a tube from a package boiler

Mechanism 

Pitting is a localized corrosion attack involving dissolution of the tube metal surface in a small and well-defined area. Pitting corrosion can occur in any component in contact with water under stagnant oxygenated conditions. Pitting in economizer tubing is typically the result of poor shutdown practices that allow contact with highly-oxygenated, stagnant water. Pitting also may occur in waterwall tubing as a result of acidic attack stemming from an unsatisfactory chemical cleaning or acidic contamination. 

Pits that are associated with low pH conditions tend to be numerous and spaced fairly close together. The pits tend to be deep-walled compared to the length of the defect. A breakdown of the passive metal surface initiates the pitting process under stagnant oxygenated conditions. A large potential difference develops between the small area of the initiated active pit (anode) and the passive area around the pit (cathode). The pit will grow in the presence of a concentrated salt or acidic species. The metal ion salt (M+A-) combines with water and forms a metal hydroxide and a corresponding free acid (e.g., hydrochloric acid when chloride is present). Oxygen reduction at the cathode suppresses the corrosion around the edges of the pit, but inside the pit the rate of attack increases as the local environment within the pit becomes more acidic. In the event that the surfaces along the walls of the pit are not repassivated, the rate of pit growth will continue to increase since the reaction is no longer governed by the bulk fluid environment. Pitting is frequently encountered in stagnant conditions that allow the site initiation and concentration, allowing the attack to continue. 

The most common cause of pitting in steam touched tubing results from oxygen rich stagnant condensate formed during shutdown. Forced cooling and / or improper draining and venting of assemblies may result in the presence of excess moisture. The interface between the liquid and air is the area of highest susceptibility. Pitting can also be accelerated if conditions allow deposition of salts such as sodium sulfate that combine with moisture during shutdown. Volatile carryover is a function of drum pressure, while mechanical carryover can increase when operating with a high drum level or holes in the drum separators. Pitting due to the effects of sodium sulfate may occur in the reheater sections of conventional and HRSG units because the sulfate is less soluble and deposits on the internal surfaces. During shutdowns the moisture that forms then is more acidic. 

Figure 2. Pitting on the ID surface of a waterwall tube

Typical Locations

In conventional units, pitting occurs in areas where condensate can form and remain as liquid during shutdown if the assemblies are not properly vented, drained, or flushed out with air or inert gas. These areas include horizontal economizer tubes and at the bottom of pendant bends or at low points in sagging horizontal tubes in steam touched tubes. 

In HRSGs, damage occurs on surfaces of any component that is intentionally maintained wet during idle periods or is subject to either water retention due to incomplete draining or condensation during idle periods. 

Attack from improper chemical cleaning activities is typically intensified at weld heat affected zones or where deposits may have survived the cleaning. 

Features

Pits often are small in size and may be filled with corrosion products or oxide, so that identification of the severity of pitting attack by visual examination can be difficult. 

Damage to affected surfaces tends to be deep relative to pit width, such that the aspect ratio is a distinguishing feature. 

Root Causes

Figure 3. Pitting on the ID surface of an economizer tube

The primary factor that promotes pitting in boiler tubing is related to poor shutdown practices that allow the formation and persistence of stagnant, oxygenated water with no protective environment. Confirming the presence of stagnant water includes: 

  1. analysis of the corrosion products in and around the pit; 
  2. tube sampling in affected areas to determine the presence of localized corrosion; and 
  3. evaluation of shutdown procedures to verify that conditions promoting stagnant water exist. 

Carryover of sodium sulfate and deposition in the reheater may result in the formation of acidic solutions during unprotected shutdown and can result in pitting attack. Similarly flyash may be pulled into reheater tubing under vacuum and form an acidic environment.

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News & Views, Volume 49 | Materials Lab Featured Damage Mechanism - Soot Blower Erosion

News & Views, Volume 49 | Materials Lab Featured Damage Mechanism: Soot Blower Erosion

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News & Views, Volume 49 | Materials Lab Featured Damage Mechanism - Soot Blower ErosionBy:  Wendy Weiss

Soot blower erosion (SBE) is caused by mechanical removal of tube material due to the impingement on the tube wall of particles entrained in the “wet” blower steam. As the erosion becomes more severe, the tube wall thickness is reduced and eventually internal pressure causes the tube rupture.

Mechanism

SBE is due to the loss of tube material caused by the impingement of ash particles entrained in the blowing steam on the tube OD surface.  In addition to the direct loss of material by the mechanical erosion, SBE also removes the protective fireside oxide. (Where the erosion only affects the protective oxide layer on the fireside surface, the damage is more properly characterized as erosion-corrosion.) Due to the parabolic nature of the oxidation process, the fireside oxidation rate of the freshly exposed metal is increased. The rate of damage caused by the steam is related to the velocity and physical properties of the ash, the velocity of the particles and the approach or impact angle. While the damage sustained by the tube is a function of its resistance to erosion, its composition, and its operating temperature, the properties of the impinging particles are more influential in determining the rate of wall loss.

