ML18094A560

LER 89-024-00:on 890609,safety Injection Concurrent W/ Reactor Trip Signal Occurred.Caused by Inadequate Drainage of Main Steamlines.Event Reviewed W/Maint Personnel & Procedures modified.W/890707 Ltr

ML18094A560
Person / Time
Site:	Salem
Issue date:	07/07/1989
From:	Miller L, Pollack M Public Service Enterprise Group
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
LER-89-024, LER-89-24, NUDOCS 8907140316
Download: ML18094A560 (7)

Text

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-PSfiG Public Service Electric and Gas Company P.O. Box E Hancocks Bridge, New Jersey 08038 Salem Generating Station July 7, 1989 U. S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555

Dear Sir:

SALEM GENERATING STATION LICENSE NO. DPR-70 DOCKET NO. 50-272 UNIT NO. 1 LICENSEE EVENT REPORT 89-024-00 This Licensee Event Report is being submitted pursuant to the requirements of the Code of Federal Regulations 10CFR

• 50.73(a} (2} (iv}. This report is required within thirty (30} days of discovery.

Sincerely yours, 1

• ~~:!:iir General Manager -

Sal~m Operations MJP:pc Distribution 8907140316 890707 PDR ADOCK 05000272 S PNU 95-2189 11 1 Ml 12-84

• NllC For111

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XJCKE1 NUM9111 (21 I r,.,. .. 131 Io I l'ACILITV NAME 111 Salem Generatinq Station - Unit 1 I o I o I o I 2 I 7 1: 1 loF 016 TITLE (41 Safetv In;ection/Rx Trip During Mode 3 Operation Due To Inadequate Procedures EVINT OATI! (Ill LEll NUMeEll Ill REPORT OATE (7) OTHEll FACILITIEI INVOLVEO. Ill MONTH QAY YEAR YEAR lt llE~~~=~~AL tt ~~xra~ MONTH OAY YEAR FACILITY NAMEll OOCKET NUMllER(Sl o'1s1010101 I I o 16 ol 9 s ~ s 19 ~ o Ii ~- - o I o o 17 ol 7s I 9 OPlllATING THll lllPOllT 11 IUIMITTEO PURIUANT TO THE REOUIREMENTI OF 10 CFll §: (~OM or men of IM fo//owln1J (111

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.0.731111211*1 LICENIEE CONTACT FOR THll LEA 1121 NAME TELEPHONE NUMIER AREA COOE M. J. Pollack - LER Coordinator COMPLETE ONE LINE FOR EACH COMPONENT FAILURE OEICllllEO IN THll lllPOllT 11:11 MANUFAC MANUFAC CAUSE .SYSTEM COMPONENT TUR ER SYSTEM COMPONENT TUR ER I I I I I I I I I I I I I I I I I I I I I I I I I I I I IUPPLEMENTAL REPORT EXPECTED (14! MONTH DAV YJAR EXPECTEO

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• I.*., *pproxlm*toly fltr..n 1ingl**-** rypowrltttn /inn) (1111 On 6/9/89, with the Unit in Hot Standby (Mode 3), a Safety Injection (SI) concurrent with a Reactor Trip signal occurred. The trip signal and SI were the result.of High Steamline Delta P caused by the Nb.

13MS15 Main Steam (~S) Safety Valve lifting. Prior to this event, post outage control rod surveillance testing was in progress using procedure SP(0)4.1.3.1.2. Shutd6wn Bank "A" was out to step 228.

Additionally, the S/Gs were being fed from the Auxiliary Feedwater System. The Steam Generator Feedwater Pumps were not latched. ~11 parts of the reactor protection system and SI logic functioned as designed upon receipt of the SI/trip signal. The root cause of this event has been attributed to inadequate draina*ge of the main steamlines caused by either of two factors: 1) inadequate procedures and 2) a failure to comply with station Administrative-Procedures*

(APs) by plant personnel in 1987. This event will be reviewed with applicable Maintenance Department.and Techni6al Department personnel.

The need to comply with AP programs in their entirety will be

~tressed~ Procedures have been modified to place the steam trap system in service when the plant enters Mode 4 (from Mode 5). As stated in the Analysis of Occurrence section, the main steamline safety ~alves were tested and ~eset, as applicable. The previously unidentified globe valve has been numbered and added to TRIS.

Westinghouse has initiated a review and analysis of this event.

Engineering investigation of the main steam safety valve setpoint concern identified as a result of this event is continuing.

NRCF_ . .

(9'831

\ . II LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1 5000272 89-024-00 2 of 6 PLANT AND SYSTEM IDENTIFICATION:

Westinghouse - Pressurized Water Reactor Energy Industry Identification System (EIIS) codes are identified in the text as {xx}

IDENTIFICATION OF OCCURRENCE:

Safety Injection/Reactor Trip During Mode 3 Operation Due To Inadequate Procedures Event Date: 6/09/89 Report Date: 7/07/89 This report was initiated by Incident Report No.89-329.

