15.2.1.1 All-volatile treatment (reducing) [1]

All-volatile treatment (reducing) or AVT(R) involves the addition of ammonia or an amine, FFP, blend of amines of lower volatility than ammonia and a reducing agent (usually hydrazine or one of the acceptable substitutes such as carbohydrazide) to the condensate or feedwater of the plant. In combination with a relatively low oxygen level (from air in-leakage) of about 10 ppb (μg/kg) or less in the condensate (usually measured at the condensate pump discharge [CPD]), the resulting feedwater will have a reducing redox potential (usually measured as a negative oxidation-reduction potential [ORP]). Higher levels of oxygen (>20 ppb [μg/kg]) (due to high air in-leakage) will usually preclude generation of the reducing environment, but are often incorrectly accompanied by excessive dosing of the reducing agent. AVT(R) is most often used to provide protection to copper-based alloys in mixed-metallurgy feedwater systems in fossil plants. In multipressure HRSG systems, AVT(R) should not be used in these cycles due to concerns for single-phase FAC, and because the corrosion product levels in the feedwater would be most likely to exceed 2 ppb (μg/kg). Reducing agents should not be used in combined cycle/HRSG plants.

15.2.1.2 All-volatile treatment (oxidizing) [1]

All-volatile treatment (oxidizing), or AVT(O), has emerged since the 1990s as the much preferred treatment for feedwater systems that only contain all-ferrous materials (copper alloys can be present in the condenser). In these cases, a reducing agent should not be used during any operating or shutdown/layup period. Ammonia or an amine, FFP, blend of amines of lower volatility than ammonia is added at the CPD or condensate polisher outlet (if a polisher is included within the cycle). This is the treatment of choice for multipressure combined cycle/HRSG plants that have no copper alloys in the feedwater. In combined cycle/HRSG plants with relatively good control of air in-leakage (oxygen levels in the range 10–20 ppb (μg/kg)), the resulting feedwater will yield a mildly oxidizing positive ORP. Under optimum conditions, a multiple pressure combined cycle plant should be able to operate with corrosion product levels of total Fe<2 ppb (μg/kg) in the feedwater and <5 ppb (μg/kg) in the drums.

15.2.1.3 Oxygenated treatment

Application of oxygenated treatment (OT) [1] in combined cycle/HRSG plants is much rarer than in conventional fossil plants, but often it is found that the use of AVT(O) with low levels of oxygen (<10 ppb (μg/kg)) on these plants does not provide sufficient oxidizing power to passivate the very large internal surface areas associated with preheaters; LP, IP, and HP economizers; and LP evaporators, especially if a deaerator is included in the LP circuit. In these cases, oxygen can be added at the same level as for conventional recirculating cycles (30–50 ppb (μg/kg)). This is the feedwater of choice for conventional fossil units with all-ferrous feedwater heaters and a condensate polisher and with an ability to maintain a CACE of <0.15 μS/cm under all operating conditions. Under optimum conditions, a multiple pressure combined cycle plant the total Fe should be <1 ppb (μg/kg) in the feedwater and <5 ppb (μg/kg) in each of the drums.

15.2.1.4 Film forming products

The application and use of FFP in conventional fossil and combined cycle/HRSG plants is increasing worldwide. They work in a different way than the conventional treatments by being adsorbed onto metal oxide/deposit surfaces thus providing a physical barrier (hydrophobic film) between the water/steam and the surface. There are three main chemical substances that have been used historically: octadecylamine (ODA), oleylamine (OLA), and oleylpropylendiamine (OLDA). As well as these compounds the commercial products contain other substances, such as alkalizing amines, emulsifiers, reducing agents, and dispersants. There is currently much confusion about their application for both normal operation and shutdown/layup, and there is no international guidance on deciding whether to use an FFP or whether it will provide a benefit to the plant. This situation will change in 2016 when the International Association for the Properties of Water and Steam (IAPWS) publishes the first FFP guidance [2].

