WATER CHEMISTRY OPERATION EXPERIENCE AND STEAM GENERATOR MAINTENANCE MEASURES IN PWRs

A. Drexler, S. Weiss, F. Roumiguiere, J. Fandrich AREVA NP GmbH, Erlangen, Germany

Water and steam serve in the water-steam cycle as the energy transport and work media.

These fluids should have no influence, through corrosion processes on the construction materials and their consequences, on the normal service of the plant. In a more detailed form, the main objectives of the steam water cycle chemistry can be stated as follows:

a) The metal release rates of the structural materials shall be minimal. b) The probability of selective and/or localized forms of corrosion shall be minimal. c) The deposition of corrosion products on heat transfer surfaces shall be minimized. d) The formation of aggressive media, particularly local aggressive environments

under deposits, shall be avoided. All these objectives are especially valid for the steam generators, which have to be

considered as the key component of the secondary side from the viewpoint of chemistry. According to these objectives, a strong dependency exists between the selection of the construction materials and design, and the water chemistry.

1 Fundamental aspects on steam generator tube corrosion and development of secondary side chemistry treatments

The boiling at the SGs causes, that all non-volatile compounds which are present in traces in the feed water flow, are concentrated (enriched) in the SG water, achieving concentrations quite higher than those of feed water. At a SG blow down rate of 0.5% of the feed water flow rate, the equilibrium concentration of a non volatile impurity in the bulk SG water is expected to be therefore 200 times the feed water concentration. That means, for the usual concentration of impurities in feed water (in the rule below the limits of detection, i.e. quite below 0.1 µg/kg for most of the non-volatile impurities), the concentrations of these impurities in the SG blowdown are expected to be few µg/kg only, provided that these substances are soluble and therefore homogeneously distributed in the SG bulk water.

Fig. 1: Accumulation of deposits on top of tube sheet with time [2], [3]

Owing to the SG tubing material properties and operation conditions, these expected concentrations in the bulk SG water are far insufficient to cause any corrosion damages. This fact is corroborated by the worldwide SG operation experience, showing that almost no SG tube damage has occurred in the free span area of the tubes, where the tubes are in contact with the bulk water inside the SG [1]. However, since there is a permanent accumulation of deposits on the SG inner surfaces, there is a risk of local enrichment of impurities beneath these deposits, if they are sufficiently thick (see Fig. 1Fig. 1Fig. 1). This might occur at the tube sheet area within the flow steadied zone (sludge pile) and also at heavily encrusted tube-to-tube support device intersections [1], [2].

2 Historical development of secondary side chemistry treatments

In the past two general approaches to water chemistry in steam generators have been used and these have been directed primarily toward minimizing corrosion in heat transfer crevices: Phosphate chemistry treatment and All-Volatile-Treatment (AVT).

Historically, based on fossil fired unit experience, most of the PWR units were using the

Phosphate treatment, since such a treatment is able to buffer contaminants entering the system and concentrating in the SG. The reason for this is that condenser tubes were historically made of copper alloys, for their high thermal conductivity, but were not always tight. In the early 1970’s (under phosphate chemistry treatment) Alloy 600 MA started to suffer from corrosion. It has been considered first, that locally the chemistry was either too alkaline or too acidic respectively inducing stress corrosion cracking (SCC) or wastage of the SG tubing. Several Na/PO4

3--ratios have been successively tried to avoid both type of corrosion but without success. In fact even both environments were able to coexist in different local parts of the SG and it became obvious that it was impossible to avoid corrosion of Alloy 600 MA tubes, whatever the Na/PO4

3- molar ratio that was in the range of 2.0 to 2.6. Most of the PWR with Alloy 600 MA tubing effectively moved to all volatile treatment

(AVT) chemistry. AVT typically involves using ammonia (NH3) to raise pH and hydrazine (N2H4) to minimize oxygen. Due to copper still present in the secondary circuit, the ammoinia concentration was low. But at the time of phosphate treatment, utilities were used to operate with rather high impurity levels, much higher than what they are now, particularly for seawater cooled plants. This has been the cause for the “denting” phenomenon. But the AVT chemistry, without any buffering effect, was unable to neutralize the acidity or alkalinity of cooling water ingresses or other pollutions, when they concentrate in the SGs. This denting phenomenon induced extremely quick and severe degradation, requiring urgent Steam Generator Replacements (SGR) in several PWR units in the USA, particularly high for seawater cooled units.

The obtainable pHT applying the Low-AVT was not high enough to be a countermeasure

to flow accelerated corrosion in main steam lines for example. In various western countries different measures, like boric acid treatment or molar ration control were implemented to improve secondary side chemistry. Also other alkalization agents than ammonia, like morpholine, Ethanol-amine (ETA), 3-Methoxy-propyl-amine (MPA) or Di-methyl-amine (DMA) were used.

