P R E P R I N T – ICPWS XV
Berlin, September 8–11, 2008
Steam Turbine Chemistry in Light Water Reactor Plants
Robert Svoboda a and Klaus Haertel b
a
b
Svoboda Consulting, Wettingen, Switzerland
Westinghouse Electric Germany GmbH, Baden, Switzerland
Email: [email protected]
Steam turbines in BWR and PWR power plants of various manufacturers have been affected by corrosion
fatigue and stress corrosion cracking. Steam chemistry was not a prime focus for related research because the
water in nuclear steam generating systems is considered to be of high purity. Steam turbine chemistry however
follows more the problems encountered in fossil fired power plants on All Volatile Treatment, where corrosive
environments can be formed in zones where wet steam is re-evaporated and dries out, or in the Phase
Transition Zone where superheated steam starts to condense in the LP turbine. In BWR plants the situation is
aggravated by the fact that no alkalizing agents are used in the cycle, thus making any anionic impurity
immediately acidic. This is illustrated by case studies of pitting corrosion of a 12% Cr gland seal, and of flow
oriented corrosion attack on LP turbine blades in the Phase Transition Zone. In PWR plants, volatile alkalizing
agents are used that provide some buffering of acidic impurities, but on the other hand also produce anionic
decomposition products.
It is recommended that such corrosion issues be addressed in future cycle chemistry guidelines for nuclear
power plants. The present international guidelines should be amended by information and guidance for
preventive actions against a possible hostile chemical environment in steam turbines.
Introduction
Steam turbines of various manufacturers have
been affected by corrosion fatigue and stress
corrosion cracking. Nuclear power plants were
affected as well as fossil fired power plants. These
corrosion phenomena are the result of a
combination of material properties, stresses and
chemical environment. Much research has been
done on the materials and stress side, as well as on
the chemistry side of fossil fired power plants [1].
Considering the costly consequences, there is
however surprisingly little information published in
the last 25 years on steam chemistry in nuclear
power plants.
In contrast to fossil plant cycle chemistry
specifications, current international cycle chemistry
specifications for nuclear power plants do not
explicitly cover steam purity:
The EPRI BWR specifications [2] do not
mention steam chemistry at all, and the EPRI PWR
specifications cover turbine chemistry in a broader,
not quantified manner, asserting that, even though
damage has occurred mainly in the chemistrysensitive phase transition zone of the LP turbines,
no correlation has yet been found between PWR
chemistry and turbine damage [3].
The VGB cycle chemistry specifications for
nuclear power plants specify values for steam
conductivity, but only as diagnostic parameters [4].
This paper is intended to give some theoretical
background as well as illustrating practical
experiences on steam chemistry in boiling water
reactor plants (BWR) and pressurized water reactor
plants (PWR) with recirculating steam generators.
Boiling Water Reactor Plants
Steam is generated directly in the nuclear
reactor. The wet steam is dried in a water separator
inside the reactor to saturated steam with very low
remaining moisture content. This saturated steam is
fed into the HP turbine. At HP turbine exhaust the
steam has obtained a high degree of moisture and
this is removed in a moisture separator, usually
combined with a reheater. This reheat steam is then
fed into the LP turbines, and subsequently
condensed in the condenser, Figure 1.
Typical steam parameters are:
- HP turbine inlet: 66 bar/280°C, <0.1% moisture
- HP turbine exhaust: 5 bar /150°C, 16% moisture
- LP turbine inlet: 5 bar /250°C superheated
- LP turbine exhaust: 0.05 bar/33°C, 10%
moisture
Figure 2 represents these key points in the Mollier
diagram.
3000
LP
HP
RH
MS
f
300
250
°C
2900
Enthalpy (kJ/kg)
R
BWR plant
200
c
2800
150
e
2700
2600
100
50
50
2500
C
20
2400
Figure 1: Schematic diagram of BWR and PWR
steam flow.