There are some basic international rules for the application of these condensate/feedwater treatments. The all-volatile treatments (AVT(R), AVT(O), or OT) have to be used for once-through boilers and are used without any further addition of chemicals in the boiler or HRSG evaporators. AVT(R), AVT(O), or OT can also be used for drum boilers of conventional fossil plants or combined cycle/HRSGs without any further addition of chemicals to the boiler/HRSG drum. However, impurities can accumulate in the boiler water of drum-type HRSGs and it is necessary to impose restrictive limits on these contaminants as a function of drum pressure both to protect the boiler from corrosion and to limit the amount of impurities possibly carried over into the steam [3], which could put at risk the superheaters, reheaters, and steam turbines. It is recognized that AVT has essentially no capability to neutralize or buffer feedwater/boiler water dissolved solids contamination. Ammonia is a rather poor alkalizing agent at high temperatures, offering very limited protection against corrosive impurities.

15.2.2.1 Phosphate treatment

Phosphates of various types have been the bases of the most common boiler/HRSG evaporator treatments worldwide. However, historically there has been a multitude of phosphate compounds and mixtures blended with other treatment philosophies, which has resulted in a wide range of control limits for the key parameters (pH, phosphate level, and sodium-to-phosphate molar ratio) and a number of reliability issues. Some of the traditional PTs such as congruent phosphate treatment (CPT), coordinated PT, and equilibrium phosphate treatment (EPT) have been used since the 1960s across the fleet of conventional fossil boilers and HRSG evaporators, sometimes successfully, sometimes resulting in tube failures and other problems. For instance, the use of CPT, where mono- and/or disodium phosphate are used to develop operating control ranges below sodium-to-phosphate molar ratios of 2.6:1, has resulted in serious acid phosphate corrosion (APC) in many conventional fossil boiler waterwalls and HRSG HP evaporators that have heavy deposits and have experienced phosphate hideout.

More recently, since the 1990s, consolidated good operating experiences worldwide have led to the recognition that TSP should be the only phosphate chemical added to a boiler/HRSG, and that the operating range should be bounded by sodium-to-phosphate molar ratios of 3:1 and TSP+1 ppm (mg/kg) NaOH with a pH above 9.0 and a minimum phosphate limit above 0.3 ppm (mg/kg). It should be emphasized that the 0.3 ppm (mg/kg) level is regarded as a minimum and that better protection will be afforded by operating at as high a level of phosphate as possible without experiencing hideout or exceeding the steam sodium limits.

PT can be used in a wide range of drum units up to high pressures (2800 psi, 19 MPa), so it is often the only alkali treatment available because CT is not suggested for use above 2400 psi (16.5 MPa). However, it will be recognized that phosphate hideout and phosphate hideout return become more prevalent with increasing pressure. Phosphate hideout is the loss of phosphate from the boiler/evaporator water on increasing drum pressure, and hideout return is the return of the phosphate to solution on decreasing pressure. Hideout and hideout return are therefore always associated with large swings of pH causing boiler/evaporator control problems, but if only TSP is used, then no harmful corrosion reactions can be initiated as was experienced with CPT using sodium-to-phosphate molar ratios below 2.6:1.

For multipressure HRSGs, PT can also be used in each of the pressure cycles, but use of PT here is for different reasons depending on the pressure of the circuit. At high pressure, the addition of TSP is basically to assist in addressing contamination in the same way as for conventional fossil plants. In the lower pressure circuits, with temperatures below 480°F (250°C), PT is used to help control two-phase FAC much as CT is used in these circuits. Of course neither solid alkali is used in the LP evaporator in units where the LP drum feeds the IP and HP feedpumps and attemperation.

15.2.2.2 Caustic treatment

Caustic treatment (CT) can be used in conventional fossil and HRSG drum-type boilers to reduce the risk of UDC, and in HRSGs for controlling FAC in the lower-pressure circuits, where all-volatile treatment has proved ineffective, or where PT has been unsatisfactory due to hideout or has experienced difficulties of monitoring and control.

The addition of sodium hydroxide to the boiler/evaporator water has to be carefully controlled to reduce the risk of CG in the HP evaporator and carryover into the steam, which could lead to damage of steam circuits and turbine due to stress corrosion cracking. Of primary risk are austenitic materials, stellite, and all steels with residual stresses (e.g., welds without heat treatment) in superheaters, steam piping and headers, turbine control and check valves, as well as components in the steam turbine. CT is easy to monitor, and the absence of the complications due to the presence of phosphate allows online conductivity and CACE measurements to be used for control purposes.

