Irvin J. Cotton Consultant R. Henry Weed, PE Sr. Project Engineer - IPP BetzDearborn Water Management Group John Kolarick Operations Manager Westinghouse Operating Services Co. Sayreville, NJ cal treatment. In a typical HRSG system, there are three main water treatment concerns: · preventing metal failure due to corrosion · minimizing deposition on heat transfer surfaces · maintaining steam purity The typical independent power/cogeneration facility also has a number of additional constraints which make water treatment more difficult than a utility or industrial power plant. These constraints range from limited properly trained personnel to perform required testing and feeding to plant shutdowns to unusual operating needs (such as extended periods of minimum power generation). In addition, the various feedwater and heating arrangements and different pressure boilers make treatment very site specific. All of these constraints can have an effect on HRSG reliability. Interruption in plant reliability can cost hundreds of thousands of dollars. This cost may be incurred by the owner and/or the operator for equipment replacement, emergency repair, or installation. In many cases, the outage is not scheduled, so there usually are penalties incurred from not meeting availability criteria. To improve HRSG reliability, it is important to understand several key items, such as HRSG design differences, selection of a comprehensive water treatment and monitoring program, and knowledge of water side reliability problems with HRSGs. Figure 1 shows a typical arrangement of a combustion turbine and HRSG in the power and steam production system of a combined cycle cogeneration facility.

To Steam Turbine Electric Generator To Host Steam System or to Combustion Turbine Steam Turbine Exhaust Gas Flow Electric Generator High Pressure Boiler System Combustion Turbine Air Fuel InterMediate Pressure Boiler System Low Pressure Boiler System To Deaerator


Reliability is a critical factor in independent power and cogeneration operations. The heat recovery steam generators (HRSG) are a major part of the power system. Thus, an understanding of HRSG design and operational parameters, along with specific knowledge of steam host plant needs, is required to engineer an effective boiler system water treatment program. This paper reviews various HRSG designs and the boiler chemical treatment programs that should be applied for each. Examples of water-side failures and how they were corrected are presented throughout the paper. Emphasis is placed on the importance of coordinated pH/phosphate chemistry, proper oxygen scavenger selection, and effective pH control through amine chemistry. Metallurgical analyses and design and operational information are presented for two similar plants as well as several case histories. Recommendations for improved design interface and on/off line monitoring are included. Brief mention is made of some of the state-of-the-art monitoring and feed systems which can also improve plant reliability. The parameters affecting erosion/corrosion, one common specific problem area, are also reviewed.


There are hundreds of cogeneration facilities across the country which couple a combustion turbine and a heat recovery steam generator to produce high temperature steam for electrical generation and for sale to host plants. The high thermal efficiency of these systems, combined with ease of construction, flexibility in operation, and acceptable environmental impact make them economically attractive. However, because cogeneration facilities are often tied into the host plant operation, there are additional considerations which sometimes receive less attention. One of these is the system's water quality and chemi1

Figure 1: Typical Combined Cycle Facility


An understanding of the heat fluxes and water and steam flows in an HRSG is an important first step in system treatment. There are several major combustion turbine manufacturers, several major boiler manufacturers, and many load, process, and power requirements for particular operating conditions. Given these varied requirements, there are numerous HRSG design configurations. These differences have been shown to have a significant impact on the requirements of the water-side treatment and even on unit reliability.

Steam Host To Steam Host Condenser To Combustion Turbine

Demineralized Makeup Deaerator

SCR Exhaust Gas Flow

FW Heater Attemp. HP Evap HP Superheater

IP Evap HP Econ IP Superheater

LP Evap IP Econ

LP Econ

Heat Removal Arrangement

The basic HRSG system directs the combustion turbine exhaust through an insulated, ceramic-lined exhaust duct. Inside the duct are vertical, finned tubes that remove heat. The tubes are constructed of various alloys, including stainless steels, and they are interconnected by headers and/or drums, depending upon the particular design. Water, steam/water, or steam travels through the tubes. As the exhaust gas passes through different sections of the duct, it gives up its heat to the different boiler sections. Each boiler section has tubes arranged to remove the required amount of heat. In a typical high pressure or intermediate pressure section, the first bank of tubes is the superheater, followed by the generating tubes, then the economizer tubes. Low pressure systems include an economizer and feedwater heater. A reheat cycle or bypass may be incorporated around the intermediate pressure boiler, but these two arrangements will not be discussed here. The heat removal sections of a typical three-pressure HRSG system are shown in Figure 2. The exact configuration of the feedwater system of each boiler is extremely important, since it can have a significant impact on the boiler water treatment options available. Figure 3 shows a typical three-pressure boiler system with an external deaerator and storage tank. This arrangement permits treatment of the deaerator with oxygen scavenger and amine and treatment of each steam generating system as an individual boiler system. In comparison, several HRSG manufacturers have designs which use the low pressure boiler steam drum as the deaerator storage tank. The LP system functions as a boiler system since steam is produced and feedwater is received from the deaerator. However, it 2

Figure 2: Arrangement of Heat Removal Sections

Low Pressure Steam Demineralizer Makeup Condensate Low Pressure Steam Deaerator

High Pressure Steam

InterMediate Pressure Steam

Storage Tank

Exhaust Gas Flow

Figure 3: Multi-Pressure Boiler System with Common Deaerator

cannot be treated with conventional coordinated pH/phosphate chemistry since the steam drum provides feedwater for the high and intermediate pressure boilers. The typical pH of this system is similar to the feedwater pH, 8.8 to 9.6. This can make it more susceptible to magnetite instability and corrosion in systems with design or operational constraints. Figure 4 shows an HRSG system with the low pressure drum providing feedwater to the other boilers.