The first PWRs in Germany started commercial operation around 1970. In all these

Siemens designed PWRs (with the exception NPP Obrigheim) SG with Alloy 800 NG tubing materials with stainless steel “egg crate” tube supports were used. The secondary side water chemistry history in Siemens designed PWRs is given in Fig. 2Fig. 2Fig. 2. All old Siemens designed PWRs having Alloy 800 NG SG tubes, which went into service in the early 1970s

started with phosphate chemistry in their SGs and low pH AVT ammonia chemistry in their entire secondary side, because of copper tubing in their condensers. Due to high feedwater iron transport under low feedwater pH conditions caused by insufficiently controlled FAC, deposits occurred within the SGs of German PWRs. Under such deposits phosphate compounds were able to concentrate and finally the first wastage corrosion was reported at the end of the 1970s. Therefore, the German Utilities decided to terminate the phosphate treatment and introduced High-AVT treatment having feedwater pH(25°C) values > 9.8.

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Fig. 2: Secondary Side chemistry treatment in Siemens designed PWR (and one PHWR).

3 Balance of Plant and Steam Generator Design and Material

3.1 Steam generator design and materials In western PWRs two types of steam generators are used (a) recirculating steam

generators, RSG and (b) once-through steam generator (OTSG). The most used type is the recirculating SG, designed by Westinghouse and its licensees (e.g. MHI, Framatome), Combustion Engineering (now part of Westinghouse) and Siemens-KWU (now AREVA NP GmbH). The other type is the OTSG designed by Babcock & Wilcox (now part of AREVA NP). Schematic view of a typical RSG designed by Westinghouse (Model D3) together with RSG designed by Combustion Engineering and Siemens-KWU are shown in Fig. 3Fig. 3Fig. 3.

In the beginning Alloy 600 MA was chosen as steam generator tubing material due to its

resistance against chloride induced stress corrosion cracking. German Original Equipment Manufacturer (OEM) Siemens-KWU decided already in 1967 to use modified Alloy 800 nuclear grade (I 800 NG), following by its first application in 1972 [5]. The basis for this decision was the SCC findings of Coriou with Alloy 600 MA [6]. The status regarding the Alloy 800 NG is that all German PWRs and several other PWRs in Switzerland, Spain, Belgium, Netherlands, Brazil and some Heavy Water PWR (HWPWR) plants in Canada South Korea and Argentina and India are using this material for their SGs. In contrast to Siemens the OEMs in France and Japan were licensees of Westinghouse and they strictly followed the US decision regarding the SG tubing material selection. Experience with Alloy 600 MA and the later used Alloy 600 TT in the PWRs identified numerous corrosion

problems. Consequently, a new material Alloy 690 TT was developed by International Nickel. This material was qualified in the lab and starting to use as early as 1985 for many new and replacement SGs. Presently, this material is the favored material for all Westinghouse plants and the plants of previous Westinghouse licensees (MHI and Framatome, now AREVA). The successful operating experience with both currently used materials Alloy 690 TT and Alloy 800 NG is 24 years and 37 years respectively.

Fig. 333: Schematic view of the RSGs designed by Westinghouse (Model D3), CE and Siemens-KWU [4].

3.2 General Design concepts of balance of plant The secondary side of PWR plants is usually designed and built either by architect

Engineers or by utilities itself. Accordingly, the design and the selected materials of the individual systems are in detail plant specific. However, two main concepts can be recognized due to the major differences in the feedwater supply.

The first one has no feedwater deaerator in its design due to cost reduction reasons and

supplies the feedwater during plant start-up operations either from the “Auxiliary FW Tank” (AFT) or from the “Condensate Storage Tank” (CST). This concept is used typically in USA PWRs but also in many other countries like in EdF plants in France. In this concept the oxygen control is performed by hydrazine injection for all operation modes and for plant start-up operations by air tight sealing of the AFT and CST. The second design concept considers the use of feedwater deaerator tank or feedwater tank. This concept has the advantage of supplying the SGs with oxygen free hot feedwater during all operation modes including the start-up operations. All Siemens-KWU designed PWRs and the new EPR™ are using this secondary side concept. Feedwater Deaerators are also used in other PWRs, like all Japanese PWRs, many CANDU plants and several other PWRs in Europe.

The second major difference in the secondary side concept is the use of “condensate

polishing system” (CPS) or “condensate demineralizer system” (CDS). In many plants CDS is considered for the impurity control, e.g. almost in all US PWRs and Japanese PWRs. Recently, in some Japanese PWRs, where High-AVT Chemistry is introduced, CDS is used only during start-up operation, i.e. it is bypassed during power operation. In contrary in European PWRs a condensate polishing systems are not so widely used, e.g. none of the EDF PWRs CDS is considered. Siemens-KWU has designed CDS only in three German PWRs, due to special request of the owner Utility. Based on its own field experience this utility does

not use the CDS during normal power operation any more. All the other Siemens-KWU designed PWRs have no CDS in their secondary side. The reason not using the CDS is the concern that CDS operation affects the SG performance due to reduced feedwater pH resulting in poor corrosion product control as well as the risk of residual impurity and resin release into SGs.

