How to prevent corrosion and deposition, and maintain steam purity, in combined-cycle/cogen plants

By Irvin J Cotton, Arthur Freedman Associates Inc, and John Obermaier, Deltak LLC

The objectives of water treatment in heat-recovery steam generators (HRSGs) are the same as they are in all boilers:

  • Prevent metal failure caused by corrosion.
  • Minimize deposition on heat-transfer surfaces.
  • Maintain the steam purity required by downstream plant systems— such as the steam turbine.

It seems it should be no more challenging— perhaps even easier—to meet these objectives with an HRSG, compared to meeting them with a conventional fossil-fired boiler. Consider that the exhaust-gas temperatures from a combustion turbine are significantly lower than those from the furnace in a boiler, hence HRSGs experience a significantly lower heat flux. Also, heat-transfer rates generally are lower in an HRSG than in a conventional fired boiler.

However, many factors are at play in the typical HRSG that complicate the water-treatment program. These include:

  • Tighter constraints on capital cost, which often eliminates the standalone deaerator, leading to excessive concentration of dissolved oxygen (DO) in the feedwater during startup.
  • Leaner staffing, which can heighten the challenge of chemistry monitoring and control, and force the use of online instrumentation— relying on sensitive instruments which, in turn, must be consistently calibrated and maintained by that leaner staff.
  • Higher water velocities, caused by tightly packed tube bundles and short-radius bends, which can accelerate problems with erosion and flow-assisted corrosion (FAC, sometimes referred to as flowaccelerated corrosion).
  • Requirements to frequently cycle the plant. Multiple, fast startups, for example, can blast 1200F exhaust gas onto HRSG tubes cooled by the overnight shutdown, creating tremendous thermal stresses that can weaken the base metal.
  • Duct burners, which add significant amounts of radiant heat to the normal convection heat absorbed by the first row of finned tubes downstream, thereby accelerating under-deposit corrosion.
  • Process demands of a steam host, in the case of a cogeneration plant. The steam host may return condensate that is contaminated, forcing the need for additional chemical or mechanical treatments to protect the HRSG, or it may restrict the chemical-treatment options that can be used in the water/steam cycle. For example, a cogen plant providing steam to a milk-pasteurization process is strictly limited in its chemical treatment program by Food & Drug Administration standards.

As a result of these complications, HRSG users need a clear understanding of the specific corrosion, deposition, and steam-purity problems they face. It follows that they also need a clear understanding of the water treatment programs that can mitigate each problem, and of the monitoring and control systems that keep the prescribed treatment programs within limits. Water treatment programs for combined- cycle plants are published in great detail by the HRSG manufacturers, turbine manufacturers, EPRI, ASME, and others, and are not covered in this article. Similarly, the monitoring and control of water chemistry is discussed in detail in an accompanying article in the 2007 Outage Handbook supplement to the 3Q/2006 issue of the COMBINED CYCLE Journal.

Focus here is on the dominant water treatment problems faced by combined-cycle/cogen plants. The problems are categorized as:

  • Condensate-system corrosion/contamination.
  • Steam purity limits.
  • Boiler and feedwater-system corrosion.
  • Oxygen pitting in the HRSG.
  • Corrosion fatigue in the HRSG.
  • Under-deposit corrosion in the HRSG.
  • FAC in the HRSG.

Condensate system corrosion / contamination

In condensate systems, iron and copper corrosion can cause piping and equipment damage, as well as the loss of water and energy if the corrosion leads to condensate leakage from the system. An even bigger problem is contaminated condensate being returned and used as feedwater. These contaminants can quickly form deposits on internal HRSG surfaces, reducing plant reliability and increasing operational and maintenance costs.

