ML18096A835

Summary of 920701 Meeting W/Util Re Resolution of Open Erosion/Corrosion Issues Identified at 920625 Meeting

ML18096A835
Person / Time
Site:	Salem
Issue date:	07/10/1992
From:	Stephen Pindale Office of Nuclear Reactor Regulation
To:	Office of Nuclear Reactor Regulation
References
NUDOCS 9207200329
Download: ML18096A835 (18)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555 July 10, 1992 Docket Nos. 50-272 and 50-311 LICENSEE:

Public Service Electric and Gas Company FACILITY:

Salem Nuclear Generating Station, Units 1 and 2

SUMMARY

OF MEETING WITH PUBLIC SERVICE ELECTRIC AND GAS COMPANY (PSE&G) ON JULY 1, 1992, TO DISCUSS RESOLUTION OF THE OPEN EROSION/CORROSION ISSUES THAT WERE IDENTIFIED IN THE JUNE 25, 1992 MEETING On July 1, 1992, PSE&G met with the NRC staff to provide information relative to open issues concerning the erosion/corrosion (E/C) program th~t had. been identified in a meeting held on June 25, 1992.

Background:

On June 25, 1992, a meeting was held with PSE&G to discuss their E/C program and the results of the implementation of that program at Salem 1 and 2.

At the conclusion of that meeting, the following issues were identified as being open and additional information was required for complete resolution:

1.

The bases for re-rating the design pressure of the portion of the feedwater system that is unisolable from the steam generator;

2.

Detailed calculation of minimum wall thickness and the application of the 1.2 factor for maximum allowable stress, including assumptions and the bases for the assumptions;

3.

Details of calculations of E/C rates; and

4.

The assurance that the corrosion pattern in the feedwater piping is not in the form of a sine curve.

In addition, PSE&G was requested to provide information concerning the sizes of the areas exhibiting E/C and the results of the steam generator expander examinations and the corrective action to be taken.

Summary:

1.

Re-rating of the portion of the feedwater system piping that is unisolable from the steam generators:

This piping was originally designed for the same pressure rating as the main feedwater system.

The 1967 edition of ANSI/ASME 831-1, which is

(

the design code of record for Salem, does not have any guidance for determining design p~e~ures for piping connected to a pres sure v'~sse 1. 1}0l I 9207200329 920710 li\\llD~ r.:fJ

. ~

I

~DR ADOCK 0500~~~2 I

H~i~~D ff~

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" However, the 1980 edition does, so PSE&G used those guidelines.

Based on the application of those guidelines, the design pressure, as detailed in Enclosure 1, was determined to be 1335 psig.

The staff agreed that this design was reasonable and had no further questions.

2.

Detailed calculation of minimum wall thickness and the application of the 1.2 factor for maximum allowable stress:

The calculation of minimum wall thickness uses the equations given in 831-1 (the code).

Two factors that are used in this calculation are the design pressure and the allowable stress as given in code stress tables.

In addition, the code allows the allowable stresses to be increased by a factor of 1.2 for pressure transients that occur for less that 1% of the time.

The maximum pressure in the feedwater system is the added shutoff heads of the condensate pumps and the main feedwater pumps (1870 psig).

PSE&G had reviewed the original design specifications for the feedwater system and found that 1870 psig was used as the maximum working pressure and that because this represented the maximum pressure transient, the allowable stress was multiplied by 1.2.

Using these factors, the minimum wall thickness was calculated to be 0.717 inches for 14-inch main feedwater piping.

A more typical way of determining the minimum wall thickness would be to determine the design pressure, which would be near the normal pressure (which in this case is about 1195 psig) and was calculated by PSE&G to be 1420 psig.

The wall thickness would be determined and then the stresses calculated for the maximum pressure condition.

Because the minimum wall thickness, as calculated using the higher pressure and higher stresses (by the 1.2 factor), enveloped the stresses using a derived design pressure, the staff agreed that this was a reasonable approach.

PSE&G again reiterated their position that if the projected wall thickness was below the minimum wall thickness, the piping/

component would be replaced.