Fig. 444: Schematic design of the secondary side concept of a typical US PWR (left side) and a Siemens designed Konvoi-Type (right side)

In all BoP designs carbon steels are used everywhere as main material except for turbine blades and for condenser tubes, in some cases also for the moisture separator and reheater (MSR) and feedwater heat-exchanger tubes other materials are used. In the past copper bearing materials were used for the tubing of these heat exchangers due to high thermal conductivity of copper. But due to adverse effect of copper on SG corrosion performance and on pH restrictions, as confirmed by field experience, most of the copper materials were already removed or scheduled to be removed in future from the secondary side. The copper tubes of the MSR and heat-exchanger were replaced either by carbon steels or by low chromium alloyed steels or even by stainless steel. The decision for selecting the tubing material was plant specific.

Carbon steels are very susceptible against FAC under high flow and two phase flow conditions. Accordingly it is recommended to use either low chromium alloyed steels or stainless steel especially in the two phase flow areas such as HP-Turbine casting, Cross-under Line, MSR Shell and Tubing, MSR Drain Lines, and Steam Extraction Lines. Unfortunately, in many plants plain carbon steels are used in those areas; and therefore these plants suffer badly under FAC degradation problems having also poor CP control, when they operate with low FW pH chemistry. This results in poor SG performance.

4 Different water chemistry strategies (state of art)

4.1 Basic water chemistry requirements for steam generator performance Field experience with steam generators in the 1970s and 1980s and their root cause

confirmed that the concentrated impurities beneath the corrosion product deposits on the SG tube surfaces together with SG tubing sensitivity is the main reason for the SG tube degradation problems. Accordingly, industry started to develop chemistry strategies to counteract these degradation problems. Many of these strategies were unfortunately not good enough to stop or avoid the SG degradation problems, because they were trying to improve only the chemistry environmental conditions in the SGs without sufficiently considering the necessary improvement in feedwater corrosion product control.

As of today it is clearly understood, that any secondary system water chemistry program

which are be followed shall ensures the steam generator chemistry key conditions: a) The corrosion product transport into the SGs shall be kept as low as possible

b) Sufficiently reducing conditions inside the SGs shall be ensured, i.e. avoidance of oxidizing conditions

c) The transport of impurities into the SGs shall be limited and properly controlled. For minimization of the corrosion product transport into the steam generators a high pH

in the overall system is required. This high pH yields to a deduction of general corrosion and flow accelerated corrosion (FAC), which occurs mainly at the wet steam areas (HP turbine outlet, cross under, moisture separator reheaters (MSR)). The state of knowledge is that to minimize FAC, the pH at the water film in contact with system surfaces at these locations (T ~ 190°C) must be pH(190°C) > 6,4. A conditioning agent must be therefore provided to achieve this goal pH(T). This goal yields to two simple questions:

a) What kind of alkalizing agent do we need to dose? b) How much do we need to dose?

4.2 High-AVT Chemistry treatment The objective of pH increasing was to stop the flow accelerated corrosion (FAC) in two

phase flow steam systems for an improved feedwater corrosion product control. The High-AVT chemistry treatment is using ammonia (NH3) for adjusting the necessary pH. Applying High-AVT chemistry has the great advantage, that only one chemical has to be dosed to ensure on the one hand reducing conditions inside the steam generator and on the other hand to maintain a sufficient high pH value in final feedwater. For both purposes hydrazine (N2H4) is dosed into the main condensate which reacts with oxygen to nitrogen and water (N2H4 + O2

N2 + 2 H2O). For that a hydrazine concentration of approximately 100 µg/kg is necessary. But N2H4 decomposes also thermally into ammonia (N2H4 x N2 + y H2 + z NH3). Depending on plant conditions, the NH3 concentration in feedwater can achieve values of 5 - 10 mg/kg. This corresponds to pH(25°C) = 9.81 – 9.98 in feedwater or pH(190°) = 6.83 – 6.98. That means the hydrazine requirements satisfy simultaneously the need of high pH for general corrosion control. Typical feedwater concentrations are summarized in Table:

Table 1: Typical concentrations in feedwater in PWRs applying H-AVT chemistry treatment

Parameter Value Ammonia [mg/kg] 5 – 15 Hydrazine (µg/kg] 20 – 150 pH (25°C) > 9.8 Specific conductivity [µS/cm] 15 – 35 Nevertheless the final NH3 concentration along the system will depend on the two

factors, i.e. production from hydrazine and elimination by Condenser exhaust (jet) pumps and SG blowdown. A “too efficient” condense r exhaust system may cause the NH3 equilibrium concentrations in the system to be too low. Plants having no blowdown enthalpy recovery (expansion tank) will have higher NH3 losses. In this cases ammonia dosing is required.