Condensate can contain several contaminants that promote the corrosion reaction, the most common being DO and CO2. Oxygen corrosion is easily recognized by the presence of sharp-edged hemispherical pits. Referred to as oxygen pitting, this phenomenon begins at weak points in the iron-oxide film and continues at the same location. Oxygen can enter the condensate by direct absorption of air into the system. Good system design is required to minimize air contact with the condensate and subsequent oxygen absorption. Receiving tanks, condenser pumps, and condenser hot wells are common points in the system for air in-leakage.

The other dominant contaminant, CO2, results from the breakdown of carbonate alkalinity in the boiler water or it can enter the system with any air in-leakage. Once the CO2 forms, it dissolves in water, creating carbonic acid, which lowers the pH and promotes corrosion of the condensate piping and equipment.

The use of neutralizing amines (to neutralize carbonic acid and elevate the pH) and of filming amines, provides corrosion protection in the condensate system. Selection of the proper amine blend is critical for effective results. Different amines have varying levels of stability, and the selection will depend on plant specifics. Table 1 characterizes some common amines used in blends—such as cyclohexylamine, morpholine, and diethylaminoethanol (DEAE). Following is a brief explanation of key amine properties:

  • Distribution ratio is a measure of the volatility of amines. It is defined as the ratio of the concentration of the amine in the steam to that in the water. The distribution ratio of amines varies with pressure.
  • Neutralizing capacity is a measure of the ability of the amine to neutralize acids.
  • Amine basicity is a measure of how much pH elevation will result once any free acids are neutralized.

Steam purity

When the downstream load on the boiler or HRSG is a large, sophisticated steam turbine, steam purity is of great concern. Purity also is of major importance at cogeneration plants where steam is used for thermal-host processes that are vulnerable to contamination. Some results of poor steam purity include deposition on turbine blades and critical control valves, superheater failure, damage to steam lines, and impairment of the thermal-host processes.

In all cases, the tighter of the turbine manufacturer’s, or the thermal host’s, steam-purity specs must be followed (Table 2). This can be challenging: Many HRSGs, because of operational needs, will experience frequent load and water-level swings. At high pressures, a volatile species of great concern is silica. Boiler-water silica concentrations that correspond to the turbine manufacturer’s limits or less in saturated steam must be maintained.

The steam-purity control program should employ proper ASTM sampling nozzles, should monitor steam silica (as well as sodium or cation conductivity) on a continuous basis, and should sample both attemperation water and boiler blowdown water on a routine basis. Other steps that may be taken to maintain proper steam purity include:

  • Maintaining effective drum-water level control, keeping drum levels as constant as possible.
  • Minimizing the number, and duration, of times the plant is operated at the maximum load rating or experiences rapid load and level changes.
  • Following the gas-turbine and HRSG manufacturers’ guidelines for ramp rate.
  • Maintaining the chemistry of boiler feedwater and attemperation water within prescribed limits.
  • Using effective steam purification equipment.
  • Adhering to ASME or EPRI guidelines for fossil boilers regarding the maximum boiler-water concentration as a function of steam pressure. Note that the ASME guidelines currently are being modified to meet the unique needs of HRSGs.

The following incidents may indicate an excessive carryover situation requiring immediate operator action:

  • Superheated temperature drops. Sudden decreases in temperature frequently are caused by large amounts of water being carried into the steam.
  • High or fluctuating drum levels. Rapid load changes can result in drum level changes that can cause carryover.
  • Header pressure variat ions. Changing loads can result in water-level swings—caused by header pressure changes—which ultimately may lead to carryover.
  • Increasing superheater temperatures. An increase in metal temperature as measured by thermocouples on individual superheater circuits may indicate a buildup of deposit inside the tubes.
  • Turbine issues—such as a buildup of first-stage pressure, loss of capacity, and sticking steamadmission, regulator, or stop valves.

Boiler and feed water system corrosion

Oxygen pitting, corrosion fatigue, under-deposit corrosion, and FAC are major concerns in the boiler water systems of combined-cycle/cogen plants. Combating these destructive mechanisms requires good control of water chemistry.

