ML20235G833
| ML20235G833 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 09/25/1987 |
| From: | Fay C WISCONSIN ELECTRIC POWER CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| CON-NRC-100 VPNPD-410, NUDOCS 8709300249 | |
| Download: ML20235G833 (31) | |
Text
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POWER COMPANY 231 W. MICHIGAN, P.O. BOX 2046, MILWA_UKEE. Wl 53201 (414) 221-2345 VPNPD-410 NRC-100 September 25, 1987-U.
S. NUCLEAR REGULATORY COMMISSION Document Control Desk Washington',
D.
C.
20555 Gentlemen:
DOCKETS 50-266 AND 50-301 RESPONSE TO EROSION / CORROSION QUESTIONNAIRE POINT BEACH NUCLEAR PLANTS, UNITS 1 AND 2 In your letter dated June 21, 1987 (which we received on July 27, 1987), you requested Wisconsin Electric Power Company to respond within sixty days to various. questions related to erosion / corrosion.
Attachments A and B provide our responses to your inquiry for Point Beach Nuclear Plant, Units 1 and 2, respectively.
If you have any further questions, please contact us.
Very truly yours, C. W.
Fay Vice President Nuclear Power Attachments Copies to NRC Resident Inspector D. Wagner, Project Manager NRC Regional Administrator - Region III Subscribed and sworn to before me this QL5LL day of September 1987.
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Notary Public, State of Wisconsin My Commission expires I" 2 7-Y O.
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8709300249 870925
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PDR ADOCK 05000266 1
P PDR
Attachment A i
"WR EROSION-CORRbSION QUESTIONNAIRE UTILITY' COMPANY:
F.sconsin Electric Power Company
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UNIT NAME:
eoint Beach Nuclear Plant, Unit 1
- MWe:
500 MWe Net
- FILED BY:
C. W. Fay DATE:
September 29, 1987 PHONE NO.
414-221-2811 DATE OF COMMERCIAL OPERATION:
December 21, 1970 sA.
GENERAL'INFORMATION-1.
Water Treatment:
Prior to 1974:
Coordinated phosphates and hydrazine
. Commencing 1974:
AVT with ammonia and hydrazine 2.
Condensate Polishers:
None 3.
Cooling' Water:
Fresh 4.
Condenser tubing:
Prior to 1986 Admiralty Brass Commencing 1986 Type 304 stainless steel 5.
Feedwater heater tubing:
(a) Low Pressure Heaters 1
1A and IB Prior to 1986 Admiralty Brass Commencing 1986 Type 439 stainless steel 2A and 2B Prior to 1986 Admiralty Brass j
Commencing 1986 Type 439 stainless steel l
l 3A and 3B i
Prior to 1986 Admiralty Brass Commencing 1986 Type 439 Stainless Steel l
l 4A'and 4B j
Prior to 1984 90/10 Cu Ni
{
Commencing 1984 Type 304 Stainless Steel (b) High Pressure Heaters:
SA and 5B Prior to 1986 80/20 Cu Ni Commencing 1986 Type 304 Stainless Steel f-
l I
Attachment A Page 2 t
1 i
6.
Boric Acid Used: Never used on secondary side of the plant B.
Erosion Corrosion Experience 1.
Erosion corrosion identified in wet steam piping:
Yes. Erosion corrosion has been found in the original extraction steam lines (A106 GRB) and the existing turbine crossunder steam lines (A53 GRB).
In 1984 the extraction steam lines were replaced with A312 TP-304 stainless steel piping to eliminate erosion corrosion problems.
2.
Erosion corrosion of MSR chevrons or mesh:
(a) Prior to 1986 the shell and internals of the MSRs were-constructed from carbon steel.
Stainless steel demister pads were used for water separation.
Erosion was noted on all of the internal carbon steel components including the shell.
Erosion of the demister pads was also noted.
(b) In.1986 the internals of the MSRs were modified, replacing all of the internal structural materials with stainless steel. The demister pads were replaced wit.h chevron separators fabricated from type 321 stainless steel. The internal structural materials and internal drain piping were replaced with type 410 stainless steel. No erosion of the stainless steel components has been observed, however, some erosion of the carbon steel shell is still evident. Repairs to the shell have been made as required.
3.
Erosion corrosion of feedwater piping:
Yes. Minor thinning of fittings in the feedwater system was noted during the spring 1987 refueling / maintenance outage. No repairs were required. The. feedwater piping is fabricated from A106 GRB seamless pipe and A234 WPB fittings.
