05000389/LER-1999-004, :on 990415,as Found Cycle 10 Psv Setpoints Were Outside TS Limits.Caused by Manufacturing Process Defect. All Three Psvs Were Replaced with pre-tested Valves During Cycle 11 Refueling Outage.With

:on 990415,as Found Cycle 10 Psv Setpoints Were Outside TS Limits.Caused by Manufacturing Process Defect. All Three Psvs Were Replaced with pre-tested Valves During Cycle 11 Refueling Outage.With

ML17241A394
Person / Time
Site:	Saint Lucie
Issue date:	06/30/1999
From:	Frehafer K, Stall J FLORIDA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
L-99-148, LER-99-004, LER-99-4, NUDOCS 9907070215
Download: ML17241A394 (9)

LER-1999-004, on 990415,as Found Cycle 10 Psv Setpoints Were Outside TS Limits.Caused by Manufacturing Process Defect. All Three Psvs Were Replaced with pre-tested Valves During Cycle 11 Refueling Outage.With

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(i) 10 CFR 50.73(a)(2)(viii) 10 CFR 50.73(a)(2)(iii) 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
3891999004R00 - NRC Website

text

~

CATEGORY 1 ~

REGULATORY INFORMATXON DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9907070215 DOC.DATE: 99/06/30 NOTARIZED: NO FACZL:50-389 St. Lucie Plant, Unit 2, Florida Power

&, Light Co.

AUTH.NAME AUTHOR AFFILIATION FREHAFER,K.W.

Florida Power

& Light Co.

STALL,J.A.

Florida Power

& Light Co.

RECXP.NAME RECIPIENT AFFILIATION DOCKET 05000389

SUBJECT:

LER 99-004-01:on 990415,as found cycle 10 PSV setpoints were outside TS limits.Caused by manufacturing process defect.

All three PSVs were replaced with pre-tested valves during cycle 11 refueling outage. With 990530 ltr.

DISTRZBUTXON CODE:

XE22T COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.73/50.9 Licensee Event Report (LER), Incident Rpt, etc.

NOTES:

RECIPIENT ID CODE/NAME LPD2-2 PD INTERNAL: AC FILE CENTER Q

B NRR/DSSA/SPLB RGN2 FILE 01 COPIES LTTR ENCL 1

1 1

1 1

1 1

1 1

1 1

1 RECIPIENT ZD CODE/NAME GLEAVES,W AEOD/SPD/RRAB NRR/DXPM/IOLB NRR/DRIP/REXB RES/DET/EIB COPIES LTTR ENCL 1

1 1

1 1

1 1

1 1

1 EXTERNAL: L ST LOBBY WARD NOAC POORE~W NRC PDR 1

- 1 1

1 1

1 LMZTCO MARSHALL NOAC QUEENER,DS NUDOCS FULL TXT 1

1 1

1 1

1 D

N NOTE TO ALL "RZDS" RECZPZEN'S:

PLEASE HELP US TO REDUCE WAST". TO HAV YOUR NAME OR ORGANIZATION REMOVED FROM DZSTRIBUTION LISTS OR REDUCE THE NUMBER OF COP ES R-"

VED BY YOU 0 YOUR ORGAN ZATZON, CONTACT THE DOCUMENT CONTROL DESK (DCD)

ON EXTENSION q

c 2083 FULL TEXT CONVERSION REQUIRED TOTAL NUMBER OF COPIES REQUIRED:

LTTR 17 ENCL 17

Florida Power 8c Light Company,6351 S. Ocean Drive, Jensen Beach, FL34S57 June 30, 1999 L-99-148 10 CFR $ 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re.

St. Lucie Unit 2 Docket No. 50-389 Reportable Event: 1999-004-01 Date ofEvent: April 15, 1999 As Found Cycle 10 Pressurizer Safety Valve Set pints Outside Technical S ecification Limits The attached revision to Licensee Event Report 1999-004 is being submitted pursuant to the requirements of 10 CFR $ 50.73 to provide notification ofthe subject event.