R
Reactor (Steam Generator)
HP
High Pressure Turbine
MS Moisture Separator
RH Reheater
LP
Low Pressure Turbine
C
Turbine Condenser
5.5
10
5
d
2
1
0.5
6.5
Entropy (kJ/kg/K)
0.2
0.1
0.05
bar
g
7.5
8.5
Figure 2: Typical BWR steam path in the Mollier
diagram, simplified schematic.
1 HP turbine inlet
2 HP turbine exhaust
3 Moisture separator outlet /Reheater inlet
4 LP turbine inlet
5 LP turbine exhaust /condenser inlet
As the BWR steam generator is identical with
the nuclear reactor, the aim is to operate the system
with a feedwater as pure as possible. This not only
comprises design and equipment features, but also
monitoring and operating efforts. This raises the
question why steam purity could be a problem in
BWR circuits.
The moisture separator typically removes 95%
of the HP turbine exhaust moisture; in other words,
5% of the impurities contained in the water phase
of LP exhaust steam pass through this device.
BWR cycle chemistry.
BWR cycle chemistry is characterized by the
use of neutral feedwater and reactor water, without
any alkalizing agents. Only for reactor water
treatment some metal additives are used. They will
not be discussed here, as there is no evidence
available on any direct relationship to steam turbine
chemistry.
One particular feature of BWRs is the
production of radiolytic gas in the reactor, which
vents off together with the steam. With traditional
BWR chemistry, the oxygen concentration in steam
is up to 20 mg/kg. Calculation of equilibrium
concentrations in the water phase of wet steam give
120 μg/kg at HP turbine inlet, 1 μg/kg at HP turbine
exhaust (and in the moisture separator), and 0.1
μg/kg in the water film at early condensation.
Measurements in the moisture separator drain
confirmed this value. With hydrogen water
chemistry, the oxygen level in the reactor and
therefore also in the steam will be lower.
Even though the oxygen concentration in the
water phase of the LP turbine is very low, it is
nevertheless not yet a reducing environment. In
fossil cycle chemistry AVT(o) (oxidizing All
Volatile Treatment) is considered as being
oxidizing even though no oxygen is added to the
system [5]. It is the resulting Oxidizing-Reducing
Potential (ORP) that counts, and this is also a prime
parameter for corrosion phenomena.
Carry-over of impurities.
The carry-over of impurities from reactor water
into steam can result from mechanical carry-over as
well as from vaporous carry-over (volatility) [6].
Mechanical carry-over of BWR is low, as the
steam moisture of typically <0.1% at reactor outlet
indicates. This is a mechanism relevant for the
possible contamination of the turbine by nonvolatile radioactive species, like Co-60, into the
steam turbine. With regard to corrosion, mechanical
carry-over is not considered to be of significance.
Vaporous carry-over (volatility) however is an
important mechanism for impurity transport from
the reactor water into the steam.
The volatility of a substance depends on its
speciation. HCl for example is a volatile gas, while
its dissociation product Cl- is a non-volatile ion that
attaches to water. The volatility of HCl hence
depends on its degree of dissociation, itself
depending on temperature, the presence of other
ions and other parameters. At 280°C, pure HCl is
highly volatile, Figure 3.
As a consequence, if traces of HCl enter the
reactor and do not meet free cations, the HCl will
not stay in the reactor water but fully partition into
the steam. That means there is the possibility of
having HCl in the steam without it being seen in the
2
Passing the moisture separator, the -now
superheated- steam will due to the distribution
coefficient still have 1 μg/kg of HCl.
Along the expansion in the LP turbine the steam
starts to condense. It is known that in the zone of
early condensation (Phase Transition Zone) the
water film can bear high concentrations of
impurities [1][7][8]. The distribution coefficient of
HCl now being smaller than 1, it will preferentially
partition into the water phase and cause an acidic
environment. This is aggravated by the fact that no
volatile alkalizing agents are used in BWR plants,
and the HCl now can produce an acidic
environment.