Multiple Pressure Systems

In a traditional powerhouse operation, there may be multiple boilers, but their pretreatment and boiler treatment are usually independently controlled. On the other hand, the combined cycle facility using one HRSG has multiple pressure boilers, with common pretreatment, identical boiler treatment, and interconnected steam operation.

Makeup Condensate High Pressure Steam InterMediate Pressure Steam





Distribution Ratio


Cyclohexylamine Ammonia Diethylaminoethanol Morpholine


Exhaust Gas Flow



Figure 4: Multi-Pressure Boiler System with Integral Deaerator


This can cause difficulties in maintaining proper boiler chemistries. Typically, the feedwater available for the lower pressure units is the same as that available for the high pressure unit. The difficulty becomes apparent when trying to maintain proper boiler water pH in each drum. First, there is a tendency to try to operate the lower pressure units at higher cycles of concentration than the high pressure unit. This means that all contaminants, as well as all additives, are cycled to a higher concentration. Secondly, the effect of any neutralizing amine in the boiler system must be considered. This includes any amine incorporated into the oxygen scavenger or from amine in the return condensate. Each neutralizing amine has a specific distribution ratio (DR), which is the percentage of amine found in the vapor phase divided by the percentage found in the liquid phase at the specified pressure. In addition, in high purity systems, the effect of amine basicity and distribution ratio can have different effects at each boiler pressure level (see Figure 5).










Pressure (psig)

Figure 5: Distribution Ratios of Neutralizing Amines Vs. Pressure

and 50,000 lb/h (22,500 kg/h) in both the intermediate pressure and low pressure boilers. If all three boilers operate at 100 cycles of concentration, the final concentration factor in the intermediate pressure drum will be 300, while in the low pressure drum it is 400 times. This means that for boiler feedwater that meets ASME guidelines for iron (e.g., 0.020 ppm, or mg/L, iron) the iron concentration in the intermediate and low pressure boilers could approach 8 ppm (mg/L). This high level of contaminants could increase the risk of deposition and possibly cause heat transfer loss and failure.

Steam Purity

Steam purity is a major factor in HRSG system design. Poor steam purity can result in the following: · steam turbine deposition and corrosion · condenser corrosion · superheater fouling or cracking · steam line cracking · combustion turbine fouling · host plant problems Each HRSG manufacturer has various types of steam separation equipment designed to remove moisture from the steam. This includes cyclone separators, chevrons, baffle plates, and wire mesh screens. However, the amount of equipment included and the specific design can vary depending upon the steam purity requirements of the bid specification.

Cascading Blowdown

The operating requirements of the owner or host plant must be fully incorporated into the design of HRSG systems. Many plants want to conserve heat, reduce makeup water requirements, and control chemical treatment costs by cascading boiler blowdown from the high pressure boiler to the intermediate pressure unit. Some designers have proceeded further to also cascade the intermediate pressure blowdown to the low pressure system. What is important in the design stage is the effect of the higher level of contamination in the lower pressure boilers. For example, consider a system producing 100,000 lb/h (45,000 kg/h) in the high pressure unit 3

Each user of the steam should be consulted to determine what level of steam purity is required. For example, suppose a facility's steam purity requirements for sodium are <0.005 ppm (mg/L). The original design specifies cascading boiler blowdown to save heat. Based upon this operating constraint, concentration of sodium in the intermediate pressure boiler water is expected to be 20 ppm (mg/L). If the boiler manufacturer offers steam separation equipment which can reduce carryover to 0.1%, the intermediate pressure unit steam would contain 20 ppb (µg/L) of sodium. The plant is forced to decide to discontinue the use of cascading blowdown, use higher purity makeup water, or pay a possible increase for the capital cost of the steam separation equipment.


Steam Drum Evaporator Drum

Headers Exhaust Gas Flow


Lower Drum

Figure 6: Three Drum Boiler Arrangement

Steam Drum

Water and Steam Flow

Knowledge of the specific flow of makeup water, feedwater, and steam within the HRSG boiler system is important. This information makes it possible to determine the level of treatment required and the restrictions on that treatment. The exact configuration of the headers, steam drum, generating tubes, downcomers, etc. must be known to set up a comprehensive inspection and monitoring schedule. For example, makeup water in HRSG systems is usually demineralized water. Since this water is fully oxygenated, the system metallurgy must be corrosion resistant. Corrosion due to low pH and oxygen pitting must be controlled with mechanical and/or chemical oxygen removal and amines to adjust pH. Figures 6 and 7 show two different designs for this part of the boiler system. Figure 6 shows the flow from the steam drum down the large downcomers into the lower drum and/or headers. In this arrangement, the sets of vertical generating tubes (risers) carry a mixture of steam and water into the "evaporator" drum. This drum is usually designed to be fully submerged at all times and it directs the steam/water mixture into the baffled portion of the steam drum. In the steam drum, the steam separation equipment removes the moisture from the steam through a series of cyclones and mist eliminators. As shown in Figure 7, the feedwater flows into the downcomers and to the lower headers and/or drum. The generating tubes from the lower section are "risers." These risers discharge the steam and water mixture directly into the steam drum separation equipment. Flow information is important when troubleshooting or when trying to determine which area of the boiler is more likely to be susceptible to deposition and/or corrosion problems. Experience has shown that these 4


Headers Exhaust Gas Flow

Lower Drum

Figure 7: Two Drum Boiler Arrangement

problems include erosion/corrosion in the low pressure section (discussed later), steam blanketing, and deposition in vertical risers near baffles and duct walls in the high pressure section. The problem of steam-blanketing is commonly seen in horizontal runs of tubes usually due to high heat input and circulation problems (see Figure 8). Where steam blanketing is occurring, deposition can occur and corrosion can take place even without the presence of free caustic. In this area, there is a steam/magnetite reaction and the dissolution of magnetite. In such cases, operational changes or design modifications may be necessary to eliminate the cause of the problem.