Very truly yours, J. A. Stall Vice President St. Lucie Nuclear Plant JAS/EJW/KWF Attachment cc:

Regional Administrator, USNRC Region 11 Senior Resident Inspector, USNRC, St. Lucie Nuclear Plant

'ir9070702i5 990630 PDR ADQCK 05000389 8

PDR an FPL Group company

NRC FORllr 366 (6 1998)

LICENSEE EVENT REPORT (LER)

(See reverse for required number of digits/characters for each block)

Estimated burden per response to comply with this mandatory information cottaction request: 50 hrs. Reported lessons learned aro incorporated into the licensing process and fod back to industry. Forward comments regarding burden estimate lo the Records Management Branch (TW F33), U.S. Nuclear Regulatory Commission, Washington, DC 205554001

~ and to the Paperwork Reduction Project (3150-0104),

Office of Management and

Budget, Washington, DC 20503.

If an information collection does not display a currently vatid QMB conlrol number, the NRC may not conduct or sponsor, and a person is nol required to respond to, Ihe information collection.

U.S. NUCLEARREGULATORYCOMMISSION APPROVED BY OMB NO. 3150-0104 EXPIRES 0&f30)2001 FACILITYNAME(1)

St.

Lucie Unit 2 DOCKET U

BER (2) 05000389 PA6 (3)

Page 1 of 6 TITLE(4)

As Found Cycle 10 Pressurizer Safety Valve Setpoints Outside Technical Specification Limits EVENT DATE 5 LER NUMBER 6 REPORT DATE 7 OTHER FACILITIESINVOLVED &

MONTH DAY YEAR YEAR SEQUENTIAL REVISION MONTH DAY YEAR NUMBER NUMBER FAClt.lrvNAME 04 15 1999 1999 004 01 06 30 1999 FACIUTYNAME DOCKET NUMBER OPERATING MODE (9) 20.2201(b) 20.2203(a)(2)(v)

X 50.73(a)(2)(i) 50.73(a)(2)(viii)

THIS REPORT IS SUBMITTE UIREMENTS OF 'IO CFR:

Chec k one or more 11 D PURSUANT TO THE REQ POWER LEVEL(10) 050 20.2203 a 1

20.2203(a)(2)(i) 20.2203 a 2 ii 20.2203 a 2 iii 20.2203 a

2) iv 20.2203 a 3

i

20. 2203(a)(3)(ii) 20.2203 a 4

50.36 c 1

50.36 c 2

50.73 a 2

ii 50.73(a)(2)(iii) 50.'73 a 2 iv 50.73 a 2

v 50.73 a 2 vii 50.73 a 2

x

?3.71 OTHER Spocify fn Abstract below or in NRC Form 36&A NAME UCENSEE CONTACT FOR THIS LER 12 TELEPHONE NUMBER (Include Area Code)

Kenneth W. Frehafer, Licensing Engineer (561 }

467 7748 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13

CAUSE

SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX

CAUSE

SYSTEM COMPONENT MANUFACTURER REPORTABLE TO EPIX AB C710 YES 6

PPLEMEN ALREPORT E PEC YES (If yes, complete EXPECTED SUBMISSION DATE).

D 14 NO EXPECTED SUBMISSION DATE (15)

MONTH OAY ABSTRACT (Limitto 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16)

On April 15,

1999, St. Lucie Unit 2 was in Mode 1 at approximately 50 percent reactor power.

Wyle Labs informed FPL of unsatisfactory test results for the code pressurizer safety valves (PSVs) removed during the cycle ll refueling outage.

Wyle Labs was contracted to perform the offsite pressurizer safety valve testing and the testing was conducted within the required time restraints.

Technical Specification 3.4.2.1 requires the PSVs to lift at 2500 psia

(+/-1 percent)

The as found settings of the removed St. Lucie Unit 2 pressurizer safety valves were from 1.6 to 3.8 percent high, outside the Technical Specification tolerance limit of

+/-

1 percent.

The cause of the highest failed pressurizer safety valve test was a manufacturing process

defect, and all pressurizer safety valves experienced mechanical setpoint drift over the operating cycle.

There is no past or present operability concern as the subject pressurizer safety valves were removed and replaced with pre-tested valves during the St.

Lucie Unit 2 cycle 11 refueling outage, There was no affect on the health and safety of the public during past St.

Lucie Unit 2 cycle 10 power operations because the limiting overpressure analyses remain bounded when actual St. Lucie Unit 2 cycle 10 operational parameters were considered.