15.3.1.1 Flow-accelerated corrosion in combined cycle/HRSG plants

FAC occurs due to the accelerated dissolution of the protective oxide (magnetite) on the surface of carbon steel components caused by flow. For combined cycle/HRSG plants a detailed review of the FAC mechanism is available [5] and is illustrated in Fig. 15.1. The concentration in this chapter is to indicate that the overall optimum cycle chemistry for these plants must first include the cycle chemistry influences of single- and two-phase FAC as outlined in Section 15.6.

15.3.1.2 FAC in combined cycle/HRSGs

All the HRSG components within the temperature range 212–572°F (100–300°C) are susceptible to FAC, which involves both the single- and two-phase variants predominantly in low temperature (LP, IP, and HP) economizers/preheaters and evaporators (tubes, headers, risers, and drum components such as belly plates). The same components can also be susceptible to FAC in HRSG designs where the nominal HP evaporator circuit operates for significant periods of time at temperatures <572°F (300°C) (e.g., the HP evaporators in older dual-pressure HRSGs, HRSGs where there is only one pressure stage, and high pressure evaporator circuits in plants running for extended periods at low load with sliding pressure operation). A quite comprehensive listing of locations of FAC in combined cycle/HRSGs is provided in Table 15.1.

The appearances of single- and two-phase FAC are illustrated in Fig. 15.2.

The corrosion products released by the FAC mechanism in these circuits and by corrosion of the nonpassivated lower-temperature/pressure circuits are transported away from the corrosion site and can eventually reach the HP evaporator and deposit on the internal tubing surfaces.

15.3.1.3 Flow-accelerated corrosion in air-cooled condensers

An increasing number of combined cycle/HRSG plants worldwide are equipped with ACC. Operating units with ACCs at the lower regimes of pH provided in IAPWS guidance documents will result in serious corrosion and FAC in the ACC tubes, most predominantly at the entries to the cooling tubes [7]. The potential for ACC to act as a major source of corrosion products needs to be considered in developing the optimum cycle chemistry control for an HRSG plant. Whether this is occurring can easily be determined by monitoring the total iron at the condensate pump discharge (CPD) [8]. To rectify the FAC situation, it will be necessary to conduct a series of tests with gradually increasing levels of pH while monitoring total iron. A condensate/feedwater pH of around 9.8 (as measured at 77°F, 25°C) will be needed to reduce the FAC to low enough levels to observe total iron values at the CPD of around 5 ppb (μg/kg) or less [7]. If the total iron values cannot be reduced to less than 5 ppb (μg/kg) by increasing the pH, then there may be a requirement to include a 5 μm absolute condensate filter or a prefilter prior to a condensate polisher if included in the cycle. Condensate polishing is not universal on plants with ACC.

Operating with elevated pH to control low temperature FAC in the ACC will also assist in addressing two-phase FAC in the other areas of the HRSG. For plants operating in the oxidizing mode, AVT(O) or OT, the customization can be useful to improve the conditions in the two-phase regions but will be of little relevance for the single-phase flow regions because, in the absence of contaminant anions, corrosion is suppressed to a very low level across the pH range 7–10.

The cycle chemistry-influenced damage in ACC can be best described through an index for quantitatively defining the internal corrosion status of ACC. This is known by the acronym DHACI (Dooley Howell ACC Corrosion Index) [7]. The index separately describes the lower and upper sections of the ACC, as described in the following paragraph.

The index provides a number (from 1 to 5) and a letter (from A to C) to describe/rank an ACC following an inspection. For example, an index of 3C would indicate mild corrosion at the tube entries, but extensive corrosion in the lower ducts. An example for the upper ACC section (upper duct/header, ACC A-frame tube entries) is shown in Fig. 15.3. An example for the lower ACC section (turbine exhaust, lower distribution duct, risers) is shown in Fig. 15.4.

The DHACI can be used to describe the status of a particular ACC in terms of its corrosion history and is a very useful means of tracking changes that occur as a result of making changes in the cycle chemistry. A plant that has a relatively poor rating for corrosion at a steam cycle pH of 8.5–8.8 (e.g., 4C) may increase the pH to 9.4–9.6, and determine whether this change improves its rating (e.g., 3B). A poor rating (e.g., 4B) indicates the need to consider options to reduce the corrosion rate especially in the tube entry areas.