4.
Erosion corrosion of the following:
Component E-C Observed Elbows Yes Tees-Yes Diffusers Not observed Reducers Not observed Valves Yes Orifices Not observed l
l l
l
I Attachment A Page 3 5.
Erosion corrosion of J-tubes:
The J-tubes on the steam generator. feed rings are fabricated from Inconel. Therefore, erosion corrosion is not a concern.
6.
Erosion corrosion of the feedwater distribution ring:
Internal inspections of the feed rings have not been performed.
Erosion corrosion is not evident by external inspection of the feed ring.
7.
Erosion corrosion of turbine:
(a) HP turbine:
Erosion has been noted in the exhaust plenum, on the stationary blading, and on the casing.
(b) LP turbine:
Erosion has been noted on the stationary blading at the base and shroud of the diaphragm.
8.
Erosion corrosion of other cycle components:
(a) Through wall leaks due to erosion have been observed and repaired on valves in the steam generator blowdown system outside containment.
It should be noted that the locations where leaks occurred were in sections of line not inclusive of the contain-ment boundary.
(b) Through wall leaks due to erosion have been observed and repaired on steam line drain piping.
9.
Feedwater temperature range where erosion corrosion was found:
From 342 F to 430 F 10.
Inspection frequency (a) Feedwater piping (1) Prior to 1987 No wall thinning inspections performed.
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Attachment A Page 4 (2) Commencing 1987:
(i)
In spring 1987 a representative sample of all susceptible areas was inspected for evidence of erosion corrosion.. Areas for inspection were selected
-based on their relative susceptibility to erosion corrosion.
-(ii) Annual inspections will be performed to further assess feedwater piping' integrity.and to monitor areas where wall thinning is occurring.
(b) Steam piping (1) Prior to-1987 (i)
Annual internal inspections of the turbine crossunder lines have been performed throughout the plant's operating history.
(ii) In 1983 a one time inspection was made of all of the carbon steel (A106 GRB) extraction steam lines to assess their condition. As a result of the inspec-tion, all of the extraction line piping was replaced with A312 TP-304 stainless steel material in 1984.
(2) Commencing.in 1987 (i)
Annual internal inspections of the turbine crossunder lines will be continued.
(ii) Annual inspections will be performed to further assess the integrity of wet steam piping fabricated of carbon steel.
11.
Inspection methods used (a) Large diameter piping Visual inspection from the interior of the piping is performed if access is possible. Suspect areas are further checked with a digital UT wall thickness measurement device.
If access to the pipe interior is not possible, wall thickness measurements are taken over the entire outside surface of the component using "A-Scan" UT Equipment.
(b) Small diameter piping Wall thickness is measured over the entire outside surface of the component using "A-Scan" UT Techniques.
_.1
Attachment A Page 5 l
1C.
' Piping design 1.
Maximum feedwater. flow-velocity:
1 21 feet /second 2.
No. of feed pumps required:
Power:
No. of Pumps 56% - 100%
2 pumps
'.0 - 56%
-1 pumps 3.
Maximum flow velocity.when.1 pump is operating:
14 feet /second
'4.
'No. of-feedwater piping components:
Component No.
Elbows.
72 Tees 12 Diffusers
- .12 Reducers 10 Valves 27 Orifices 3
Venturis' 2
Branch Conn.
4 5.
' Maximum flow velocity-in wet steam piping:
260 feet /second 6.
Feedwater-temperatures and pressures (a) Figure A-1, Typical Feed Train Conditions (b) Figures A-2 through A-7, Design Heat Balance Diagrams D.
Feedwater and condensate chemistry 1.--
See Table A-1 for typical values for feedwater and condensate chemistry.
l 2.
Feedwater chemistry history:
See Table A-1 l
Attachment A Page 6 3.
Chemical additions (a) Ammonia:
Typical concentration in feedwater: 600 ppb Added at: Not added (b) Hydrazine:
Typical concentration in feedwater:
10 ppb l
Added at:
Condensate pump discharge
)
l (c) Boric acid: Not added.
E.
Materials 1.
Feedwater piping:
Component ASTM Spec Piping A106 GRB Fittings A234 GRB Flanges A105 2.
Wet steam piping:
(a) Turbine crossunder piping:
All piping & fittings A53 GRB (b) Extraction piping:
Component ASTM Spec Piping A312 TP-304 Fittings A403 WP-304 Flanges A182-F 3.