NRC FORM 366 (6-1998)

NRC FORM'366A (6-1998)

LlCENSEE EVENT REPORT (LER}

TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSION FACILITYNAME(1)

St. Lucie Unit 2 Doc T

NUMBER 2 05000389 LER NUMBER (6)

SEQUENTIAL REVISION NUMBER NUMBER 1999 004 01 PAGE (3)

Page 2 of 6 TEXT (tf more space is rettvired, vse additional copies of NRC Form 366A} (1l)

Description of the Event On April 15,

1999, St.

Lucie Unit 2 was in Mode 1 at approximately 50 percent reactor power.

Wyle Labs informed FPL of unsatisfactory test results fox the code pressurizer safety valves (PSVs)

(EIIS:AB:RV) removed during the cycle 11 refueling outage.

In accordance with the inservice testing (IST) program, pressure relief devices are tested per ANSI/ASME OM-1987, Part 1,

"Requirements fox Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices."

Section 1.3.3, "Test Frequency, Class 1 Pressure Relief Devices, " of the code requires testing within 12 months of removal from service when the surveillance requirements are satisfied by installing a full complement of pre-tested valves.

Wyle Labs was contracted to perform the testing and the testing was conducted within the required time restraints.

Technical Specification 3.4.2.1 requires the PSVs to liftat 2500 psia

(+/-1 percent).

The as found settings of the Unit 2 PSVs were outside the Technical Specification tolerance limit of +/-

1 percent.

As sho~n below, the deviat'on ranged from 1.6 to 3.8 percent high for the three valves.

Valve V1200 V1201 V1202 Serial Number N84217-00-0005 N84217-00-0008 N84217-00-0007 Set Pressure Acceptable Range As Found Set Pressure Result 2500 psia 2475-2525 psia 2539.7 psia 1.6% High 2500 psia 2475-2525 sia 2593.7 sia 3.86 High 2500 psia 2475-2525 psia 2567.7 psia 2.7% High No present operability concern exists, as the PSVs were all removed and xeplaced with pre-tested valves during the St. Lucie Unit 2 cycle ll (SL2-11) refueling outage under work orders (WO)

98001961, 98001960, and 98001959.

Cause of the Event

The cause of the 3.8 percent high pressurizer safety valve setting was an inadequate manufacturing process and mechanical setpoint drift.

The cause of the other high settings was mechanical setpoint drift.

The ANSI/ASMF. OM-1987, Part 1,

code requires that a cause determination be performed and corrective actions implemented for any valve exceeding its nameplate setpressure by 3 percent ox greater.

Only one valve, V1201 (S/N N84217-00-0008),

exceeded this 3

percent threshold and is the first new block body valve to exceed this criteria.

Investigation into this failure indicates that it was caused by an inadequate manufacturing process.

Specifically, the spring coil was not perfectly flat and resulted in misalignment of the load train (loading of the disc from the spring assembly).

This caused minor scoring of 'the internal guides that resulted in a larger opening force (which corresponds to a higher as found setpressure).

Eight of the nine new block body valves have been inspected or overhauled since they were originally purchased, and no similar manufacturing defects have been noted.

Additionally, based on the limited historical block body pressurizer safety valve testing data, the actual drift over one operating cycle averages 1.4 percent and the prevalent trend is upward.

All three Unit 2 valves exhibited an upward setpoint drift.

The three valves tested following the St. Lucie Unit 1 cycle 15 refueling outage did not display this upward trend.

NRC FORINT 366A I6 1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION U.S. NUCLEAR REGUI.ATORY COMMISSION FACILITYNAME (1)

St. Lucie Unit 2 NUMBER (2) 05000389 LER NUMBER (6)

SEQUENTIAL REVISION NUMBER NUMBER 1999 004 01 PAGE (3)

Page 3 of 6 fifmore spaceis rerkuired, use adddional copkes of ftVRC Form 366'A

)

Analysis of the Event

FPL reviewed NUREG-1022, Revision 1, "Event Reporting Guidelines 10 CFR 50.72 and 50.73k o and determined that this event is reportable under 10 CFR 50.73(a) (2) (i) (B) as "any operation or condition prohibited by the plant's Technical Specifications."

Although discrepancies found in Technical Specification surveillance tests should be assumed to occur at the time of the test, the existence of multiple sequential test failures involving safety valves may be an indication that the discrepancies arose over a period of time.