Basis for the High-AVT chemistry treatment are the Guidelines R 401 J (2006) of the

VGB (Technische Vereinigung der Großkraftwerkbetreiber e.V., i.e. Technical Association of power plant operators) [8], [9]. Currently the High AVT chemistry treatment is not applied only in Siemens-KWU designed plants or plants with Siemens-KWU or AREVA designed replacement SGs but also in NPP of other original equipment manufacturer in Europe and Asia.

The advantage of this High-AVT chemistry is its simple application. It does not produce

organic acids in the cycle and therefore there is no cation conductivity increase, as some other

chemical treatments do, due to production of organic acids. Therefore the cation conductivity can be easily used as an indicator of impurity concentration in final feedwater. High-AVT is field proven for its efficiency with respect to corrosion product control. By applying High-AVT very low iron concentration values (taken as the key components for corrosion products) in the final feedwater are achievable. By rising the pH(25°C) > 9.8 in final feedwater iron concentration values even below of 1 µg/kg are achievable (Fig. 5Fig. 5Fig. 5).

Fig. 555: Long-Term feedwater iron concentration as a function of pH increase at NPP Gösgen [10] A prerequisite for High-AVT chemistry treatment is the absence of copper materials in

the secondary side. With respect to SG performance, this is actually not a disadvantage. In order to have good SG performance, copper materials do not belong to an adequate secondary side design. However, it is a handicap from the economical stand point of view, because replacement of copper materials from their secondary side is expensive, especially if all heat exchangers are equipped with copper tubing. Nevertheless several plants in Japan and in Spain replaced their components with copper tubing. Another issue is the fact that High-AVT chemistry requires not to using condensate polishing system (CPS) if any in continuous operation. This is due to high ammonia concentrations, which would exhaust the CPS resins in a short operating time, if it remains in service. Nevertheless it is not recommended to use a CPS due to pH decrease and influence on corrosion product control. Finally, there is no need to use CPS in absence of condenser leaks.

High-AVT chemistry has field experience of more than 35 years and has been proven to

be very effective to drastically reduce feedwater iron concentrations. For example, in older Siemens-KWU designed plants, SG tube fouling could be stopped after introducing High-AVT chemistry (Fig. 6Fig. 6Fig. 6). At plants operating from the beginning on High AVT, the SG tube fouling was negligible even after 25 years of operation. Under High-AVT conditions, the feedwater iron transport is so low that the amount of sludge removed by annual tube sheet lancing became to be in the range of 2 – 3 kg per SG.

Similar good field results were also experienced with High-AVT chemistry at other

plants in Europe having Siemens-KWU replacement SGs and/or several plants built by MHI in Japan. PWR Tsuruga-2 was operating during its first 14 cycles under low-pH AVT conditions with a feedwater pH(25°C) between 9.2 and 9.3. During this operating period, a lot of FAC damage was experienced not only in the condensate and in feedwater systems but also in the wet steam systems, which made partial replacement of the CS piping at affected areas

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necessary. In addition to this FAC damage, the plant also has experienced an increased SG tube-fouling rate. In 2005, after replacing all copper bearing materials in the secondary side, Tsuruga-2 introduced High-AVT chemistry in order to stop this FAC problem and to improve the SG performance. In a short time, the High-AVT chemistry was effective to reduce the feedwater Fe concentration to a target value of ~1 μg/kg. The iron transportation into SGs was reduced by factor 5 [12], [13], [14], [15]. In general, the FAC was also effectively counter-acted, except in a few locations, in which severe flow conditions exist locally.

Fig. 666: SG tube fouling measurements at Siemens designed plants [10], [11]

4.3 Alternative Amines Beside the use of ammonia obtained directly by thermal decomposition of hydrazine as

alcalizing agent ammonia other alternative amines are used. In these organic amines one or several atoms of hydrogen are replaced by a hydrocarbon chains. They generally have a better distribution coefficient between the water and steam phase of two flow system and might be provide a better protection against FAC.

In addition to ammonia various amines (morpholine, ETA, MPA, etc) may be used to get

the AVT. Each reagent has its own advantages and inconveniences for protection of a defined material or component of the system and for operation easiness (costs, resins life duration, wastes, etc). The reagent selection depends on many criteria selected by the utility.

The generally considered main advantage of morpholine (C4H8ONH) is its ability to

protect all of the secondary system against FAC, even in presence of copper alloys and at a pH(25°C) of 9.2 [22]. This is why it has been used in most and the French units, i.e. in 50 out of the 58 PWR Units in 2009. Morpholine is also used in about 12 % of the US PWR Units either alone (5%) or with other amines [17]. One most cited advantage of morpholine is its steam-water-distribution coefficient, which is close to 1, which gives an approximately constant concentration throughout the steam/water system. The main disadvantage of morpholine is the relatively high molar concentration that is required for giving the desired feedwater pH, particularly if pH(25°C) > 9.5 is selected. The consequence of the higher molar concentration is that it reduces the lifetimes of the condensate polisher or blowdown resins beds. The second main consequence of this higher molar concentration is an increase of nitrogen in liquid effluents, particularly if the ion exchange resigns are regenerated. The third main consequence of morpholine is an increase in the concentrations of the organic acid anions, acetate and formate, that is observed in some cases.