Additionally, the index provides a convenient tool for comparison between different units. This can aid in determining whether some cycle chemistry factor in effect at one station, e.g., use of an amine rather than ammonia, is yielding better results.

15.3.1.4 Steam turbine phase transition zone failure/damage

Impurities in the steam from the HRSG may cause deposits and corrosion in steam turbines and thus the steam purity controls most corrosion processes and is vital to combined cycle plant reliability. These problems can usually be avoided by following the guidance in the IAPWS Steam Purity Technical Guidance Document (TGD) [9], which needs to be compatible with the condensate, feedwater, and evaporator chemistries discussed in Sections 15.2.1 and 15.2.2.

The four most important corrosion-related failure/damage mechanisms in the low pressure (LP) steam turbine are deposition, pitting, corrosion fatigue, and stress corrosion cracking. The local steam environment determines whether these damage mechanisms occur on blade and disk surfaces. The PTZ, where the expansion and cooling of the steam leads to condensation, is particularly important. A number of processes that take place in this zone, such as precipitation of chemical compounds from superheated steam, as well as deposition, evaporation, and drying of liquid films on hot surfaces, lead to the formation of potentially corrosive surface deposits. Understanding the processes of transport, droplet nucleation, the formation of liquid films on blade surfaces, and concentration of impurities is vital to understanding how to avoid corrosion-related damage, and to improve unit efficiency/capacity [9].

The following two cycle chemistry operating regimes are identified as relevant to steam turbine corrosion. Of course, adequate materials properties (composition, structure, internal stresses, etc.) and design (temperature, stresses, crevices, etc.) also play essential roles.

Thus, if adequate layup protection (dehumidified air (DHA)) is not provided, serious corrosion damage may occur even with the best operating chemistry, materials, and design, and with only few major deposits. It is recognized that pitting can possibly also initiate during operation in crevice areas such as blade attachments.

Impurities can enter the steam from the HRSG by the following processes:

For a complete description of the chemistry in the PTZ of the LP steam turbine the reader is referred to the IAPWS Steam Purity TGD [9]. This includes the details on droplet nucleation, liquid film formation on turbine parts, deposition of oxides and impurities on surfaces, and how inadequate shutdown practices results in pitting. The major failures mechanisms of corrosion fatigue and stress corrosion cracking are initiated at pits so this sequential process is most important.

15.3.1.5 Combined cycle/HRSG steam purity limits

For combined cycle/HRSG plant with condensing turbines operating with superheated steam the following guideline limits (Table 15.2) are suggested by IAPWS [9]:

These limits are considered as the normal operating values during stable operation to avoid the steam turbine damage mechanisms and are consistent with long-term turbine reliability.

15.3.1.6 Steam purity for startup

In the case of a warm start, the values for normal operation (Table 15.2) should be attained within 2 hours, and in the case of a cold start within 8 hours. During startup, the impurity concentrations should show a decreasing trend.

Steam should not be sent to the turbine if the concentration of sodium exceeds 20 ppb (μg/kg). The immediate need at startup to ensure compliance with this limit requires a sodium monitor for steam, as specified in the IAPWS Guidance on Instrumentation for Cycle Chemistry [10].

Steam should not be sent to the turbine if the CACE exceeds 0.5 μS/cm. Allowance may be given to possible contributions from carbon dioxide and for sodium in units that only use TSP in the evaporator water. The actual contribution of carbon dioxide must be measured and regularly verified for the specific plant. Degassed CACE can help to estimate the contribution of carbon dioxide.

15.3.1.7 Unit shutdown limits

In addition to operating with a set of normal and action levels it is also necessary to define a set of cycle chemistry conditions under which a unit must be shut down because of severe contamination. Shutdown conditions usually involve defining a steam CACE that indicates serious acidic contamination. Typically, a value of 1 µS/cm can be used under conditions that coincide with other upset conditions in the steam/water cycle. Carbon dioxide from air in-leakage or certain conditioning agents may warrant a less stringent CACE.

15.3.1.8 Failure/damage mechanisms in HRSGs: highlighting the under-deposit corrosion mechanisms

The three UDC mechanisms in HRSGs, i.e., HD, APC, and CG, occur exclusively in HP evaporator tubing [11–13], and all require relatively thick porous deposits and a chemical (either a contaminant or nonoptimized treatment) concentration mechanism within those deposits. UDC damage can occur early in the life of an HRSG due to the inverse relationship between deposit loading/thickness and the severity of the chemical excursion.