CONDITIONS PRIOR TO OCCURRENCE:

Mode 3 {Hot Standby; DESCRIPTION OF OCCURRENCE:

On June 9, 1989 at 1641 hours0.019 days <br />0.456 hours <br />0.00271 weeks <br />6.244005e-4 months <br />, with the Unit in Hot Standby {Mode 3),

a Safety Injection (SI) concurrent with a Reactor Trip signal occurred. The trip signal and SI were the result of Hig~ Steamline Delta P caused by the No. 13MS15 Main Steam (MS) Safety Valve {SB}

lifting.

Prior to this event, post outage control rod surveillance testing was in progress using procedure SP(0)4.1.3.1.2. Shutdown Bank "A" was out to step 228. Additionally, the S/Gs were being fed from the Auxiliary Feedwater ~ystem. The Steam G~nerator Feedwater Pumps were not latched. All p~rts of the reactor protection system and SI logic functioned as designed upon receipt of the SI/trip signal.

The Unit was stabilized in Mode 3, and_in accordance with the requirements of the Code of Federal Regulations 10CFR 50.72{b) (2) (ii), the Nuclear Regulatory Commission was notified of the automatic actuation of the Emergency Core Cooling System (ECCS)

{JEI .- This was the seventeenth SI actuation cycle to date.

APPARENT CAUSE OF OCCURRENCE:

The root cause of this event has been attributed to inadequate drainage of the main steamlines caused by either of two factors: 1) inadequate procedures and 2) a failure to comply with station Adniinistrative Procedures (APs) by plant personnel i'n 1987.

Operation Department procedures did not require the MS7 valves { "Ma_ip.=c::-::o-="-

Steam Drain Valves) to be open d~ring Modes 3 and 4. The opening of the val'?"es allows drainage of ~ondensate upstream of the MS167 valll.eS---~

• c II II LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1"'---~-~~---~-~-~5-=-0-=-0~0~2~7~2'---~--8~9=-----~0=2~4_--=-o-=-o-~_ ____;3o._o=f=-=6__

APPARENT CAUSE OF OCCURRE_NCE=-=-:_ _,_(-=-c-=o-=nt 'd}

("Main Steam Stop Valves"). This condensate would build up in the main steamline which could lead. to this event (as *explained below}.

Subsequent to this event. a previously unidentified globe valve was discovered. During the 7th refueling outage. in early 1987, this valve was added to the main steam system drain line just upstream of the No. 12 Condenser. Since this unknown valve was closed, flow to the Condenser would not have occurred even with the MS7 valves open.

The unauthorized installation of this valve is contrary to the requirements of Administrative Procedure (AP) AP-8, "Design Change Test and Experiment Program" which states that a DCR is required for any design change involving a print revision.

Water from the four main steamlines' is drained through steam traps.

These lines join in a single header which enters the No. 12 Condenser. The valve was added in conjunction with the replacement of piping and was to function a~ an isolation valve in support of any future related work. Therefore. with this valve closed, no drainage to the No. 12 Condenser could occur. Operations was not informed of the installation of the valve; therefore, the computerized Tagging Request Information System (TRIS) was not updated to identify the existence of the valve.

As indicated above. investigation revealed that the main steamlines contained a significant amount o~ water at saturated temperature. In the No. 13 main steamline. this saturated water underwent oscillating wave phenomenon by changing to steam and back to water resulting in steamline steam/water mixture density changes. These density wave oscillations took the form of pressure spikes resulting in safety valve 13MS15 lifting twice and the resulting SI on differential pressure. After lifting the first time, the valve reseated.

However. due to the decrease in steamline pressure due to this first lift, the remaining saturated water in the line flashed to steam resulting in the valve's second lift. Water and steam were observed to exhaust from the valve.

Approximately five (5) minutes prior to. the first safety valve lift.

No. 13 S/G blowdown was initiated. This may have caused the initiation of the oscillating wave phenomenon.

The review of available data indicate that No~ 13 S/G steam flow channel experienced spikes of 28% and 46% .. from an initial indicated signal of 7.5%. occurred. This corroborates indications that the safety valve lifted twice.

ANALYSIS OF OCCURRENCE:

-- r- - - - - - - - - - - -

The reactor trip signal was generated as a result of the safety injection signal. Normally, the trip signal is provided to protect the core in the event of a LOCA. assuming a.trip signal was not already generated from other logic sources. _____________

. - II LICENSEE EVENT REPORT (LER) TEXT CONTINUATION

\ Salem Generating Station DOCKET NUMBER tER NUMBER PAGE Unit 1 5000272 89-024-00 4 of 6

~~ALYSIS OF OCCURRENCE~=~~(c~o~n=t~'d~)

The SI signal on high differential pressure (> 100 psigl between steamlines is *designed to detect a steamline break and mitigate the subsequent large positive reactivity insertion in the core due to the reduction in Tave. The SI signal was the result of the oscillating wave phenomenon as discussed in the Apparent Cause of Occurrence section.

After the event. main steamline pipe temperatures were taken.

