ML17227A492

Responds to Violations Noted in Insp Rept 50-389/92-07. Corrective Actions:On 920421,main Steam Safety Valve Testing Stopped & Gauge Calibr Data Sheets Reviewed & Containment Pressure Sensing Lines Will Be Labeled

ML17227A492
Person / Time
Site:	Saint Lucie
Issue date:	06/26/1992
From:	Goldberg J FLORIDA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
L-92-172, NUDOCS 9207060170
Download: ML17227A492 (7)

Text

ACCELERATED DISTMBUTION DEMONSTPWTION SYSTEM REGULATORY INFORMATION DlSTRIBUTION SYSTEM (RIDS)

Jl CESSION NBR:9207060170 DOC.DATE: 92/06/26

~ NOTARIZED: NO DOCKET CIL:50-369 St. Lucie Plant, Unit 2, Florida Power & Light Co.

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05000389 AUTH. NAME AUTHOR AFFILIATION GOLDBERG,J.H.

~ Florida Power & Light Co. ~

RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk)

SUBJECT:

Responds to violations noted in Insp Rept 50-389/92-07.

Corrective actions:on 920421,main steam safety valve testing stopped & gauge calibr data sheets reviewed &

containment pressure sensing lines will be labeled.

DISTRIBUTION CODE: IEOID COPIES RECEIVED:LTR Q ENCL j SIZE:

TITLE: General (50 Dkt)-Insp Rept/Notice of Violation Response NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD2-2 PD 1 1 NORRIS JP 1 1 INTERNAL: ACRS 2 2 AEOD 1 1 AEOD/DEIIB 1 1 AEOD/DSP/TPAB 1 1 DEDRO 1 1 NRR MORISSEAUPD 1 1 NRR/DLPQ/LHFBPT 1 1 NRR/DLPQ/LPEB10 1 1 NRR/DOEA/OEAB 1 1 NRR/DREP/PEPB9H 1 1 NRR/DST/DIR 8E2 1 1 NRR/PMAS/ILRB12 1 1 NUDOCS-ABSTRACT 1 1 1 1 OGC/HDS3 1 1 EG FILE 02 1 1 RGN2 FILE 01 1 1 EXTERNAL: EG&G/BRYCE,J.H. 1 1 NRC PDR 1 1 NSIC 1 1 NOTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE W~! CONTACT THE DOCUMENT CONTROL DESK, ROOM PI-37 (EXT. 20079) TO ELIMINATEYOUR NAME FROM DISTRIBUTION LISTS FOR DOCUMENTS YOU DON'T NEED!

TOTAL NUMBER OF COPIES REQUIRED: LTTR 23 ENCL 23

P.O. Box14000, Juno Beach, FL 33408-0420 FPL JUN 2 6 3992 L-92-172 10 CFR 2.201 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Re: St. Lucie Unit 2 Docket No. 50-389 Reply to Notice of Violation Ins ection Re ort 92-07 Florida Power and Light Company (FPL) has reviewed the subject inspection report and pursuant to

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10 CFR 2.201 the response to the notice of violation is attached.

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Very truly yours, J. H. Goldberg President Nuclear Division JHG/JWH/kw Attachment cc: Stewart D. Ebneter, Regional Administrator, USNRC Region II Senior Resident Inspector, USNRC, St. Lucie Plant DAS/PSL 8713-92 9207060170 920626 PDR ADOCK OS000389 gYpg 6 PDR an FPL Group company ~(l

Re: St. Lucie Unit 2 Docket Nos. 50-389 Reply to Notice of Violation Ins ection Re ort 92-07 VIOLATION (A):

Unit 2 Technical Specification (TS) 6.8.1.c required that written procedures shall be established, implemented, and maintained covering surveillance and test activities of safety-related equipment. TS 4.7.1.1 and associated table 4.7-0, Steam Line Safety Valves, required that four specific safety valves per SG be verified to be set at 1000 psia +/- one percent t10psi], and that the other four be set at 1040 psia +/- one percent. Licensee procedure GMP-0705, Rev 17, Main Steam Safety Valve Maintenance and Setpressure Testing, implemented these requirements. GMP-0705 section 8.0, Material and Equipment Required, plainly specified that all test gages shall have an accuracy of 0.5~ of full scale.