Figure 8: Steam Blanketing of a High Pressure Riser Tube

Host Requirements

Combined cycle plants must meet the steam requirements of the host plant, while at the same time fulfill the contractual obligations for electrical production to the utility power grid. Three areas of concern are: · varying host steam load demands · stringent host steam purity requirements · condensate contamination Of primary concern from a design standpoint are the steam flow and pressure requirements of the host. The various steam load scenarios must be outlined to the HRSG designer to ensure that the system can meet those needs. A second concern, which is frequently overlooked, is the input of host plant steam requirements on design. These specifications usually define steam purity in terms of maximum limits of total dissolved solids. However, they may also establish limits on the types of volatile components and their concentration in the steam. This is seen frequently in plants which are regulated by FDA or USDA and are also seen in plants which have process limitations. The third concern, which arises from close association with a steam host, is varying heat value and purity of condensate return from the host. These parameters determine the level of condensate treatment required, determine pretreatment needs, and establish where the host condensate can be pumped back into the feedwater cycle. Contaminated condensate can impact the reliability of operation, and provisions must be made to handle this problem when it occurs. These concerns emphasize that maintaining a close and ongoing relationship with the host company is critical.

the exhaust gases. Even with straightening vanes (which uniformly distribute gas flow) steam generation in one part of the boiler may be higher than in an adjacent area. Temperature and velocity profiles on operating units have indicated varying heat fluxes in different areas.

Design Versus Operating Conditions

In HRSG systems, operating pressures can vary significantly from the original design pressure. When combined with varying load requirements, this can lead to problems. For example, if the design pressure is significantly higher than the operating pressure, the velocity of the fluid flow through the tubes can be affected. This can have a significant impact on the reliable operation of the HRSG. In particular, the low pressure section of the HRSG may be more susceptible to the effects of these pressure changes. For example, the specific volume of saturated steam at 25 psig (1.8 kg/cm2) is 10.6 ft3/lb (0.7 m3/kg). At 10 psig (0.7 kg/cm2), the specific volume increases to 16.5 ft3/lb (1.1 m3/kg). This is a 56% increase in specific volume for a relatively small decrease in operating pressure. Since the cross-sectional area in the tubes was fixed during design, this increase in specific volume increases the velocity of the fluid flowing through the tubes. This is one factor that can have an impact on the erosion/corrosion phenomenon seen in some HRSGs. Generally, the impact of changes in operating pressure are not seen in intermediate and high pressure boilers. The estimated maximum velocity and metallurgy type must be specified by the boiler manufacturer for all anticipated operating conditions. Particular emphasis should be made to known problem areas.

Duct Burners/Varying Heat Flux

The inclusion of duct burners is another major design difference which should be considered. Duct burners are used primarily to supplement the heat input when steam thermal demands exceed the heat available from the combustion turbine exhaust. Some facilities use the duct burners for burning waste fuel products or to provide heat for host steam production when the combustion turbine is down. The exact location of these burners can affect heat fluxes in a particular portion of the HRSG. Problems that can occur with duct burners include improper orientation and overfiring in one section. In addition, even without duct burners, there may be a higher heat flux in one area due to poor distribution of 5


The host plant steam requirements are usually communicated directly to the owner. The owner balances these needs with financial considerations when an Engineer/Procure/Construct (EPC) contractor is hired. The host plant steam requirements are then relayed to the equipment designers through bid specifications and other meetings. Even though all parties attempt to communicate effectively, not all considerations may be met. Improving the communication path should be a priority to minimize operational problems. Specifically, once the equipment supplier has been selected, there should be more direct interface between the user and designer. It is during this period that some of the special conditions and unusual operating scenarios can

be discussed to ensure that the HRSG system can reliably handle them.

boiler water indicated elevated iron levels in both pressure boilers. Subsequent investigation showed that there were several items which were contributing to the problem. First, there was metal loss associated with a feedwater valve which was improperly installed. Metal loss was also occurring in the piping returning heated feedwater to the deaerator. Secondly, inspection of the vortex breakers in the low pressure steam drum showed extensive metal loss. After redesign and replacement of these components, the iron levels were lower, but still well in excess of expected levels. Boroscopic inspection of the steam generating tubes in the area just prior to entry into the evaporator drum of the low pressure system showed a significant localized wear pattern. The pattern and metallurgical examination confirmed that erosion/corrosion was the primary cause of the metal loss in this elbow area. The upper row of elbows entering the evaporator drum on the side facing the gas pass were replaced on one unit with T-22. T-22 is a higher alloy chromium/molybdate material, which has higher erosion wear resistance than the standard SA178A carbon steel material. In the other unit, the existing carbon steel tubes were not fully replaced. Further investigation revealed that the cyclone separators in the low pressure steam drum showed significant metal loss, requiring repair or replacement. In addition, the crossover tube designed to feed the steam/water mixture to the far set of cyclones showed significant metal loss. It was replaced during the outage. Following the outage, an evaluation was conducted to determine if other factors could be isolated which were contributing to increased metal loss. The factors evaluated included: · feedwater temperature (heater in and out of service) · phosphate and pH levels · oxygen scavenger usage · operating pressure of the low pressure system On-site iron testing, with confirmation of results by laboratory analysis, was continued. In addition, an Orbisphere hydrogen analyzer was connected to the steam and feedwater samples. This instrument can detect low levels of hydrogen gas which can be related to corrosion. Feedwater temperature and phosphate treatment levels had no effect on iron levels. The hydrogen analyzer also did not indicate any significant variation with 6