The details of PSE&G's calculations are given in Enclosure 1.

3.

Details of calculations of E/C rates:

In calculating the E/C rates, PSE&G used a method of averaging around the minimum point as measured by ultrasonic testing (UT).

The method incorporated the results of inspections from three outages, if available. A method was also developed if the area had been inspected less than three times.

In addition, an E/C rate was calculated that was based on the nominal wall thickness. The maximum rate that was calculated was used to project the wall thickness that would remain at the end of the operating cycle.

The staff agreed that the E/C rates and projections were conservative.

The details of PSE&G's E/C rate calculations are given in Enclosure 1.

4. Ass4rance that corrosion is not occurring in the form of a sine pattern:

PSE&G stated that, based on discussions with other utilities and parties knowledgeable in the field of E/C, they did not identify a mechanism that would produce a sine pattern.

To assure that the minimum is identified, the grid is extended two pipe diameters when a decreasing trend is noted at the.grid boundary.

To be considered satisfactory, the pipe wall must be 75 mils above the calculated minimum wall thickness.

The staff found this to be acceptable.

5.

The areas of E/C are given in Enclosure 2.

The size of the areas that are exhibiting E/C are generally small (less than 10 square inches).

6.

Results of the steam generator expander examinations.

In Salem 1, cracking of three of the four expanders had been found. The decision had been made by PSE&G to replace all four expanders prior to restart.

In Salem 2, an indication in one expander was noted, but it was determined by UT not to be a crack.

No other indications were found in Salem 2.

PSE&G is looking into the reasons Salem 1 experienced cracking and Salem 2 did not.

The major area of investigation is the operation of the Auxiliary Feedwater System.

At the conclusion of the meeting, the staff had no further questions concerning the application of the design code, the corrective actions being taken and the basis for the calculation of minimum wall and E/C rates. is a list of attendees at the meeting.

Enclosures:

/S/

Stephen M. Pindale, Acting Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation

1.

Handout of Erosion/Corrosion Issues

2.

Areas of Erosion/Corrosion

3.

Meeting Attendees cc w/enclosures:

See next page DISTRIBUTION:

Docket File JCalvo NRC & Local PDRs CMiller PDI-2 Reading JStone TMurley/FMiraglia MO'Brien JPartlow OGC SVar a EJordan NAME DATE RLobel, EDO CHsu, 9715 JMedof f DESmith BLeFave KParczewski MHartzman JFair SPindale RMcBrearty RHermann DGamberoni "l_ 110192 I I FILENAME: A:\\METSUM.71 ACRS (10)

EWenzinger, R-I JWhite, R-I I I

4.

Assurance that corrosion is not occurring in the form of a sine pattern:

PSE&G stated that, based on discussions with other utilities and parties knowledgeable in the field of E/C, they did not identify a mechanism that would produce a sine pattern.

To assure that the minimum is identified, the grid is extended two pipe diameters when a decreasing trend is noted at the grid boundary.

To be considered satisfactory, the pipe wall must be 75 mils above the calculated minimum wall thickness.

The staff found this to be acceptable.

5.

The areas of E/C are given in Enclosure 2.

The size of the areas that are exhibiting E/C are generally small (less than 10 square inches).

6.

Results of the steam generator expander examinations.

In Salem 1, cracking of three of the four expanders had been found. The decision had been made by PSE&G to replace all four expanders prior to restart.

In Salem 2, an indication in one expander was noted, but it was determined by UT not to be a crack.

No other indications were found in Salem 2.

PSE&G is looking into the reasons Salem 1 experienced cracking and Salem 2 did not.

The major area of investigation is the operation of the Auxiliary Feedwater System.

At the conclusion of the meeting, the staff had no further questions concerning the application of the design code, the corrective actions being taken and the basis for the calculation of minimum wall and E/C rates. is a list of attendees at the meeting.

Enclosures:

1.

Handout of Erosion/Corrosion Issues

2.