It is evident that such impurity transport is
sensitive to the actual speciation of the impurity. If
HCl meets free Na+ cations in the reactor water, the
volatility of HCl is lower, Figure 3. Clconcentration in steam will be, as explained above,
unaffected . However, due to its lower volatility, a
larger fraction of Cl-, together with Na+ will be
drained off in the moisture separator. Due to its
95% water removal efficiency, at least 5% of the
Cl- of HP turbine exhaust will then pass to the LP
turbine, and all of this Cl- will be in the early
condensate. The cation, if still together with the Cl-,
will also influence pH.
Figure 3: Partitioning constants of electrolytes and
dependence on temperature [5].
reactor water. Its concentration in steam will be the
same as in feedwater.
If there are free cations in the reactor water, HCl
will dissociate and therefore be considerably less
volatile, Figure 3. In this case Cl- will be seen in the
reactor water. Because the reactor water clean-up
has a low flow rate relative to steam, its Cl- removal
rate will be small compared to removal by steam,
determined by steam flow rate and volatility.
Therefore the Cl- concentration in steam may
nevertheless be about the same as in feedwater [7].
Similar considerations apply to other substances,
like H2SO4 and sulphates, as well as for silica. Their
volatility however is lower than for HCl.
Example: corrosion at dry-out of wet steam.
BWR live steam, having passed pressure
reduction, was used for the HP turbine gland seals.
Along its path it was expanded adiabatically down
to atmospheric pressure. Figure 4 visualizes this
expansion in the Mollier diagram. It is seen that at a
certain point the wet steam passes the saturation
line and dries out.
Pitting corrosion, of 0.5 - 1mm in width and in
depth, was observed exactly at the calculated point
of dry-out, Figure 5, accompanied by white
deposits of mainly Silica and with traces of
Chloride. It is probable that these deposits caused
pitting corrosion during shutdown periods. But it is
also possible that acidic impurities attained high
concentrations in the last water film before dry-out,
and together with the oxidizing ORP caused the
pitting corrosion.
Before this incident, reactor water conductivity
generally was 0.10 μS/cm and Cl- 1 μg/kg. Due to a
small cooling water inleakage, conductivity was up
to 0.1 to 0.2 μS/cm and Cl- up to 10 μg/kg for a
period of 4 months.
The same mechanism could lead to a corrosive
environment at turbine blade roots in the wet steam
region. Water films on turbine blades are affected
Distribution of impurities along the steam path.
Staying with the example of HCl: its volatility
decreases with decreasing pressure, Figure 3. At
temperatures below 150°C, its distribution
coefficient becomes smaller than 1, meaning that in
two-phase steam the concentration in the water
phase becomes larger than in the vapour phase.
If, for example, 1 μg/kg of HCl comes along
with the reactor steam, it will be in the vapour
phase and due to its volatility not in the water phase.
The water film in the HP turbine will therefore have
a negligible concentration at HP turbine inlet, and
taking a distribution coefficient of 1 at HP turbine
exhaust, there will here also be 1 μg/kg of HCl in
the water phase, if the effect of moisture that has
been drained off in the HP turbine is neglected.
3
3000
BWR plant
300
250
°C
Enthalpy (kJ/kg)
2900
200
2800
150
2700
100
2600
HP turbine
gland seal
50
50
2500
20
10
5
2
1
0.5
0.2
0.1
0.05
bar
2400
5.5
6.5
Entropy (kJ/kg/K)
7.5
8.5
Figure 4: Expansion of gland seal steam. Slightly
moist high-pressure steam is expanded down to
atmospheric pressure over a regulating valve and the
HP gland seal. During expansion the steam moisture
decreases and dries out, incidentally, in the gland seal.
The fully expanded steam then is superheated.
Corrosion took place in the dry-out zone.
Figure 5: Pitting corrosion in the gland seal
of a HP turbine in a BWR plant. Material:
12% Cr steel. The pits have 0.5 - 1 mm width
and depth.
by centrifugal forces that move the water towards
the blade tip. This is seen by water-streaking
patterns on turbine blades [9] and also by the
effectiveness of turbine drains between the
stationary blades. This way, steam near the blade
roots will have lower moisture than the average at
this turbine stage. When such low-moisture steam
expands adiabatically by leaking through a blade
root, it may dry out and cause high local impurity
concentration. Similar considerations can be made
for keyways, if there are any.
