Water Chemistry Control in LWRs

5.02

Water Chemistry Control in LWRs

C. J. Wood Electric Power Research Institute, Palo Alto, CA, USA

ß 2012 Elsevier Ltd. All rights reserved.

5.02.1

Introduction

18

5.02.2 5.02.2.1 5.02.2.2 5.02.2.3 5.02.2.4 5.02.2.5 5.02.3 5.02.3.1 5.02.3.2 5.02.3.3 5.02.3.4 5.02.4 5.02.4.1 5.02.4.2 5.02.4.3 5.02.4.4 5.02.5 5.02.6 References

BWR Chemistry Control Evolution of BWR Chemistry Strategies Mitigating Effects of Water Chemistry on Degradation of Reactor Materials Radiation Field Control Fuel Performance Issues Online Addition of Noble Metals PWR Primary Water Chemistry Control Evolution of PWR Primary Chemistry Strategies Materials Degradation PWR Radiation Field Control Fuel Performance PWR Secondary System Water Chemistry Experience Evolution of PWR Secondary Chemistry Strategies Chemistry Effects on Materials Degradation of SGs Control of Sludge Fouling of SGs Lead Chemistry Chemistry Control for FAC in BWRs and PWRs Water Chemistry Control Strategies

19 19 20 23 26 27 27 27 29 33 35 37 37 40 43 44 45 45 46

Abbreviations AO

AVT

BOP BRAC

BWR CGR CRUD DMA DZO EBA ECP

Axial offset, referring to localized flux depression in reactor core caused by buildup of boroncontaining deposits. Originally called AOA for axial offset anomaly. All-volatile treatment, suing ammonia for pH control in steam generators Balance of plant BWR radiation and control, referring to designated standard points in BWR reactors for radiation field measurements Boiling water reactor Crack growth rate Corrosion product deposits on fuel element surfaces Dimethylamine Depleted zinc oxide (BWRs) Enriched boric acid (PWRs) Electrochemical corrosion potential

ETA FAC GE

HWC HWC-L HWC-M IGA IGSCC LWR MOX MPA MRC NDE NMCA NWC OD IGA/SCC

Ethanolamine Flow-assisted corrosion General electric, the vendor for BWRs in the United States and some other countries Hydrogen water chemistry HWC (low) with 0.2–0.5 ppm hydrogen HWC (moderate) with 1.6–2.0 ppm hydrogen Intergranular attack Intergranular stress corrosion cracking Light water reactor Mixed oxide fuel 3-methoxypropylamine Molar ratio control (PWR secondary side) Nondestructive examination Noble metal chemical addition Normal water chemistry (BWRs) Outside diameter IGA/SCC in steam generator tubes

17

18

Water Chemistry Control in LWRs

OLNC OTSG PAA PbSCC PWR PWSCC SCC SG SHE

On-line noble chemistry Once through steam generator Poly acrylic acid Lead assisted stress corrosion cracking Pressurized water reactor Primary water stress corrosion cracking Stress corrosion cracking Steam generator Standard hydrogen electrode (for ECP measurements)

5.02.1 Introduction Other chapters of this comprehensive describe the various degradation processes affecting the structural materials used in the construction of nuclear power plants (see Chapter 5.04, Corrosion and Stress Corrosion Cracking of Ni-Base Alloys; Chapter 5.05, Corrosion and Stress Corrosion Cracking of Austenitic Stainless Steels; and Chapter 5.06, Corrosion and Environmentally-Assisted Cracking of Carbon and Low-Alloy Steels). This chapter describes the influence of water chemistry on corrosion of the most important materials in light water reactors (LWRs). In particular, alloys susceptible to intergranular attack (IGA) and stress corrosion cracking (SCC) are significantly impacted by water chemistry, most notably, sensitized 304 stainless steel in boiling water reactors (BWRs) and nickelbased alloys in pressurized water reactors (PWRs). Excellent water quality is essential if material degradation is to be controlled. In the early days of nuclear power plant operation, impurities in the coolant water were a major factor in causing excessive corrosion. Chlorides and sulfates are particularly aggressive in increasing intergranular stress corrosion cracking (IGSCC) and other corrosion processes. Transient increases of impurities in the coolant that occur during fault conditions (e.g., condenser leaks and ingress of oil or ion exchange resins) proved to be particularly damaging. Thus, water chemistry was traditionally regarded as a key cause of material degradation. Initial efforts to improve water quality brought about a slow but steady reduction in impurities through improved design and operation of purification systems. Not only were the average concentrations of impurities reduced over time, but the frequency and magnitude of impurity ‘spikes’ from transient fault conditions were also diminished.

However, excellent water chemistry alone was not sufficient to control corrosion. Hence, programs to modify water chemistry were introduced, including minimizing oxygen to reduce the electrochemical corrosion potential (ECP) in BWRs, and oxygen and pH control in PWRs. More recently, additives to further inhibit the corrosion process have been developed and are now in widespread use. As a result, water chemistry advances are now an important part of the overall operating strategy to control material degradation. Primary system water chemistry also affects fuel performance through the deposition of corrosion products on fuel pin surfaces, and influences radiation fields outside the core. Core uprating through increased fuel duty has reduced margins for tolerating corrosion products (CRUD) on BWR fuel pin surfaces. In PWRs, increasing fuel cycle duration has increased the challenge of controlling pH within the optimum range. At the same time, regulatory limits on worker radiation exposure are tending to be tightened worldwide, putting pressure on the operators to reduce radiation dose rates. Successful operation of PWR steam generators (SGs) and the remainder of the secondary system demand strict water chemistry control in secondary side systems if corrosion problems are to be avoided. Other operating parameters also influence the optimization process, for example, life extension (to 60 years) has emphasized the importance of controlling degradation of circuit materials. Therefore, although control of structural material degradation remains the highest priority, water chemistry must be optimized between the sometimes-conflicting requirements affecting other parts of the reactor. Advances in water chemistry have enabled plant operators to respond successfully to these technical challenges, and the overall performance has steadily improved in recent years.1 Plant-specific considerations sometimes influence or indeed limit the options for controlling water chemistry, so we see different chemistry specifications at different plants. This is especially true internationally and significant differences between countries are noted. The US industry started developing water chemistry guidelines 25–30 years ago, and these now provide the technical basis for guidelines in many other countries. The early editions of these guidelines presented impurity specifications and required action if limits were exceeded. When advanced water chemistries were developed and qualified, the guidelines evolved into a menu of options within an envelope of specifications that should not be

Water Chemistry Control in LWRs

exceeded. Guidance is now provided on how to select a plant-specific water chemistry strategy.2 The basis for water chemistry control was discussed in detail by Cohen.3 The remainder of this chapter describes more recent water chemistry developments for BWRs, PWR primary systems, and PWR secondary systems including SGs, with a short section on flow-assisted corrosion (FAC) in both BWRs and PWRs.

5.02.2 BWR Chemistry Control 5.02.2.1 Evolution of BWR Chemistry Strategies BWR water chemistry has to be optimized between the requirements to minimize material degradation, avoid fuel performance issues, and control radiation fields. These factors are depicted in Figure 1,4 which also includes the main chemistry changes involved in the optimization process. Plant-specific considerations sometimes influence or indeed limit the options for controlling water chemistry, so we see different chemistry specifications at different plants. This is especially true internationally and significant differences in chemistry strategies between countries are noted. Design features are an important reason for these different chemistry regimes, to which must be added the effects of different operational strategies in recent years. For example, a key issue facing BWRs in the United States concerns IGSCC of reactor internals, as discussed in other chapters. The occurrence of IGSCC resulted in the

Clad corrosion crud deposition: Limits on feedwater zinc

Impurity control: Monitoring/analysis required

implementation of hydrogen water chemistry, with or without noble metal chemical addition (NMCA), to ensure that extended plant lifetimes are achieved. German plants use 347 stainless steel, which is less susceptible to IGSCC than sensitized 304 stainless steel used originally in US-designed plants. Some Swedish and Japanese plants have replaced 304 stainless steel reactor internals with 316 nuclear grade material to minimize potential problems, as this material is less susceptible to IGSCC. As a result, many of these plants continue to use oxygenated normal water chemistry, whereas all US plants control IGSCC through the use of hydrogen water chemistry (HWC) with or without normal metal chemical addition to improve the efficiency of the hydrogen in reducing ECP. Second, BWRs in United States undoubtedly have greater cobalt sources than plants in most other countries, despite strong efforts to replace cobalt sources. This resulted in higher out-of-core radiation fields, leading all US plants to implement zinc injection to control fields, whereas only a small number of plants of other designs use zinc. Third, the move to longer fuel cycles and increased fuel duty at US plants, while having major economic benefits, has led to new constraints on chemistry specifications in order to avoid fuel performance issues. Figure 2 depicts the changing chemistry strategies over the past 30 years, showing the focus on improving water quality in the early 1980s and the move to educing chemistry to control IGSCC, which in turn resulted in increased radiation fields, subsequently controlled by zinc injection.

Materials degradation and mitigation

Water chemistry guidelines

Fuel performance

Chemistry control issues

Figure 1 Boiling water reactor chemistry interactions.

19

BWR internals IGSCC, IASCC: HWC or NMC required

Radiation exposure

Radiation fields crud bursts: Zinc required

20

Water Chemistry Control in LWRs

Increasing concerns about core internals cracking led to the need to increase hydrogen injection rates, which in turn resulted in the introduction of NMCA to reduce operating radiation fields from N-16. Figure 3 shows the rate of implementation of HWC, zinc and NMCA, and online noble metal addition (OLNC). The rationale and implications of these developments are discussed in greater detail in subsequent sections. The goal for BWRs is therefore to specify chemistry regimes that, together with the improved materials used in replacement components (e.g., 316 nuclear grade stainless steel), will ensure that the full extended life of the plants will be achieved without the need for further major replacements. At the same time, radiation dose rates, and hence worker radiation exposure, must be closely controlled, and fuel performance must not be adversely affected by chemistry changes.

The first requirement of plant chemistry is to maintain high-purity water in all coolant systems, including the need to avoid impurity transients, which are beyond the scope of this paper. The performance of all plants has improved steadily over the years, as shown by the trend for reactor water conductivity for GE-designed plants, given in Figure 4. This figure shows that conductivity now approaches the theoretical minimum for pure water. In fact, deliberately added chemicals, such as zinc (discussed in the following section), account for much of the difference between measured values and the theoretical minimum. The conductivity data are consistent with the reactor water concentrations for sulfate and chloride. In fact, sulfate is the most aggressive impurity from the viewpoint of IGSCC, and much effort has gone into reducing it. 5.02.2.2 Mitigating Effects of Water Chemistry on Degradation of Reactor Materials

1977: Neutral, oxygenated water

Corrosion, radiation buildup issues

1980s: Purer is better

IGSCC was first observed in small bore piping using sensitized 304 stainless steel fairly soon after BWRs started operation. Laboratory studies showed that impurities increased IGSCC rates, and in fact water quality in BWRs gradually improved in the early 1980s. However, the same studies found IGSCC in high-purity oxygenated water typical of good BWR operations. The key parameter affecting IGSCC was found to be ECP, as shown in Figure 5. In this laboratory test, the change from oxidizing conditions typical of normal water chemistry (NWC) operation

Chemistry guidelines

Late 1980s–1990s: HWC, zinc

Controlling IGSCC, radiation buildup

2000s: Noble metal chemical addition

Core internals cracking control with lower fields

Promising new option

2006–2008: Online Noblechem

Figure 2 Evolution of Boiling water reactor chemistry options from 1977 to 2008.