Ethanolamine (ETA) is an alternate amine, largely used in an increasing number of

countries with PWR units. It is now used in almost 75 % of US PWR units either alone (57%) or with other amine (Fig. 7Fig. 7Fig. 7) where the level of iron in FW is typically lower than 2 μg/kg. This value is even lower in units where deep bed condensate polishers are not permanently in operation, allowing operating the unit at a higher pH [17]. It is applied at PWRs plants in Europe, Korea, Japan and South Africa [18].

Fig. 777: Amine Applications for Secondary pH Control at US Plants [18] ETA was selected, because the laboratory data was promising that pHT values would be

more increased in wet steam areas and also organic acid production would be less when compared to morpholine. The distribution coefficient is less than 1 (150°C < T < 280°C), i.e. ETA stays more in water phase, which will not give a constant concentration in the different parts of the secondary side system. This result in the possibility that the various portions of the system are not exposed to the optimum ETA concentration and therefore less protection may exist in some parts of the secondary system if ETA concentration is adjusted for other parts of the system. However, in the two-phase parts of the secondary system the liquid phase may have a higher ETA concentration.

In addition to morpholine or ETA, other reagents may be used, each of which has its own

advantages and disadvantages. Moreover, some utilities with PWR made the interesting approach of using a mixing of amines with each one its own purpose, such as protecting different part of the secondary side circuit against FAC or more efficiently reducing the corrosion products transport and deposition. The main considered amines are DMA (Dimethylamine) and MPA (methyl-propanolamine). The only disadvantage of such a mixing of amines is the higher complexity of reagents injection, regulation and monitoring. MPA is used in about 25 % of US PWR Units either alone (15%) or with other amines [17].

5 Steam Generator Health Assessment

As already stated high steam generator performance is a prerequisite for high plant availability and for possible life time extension. The major opponent to that is corrosion and fouling of the heating tubes. The most effective ways of counteracting all degradation problems and thus of improving the steam generator performance is to keep them in clean conditions or if necessary to plan cleaning measures such as mechanical tube sheet lancing or chemical cleaning. A methodology how to assess the cleanliness condition of a steam

generator by evaluating all available operational and inspection data together, such as thermal performance and water chemistry data is the AREVA NP Fouling Index. The fouling index enables monitoring the condition of a specific steam generator, to compare it with other plants and, finally, to serve as criterion for cleaning measures such as chemical cleaning. In order to gain a complete picture of each SG’s cleanliness condition in a plant or its evolution, all suitable plant operational and SG inspection data should be evaluated together. These data serve as “fouling indicators”, which may be categorized as follows:

(a) Water Chemistry Data

• Corrosion product mass balance • Hydrazine thermal decomposition • Impurity ingress (Sulphate, Chloride and other salts / Out of specification

conditions, e.g. condenser leaks) • Calculation of local conditions (Hide-out and Hide-out Return)

(b) Inspection Results

• Visual inspections • Tube sheet lancing results • Tube scale thickness measurements

(c) Steam generator heat transfer calculation

• Design Data (heating surface, number of plugged tubes etc.) • Process parameter (mass flow rates, temperature, pressure)

Fig. 888: Principle of AREVA NP Fouling Index. In the next step of the cleanliness evaluation weighting factors are applied in order to

normalize the fouling indicator parameters and make them comparable among each other [19]. Based on field experience, heat transfer performance and water chemistry data have been found to be the most important parameter category. As per definition, the sum of all weighting factors is 100%. Within each category the individual indicator parameters are separately weighted. From the sum of the weighted individual indicator parameters an overall fouling index of the SG can be calculated which can, as per the above definitions, have values between 0 and 100, where 0 stands for “clean” and 100 stands for “fouled”.

The overall fouling index can be used as a basic indicator to decide whether counter

measures are necessary or not. Three zones are defined, which are indicated with different colors in the soft ware:

• “Green” zone (Index 0 to 50): No cleaning actions have to be foreseen. • “Orange” zone (Index 50 to 80): An optimization of the chemistry program shall

be considered (corrosion product control, oxygen control etc.) and cleaning measures shall be planned in a long term.

• “Red” zone (Index 80 to 100): cleaning actions have to be initiated as soon as possible. Possible cleaning actions are mechanical tube sheet lancing with high pressure water jets or chemical cleaning of the whole tube bundle.

Of course, the overall index is not a strict number for the measures. The final decision

will also be based on localized problems (e.g. tube denting in the vicinity of the tube support plate) as well as on the individual fouling indicators which were evaluated in the course of the expertise.