To minimize corrosion in the boiler water system, plant operators must maintain an elevated or alkaline pH. More important—and unfortunately more difficult to control—is the concentration of DO in the feedwater. It is the main cause of oxygen pitting. Most oxygen should be removed in the deaerator by mechanical means. The scrubbing section of the deaerator heats incoming water by mixing it with steam. The solubility of oxygen and other dissolved gases is greatly reduced at elevated temperatures, and most of the gases are vented to the atmosphere. This mechanical scrubbing usually reduces the oxygen concentration to less than 20 ppb.

Many specialists consider oxygen even at this relatively low concentration to be harmful to feedwater systems, and advise injecting chemicals—known collectively as “oxygen scavengers” or “reducing agents”—to further slash the oxygen concentration. Many other specialists, however, strongly discourage the use of these reducing agents in plants with all-ferrous metallurgy, since some oxygen and an oxidizing environment can be beneficial. To do this it is important to have excellent boiler feedwater quality with very low levels of contaminants. The trend today in the combined-cycle/cogen community is to eliminate or at least minimize the use of reducing agents. Each system must be evaluated separately using established guidelines.

When used, oxygen scavengers include sulfites, hydrazine, and organic scavengers—such as diethyl hydroxylamine (DEHA), ascorbic acid, hydroquinone, and oximes— with and without catalysts. Rates of reaction depend on initial oxygen concentration, reaction time, temperature, pH, catalytic effects, the scavenger used, and the scavenger concentration.

Oxygen concentration also must be controlled through proper lay-up, startup, and shutdown procedures, since significant oxygen ingress can occur during plant downtime and transients.

Lay-up procedures. Most oxygen attack in HRSGs occurs offline during lay-up, or during the preceding shutdown and subsequent startup. Proper steps must be taken—using a wet or a dry lay-up procedure, depending on the operational situation—and taking extra care to ensure that pH and oxygen are maintained per specifications. Since each case is specific, procedures must be developed for each unit and plant.

Short-term wet lay-up is considered to be approximately 48 hours or up to the time that the drums lose positive internal gauge pressure through temperature reduction. Use of equipment such as a stack damper to reduce the rate of cooling will maintain pressure for a longer period. Long-term wet lay-up generally is used for outages lasting two to 30 days, although this method can be used for longer periods of time if water chemistry is closely monitored and adjusted over time. For lay-ups longer than 30 days, a dry lay-up is often implemented.

The procedure for wet lay-up will depend on water chemistry program, materials of construction, and how soon the plant will return to service. In the event that nitrogen or sparging steam cannot be used to pressurize the HRSG, oxygen will eventually infiltrate the steam/water side, and a specific water chemistry program for lay-up will be more critical.

During a short-term wet lay-up, residual pressure will prevent infiltration of oxygen into water and steam paths of the HRSG and typical operating water chemistry can be maintained. As component temperature falls, nitrogen or steam can be injected into the unit to maintain pressure. Nitrogen is typically used to maintain the pressure at 5 psig. Sufficient nitrogen will be required to blanket the superheater and cap the drum.

If the lay-up is extended to a longer term, chemical additions and sampling are required to maintain proper water chemistry. The choice and concentration of chemicals will determine the need to drain the unit prior to operation.

Dry lay-up may be required for short-term maintenance or when a long-term wet lay-up is not practical. The HRSG should be drained when still hot to evaporate as much water as possible, using care to drain to a suitable location. If the lay-up will be long-term, all water must be removed and additional methods to maintain low moisture within the steam and water paths are recommended.

Oxygen pitting in the HRSG

Oxygen-induced corrosion of mild steel is an electrochemical reaction common in HRSGs that leads to both general corrosion and localized pitting of the internal metal surfaces. As discussed above for feedwater systems, the rate of oxygen pitting in HRSGs increases with increasing oxygen level and off-spec pH.