Two plants having similar designs began to experience boiler tube failures at approximately the same time. These two plants, one located in the mid-Atlantic area and one in New England, had the same general components. Both facilities fire natural gas in two 104 MW combustion turbine trains and recover the exhaust heat in two, dual pressure, same manufacturer HRSGs. Both plants also use one single flow extraction steam turbine to generate an additional 50 to 90 MW. Cooling of the steam from the turbines is accomplished with air cooled condensers. Each HRSG produces 900 psig (63 kg/cm2) superheated steam for steam turbine use and export to a steam host. Low pressure steam is sent to the low pressure steam systems for use in the deaerator, steam turbine, or steam host. However, differences in operational and host plant requirements impacted the two relatively identical systems. Inspection and investigation revealed that the metal loss problems were different. These problems were attributed to design and operational causes.

Different Plant Design/Operation

Although the plants are almost identical, there are some differences that make each plant unique. At the mid-Atlantic plant, the requirements for steam to the host vary from 0 to 210,000 lb/h (0 to 94,500 kg/h) and all steam additives must be FDA approved. At the New England plant, host steam flow and demineralized makeup flow is less. In addition, this plant must minimize wastes since it is a zero discharge facility. Also of importance is the difference in operating pressures. The mid-Atlantic plant normally produces 680,000 lb/h (306,000 kg/h) superheated steam at 870 psig (61 kg/cm2) and low pressure steam at 185,000 lb/h (83,300 kg/h) and 80 psig (5.6 kg/cm2), and it operates the deaerator at 6 psig (0.4 kg/cm2). At the New England facility, high pressure steam flow is 690,000 lb/h (311,000 kg/h), while low pressure steam flow is 95,000 lb/h (42,800 kg/h) at 92 psig (6.4 kg/cm2).

System Reliability Improvements

Manifestations of a problem at the mid-Atlantic facility began to appear shortly after commercial operation, but prior to any boiler tube failure. Monitoring of the

any changes. Feedwater iron levels remained at the previous level of <0.005 ppm (mg/L) in all tests. The most significant change was noted in the low pressure boiler system, when it was operated at a higher pressure of 85 to 104 psig (6.0 to 7.3 kg/cm2). The iron testing showed a significant reduction of iron levels in the boiler water. Recent inspection of the mild steel tubes in the low pressure section showed that although erosion/corrosion was not completely eliminated, the amount of area affected and the subsequent metal loss appeared to be reduced. The newly installed tube elbows of higher alloy steel showed virtually no metal loss.

steam blanketing by making several chemical changes. Initially, the boiler was treated using standard coordinated pH/phosphate guidelines. This treatment was continued, but the phosphate levels were reduced to lower the total solids available for deposition. Subsequent visual and metallurgical analysis of tube sections in the immediate area showed continued steam blanketing and some deposition, but much less evidence of the associated under-deposit corrosion.


The three primary purposes of HRSG system treatment programs are prevention of corrosion, control of deposition, and maintenance of required steam purity. Selection of the optimum treatment program depends on many factors. With HRSG operations, as with all boiler system treatment programs, there are three major areas that require protection with chemical treatment programs: boiler feedwater systems, boiler systems, and condensate systems.

Other Causes of Failure Experienced

Weld problems in the economizer section in hard-toreach areas were also detected in the unit. In addition, depending on the particular HRSG design, various banks of tubes and headers may be supported either independently or inter-dependently. Due to cyclic operation, this can result in differences in thermal expansion of various components, thus further aggravating these stress problems. This type of mechanical stress failure is usually more readily identified and can usually be solved with structural changes. Although these mechanically-related problems frequently are apparent within a short time after start-up, they may not surface for several years.

Established Guidelines

In all cases, boiler feedwater requirements are dictated by the highest pressure unit and/or turbine Nox water/steam requirements. Water quality and steam purity limits are designed to protect the equipment, meet the emission standards, and maintain warranty coverage. An established list of guidelines frequently used for cogeneration systems is the American Society of Mechanical Engineers (ASME) boiler feedwater consensus guidelines. Other commonly used guidelines include: · the Electric Power Research Institute (EPRI) maximum levels of contaminants, which are primarily based on electric utility experience and known turbine pathway contaminant solubilities · the steam turbine manufacturer's maximum permissible levels of various contaminants for protection of critical steam turbine equipment (see Table 1) · the gas turbine manufacturer's specified allowable contaminants in steam and water for NOx control (see Table 2). (Note that these are different from the steam turbine manufacturer's levels and may be more stringent.) 7