For HD, the concentrating corrodent species is most often chloride that enters the cycle through condenser leakage (especially with seawater or brackish water cooling) and via slippage into demineralized makeup water in water treatment plants where ion exchange resins are regenerated with hydrochloric acid.

APC relates to a plant using phosphate blends that have sodium-to-phosphate molar ratios below 2.6 and/or the use of CPT using either or both mono- or disodium phosphate.

CG involves the concentration of NaOH used above the required control level within caustic treatment, or with the use of coordinated phosphate with high levels of free hydroxide, or the ingress of NaOH from improper regeneration of ion exchange resins or condenser leakage (freshwater cooling).

15.3.1.9 Deposition in HRSG HP evaporators

Deposition and the UDC mechanisms can occur on both vertical and horizontal HRSG HP evaporator tubing. On vertical tubing the deposition usually concentrates on the internal surface (crown) of the tube facing the gas turbine (GT). It is nearly always heaviest on the leading HP evaporator tube in the circuit as these are the areas of maximum heat flux. Area of concentration can be the tube circuits adjacent to the side walls or to the gaps between modules due to gas bypassing. The UDC mechanisms usually occur in exactly the same areas. On horizontal tubing in VGP HRSGs both deposition and the UDC mechanisms occur on the ID crown facing toward or away from the GT. Damage occurs on the side facing away from the GT when poor circulation rates, steaming, or steam blanketing lead to stratification of water and steam and subsequent heavy deposition in a thin band along the top of the tubing corresponding to the steam–water interface during service. When circulation is adequate, the UDC mechanisms occur on the internal crown of the lower tube surface facing the GT.

The UDC mechanisms of HD and CG have been well understood since the 1970s, and the acid phosphate mechanism since the early 1990s [14]. But until about 2015 the understanding of how the initiating deposition takes place in HRSG tubing has been less well understood as is the level of deposits necessary for these mechanisms to initiate by concentration within thick deposits.

Until about 2015 there have not been any comprehensive studies to characterize and quantify the critical level of deposits forming in HRSG HP evaporator tubes. Initial published data from over 100 HRSGs worldwide has led to a new understanding on where to sample and how to analyze HRSG tubes for deposits and how to determine if the HRSG needs to be chemically cleaned [15]. This is now published in an IAPWS TGD [16] and the deposit map is shown in Fig. 15.5.

Examples of deposit loadings from over 100 HRSGs worldwide have been plotted to develop the new deposit map shown in Fig. 15.5. Plants included cover a very wide range of HRSGs from 17 HRSG manufacturers with HP drum pressures spanning the range 1300–2200 psi (8.9–15.2 MPa) and with deposits up to 125 g/ft² (136 mg/cm²). Full coverage of this is included in the IAPWS TGD [16].

Some general comments from the IAPWS document are made here about the three colored cloud regions of Fig. 15.5:

This new concept contained within the background of Fig. 15.5 of avoiding deposits that are thick enough to allow concentration provides the first step of avoiding UDC. The readers should be aware that the selection of the right cleaning procedure is not always easy and simple, and that a certain caution and pretest is advised. The results from the metallurgical analyses of the deposits can be used to identify the chemicals (solvents) that should be used in a chemical cleaning process if the analyses indicate that cleaning is needed.

15.4.1.1 Corrosion products

Categories include the following: corrosion product levels are not known or monitored, the levels are too high and above international guideline values [8], inadequate and/or not sufficient locations being monitored, sampling conducted at the same time/shift each time, and using techniques with incorrect detection limit; a most common feature is monitoring the soluble part only by not digesting the sample. A key easy-to-observe verification aspect of this RCCS is black deposits in the steam and water sampling troughs for combined cycle/HRSG units on AVT(O), or red deposits for units on AVT(R).

15.4.1.2 Conventional boiler/evaporator deposits [16]

Categories include the following: HRSG HP evaporator samples have not been taken for analysis, there is no knowledge of deposits and deposition rate in HP evaporators, samples taken but not analyzed comprehensively according to the IAPWS TGD [16], deposits excessive and exceed criteria to chemical clean, the HP evaporator deposits are not linked with chemistry in the lower-pressure circuits or to the levels of transported total iron [8], the HP evaporator has been sampled and needs cleaning according to IAPWS criteria [16] but management delayed or canceled.