Chemical analyses See Table A-2 for typical analyses.
i
TABLE A-1 TYPICAL FEEDWATER & CONDENSATE CHEMISTRY UNIT 1 Year of Operation 1st 1974 1976 1978 1980 1982 1983 1985 1986 1987 Feedwater pH Maximum' 9.60 9.60 9.40 9.60 9.30 9.35 9.30 Minimum 9.30 9.00 9.05 8.80 8.96 8.50 8.60 Average 9.30 9.45 9.40 9.20 9.28 9.25 9.24 9.20 9.21 9.20 Dissolved 0 (PP )
b 2
Maximum 35 80 150 1000 Minimum
<5
<5
<5
<5 Average 5
<5
<5
<5
<5
<5
<5
<5
<5
<5 Cat Cond(pS/cm) 0.7 0.4 0.4 0.3 0.3 0.2 0.2 0.2 0.2 0.2 Spec cond(pS/cm) 6.0 7.8 6.5 6.0 5.1 4.8 4.8 4.5 4.7 4.7 NH (ppb) 900 750 700 790 600 640 600 580 570 3
NH4 (ppb) 15.0 14.0 8.0 7.0 7.0 9.0 10.7 13.0 11.8 7.4 2
Boron (ppb).
Condensate pH Maximum 9.60 9.70 9.67 9.50 9.53 9.52 9.35 Minimum 9.20 9.00 9.06 9.18 8.98 8.10 8.55 9.50 9.40 9.30 9.32 9.37 9.36 9.27 9.22 9.23 Average Air Inleakage-(SCFM) 10.0 6.0 6.0 3.5 3.6 5.5 3.4 I
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NOTES:
1.
VALUES SHOWN ARE BEST ESTIMATES BASED ON A SAMPLE OF PLANT HISTORICAL RECORDS.
- 2.
- DATA WAS NOT AVAILABLE.
I l
3.
MINIMUM AND MAXIMUM VALUES ARE DUE TO TRANSIENT AND TYPICALLY SHORT DURATION CONDITIONS. AVERAGE VALUES BEST REPRESENT THE NORMAL CHEMICAL ENVIRONMENT WITHIN THE SYSTEMS.
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TABLE A-2 TYPICAL CHEMICAL ANALYSES OF CARBON STEEL PIPING MATERIAL 1.
A106 Grade B Constituent'
% Composition Carbon 0.18 - 0.27 Manganese 0.63 - 0.86 Phosphorous 0.008 - 0.004 Sulfur 0.018 - 0.030 Silicon 0.14 - 0.23 Chromium Not Analyzed for
- l 2.
A53 Grade B Constituent
% Composition Carbon 0.21 - 0.23 Manganese 0.51 - 0.84 j
Phosphorous 0.005 - 0.014 Sulfur 0.015 - 0.035 Silicon Not analyzed for Chromium Not analyzed for
- l Analysis for chromium content was not a requirement of piping specifications A106 or A53 at the time of plant construction. Therefore, information concerning chromium content is not available for carbon steel piping installed
]
in the plant.
From an analysis of several samples of A106 Grade B pipe stock l
material on site at PBNP, a variation in chromium content from 0.01% to 0.12%
]
was noted.
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Attachment B' PWR EROSION-CORROSION QUESTIONNAIRE UTILITY COMPANY:
Wisconsin Electric Power Company UNIT NAME:
Point Beach Nuclear. Plant Unit 2 MWe:
500 MWe Net FILED BY C. W. Fay.
DATE:
September-29, 1987
-PHONE NO.
414-221-2811 DATE OF' COMMERCIAL OPERATION :
October 1, 1972 A.
GENERAL INFORMATION 1.
Water Treatment:
Prior to 1975:
Coordinated phosphates and hydrazine Commencing 1975:
AVT with mmmonia and hydrazine 2.
Condensate Polishers:
None 3.
Cooling Water:
Fresh 4.
Condenser tubing:
Prior to 1985 Admiralty Brass
' Commencing 1985 Type 304 stainless steel 5.
Feedwater heater tubing:
(a) Low Pressure Heaters 1A and IB Prior to 1985 Admiralty Brass Commencing 1985 Type 439 stainless steel 2A and 2B Prior to 1985 Admiralty Brass Commencing 1985 Type 439 stainless steel 3A and 3B j,
Prior to 1985 Admiralty Brass Commencing 1985 Type 439 Stainless Steel l
4A and 4B Prior to 1983 90/10 Cu Ni Commencing 1983 Type 304 Stainless Steel
-(b) High Pressure Heaters:
5A and SB Prior to 1985 80/20 Cu Ni Commencing 1985 Type 304 Stainless Steel
f Attachment B Page'2 6.