HRSG High Pressure Failures

In New England, the plant experienced two tube failures associated with the high pressure section. A steam generating tube between the lower header and the evaporator drum failed. Metallurgical analysis indicated the problem was internal metal wastage. Visual examination of the tube showed parallel, longitudinal deposits along the 10 o'clock and 2 o'clock surfaces. Inorganic analyses of the deposits in the area above and surrounding the failure confirmed the phenomenon of "steam blanketing." Steam blanketing originates when there is insufficient fluid flow to maintain adequate cooling. It is more common in horizontal or sloped tubes and is identifiable by the line of boiler water salts which are evaporated at the steam and water interface. Corrosion can occur under the deposits by providing a mechanism for concentration of normally soluble species under the deposit and at or above the liquid/ vapor interface. Steam blanketing was determined to be the root cause of the tube failures (a circulation-related problem). It was possible to reduce the corrosive effect of the

Table 1: Industrial Turbine Steam Purity Specifications

Manufacturer Control Parameter Cation conductivity, µS/cm Dissolved oxygen, ppb (µg/L) Sodium, ppb (µg/L) Chlorides, ppb (µg/L) Silica, ppb (µg/L) Copper, ppb (µg/L) Iron, ppb (µg/L) Na/PO4 molar ratio Notes: a. b. Typical value. (Should be analyzed at least once per week.) Used for chemical control by continuous direct analysis of the condensed inlet steam or as recalculated from steam generator water and mechanical plus vaporous carryover. c. d. e. Continuous analysis recommended. For units with phosphate water treatment. GE specifications, Bulletin GEK98965 Westinghouse 0.3 10 5 5 10 2 20 2.3-2.7 b,c b,c b,c b,c c a a a,d 20 <3 < 20 20 20 < 10 GEe < 0.2 ABB < 0.2

Boiler Feedwater Protection

Proper boiler feedwater treatment must protect piping, feedwater heater(s), economizers, and the deaerator. The most common causes of corrosion are due to oxygen pitting and acidic attack due to low pH.

Oxygen Control

Without proper mechanical deaeration and chemical oxygen scavenging, oxygen in the feedwater will enter the boiler. Oxygen is highly corrosive when present in hot water, and even small concentrations can cause serious pitting problems. The oxygen scavengers most commonly used in boiler systems are sulfite, hydrazine, and organic oxygen scavengers, such as hydroquinone and ascorbate. It is of critical importance to select and properly use the best chemical oxygen scavenger for a given system. Major factors that determine the best oxygen scavenger for a particular application include: reaction speed, residence time in the system, operating temperature and pressure, and feedwater pH. Interferences with the scavenger/oxygen reaction, decomposition products, and reactions with metals in the system are also important factors. The selection of scavengers are also influenced by the use of feedwater for attemperation, the presence of economizers in the system, and the end use of the steam. Several different organic compounds are used to remove dissolved oxygen from HRSG boiler feedwater and condensate including: hydroquinone, ascorbate, and BetzDearborn CorTrolTM treatment, a nitrogencontaining oxygen scavenger (NCOS). These materials are less toxic than hydrazine and can be handled more safely. Hydroquinone is unique in its ability to react quickly with dissolved oxygen, even at ambient temperature. As a result of this property (in addition to its effectiveness in operating systems), hydroquinone is particularly effective for use in boiler storage and during system start-ups and shutdowns. It is also used widely in condensate systems. In addition, it has been effectively used to reduce metal oxides as a result of its metal conditioning properties. Ascorbate-based materials are commonly used where FDA or USDA limitations apply. The NCOS materials are used where an alkaline material with amine is beneficial. In addition, the use of proprietary materials incorporating amines and oxygen scavengers with the same volatility characteristics can reduce corrosion and improve reliability. 8

Table 2a:Typical Water and Steam Guidelines for NOx Control

Contaminant General Electric (Steam) Westinghouse (Water)* 18 6.0 7.5-8.0 0.1 LM 6000 Turbines 0.1 0.1 0.1 0.5 0.5 6.0-8.0 3

Total Trace Metals 0.5 (Na + K), ppm (mg/L) SiO2, ppm (mg/L) TDS and TSS, ppm (mg/L) Cl, ppm (mg/L) SO4 pH Fe + Ca, ppm (mg/L) 5.0 6.5-7.5 -

Specific Conductivity, 8.0 µmhos/cm TDS, ppm (mg/L) -

Specifications may vary depending on the manufacturer. * Based on millions of pounds of fuel.

Table 2b: Total Allowed in Water, Fuel, and Air

Contaminant Na + K, ppm (mg/L) Pb, ppb (µg/L) Vanadium, ppm (mg/L) Ca, ppm (mg/L) Conductivity, µmhos/cm at 25 °C General Electric (Steam) 1.0 1.0 0.5** 2.0 Westinghouse (Water) <0.5 LM 6000 Turbines* 0.1 0.5-1.0

Manufacturers may additionally specify total limits in the combined stream of fuel, steam, and air which contacts the turbine. * ** For the LM Series (GE), the total limits for all contaminants is 0.2 ppm by weight. This limit refers to fuels where no corrosion inhibitor is used.

pH Control

Maintenance of proper pH throughout the HRSG feedwater, boiler, and condensate systems is essential for corrosion control. Since condensate accounts for 60 to 98% of boiler feedwater, control of pH is important for the following reasons: · low pH or insufficient alkalinity can result in corrosive acidic attack · high pH or excess alkalinity can result in caustic gouging/cracking and carryover due to foaming · the speed of oxygen scavenging reactions is highly dependent on pH levels To elevate condensate and feedwater pH, neutralizing amines should be used. Amines are effective, easy to apply, and do not have the control problems of caustic and ammonia. In addition to pH monitoring, it is important to monitor the feedwater system for corrosion by means of iron and copper testing.