40

Number of BWRs

35

Zn injection

NMCA

HWC (no NMCA)

OLNC

30 25 20 15 10 5 0 1983

1988

1993

1998

2003

2008

Figure 3 Implementation of zinc injection, hydrogen water chemistry, noble metals chemical addition, and online noble metal at US boiling water reactors.

Water Chemistry Control in LWRs

21

0.40 0.35 EPRI action level 1

Conductivity ( µS cm–1)

0.30 0.25 0.20 0.15 0.10 0.05 Theoretical conductivity limit, 25 ºC

0.00 1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

Figure 4 Boiling water reactor mean reactor water conductivity at US boiling water reactor.

250

0.4950

0.4945 200

2.7 ⫻ 10−8 mm s–1 1 ⫻ 10−6 mm s–1

150

0.4935

0.4930

0.4925

100 CT2 #7-304SS 4 dpa Constant load, 19 ksi√in.

Dissolved O2

Outlet cond: 0.30 μS cm–1

50

Inlet cond: 0.27 μS cm–1 Na2SO4

0.4920

0.4915 1488

Dissolved oxygen (ppb)

Crack length (in.)

0.4940

1508

1528

1548

1568

1588

0 1608

Test time (h) Figure 5 Laboratory results showing the effect of reducing oxygen concentration on crack growth of 304 stainless steel.

to reducing conditions greatly reduced the rate of crack growth. Furthermore, hydrogen injection was effective at reducing the ECP in BWRs, as shown in Figure 6. In this figure, it can be seen that crack growth rates (CGR) for Alloy 182 were low in hydrogen water

chemistry (HWC), but increased greatly when the plant reverted to normal water chemistry (NWC). These results indicated that continuous hydrogen injection was required to fully mitigate cracking. Examination of extensive inspection data from several plants indicated that no IGSCC was observed with an

22

Water Chemistry Control in LWRs

901.00 900.00

HWC ECP = −510 mV (SHE)

NWC ECP = +110 mV (SHE)

Crack length

174 miles year-1

HWC

< 5 miles year-1

899.00 898.00 897.00 < 5 miles year -1

Alloy 182

896.00 895.00 800

900

1000

1100

1200

1300 Time (h)

1400

1500

1600

1700

Figure 6 Effect of hydrogen water chemistry on crack growth of Alloy 182.

ECP of
230 mV or lower, using a standard hydrogen electrode (SHE). This is the basis for the
230 mV requirement used by US plants for IGSCC control. In BWRs, the radiation field in the core decomposes water to hydrogen and oxygen species, most of which immediately recombine back to water. But some remain as oxygen or hydrogen peroxide, because some hydrogen is stripped into the steam phase before it can recombine. These same radiolysis reactions cause hydrogen to react with oxygen or peroxide to reduce ECP. These reactions occur mainly in the downcomer, and relatively low hydrogen concentrations are effective at lowering ECP in out-of-core regions of the system. More than half the BWRs in the United States adopted low hydrogen injection rates of 0.2–0.5 ppm (called HWC-L), which, coupled with the replacement of recirculation piping using 316 stainless steel, mitigated IGSCC of recirculation piping. In the 1990s, concerns about the cracking of core internals increased, but the low concentrations of hydrogen used to protect out-of-core regions were not sufficient to reduce ECP enough to mitigate IGSCC of in-core materials, because of the radiolysis of water occurring in the core. As a result, it was necessary to increase hydrogen concentrations to 1.6–2.0 ppm to lower the in-core ECP sufficiently to provide protection in the reactor vessel (termed HWC-M for moderate concentrations of hydrogen). Although this approach was effective in protecting core internals, it also increased radiation fields in the steam side of the circuit, including the turbines, as a result of carryover of nitrogen-16 under reducing chemistry. (Under the oxidizing conditions of NWC, most of the N-16 remains in the water as soluble

species such as nitrate, and only a small percent is transported with the steam.) In some plants, local shielding of turbine components has reduced the impact of the gamma radiation to acceptable levels, but the projected 4–6-fold increase did in fact curtail plans for increased hydrogen injection rates at many plants. Note that these N-16 radiation fields are a problem only when the plant is at power, as rapid decay occurs at shutdown because of the short halflife of N-16. (By contrast, out-of-core radiation fields from Cobalt-60 persist after shutdown and impact on maintenance work during outages.) NMCA was developed to increase the efficiency of hydrogen in BWR cores, to avoid high N-16 fields. In this process, a nanolayer of platinum þ rhodium is deposited on the wetted surfaces of the reactor. These treated surfaces catalyze the hydrogen redox reaction, converting oxygen back to water. When the addition of hydrogen to the feedwater raises the molar ratio of H2 to O2 to 2 or higher, the ECP of the treated surfaces drops to the hydrogen/oxygen redox potential, which is about
450 mV (SHE). This can be achieved with hydrogen concentrations of only about 0.2 ppm, and under these conditions, the main steam radiation level is not increased to an unacceptable level. The first plant used NMCA successfully in 1997, and over 25 plants have already followed, with excellent results. Field measurements show that NMCA has been effective in providing mitigation against IGSCC by lowering the ECP below the
230 mV (SHE) threshold with relatively low hydrogen injection rates. The NMCA process is typically applied at refueling outage, before new fuel is inserted into the core,

Water Chemistry Control in LWRs

additional benefit with NMCA on the upper, outer shroud regions, as indicated by the additional shading in the left-hand side of the figure5. It is estimated that noble metals protect slightly more of the outer core region than does moderate HWC (HWC-M), but the difference is not significant. Figure 8 shows the dramatic benefit of noble metals in reducing the rate of stub tube cracking at Nine Mile Point 1 since the application in 2000. Before 2000, several stub tubes had to be repaired or replaced at each outage, but since the application, only one tube leaked, and this was believed to have already cracked before NMCA. Recently, attention has been focused on the online application of noble metals, with the first application at the KKM plant in Switzerland. By April 2008, there were four applications in the United States. This is discussed in a later section.

HWC protected regions

NMCA protected regions

and is effective for about three fuel cycles, before reapplication is necessary. The regions of the reactor vessel internals that are protected by HWC-M or NMCA are shown in Figure 7. While both techniques offer significant areas of mitigation, there is an

5.02.2.3

Radiation Field Control

Corrosion products deposited on the fuel become activated, are released back into the coolant, and may be deposited on out-of-core surfaces. Both soluble and insoluble species may be involved, the latter tending to deposit in stagnate areas (‘crud traps’). The chemistry changes to control IGSCC resulted in increased out-of-core radiation fields, and the implementation by most plants of depleted zinc injection to

Figure 7 Mitigated regions of the boiling water reactor core.

Number of stub tubes identified with IGSCC throughwall cracking based on leakage

12

10

8

Noble metal applied mid cycle may 2000

6

4

2

0 1984–1985 1986–1987 1988–1990

23

1991

1993

1995

1997

1999

2001

2003

2005

2007

RFO-11

RFO-12

RFO-13

RFO-14

RFO-15

RFO-16

RFO-17

RFO-18

RFO-19

Year Figure 8 Mitigation of stub tube cracking at Nine Mile Point Unit 1.

24

Water Chemistry Control in LWRs

control dose rates, as discussed later in this section. During shutdowns, the major radiation source for personnel exposure is activated corrosion products, deposited on primary system surfaces. Exposures are generally accumulated at high-radiation field locations where maintenance work is frequently needed. Although improvement of maintenance equipment and procedures, reduction of maintenance requirements, increased hot-spot shielding, and control of contamination dispersion have significantly reduced total exposure, further reduction of radiation fields is a major goal in programs for minimizing occupational radiation exposure. The primary source of radiation field buildup on out-of-core surfaces in BWRs is 60Co, which in mature plants usually accounts for 80–90% of the total dose. 60Co has a relatively long half-life of 5.27 years. The higher the soluble 60Co concentration in the coolant, the more 60Co is incorporated and deposited on out-of-core systems and components, resulting in higher dose rates on recirculation piping, the reactor water cleanup system, dead legs, and other crud traps in the system. Other activated transition metals such as 54Mn, 58Co, 59Fe, and 65Zn contribute the remainder of the dose. 51Cr also contributes significantly to the piping dose in some NMCA plants. The radiation fields commonly measured in a BWR at the straight vertical section of recirculation pipes are considered to be more representative for the purposes of radiation buildup trending and comparison with other plants. These measurements are done in a prescribed manner developed under the EPRI BWR Radiation and Control program and are called BRAC point measurements. These measurements represent primarily the incorporation of soluble 60Co into the corrosion film on the piping surfaces and tend to be a fairly good predictor of drywell dose rates. The deposition of particulate oxides that contain 60Co and other activated species can also contribute significantly to outof-core radiation levels in BWRs, especially in hot spots. The particulate oxides, which vary in size, originate primarily from corrosion of the steam/condensate system and are introduced via the feedwater. The sole precursor of the gamma-emitting 60Co isotope is 59Co. 59Co is present as an impurity in the nickel in structural alloys used in BWRs (e.g., Type 304 stainless steel) and is the main constituent of wear-resistant alloys (e.g., Stellite), used as hard facing in valves and other applications requiring outstanding wear resistance. Corrosion and wear lead to release of 59Co into the coolant from these sources,

which is transported to the core and incorporated into the crud that deposits on the fuel rods. The 59 Co is activated to 60Co by neutron activation, released back into the coolant, and incorporated as a minor constituent into the passive films that form on components that are inspected, repaired, and replaced by maintenance personnel. Components in the neutron flux (e.g., the control blades) directly release 60Co. Cobalt source removal is clearly important if radiation fields are to be minimized. Another gamma-emitting isotope, 58Co, is formed by the activation of nickel from stainless steel and nickel-based alloys. 58Co has a shorter half-life and is not as major a contributor to radiation fields as 60Co in BWRs, but is much more significant in PWRs. Shutdown drywell dose rates increase when coolant chemistry is changed for the first time from oxidizing (NWC) to reducing (HWC) conditions. This results from a partial restructuring of the oxides formed under the oxidizing conditions of NWC (Fe2O3 type) to a more reducing spinel type oxide compound (Fe3O4 type). The oxides affected are the fuel deposits, the corrosion films on stainless steel piping, and out-of core deposits. This results in an increase in the chemical cobalt (and 60Co) concentration in the oxide because of the higher solid-state solubility of transition metals in the spinel structure. The presence of a higher soluble reactor 60Co concentration released from fuel crud while this conversion is occurring only aggravates the situation. The processes are depicted in Figure 9. The net result at most plants is a temporary increase in reactor water 60 Co, both soluble and insoluble forms, which leads to significantly increased shutdown dose rates because of both the increased reactor water concentrations and the increased capacity for transition metal uptake by the spinel phases.6

Oxide stable under normal water chemistry Fe2O3 (containing 60Co, 58Co, 54Mn, etc.)