Areas of Erosion/Corrosion

3. Meeting Attendees cc w/enclosures:

See next page

~

Stephen M. Pindale, Acting Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation

Public Service Elect~ & Gas

. Company cc:

Mark J. Wetterhahn, Esquire Winston & Strawn 1400 L Street NW Washington, DC 20005-3502 Richard Fryling, Jr., Esquire Law Department - Tower 5E 80 Park Place Newark, NJ 07101

• Mr. Calvin A. Vondra General Manager - Salem Operations Salem Generating Station P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. S. LaBruna Vice President - Nuclear Operations Nuclear Department P.O. Box 236 Hancocks Bridge, New Jersey 08038 Mr. Thomas P. Johnson, Senior Resident Inspector Salem Generating Station U.S. Nuclear Regulatory Commission Drawer I Hancocks Bridge, NJ 08038 Dr. Jill Lipoti, Asst. Director Radiation Protection Programs NJ Department of Environmental Protection CN 415 Trenton, NJ 08625-0415 Maryland People's Counsel American Building, 9th Floor 231 East Baltimore Street Baltimore, Maryland 21202 Mr. J. T. Robb, Director Joint Owners Affairs Philadelphia Electric Company 955 Chesterbrook Blvd., 51A-13 Wayne, PA 19087

..tat i 011, Richard Hartung Electric Service Evaluation Board of Regulatory Commissioners 2 Gateway Center, Tenth Floor Newark, NJ 07102 Regional Administrator, Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Lower Alloways Creek Township c/o Mary 0. Henderson, Clerk Municipal Building, P.O. Box 157 Hancocks Bridge, NJ 08038 Mr. Frank X. Thomson, Jr., Manager Licensing and Regulation Nuclear Department P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. David Wersan Assistant Consumer Advocate Office of Consumer Advocate 1425 Strawberry Square Harrisburg, PA 17120 Mr. J. A. Isabella MGR. - Generation Department Atlantic Electric Company P.O. Box 1500 1199 Black Horse Pike Pleasantville, NJ 08232 Carl D. Schaefer External Operations - Nuclear Delmarva Power & Light Company P.O. Box 231 Wilmington, DE 19899 Public Service Commission of Maryland Engineering Division ATTN:

Chief Engineer 231 E. Baltimore Street Baltimore, MD 21202-3486 Mr. Steven E. Miltenberger Vice President and Chief Nuclear Officer Public Service Electric & Gas Company Post Office Box 236 Hancocks Bridge, New Jersey 08038

t:NCLOSURL 1 PSE&G/NRC MEETING DISCUSSION OF EROSION/CORROSION ISSUES AGENDA JULY 1, 1992

• DISCUSSION OF FEEDWATER SYSTEM DESIGN PRESSURE

• DISCUSSION OF APPLICATION OF 1.2 STRESS ALLOWABLE FACTOR

• EROSION/CORROSION RATE CALCULATION

• DISCUSION OF SINE PATTERN EROSION/CORROSION e ADDITIONAL INFORMATION CHARACTERIZATION OF EROSION/CORROSION AREAS UPDATE ON STEAM GENERATOR EXPANDER EXAMINATIONS

DETERMINATION OF DESIGN PRESSURE FEEDWATEA PIPE - S/G TO FIRST VALVE SALEM NUCLEAR GENERATING STATION REF:

ANSI/ASME 831.1 - 1980 122.1.3 FEEDWATER DESIGN PRESSURE

• S/6 MAX. ALLOWABLE WORKING PRESSURE (MAWP)

+ (LESSER OF 251 MAWP OR 225 psi)

+ STATIC ELEVATION PRESSURE S/G DESIGN P

• 1085 psig, 251 (1085)

• 271.25 STATIC EL. HEAD

• 23.4 225 1333.4 - 1335 FOR INFORMATION:

• HIGHEST SAFETY VA. SET AT 1125 psi, + 31

• 1158.75 e S/G MAX OVERPRESSURE 1085 (1.1)

• 1193.5

c.

I

June 30, 1992 STEAM GENERATOR FEEDWATER MINIMUM WALL TIIICKNESS DESIGN BASIS BACKGROUND

1.

From the piping specification (S-C-MPOO-MGS-0001), the normal working service pressure is 1195 psig.