6 Steam Generator Chemical Cleaning

There are several commercially available steam generator secondary side chemical cleaning methods available on the market from different suppliers. Generally speaking complexing agents (i.e. for example ethylenediamine tetraacetic acid – EDTA) are applied, whereas the processes differ for example in application duration, waste removal capacity, equipment and plant system integration requirements.

Goals of a chemical SG cleaning are to mitigate localized problems as well as general SG

fouling. Localized problems could be deposit blocked tube support structures (as observed in several EDF NPP´s prior to a HTCC [21]) or tube denting phenomena in the vicinity of the tube support plate. Whereas a decreasing thermal transfer rate would be an issue of general SG fouling. In comparison to other widely applied partial cleaning methods like tube sheet sludge lancing, inner bundle lancing or upper tube bundle flushing, which are localized remedies a chemical SG cleaning is an efficient full volume remedy.

6.1 AREVA´s SG chemical cleaning processes AREVA NP GmbH is providing several chemical cleaning methods, which are selected,

based on SG situation and customised to the plant specific requirements. The needs and conditions in terms of SG cleaning and maintenance are unique for every plant. In order to adapt to such different needs AREVA NP developed the C³ strategy (Customized Chemical Cleaning). In the following paragraphs basic principles of AREVA´s chemical cleaning processes are summarized.

6.1.1 AREVA´s High Temperature Chemical Cleaning (HTCC)

This process is a high temperature process, using the primary side as heat source. Depending on the plant design characteristics and restrictions HTCC can be applied during the shut down phase of the plant, thus having a minimum impact on the critical path. Since chemical reactions rates are enhanced by higher temperatures the overall duration of the magnetite dissolution step is the lowest of all chemical cleaning processes, being in the range of some 10´s of hours per SG. Furthermore the ratio of magnetite deposits dissolution to carbon steel dissolution is shifted towards deposit dissolution at process temperature around

160 °C. Therefore the addition of an inhibitor, which is in most cases containing sulphur (e.g. CCI 801) is not required. Thus preventing the ingress of impurities into the SG, which are detrimental with regards to localised corrosion issues.

The process comprises of several injections of the applied chelating chemicals, followed

by filling the SG to pre-calculated levels (e.g. above certain TSP or TSG) with demineralized water. Mixing and enhanced solvent agitation is realized by venting (i.e. controlled opening of the SG pressure relieve valves) and simultaneous inert gas injection. By this injection strategy an optimum chemistry concentration is ensured to obtain the maximum magnetite dissolution, while keeping the carbon steel corrosion at a minimum. The process can be followed and controlled by measuring the amount of unsaturated chelating agent and by measuring the ratio of nitrogen to hydrogen in the off gas, which is a measure for carbon steel dissolution. An additional control parameter is the amount of reducing agent. If required an additional injection of the reducing agent is performed, thus ensuring reducing conditions during the whole process. After draining the SGs the process can be followed by a copper removal process and usually is followed by a tube sheet lancing to remove loose remaining particles.

Fig. 999: AREVA NP GmbH HTCC process

In the following some published operational field experience with AREVA´s HTCC is

summarised: The process, which is the most often one applied, has proven its capability of removing deposits fast and effective in more than 62 applications in more than 250 SGs worldwide from all vendors (e.g. KWU, W/C, B&W, FRA, CE, W, and VVER). During the recent cleaning activities in France in 2007/08 huge amounts of deposits have been removed by the AREVA NP GmbH HTCC process, ranging form 2950 kg to 3450 kg of removed deposits per SG. [21] After the cleaning operations a visual inspection has been performed on the bottom part of the SG, proving that the tubing, tube sheet, flow distribution baffle and tube support plates were satisfactorily clean and no deposits could be seen in the tube to TSP crevices (Fig. 10Fig. 10Fig. 10). [21]

Long term experience showed also that a chemical cleaning can improve the corrosion

situation in SGs. Based on sodium ingress ODSCC was observed in one plant, leading to 371 plugged tubes [23]. By removal of accumulated impurities (i.e. detrimental ions) in deposits during HTCC the progress of the corrosion phenomena could be stopped. The number of tubes, which had to be plugged in the cycles following the HTCC, was reduced during the outages after the cleaning (47 in the 1st, 2 in the 2nd and 0 in the 3rd outage after the HTCC). Thus field experience showed that HTCC can improve SG corrosion situation, but also

showed that, once the corrosion process has made considerable progress cleaning processes can not remove the impurities from the deep cracks. Hence it is recommended not to delay the cleanings once the corrosion process has started. [20]

Fig. 101010: TSP 1 before HTCC (left picture) and after HTCC (right picture) [21]

In addition to the local benefits (i.e. deposit removal from TTS and in the vicinity of the tube support structure) a significant decrease in fouling factor and in almost all SGs an increase in main steam pressure (up to 1.8 bar) was observed. [22]

Figure 1113: Main steam pressure recovery after a HTCC process

6.1.2 AREVA´s Deposit Accumulation Reduction Technology (DART HT)

DART HT is a maintenance cleaning process, to dissolve a part of the magnetite inventory, usually applied to remove up to 1200 kg magnetite per SG. This process is mainly used as maintenance cleaning method for older SG´s to reduce their magnetite deposit load. The process is based on the well known HTCC process, applied also at temperatures of around 160°C. Its effectiveness to clean the tube support structure (i.e. blocked broach holes) as well as hard sludge from the tube sheet is similar to the HTCC process. The main difference between those two processes is the concentration of the chemicals, whereas the DART HT is performed at an under-stoichiometric ratio of complexing agent and expected

magnetite. Corrosion of carbon steel is prevented by a stringent control of free complexing agents, hence no process control is required.