Improper wet lay-up procedures or startup procedures can lead to oxygen levels in the boiler water that are many times greater than normal operating levels. During dry lay-ups, high humidity or poor drainage will accelerate the corrosion. It follows, therefore, that plants that cycle are subject to much more corrosion damage than plants that don’t.

Several operational steps can be taken to avoid, or at least minimize, HRSG damage caused by oxygen pitting. Chief among them is minimizing oxygen in the feedwater. The oxygen level frequently recommended is 5-15 ppb. To promote the formation of a healthy, protective magnetite layer, oxygen level should not be reduced below 5 ppb. Maintaining deaerator tank pressure and condenser vacuum during short outages will help control oxygen in the feedwater. As additional protection, proper lay-up procedures will reduce the exposure of the HRSG’s internal surfaces to both oxygen and moisture. The importance of proper layup procedures in frequently cycled combined-cycle/cogen plants cannot be overstated.

Case study: oxygen pitting. A forced-circulation HRSG with vertical gas flow and horizontal tubes experienced oxygen pitting in its economizer, evaporator, and superheater sections. To determine the extent of the damage, a laser scan of approximately 10% of the tubes was conducted (Fig 1).

The scan revealed that the pitting was predominately on the bottom inner diameter (ID) of the tubes, but also continued up the tube walls. Calculations showed that the pitting depth left a tube-wall thickness that was below the minimum required by the ASME Boiler and Pressure Vessel Code. Without chemical cleaning of the tubes, and without revised lay-up practices, the frequency of tube failures was expected to increase. However, past experience has shown that chemical cleaning of severely pitted tubes may result in many immediate leaks, causing an unplanned, and lengthy shutdown. As a result, the owner opted to re-tube the entire unit at the next outage.

In this case study, the damage most likely was caused by oxygen infiltration into pools of water during a dry lay-up.

Corrosion fatigue in the HRSG

Corrosion fatigue is a destructive failure mechanism that occurs in metals as a result of the combined action of a cyclic stress and a corrosive environment. Very often, the corrosive environment is an oxidizing one. The combined effect of the two factors is much greater than the effect of either one alone.

The combined action of cyclical stress and oxidation can cause corrosion fatigue failures in a relatively low number of stress cycles. This is not to say that a corrosive environment is required for fatigue cracking to occur, or that cyclic stress is required for corrosion (say pitting) to cause tube leaks. Either factor alone can cause HRSG tube leaks. However, the simultaneous action of the two components of corrosion fatigue is synergistic, causing rapid tubing failure. Economizers are most susceptible to corrosion fatigue because they are often constructed of carbon steel and may experience high stresses during startup.

Corrosion-fatigue cracking usually begins at surface defects or oxygen pits, which act as stress concentrators. Corrosion pits may form on the tube ID when oxygen is present. Corrosion-fatigue cracks propagate, through the combined effects of cyclic stress and corrosion. When a stress is applied to a tube, the stress is concentrated at the root of the corrosion pit. The concentrated stress can far exceed the material yield stress, causing the root of the crack to plastically deform.

The protective corrosion layer will be cracked away from the plastically deformed area, exposing new material to the effects of oxygen corrosion. This process will be repeated each time the tube is exposed to a stress cycle, driving the crack deeper into the material. The number of stress cycles required to fail the tube is dependent upon both the level of the applied load and the oxygen concentration.

To minimize corrosion fatigue in the HRSG, several operational steps can be taken. These include:

  • Maintain economizer flow at startup. Keep water flowing through the economizer or preheater during periods of low or no steam flow. Blow down water from the evaporator or divert it from the economizer outlet to a “storage” volume upstream in the steam cycle—the condenser hotwell, for example. Water flowing continuously through the economizer or preheater during startup will prevent excessive metal temperatures in the HRSG component, thus minimizing the magnitude of stress cycles caused by thermal shock.
  • Minimize oxygen in the feedwater. This may include maintaining deaerator tank pressure and condenser vacuum during short outages, and use of wet lay-up procedures versus draining of the HRSG for longer outages.
  • Minimize sudden changes in feedwater flow or temperature. The feedwater control system should be carefully tuned to remove control parameters that permit sudden changes in feedwater flow. It may be necessary to modify the feedwater control valve package to include a smaller startup control valve to provide finer feedwater flow control at startup.