Boiler Water Treatment Programs

In the boiler, either high or low pH increases the corrosion rates of mild steel. The pH that is maintained depends on the pressure, makeup water characteristics, chemical treatment, and other factors specific to the system. For optimum protection in single or multipressure HRSG systems with high quality feedwater, coordinated phosphate/pH treatment programs are used. Frequently synthetic polymers are added to the boiler water to control deposition of metal oxides and other contaminants. As mentioned, steam blanketing may also be the root cause of deposition. If the boiler water contains free hydroxide, high concentrations of NaOH can form under deposits. Caustic attack (see Figure 9) creates irregular patterns, often referred to as gouges. Deposition may or may not be found in the affected area.

Coordinated Phosphate pH Treatment

Boiler feedwater systems using demineralized or evaporated makeup or pure condensate may be protected from caustic attack through the use of coordinated phosphate/pH control. The phosphate buffers the boiler water, reducing the chance of large pH changes due to the development of high caustic concentrations. Excess caustic combines with disodium phosphate and forms trisodium phosphate. Different forms of phosphate consume or add caustic as the phosphate shifts to the proper form. Maintaining boiler water chemistry within the recommended control box is achieved through feed of the proper type of phosphate and adjustment of boiler blowdown (see Figure 10).

Figure 9: Caustic Gouging of a Boiler Tube

10.8 10.6 10.4 10.2 10.0 pH at 25°C 9.8 9.6 9.4 9.2 9.0 8.8 8.6 8.4 8.2 1.0 2 3 4 5 6 7 8 10 15 20 30 40 50 60 ppm Orthophosphate, as PO4

2.6 :1 N a/P O4

Control Area 2001-2500 psig

"Free" Caustic Region

N .0:1

TIO RA AR OL a/PO 4 M O 4 8:1 N a/P 2.

Control Area 901-1500 psig

Control Area 900 psig



3 Y AR ND O4 OU a/P MB :1 N 2.7 IMU

Control Area 1501-2000 psig


Control Area >2501 psig





Vector Control Diagram

Blo wd ow


Control Area 2501-2600 psig

Figure 10: Coordinated pH/Phosphate Control


Caustic T Ph riso os diu ph m at e




:1 N







"Captive" Alkalinity Region

Disodium Phosphate

m diu so te no pha Mo hos P

Synthetic Polymer Treatment

In addition to application of coordinated phosphate/pH programs, clean boiler tube surfaces reduce potential concentration sites for caustic corrosion. Deposit control treatment programs, such as those based on addition of synthetic polymers, can help provide clean surfaces and are used widely in HRSG systems. Polymer use is especially critical in systems subject to periodic condensate contamination. A new product has been developed that has resulted in a significant improvement in deposit control and, in some cases, cleanup of iron-based deposits. BetzDearborn OptiSperseTM treatment is a polymeric material based on a patented, unique chemistry using a modified phosphate chemistry as the functional group. A slight degree of dephosphorylation allows the material to provide orthophosphate and, thus, to operate within the coordinated phosphate/pH control range.

Amine basicity is the extent to which an amine hydrolyzes, which determines its effect on pH. The higher the basicity, the higher the resultant pH at condensation (once acid is neutralized). A lower molecular weight amine means less weight is required to react with a given weight of acid. Stability is important in high pressure systems, since thermal decomposition can lead to ammonia and nonbeneficial organic materials.

The recycle ratio is a measure of the amount of amine that is returned to the system. This is system as well as amine dependent. Ideally, an amine or blend of amines can be selected, which minimizes corrosion and maximizes system water-side reliability. A relatively new development by BetzDearborn in amine selection is the Condensate Modeling System (CMSTM). This program accurately simulates the effect of various chemicals and operating conditions on a specific complex system and allows the selection of the optimum amine treatment program.

Amine Treatment

The primary reasons to treat feedwater and condensate systems in cogeneration plants with amine are: · Host plants require protection of steam condensate. · Boiler feedwater must be buffered to an effective pH range for corrosion protection. · Elevated pH is required for efficacy of oxygen scavengers. · Passivation of metals is enhanced with amines. · There is evidence that initial condensation of steam at the Wilson line in condensing turbines can result in low pHs without proper neutralizing amines. · Ammonia may cause stress corrosion cracking of copper bearing alloys. · Low distribution amines are needed to prevent low pH's especially during storage and start-up. Selection of the proper amine blend is critical for effective results. The following is a brief explanation of key amine properties:


Although many systems have been designed and operated at a high level of reliability, problems related to water-side reliability have occurred. Common problems include: · economizer deposition (and resultant corrosion), economizer stress corrosion cracking, and fatigue cracking · steam blanketing and deposition, particularly in the high pressure section · boiler tube component cracking · superheater overheating, corrosion, stress corrosion cracking, and fatigue cracking · erosion/corrosion of low and, to some extent, of intermediate pressure systems Many of these problems can be interrelated. A review of 60 recent industry-wide economizer problems, some including failures, indicated that 40% were due to fireside corrosion, 35% were due to fatigue or stress corrosion cracking, 15% were due to deposition, and 10% were due to oxygen pitting. High pressure sections can experience failures in several areas. This is due to a combination of contaminated feedwater and circulation-based problems that can result from higher heat flux in selected areas. One of the primary problems experienced in superheaters has also been due to overheating due to variations in flue gas heat flux. This is more frequently seen in systems that cycle frequently and have duct 10