Therefore, the condition may have existed during plant operation.

Analysis of Safety Significance As described in the UFSAR, Section 5.4.13.2, the reactor coolant system (RCS) is protected against overpressure by protective and control devices such as the pressurizer spray system, the power operated relief valves, and the high-pressure reactor trip.

In addition to these

features, three ASME Code PSVs ensure that RCS piping and components are protected from overpressure in accordance with ASME code requirements.

No present operability concern exists, as the PSVs were all removed and replaced with pre-tested valves during the cycle 11 refueling outage.

An assessment of the accident analyses was performed to determine if the setpoint deviations could have led to the violation of overpressurization limits during the operation of cycle 10.

The function of pressurizer safety valves in the safety analyses is to mitigate the consequences of overpressurization events by limiting peak pressure below the acceptance limits.

The limiting overpressurization events are in the category of "Decrease in Heat Removal by the Secondary System."

The limiting events in this category affected by deviations in PSV setpoints are the feedline break and loss of condensex vacuum analyses.

Feedline Break A revised feedline break analysis has xecently been performed for St. Lucie Unit 2 as part of the reload process improvement (RPI) to be implemented for cycle 12.

The RPI is described in FPL Lettex L-98-308, "St. Lucie Unit 2, Docket No. 50-389, Proposed License Amendment, Cycle 12 Reload Process Improvement."

The feedline break analysis of letter L-98-308 bounds the operation of cycle 10, the current cycle and anticipated future cycles.

The revised feedline bxcak analysis, which used a

conservative PSV setpoint of 2575 psia, showed acceptable results with respect to the overpressurization criteria for primary and secondary systems.

Since the average as-found setpressure of the PSVs to be evaluated is 2568 psia (i.e.,

(2575 psia),

the xesults of the assessment bounds cycle 10 operation with these as-found setpoints (a

lower PSV setpoint would open the valves earlier helping in the mitigation of the overpressurization event).

Loss of Condenser Vacuum This is the limiti.ng pressurization event for St. Lucie Unit 2.

Similar to the feedline break analysis, a revised loss of condenser vacuum analysi.s has recently been performed for St.

Lucie Unit 2 as part of the RPI to be implemented for cycle 12.

This analysis bounds the operation of cycle 10, the curxent cycle and anticipated future cycles.

The revised loss of condenser vacuum analysis, which used a

PSV setpoint of 2550 psia, showed acceptable results with respect to the overpressurization criteria for primary and secondary systems.

Since the average as-NRC ORM 366A 16 1998)

NAC FORM 366A I6 1999)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION US. NUCLEAR REGULATORY COMMISSION FACILITYNAME I1)

St. Lucie Unit 2 flfmore space hs reqhhhred, hrse adChaonal cophes of NRC orm 366A NUMBER (2) 05000389 LER NUMBER (6)

SEQUENTIAL REVISION NUMBER NUMBER 1999 004

01 PAGE (3)

Page 4 of 6 Analysis of Safety Significance (cont'd) found setpressure of the PSVs to be evaluated here is 2568 psia

(>2550 psia),

the inputs and assumptions of the analysis were evaluated to determine the impact of as-found set pressures that could have existed during cycle 10 operation (a higher PSV setpoint would open the valves later adversely impacting the mitigation of the overpressurization event).

A review of the RPI analysis determined that several key parameters are modeled conservatively as compared to the actual values applicable for cycle 10 operation.

The values used in the RPI analysis and the corresponding cycle 10 values are listed below.

Although a higher PSV setpoint would make the consequences

worse, other parameters such as a higher initial pressurizer

pressure, a lower analysis high pressure trip setpoint, a higher initial primary system temperature, and a less positive (or a negative) moderator temperature coefficient (MTC) would make the event less severe as described below.

~ Initial Pressuri zer Pressure 4 High Pressure Trip Setpoi nt:

Increasing the initial pressure

(> 30 psi) and reducing the trip pressure (20 psi) will result in an earlier reactor trip, substantially reducing the heat input into the RCS.

An initial pressure of 2220 psia is consistent with the cycle 10 normal operating pressure of 2250 psia minus an uncertainty of 30 psi.