Contrary to the above, on April 21, 1992, the licensee failed to implement GMP-0705 section 8.0, Material and Equipment Required, by using 200 pound per square inch gage M-201 which had a large one percent calibration label on its side and was also accompanied by a calibration record showing that it actually varied over a one percent range. Another gage in use that had not been questioned also had a large one percent calibration label but the calibration record showed that is was actually satisfactory for this test.

VIOLATION (B):

Unit 2 Technical Specification (TS) 3.3.2 and included Table 3.3-3 required that Engineering Safety Features Actuation System (ESFAS) instrumentation be OPERABLE for the Containment Spray function in operational Modes 1, 2, or 3; including a minimum of three of the four channels of Containment Pressure High-High. Action Statement 17 required that, with three of the four channels OPERABLE, the inoperable channel must be placed in the tripped condition within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Action Statement 17 further stated that one additional channel may be bypassed for up to two hours for surveillance testing.

Unit 2 TS 3.3.2 and included Table 3.3-3 also required that ESFAS instrumentation be OPERABLE for the Safety Injection, Containment Isolation, and Main Steam Line Isolation functions in operational Modes 1, 2, or 3; including a minimum of three of the four channels of Containment Pressure High. Action Statement 13 required that, with three of the four channels OPERABLE, power operation may continue provided that the inoperable channel is placed in the bypassed or tripped condition within one hour. Action Statement 14 required that, with two of the four channels inoperable, power operation may continue provided that one of the inoperable channels has been bypassed and the other inoperable channel is placed in the tripped condition within one hour.

St. Lucie Unit 2 Docket Nos. 50-389 Reply to Notice-of Violation Ins ection Re ort 92-07 VIOLATION (B)

(continued)

Unit 2 TS 3.3.1 and included Table 3.3-1 required that. reactor protective system (RPS) instrumentation be OPERABLE in operational Modes 1 or 2, including a minimum of three of the four channels of Containment Pressure High. Action Statement 2.a required that, with three of the four channels OPERABLE, power operation may continue provided that the inoperable channel is placed on the tripped or bypassed condition within one hour. Action Statement 2.b required that, with two of the four channels OPERABLE, power operation may continue provided that one of the inoperable channels has been bypassed and the other inoperable channel is placed in the tripped condition within one hour.

Contrary to the above, Containment Pressure Channel C (High and High-High) was inoperable at least during the previous operating cycle from about. December, 1990 to April 22, 1992, because its instrument sensing line inside containment was capped, and Containment Pressure Channel C was not placed in the tripped or bypassed condition as required. During most of this time, St.

Lucie Unit 2 was operated in Mode 1 or 2. Additionally, with Containment Pressure Channel C inoperable, another channel of containment pressure was placed in bypass on April 19, 1992, for a total of approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, while the unit was operated in Mode 1 ol 2 ~

St. Lucie Unit 2 Docket Nos. 50-389 Reply to Notice of Violation Ins ection Re ort 92-07 RESPONSE (A) 1~ The reason for the violation was personnel error on the part of Maintenance Supervision. Supervision did not verify the procedural requirements for Test Gauge Calibration accuracy were met. A factor contributing to this personnel error was that the requirements for gauge accuracy were not specified in all applicable sections of the maintenance procedure.

2 ~ Corrective Ste s Taken and Results Achieved On April 21, 1992, Main Steam Safety Valve testing was stopped and gauge calibration data sheets were reviewed. Gauge f201 was determined not to meet the .54 accuracy requirement and was replaced with a new gauge meeting the .54 accuracy standard. The Main Steam Safeties which had been tested with Gauge f201 were retested using the new gauge and determined not to require adjustment. All personnel involved were made aware of the infraction and the need for procedural compliance.