2.

From the piping specification (S-C-MPOO-MGS-0001), the maximum working service pressure is 1870 psig.

3.

From the UFSAR, Revision 6, Table 10-4.1, the main feedpump shut-off head is 1893 psig (when the condensate pump impeller was modified, the shut-off head was increased from 1870 psig to 1893 psig).

4.

From the piping specification (S-C-MPOO-MGS-0001), the maximum working service temperature is 4 70F.

5.

From the UFSAR, Revision 6, section 3.9.2, piping equivalent to ASME Code Classes 2 & 3 was designed to B31.1, extended in a manner paralleling later versions of the ASME Code. The following limits were used:

Design Loading Stress Category Combination Limit Normal Normal Pressure & Weight Pc<Sh and External Loadings PL<Sh Upset Maximum (short time)

Pc< 1.2Sh Pressure & Weight and PL< l.2Sb External Loadings and QBE Faulted.

Maximum (short time)

Pc< 1.2Sh Pressure & Weight and PL< l.8Sh External Loadings and SSE where Pc is the circumferential stress and PL is the longitudinal stress.

6.

From B31. l, 1967 Edition, paragraph 102.3.2.(a), "The calculated stress due to internal pressure shall not exceed the allowable stress values given in the Allowable Stress Tables, except as permitted in Paragraph 102.2.4."

1

7.

From B31.1, 1967 Edition, paragraph 102.3.3.(a), "The sum of the longitudinal stresses produced by internal pressure, live and dead loads and those produced by occasional loads such as the temporary supporting of extra weight may exceed the allowable stress values given in the Allowable Stress Tables by the amounts and durations of time given in Paragraph 102.2.4."

8.

From B31.1, 1967 Edition, paragraph 102.2.4, "It is recognized that variations in pressure and temperature inevitably occur, and therefore the piping system shall be considered safe for occasional operation at higher than the design pressure or temperature. Either pressure or temperature, or both, may exceed the design values if the stress in the pipe wall calculated by the formulas using the maximum expected pressure during the variation does not exceed the S-value allowable for the maximum expected temperature during the variation by more than the following allowances for the periods of duration indicated:

(1)

Up to 15 percent increase above the S-value during 10 percent of the operating period.

(2)

Up to 20 percent increase above the S-value during 1 percent of the operating period."

9.

The original pipe wall sizing calculations for the SGF piping used allowable stresses for A106 Gr. B & C material of 18,000 psi and 21,000 psi. These values are 20 percent greater than the Allowable Stress table values of 15,000 psi and 17,500 psi.

10.

The original pipe wall sizing calculations for the SGF piping used a pressure of 1870 psig.

CONCLUSIONS

1.

The original calculations (and UFSAR) are based on the maximum expected pressure and 120% of the allowable stress.

2.

The maximum expected pressure is the main feedpump shut-off head.

3.

The maximum expected pressure is assumed to occur less than 1 % of the operating time.

4.

A specific "design pressure" was not defined. All calculations are based on the normal pressure and maximum pressure.

5.

If a "design pressure" were to be defined, it would likely be about 1420 psig. This value is based on the maximum normal pressure of 1195 psig plus a safety margin of 225 psig (using a similar approach to what the 1980 B31.1 Code recommends for piping inside the last isolation valve).

2

6.

If the minimum wall thickness calculations were performed using 1420 psig and 100%

of the allowable stress and 1870 psig and 120% of the allowable stress, the 1870 psig/120% ~case would be limiting (for example, for 14" pipe):

t

=

1870*14 0 717 l8?0 2(1.2*17500+1870*0.4) =.

1420 *14 t 1420 = _2_(_1_7_5_0_0_+_1_4_2_0_*_0_. ) = 0. 550

7.

In addition, when determining the minimum wall thickness, the longitudinal stress equations in B3 l.1 are also evaluated to verify that the longitudinal stress limits are satisfied.

3

CALCULATION METHODOLOGY FOR EROSION RATES AND THICKNESS PREDICTIONS June 30, 1992 The method used to calculate the predicted minimum wall thickness at the next refueling outage is based on the UT inspection results from previous outages and is described below.