• Corrosion films • Vessel crud • Fuel crud

Restructuring under HWC conditions

Fe3O4 form of oxide

Small insoluble particles containing 60Co, 54Mn, etc. Soluble 60Co, etc. released during restructure

Figure 9 Boiling water reactor oxide behavior under reducing conditions.

Water Chemistry Control in LWRs

25

0.8 Before Zn addition After Zn addition

RxW 60Co (Ci kg −1)

0.6

0.4

0.2

0 Brunswick-1

Brunswick-2

Dresden-2

Figure 10 Hydrogen water chemistry plant RxW

60

Duane Arnold

Fitz patrick

Monticello

Pilgrim

Co response to zinc addition.

As mentioned earlier, zinc addition reduces radiation field buildup. The mechanism of the zinc ion effect is complex, as release of 60Co from fuel crud is reduced, and deposition out-core is also reduced. Overall, reactor water 60Co is decreased significantly after zinc addition, as shown by plant data in Figure 10. Aqueous zinc ion promotes the formation of a more protective spinel-structured corrosion film on stainless steel, especially when reducing conditions are present. Second, both cobalt and zinc favor tetrahedral sites in the spinel structure, but the site preference energy favors zinc incorporation. Thus, the available sites have a higher probability of being filled with a zinc ion than a cobalt ion (or 60Co ion), and hence the uptake of 60Co into the film will be significantly less if zinc ion is present in the water. The 60 Co remains longer in the water and is eventually removed by the cleanup system. The zinc was originally added to the feedwater as ZnO, but it was quickly found that the 65Zn that was created by activation of the naturally occurring 64Zn isotope in natural zinc created problems. With the use of zinc oxide depleted in the 64Zn isotope, called depleted zinc oxide (DZO), this drawback was eliminated. Because of the high cost of DZO, feedwater zinc injection was not implemented widely until HWC shutdown dose issues emerged. For the case of plants treated with NMCA and injecting hydrogen, the oxidant concentration on the surface of the stainless steel is zero (due to the Pt

and Rh catalyzing the reaction of any oxidant with the surplus hydrogen). The net result is that the ECP is at or very near the hydrogen redox potential, typically about –490 mV (SHE) for neutral BWR water. This low potential causes a much more thorough restructuring of the oxides to the spinel state than observed under moderate hydrogen water chemistry (HWC-M). Feedwater iron ingress has a significant influence on the effectiveness of zinc injection. As discussed in the next section, deposits on fuel cladding surfaces (called ‘CRUD’) are mainly composed of iron oxides, with other constituents. Therefore, reducing iron ingress from the feedwater has the benefit of minimizing crud buildup, which is important for fuel reliability (next section). For these reasons, extensive efforts have been made to reduce iron ingress, with significant success. Furthermore, fuel crud has a large capacity for incorporating zinc and is in fact where most of the zinc ends up. The lower the amount of crud on the fuel, the greater the proportion of zinc that remains in solution and can subsequently be incorporated in out-of-core surfaces. Therefore, at plants with low feedwater iron, less zinc is captured by the crud on the fuel, so a relatively greater amount remains in solution and is available to control out-of core radiation fields. This is very important, as zinc injection rates are limited by fuel performance concerns, and hence lowering feedwater iron is essential for maintaining lower radiation fields.

26

Water Chemistry Control in LWRs

5.02.2.4

Fuel Performance Issues

Fuel durability has improved over the years, and failures have declined, helped by improvements in water purity. In operation, zircaloy fuel cladding develops a thin oxide layer (ZrO2), which typically does not adversely affect performance. However, an increase of deposition of corrosion product deposits (‘crud’) on this oxide film is undesirable because it can reduce heat transfer and increase fuel pin temperatures, with resultant increased corrosion of the fuel cladding, ultimately increasing the risk of fuel failure. Moreover, the addition of additives to control corrosion may increase the risk of crud buildup on the fuel. For example, zinc and noble metals in BWRs tend to increase the adherence of crud deposits on the fuel, which can result in undesirable oxide spalling in higher-rated cores. In fact, corrosion-related fuel failures occurred at four plants in the United States between 1999 and 2003. Although the precise root cause of fuel failures is often difficult to determine, it is clear that excessive crud buildup played a role in these failures. With progressive uprating of fuel duty in both PWRs (and BWRs), the margin to tolerate crud has been reduced and additional care has to be taken in specifying the water chemistry to avoid undesirable fuel performance issues. Despite these more demanding conditions, fuel failures have decreased in recent years. Concern about the possibility of adverse effects of NMCA on fuel has prompted imposition of a strict limit on the amount of noble metal that can end up on the fuel and guidance on the injection of zinc. Plant data indicate that spalling of the corrosion layer from

fuel cladding, which is often regarded as a precursor to cladding failure, is prevented if the cycle average feedwater zinc is maintained below 0.4 ppb in NMCA plants (0.6 ppb for non-NMCA plants). More recent data indicate that quarterly averages may be as high as 0.5 ppb for NMCA plants, without occurrence of spalling.5 These feedwater zinc data are the basis for limits in the water chemistry guidelines. The 2008 chemistry guidelines7 retain the cycle average feedwater zinc limit of 0.4 ppb (0.6 ppb for non-NMCA plants) but enable a slight increase in the quarterly average to 0.5 ppb, which may allow flexibility in controlling radiation buildup in parts of the cycle. The tighter control of water chemistry in recent years has been successful in controlling crud formation on fuel cladding, and Figure 118 shows failures from pellet–clad interaction causing SCC, fabrication defects, debris, and crud/corrosion. Note that there have been zero crud/cladding related fuel failures in US BWRs since 2004 (although assessment of 2007 failures is not yet complete, crud/corrosion is not believed to be a factor here). Analysis of recent plant data confirms that control of feedwater iron ingress has the positive benefit of reducing the amount of crud on the fuel. Control of copper, which generally originates from admiralty brass alloys, is also beneficial; not only can copper have detrimental effects on the fuel, but it also limits the ability of hydrogen to reduce the ECP, and it also leads to higher radiation fields. As a result, most US plants have replaced condensers containing brass tubing.

Number of failed assemblies

30 25 20

PCI-SCC Unknown Fabrication Debris Crud/corrosion

15 10 5 0 2000

2001

2002

2003 2004 EOC year

2005

2006

Figure 11 US boiling water reactor fuel failures by mechanism for each end-of-cycle (EOC) year.

2007

Water Chemistry Control in LWRs

5.02.2.5

Online Addition of Noble Metals

As discussed earlier, the classic NMCA process is generally applied during refueling outages before the new fuel is loaded into the core. Reapplication after about three cycles of operation takes approximately 2 days, while the plant maintains 107–154  C as it enters the refueling outage. To reduce this outage time, GE-Hitachi developed OLNC, first demonstrated at KKM (a GE design of plant in Switzerland) in 2005, with several more additions subsequently. Preliminary results indicate that there have been no unexpected chemistry effects during the first OLNC applications, and shutdown radiation fields actually decreased at KKM after OLNC.5 Subsequently, CGR of susceptible welds decreased significantly, as shown by the decrease in slopes in Figure 12 after OLNC initiation for two welds that have been monitored for several years. The effects of OLNC on fuel have been extensively studied in fuel removed from KKM, and no adverse effects have been observed. The jury is still out on this concern, but the general assessment is that OLNC will have no more impact than the classic application, and may well prove to be of less concern. More IGSCC and fuel measurements are planned, but with no issues emerging to date, it appears that OLNC applications about every 12 months would be effective and economical, avoiding the critical path time necessitated for the classic NMCA application during refueling outages. Initial OLNC applications have been carried out at plants that had previously applied noble metals in the classic off-power manner.

However, the first OLNC application at a plant that has not used noble meals previously occurred in late 2008, but no results are available.

5.02.3 PWR Primary Water Chemistry Control 5.02.3.1 Evolution of PWR Primary Chemistry Strategies In the very early days of PWR operation, heavy crud buildup on fuel cladding surfaces was caused by the transport of corrosion products from the SGs into the reactor core. As a result, activated corrosion products caused high-radiation fields on out-of-core surfaces (Figure 13), fuel performance was compromised, and even coolant flow issues were observed in some plants. These problems were initially mitigated by imposing a hydrogen overpressure on the primary system, to reduce the ECP, and raising the primary chemistry pH. Materials degradation in primary systems was then not a major concern, with most of the emphasis focused on secondary side corrosion issues in the SGs. Commercial PWR power plants use a steadily decreasing concentration of boric acid as a chemical shim (for reactor control) throughout the fuel cycle, which results in the use of lithium hydroxide to control pH. Some 30 years ago, the concept of ‘coordinated boron and lithium’ was developed, whereby the concentration of LiOH was gradually reduced in line with the boric acid reduction to maintain a constant pH.

300 NC appl.

HWC

Indication length (mm)

250 Ind 9

Ind10

Not inspected in 00, 01,04

200 150 100 50

27

OLNC 37 g OLNC 98 g OLNC 198 g OLNC 199 g

Indications 9,10 may be seeing mitigation by OLNC

0 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Year Figure 12 Ultrasonic inspection results after online noble metal chemical addition.

28

Water Chemistry Control in LWRs

Corrosion products deposit out of core Pressurizer Steam generator Corrosion products activated in reactor core

Corrosion products released from SG tubing Coolant pump Reactor Primary loop

Figure 13 Transport and activation of corrosion products in pressurized water reactor primary systems.

Corrosion products released from the steam generator tubes are transported, dissolved, or deposited by the coolant on the basis of solubility differences. The solubility of nickel and iron depend on pH, temperature, and redox potential, all of which vary with location around the nonisothermal system. Originally, a constant at-temperature pH of 6.9 was recommended, based on the minimum temperature coefficient of solubility of magnetite. In fact, it was determined that heavy fuel crud buildup was avoided if a constant pH of at least 6.9 was maintained. This was possible with 12-month fuel cycles, but fuel cladding corrosion concerns limited the maximum LiOH concentration to 2.2 ppm. Consequently, plants often started the fuel cycle with pH below 6.9, which resulted in deposition of corrosion products on the fuel, activation of cobalt and nickel, and subsequent transport to out-of-core surfaces, resulting in radiation fields remaining relatively high. Even though detailed studies of fuel crud showed that the prime constituent of the crud was nickel ferrite (for which the optimum pH is 7.4), this coordinated chemistry had remained the standard for many years, until higher pHs became the norm in the 1990s. Although research and plant demonstrations showed that the 2.2 ppm limit was excessively conservative, the move to higher Li concentrations has been slow. However, detailed fuel examinations from a recent plant demonstration (that will be discussed later) have indicated that Li can be raised to as high as 6 ppm.