Distribution ratio (DR) is a measure of the volatility of amines and is defined as follows:

DR= concentration of amine in steam concentration of amine in liquid Note that the DR of amines varies with pressure and the selection of the proper blend of amines is required to provide protection to all portions of the system.

burners. Temperature and velocity profiles should establish the heat flux in the unit and should be run periodically. As always, manufacturer's start-up recommendations must be closely followed to help minimize overheating. A recent survey of approximately 140 recent superheater problems indicated that 10% were due to pitting attack, 10% were due to fireside corrosion, 5% were due to erosion/corrosion, 40% were due to overheating, and 35% failed from cracking. The overheating, creep cracking, and other problem areas can be interrelated. Carryover of solids into the superheater is another major problem. Deposition due to carryover can lead to long-term overheating and subsequent failure. In addition, failures can occur due to cracking. Adequate control of boiler water level, especially during start-ups, and periodic testing of steam purity using ASTM sampling nozzles can help prevent failures. If direct feedwater attemperation is used, adequate continuous monitoring downstream of the injection is needed to ensure good quality water. If caustic is used for feedwater pH adjustment or if chlorides are present in the feedwater, stress corrosion cracking can result.


While it may not be possible to prevent all HRSG boiler tube failures and eliminate problems, it certainly is possible to reduce the number of occurrences and to monitor closely enough to take preventative action to minimize downtime. The required procedures include: communication during design and construction, effective treatment and monitoring during operation, and inspection during outages.

Design Communication

Prior to construction of the HRSG, decisions have been made which will impact and affect its operational reliability. The end user needs to have communicated to the designer their special conditions regarding operation. These may include plant emergency shutdown procedures, rapidity of load change to be expected, or pressure variations desired under special load conditions. Early involvement of the water treatment company in the project will provide benefits in construction and operation. They have the experience to look at all of the water-related aspects of the plant design. Not only can they alert the owner or developer to potential problems, but they can make specific recommendations for storage and chemical feed and indicate proper sam-


One problem that has recently surfaced in many HRSGs is two phase (steam/water) generating tube erosion/corrosion. Erosion/corrosion can be defined as the increase in rate of attack on a metal because of movement between the fluid and the metal surface. Figures 11a and 11b are photos of a riser tube which experienced severe erosion/corrosion. This problem has led to tube metal loss and failures in both the low pressure and intermediate pressure sections. In addition, baffle plates, cyclone separators, and related equipment have also experienced erosion/corrosion and required replacement. There are many factors that impact susceptibility of the HRSG system to erosion/corrosion. Some key parameters include geometry of the system, velocity of the steam/water mixture, metallurgy, and chemistry. BetzDearborn has investigated numerous cases of erosion/corrosion - but that information is beyond the scope of this paper. Much technology is known and one fact is clear: each system must be evaluated individually since the above variables are interrelated, and specific design and operational differences exist. 11

Figure 11a:Erosion Corrosion of a Riser Tube in a Low Pressure HRSG (Arrow Indicates Failure)

Figure 11b:Close-up of Erosion Corrosion of a Riser Tube (Arrow Indicates Failure)

pling locations. The direct discussions between user, supplier, and equipment designer will provide benefits in terms of easier startup and fewer operational difficulties.

the specified amount of chemical has actually been fed. At one East Coast facility, its use enabled precise chemical control, eliminated unnecessary operator attention, eliminated the need for a day tank, and resulted in better control and reliability.

Table 3: Recommended Monitoring Schedule

Sample Point Treated Makeup Analysis Required Hardness Conductivity Silica Conductivity Iron Silica Feedwater pH Silica Iron Oxygen pH Silica Phosphate Conductivity Silica Conductivity Sodium Suggested Frequency Once per shift Continuous Continuous Continuous Once per shift /StartOnce per shift Once Once Once Once Once Once Once Once per per per per per per per per shift shift day shift shift shift shift shift


The system designer will also specify sufficient instrumentation to properly monitor boiler operation. This includes such items as ASTM steam sampling nozzles and liquid sample connections on economizers and feedwater heaters. A well-designed laboratory, with adequate testing apparatus and some instrumentation, is essential in today's operation. In addition to the Hach DR 2000 spectrophotometer, which has provided reliable service for a number of years, two laboratory quality pH meters and one multi-range conductivity instrument are required. On-line instrumentation is dependent upon the preferences of the user. On-line pH and conductivity monitors can provide continuous monitoring for quick response to upsets. The inclusion of an on-line silica analyzer and a sodium analyzer should be considered. These analyzers are versatile in troubleshooting problems and important as monitoring tools. Thermocouples in various sections of the duct work and velocity profiles will provide early warning of problems such as gas flow maldistribution. This is just part of the equipment which needs to be specified or included in a design to monitor the system effectively. Once the plant is operating, the monitoring program should be designed to ensure proper chemical control and to alert personnel of possible operational problems. Water treatment testing which is required as a minimum is shown in Table 3. Periodic testing by a qualified laboratory is recommended to verify the accuracy of operator testing and to test for low level contaminants. Much of this special testing should be periodically performed by the consulting water treatment company. Maintaining water quality has always been a primary operating concern. As the number of operators is limited, other methods must be used to ensure consistent chemical feed and control. One example of computer controlled chemical feed is the BetzDearborn PaceSetter PlusTM equipment. This equipment automatically feeds chemicals without operator handling based upon an operating variable, such as feedwater flow. Then it verifies that

Condensate up

Boiler Blowdown


Once per shift Once per shift Once per shift

The operators must receive technical training in daily instrument maintenance and the time and responsibility to perform it. Even if steam purity problems have not been detected in daily operator testing, a continuous steam purity study should be performed. By continuously monitoring sodium, the steam purity can be judged during various load conditions. The amount of data available at most cogeneration facilities is staggering, although most of it is not normally maintained in a useful form. The data obtained from testing, monitoring, and chemical feed parameters should be maintained in interactive computer files. The major water treatment chemical companies now offer operator interactive software packages which store manually-obtained data and provide immediate feedback for out-of-control parameters. In addition, most of these packages have graphing capabilities and statistical process control (SPC) for the manager to compare parameters simultaneously over a specified period of time.