1.

Review the inspection results for the previous three refueling outages. For each outage, identify the location of the minimum wall thickness, both the circumferential and axial locations. If inspection results are available for only two outages, use those results. If results are available for only one outage, go to step 7.

If the location of minimum thickness varies significantly (e.g., at both ends of a reducer or elbow), then there are two areas of erosion and the following calculations should be completed for each area.

2.

Determine the circumferential location of the minimum wall thickness for each set of inspection data.

3.

Determine the axial location of the minimum wall thickness for each set of inspection data.

4.

For each set of inspection data, calculate an average wall thickness in the area of the minimum thickness. The average minimum is calculated using each of the measurement points in the grid area bounded by the range of the measured minimum thicknesses plus one grid location in each direction. For example, if the following grid was used for UT measurements:

Tn T12 T13 T14 Tis T16 T21 T22 T23 T24 T2s T26 T31 T32 T33 T34 T3s T36 T41 T42 T43 T44 T4s T46 Ts1 Ts2 Ts3 T54 Tss Ts6 T61 T62 T63 T64 T6s T66 and the minimum wall thickness was at location T33 during the last inspections, location T45 two inspections ago and location T53 three inspections ago, the area used to calculate the average thickness would be all points in the area bounded by T22, T 26, T 66, and T 62*

The calculated averages are labeled:

t1 average thickness three outages ago

~

average thickness two outages ago t3 average previous outage In addition, a fourth thickness is defined equal to the nominal wall thickness:

to nominal wall thickness If data is available for only two previous outages, the average thickness t1 can not be calculated and is neglected.

5.

The predicted erosion-corrosion rate is selected as the maximum of the four rates calculated using thicknesses to to t3 and the plant operating durations between the measurements:

r P = MAX ( r 12, :r 23' :r 13 / :r 03 >

I12 = tl -t2 d12

r 23 = t2 -t3 d23 r13 = tl -t3 d13

r 03 = ta -t3 da3 where:

d12 is the plant operating duration between measurements 1 and 2 d23 is the plant operating duration between measurements 2 and 3 d13 is the plant operating duration between measurements 1 and 3 d03 is the plant operating duration until measurement 3 If data is available for only two outages, d12 and d13 can not be calculated, so the predicted erosion rate is taken equal to the greater of the rates d23 and daJ.

6.

The predicted mm1mum wall thickness at the next outage is calculated using the minimum wall thickness measured at any inspection, t"mm, the predicted erosion rate, r,

p and the time until the next outage, ~*

tp = tmin -:rp~

7.

If data is available for only one outage, extrapolation using measured erosion rates can not be performed. In these cases, an estimated erosion rate over the plant life is used.

The wall thickness at the beginning of plant life is assumed to be the greater of the pipe nominal wall thickness or the maximum measured wall thickness (from the inspection results). This value is identified as fo.

to is the thickness at beginning of life For fittings such as tees, reducers, etc., where additional material reinforcement was added during original fabrication, engineering judgement should be used to estimate a local maximum thickness instead of simply selecting the maximum measured value.

Whenever a judgement is made, the rationale for selecting to should be documented in the calculation.

8.

The measured minimum wall thickness is identified as t1*

t1 is the minimum measured wall thickness

9.

The erosion rate is calculated using the time the plant has operated.

to - ti

rp =

d 01 where:

do1 is the operating time at the time of the measurement

10.

The predicted minimum wall thickness at the next outage is calculated using the minimum wall thickness, th the predicted erosion rate, rP, and the predicted operating time until the next outage, ~*

LOCATION COMPONENT lS-SGF-52-El 12 x 14 Reducer lS-SGF-37-El 12 x 14 Reducer lS-SGF-22-El 12 x 14 Reducer lS-SGF-4-El 12 x 14 Red~cer lS-HD-260-Ll 6 Elbow 1S-FWR-P2-Pl 6 Pipe lS-FWR-10-Bl 6 Pipe Bend lS-FWR-PlO-Pl 6 Pipe lS-SGF-71-Ll 20 Elbow 1S-SGF-5L-Pl 14 Pipe 1S-C216-Ll UNIT 1 11 COMPONENTS COMMENTS Thinning in counter bore area.