Case study: corrosion fatigue.

Fig 2 illustrates an example of corrosion fatigue caused by cyclical stress and exposure to high oxygen content. In this example, a carbon-steel feedwater heater received deoxygenated water from the condenser hot well during startup. The water from the feedwater heater entered the deaerator, where oxygen was further reduced to obtain levels prescribed for the boiler and economizer systems. Pegging steam was available to the deaerator for operation during startup.

Unfortunately, during initial operation, condenser problems dictated frequent plant shutdowns. The condenser hot well was unable to maintain a vacuum, which led to an oxygen concentration that was many times the normal operational level in the feedwater preheater. Subsequent startups after these outages allowed transient high oxygen levels.

In addition to high oxygen levels, the input of cold (ambient temperature) water into the hot feedwater panels during startup created stress at the upper and lower return bends of the inlet pass. The thermal stresses in the feedwater heater were relatively small. The difference in gas and water temperatures at the location of the failure would have been less than 100 deg F. This would result in even lower differential temperatures of the tube metal between the first and second passes. Alone, therefore, the cyclical stress would not cause a failure.

However, oxidation combined with the stress initiated the corrosionfatigue cracks, and the combination of repeated corrosion and stress risers at the tip of the crack allowed the crack to propagate through the tube wall.

At this plant, the recommendation was that the carbon-steel feedwater preheater be replaced with a duplex stainless-steel type. This recommendation was based on the plant’s desire to cycle frequently and the assumption that the feedwater preheater would continue to experience high oxygen levels during startup.

The carbon-steel economizer in this unit is just now experiencing corrosion fatigue—eight years after the feedwater heater failed. Failure of the economizer suggests that startups contributed to the corrosion. The difference in timeline could be attributed to the use of the deaerator and pegging steam, or of the oxygen scavenger to remove DO upstream of the economizer. In addition, the economizer uses a thicker-wall tube.

Under-deposit corrosion in the HRSG

Under-deposit corrosion is a failure mechanism where evaporation of water within tube wall deposits forms a corrosive concentration of chemicals at the boundary of the deposits and the base metal. Underdeposit corrosion typically occurs in HRSG evaporator tubes, though it also can occur in any circuit where steam is generated under certain conditions.

Deposits that form on the tube wall originate from a variety of sources— such as feedwater impurities, chemical additions, and corrosion products within the boiler and preboiler sections of the HRSG. Solids in solution can precipitate out when concentrations increase because of high evaporation rates, or when the solubility decreases from fluctuating temperatures and pressures within the boiler.

The initial deposit also may develop by oxidation of the tube wall. In the absence of a strong magnetite layer, thicker and more porous oxide layers—such as wustite or hematite— may form.

Deposits tend to form in areas where local steam quality is the highest. Areas with high heat flux, such as finned tubes downstream of a duct burner, are most at risk as well as tubes having a low water velocity or circulation ratio. Areas of steam blanketing and flow disturbances are initiation points for under-deposit corrosion.

Under-deposit corrosion in HRSGs can occur in one of several modes, depending on the water chemistry program. Each mode is similar in appearance, so a metallurgical analysis as well as review of past water chemistry is required to determine the specific mode—and thereby select the corrective action. Modes include (1) caustic attack, which results from elevated levels of sodium hydroxide; (2) phosphate attack, which results from the reaction of magnetite with disodium or monosodium phosphate; and (3) acid attack, which results from the release of acidic chemicals into the feedwater. Acid attack also is referred to as hydrogen damage because the tube microstructure becomes brittle the formation and penetration of methane. This can result in a fracture of the tube wall in lieu of a final through-wall, pin-hole failure from corrosion.

