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

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

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

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

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

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

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

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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News & View, Volume 43 | Metallurgical Lab Featured Damage Mechanism- Failure of Dissimilar Metal Welds (DMW) in Steam-Cooled Boiler Tubes

News & Views, Volume 43 | Metallurgical Lab Featured Damage Mechanism: Failure of Dissimilar Metal Welds (DMW) in Steam-Cooled Boiler Tubes

By:  Wendy Weiss

News & View, Volume 43 | Metallurgical Lab Featured Damage Mechanism- Failure of Dissimilar Metal Welds (DMW) in Steam-Cooled Boiler TubesLarge utility-type steam generators inevitably contain a large number of pressure part welds that join components fabricated from different alloys.

Background
The welds made between austenitic stainless steel tubing and the lower-alloyed ferritic grades of tubing (T11, T22) deserve special mention because of the early failures that developed in some of these dissimilar metal welds (DMWs) soon after their introduction in superheater and reheater assemblies.  Prior to the mid-1970s, many DMWs were fabricated either as standard fusion welds using an austenitic stainless filler metal, such as TP308, or as induction pressure welds, in which the tubes were fused directly to each other without the addition of filler metal.  Some of these welds failed after less than 40,000 hours of operation, with the earliest failures being associated with DMWs that operated “hot” in units that cycled heavily and were subjected to bending stresses during operation. 

After the mid-1970s, and in response to extensive research carried out by EPRI and other organizations, an increasing number of DMWs in superheater and reheater tubes were fabricated as fusion welds using nickel-based filler metals, such as the INCO A, INCO 82, INCO 182, etc.

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