Thinning in counterbore area.

Thinning in counter bore area.

Thinning in counterbore area.

Slight erosion, must review past history.

Thinning in counterbore area (P22 material).

Thinning in extrados appears attributable to bending.

Intrados proportionately thicker in bending area than extrodos.

In straight areas of pipe, pipe wall thickness is more uniform.

Thinning in counter.bore area (P22 material).

Slight erosion in downstream pipe, must review past history. ~

Slight erosion, must review past history.

General thinning thru-out entire fitting.

Counterbore area encroaching upon tm.

Could have been received in thin condition since identical other train elbow and two (2)

Unit 2 24-inch elbows are about 0.250" above tm thru-out elbow.

11 Components are all above Code tm using 1.20 SH criteria per 1967 831.1 para 102.2.4

LOCATION COMPONENT 2-SGF-113-Rl 24 X 18 Reducer 2-SGF-113-R2 24 X 18 Reducer 2-SGF-113-TlB 24 Tee 2-SGF-112-Ll 24 Elbow 2-SGF-113-T2B 18 X 14 Tee 2-SGF-19-Ll 14 Elbow 2-SGF-34-Ll 14 Elbow 2-SGF-33-L2 14 Elbow 2-SGF-108-Ll 24 Elbow UNIT 2 COMPONENTS COMMENTS Replace due to localized thinning below Code tm in counter bore area.

Appears dut to initial eccentric fit up.

Some erosion occurring.

"DITTO" Above.

Lowest reading 0.105" > ~m in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.159" > tm in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.148" > ~m in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.015" > tm in counterbore area of connecting pipe.

Appears due to initial eccentric fit up.

Some slight erosion occurring downstream.

Lowest reading 0.049" > tm in counterbore area of connecting pipe.

Appears due to initial eccentric fit up.

Some slight erosion occurring downstream.

Lowest reading 0.031" > tm in downstream pipe area.

Some erosion occurring.

Lowest reading 0.047" > tm in counterbore area Some erosion appears to be occurring in extrados.

e*

2-SGF-49A-El 16 X 14 Reducer Lowest reading 0.093" > tm in counterbore area of connecting '~

14" pipe.

No apparent erosion occurring.

2-SGF-47-L2 14 Elbow 2-SGF-48-Ll 14 Elbow 2S-HD-554-Ll 8 Elbow 2-SGF-81-T2B 20 X 18 Tee Lowest reading 0.059" > tm in counterbore area of upstream pipe.

No apparent erosion occurring.

Lowest reading 0.061" > tm in counterbore area of upstream pipe.

No apparent erosion occurring.

Lowest reading 0.043" > tm in downstream pipe.

Some slight erosion occurring.

Lowest reading 0.154" > tm in counterbore area of 18" tee branch to pipe.

No apparent erosion occurring.

12 of 14 components are all above tm using 1.20 s8 criteria per 1967 B31.l para 102.2.4; 2 of 14 being replaced are below Code tm only in counterbore area.

All SGF components tm derived using 1893 PSI although some SGF fittings fall within present P-MAX of 1335 PSI.

LOCATION COMPONENT lS-SGF-52-El 12 x 14 Reducer lS-SGF-37-El 12 x 14 Reducer lS-SGF-22-El 12 x 14 Reducer lS-SGF-4-El 12 x 14 Reducer lS-HD-260-Ll 6 Elbow 1S-FWR-P2-Pl 6 Pipe lS-FWR-10-81 6 Pipe Bend lS-FWR-PlO-Pl 6 Pipe lS-SGF-71-Ll 20 Elbow 1S-SGF-5L-Pl 14 Pipe 1S-C216-Ll

.:.~

UHIT 1 11 COMPONENTS COMMENTS Thinning in counterbore area.

Thinning in counterbore area.

Thinning in counterbore area.

Thinning in counterbore area.

Slight erosion, must review past history.

Thinning in counterbore area (P22 material).