15.4.1.3 Drum carryover

Categories include the following: measurement of carryover [3] not conducted since commissioning, not conducted even on units with PTZ problems, not aware of simple process to measure carryover [3], saturated steam samples not working or nonexistent, samples taken are not isokinetic.

15.4.1.4 Continuous online cycle chemistry instrumentation [10]

Categories include the following: installed and operating instrumentation is at a low percentage compared to IAPWS (a normal level is between 58 and 65%); too many out of service, not maintained or calibrated; instruments are not alarmed for operators and many are shared by multiple locations and not/never switched; plant relies on grab samples to control plant (1–3 times per day/shift); the instrumentation most often missing is CACE (cation conductivity) and sodium on main or HP steam and conductivity (specific conductivity) on makeup line to condenser.

15.4.1.5 Challenging the status quo

Categories include the following: no change in chemistry since commissioning; using incorrect or outdated guidelines; continuing to use reducing agents in combined cycle/HRSGs and thus risking or experiencing single-phase FAC; continuing to use the wrong phosphate treatment (usually not using only TSP); not having a chemistry manual for the unit, plant or organization; incorrect addition point for chemicals (most often reducing agent with AVT(R)); not questioning use of proprietary chemical additions (phosphate blends, amines, FFP) and therefore not knowing the composition of chemicals added to the unit/plant; not determining through monitoring the optimum feedwater pH to prevent/control FAC.

15.4.1.6 Shutdown/layup protection

Categories include the following: unit/plant has no equipment for providing shutdown protection (nitrogen blanketing, DHA), equipment present but not used or inoperable/not maintained, poor/no operator procedures, only partial protection applied (HRSG vs feedwater), no DHA provided for the steam turbine shutdowns.

15.4.1.7 Contaminant ingress

Categories include the following: no assessment of risk; inadequate instrumentation and alarms (especially for seawater cooled plants); operators allow exceedances of control and shutdown levels; chemists and/or operators compromise limits to plant ability (make high readings acceptable), or make up (invent) normal and action levels which have no technical relevance; no comprehensive procedures to deal with contaminant ingress.

15.5.1.1 Case study 1

This L-0 blade cracking occurred in a 700-MW 2×1 combined cycle/HRSG plant after about 90,000 operating hours. The cracking emanated from pits on the blade surface. The plant had two GTs and a steam turbine (HP/IP and LP), and triple-pressure HRSGs with HP drum pressure of ~10.3 MPa (1500 psi). The condenser had titanium tubes that had experienced numerous condenser leaks of the brackish cooling water. The cycle chemistry condensate/feedwater treatment included a proprietary amine blend (ETA/MPA) and a reducing agent (carbohydrazide), and a proprietary phosphate blend was added to all three drums.

During the root cause analysis the following seven RCCS were identified with the last five being directly related to the PTZ cracking:

It can easily be seen that this represents a “full house” of RCCS. Singly, each RCCS would (probably) not have caused failure/damage, or be viewed as the plant operating out of control. But together, these are commonly the basis of PTZ failures and damage worldwide. The other important observation is that operating with seven RCCS in total is rare but is a clear indicator that some other failure/damage mechanism, such as HD, will occur in the future.

15.5.1.2 Case study 2

The unit in this assessment was a 650-MW 2×1 combined cycle plant with about 93,000 operating hours. The plant had two GTs and a steam turbine (HP and IP/LP), and triple-pressure HRSGs with HP drum pressure of ~10.3 MPa (1500 psi). The condenser had SeaCure tubes that had experienced condenser leaks of the cooling water (~200 ppb Cl and ~400 ppb SO₄). The cycle chemistry condensate/feedwater treatment included a proprietary amine blend (ETA/MPA). The reducing agent (hydroquinone) had been eliminated a few years before the assessment. A proprietary phosphate blend was added to the HP drums.

During the cycle chemistry/FAC assessment for this plant the following seven RCCSs were identified:

By comparing this listing with that from the first case study, the similarities will be noted, and the risks for PTZ cracking and UDC were assessed to be high, illustrating the powerfulness of the RCCS methodology.