Example: corrosion at LP turbine blades.
In another BWR plant, cracks were observed on
12% Cr steel LP turbine blades at the Phase
Transition Zone, Figure 6. The cracks were related
to small corrosion pits.
Such corrosion pits usually are result of
corrosive hygroscopic salt deposits acting under
moist atmospheric shutdown conditions. Visual
inspection of the affected blade confirmed that the
pits were all in a dry area near the trailing edge on
the suction side of the blade [9][10].
The failure investigation also indicated that at
3000
BWR plant
300
250
°C
Enthalpy (kJ/kg)
2900
200
2800
150
Phase Transition
Zone
2700
100
2600
50
50
2500
20
10
5
2
1
0.5
0.2
0.1
0.05
bar
2400
5.5
6.5
Entropy (kJ/kg/K)
7.5
8.5
Figure 6: Phase Transition Zone. The expansion of
steam in the LP turbine approached the saturation line,
and condensation of water phase commences. Nonvolatile impurities will partition into this water phase.
Because the fraction of water phase in steam is still low
at this point, the concentration of these impurities will be
high. Corrosion took place in this zone.
Figure 7: Flow-oriented corrosion at a LP
turbine blade at the Phase Transition Zone in a
BWR plant. Material: 12% Cr steel. The width of
the picture is ca. 10mm; the corrosion attack is up
to 0.5 mm deep.
4
the wet pressure side of the blade a distinct floworiented corrosion took place, Figure 7. The attack
was up to 0.5 mm deep, and had the distinct pattern
of the streaks formed by the water film [9]. Water
droplet erosion can be ruled out because of the
smooth appearance of the affected areas, and the
low steam moisture.
With very low steam moisture, and under
neutral or alkaline moisture conditions, Flow
Accelerated Corrosion does not affect 12% Cr steel
blades.
This flow-oriented corrosion attack is an
indicator that the blade was subjected to a locally
acidic environment.
There were no reports on abnormal reactor
water chemistry for this plant. Its basic cycle
chemistry features however are special. The plant
has a surface condenser tubed with titanium, and
cooled by brackish water. Condensate polishing is
done at a temperature of 65°C by powdered resin
precoat filters.
One possible explanation of the blade corrosion
could then be as follows: It is known that titanium
tubes had at their introduction suffered pinhole
leaks by steam droplet erosion [11]. If sufficiently
small, such pinhole leaks go undetected. Passing
the powdered resin filters, Chloride has a weaker
retention than Sodium. Thus, trace amounts of
hydrochloric acid are produced, that partition into
the steam and concentrate in the Phase Transition
Zone of the LP turbine. An acidic water film is
created on the turbine blades. The local dissolution
rate of the blade surface will follow the flow pattern
of the water film.
3000
PWR plant
300
Enthalpy (kJ/kg)
250
f
2900
°C
200
c
2800
150
e
2700
2600
100
50
50
2500
20
10
2400
5.5
5
2
d
1
0.5
6.5
Entropy (kJ/kg/K)
0.1
0.2
7.5
0.05
bar
g
8.5
Figure 8: Typical PWR steam path in the Mollier
diagram, simplified schematic.
1 HP turbine inlet
2 HP turbine exhaust
3 Moisture separator outlet /Reheater inlet
4 LP turbine inlet
5 LP turbine exhaust /condenser inlet
question again why steam purity could be a
problem in PWR circuits.
PWR steam turbine chemistry.
Much that has been said for BWR also applies
analogous to PWR plants. The important difference
is that the alkalizing agent provides some protection
against acidic environments, and corrosion effects
by acidic impurities may thus be more easily
prevented.
On the other hand, boric acid treatment of the
steam generator water (boric acid is very volatile),
and the use of amines that decompose to organic
acids have added another dimension to steam
turbine chemistry.
An analysis of boric acid and morpholine
treatment has shown that the net effect on local pH
in the steam turbine is better alkalisation and not
acidification [12]. There remains however the
question if such organic decomposition products
may have selective corrosive properties other than
just its plain influence on pH [13].