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News & Views, Volume 48 | Metallurgical Lab Case Study – Grade 91 Elbows Cracked Before Installation

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By:  Wendy Weiss and Terry Totemeier

News & View, Volume 48 | Metallurgical Lab Case Study - Grade 91 Elbows Cracked Before InstallationStructural Integrity (SI) personnel visited a power plant construction site to examine four Grade 91 elbows (ASTM A234-WP91 20-inch OD Sch. 60) that were found to contain axially oriented surface indications. The elbows had not yet been installed. The indications were initially noticed during magnetic particle testing (MT) after one end of an elbow was field welded to a straight section and post weld heat treated (PWHT). Subsequently, three additional similarly welded elbows were inspected and indications were found at both the welded (inlet) and open (outlet) ends of three elbows. The elbow with the most significant indications was selected for SI’s on-site examinations. Figure 1 shows the inlet and outlet ends of the selected elbow.

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News & View, Volume 47 | Materials Lab Featured Damage Mechanism- SH:RH Fireside Corrosion in Conventional Coal Fired Boilers

News & Views, Volume 47 | Materials Lab Featured Damage Mechanism: SH/RH Fireside Corrosion in Conventional Coal Fired Boilers

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By:  Wendy Weiss

Superheater/reheater fireside corrosion is also known as coal ash corrosion in coal fired units.

News & View, Volume 47 | Materials Lab Featured Damage Mechanism- SH:RH Fireside Corrosion in Conventional Coal Fired Boilers

MECHANISM
Coal ash corrosion generally occurs as the result of the formation of low melting point, liquid phase, alkali-iron trisulfates. During coal combustion, minerals in the coal are exposed to high temperatures, causing release of volatile alkali compounds and sulfur oxides. Coal-ash corrosion occurs when flyash deposits on metal surfaces in the temperature range of 1025 to 1200oF. With time, the volatile alkali compounds and sulfur compounds condense on the flyash and react with it to form complex alkali sulfates such as K3Fe(SO4)3 and Na3Fe(SO4)3 at the metal/deposit interface, which are low melting point compounds. The molten slag fluxes the protective iron oxide covering the tube, exposing the metal beneath to accelerated oxidation.

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News & View, Volume 46 | Metallurgical Lab Featured Damage Mechanism- Waterwall Fireside Corrosion (WFSC) in Conventional Boilers

News & Views, Volume 46 | Metallurgical Lab Featured Damage Mechanism: Waterwall Fireside Corrosion (WFSC) in Conventional Boilers

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By: Wendy Weiss

News & View, Volume 46 | Metallurgical Lab Featured Damage Mechanism- Waterwall Fireside Corrosion (WFSC) in Conventional BoilersIndustry experience shows that waterwall tubing in conventional boilers can be susceptible to fireside corrosion, depending on fuel type, firing practice, etc. In boilers where fireside corrosion has been identified as a maintenance issue, wastage rates of 5 to 25 mils/year are not uncommon. Since the mid 1990s, the installation of low NOx burner systems designed to lower NOx emissions has significantly increased the wastage rates in some boilers. Operators of subcritical boilers have reported wastage rates as high as 30 mils/year, while those operating supercritical boilers have reported rates exceeding 100 mils/year in the worst cases. These higher damage rates have resulted in an increase in tube failures, and operators have struggled to accurately define the extent of the damage and install the appropriate mitigating technologies.

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News & View, Volume 45 | Metallurgical Lab- Case Study – Thermowell Failure Analysis

News & Views, Volume 45 | Metallurgical Lab: Case Study – Thermowell Failure Analysis

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By:  Wendy Weiss

News & View, Volume 45 | Metallurgical Lab- Case Study – Thermowell Failure AnalysisStructural Integrity (SI) was recently asked to examine a fractured thermowell and determine the damage mechanism.  The thermowell had been removed from bypass line piping in a heat-recovery steam generator (HRSG) that ran from the High Pressure (HP) bypass valve to the cold reheat section, and sent to the SI Materials Science Center. As reported by plant personnel, the fracture was located within the pipe wall. The pipe material was specified as ASME SA-335, Grade P22, and the thermowell was specified to be ASME SA-182, Grade F22.

Examination Procedure and Results

The fractured thermowell sections were visually examined and photographed in the as-received condition, as shown in Figure 1. The thermowell was comprised of two pieces: the thermowell housing itself which protruded into the steam stream, and a fitting connection to the pipe into which the thermowell housing was inserted.

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News & View, Volume 45 | Metallurgical Lab Featured Damage Mechanism Acid Dewpoint Corrosion in Conventional Fossil Boilers and Combined Cycle HRSGs

News & Views, Volume 45 | Metallurgical Lab Featured Damage Mechanism – Acid Dewpoint Corrosion in Conventional Fossil Boilers and Combined Cycle HRSGs

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By:  Wendy Weiss

Acid dewpoint corrosion can occur in conventional and HRSG units in locations where temperatures fall below the sulfuric acid dewpoint temperature. This can occur when either the tube metal temperatures are below the acid dewpoint so that condensate forms on the metal surface, or when flue gas temperatures are below the acid dewpoint, so that the condensate will form on fly ash particles.

Mechanism
This type of fire-side damage occurs when sulfur dioxide (SO2) in the flue gas oxidizes to sulfur trioxide (SO3) and the SO3 combines with moisture to form sulfuric acid. If the temperatures are at or below the acid dewpoint, so that the sulfuric acid condenses, then tube metal corrosion occurs. The temperature at which condensate first forms depends on a number of factors, including the partial pressures of SO3 and water vapor in the flue gas, but is usually around 250 to 300°F.

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