About 25 years ago, primary water stress corrosion cracking (PWSCC) of Alloy 600 SG tubes was observed in a few plants, leading to studies on mitigating this effect. Following successful demonstration of zinc injection in BWRs, initial field tests at PWRs showed that radiation fields were reduced, and laboratory studies indicating that PWSCC was reduced were eventually confirmed. As a result, zinc injection is being implemented at an increasing rate, although concerns about fuel performance at highduty plants have not been completely resolved. Most recently, buildup of boron-containing crud in areas of subcooled nucleate boiling leading to localized flux depression has encouraged the use of higher Li concentrations to minimize corrosion product transport. Concerns about the potential adverse effects of zinc deposited in high-crud regions have resulted in several highly rated plants applying in situ ultrasonic fuel cleaning before implementing zinc injection. Although zinc injection was developed for radiation field control, laboratory studies showed that it also inhibited SCC under PWR conditions. The identification of PWSCC in reactor vessel penetrations in the last 15–20 years has encouraged the use of zinc injection, but has also focused attention on the effects of dissolved hydrogen, for which the recommended range has remained 25–50 ml kg
1 for 30 years. It now appears that raising hydrogen will reduce PWSCC rates, while lowering it may delay initiation of PWSCC. The interactions of materials, radiation fields, and fuels in PWR primary

Water Chemistry Control in LWRs

PWSCC: pH (Li, B) minimal effect Zn beneficial dissolved H2 effect

Plant operations

29

Dissolved H2 control range

Materials degradation

PWR chemistry control

Fuel performance

Plant dose rates Radiation fields: pH (Li, B), Zn beneficial

Crud deposition: Zn concern for highly rated cores

Figure 14 Pressurized water reactor primary chemistry optimization. Reproduced from Fruzzetti, K.; Perkins, D. PWR chemistry: EPRI perspective on technical issues and industry research. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008.

Dissolved (H2) range changes

Elevated constant pH (7.3/7.4) Ultrasonic fuel cleaning Elevated constant pH (7.1/7.2) Zinc injection Modified elevated lithium program EPRI water chemistry guidelines Elevated lithium program Constant pH 6.9 1975

1980

1985

1990

1995

2000

2006 2008

Figure 15 Pressurized water reactor primary chemistry changes at US plants.

chemistry and optimization issues covered in the water chemistry guidelines, which are discussed later, are depicted in Figure 14. The evolution of water chemistry control in PWR primary systems in the United States over the last 30 years is shown in Figure 15. The following sections address the three main factors – pH control, zinc injection, and dissolved hydrogen control – that have dominated PWR primary chemistry strategies in the past and continue to do so today.9 Each of these factors is considered from the viewpoint of materials degradation, radiation field control, and fuel performance concerns.

5.02.3.2

Materials Degradation

Materials degradation has been covered in detail in Chapter 5.04, Corrosion and Stress Corrosion Cracking of Ni-Base Alloys and Chapter 5.05, Corrosion and Stress Corrosion Cracking of Austenitic Stainless Steels, and here only the specific effects of water chemistry variables on materials in PWR primary systems will be reviewed, particularly those that may affect the chemistry of optimization process. Recent papers by Andresen et al.10,11 provide detailed results of a comprehensive study of the effects of PWR primary water chemistry on PWSCC of nickel-based alloys. Extensive studies have been carried out to determine the effect of lithium, boron, and pH on PWSCC, and the generally held conclusion is that any effects are minimal, especially compared to material susceptibility, stress state and temperature, and other operational issues. Crack initiation tests using the most reliable types of reverse U-bend specimens indicate that pH has a relatively small effect on crack initiation (generally less than a factor of 2). Although the most rapid crack initiation occurred at pH310  C 7.25, with slower rates at higher or lower pHs, CGR tests generally confirm that pH has minimal effect. The effect of lithium is even smaller than the pH effect, and the influence of boron is minor or nonexistent. Andresen et al. concluded that the effects of relevant variations in PWR primary water chemistry (B, Li,

30

Water Chemistry Control in LWRs

and pH) have little effect on the SCC growth rate in Alloy 600, and thus provide little opportunity for mitigation of PWSCC. Plant data have found no adverse effects from increasing lithium and pH in primary systems. As a result, it is considered that adjusting pH, lithium, or boron to minimize crack initiation may be of minimal value. The 2007 edition of the PWR Primary Water Chemistry Guidelines12 reviewed the most recent data and concluded that pH strategy changes based on PWSCC considerations are not warranted. This means that plants have the flexibility to pursue B/Li/pHt chemistry adjustments to minimize crud transport and radiation buildup without concern for negative effects on PWSCC susceptibility of nickelbased alloys, although of course chloride and sulfate impurities should continue to be minimized. Following good experience in BWRs, zinc injection has been implemented in the primary systems of PWRs, both to reduce primary side cracking of nickelbased alloys and to control dose rates. The qualification work for BWRs showed that zinc inhibited SCC, but the benefit was not sufficient to avoid the need for hydrogen water chemistry to mitigate IGSCC. Thus, the motivation for BWR zinc injection was exclusively radiation field control. The situation in PWRs is different, as laboratory work13 showed that initiation of PWSCC was significantly delayed by zinc injection, and hence the motivation for the initial applications of zinc in most US PWRs at the 10–30 ppb level was to control PWSCC of SG tubing. Additionally, German-designed PWRs and a few US plants used 5 ppb depleted zinc for radiation control.

Figure 16 shows the rate of introduction of zinc injection at PWRs worldwide. Zinc injection produces thinner, more protective oxides on stainless steel and Alloy 600, with zinc displacing Co2þ, Ni2þ, and Fe2þ from normal spinels to give ZnCr2O4, which is very stable. The benefits of PWR zinc injection have been clearly demonstrated in reducing PWSCC degradation (especially growth rate) of Alloy 600 SG tubes, and in controlling radiation fields. Evaluation of currently available laboratory data2 indicates that PWSCC initiation will be reduced, and PWSCC CGR may be reduced in thicker cross-section components, depending upon other factors such as the stress intensity factor of the specimen. Andresen et al.11 concluded that crack growth mitigation by adding Zn requires further study, although two of four tests show a decrease in growth rate of >3. Molander et al.14 also found that the effect of zinc on CGR was minor. Hence, more work is needed before making definitive conclusions from laboratory studies regarding the benefit of zinc in mitigating CGR. SG tube nondestructive examination (NDE) data from eight plants injecting zinc indicated reduction in the incidence of PWSCC by a factor of 2–10.9 An example from a 2-unit PWR showing the effect of zinc on SG tubing over successive cycles is given in Figure 17. The largest effect of zinc appears to be on initiation of cracking, with a smaller effect on CGR, with the data indicating a factor of 2–10 reduction for initiation and about a factor of 1.5 reduction in CGR, consistent with the extensive laboratory work,11

Application of zinc in world PWRs

Number of plants and percentage of PWR injecting zinc

50 45

Percent of PWRs injecting

Number of units injecting

40 35 30 25 20 15 10 5 0 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Year

Figure 16 Application of zinc injection in pressurized water reactors worldwide.

Water Chemistry Control in LWRs

31

140 X indicates last refueling outage before start of zinc injection

Number of new tubes affected

120 100 80

Unit 1 Unit 2 60 40 20 0

X−3

X−2

X−1

X+1 X Refueling outage

X+2

X+3

X+4

Figure 17 Effect of zinc on steam generator tube degradation at a US pressurized water reactor.

70 60 Number of plants

indicating that zinc inhibits mainly by delaying the initiation of PWSCC. However, the SG NDE data also showed that zinc reduced the rate of crack propagation (depth) by 17–60%. These results are consistent with initial laboratory test data indicating that zinc reduced crack propagation by a factor of approximately 3 at low stress intensities, but had no effect at higher stress intensities. In addition, the lack of cracking in the Farley PWR pressure vessel head penetrations (exposed to zinc for over 12 years), compared to PWSCC indications in similar pressure vessel heads in other plants, suggests that zinc addition is beneficial for Alloy 600 (and possibly Alloy 82/182) thick-section components under PWR primary service conditions. Recent work has studied the influence of dissolved hydrogen on PWSCC. In the early days of PWR operation, the lower limit on hydrogen was set at 25 ml kg
1, to provide adequate margin against radiolysis and heavy crud formation. Plant tests in France showed that this limit was excessively conservative and that less than 10 ml kg
1 would be satisfactory, provided good control of oxygen was maintained in makeup water. Several workers have found that the maximum in PWSCC CGR occurs close to the ECP corresponding to the Ni/NiO thermodynamic equilibrium condition.15 Although this potential is unaffected by lithium/boron/pH (consistent with the fact that these do not greatly influence PWSCC over the range of practical relevance), the equilibrium potential is significantly affected by the dissolved hydrogen

50 40 30 20 10 0 25–30 30–35 35–40 40–45 45–50 Cycle average hydrogen concentration (cm3 kg−1)

Figure 18 US plant data for dissolved hydrogen.

concentration. Andresen et al. found that the peak in SCC growth rate versus H2 fugacity was temperature dependent, but generally fell within the hydrogen concentration range used in PWRs. This provides an opportunity for mitigation, by perhaps a factor of 2 in Alloy 600 and a factor of 5 in Alloys 182, 82, and X750, as the median value of the dissolved hydrogen concentration for US plants is approximately 35 ml kg
1. US PWRs currently operate within dissolved hydrogen within the recommended 25–50 ml kg
1 range, with the majority in the 30–40 ml kg
1 range, but none with more than 44 ml kg
1 (Figure 18). The lower limit is set conservatively to provide an operating margin over the level of hydrogen required

32

Water Chemistry Control in LWRs

to suppress water radiolysis in the reactor core. Somewhat lower concentrations are used in other countries. The dissolved hydrogen concentrations corresponding to the peak CGR for a typical range of PWR primary operating temperatures are 4.3 ml kg
1 at 290  C, 10.4 ml kg
1 at 325  C, and 16.5 ml kg
1 at 343  C.15 Andresen et al.11 published Figure 19, which indicates the proposed factors of improvement on changing from an initial hydrogen concentration of 25 ml kg
1. It can be seen that raising the hydrogen provides benefit, but lowering it is detrimental below 330  C.