Outages provide the only time to get inside the equipment for inspection and testing. The steam, mud drums, and some headers are easy to inspect visually, but the tubes must be checked with a boroscope. The boroscope permits visual inspection further down into the higher heat transfer portions of the boiler, and the tube elbows and horizontal runs can be inspected more thoroughly.


Videotaping the inspection is helpful for comparison of conditions from year to year. Additional specialized testing, such as ultrasonic thickness testing, should be performed on elbows or other areas where loss of metal is possible. In areas where deposition is suspected, tube sections should be removed for the performance of deposit weight density (DWD) testing. Deposits will decrease heat transfer, reduce efficiency, and increase the chance for overheating.

When the tube sections were taken for metallurgical analysis, excessive deposition was revealed. The deposits consisted of iron, nickel, and hardness at a density of 369 grams/ft2 (4.1 kg/m2). In addition, cleaning of the surface indicated severe under-deposit caustic corrosive attack. Figures 12a and 12b show the extensive deposition and pitting corrosion uncovered. Subsequent investigation indicated that excessive oxygen levels were allowed to enter the boiler feedwater via the deaerator bypass line. Inspection of the gas side of the superheater and generating banks indicated a significant degree of bowing tubes in certain areas. Most of the tube failures occurred in locations next to the partition, downcomers, and duct walls. Several steps were taken to address these problems. A demineralizer and condensate study has been implemented to identify and eliminate contamination sources. The system treatment was changed to coordinated phosphate/pH control, along with use of a synthetic phosphate-based polymer. Plans for a standby rental boiler and retubing of the affected sections of the HRSG have also been made. A velocity and temperature profile study was recommended and will be completed to address the gas side heat flux problem. The unit continued to be closely monitored. No recent failures have occurred.


A Gulf coast chemical plant treated with another company's boiler water treatment program, experienced failures in the HRSG high pressure system. The HRSG is a two-pressure system and the high pressure unit produces 360,000 lb/h (162,000 kg/h) steam at 850 psig (60 kg/cm2) and the 25 psig (1.8 kg/cm2) low pressure section produces 30,000 lb/h (13,500 kg/h) steam. Feedwater consists of demineralized makeup and 70% condensate return.


Maintaining HRSG reliability and availability is critical in today's market. It affects the economic welfare of all of the parties involved. Despite the complexity of HRSG systems, the following action can be taken to improve the water-side reliability of these units.

Figure 12a:HRSG High Pressure Deposition

· Understand the water flow, operating parameters, and chemistry of the system. · Provide an effective water treatment program, including effective chemicals, service, and control programs. · Stress proper monitoring, both continuous and spot checks. · Document any failures and the corrective action taken. · Become knowledgeable about potential failures in the industry and possible remedial action. · Schedule detailed inspection during each outage. Following these steps will ensure that reliability is maintained and can help alert operating management to potential problems. If problems do occur, management will be prepared to effectively troubleshoot and resolve them. 13


12b:HRSG High Corrosion




1. Passell, T. O., "Feedwater Water Quality Control Extends Power Plant Life," Power Engineering, September 1993, page 19. 2. Makansi, J, "HRSG's, Steam Turbines and Auxiliaries for Combined Cycles," Power, September 1994, page 43. 3. Lapriore, R. P., "How Utilities Monitor Pipe-Wall Thinning at Nuclear Plants," Power, August 1988, page 67. 4. Mancini, K. B.; Huchler, L. A.; Cotton, I. J.; "Continuous Monitoring and Control in Steam Generating Systems," National Association of Corrosion Engineers, Corrosion 92, paper no. 415. 5. Robinson, J. O., "New Computer Modeling System Improves Condensate Treatment," National Association of Corrosion Engineers, Corrosion Asia, Singapore, September 26-30, 1994. 6. Robinson, J. O., "Water Treatment for Cogeneration Plants," Cogeneration World, July/August 1985. 7. Levine, J., "Factor Water Treatment Up-Front in IPP Plant Design," Power, September 1994, page 70.

8. Jonas, O., "Control Erosion/Corrosion of Steels in Wet Steam." 9. Heitmann, H. G., Kastner, W., "Erosion-Corrosion in Water-Steam Cycles Causes and Counter Measures," VGB Kraft Works Technik 62, No. 3, March 1982. 10.Electric Power Research Institute, "Guide to the Design of Secondary Systems and Their Components to Minimize Oxygen Induced Corrosion," EPRI NP2294, Project S189-1, March 1982. 11.Burgmayer, P. R., Cotton, I. J., Knowles, G., "Oxygen Scavenging and Passivation in Steam Generating Systems: Fiction, Folklore and Fact," NACE, Nashville, TN, April 1992. 12.Private communication with Dr. P. R. Burgmayer, BetzDearborn Research & Development, Trevose, PA.




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