Temperature differences between the piping top and bottom for the four steamlines indicate the lines were approximately 30 - 40% full of saturated water. Temperature readings showed the bottom of steam pipes to be up to 130°F below the top of the pipes. Upon opening the MS7 valves, the previously unidentified globe valve (just upstream of the No. 12 Condenser) and the MS924 vent valve the steamline temperatures equalized.

After the event. the 13MS15 main steamline safety valve was lift set tested. It lifted at 1053 psig. which is 6 psig below its setpoint acceptance value. The valve was reset and retested satisfactorily.

The setpoint variance may have contributed to the premature opening

• of the 13MS15 valve. No safety significance is attributed to this variance. The remaining nineteen main steamline safety valves were tested. Nine of these valves were similarly below their setpoint acceptance value. These valves were also reset and retested satisfactorily. It is suspected that the reason the valve setpoints were found lower than the manufacturer set value is because the installed valves are exposed to high ambient temperature from the

• Main Steam System piping which increases the spring temperature and lowers the valve setpoint. These valves are new (installed during the current refueling outage). Their lift setpoints are factory set using a steam lift bench test, but the bench test does not allow the spring to heat up to a temperature equivalent to actual plant ambient conditions.

During this event. the No. 12 Auxiliary Building Exhaust Fan tripped after receipt of an SI start signal. It also tripped *on a manual start attempt.

The No. 12 Auxiliary Building Exhaust Fan 460 V breaker was retested in accordance with procedure M3Q, "230 and 460 Volt K-Series Breaker overload Test". The as-found "300% trip time" was approximately 9 -

10 seconds compared to the acceptance range of 7 to 35 seconds. The breaker setting was adjusted to the high end of the range (i.e .. 25 to 35 seconds). retested and returned to service. Due to the high in-rush current. unique to large fan motor starts. the setting of

• this breaker.trip setpoint to the low end of the acceptance range would not guarantee a start in all conditions.

Additionally, the "B" Reactor Trip Shunt Relay actuation did not print out on the Sequence Of Events (SOE) recorder. The Shunt Relay "B" Trip actuation capability was tested severa],_ times_ cifter t_hl:!

SI/trip. It successfully actuated after each test. It has been

,,. "-------------~

I LICENSEE EVENT REPORT (LER) *TEXT CONTINUATION Salem* Generating Station DOCKET NUMBER LER NUMBER PAGE t.Jnit 1 5000272 89-024-00 5 of 6 ANALYSIS OF OCCURRENCE: (cont'd) determined by PSE&G engineering that the relay did function during the event, however, its functioning was not recorded due to the soeed of the initiating event. Either the relay did not completely de=-energize or the relay did de-energize but did not do so long enough for the SOE recorder to record it. The "A" Reactor Trip Shunt relay de-energization was recorded on the SOE recorder. It cleared on the recorder in approximately one cycle (16 mseconds) which indicates that the event was very fast. The "B" reactor trip breaker did open autom~ticalli due to the ev~nt.

The high differential pressure between steamlines trip/SI is designed to mitigate transients from full power. Since this event occurred in Mode 3 the affect(s) on the plant were minimal. This event did not affect the health or safety of the public: however, it is reportable, in accordance with Code of Federal Regulations 10CFR50.73(a) (2) (iv).

due to the automatic actuad.on of the Reactor Protection System and an Engineered Safety Feature.

CORRECTIVE ACTION:

This event will be reviewed with applicable Maintenance Department and Technical Department personnel. The need to comply with AP programs in their entir~ty will be stressed.

Procedures have been modified.to place the steam trap system in service when the plant enters Mode 4 (from Mode 5) .* *The main steamline safety valves testing was not initiated until this procedure*

was used.

As stated in the Analysis of Occurrence section. the m~in steamline safety valves were tested and reset, as applicable.

The previously unidentified globe valve has been numbered and added to TRIS. It is now identified in TRIS as "normally open". A design change package has been initiated which will establish the appropriate administrative design configuration contol for the globe valve.

The. M3Q procedure has been revised to set the Auxiliary Building Exhaust and Supply Fans 460 V breakers trip setpoint to the high end (25 - 35 seconds) of the acceptance range (7 - 35 seconds). The No.

12 Auxiliary Building Exhaust Fan breaker has been set to the high end of the acceptance range and has been returned to service. The other 460 V fan motor ~reakers will be te~ted and reset a~. applicable~

Westinghouse has initiated a review and analysis of this event.

Engineering investigation of the main steam safety valve setpoint concern is continuing.

POST SAFETY INJECTION DATA:

Initial Pressurizer Level 26%

LICENSEE EVENT REPORT (LERI TEXT CONTINUATION Salem Generating Station DOCKET NUMBER LER NUMBER PAGE Unit 1 5000272 89-024-00 6 of 6 POST SAFETY INJECTION DATA: (cont'd)

Final Pressurizer Level 69%

Initial Pressurizer Pressure 2235 psig Final Pressurizer Pressure 2235 psig*

Initial Average Reactor .coolant Temperature 548° F Final Average Reactor Coolant Temperature 536° F*

Refueling Water Storage Tank Temperature Duration of Safe~y Injection 11 minutes

.G~~~~~l~r -

Salem Operations MJP:pc SORC Mtg.89-071