Boric Acid Used:
Never used on secondary side of the plant B.
Erosion Corrosion Experience 1.
Erosion corrosion-identified in wet steam piping:
Yes.. Erosion corrosion has been found in_the original extraction steam lines (A106 GRB) and the existing turbine crossunder steam lines (A53 GRB).
In 1984 the extraction steam lines were replaced with A312 TP-304 stainless steel piping to eliminate erosion corrosion problems.
2.
Erosion corrosion of MSR chevrons or mesh:
'(a).. Prior to '1985 the shell and internals of the MSRs were constructed from carbon steel.
Stainless steel demister pads were used for water separation. Erosion was noted on all of the internal carbon steel components including the shell. Erosion of the demister pads was also noted.
(b) In 1985'the internals of:the MSRs were modified, replacing all t
of th'e, internal structural materials with stainless steel. The demister pads were replaced with chevron separators fabricated from type 321 stainless steel.
The internal structural materials and internal drain piping were replaced with type 410 stainless steel. No erosion of the stainless steel components has been observed, however, some crosion of the carbon steel J
shell is still evident. ' Repairs to the shell have been made as
]
required.
3.
Erosion corrosion of feedwater piping:
No inspection for erosion corrosion have been performed to date.
4.
Erosion corrosion of the following:
Component E-C Observed
)
Elbows Yes Tees Yes Diffusers Not observed Reducers Not observed Valves Yes Orifices Not observed l '.
L r
r Attachment B Page 3 5.
Erosion corrosion'of J-tubes:
There are no "J" tubes on the feedwater distribution ring.
6.
Erosion corrosion of the feedwater distribution ring:
Internal inspections of the feedwater distribution. rings have not been performed. Erosion corrosion is not evident by external' inspection of the feed ring.
7.
Erosion corrosion of turbine:
(a) HP turbine:
Erosion has been noted in the exhaust plenum, on the stationary blading, and on the casing. Repairs were made as required.
(b) LP turbine:
Erosion has been noted on the stationary blading at the base and shroud of the diaphragm. Repairs were made as required.
8.
Erosion corrosion of other cycle components:
(a).Through wall leaks due to erosion have been observed and repaired on valves in the steam generator blowdown system outside containment.
It should be noted that the locations where-leaks occurred were in sections of line not inclusive of the containment boundary.
(b) Through wall leaks due to erosion have been observed and repaired on steam line drain piping.
9.
Feedwater temperature range where erosion corrosion was found:
No erosion corrosion detected to date.
10.
Inspection frequency (a) Feedwater piping (1) Prior to 1987 No wall thinning inspections performed.
P
,e J. ;
Attachment B
-Page 4 l
. (2) ~ Commencing 1987:
i (i) In the. fall of 1987 a representative sample of all.
susceptible' areas will be inspected for evidence of
' erosion corrosion. Areas-for_ inspection will be selected based on their relative susceptibility to erosion corrosion.
1 (ii)-Annual inspections will be performed to further assess feedwater piping integrity and to monitor areas where wall. thinning is_ occurring.
(b) Steam piping l
(1) Prior to 1987 (i) Annual internal inspections of the turbine crossunder lines have been performed throughout the plant's operating history.
(ii) In 1982 a one time inspection was made of all of the carbon steel-(A106 GRB) extraction steam lines to assess their condition. As a result of the inspec-tion, all of the extraction line piping was replaced with A312.TP-304 stainless steel material in 1984.
(2) Commencing in 1987 (1) Annual internal inspections of the turbine crossunder lines will be continued.
(ii) Annual inspections will be performed to further assess the integrity of wet steam piping fabricated of carbon steel.
11.
Inspection methods used (a) Large diameter piping Visual inspection from the interior of the piping is performed if access is possible. Suspect areas are further checked with a digital UT wall thickness measurement device.
If access to the pipe interior is not possible, wall thickness measurements are l
taken over the entire outside surface of the component using "A-Scan" UT Equipment.
J j
(b) Small diameter piping Wall thickness is measured over the entire outside surface of I
the component using "A-Scan" UT Techniques.
4 Attachment B Page 5 C.
Piping Design 11.
Maximum feedwater flow velocity: 21 feet /second 2.
- No. of feed pumps required:
Power No. of Pumps 56% - 100%.
2 pumps 0 - 56%
1 pumps
.3.