In response to the data showing the benefit of increasing hydrogen in reducing CGR, the US industry program in progress focuses on the extent to which dissolved hydrogen can be increased without adverse consequences to other parts of the system. Other countries, including Japan, are also investigating lowering hydrogen, because laboratory data suggest that the initiation of cracking is delayed at lower hydrogen concentrations. This is depicted in Figure 20, as discussed by Molander.14 The lower line in this figure shows the time to initiate cracking, based on laboratory tests using

Factor of improvement from H2

4.0 Based on Alloy 182, a current H2 level of 25 cm3 kg−1

3.5

70 cm3 kg-1 H2

25

3.0

45 cm3 kg-1 H2

25

2.5 2.0 1.5

Good 1.0 25 0.5 0.0 270

280

290

1 cm3 kg-1 H2

300 310 320 Temperature (⬚C)

4 cm3 kg-1 H2

25

330

340

Bad

350

Figure 19 Effect of dissolved H2 on primary water stress corrosion cracking crack growth rate at different temperatures.

ml H2/kg H2O (330 ˚C) 10

15

20

25

30

Crack initiation time (h)

Jenssen data on Alloy 600

35

1E−07

Growth 8E−08

20 000

6E−08

15 000

4E−08

10 000 Initiation

2E−08

5000

0 0

5

10 Hydrogen activity (kPa)

15

Crack growth rate (mm s–1)

5 25 000

0E+00 20

Figure 20 Dependencies between the dissolved hydrogen content in pressurized water reactor primary coolant on the crack initiation time observed on initially smooth surfaces and on the crack propagation rate.

Water Chemistry Control in LWRs

reverse U-bend specimens, whereas the upper line shows crack growth data over a similar concentration range. Thus, the lowering of hydrogen appears feasible. However, the relative importance of crack initiation and crack propagation is very dependent on material and plant conditions. In the United States, concern about increased crack propagation at low hydrogen and low temperatures, as shown in Figure 19, has resulted in moving to higher hydrogen being preferred to the alternative of reducing hydrogen. Several factors combine to make higher H2 the preferred way to mitigate SCC, including the importance of bottom-head penetrations (which are exposed to 290  C water) and the recent observation that the CGR in coldworked Alloy 600 is not mitigated at low H2.11 The preferred strategy in the United States is to gradually increase hydrogen to the upper end of the existing range, with the potential to move higher (say to 60 ml kg
1) when the ongoing qualification work is completed. This will include evaluation of the effects of dissolved hydrogen on radiation fields and fuel performance, although any such effects are expected to be minimal.16 5.02.3.3

PWR Radiation Field Control

Corrosion products released from out-of-core materials (primarily SG tubing) deposit on the fuel and become activated, are released back into the coolant, and may be deposited on out-of-core surfaces. Both soluble and insoluble species may be involved, with the latter tending to deposit in stagnate areas (‘crud traps’). In addition to the chemistry items discussed later in this section, it must be stressed that other factors are important to the goal of reducing radiation fields. In particular, the success of the later German-designed plants in eliminating cobalt sources in hardfacing alloys, thereby achieving very low radiation fields, demonstrates the benefits of cobalt source reduction. With many plants replacing SGs, a correlation between recontamination rates and surface finish of the new SG tubing has been noted by Hussey et al.17 Typical PWR fuel cycles start with a relatively high boric acid concentration, which gradually reduces to zero at the end of the cycle. Lithium hydroxide is added to maintain an approximately constant pH. As the duration of fuel cycles increased, more boric acid was required at the start of cycle, which in turn necessitated increased LiOH to maintain the desired pH (Figure 21). As mentioned earlier, radiation field buildup can be controlled by minimizing corrosion product

33

transport and activation. Initially, coordination of lithium hydroxide with boron to maintain a constant at-temperature pH of 6.9 was recommended, based on the minimum solubility of magnetite. In fact, the prime constituent of the crud turned out to be nickel ferrite, requiring a pH of 7.4 for minimum solubility. Fruzzetti et al.15 have recently reviewed the data on elevated pH, which provides a number of benefits including decreased general corrosion (and thus reduced corrosion product transport to the core). Field-tests of pHs greater than 6.9 confirmed that radiation fields were lower. Although no adverse effects were observed on the fuel, many plants were slow to abandon a 2.2 ppm limit, established to avoid excessive zircaloy corrosion. However, there were indications of heavier crud formation after long periods operating below pH 6.9, and as fuel concerns relaxed, a gradual move toward a maximum of 3 ppm lithium resulted. Moreover, pHs in the range 7.1–7.2 became more popular in the late 1990s, with 7.3–7.4 eventually gaining favor. Figure 22 shows the maximum lithium concentrations reported by US PWRs in recent years. It can be seen that 95% are now using greater than 3 ppm at full power: a significant change from earlier in the decade. A demonstration of elevated Lithium/pH is in progress at Comanche Peak PWR.18 The goal was to reduce radiation fields and reduce susceptibility to the Axial Offset Anomaly (AOA) by reducing crud buildup. This test involved increasing the primary system pH from 7.1/7.2 to 7.3 and then two cycles at 7.4. No significant adverse trends have been noted, either in the area of chemistry or core performance. Radiation fields measured have shown a modest but continued improvement. On the basis of the positive trends and absence of any negative effects, Comanche Peak has established elevated constant pHTave 7.4 as the primary chemistry regime for both units. Without the increases in pH/lithium that have taken place, radiation fields would have been expected to increase significantly for longer fuel cycles. The increase in boiling in localized regions of the core (called subcooled nucleate boiling) in PWRs resulting from power uprating has resulted in higher crud buildup on the upper fuel surfaces, and there is growing evidence from US PWRs that radiation fields are indeed higher for the highest rated cores. Enriched boric acid (EBA), that is boric acid enriched with B-10, enables a given pH to be achieved with less lithium hydroxide, as the required concentration of B-10 can be obtained with less total

34

Water Chemistry Control in LWRs

Constant pH 7.2 6

Lithium ‘Li high limit’ ‘Li low limit’

5 Li target = 6.0 E−7 B2 + 0.0023B + 0.4413

Lithium (ppm)

4 3.5 ppm limit 3 2.2 ppm limit 2

Start of 18-month cycle

1

Start of 12-month cycle

0

20

80

140

200

260

320

380

440

500

560

620

680

740

800

860

920

980

1040

1100

1160

1220

1280

1340

1400

1460

1520

1580

1640

1700

0

Boron (ppm) Figure 21 Lithium concentrations required to maintain pH 7.2 for different fuel cycle lengths.

boric acid. EBA is used at several plants in Europe, typically to increase shutdown margin when using mixed oxide fuel (MOX), but has not been applied to date in the United States. However, consideration is being given to using EBA at some plants that will use MOX fuel in the future. Despite the transition to the use of EBA in operating plants, designing for it in new plants is recommended.19 As discussed earlier, the motivation for the initial applications of zinc in most US PWRs was to control PWSCC of SG tubing. However, German-designed PWRs and a few US plants used 5 ppb depleted zinc for radiation control, mostly with depleted zinc to avoid zinc-65 formation. A recent paper ‘‘Understanding the zinc behavior in PWR primary coolant: a comparison between French and German experience’’ by Tigeras et al.20 provides a European perspective on this topic. This paper concludes that ‘zinc injection seems to present the most positive and clearest results: in all the units injecting zinc, a dose rate reduction has been detected after a certain period of exposure without leading to any negative impact on plant

systems, components, and operation.’ Thus ‘zinc injection should be considered as a strategy with benefits in short, medium, and long term. Its application as soon as possible in the life of nuclear power plants and especially before SG replacement and fuel cycles modifications seems to be an excellent decision to contribute to ensuring the passivation process of new components, the fuel performance, the full power operation of the units, and the long life of materials and components.’ Figure 23 shows the effect of zinc in reducing radiation dose rates at several plants. It can be seen that the reduction factor approximately correlates with the cumulative zinc exposure in ppb months (the product of the average zinc concentration and the duration of zinc addition). As little as 5 ppb zinc has been shown to reduce radiation fields by 35–50% at operating plants, based on zinc exposures of 700 ppb months. There is relatively little difference between plants with Alloy 600/690 SG tubing and those with Alloy 800 tubing, but plants using depleted zinc show greater benefit than those using natural zinc, as shown in the figure.

Water Chemistry Control in LWRs

35

Percentage of units within range

70

<3 ppm 3.0−3.5 ppm >3.5 ppm

60 50 40 30 20 10 0

2000

2001

2002

2003

2004

2005

2006

2007

EOC year Figure 22 Maximum reported coolant lithium (full power) at US pressurized water reactors.

Cumulative dose rate reduction fraction

1.2 Alloy 800 w/depleted zinc Alloy 600 and 690 w/depleted zinc Alloy 600 and 690 w/natural zinc Log Alloy 800 plants Log Alloy 600 and 690 w/depleted zinc Log Alloy 600 and 690 w/natural zinc

1

0.8

0.6

0.4

0.2

0 0

200

400

600 800 1000 1200 1400 1600 Cumulative zinc exposure (ppb months)

1800

2000

Figure 23 Effect of zinc injection on radiation dose rates.

5.02.3.4

Fuel Performance

With progressive uprating of fuel duty, the margin to tolerate crud has been reduced and additional care has to be taken in specifying the water chemistry to avoid undesirable fuel performance issues. Figure 24 shows the root causes of PWR fuel failures since 2000, including failures from pellet–clad interaction causing SCC, fabrication defects, debris, grid fretting, and crud/corrosion. In contrast to the BWR

situation, shown in Figure 11, very few failures in recent years have been attributed to crud/corrosion (the exceptions to this comment are discussed in a following section). A phenomenon called axial offset (AO) has caused concern over the past 10 years.21 AO is a measure of the relative power produced in the upper and lower parts of the core and is normally expressed as a percent, with a positive percent indicating that

36

Water Chemistry Control in LWRs

Number of failed assemblies

120 Unknown Debris Crud/corrosion

100

Fabrication PCI-SCC Grid fretting

80 60 40 20 0 2000

2001

2002

2003

2004

2005

2006

2007

EOC year Figure 24 US pressurized water reactor fuel failures by mechanism.