Pressurized Water Reactor Plants
Steam is generated in the steam generators, which
separate the nuclear reactor from the steam/water
cycle. The steam arrangement is quite similar to
BWR systems; steam conditions are slightly lower,
Figure 8.
Conclusions
PWR cycle chemistry.
PWR cycle chemistry is characterized by the
use of volatile alkalizing agents for feedwater,
usually in combination with a reducing agent like
hydrazine.
There is not any more oxygen in the steam, and
the ORP throughout the system is distinctly
reducing.
As the steam generators are tubed with sensitive
materials, it is the aim to operate the system with as
pure a feedwater as possible. This raises the
Water in the steam generating system of BWR
and PWR plants is of high purity. Steam turbine
chemistry however follows more the problems
encountered in fossil fired power plants on All
Volatile Treatment, where corrosive environments
can be formed at places where moisture evaporates
or superheat steam starts to condense.
This is aggravated in BWR plants by the fact
that no alkalizing agents are used in the cycle, thus
making any anionic impurity acidic.
5
View. Power Plant Chemistry 8 (2006) 8, pg
502-509
[13] J.Denk, R.Svoboda :Stress Corrosion Cracking
Due to Carbon Dioxide and Organic
Impurities in the Steam / Water Cycle. Power
Plant Chemistry 8 (2006) 7, pg 401-408
It is recommended that such corrosion issues be
addressed in future cycle chemistry guidelines for
nuclear power plants. The present international
guidelines should be amended by information and
guidance for preventive actions against a possible
hostile chemical environment in steam turbines.
References
[1] Steam, Chemistry and Corrosion in the Phase
Transition Zone of Steam Turbines. EPRI
report 108184 V1, 1999
[2] BWR Water Chemistry Guidelines - Revision
2004. EPRI report 1008192, October 2004
[3] PWR Secondary Water Chemistry Guidelines
- Revision 6. EPRI report 1008224, 2004
[4] VGB Guidelines for the Water in Nuclear
Power Plants with Light Water Reactor.
VGB R 401 J, Rev. 2006
[5] Cycle Chemsitry Guidelines for Fossil Plants:
All Volatile Treatment, EPRI report, 1004187,
November 2002
[6] Procedures for the Measurement of Carryover
of Boiler Water into Steam. IAPWS Guidance
document (in preparation)
H.Sandmann,
S.Romanelli,
[7] R.Svoboda,
M.Bodmer: Volatility of anions in steamwater systems of power plants. Conf. BNES
"Water chemistry of nuclear reactor systems",
Bournemouth / GB, Oct 1989, pg 229-234
[8] R.Svoboda, H.Pflug, T.Warneke, M.Koebel:
Investigations into the Composition of the
Early Condensate in Steam (VGB Research
Project Nr.182) VGB Power-Tech, 84 (2004)
11, pg 74-79
H.Sandmann
,S.Romanelli,
[9] R.Svoboda,
M.Bodmer Early condensate in steam
turbines. International VGB-EPRI-Conference
on Interaction of Iron Based Materials with
Water and Steam, Heidelberg / DE, June 1992
[10] R.Svoboda, M.Bodmer: Investigations into the
Composition of the Water Phase in Steam
Turbines. 14th International Conference on the
Properties of Water and Steam, Kyoto / J, Aug
29 - Sep 3, 2004. Power Plant Chemistry, 6
(2004) 11, pg 594-601
[11] J.Tavast, H.G.Seipp, R.Svoboda: The Use of
Titanium in Water/Steam Cycles of Power
Plants. International VGB-EPRI-Conference
on Interaction of Non-Iron Based Materials
with Water and Steam, Piacenza / IT, June
1996
[12] R.Svoboda, H.Hehs, F.Gabrielli, H.G.Seipp,
F.U.Leidich, B.Roberts: Organic Impurities
and Conditioning Agents in the Steam / Water
cycle: A Power Plant Manufacturer's Point of
6