Case study: under-deposit corrosion.

Two HRSGs were installed in 1990, each a three-pressure system in cogeneration service, with an operating HP steam pressure of 923 psig. The plant relied on a coordinatedphosphate water treatment program, based on disodium and monosodium phosphate. The sodium-to-phosphate molar ratio was supposed to be controlled between 2.2:1 and 2.8:1. The drum water pH target control band was 9.7 to 10.4.

In 2002, the plant reported two instances, within seven weeks of each other, where a condenser leak of hydrochloric acid caused the pH to fall to 5.4 for 48 hours and 5.0 for 24 hours, respectively. In response to each pH excursion, the pH was increased by adding caustic and trisodium phosphate while the plant remained on-line. One month after the second excursion, tube leaks were observed in the front tubes of one unit’s evaporator section immediately downstream of a duct burner.

During an outage a few months later, leaks were observed in 54 evaporator tubes of that unit, with evidence of under-deposit corrosion observed in the form of multiple mound shaped deposits (Fig 3). The deposits formed in three rows of tube immediately downstream of a duct burner and only in the lower half of the tube, primarily along the sidewalls. Inspection of the other unit showed no signs of tube damage. This was puzzling, because both HRSGs receive feedwater from the same source, so both HRSGs were subject to the same low-pH excursions.

While the chemical excursion may have caused the corrosion, a previous chemical cleaning may have served as the source of deposit formation. Both units were chemically cleaned after construction 13 years earlier. Commissioning records indicate that the cleaning procedure was not 100% complete in the affected unit or not performed according to procedure. If true, this might explain why underdeposit corrosion was initiated in one unit and not the other.

There was no further evidence to suggest any particular type of deposit or timeline of the formation for the initial deposit. Therefore, samples were sent to two independent parties for chemical analysis and interpretation. The results did not provide clear evidence of a specific mode of under-deposit corrosion. Corrosion products in support of acid-phosphate attack or caustic gouging were not observed in significant quantity after spectral analysis. Hydrogen damage was also not observed in either sample. Despite one suggestion of caustic attack, investigators believed that this mode of underdeposit corrosion was not the most probable cause.

EPRI has noted that corrosion under acid attack will occur much more rapidly than corrosion under caustic attack for the same concentrations of sodium hydroxide and chloride. The time between the lowpH excursions and the tube leaks (one to two months) suggests that the excursion facilitated, and may have initiated, the corrosion. Thus investigators concluded that acid attack was the most probable mode of under-deposit corrosion, despite the fact that hydrogen damage was not observed.

The mounds of porous corrosion products leading up to the final failure were a platform for rapid localized boiling that would have trapped and concentrated feedwater chemicals. Treatment of the feedwater after the acid leak or ongoing phosphate chemistry program could have resulted in additional corrosion by caustic gouging or acid-phosphate attack. Although the examination results were not conclusive in this case, guidelines are available to identify the mode of corrosion and recommend action for each situation.

FAC in the HRSG

FAC is a progressive form of waterside metal wastage that strips away metal from the wetted surfaces of pressure parts. Pressure parts will thin if FAC is occurring, and failures will result if it is allowed to continue. The phenomenon is most likely to attack pressure parts under the following conditions:

  • Reducing environment (zero oxygen, possible excess scavenger).
  • Extremely low DO content (at or near zero).
  • Low boiler-water pH (less than 9.2).
  • High water-side velocities.
  • Water temperatures between 230F and 480F.
  • Pressure parts made of carbon steel.

Under normal conditions (no FAC attack), iron is constantly being transported out of the pressure-part wall by two paths. Iron is oxidized to magnetite (Fe3O4) which forms a protective oxide layer on the inside of the pressure part. Simultaneously, iron from the base metal and the magnetite layer is “dissolved” into the flowing fluid. Under normal conditions, the magnetite formation and dissolution rates are equal, and both the magnetite and iron dissolution rates are very slow. This process results in a firm protective magnetite (corrosion) layer and only small amounts of iron dissolved in the fluid (typically less than 5 ppb).