more power is produced in the upper part of the core. AOA occurs when boron concentrates in corrosion product deposits (crud) on the upper spans of fuel assemblies undergoing subcooled nucleate boiling, causing a reduction in neutron flux. AOA has affected at least 20 PWRs in the United States, as well as several in other countries. Clearly, fuel crud is involved in the AO phenomenon, and water chemistry effects must be considered in controlling AO. Besides their axial asymmetry, the composition of fuel deposits in boiling cores is different from nonboiling fuel. The nickel-rich deposits on boiling cores tend to be removed much less effectively by conventional chemistry shutdown evolutions than the nickel-ferrite deposits on nonboiling cores. Alternative methods are therefore required for removing corrosion product deposits from reload fuel from highduty cores, including ultrasonic fuel cleaning. An important difference exists between plants with Alloy 600 or 690 SG tubing and those (such as German-designed plants) with Alloy 800 tubing. The latter have a much lower proportion of nickel in fuel crud and have not experienced the AO phenomenon.22 Early work showed that lithium increased zircaloy oxidation rates, although the adverse effects were reduced in the presence of boric acid. As a result, a limit of 2.2 ppm lithium was generally imposed to reduce zircaloy corrosion, although excessive crud formation at low pHs was likely to be more detrimental to the cladding than higher lithium concentrations, especially as the resistance

to corrosion of zircaloy improved. This was confirmed by one of the few failures in recent years that was uniquely attributed to crud buildup. In this example, a move to a longer fuel cycle necessitated increasing the boron concentration at start of cycle; however, the 2.2 ppm lithium limit was retained, resulting in the pH being well below 6.9 for the initial period of the cycle. This in turn caused heavy crud formation, to which subsequent fuel failures were attributed. The move in the past ten years to greater fuel duty, with operation of fuel at higher temperatures (with localized subcooled nucleate boiling), has caused crud-related problems to reappear, particularly the localized flux depression as a result of buildup of boron-containing crud, which were discussed earlier. This in turn has renewed interest in elevated pH/ lithium to minimize corrosion product transport, the use of EBA and the more immediate mitigation that can be obtained from fuel cleaning. Fuel performance is always a concern with changes in water chemistry, such as zinc injection. On the basis of current experience, the impact appears to be minimal for the majority of plants, but insufficient data exist for plants with the highest fuel duties to allow application without postexposure fuel inspections. Data from US plants suggest little or no fuel concerns for coolant zinc levels up to 40 ppb for plants with less-highly rated cores. Extended experience at these plants, over at least 10 years of operation, indicates no adverse effects on fuel at zinc concentrations from 15 to 25 ppb. However, there have been no data

Water Chemistry Control in LWRs

available until recently for higher zinc concentrations in higher duty cores where significant subcooled nucleate boiling occurs on the fuel clad surface.23 Perkins et al.24 comment that fuel performance must be considered prior to injecting zinc and additional monitoring and fuel surveillances to understand and evaluate the impact and the role of zinc may be required in some circumstances.

5.02.4 PWR Secondary System Water Chemistry Experience 5.02.4.1 Evolution of PWR Secondary Chemistry Strategies The objectives of PWR secondary water chemistry control are to maximize secondary system integrity and reliability by minimizing impurity ingress and transport, minimizing SG fouling, and minimizing corrosion damage of SG tubes. Since secondary side corrosion damage of SG tubes is primarily caused by impurities in boiling regions, where high concentrations of impurities occur in occluded regions of the SG formed by corrosion product deposits, new approaches are continually sought to control corrosion product transport to and fouling within the SGs.25 PWRs have experienced IGA on both the primary and secondary sides of the Alloy 600 SG tubing, which has been a major contributing cause of the replacement of most of the SGs with mill-annealed tubing, not only in the United States but internationally. Figure 25 illustrates the various corrosion processes found in different locations in a recirculating SG.26 PWR secondary system water chemistry has evolved through many changes over the years, largely in response to emerging technical issues associated with this degradation of structural materials in SGs. In the early days of PWR operation, wastage became a problem in the secondary side of PWR SGs, resulting in a switch from the use of sodium phosphate inhibitor to all-volatile treatment (AVT) using ammonia, which in turn brought about the denting phenomenon. Tighter control of impurities, oxidizing potential, and pH were necessary to mitigate the denting problem. Despite continued chemistry improvements, many plants have had to replace SGs of earlier designs (e.g., those tubed with Alloy 600MA), as shown in Figure 26. Newer generation SGs are performing well, although there remain concerns about the adverse effects of lead impurity, causing Pb-assisted stress corrosion cracking (PbSCC), which is discussed later.

37

Lead has been observed in various flow streams (final feedwater, heater drains, etc.) in the secondary systems of PWRs. Lead is detected at some concentration in nearly all deposit analyses (SG and other locations). Lead is present in trace concentrations in secondary system materials of construction, as well as in chemical additives such as hydrazine.15 Figure 27 shows the worldwide causes of SG repairs through 2004. It can be seen that IGA is currently the most prevalent form of degradation. Figure 28 compares the behavior of three types of SG tubing, Alloy 600MA (mill-annealed material used in early plants, Alloy 600TT (thermally treated material used in later plants), and Alloy 690TT (an improved alloy used in most replacement SGs). This diagram is taken from the 2008 PWR Secondary Water Chemistry Guidelines,27 which contains a much more detailed account of corrosion processes. 600TT has reduced susceptibility under mildly oxidizing highalkaline conditions, that is, SCC is not observed until higher pH than for 600MA, and 600TT has approximately the same susceptibility as 600MA under acidic conditions. 690TT is indicated as having a still smaller region of susceptibility in the high-alkaline region and as having no susceptibility in the acid region except under highly oxidizing conditions that are unlikely to occur in plants. However, other work indicates that SCC can occur in 690TT at an acidic pH, especially if lead is present. Also, SCC occurs in both 600MA and 600TT in the mid pH region if lead is present. In the 1990s, improved pH control using amines became a regular practice, and fine-tuning, including using mixtures of different amines to control pH throughout the circuit and coordination with resin utilization, continues today. Hydrazine is used to remove oxygen from the system. Hydrazine levels have continually been reviewed and ‘optimized,’ with due regard to any impact on FAC in secondary systems, as FAC rates increase at very low oxygen concentrations. Molar ratio control (MRC) describes a control strategy that adjusts the bulk water chemistry, generally sodium and chloride, such that the solution that is developed in the flow-occluded region is targeted to be near neutral. MRC can involve the addition of chloride ions to ‘balance’ the cations that cannot be reduced via source term reduction programs. MRC was widely practiced to minimize SCC concerns, but has not been actively employed at plants replacing to SGs tubed with Alloy 690TT. With more plants replacing their SGs, less plants are adopting the MRC program. Only ten plants were doing MRC in 2007,28 and they are all with original SGs with

38

Water Chemistry Control in LWRs

U-bend cracks (PWSCC)

Fatigue

Free span ODSCC IGA

ODSCC

PWSCC

Expansion transition

PWSCC

PWSCC or ODSCC

ODSCC Denting

Fretting, wear, corrosion, thinning

Tubesheet Pitting IGA

Expansion transition

Tubesheet

ODSCC Sludge

Tubesheet

PWSCC tube-end cracking

Tubesheet

Figure 25 Corrosion processes in recirculating steam generators, showing primary water stress corrosion cracking and outside diameter stress corrosion cracking on the secondary side.

Water Chemistry Control in LWRs

39

140 Operating plants Plants w/replacement SGs 120

134

84 88

81

134 134

134 72

64 67

59

52

45 51

37

22 29

17

10

7

7

7

7

3 5 7

2

78

134

134

132

131 132

134 131 131

132

132 133

134

12

132

134

12

133

133

130

121

63 68

55

46

1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

1

22

20

31

41

40

0

11

93 99

60

108 115

127

80

79

Number of plants

100

Year Figure 26 Steam generator replacement status worldwide.

100 90 80

Percent

70 60 50 40 30 20 10 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

0 Year IGA Impingement Pitting Other Wear Thinning

Fatigue Unknown SCC Preventive

Figure 27 Worldwide causes of steam generator tube repair.

600MA and 600TT tubing. Currently, no plants with replaced SGs are believed to be using MRC. Titanium-based inhibitors to minimize corrosion are also employed at some plants. Boric acid

treatment (BAT) involves the addition of boric acid to feedwater. Such approaches are worthy of consideration, on the basis of plant-specific degradation mechanisms, operational considerations, and

40

Water Chemistry Control in LWRs

1.0

TT690

Potential (V vs. Ec )

0.8 Some tests indicate that 690 TT may be susceptible in the low pH region, especially if lead is 690 TT U-bend cracked present in near neutral AVT with lead and oxidizing sludge TT690 TT600 TT600 MA600

0.6

0.4

MA600 0.2 600 MA and 600 TT can be susceptible in mid pH range if lead or reduced sulfur is present.

0

2

3

4

5

6 7 8 pH 300 °C (572 °F)

9

10

11

12

Figure 28 Corrosion mode diagram for Alloys 600MA, 600TT and 690TT (based on Constant Extension Rate Tensile Tests at 300  C), showing regions where materials are susceptible to attack.

interactions. The most recent developments are aimed at reducing deposit buildup in crevices, including the use of dispersants, such as polyacrylic acid (PAA), that is discussed in more detail later. The historical trends in PWR secondary chemistry are shown in Figure 29. 5.02.4.2 Chemistry Effects on Materials Degradation of SGs Corrosion of SG tubes has been the major issue affecting selection of secondary water chemistry parameters. However, corrosion and FAC of SG internals and other secondary system components are also important concerns. Corrosion of SG tube materials is mainly affected by the following water chemistry related factors, in addition to nonwater chemistry factors such as material susceptibility, temperature, and stress:  pH – Corrosion of several different types, including IGA/SCC and pitting, are strongly affected by the local pH. High pH (caustic conditions) and low pH (acidic conditions) accelerate the rates of IGA/SCC.  ECP – The ECP is a measure of the strength of the oxidizing or reducing conditions present at the

metal surface. The rate of corrosion processes are strongly affected by the ECP. Secondary side SCC in tube alloys tends to be accelerated by increases in ECP, that is, by the presence of oxidizing conditions.  Specific species – Some impurity species accelerate corrosion of tubing alloys as a result of their effects on pH and ECP. In addition, lead and reduced sulfur species (e.g., sulfides) appear to interfere with formation of protective oxide films on the tube metal surfaces, and thereby increase risks of IGA/SCC, independent of influences on pH or potential. Similarly, chlorides tend to increase the probability of pitting. These factors have been most thoroughly explored for mill-annealed Alloy 600 (600MA). As discussed in Chapter 5.04, Corrosion and Stress Corrosion Cracking of Ni-Base Alloys, tests indicate that the other tubing alloys, that is, stress-relieved Alloy 600 (600SR), thermally treated Alloy 600 (600TT), nuclear grade Alloy 800 (800NG), and thermally treated Alloy 690 (690TT), exhibit similar tendencies, but have increased resistance to corrosive attack, in the order listed, with 690TT having the highest resistance. Laboratory tests and plant experience indicate that 690TT has very high resistance to IGA/SCC on the outside diameter on tubing (OD IGA/SCC) in

Water Chemistry Control in LWRs

41

Pb remediation Dispersants Titanium Molar ratio control MPA, DMA ETA chemistry Morpholine chemistry Boric acid addition EPRI water chemistry guidelines Ammonia chemistry Phosphate 1975