6.1.3 AREVA´s Deposit Accumulation Reduction Technology (DART LT)

This soft cleaning process is a low temperature version of the above mentioned DART HT process, applied at a temperature range of 80-120°C. To control carbon steel corrosion an AREVA proprietary sulphur free inhibitor is to be applied. The applied inhibitor has the advantage of being sulphur-free hence preventing the ingress of detrimental impurities into the plant system.

6.1.4 AREVA´s Deposit Minimization Treatment (DMT)

This process is designed as a maintenance cleaning method with a negligible corrosion of carbon steel to be applied on a regular basis, maintaining the SG´s in clean conditions. The design base is to remove up to 500 kg of magnetite per SG´s (including subsequent sludge lancing).

The process can be applied with a minimum impact and requirement of plant systems,

since the chemicals are injected already mixed to the appropriate concentration and preheated to the reaction temperature by supplier equipment and tools. The process is based on oxalic acid as chelating agent building a soluble ferric iron oxalate complex. Innocuousness with regards to SG base material is ensured by the self-inhibiting characteristic of the applied cleaning solution. An insoluble ferrous oxalate complex is formed directly on the surface of the carbon steel, generating a tightly adhering film. This film acts as a protective film on the carbon steel surfaces thus limiting the general corrosion of carbon steel.

After draining the DMT dissolution solvent a conversion step is performed. The

conversion solvent turns very low soluble ferrous oxalate in a highly soluble ferric oxalate complex which will be removed by draining of the conversion solvent. Simultaneously a protective iron oxide layer (e.g. Fe2O3) is formed on carbon steel surfaces. All liquid waste components can be easily decomposed thermally or electrochemically, thus allowing a significant waste reduction. The DMT process has been applied successfully in the US and is currently under qualification for the French NPP fleet, where the applications are scheduled to start in beginning of 2011.

6.2 Other chemical cleaning processes

6.2.1 EDF process

EDF has developed and patented its own SG chemical cleaning process in the 1980s. This process is designed to use a single cleaning solvent to dissolve iron oxides and copper. A combination of gluconic and citric acid is used for the iron removal step. A sulfur containing inhibitor, P6 from Multiserve, is used for the control of the carbon steel corrosion. Ammonia is also used to adjust the pH of 3.3 at ambient temperature of 25 °C (77 °F). The process application temperature is 85°C (185°F) and during the application a nitrogen blanket is used in the SGs to exclude oxygen.

It was found that 170 hours of iron solvent application is sufficient for the effectively

cleaning of the entire tube bundle and of the TS. However, it was also confirmed that tube to drilled Hole TSP crevices could not be cleaned at all. [22]

6.2.2 EPRI SGOG

This process is applied worldwide by different vendors (e.g. AREVA or Westinghouse) on a licensing base. Main intention during the development of the process was the reduction of corrosion products in the crevices of drilled hole TSP to mitigate denting effects. The EPRI SGOG solvent system for a full scale chemical cleaning consists of three EDTA based cleaning solvents, i.e. a magnetite solvent, a copper solvent and a crevice solvent. The process generally ends with a passivation step. Prior to the application, between the process steps and after the end of the process several rinsings (full volume and partial volume rinsings) are required, resulting in an according amount of liquid waste.

The process duration is normally in the range of several days, depending on the actual SG

situation and the actual required numbers of applications steps. Hence usually external heaters and recirculation equipment is used. To mitigate carbon steel corrosion caused by the long contact time of active chemicals with SG internals the sulfur-containing inhibitor CCI 801 is applied, thus requiring a thorough rinsing to remove detrimental inhibitor residuals. The inhibitor ensures low general carbon steel corrosion, where the surfaces are inhibitor wetted. [22]

7 References

[1] R. Staehle, J. Gorman; “Progress in understanding and mitigating corrosion on the secondary side in PWR steam generators”; 10th Intern. Conference on Environmental degradation of materials in nuclear power systems- water reactors, Aug. 5-9, 2001, Lake Tahoe, Nevada, USA.