Under conditions of active FAC, the magnetite layer is dissolved into the fluid stream more quickly by a reduction reaction promoted by the presence of hydrogen in the water. This process is directly proportional to the oxidation-reduction potential (ORP) of the fluid. At the same time, iron diffuses across the magnetite layer into the bulk fluid stream inside the pressure part at an accelerated rate as the magnetite layer is thinned. Both processes result in an increased dissolved iron level and an increased rate of iron transport from the pressure part—in other words, material thinning.

In HRSGs, the low-pressure (below 250 psig) evaporators and the lowtemperature (less than 480F) economizers are the most susceptible to FAC damage. These components tend to operate in the most susceptible temperature range and may see higher than usual water-side velocities under certain operating scenarios (Fig 4).

FAC can be detected through careful tracking of iron content in the boiler water, and through nondestructive evaluation of vulnerable areas using ultrasonic testing and boroscope inspection.

Case study: FAC.Thinning of pressure- parts materials was observed in the low-pressure (LP) section of a twopressure HRSG operating in cogeneration service. The unit was installed in 1996 and consists of an HP and LP pressure level. The HP evaporator is rated approximately 350,000 lb/hr of saturated steam at 630 psig/494F, the LP evaporator approximately 34,000 lb/hr of saturated steam at 27 psig/269F. Steam from the HP evaporator (after superheating) is used by a thermal host, while steam from the LP evaporator is used for deaeration of the feedwater.

An inspection was performed to determine the nature of the metal thinning. It was diagnosed as FAC, based on the temperature regime of the affected section, the nature of the thinning, and operational data—specifically, data on DO and pH. During the inspection, FAC was found in these four areas of the LP system:

  • Piping fittings between the upper header and LP drum.
  • LP-drum downcomer pipe and vortex.
  • LP lower manifold.
  • Tube bends into the headers.

To help understand the causes of FAC, oxygen levels in the LP section were trended, using data collected over a three-year period. The levels typically were less than 5 ppb, and often were zero, substantially contributing to FAC (Fig 5). The plant reported use of carbohydrazide as an oxygen scavenger at the chemical dosing station. The initial application of carbohydrazide was at 0.6 ppm, but at the time of inspection the scavenger was dosed to 0.05 ppm minimum value. Up to seven months before the inspection, the plant had used hydrazine as an oxygen scavenger, dosed to 60 ppb.

The plant sells steam to a thermal host, which dictated an upper pH target of 9.0. This is lower than desired for FAC prevention. Trending actual plant data, however, revealed that the average pH was even lower—below 9.0—leaving the LP section even more vulnerable to FAC (Fig 6).

The pressure at which the LP boiler is operated is a key parameter in reducing the risk of FAC damage. As pressure is decreased, an increase in fluid-mixture specific volume results in an increase in velocity. For natural circulation HRSGs, this is especially true in circuits between the upper half of the evaporator tubes and the steam drum.

Analysis of three years worth of LP-boiler operating-pressure trend plots revealed that average LPboiler operating pressure had been increased from approximately 47 to 58 psig. Both pressures are above the originally intended operating pressure of 27 psig. The LP boiler was designed for safe internal velocities with an operating pressure of at least 27 psig. With the increase in operating pressure, resulting in a decrease in water/steam mixture specific volume, actual water-side velocities were lower than original design values, hence lowering the risk of FAC.

The plant reported that the pH of the boiler water could not be raised above 9.2, because of thermal-host restrictions. In addition, oxygen levels could not consistently be controlled to the prescribed range. Because of these operational restrictions, investigators recommended replacing the affected areas with 2.25%-chrome steel. ccj oh