1980

1985

1990

1995

2000

2005

Figure 29 Evolution of water chemistry for pressurized water reactor secondary systems.

normally expected crevice conditions, but OD IGA/ SCC could possibly occur as a result of upsets or as a result of long-term fouling and accumulation of aggressive species in deposit-formed crevices. Alloy 800NG also has high resistance to OD IGA/SCC, but laboratory tests indicate that it is about twice as susceptible as Alloy 690TT, and it has experienced limited amounts of IGA/SCC in plants, while no operation-related corrosion of 690TT has been reported. Laboratory tests and some plant experience indicate that 600TT is significantly more resistant than 600MA but less resistant than 800NG and 690TT. Water chemistry selected to protect SG tubes appears to be satisfactory for most balance-of-plant (BOP) components such as turbines. The main corrosion concerns in the BOP that affect secondary system water chemistry are FAC of carbon steel piping, tubing, and heat exchanger internals and shells, and ‘ammonia’ attack of copper and copper alloy tubes. In addition, FAC has also affected some recirculating SG internal components (e.g., feedrings, swirl vanes). FAC is mainly influenced by the at-temperature pH and oxygen content around the secondary system. ‘Ammonia’ attack of copper alloys is mainly influenced by the concentrations of ammonia and oxygen at the copper alloy locations, but is also accelerated by increases in concentrations and pH associated with other amines, although not as strongly as by increases in ammonia. Once-through steam generators (OTSGs) have different thermal hydraulics and (in original SGs)

tube materials than recirculating steam generators (RSGs). These differences have led to OTSGs having somewhat different tube corrosion experience than RSGs of the same vintage. For the most part, OTSGs have experienced somewhat lower rates of tube degradation. However, significant IGA/IGSCC has been detected in the upper bundle free spans of several units, especially at scratches, and SG replacement has been performed or is planned at all units. The locations in SGs that are most affected by IGA/IGSCC are those where free circulation of secondary water is impeded by the local geometry, for example, in crevices formed by tube support plates or by sludge piles that can accumulate on the tube sheet. Impurities in the secondary water can concentrate in these locations by boiling and evaporation in a process called ‘hideout.’ The key issue influencing water chemistry regimes in PWR secondary system is to minimize SG degradation by controlling sludge buildup, reducing (and balancing, e.g., MRC) the concentration of impurities (i.e., sodium, chloride and sulfate) in deposits at the tube-tubesheet and tube-tube support plate interfaces. The use of advanced amines to control pH has increased significantly in the past few years, as discussed in a following section. Figure 30 shows the main approaches used in typical chemistry control strategies. Impurities are removed from SGs by blowdown of the coolant. Over the past 20 years or so, average

42

Water Chemistry Control in LWRs

Key issue: Mitigating IGA/IGSCC in concentrating regions

Approach: Control local chemistry

Molar ratio control

Reduce Na increase Cl

Reduce iron

Redox potential

Amines dispersants

Reduce Cu increase N2H4

Inhibitors

Boric acid TiO2

Figure 30 Pressurized water reactor secondary chemistry control strategies.

blowdown impurity concentrations in US SGs have been reduced from several ppb to the sub-ppb range. Many PWRs today have SG blowdown concentrations near or below the analytical detection limit. Minimization of impurities is recommended but has been insufficient to prevent or completely mitigate IGA/IGSCC at most plants with susceptible tube material and design, as it can result in sodium-rich feedwater. Cations such as sodium can be more effectively retained by boiling in a crevice than chloride. Hence, excess cations over anions or anions over cations result in specific corrosion issues because of concentration processes in local environments. The original all-volatile treatment used ammonia to control pH, but a less-volatile chemical than ammonia would improve pH control throughout the circuit. Early work employed morpholine, but now several other amines are used. Since the initial application of advanced amine chemistry about 15 years ago, there has been tremendous success in reducing the transport of corrosion products to the SGs by improving the attemperature pH around the BOP, especially in the two-phase regions. This has resulted in mitigation of FAC and thus reduced generation of corrosion products that ultimately get transported to the SGs. Ethanolamine (ETA) remains the most used amine at US plants, with 75% of the US plants using ETA or ETA with other amines, such as dimethylamine (DMA) or 3-methoxypropylamine (MPA), to control secondary cycle pH, as shown in Figure 31.17 Several plants now use a mixture of amines to achieve the optimum pH throughout the secondary system, with 25% of the US plants using MPA or MPA with other amines while 12% of the plants use morpholine or morpholine with other amines.

0%

4% 5%

4%

16% 56%

2% 7% 6%

ETA MPA

ETA/DMA ETA/MPA MPA/DMA MPA/Morph Morph/DMA

ETA/Morph Morph

Figure 31 Amines used in the secondary systems of US pressurized water reactors.

The proper control of oxygen in pressurized water reactor (PWR) secondary feedwater, using an oxygen scavenger such as hydrazine and/or carbohydrazide, has been an enduring issue. The requirements for oxygen concentration necessitate that some optimization take place. Maintaining reducing conditions – that is, low electrochemical potential – in the SG is essential to minimize SCC. On the other hand, some oxygen in the feedwater counteracts corrosion of

Water Chemistry Control in LWRs

1985

< 1992

1993

1994

1995

1996

1998

43

2005

% of US PWRs using advanced water chemistries 120 99

100 80 60

76 62

73

40 58

40 68

44

44

20 23

0

3

Using advanced amines

57

30

23

30 30

50

41

31 33

28

0

3

On molar ratio control

Using >100 ppb FW N2H4

35

19 37 41

17

Using boric acid treatment

Figure 32 Pressurized water reactor secondary chemistry trends.

carbon steel surfaces and the transport of corrosion products to the SG. Recent work has investigated the effect of hydrazine and oxygen on the ECP of SG tubing materials (Alloys 600 and 690) as well as stainless steel (304 and 316) and carbon steel during PWR startup conditions. These laboratory studies have shown that changes in the concentration of hydrazine, used to ensure a reducing potential in the SG, within the typical range allowed and employed (e.g., 20–150 ppb) have no discernable effect on FAC at feedwater temperatures (e.g., 180–235  C). Figure 32 shows the trends in using advanced water chemistry regimes in the secondary systems at US plants. 5.02.4.3

Control of Sludge Fouling of SGs

Corrosion products in the secondary side of PWR SGs primarily deposit on the SG tubes. These deposits can inhibit heat transfer, lead to thermal–hydraulic instabilities through blockage of tube supports, and create occluded regions where corrosive species can concentrate along tubes and within tube-to-tube support plate crevices. The performance of the SGs can be compromised not only through formation of an insulating scale, but also through the removal of tubes from service due to corrosion. Although the application of various amines to control the at-temperature pH (pHT) in specific locations of PWR secondary systems has been

successful in reducing the corrosion of BOP metals and thus reducing corrosion product transport to SGs, a complementary strategy now exists for significantly reducing SG fouling through online application of dispersant, which inhibits deposition. By inhibiting deposition of the corrosion products, the dispersant facilitates more effective removal from the SGs via blowdown. This strategy has been employed at fossil boilers for many decades. However, due to the use of inorganic polymerization initiators (containing sulfur and other impurities), polymeric dispersants had not been utilized in the nuclear industry. Only recently has a PAA dispersant been available that meets the criteria for nuclear application, and progress has been made in reducing SG fouling by application of an online dispersant to substantially improve the efficiency of blowdown iron removal. Dispersant application is proving to be a highly promising technology for markedly decreasing SG fouling, delaying (or possibly eliminating) the need for expensive chemical cleaning and effectively reducing the frequency of sludge lancing for SG maintenance. Online application of PAA to the feedwater system has been successfully demonstrated to greatly increase the efficiency of the blowdown system in eliminating feedwater corrosion products from fouling the SGs. The first application occurred at Arkansas Nuclear One Unit 2 for a three-month trial in early 2000, which demonstrated a significant improvement in the blowdown iron removal efficiency from 2% to 60% with 4–6 ppb PAA in

44

Water Chemistry Control in LWRs

With dispersant

Iron removal efficiency

100

10 Without dispersant

1 0

0.5 1 1.5 2 Dispersant concentration (ppb)

Figure 33 Iron removal efficiency during dispersant test at McGuire pressurized water reactor.

the feedwater. The second application, in 2005–2006, at McGuire Unit 2 for a 6–9 month trial in their replacement SGs tubed with Alloy 690TT showed a similar significant improvement., as shown in Figure 33.15 The following conclusions are evident from the McGuire 2 demonstration described in the above reference:  PAA is an effective dispersant. A feedwater PAA concentration approximately equal to the feedwater iron concentration (2 ppb in this case) appears to effectively remove approximately 50% of the influent feedwater iron under steady-state operating conditions.  Although blowdown copper spikes with initial PAA application (albeit to a much lesser extent than iron), it quickly returns to normal levels and remains there.  Filter element consumption is manageable.  Blowdown cation conductivity and ammonia behavior changed during the trial, but these changes are believed to be mainly due to changes in plant configuration and not PAA.  The SG thermal performance level has improved slightly with dispersant application, most likely due to slight beneficial changes in the tube deposit thermal properties. The long-term trial at McGuire 2 demonstrated the significant improvement in blowdown iron removal efficiency with application of PAA dispersant (a follow up to the successful short-term trial at ANO-2 in 2000). Based on the success of the McGuire 2 long-term trial, evaluations are in progress with SG vendors looking toward technical concurrence for long-term use in their fleet of recirculating SGs.

5.02.4.4

Lead Chemistry

PbSCC is a serious concern that can affect all SG tubing materials currently employed. A better understanding of lead behavior is needed at SG and feedwater temperatures before possible mitigation techniques can be successfully developed. It is well known that soluble lead at very low concentrations can contribute to SCC of nickel alloys. Likewise, it is well known that some locations on the secondary side of PWR SGs will accumulate lead in the solid state (i.e., deposit) with local concentrations considerably in excess of those observed to accelerate cracking in laboratory testing. Recent investigations using analytical transmission electron microscopy15 have identified lead in the cracks of many tubes pulled from PWRs. However, the absence of extensive operating SG tube failures at rates comparable to what might be predicted based on laboratory studies of PbSCC indicates that some mitigating phenomenon could be present.15 EPRI has published a sourcebook on lead29 that summarizes the state-of-knowledge regarding PbSCC and its effects on PWRs. It incorporates PbSCC laboratory testing, the current understanding of lead transport and other physical chemistry aspects of lead, and the accumulated industry experience regarding PbSCC and its mitigation. Three clearly understood and accepted facts regarding lead in PWR secondary water systems became clear as this sourcebook was being put together:  In laboratory testing, the presence of lead accelerates SCC of mill-annealed 600MA, stress-relieved 600SR, and thermally treated 600TT stainless steels as well as thermally treated Alloy 690 (690TT).  In operating PWRs, lead is present in the secondary system.  In two cases, a large ingress of lead to the secondary system has occurred as a result of lead blankets having been left behind in SGs; the tubes in the affected SGs cracked sooner and faster than in the other SGs at the same units. Set against these known facts are the following four points:  The mechanisms by which lead is transported from its ultimate source to the SG tube and into a crack are not well understood, and a comprehensive evaluation of possible mechanisms has not been performed.