. Maximum flow velocity when 1 pump is operating:
14 feet /second 4.
No. of feedwater piping components:
Component No.
Elbows 68 Tees 12 Diffusers 12 Reducers
-10 L
Valves' 27 I
Orifices 3
Venturis 2
Branch Conn.
4 l
l 5.
Maximum flow velocity'in wet steam piping:
260 feet /second 6.
Feedwater temperatures and pressures (a) Figure B-1, Typical Feed Train Conditions (b) Figures B-2 through B-7, Design Heat Balance Diagrams D.
Feedwater and Condensate Chemistry 1.
See Table B-1 for typical values for feedwater and condensate chemistry.
l 2.
Feedwater chemistry history:
See Table B-1
l I
f Attachment B Page 6 q
3.
Chemical additions (a) Ammonia:
Typical concentration in feedwater: 600 ppb Added at: Not added (b) Hydrazine:
Typical concentration in feedwater: 10 ppb Added at:. Condensate pump discharge (c). Boric acid: Not added.
E.
Materials 1.
Feedwater piping:
Component ASTM Spec Piping A106 GRB Fittings A234 WPB Flanges A105 2.
Wet steam piping:
(a) Turbine crossunder piping:
All piping & fittings A53 GRB (b) Extraction piping:
Component ASTM Spec Piping A312 TP-304 Fittings A403 WP-304 Flar,ges A182-F 3.
Chemical analyses See Table B-2 for typical analyses.
1
TABLE B-1 TYPICAL FEEDWATER & CONDENSATE CHEMISTRY UNIT 2 Year of Operation 1st 1974 1976 1978 1980 1982 1983 1985 1986 1987 Feedwater pH Maximum 9.60 9.36 9.65 9.52 9.40 9.54 9.38 9.33 Minimum 9.30 8.20 9.00 8.94 8.30 8.73 8.82 7.37 Average 9.20 9.45 9.30 9.10 9.24 9.26 9.28 9.22 9.18 9.19 Dissolved 0 (PP )
j b
2 Maximum 104 600 400 Minimum
<5
<5
<5 Average 5
<5
<5
<5
<5
<5
<5
<5
<5
<5 Cat'Cond(pS/cm) 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.2 Spec Cond(pS/cm) 8.0 8.0 5.0 4.0 5.0 4.7 4.8 4.6 4.6 4.7 NH (ppb) 1000 1000 750 400 700 600 600 600 600 610 3
NH4 (ppb) 10.0 12.0 8.0 3.0 5.0 9.0 9.0 12.6 9.4 11.7 2
Boron (ppb)
Condensate pH Maximum 9.60 9.40 9.70 9.62 9.54 9.55 9.35 Minimum 9.20 8.90 9.00 9.14 9.04 8.16 7.19 9.40 9.40 9.10 9.30 9.40 9.38 9.30 9.24 9.24 Average Air Inleakage (SCFM) 12.7 11.0 4.5 5.2 3.9 3.5
3.5 NOTES
1.
VALUES SHOWN ARE BEST ESTIMATES BASED ON A SAMPLE OF PLANT HISTORICAL RECORDS.
- 2.
- DATA WAS NOT AVAILABLE.
3.
MINIMUM AND MAXIMUM VALUES ARE DUE TO TRANSIENT AND TYPICALLY SHORT DURATION CONDITIONS. AVERAGE VALUES BEST REPRESENT THE NORMAL CHEMICAL ENVIRONMENT WITHIN THE SYSTEMS.
IL-_---_-__-_-__________-__--
l TABLE B-2 TYPICAL CHEMICAL ANALYSES OF CARBON STEEL PIPING MATERIAL 1.
A106 Grade B Constituent
% Composition Carbon 0.18 - 0.27 Hanganese 0.63 - 0.86 Phosphorous 0.008 - 0.004 Sulfur 0.018 - 0.030 Silicon 0.14 - 0.23 Chromium Not Analyzed for
- 2.
A53 Grade B Constituent
% Composition Carbon 0.21 - 0.23 Manganese 0.51 - 0.84 Phosphorous 0,005 - 0.014 Sulfur 0.015 - 0.035 Silicon Not analyzed for Chromium Not analyzed for *
- Analysis for chromium content was not a requirement of piping specifications A106 or A53 at the time of plant construction. Therefore, information concerning chromium content is not available for carbon steel piping installed in the plant. From an analysis of several samples of A106 Grade B pipe stock material on site at PBNP, a variation in chromium content from 0.01% to 0.12%
was noted.
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