3 ~ Corrective Ste s to Avoid Further Violations a) A memo was issued to all Production Supervisors and Foremen to stress the importance of procedural compliance.

b) Disciplinary action was administered to the Maintenance Supervision involved in this event.

c) Maintenance procedure GMP-0705 will be revised to specify the gage accuracy requirements in all applicable sections of the procedure and include gauge accuracy requirements as part of the QC holdpoint to verify M&TE of pressure gauges.

d) Mechanical Maintenance will review all safety and relief valve test procedures to ensure test gauge ranges, type, and accuracy requirements are adequately specified.

4 ~ Full compliance was achieved on April 21, 1992, upon completion of corrective action in paragraph 2.

Maintenance procedure reviews/revisions will be completed by August 21, 1992.

Re: St. Lucie Unit 2 Docket Nos. 50-389 Reply to Notice of Violation Ins ection Re ort 92-07 RESPONSE (B) ~

1. The reason for the violation was personnel error which resulted in the inadvertent capping of the high pressure sensing line to the containment pressure transmitter PT-07-2C.

2 ~ Corrective Ste s Taken and Results Achieved a) The cap attached to the sensing line was removed on May 7, 1992 restoring the operability of the instrument channel.

b) An examination of maintenance and operating history was performed to determine the period of inoperability and the work authorized on this instrument. Documented evidence indicates that no related work was authorized on this instrument. The evidence also indicates that the instrument was last verified to be operable on April 13, 1989, when the sensing lines were proven to be unobstructed.

c) An engineering analysis and a PRA were performed to identify the potential consequences of this instrument channel being inoperable. The conclusion of this analysis established that neither a containment breach nor additional core damage would result from this sensing line being capped.

d) A pressurized air test was performed on all other Unit 1 and Unit 2 containment pressure transmitter sensing lines which verified all sensing lines were unobstructed. This was performed on May 7, 1992.

3 ~ Corrective Ste s to Avoid Further Violations a) Containment pressure sensing lines on Unit 1 and 2 will be labeled to prevent inadvertent capping utilizing the established plant labeling procedures. Unit 2 will be completed prior to Mode 4 during the 1992 refueling outage. Unit 1 will be completed during the 1993 Spring refueling outage.

b) Plant drawings on Unit 2 will be revised as necessary to identify required sensing line cap configuration by October 14, 1992. Unit 1 drawings will be revised by August 1, 1993.

Re: St. Lucie Unit 2

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Docket Nos. 50-389 Reply to Notice of Violation Ins ection Re ort 92-07 c) A new containment atmosphere penetration inspection procedure (I&C Procedure No. 1400205) has been written to verify selected containment instrumentation piping penetrations which sense the containment open volume atmosphere are free of obstructions. This instrumentation includes process inputs into the Containment Hydrogen Analyzer, Containment Atmosphere Radiation Monitoring, Engineered Safety Features Actuation System, Reactor Protection System, and Containment Differential Pressure Instrumentation. This procedure will be performed prior to a reactor startup following each refueling outage.

d) Mud-dauber caps (insect end-covers) have been installed on Unit 2 containment pressure sensing lines to preclude personnel from capping them. Unit 1 installation will occur during the 1993 Spring refueling outage.

4. Full compliance was achieved on May 7, 1992, upon completion of corrective action in paragraph 2.a).

Corrective Action 3a for Unit 2 will be completed prior to f

heatup to mode 4 during the 1992 refueling outage.

Corrective Action 3a for Unit 1 will be completed during the 1993 Spring refueling outage.

Corrective Action 3b for Unit 2 will be completed by October 14, 1992.

Corrective Action 3b for. Unit 1 will be completed by August 1I 1993 Action 3d for Unit 1 will be completed during the

'orrective 1993 Spring refueling outage.