Also, the high pressurizer pressure trip value of 2400 psia for this analysis is acceptable

for, cycle 10 which accounts for an uncertainty of 30 psi on the Technical, Specification trip setpoint of 2370 psia.

The reduction in heat input into the RCS due to an earlier reactor trip (based on these input changes) is expected to offset any adverse effects of a later opening of PSVs by 18 psi.

~

Initiai RCS Temperature:

Increasing initial RCS temperature will result in increased heat removal to the secondary system providing some beneficial impact on the calculated peak RCS pressure.

~

Moderator Temperature Coefficient:

A less positive or a negative MTC would result in lower reactor power leading to a slower pressure increase up to the time of reactor trip.

This reactor power at the trip time is important in determining the final peak pressures.

An analysis value of -2 pcm/ F bounds cycle 10 operation which was predicted to have a

MTC of (

- 5 pcm/"P at all times during cycle 10 at hot full power.

The impact of the above parameters was evaluated using RETRAN computer code.

RETRAN is maintained by EPRI and is used extensively in the nuclear industry for non-LOCA

safety analyses

RETRAN calculations were first done with the key parameter values the same as in the RPI analysis.

RETRAN calculati,ons were then repeated with the values changed to the cycle 10 values, as shown below.

NRC 0

M 366A 16-1998)(6-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSION FACILITYNAME(1)

St. Lucie Unit 2 OOCKET NUMBER 2 05000389 LER NUMBER (6)

SEQUENTIAl REVISION NUMSER NUM8ER 1999 004 01 PAGE (3)

Page 5 of 6 TEXT (lfmore space is required, use additionat copies of NRC Form 366A) (17)

Analysis of Safety Significance (cont')

Parameter Initial Pressurizer

Pressure, psia Initial Core Inlet temperature, F

High Pressurizer Pressure Trip

setpoint, psia Pressurizer safety Valve Opening

Pressure, psia Moderator Temperature Coefficient (MTC), pcm/'F Initial Core Thermal

Power, MWth RPI Value 2180 535 2420

~

2550

+3.0 2754 Cycle 10 Value 2220 545 2400 2568

- 2.0 2754 It was found that the impact of the higher PSV setpoints is more than offset by the parameter changes reflecting cycle 10 operation.

The peak pressures for this event during cycle 10 operation thus would have remained bounded by the UFSAR analysis values.

RETRAN calculations showed that the peak RCS pressure is reduced by approximately 10 to 30 psi using cycle 10 specific conditions with as-found PSVs setpoints.

The input changes addressed above have an insignificant impact on the peak secondary pressure.

Conclusion As discussed

above, the limiting overpressure events were bounded once the actual St.

Lucie Unit 2 cycle 10 operational parameters were considered in the analyses.

Therefore, FPL concludes that the as found PSV setpoints did not adversely affect the health and safety of the public during past cycle 10 operation.

Additionally, setpoint drift averaged 1.4 percent in the upward direction over an operating cycle.

In order to conservatively evaluate the potential impact of this potential setpoint drift on the St.

Lucie Unit 1 and 2 operating cycles, the as left settings of the six installed pressurizer code safeties were evaluated.

The current analyses of record for St. Lucie Units 'l and 2 bound the expected average pressurizer code safety setpoint drift.

NRC FOR% 366A (6-1998)

LICENSEE EVENT REPORT (LER)

TEXT CONTINUATION U.S. NUCLEARREGULATORYCOMMISSION FACILITYNAME(1)

St. Lucie Unit 2 DOCKET NUMBER 2 05000389 LER NUMBER (6)

SEQUENTIAL REVISION NUMBER NUMBER 1999 004 01 PAGE (3)

Page 6 of 6 TEXT (ifmore space is required. use additional copies of NRC Form 366A) (17)

Corrective Actions

1. All three St.

Lucie Unit 2 PSVs were replaced with pre-tested valves during the cycle 11 refueling outage (SL2-11) via work orders (WO) 98001961,

98001960, and 98001959.

The removed valves will be overhauled and retested at Wyle Labs 2.

FPL is developing a long term action plan to address potential pressurizer safety setpoint drift.

Additional Information

Failed Com onents Identified Component:

pressurizer safety valve Manufacturer:

Crosby Model:

Similar Events

None HB-86-BP, forged block body design, size 3K6, assembly N84217