Water Chemistry Control in LWRs

 The threshold concentration at which lead will accelerate SCC in SGs is not well defined.  No definitive indicator of PbSCC is available.  There is no well-characterized mechanism by which lead accelerates SCC. Recent work has shown that adsorption/desorption of Pb on corrosion products and SG tubing surfaces could potentially be a major sink/source, respectively, for Pb microscopy.15 There is no direct evidence of adsorption in SGs; however, there is sufficient potential for this mechanism that direct high-temperature measurements under SG conditions have been performed. As a result of ongoing laboratory studies, microscopy15 speculates that formation of a lead layer slows repassivation, after a passive film at the crack tip is disrupted, potentially to an extent to which a crack can initiate and propagate.

5.02.5 Chemistry Control for FAC in BWRs and PWRs FAC causes wall thinning of carbon steel piping, vessels, and components, as discussed in Chapter 5.06, Corrosion and Environmentally-Assisted Cracking of Carbon and Low-Alloy Steels. The wall thinning is caused by an increased rate of dissolution of the normally protective oxide layer, for example, magnetite, that forms on the surface of carbon and low-alloy steels when exposed to highvelocity water or wet steam. The oxide layer reforms and the process continues. If the thinning is not detected in time, the reduced wall cannot withstand the internal pressure and other applied loads. The result can be either a leak or a complete rupture. The rate of wall loss (wear rate) of a given component is affected by temperature, fluid bulk velocity, the effect of component geometry on local hydrodynamics, the at-temperature pH, the liquid phase dissolved oxygen concentration, and the alloy composition. The addition of chromium to steels decreases the rate of FAC. Materials used to replace piping damaged by FAC include low-alloy steels containing chromium and molybdenum (P11, 1.25% Cr–0.5% Mo and P22, 2.25% Cr–1% Mo) and carbon or lowalloy steels clad with stainless steel. Corrosion models are used to estimate wall thinning and determine where monitoring is required. An example of the approach commonly used in the United States is described by Chexal and Horowitz.30

45

The main chemistry factors that affect the rate of FAC are pH and dissolved oxygen concentration. FAC is not an issue for PWR primary systems. As indicated earlier, laboratory studies have shown that changes in the concentration of hydrazine in the PWR secondary system feedwater, used to ensure a reducing potential in the SG, have no discernable effect on FAC at feedwater temperatures, within the typical range allowed and employed. The chemistry parameter that a BWR plant has some degree of control over is dissolved oxygen. Oxygen affects the form and solubility of the oxide layer, the dissolution of which is inherent in FAC. Several plants inject oxygen into the system, as the rate of FAC increases dramatically if the oxygen concentration is less than about 25 ppb. Plant data are shown in Figure 34. Use of HWC in a BWR can significantly reduce the amount of oxygen in the main steam, extraction steam, and heater drain systems, thus potentially increasing the FAC rates in these areas of the plant. The effect of NMCA on the corrosion behavior of carbon steel in 550  F (288  C) water containing various amounts of oxygen and hydrogen has been studied and the data confirm that there is no adverse effect of NMCA on FAC.7 The carbon steel segments of the BWR vessel bottom-head drain line have been identified as being FAC susceptible because of the flow conditions and the potential for low dissolved oxygen concentrations. However, a significant number of inspections have been performed recently at US plants and little thinning has been observed. The 2008 edition of the BWR Water Chemistry Guidelines7 recommends that feedwater oxygen should be maintained above 30 ppb to minimize FAC of carbon and low-alloy steels.

5.02.6 Water Chemistry Control Strategies Sometimes, step changes in chemistry strategy are unavoidable, as with the move to reducing chemistry in BWRs. In these cases, the operators must be prepared to deal with adverse effects. Some BWRs adopting reducing conditions experienced a large jump in out-of-core radiation fields, which may be avoided with prior zinc injection. Addition of new chemicals requires extensive qualification. For example, the successful demonstrations of BWR online noble

Water Chemistry Control in LWRs

Relative FAC wear rate (expressed as percentage of the average wear rate of components at 10 pbb oxygen)

46

160 140 Plant A 120

Plant A

100

Plant B Plant C

80

Plant D 60

Average

40 20 0 0

10

20

30

40

50

60

70

80

Dissolved oxygen (ppb) Figure 34 Plant data showing the relationship between flow-assisted corrosion and dissolved oxygen. (Oxygen values are localized, calculated by the CHECWORKS codes from measured values at condensate or feedwater locations.)

chemistry and PAA dispersants in PWR SGs resulted from detailed monitoring and evaluation during the first injections. If possible, changes in chemistry should be made in baby steps, with monitoring at each step, before further changes are implemented. Examples of this strategy are the gradual increases in lithium/pH and dissolved hydrogen in PWR primary systems. These incremental changes minimize adverse side-effects and allow a planned approach to the optimum plant-specific chemistry control program. The US nuclear power industry produces guidance documents to assist plant personnel in determining a plant-specific chemistry control strategy. The early versions of these documents, developed in the 1980s, listed water chemistry specifications and actions to be taken if the limits were exceeded. As more chemistry options became available, the guidelines evolved into providing guidance on selecting the most appropriate chemistry for a specific plant. Thus, the 2008 BWR Water Chemistry Guidelines7 offers recommendations on controlling ECP, zinc injection, and feedwater iron control. Likewise, the 2007 PWR Primary Water Chemistry Guidelines12 provides guidance on pH control and zinc injection, and the 2008 PWR Secondary Water Chemistry Guidelines27 discusses impurity control, amines, and dispersants. Theses documents are used by all US nuclear power plants and provide the technical basis for similar guidelines used in many other countries. Development of a strategic water chemistry plan, as discussed in these documents, is seen as crucial to controlling material degradation in the future.

References 1.

2.

3. 4.

5.

6.

7. 8. 9.

10.

11.

12.

Swan, T.; Wood, C. J. In Developments in Nuclear Power Plant Water Chemistry, VIIIth International Conference on Water Chemistry of Nuclear Reactor Systems, Oct 23–26, 2000; BNES: Bournemouth, UK, 2000. Fruzzetti, K.; Wood, C. J. In Developments in Nuclear Power Plant Water Chemistry. International Conference on Water Chemistry of Nuclear Reactor System, Jeju Island, Korea, Oct 23–26, 2006. Cohen, P. Water Coolant Technology of Power Reactors; Gordon and Breach: New York, 1969. Jones, R. L. In International Water Chemistry Conference, San Francisco, Oct 11–15, 2004; EPRI: Palo Alto, CA, 2004. Garcia, S.; Wood, C. Recent advances in BWR water chemistry. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. Cowan, R.; Hussey, D. Radiation field trends as related to chemistry in United States BWRs. In 2006 International Conference on Water Chemistry of Nuclear Reactor Systems, Jeju Island, Korea, Oct 23–26, 2006. EPRI. Boiling Water Reactor Water Chemistry Guidelines – 2008 Revision; EPRI: Palo Alto, CA, 2008. Edsinger, K. In Nuclear News; Tompkins, B., Ed.; 2008; pp 34–36. Fruzzetti, K.; Perkins, D. PWR chemistry: EPRI perspective on technical issues and industry research. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. Andresen, P.; Ahluwalia, A.; Hickling, J.; Wilson, J. Effects of PWR primary water chemistry on PWSCC of Ni alloys. In 13th International Conference on Environmental Degradation of Materials in Nuclear Power Systems, Whistler, Canada, Aug 19–23, 2007. Andresen, P.; Ahluwalia, A.; Wilson, J.; Hickling, J. Effects of dissolved H2 and Zn on PWSCC of Ni alloys. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. EPRI. Pressurized Water Reactor Primary Water Chemistry Guidelines: Revision 6; EPRI: Palo Alto, CA, 2007.

Water Chemistry Control in LWRs 13. Pathania, R.; Yagnik, S.; Gold, R. E.; Dove, M.; Kolstad, E. Evaluation of zinc addition to PWR primary coolant. In 7th International Symposium on Environmental Degradation of Materials in Nuclear Power Systems, Breckenridge, CO, NACE: Houston, TX, 1995; pp 163–176. 14. Molander, A.; Jenssen, A.; Norring, K.; Ko¨nig, M.; Andersson, P.-O. Comparison of PWSCC initiation and crack growth data for Alloy 600. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. 15. Fruzzetti, K.; Rochester, D.; Wilson, L.; Kreider, M.; Miller, A. Dispersant application for mitigation of steam generator fouling: Final results from the McGuire 2 long-term trial and an industry update and EPRI perspective for long-term use. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. 16. Haas, C.; Ahluwalia, A.; Kucuk, A.; Perkins, D. PWR operation with elevated hydrogen. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. 17. Hussey, D.; Perkins, D.; Choi, S. Benchmarking radioactivity transport and deposition in PWRs. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. 18. Stevens, J.; Bosma, J. Elevated RCS pH program at Comanche peak. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. 19. Nordmann, F. Worldwide chemistry objectives and solutions for NPP. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008.

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25. 26. 27. 28. 29. 30.

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Tigeras, A.; Stellwag, B.; Engler, N.; Bretelle, J.; Rocher, A. Understanding the zinc behavior in PWR primary coolant: A comparison between French and German experience. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. Frattini, P. L.; Blok, J.; Chauffriat, S.; Sawicki, J.; Riddle, J. In VIIIth International Conference on Water Chemistry of Nuclear Reactor Systems, Oct 23–26, 2000; BNES: Bournemouth, UK, 2000. Riess, R. Personal communication, 2008. Byers, W.; Wang, G.; Deshon, J. Limits of zinc addition in high duty PWRs. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. Perkins, D.; Ahluwalia, A.; Deshon, J.; Haas, C. An EPRI perspective and overview of PWR zinc injection. In VGB NPC’08 Water Chemistry Conference, Berlin, Sept 14–18, 2008. Millett, P. J; Hundley, F. Nucl. Energ. 1997; 36, pp 251–258. EPRI. Personal communication from K. Fruzzetti, 2009. EPRI. Pressurized Water Reactor Secondary Water Chemistry Guidelines – Revision 6; EPRI: Palo Alto, CA, 2008. Choi, S. Personal communication, 2009. EPRI. Pressurized Water Reactor Lead Sourcebook; EPRI: Palo Alto, CA, 2006. Chexal, V.; Horowitz, J. Chexal–Horowitz flowaccelerated corrosion model – Parameters and influences. In ASME PVP-Vol B, Current Perspectives of International Pressure Vessels and Piping Codes and Standards, Book No. H0976B, 1995.