Thinning in extrados appears attributable to bending.

Intrados proportionately thicker in bending area than extrodos.

In straight areas of pipe, pipe wall thickness is more uniform.

Thinning in counterbore area (P22 material).

Slight erosion in downstream pipe, must review past history. ~*

Slight erosion, must review past history.

General thinning thru-out entire fitting.

counterbore area encroaching upon tm.

Could have been received in thin condition since identical other train elbow and two (2)

Unit 2 24-inch elbows are about 0.250" above tm thru-out elbow.

11 Components are all above Code tm using 1.20 SH criteria per 1967 831.1 para 102.2.4 c::

v

LOCATION COMPONENT 2-SGF-113-Rl 24 X 18 Reducer 2-SGF-113-R2 24 X 18 Reducer 2-SGF-113-TlB 24 Tee 2-SGF-112-Ll 24 Elbow 2-SGF-113-T2B 18 X 14 Tee 2-SGF-19-Ll 14 Elbow 2-SGF-34-Ll 14 Elbow 2-SGF-33-L2 14 Elbow 2-SGF-108-Ll 24 Elbow UHI:T 2 COMPONENTS COMMENTS Replace due to localized thinning below Code tm in counter bore area.

Appears dut to initial eccentric fit up.

Some erosion occurring.

"DITTO" Above.

Lowest reading 0.105" > tm in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.159" > tm in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.148" > tm in counterbore area of connecting pipe.

No E/C occurring in tee.

Lowest reading 0.015" > tm in counterbore area of connecting pipe.

Appears due to initial eccentric fit up.

Some slight erosion occurring downstream.

Lowest reading 0.049" > tm in counterbore area of connecting pipe.

Appears due to initial eccentric fit up.

Some slight erosion occurring downstream.

Lowest reading 0.031" > tm in downstream pipe area.

Some erosion occurring.

Lowest reading 0.047" > tm in counterbore area Some erosion appears to be occurring in extrados.

)..

2-SGF-49A-El 16 X 14 Reducer Lowest reading 0.093" > tm in counterbore area of connecting ~~

14" pipe.

No apparent erosion occurring.

2-SGF-47-L2 14 Elbow 2-SGF-48-Ll 14 Elbow 2S-HD-554-Ll 8 Elbow 2-SGF-81-T2B 20 X 18 Tee Lowest reading 0.059" > tm in counterbore area of upstream pipe.

No apparent erosion occurring.

Lowest reading 0.061" > tm in counterbore area of upstream pipe.

No apparent erosion occurring.

Lowest reading 0.043" > tm in downstream pipe.

Some slight erosion occurring.

Lowest reading 0.154" > tm in counterbore area of 18" tee branch to pipe.

No apparent erosion occurring.

12 of 14 components are all above tm using 1.20 SH criteria per 1967 831.l para 102.2.4; 2 of 14 being replaced are below Code tm only in counterbore area.

All SGF components tm derived using 1893 PSI although some SGF fittings fall within present P-MAX of 1335 PSI.

Jim Partlow Jim Stone Richard Lobel Chuck Hsu Jim Medoff Charlie Mi 11 er Mel Gray Bob Coward Frank Thomson Tim Taylor D. E. Smith Bi 11 LeFave Kris Parczewski Mark Hartzman John Fair S. Pindale Ron Haupt Robert McBrearty Robert Hermann David Gamberoni MEETING ATTENDEES EROSION/CORROSION IN FEEDWATER SYSTEM SALEM NUCLEAR GENERATING STATION, UNITS 1 & 2 July 1. 1992 ORGANIZATION NRR/AD NRR/PDI-2 NRC/EDO AEOD/ROAB NRR/EMCB NRR/PDI-2 PSE&G-Licensing MPR Associates PSE&G-Licensing PSE&G NRR/DET/EMCB NRR/DST/SPLB NRR/DET/EMCB NRR/DET EMEB NRR/DET/EMEB NRC/R-I/Res. Inspector Pressure Piping Engineering Associates NRC/R-I/Reactor Engineer NRR/DET/EMCB NRR/DOEA I.