[2] S. Odar, A. Dörr, P. Schub; ”Stages of developement of secondary water chemistry in pressurized water reactors”; VGB Kraftwerkstechnik 66, Nr. 11; November, 1986

[3] S. Odar, R. Bouecke, B. Stellwag; ”Experience with KWU steam generator tubing corrosion phenomena and their prevention”; 2nd International Topical Meeting on Nuclear Power Plant Thermal Hydraulics and Operation; April 1986, Tokyo, Japan

[4] R. Riess, J. Kysela, S. Odar, P. Ford, P. Combrade, P. M. Scott, LCC5 Annual Report, Advanced Nuclear Technology International, Krongjutarvägen 2C, SE-730 50 Skultuna, Sweden, November 2009

[5] W. Debray, L. Stieding; “Materials in the primary circuit of water cooled power Reactors”, Paper No 3, International Nickel Power Conference, Lausanne, Switzerland, 1972.

[6] H. Coriou et al. ; “Corrosion sous contrainte de l’Inconel dans l’eau à haute temperature”, 3° Colloque de Métallurgie sur la Corrosion, page 161-169, CEN Saclay, France et North Holland Publishing Amsterdam, 1959

[7] S. Odar, Water Chemistry Measures to Improve Steam Generator performance, Proc. Of the 14th Int. Conf. on the properties of Water and Steam, Kyoto, Sept. 2004, p.531.

[8] VGB PowerTech, “Richtlinie für das Wasser in Kernkraftwerken mit Leichtwasserreaktoren”, R 401 J, 2006

[9] H. Neder, M. Jürgensen, D. Wolter, U. Staudt, S. Odar, V. Schneider; “VGB Primary and Secondary Side Water Chemistry Guidelinesfor PWR Plants”; International conference on water chemistry of nuclear reactor systems, Jeju Island Korea, October 23 – 26, 2006

[10] S. Odar, “Water Chemistry Measures to Improve Steam Generator Performance” Symposium on Water Chemistry and Corrosion of Nuclear Power Plants in Asia Gyeongju, Korea, October 11 – 13, 2005

[11] U. Staudt, S. Odar and A. Stutzmann, “Comparison of French and German Chemistry Programs”, International Conference on Water Chemistry in Nuclear Reactor Systems – SFEN (French Nuclear Energy Society), Avignon, France, April 22 – 26, 2002.

[12] H. Takiguchi, “Study on Application of Oxygenated Water Chemistry for Suppression of Flow Assisted Corrosion in Secondary System of PWRs”, 14th International Conference on the Properties of Water and Steam Water, Kyoto, Japan, August 29 – Septemper 3, 2004

[13] E. Kadoi, W. Sugino, T. Takahashi, M. Furukawa and H. Takiguchi, “First trial of High-AVT chemistry for PWR secondary water chemistry in Japan”, Proceedings of Symposium on Water Chemistry and Corrosion in Nuclear Power Plants in Asia, Fukuoka, Japan, 2003.

[14] E. Kadoi, H. Takiguchi and K. Otoha, “Optimization of secondary water chemistry in JAPC PWR”, Proceeding of International Conference on Water Chemistry of Nuclear Reactor Systems, San Francisco, US, 2004.

[15] E. Kadoi, T. Ohira, W. Sugino and K. Otoha, “The experience of High-AVT in Tsuruga-2”, Proceedings of Symposium on Water Chemistry and Corrosion in Nuclear Power Plants in Asia, Gyeongju, Korea, 2005.

[16] H. Neder, M. Bolz, H.-R. Sauer, G. Holz, U. Staudt, S. Odar and V. Schneider “Water Chemistry Guidelines and Practices in Siemens Designed PWRs - A Comparison with Other PWRs”, NPC ’08, Berlin, September 14 – 18, 2008

[17] S. Choi and J. Lumsden, “Investigation of Lead Equilibrium Lines on Pourbaix Diagram Using Electrochemical Measurements at 280°C”, NPC’08 International Conference on Water Chemistry of Nuclear Reactor Systems, Berlin, September 14 – 18, 2008.

[18] K. J. Galt and N. B. Caris, “Ethanolamine experience at Koeberg Nuclear Power Station, South Africa”, International Conference on Water Chemistry in Nuclear Reactors systems, SFEN, Avignon, France, April 2002.

[19] S. Odar, V. Schneider, T. Schwarz, R. Bouecke; “Cleanliness Criteria to Improve Steam Generator Performance”; International conference on water chemistry of nuclear reactor systems, Jeju Island Korea, October 23 – 26, 2006

[20] S. Odar, Twenty years of experience gained with Framatome-ANP high temperature steam generator chemical cleaning process, Symposium on water chemistry and corrosion of nuclear power plants in asia, Gyeonju, Korea, 2005

[21] M. Dijoux et al., Application of AREVA inhibitor free high temperature chemical cleaning process against blockages on SG support plates, Internations conference on water chemistry of nuclear reactor systems, Berlin, Germany, 2008

[22] ANT International, LCC5 Special topic report – decontamination and steam generator chemical cleaning, 2009

[23] EPRI Steam generator progress report, Rev. 15, 2000